CE2030 Report FINAL. Report_final.pdf · 12.2.1.7 Wrap up of Costs of a Premature Nuclear Phase Out...

Commission Energy 2030 June 19, 2007

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Commission ENERGY 2030

— FINAL REPORT —

June 19, 2007

Belgium's

Energy Challenges

Towards 2030

William D'haeseleer (Chairman), Main Author & Editor Contributing Authors & CE2030 Members: Pierre Klees (Vice-Chair), Johan Albrecht, Jacques De Ruyck; Pierre Tonon, Jean-Marie Streydio; Permanent Members Ronnie Belmans, Luc Dufresne, Bernard Leduc, Stef Proost, Jean-Pascal van Ypersele; Non-Permanent Belgian Members Jean-Marie Chevalier, Wolfgang Eichhammer, Pierre Terzian; Non-Permanent Foreign Members

Commissioned by

Minister Marc Verwilghen

Federal Minister of Energy


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Key Messages in a Nutshell1

The objective of a sound energy policy is to offer energy services for a variety of applications, based on an energy basket that guarantees a firm security of supply, at an acceptable cost for society, and in an environmentally friendly way. In that respect, Belgium must think in European terms and do so entirely. The Belgian energy policy will have to consist of a balanced mixture of contributing elements. Four groups of “energy sources” have to be considered, each having their specific merits and limitations, and it is generally recognized by most relevant international organizations such as IEA and the EU that omitting one of them will likely lead to a sub-optimal solution, the four being energy savings, carbon-based resources, nuclear and renewables. First and foremost, energy savings must be advocated and implemented as much as techno-economically possible. To reflect the value of energy as an economic good and the related external costs, to keep sufficient pressure for rational use of energy, and to optimize load time management, energy prices must be fully passed on to the customer. On the supply side, a diversity of primary energy sources and conversion technologies must be opted for, with a voluntaristic, but nevertheless still 'doable' integration of renewables. Because of limited potential of renewables, Belgium should implement the EU directives in a clever and justified way to contribute to a healthy European energy mix and environmental-burden reduction. Until a full CO2 allowance market is established, Belgium may commit to ambitious quota (in % terms) for supply of renewable energy to the end customers but decouple it from local production, and should advocate European exchange of certificates. Belgium should reconsider its offshore wind policy and be more forthcoming in the concession allocation of sites. The authorities should reconsider the sites of the 'Wenduine Bank' and the 'Vlakte van de Raan', as these sites may offer a reasonable degree of technological success at an acceptable cost. Far offshore sites are not to be dropped, but should be developed meticulously. Through a carefully designed staged process, an international leading role for far offshore may be established. Accounting for the post-Kyoto agreements, Belgium has to use the appropriate means to cope with them in the most economic way, both by stimulating greenhouse gas reduction on a national basis and by emission trading mechanisms. Regarding the use of coal for electricity generation, Belgium must collaborate strongly internationally on the development of Carbon Capture and Storage (CCS). The circumstances when the nuclear phase-out law has been voted have changed substantially; the urgency for climate-change action is becoming evident and the era of very cheap fuel prices is most likely behind us. This facing with current reality and future expectations, requires a profound reconsideration of the current official Belgian standpoint on nuclear power. Phasing out nuclear power in Belgium by 2025 under a considerable post-Kyoto constraint and in the absence of CCS will be extremely expensive and strongly perturbing for our economic fabric. Therefore, it is advised to keep the nuclear option open and to reconsider the nuclear phase out. On security of supply, four aspects are to be focused on as priorities.

• Diversity of supply of primary sources and technologies (type and origin) is the first and foremost rule.

• A stable investment climate must be guaranteed for competitive market players to have sufficient new electricity generation capacity on line timely and to keep a substantial refinery capacity.

1 These Messages and Conclusion & Recommendations of the CE2030 are endorsed by all Permanent Members and most Non-Permanent Members. Non-Permanent Member JP van Ypersele can only accept a possible delaying of the nuclear phase out by five years (without construction of new nuclear plants), if in the mean time a transition to a non-nuclear future is prepared with ambitious measures. See footnotes on point 3 of the Recommendations.


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• Transmission and distribution network operators must be 'allowed' to invest in extensions, adaptations, and preventive maintenance, so as to avoid supply interruptions, support the connection of renewables and facilitate the European market; the Regulator must accept the costs involved being transmitted to the customers; environmental and construction permits must be delivered timely by the competent authorities.

• A comprehensive study to find the appropriate energy mix, a.o., based on the portfolio theory must be carried out.

The liberalization process for electricity and gas in Belgium must be continued in line with the European common energy market concept. Industry has to be enabled to fully participate in the European wholesale energy market, by co-investing in generation assets, by long-term contracts, by establishing a liquid wholesale market, supported by sufficient transnational transmission capacity. Sufficient retail market access should develop over time to reach a good mix of suppliers in Belgium. Regulated capped prices at the retail level are advised against. Strict supervision by a competent and independent Regulator is necessary while accounting for the development of a European regulatory institution. Belgium should devote much more research & development means to energy. To maximally profit from economies of scale, substantial financial incentives must be given to research groups for participation in European projects. European energy research priorities must be the guideline. In order to coordinate this work and to gather the necessary data for decision makers, Belgium should establish a Strategic Energy Watching Brief. In order to achieve all the above, the governments should take initiatives to stimulate young people to be trained in modern energy systems (technicians, engineering professionals, architects, economists, …). Upon lifting the nuclear phase-out law, an agreement with the owners of the Belgian nuclear power plants is to be sought for, to establish a "correct" nuclear-extension concession fee, the revenues of which could be used for stimulating investments in energy savings & demand-side management, for development in renewable energy, for development & research in emerging energy technologies and carriers.


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Table of Contents Key Messages in a Nutshell

Part 0. Executive Summary

Abbreviations, Acronyms, Units & Conversion Factors Part I. Context, Issues to be Addressed, and Elements of Solution 1. Scope, Boundary Conditions & General Hypotheses 1.1 The Commission ENERGY 2030, its mission and the scope of activities 1.2 The External Review Process and the Final Report 1.3 The Energy Scene; Approach & Philosophy of the CE2030 2. Current Situation in Belgium and Historic Evolution 2.1 Historic Evolution of Overall Energy Characteristics 2.1.1 Total Primary Energy Supply & Total Final Energy Consumption for all Carriers & Sectors 2.1.1.1 Total Primary Energy Supply (TPES) 2.1.1.2 Total Final (Energy) Consumption (TFC) 2.1.2 Salient Features of Oil Supply and Demand 2.1.3 The Belgian Natural Gas Supply and Demand 2.1.4 The Belgian Coal Supply and Demand 2.1.5 The Nuclear Fuel Cycle in Belgium 2.1.6 Renewables in Belgium 2.1.7 Electric Energy in Belgium 2.1.7.1 Important Figures 2.1.7.2 Comments on Electricity Generation and Transmission a. International Electrical Energy Exchanges b. Electricity HV Grid Infrastructure 2.2 Energy Prices in Belgium 2.2.1 Wholesale Energy Price Evolution & Influencing Factors 2.2.1.1 Wholesale Primary Energy Prices a. Crude Oil b. Natural Gas c. Coal d. Uranium 2.2.1.2 GHG Emission-Trading-Scheme Prices 2.2.1.3 Wholesale Electricity Prices 2.2.2 Energy Prices at the Consumer Level 2.2.2.1 Comparison of Belgian Prices with Neighboring Countries 2.2.2.2 Breakdown of Belgian Electricity Prices 2.2.3. Evolution and Breakdown of Belgian Liquid Fuel Prices 2.3 Legal & Regulatory Framework 3. Challenges 3.1 Security of Supply 3.2 Clean Energy Provision 3.2.1 Internalizing External Costs as a Means Towards a Sustainable Energy Provision 3.2.2 The Enhanced Greenhouse-Gas Effect and Climate Change 3.2.2.1 The Climate-Change Issue in General 3.2.2.2 Flexible Mechanisms to Justify Emission Reductions 3.2.2.3 The Kyoto Protocol and Belgium 3.3 Affordable Energy Provision and Competitiveness 4. Demand for Energy & Energy Saving 4.1 Energy Intensity/Efficiency and Demand for Energy Services 4.2 The Cost of a Saved Energy Unit 4.2.1 The Cost of a Saved kWh 4.2.2 Market Barriers & Market Failures 4.3 Energy Demand and the CE2030 4.4 Historical Energy Demand in Belgium 4.5 The Fraunhofer Study on Management of Energy Demand


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Part II. Exploring the Future --Scenario Analysis-- 5. Definition of Scenarios 5.1 Scenario Model: PRIMES 5.1.1 PRIMES Description 5.1.2 Some elements of the PRIMES database 5.2 Goal of the Scenario Exercises 5.2.1 Philosophy of Baseline 5.2.2 Philosophy behind the Alternative Scenarios 5.3 Description of Scenarios Implemented 5.3.1 Introductory Considerations 5.3.2 The Baseline — Basic Hypotheses 5.3.2.1 Belgian Baseline part of the European Baseline 5.3.2.2 Economic Activity and Demand for Energy Services 5.3.2.3 Fuel Price Assumptions for the Baseline 5.3.2.4 Specific Assumptions on PRIMES modeling for Belgium and the baseline in particular a. Rationale Behind the Baseline or Reference Projection b. Transport Activity c. Natural Gas supply in 2030 d. Modeling of Renewables in the Power Sector e. Modeling of Biomass Supply and Uses f. Electricity Imports 5.3.2.5 Maximum Assumed Potentials 5.3.2.6 Greenhouse Gases in PRIMES 5.3.3 Baseline-Like with Soaring Fuel Prices 5.3.4 The Concrete Scenarios Considered 5.3.4.1 Overview 5.3.4.2 Post-Kyoto Scenarios a. Greenhouse gases versus CO2 and the flexible mechanisms a.1 Focus on the Belgian Territory a.2 European-Wide Approach b. Domestic reduction of energy related CO2 c. European-wide reduction of GHG based on equimarginal abatement cost d. The Nuclear- Option e. Carbon Capture and Sequestration as a switching variable 5.3.5. Summary of Scenarios 6. Results of the Scenarios 6.1 PRIMES Baseline Scenario; Belgian Results 6.1.1 Final Energy Demand in the Baseline 6.1.2. Electricity Generation in the Baseline 6.1.2.1 Installed Generation Capacity in the Baseline 6.1.2.2 Generated Electric Energy in the Baseline 6.1.3 Primary Energy Demand in the Baseline 6.1.4 CO2 Emissions in the Baseline 6.1.5 Baseline; Closure 6.2 Soaring Fuel Prices-Affected Baseline-Type Scenario — Results 6.3 Alternative Scenarios; Results 6.3.1 Results of Domestic Energy-Related CO2 Reduction Scenarios 6.3.1.1 The Scenarios Revisited in a Nutshell 6.3.1.2 Abatement Cost to Reach Post-Kyoto Reductions 6.3.1.3 Summary of Results Compared to the Baseline 6.3.1.4 Final Energy Demand a. General Observations on Total and Sectoral Energy Demand Evolution b. Fuel Mix and Carrier Contribution in General and the Transport and Residential Sectors 6.3.1.5 Electricity Generation Sector 6.3.1.6 Primary Energy Demand 6.3.1.7 Distribution of CO2-Emission Reductions over the Sectors a. Options for CO2 Reduction b. Total an Sectoral CO2 Emissions 6.3.1.8 Price and Cost Considerations 6.3.1.9 Wrap up of Simulation Results of the Alternative Scenarios for Domestic CO2 Reduction 6.3.2 Critical Post-Scenario Evaluation of Domestic CO2-Reduction Scenarios 6.3.2.1 Renewables Potential and Market Penetration & Diffusion


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a. Growth Rate of Renewables and Market Diffusion b. Grid Investments for Renewables Accommodation c. Subsidy Requirements for Renewables Accomodation 6.3.2.2 Carbon Capture and Storage (CCS) 6.3.2.3 Implications for Security of Supply and Energy Dependence a. Impact of the Domestic CO2 Reduction Scenarios on Natural Gas Demand b. Impact of the Domestic CO2 Reduction Scenarios on Electricity Generation in Belgium 6.3.3 Post-Kyoto Reduction Scenarios in a European Context 6.3.3.1 Influence of EU GHG Constraint on Belgian Energy Situation a. Marginal Abatement Costs b. Reduction of GHG and Energy-Related CO2 in Belgium b.1 Overall Emission Reductions b.2 Contribution of Sectors to Domestic CO2 Abatement b.3 The role of Nuclear as a Cheap Abatement Cost Option b.4 Impact of CCS c. Final Energy Consumption / End Energy Demand c.1 Final Energy Consumption per Sector c.2 Final Energy Consumption per Energy Carrier d. Electricity Generation 6.3.3.2 Consequences for Belgium of EU-wide GHG Reduction a. Import Dependency and Security of Supply a.1 Electricity-Generation Basket a.2 Structure of the Primary Energy Needs of Belgium b. Cost Consequences of the EU scenarios b.1 Cost for Domestic GHG Abatement in Belgium b.2 Cost of Purchasing Emission Allowances Abroad 7. Comparison with other Studies & Authoritative Documents 7.1 Tobback Climate Study 7.2 DLR Study (Commissioned by Greenpeace) 7.3 IEA WEO 2006, EU Climate Package, Stern Report, IPCC AR-4, IEA Review Germany & the UK Energy Review

Part III. The Broader Energy Picture in Belgium 8. Some Elements of the Belgian Liberalized Energy Markets 8.1 General Observations on the Belgian Liberalized Markets 8.2 Liberalized Markets and the PRIMES Scenarios 9. Import Dependency, Security of Supply & Reliability 9.1 General Considerations 9.2 Security of Supply of Natural Gas for Belgium 9.2.1 The Consequences of Phasing Out Nuclear and Coal-Fired Power Stations 9.2.2 Average Gas Demand versus Peak Gas Demand 9.2.3 Potential Future Gas Supplies for Belgium 9.2.4 Several Stakes behind an Adequate Gas Supply 9.2.4.1 LNG Import Infrastructure 9.2.4.2 Gas Storage Requirements 9.2.4.3 Gas Supply and Liberalized Markets 9.2.4.4 The Developing Role of Russian Gas 9.2.4.5 Belgium as a Transit Country 9.3 Security of Supply of Electric Power Delivery in Belgium 9.3.1 Some Basic Reminders 9.3.2 Options for Meeting the Increasing Electricity Demand 9.3.2.1 Domestic Generation a. Starting Situation b. Renewable Energy Sources (RES) b.1 Generation Capacity Potential b.2 Impact on Security of Supply c. Need for Storable Fuel: Coal Fired Stations 9.3.2.2 Import of Electricity a. Import Potential


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b. Impact on Security of Supply, Electricity Prices and the Environment 9.4 Availability of Nuclear Resources 9.5 Portfolio Analysis 10. Reaching Post-Kyoto in Practice 10.1 Announced GHG Reductions and EU Objectives 10.2 Non-CO2 GHG and the Use of Flexible Mechanisms 10.3 Expected GHG and CO2 Reductions and the Cost Consequences 11. Socio-Economic Consequences 12. The nuclear power option 12.1 The Nuclear Phase-out law 12.2 Considerations on the Future of Nuclear Power in Belgium 12.2.1 The Cost of Phasing out Nuclear Power in Belgium 12.2.1.1 Extra Cost for GHG-Reduction Commitments a. Domestic CO2-Reduction Constraint b. European GHG Reduction Constraint 12.2.1.2 Higher Prices for Electricity 12.2.1.3 Concession Fee for Continued Operation 12.2.1.4 Increased Import Dependency 12.2.1.5 Postponed Decommissioning of Nuclear Units 12.2.1.6 Negotiating Advantage with Respect to Foreign Owners 12.2.1.7 Wrap up of Costs of a Premature Nuclear Phase Out 12.2.2 Operational Extension of Existing Power Plants 12.2.2.1 Existing Operation of Nuclear Plants Independent of a Phase Out 12.2.2.2 Continued Operation of Nuclear Plants after the Original Phase-out lawPhase-out law Deadline 12.2.3 New Nuclear Power Plants 12.3 Nuclear Liability 12.4 Nuclear Power, Energy Efficiency and Renewables

Part IV. Conclusions and Recommendations References Annexes Supporting Documents Part A. Energy Related Issues Addressed Part B. Scenario Description & Clarifying Document FPB Part C. Extra General Bibliographical References


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Abbreviations, Acronyms, Units & Conversion Factors AC Alternating Current ADS Accelerator Driven System(s) ANFC/FANC Agence Fédérale de Contrôle Nucléaire / Federaal Agentschap voor Nucleaire Controle (Federal Agency for Nuclear Control) BACAS Royal Belgian Academy Council of Applied Science bbl barrel Bcm Billion cubic meter BWR Boiling Water Reactor CCGT Combined Cycle Gas Turbine CC-mode Combined Cycle mode CCS Carbon Capture and Storage CDM Clean Development Mechanism CE2030 Commission Energy 2030 CES Center for Economic Studies CEU Commission of the European Union CHP Combined Heat & Power (sometimes also referred to as 'cogeneration') CPI Consumer price index CREG Commissie voor de Regulering van de Elektriciteit en het Gas / Commission de Régulation de l'Electricité et du Gaz CWaPE Commission Wallonie pour l'Energie DC Direct Current DG Directorate General DG TREN Directorate General for Transport and Energy (European Commission) DNO Distribution Network Operator DSM Demand Side Management DSO Distribution System Operator ENOH Effective Number of Operating Hours ENOVER / CONCERE Overlegcel Staat-Gewesten voor Energie / La cellule de Concertation Etat- Régions pour l’Energie EPR European Pressurized Reactor ER Exchange Rate ET Emission Trading (generic term; also referring to a flexible mechanism under the Kyoto Protocol) ETS Emission Trading Scheme (here to refer to the European Union ETS) EUA European Union Allowance (an emission permit under the EU-ETS) EUR = € Euro FANC/ANFC Federaal Agentschap voor Nucleaire Controle / Agence Fédérale de Contrôle Nucléaire (Federal Agency for Nuclear Control) FBFC Franco-Belge de Fabrication des Combustibles FED Final Energy Demand FLE Full Load Equivalent FM Flexible Mechanisms FPB Federal Planning Bureau FRDO / CFDD Federale Raad voor Duurzame Ontwikkeling / Conceil Fédéral du Développement Durable GDP Gross Domestic Product GHG Greenhouse Gas(es) GIC Gross Inland Consumption (= TPES = PEC) HHV Higher Heating Value HVDC High Voltage Direct Current IBGE / BIM Institut Bruxellois pour la Gestion de l'Environnement / Brussels Instituut voor Milieubeheer IAEA International Atomic Energy Agency (part of the UN) IEA International Energy Agency (part of the OECD) IGCC Integrated gasification combined cycle IIASA International Institute of Applied Analysis IRP Integrated Resource Planning JI Joint Implementation LHS Left-Hand Side LNG Liquefied natural gas LWR Light Water Reactor MS Member State (of the European Union) NAP National Allocation Plan NEA Nuclear Energy Agency (part of the OECD)


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NH Northern Hemisphere NIR National Inventory Report NL Netherlands NPO Non-Profit Organization NPP Nuclear Power Plant NTC Net Transfer Capacity NTUA National Technical University of Athens OECD Organization for Economic Co-operation and Development OPEC Organization of Petroleum Exporting Countries PEC Primary Energy Consumption (= GIC = TPES) PPI Producer Price Index ppmv parts per million (on volume basis) PPP Power Purchasing Parity PSO Public Service Obligations PWR Pressurized Water Reactor RES Renewable Energy Sources RHS Right-Hand Side SoS Security of Supply TFC Total Final (energy) Consumption toe ton oil equivalent TPES Total Primary Energy Supply (= GIC = PEC) TSO Transmission System Operator TTC Total Transfer Capacity UAE United Arabic Emirates UCTE Union for the Coordination of Transmission of Electricity UN United Nations UK United Kingdom USA United States of America VREG Vlaamse Reguleringsinstantie voor de Elektriciteits- en Gasmarkt WANO World Association of Nuclear Operators WEO World Energy Outlook

Conversion factors 1 toe (ton oil equivalent) = 41.868 GJ = 11.63 MWh 1 kWh = 3.6 MJ 1 ft

3 = 0.02832 m

3

1 Bcm (billion cubic meters) = 1 G m3= 0.8859 Mtoe = 885.9 ktoe


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Summary of scenarios

Baseline:

Bpk00: base scenario in which no post-Kyoto reduction limit is imposed in Belgium and where a decommissioning

of nuclear plants takes place. Fuel prices are those of the 'standard'-baseline prices in Figure 5.7

Bpk00-h: baseline-type scenario in which no post-Kyoto reduction limit is imposed in Belgium and where a

decommissioning of nuclear plants takes place. Fuel prices are those of the 'soaring' type as shown in Figure 5.8

Domestic energy-related CO2-reduction scenarios

Bpk15: scenario in which Belgium reduces its energy CO2 emissions by 15% in 2030 compared to the 1990 level

and where a decommissioning of nuclear plants takes place

Bpk15n: scenario in which Belgium reduces its energy CO2 emissions by 15% in 2030 compared to the 1990

level, lifetime extension of existing nuclear plants + possibility of having 1 new nuclear unit of 1700 MW after 2020

Bpk15s: scenario in which Belgium reduces its energy CO2 emissions by 15% in 2030 compared to the 1990

level, decommissioning of nuclear plants and CCS is not available in the period 2020-2030

Bpk15ns: scenario in which Belgium reduces its energy CO2 emissions by 15% in 2030 compared to the 1990


and CCS is not available in the period 2020-2030


and decommissioning of nuclear plants








European-wide GHG-reduction scenarios

EUpkGHG30s: scenario in which the EU reduces its GHG emissions by 30% in 2030 compared to the 1990

level, decommissioning of nuclear plants in Belgium and CCS is not available in the period 2020-2030 in Europe

EUpkGHG30ns: scenario in which the EU reduces its GHG emissions by 30% in 2030 compared to the 1990

level, lifetime extension of existing Belgian nuclear plants + possibility of having 1 new nuclear unit of 1700 MW

after 2020 in Belgium; CCS is not available in the period 2020-2030 in Europe

The following conventions have been applied: B: stands for Belgium pk: stands for post Kyoto 00, 15 or 30: stands for the imposed Post-Kyoto reduction n: means nuclear option open s: means no CCS allowed (abbreviation of the French "sans") h: high fuel prices


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Part 0

Executive summary


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Terms of Reference of the Commission ENERGY 2030 The final report of the Commission ENERGY 2030 has been submitted to the Federal Government on June 19, 2007. Its conclusion and recommendations have been approved by all Permanent Members and most Non-Permanent Members.

2 The final version of this report has been released to the public

on June 22. This final report has taken into account the relevant and pertinent remarks and comments put forward by the External Review Panels, which have provided their input in March 2007. The Commission ENERGY 2030 (CE2030) has been formally set up by the Royal Decree of December 06 2005 (Moniteur Belge / Belgisch Staatsblad of December 19 2005). The main objective of the assignment given to the Commission ENERGY 2030 for studying Belgium’s energy policy up to 2030, in a European context, is set out in the study’s Summary Memorandum, formally enacted through the Royal Decree. The goal is to «provide the scientific and economic analyses necessary to evaluate Belgium’s options with regard to the energy policy up to 2030». Furthermore, it is stated that the study will «specifically focus on the economic, social and environmental aspects associated with the various options or scenarios for investment policy involving production, storage and transport while bearing in mind the different types and sources of renewable and non-renewable energy as well as examine the issues of security of supply, energy independence and technical feasibility». The study also looks into the cost of the energy system, trends in regional and national energy demand, honoring agreements concerning the environment and the maintenance or further development of technological know-how.

Guidelines to the Reader; Structure of the Report The main Report of the Commission ENERGY 2030 tries to address both 'comprehensively' but relatively 'concisely' the energy challenges of Belgium with a time horizon of 2030. Towards that end, we examine effectively all energy-related matters across the board, without repeating what has been covered in other good writings. The aim of this report is to identify the major characteristics of the Belgian energy system (as part of the European and world energy markets), to explain the considerable challenges ahead, and to propose ambitious but realistic routes towards a 'sustainable' energy future. Based on its analyses of the whole energy chain & system, supported by scenario results provided by a simulation model, the Commission ENERGY 2030 (henceforth mostly abbreviated as CE2030) has acquired a good understanding of the ins and outs of the Belgian energy economy. Hereby, the past is deliberately considered as 'having occurred' (and being non 'retraceable') but valuable lessons from it have been drawn, and corrections towards a reorientation will be proposed if deemed necessary. The challenge for the CE2030 is to propose credible 'solutions' to get us safely to the year 2030 and beyond, by outlining the right directions and hence, by laying the groundwork for a longer-term energy future. It must be stressed that the Commission ENERGY 2030 was not commissioned to perform own research work or modeling-development. The existing model PRIMES has been utilized to execute energy scenarios with plausible constraints and policy options. Modeling exercises are very important as consistency check, but as models cannot be expected to represent all the intricacies of the complex energy economy, careful judgment is required in interpreting the results. Models always follow a straightforward but unavoidably simplified modeling logic, thereby unable to deal with all feedbacks of economic agents, including policymakers. The modeling results give most valuable indications and trends. However, these findings must be complemented with qualitative evaluation and qualified expert opinion. In any case, scenario results should never be considered as predictions of the future: scenarios are modeling exercises which, given the ('mechanistic') algorithm and structure of the simulation model, the inputs, the boundary conditions and hypotheses, project what can be expected under these characteristics just mentioned. The expert judgment for qualifying the scenario results is guided by expertise, experience and the extensive existing energy-related literature. Not counting the Executive Summary, the Final Report is therefore structured as follows:

2 Non-Permanent Member JP van Ypersele does not agree with point 3 of the Recommendations on a possible lifting of the nuclear phase out as clarified by the footnotes over there. Some comments on energy efficiency by Non-Permanent Member W. Eichhammer have been made available on the website www.ce2030.be .


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Part I. Context, Issues to be Addressed and Elements of Solution 1. Scope, Boundary Conditions and General Hypotheses 2. Current Situation in Belgium and Historic Evolution 3. Challenges 4. Demand for Energy and Energy Savings Part II. Exploring the Future —Scenario Analysis— 5. Definition of the Scenarios 6. Results of the Scenarios 7. Comparison with other Studies & Authoritative Documents Part III. The Broader Energy Picture in Belgium 8. Some Elements of the Belgian Liberalized Energy Markets 9. Import Dependency, Security of Supply & Reliability 10. Reaching Post-Kyoto in Practice 11. Socio-Economic Consequences 12. The Nuclear Power Option Part IV. Conclusions & Recommendations Part I is introductory in the sense that it collects all ingredients necessary for appropriate interpretation of the scenario simulations that are performed in a later part. Important therefore is a situation sketch of the Belgian energy economy, considering the evolutionary behavior of primary-energy demand, final-energy consumption, petroleum, gas and electricity carriers and markets, and the current energy prices in Belgium. Appropriate reference is made to the legal and regulatory framework of the energy theater. Before being able to launch into the analysis exercise, one must then identify the future challenges that we face to obtain a sustained and sustainable energy provision. In pragmatic translation of ‘sustainable energy provision’, we consider three important elements: a firm security of supply, both in the long run as to primary-energy delivery and concerning power reliability, so as to avoid blackouts. This energy provision must occur in a clean manner, whereby the threat for climate change is the most urgent ‘constraint’ on our energy system. In the end, the whole energy system must provide energy at affordable prices and be acceptable for the overall economy of the country. As a major component of energy provision in the wide sense, the consumption part is of uttermost importance. Therefore, in a separate chapter, the issue of energy demand and the opportunities and difficulties to establish energy savings are identified. Part II then launches into a major scenario exercise, whereby first a baseline is considered that lets the energy system evolve based on existing legislation & measures and boundary conditions. In the baseline for Belgium, this means that no post-Kyoto limits are set and that the nuclear phase-out law is assumed to be fully enacted. A variety of other scenarios has then been considered, whereby two approaches have been taken. In a first approach, eight variants, with a domestic energy-related CO2 emission reduction by 15% and 30% in 2030 compared to 1990, and with each time the nuclear phase out enacted or lifted, and with CO2 capture and storage assumed to be available or not, have been performed. In a second approach, a EU-wide reduction by 30% of Greenhouse Gases (GHG) is imposed, whereby it is investigated how the Belgian energy theater responds to such obligation. In this second approach, domestic reductions of GHG are limited, but (depending on the type of burden sharing within the EU, if any) that will likely have to be compensated by emission reductions abroad, thereby effectively purchasing emission allowances. The results of these scenarios are summarized in the Conclusions hereunder. After having performed the scenario exercise, the results of the modeling are confronted with the challenges revealed and we evaluate, qualify and further interpret the obtained results. Specifically, a mathematical model cannot include all parameters required to draw up a coherent energy policy (e.g. energy independence, security of supply, nature of electricity as a commodity and the impact of the liberalization of relevant markets, development of know-how, comparative analysis of practices in Europe and throughout the world). Therefore, a considerable additional interpretative analysis has been considered along with the results of the theoretical scenarios.


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In Part III of the report, the Broader Belgian energy picture is looked at. We deal with issues such as 'Elements of the Belgian Liberalized Energy Markets', 'Import Dependency', 'Security of Supply & Reliability', 'Reaching Post-Kyoto in Practice', 'Socio-Economic Consequences', and 'The Nuclear Power Option'. The main conclusions and recommendations are grouped together in Part IV, but for convenience, they are set out below. It is up to the public authorities to adopt them and put them into practice. In addition to this Final Report proper, a set of Supporting Documents is being provided, which serve to document the issues of the main report. In a first collection of supporting documents, essays on particular energy-related topics have been written by the different members of the CE2030 and by DG ENERGY of the Federal Ministry of Economic Affairs (FOD/SPF Economy). These documents are the sole responsibility of the individual authors; no attempt has been made to streamline those essays. They are to be considered as inputs to the overall discussion. Likewise, a detailed account of the scenario analysis is provided in the second part of the supporting documents. The input report dealing with the PRIMES results is under the responsibility of the Belgian Federal Planning Bureau. The Preliminary Report of the CE2030 has been reviewed by a set of Review Panels, reflecting a large cross section of the relevant societal actors. The following organizations/institutions have participated in the review: * Belgium: - the Federal-Regional consultation cell (ENOVER/CONCERE) - Central Council for the Economy (enterprises & unions) - National Bank of Belgium, - the members of the Regulatory Forum (CREG, VREG, CWaPE, IBGE/ BIM) - Federal Council for Sustainable Development (CFDD/FRDO) - Belgian Academy Council for Applied Sciences (BACAS) * International: - International Energy Agency (IEA) - Directorate General Energy of the European Commission (DG TREN) The CE2030 has analyzed and evaluated the comments made by the Review Panels and has taken into account the relevant and pertinent remarks for the final version of its Report. The Preliminary Report of the CE2030, the questions & answers by the Review Panels throughout the process and their comments are available on the CE2030's website, given below. In line with the Royal Decree, this Final Report has been submitted to the Minister of Energy on June 19 2007. This Report and the Supporting Documents, and relevant documents can be consulted at the CE2030 website, http://www.ce2030.be . William D'haeseleer Chairman CE2030 On behalf of its members: Permanent Members: P. Klees (Vice-Chair), J-M. Streydio , J. Albrecht, J. De Ruyck , P. Tonon Non-Permanent Members: R. Belmans, B. Leduc, J.-P. van Ypersele, L. Dufresne, S. Proost, J-M. Chevalier, P. Terzian and W. Eichhammer


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Acknowledgement The interest and contribution of the advisory member F. Sonck, and the ex-officio observers, M-P Fauconnier and H. Bogaert, are acknowledged. The follow up and assistance of the Secretariat, held by M. Deprez, H. Autrique and R. Karmun, of the DG Energy of the Ministry of Economic Affairs, is very much appreciated. Finally, ‘last but not least’, the CE2030 is very thankful and greatly acknowledges the efforts, input, reflections and analyses provided by D. Gusbin and D. Devogelaer of the Federal Planning Bureau. Their scenario-analysis documents have served as the major input to the activities of this Commission Energy 2030.


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Summarizing Conclusions

of the Commission Energy 2030 The Energy Issue is a Daunting Challenge The goal of a comprehensive energy-provision strategy for Belgium must be to offer energy services

3

for a variety of applications, but in a 'sustainable' manner. Viewed pragmatically, a 'sustainable energy provision' relies on an energy basket that simultaneously guarantees a firm security of supply, at an acceptable cost for our society,

4 and in an environmentally friendly way.

Against the current situational background of the following elements:

• oil & gas prices that fluctuate strongly and can be very high; • the anticipated soaring energy-demand on a worldwide scale to give poorer nations a well-

deserved energy provision, in turn leading to possibly severe tensions on the world energy-supply scene;

• the lack of own energy resources, and therefore the very large import dependency for oil and gas from geopolitically unstable regions, with very strong oil dependence for transport, home heating and chemicals, and strong gas dependence for industrial applications and electricity generation;

• the geographical reality of our country, considerably limiting the natural influx of renewable flows;

• expected substantial post-Kyoto GHG- and CO2-emission reduction obligations; • the existing nuclear phase-out law, starting in 2015 and fully executed in 2025; • the creation of a common liberalized European energy market; • the huge investments needed worldwide to replace existing and ageing energy

infrastructure, to develop further production investments for oil and gas, to extend transmission networks for electricity and gas;

and the high degree of uncertainty with many of them, the CE2030 must conclude that the future energy provision for Belgium represents a daunting challenge over the coming 25 years and beyond.

A European Approach is Imperative As a result of its analysis of the current situation in Belgium, Europe and worldwide, and the scenarios performed and studied, the CE2030 has the conviction that Belgium cannot afford to solely think nationally in energy matters, albeit that national responsibilities should not be evaded. Indeed,

• concerning import dependency and security of supply (especially towards an optimal mix of long-term contracts and spot-market supply of gas, and gas storage capability; exchange of electrical fluxes to smoothen out imbalances);

• for establishing a real competitive energy market (especially on the wholesale level for gas and electricity);

3 By "energy services" is meant the activities and applications we wish to enjoy: heat rooms to comfortable temperatures, keep food and drinks cool, drive kms, provide drive power and process heat in industry, etc. This concept here is different from the "services" provided by so-called "energy service companies (ESCOs)". 4 The CE2030 considers the social aspect of energy provision as being part of the economic dimension. All scarce resources must be utilized in the most efficient way, and prosperity for society should be maximized (subject to obvious and/or reasonable constraints) and the acquired welfare must then be distributed in an equitable way, such that all members of the population could benefit from a well-functioning economy. The social issues go much broader than merely energy issues; governments must develop a broad social framework for their citizens. The energy-provision issue must not be singled out for social-policy purposes, but citizens must get equal and fair access to all energy-related opportunities. If imperfections exist, authorities should correct these distortions, and possibly compensate. However, priority must go to a broad social framework; energy-related interventions should be limited in time (except for the right to have access to a certain minimum of energy supply).


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• since most of the energy-conversion infrastructure is owned by international shareholders and is operated in function of the European market, and perhaps more so in the future;

• for making its GHG-reduction commitments acceptable (to basically finance reduction emissions elsewhere);

• to demonstrate sufficient weight on the international scene for negotiations with equipment manufacturers, for launching large R&D programs, …;

• to push through necessary but difficult decisions and commitments, that are unpleasant/hard to make on a national level (similar to e.g., the Maastricht criteria);

a European-wide approach is imperative. The CE2030 is therefore of the firm opinion that Belgium has to fully subscribe to a European energy policy, thereby relying on an appropriate regulatory EU framework. Conclusions of Scenario Analysis The CE2030 has carefully studied the energy-provision issue for Belgium. It has done so by exploring and studying the relevant scientific, technical and economic energy-related literature, through consultation of experts in the field. Moreover it has examined the feasibility and economic costs of different scenarios with the time horizon of 2030, obtained by the PRIMES energy model.

5

All sectors (industry, residential & commercial & service sector, transport sector, electricity sector) as well as all primary and final energy carriers (oil, gas, coal, renewables, uranium, electricity, heat) have been studied. Because of the circumstances, mainly induced by the climate-change threat, the electricity sector plays a crucial role, however, in that important switches (nuclear power and carbon capture & storage) are situated in that sector and because the gas supply for that sector is of utmost importance. Nevertheless, the interaction between all sectors and carriers is properly taken into account. The CE2030 has furthermore reflected attentively upon the comments made by the Review Panels, and has taken into account the pertinent remarks in its final report. All scenarios considered assume a reasonable projection of future demand for energy services (related to GDP growth, demographics, etc), identical to the recent PRIMES scenarios published by the European Commission DG TREN in May 2006. The results are clearly related to this basic hypothesis; a slower growth will lead to less pressure on the energy system; if growth turns out to be higher, then reality may be more demanding than what the model results show.

Baseline Scenario

A first so-called baseline scenario (basically a further endogenous future energy-system development, designed to allow comparison with later alternative scenarios) implements all energy- and climate-related policy measures and instruments agreed upon until 01.01.2005. It assumes no extra policy measures and does not impose any post-Kyoto constraints on greenhouse gases (GHG). In this scenario, the nuclear phase out is assumed to be fully effectuated.

6 7

In the baseline projections, despite a considerable increase of energy-service demand, the final energy demand itself (at the level of the consumer) increases only moderately. This means that relatively cheap options for energy efficiency are taken up, leading to a considerable decrease by 2030 in energy intensity

8 by 30% compared to the value in 2005 for all sectors. In the baseline

5 The actual scenario runs with the energy-system model PRIMES have been executed by the University of Athens (NTUA). The scenarios were defined by the CE2030 after discussion with experts of the Belgian Federal Planning Bureau (FPB), which was responsible for the detailed scenario analysis. At the present time, there is no appropriate modeling alternative since the PRIMES approach has been selected by the FPB and the renewed version of MARKAL/TIMES was not ready for detailed examination within the CE2030 framework. Moreover, PRIMES is a widely recognized European model, frequently used by the European Commission as a tool for helping to design its energy policy. 6 The Baseline is not designed to meet medium-term targets (e.g., in 2012); in principle, it provides a means to check whether the measures are sufficient to meet the targets. 7 Assumed fuel prices start from 55$/bbl in 2005, to become 60$/bbl in 2030. Gas prices are coupled to oil prices. All prices are expressed in constant terms in $2000. 8 Being the energy demand per unit GDP.


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scenario, coal-based electricity generation basically replaces most of the nuclear capacity and increases fivefold between 2020 and 2030. Overall CO2 emissions increase substantially from 116 Mton/a in 2005 to 140 Mton/a in 2030 (being an increase by 32% compared to 1990). In this baseline scenario, the higher oil & gas prices and the nuclear phase out put a certain pressure on the energy system, but the absence of a post-Kyoto limit allows a 'convenient' escape route through the massive installation of coal power plants for electricity generation. Clearly, the Baseline is not sustainable with regard to CO2 emissions. A variant to this baseline, assuming 'soaring' oil prices up to 100 $/bbl in 2030, does not lead to a dramatic difference. The final energy demand is slightly lower but the overall CO2 emission remains at the same level as in the baseline. Alternative Scenarios with Post-Kyoto Obligation To contrast with the baseline, several 'alternative' scenarios have been considered in order to find out what the effect of certain policy choices & technology-availability options are. Two types of scenarios have been examined. In a first approach only domestic reductions of energy-related CO2 emissions on the Belgian territory have been implemented. In a second approach, a European-wide Greenhouse-Gas reduction (GHG) obligation has been imposed. Part of these reductions has been materialized in Belgium; the remaining obligations are to be satisfied by purchasing emission allowances abroad. a. Domestic CO2 Reduction Constraint Two post-Kyoto targets of 15% and 30% of domestically energy-related CO2 reductions in 2030 compared to 1990 have been investigated, with for each case the implementation of the nuclear phase-out law, and the possibility for Carbon Capture and Storage (CCS) as additional 'turn-on/switch-off' variables. Such scenarios have the advantage of being transparent and they show the degree of difficulty to meet the imposed constraints domestically. The scenario results show indeed that domestically effectuated CO2 cuts up to 30% are not affordable for Belgium if nuclear power is phased out and if carbon capture & storage (CCS) turns out to be unavailable. This is a proof 'ex absurdo'. Without nuclear power and without CCS, marginal CO2 abatement costs (or market price for CO2 permits, here called 'Carbon Value', or CV) of up to 500 to 2000 €/ton CO2 for the -15% and -30% scenario, respectively, are reported. For the same increasing energy-service demand as in the baseline, these very high carbon values force a drastic final-energy demand reduction, well beyond those demand reductions doable at reasonable cost, and thereby imposing a high cost on our economy. With such pressure on the energy system, final energy demand for the 15%-reduction case diminishes by 20%, and the energy-related cost in 2030 compared to the year 2000, would increase by 150% in industry, 150% in the tertiary sector and by 170%, in the residential sector, compared to 24%, 31% and 63%, respectively, in the baseline.

9

For the 30% CO2 reduction case, these numbers are much more dramatic. The final energy reduces by somewhat more than 30%, while the energy-related cost in 2030 would increase by an astounding 440%, 510% and 420%, for industry, tertiary and residential sector, respectively, again compared to 24%, 31% and 63% in the baseline.

10

Primary-energy import dependency (in terms of average energy per year) amounts to about 90% for both cases.

11 Gas dependency for electricity generation is about 80-85%, again in average annual

energy terms, but more than 90% when the installed wind and photo-voltaic (PV) capacities are not able to deliver power.

9 Expressed in €2000/toe. 10 Expressed in €2000/toe. 11 Import dependency in the Baseline (also with the nuclear phase out implemented) amounts to 95%.


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Final Energy Demand Intensity

Alternative Scenarios -15%

60

70

80

90

100

110

120

130

140

150

160

2000 2005 2010 2015 2020 2025 2030 2035

Year

FE

D in

ten

sit

y [

kto

e/M

eu

ro]

Baseline Soar BL no nuc; with CCS

with nuc; with CCS no nuc; no CCS with nuc; no CCS

Energy prices per unit energy per sector

Industry [€2000/toe]

Tertiary [€2000/toe]

Residential [€2000/toe]

Values for 2030

In 2000: 540

In 2000: 820

In 2000: 960

Baseline 660 (24%) 1100 (31%) 1600 (63%)

-15% no nuc / no CCS

1300 (150%) 2100 (150%) 2600 (170%)


2900 (440%) 5000 (510%) 5000 (420%)

( % change between 2000 and 2030) ; 1 toe = 41.868 J = 11.63 MWh

If a nuclear phase out is implemented, and given expected technological evolution, the scenario results show that domestic CO2 reductions are very expensive. The numbers, as produced by PRIMES under the given hypotheses, show that a domestic CO2 reduction of up to 15% would be barely tolerable; but also the 'unreasonableness' of a domestic 30% CO2 reduction scenario by 2030 (compared to 1990). After having utilized the other 'solution paths', such as energy savings and renewable energy, to a maximum reasonable extent according to PRIMES, substantial relief of this extremely heavy task to reduce domestic CO2 emissions can be further obtained if carbon capture and storage (CCS) would be available or if nuclear power were allowed to continue operation beyond 2015 and 2025. For the 15% CO2 reduction cases, marginal abatement costs (CVs) of about 50 to 100 €/ton result, whereas the -30% case still leads to CVs of the order of 200 to 500 €/ton. Still a 'respectable' end-energy demand reduction occurs, albeit at a lower cost. To go from 2000 to 2030, the projected energy-system costs for the end-use sectors are as follows. For the -15% case, the cost is 'slightly' higher than the cost in the baseline (although still up to 50% higher for industry) if nuclear power were allowed, whereby the no CCS case is yet somewhat more costly; the case without nuclear power but with CCS, has a system cost that is 2 to 4 times more expensive than the baseline. For the 30% reduction case, costs with nuclear power allowed range from about 2 to 4 times the cost of the baseline (compared to a factor 15 to 20 without nuclear power and without CCS), with the case with both nuclear and CCS available, being the cheapest. The import dependency reduces to about 65-70% when nuclear power is allowed.

12

12 Here, import dependency over a time scale of about one to two years is meant. Nuclear generated electricity is considered of domestic origin on this time scale.


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Values for 2030

In 2000: 540

In 2000: 820

In 2000: 960

-15% with nuc / with CCS

CCCS CCS

730 (37%) 1100 (36%) 1600 (71%)

-15% with nuc / no CCS

790 (47%) 1200 (43%) 1700 (79%)

-15% no nuc / with CCS

970 (81%) 1500 (83%) 2000 (110%)


930 (73%) 1400 (73%) 2000 (100%)


1200 (120%) 1800 (120%) 2400 (150%)


1300 (130%) 2000 (140%) 2500 (160%)


It must be noted, however, that these two ‘alleviating options’ are not equivalent though. Carbon capture and storage is still to be developed and it is very risky to assume that it will be routinely commercially available by 2030 in Belgium (especially the storage part). Nuclear power is currently operating, meaning that this is an option that the Belgian policy makers can make available to the electricity generation sector. To give the system model some liberty to find an outcome, not too many constraints on potentials were imposed. In a post-model interpretative analysis, a pertinent situation sketch, concentrating on the challenges revealed, has qualified these simulation results. By confronting the challenges revealed with plausible ‘real-life’ difficulties, such as taking into account the grid-extension costs for massive expansion of offshore wind capacity (> 900 MW) and PV installed power (> several 100 MW), the rate of technology manufacturing, and the offers asked from the consumers to pay extra for a particular new type of energy provision, the situation will be more critical, both for import dependency and system cost. The system cost to adapt the high voltage network for 3,800 MW offshore wind power is estimated to be about 700 M€; the adaptation of the distribution grid to accommodate more distributed generation, amongst which massive utilization of PV, is estimated to be about 2,000 M€ over a period of 10-20 years. The commitments for green certificates may be overwhelming and policy makers must realize what they promise, so as to remain correct to investors, on the one hand, and with regard to the offers they ask from the final energy consumers, being reflected in higher energy tariffs/prices, on the other hand. Assuming that the current legal framework of guaranteed buy-back prices

13 is kept, are in constant €

and if paid during 20 years, then the following daunting cost figures would apply: - the current 846 MW of offshore wind farms with concession à ~ 6,000 M€

14

- the next 3000 MW offshore wind power à ~ 21,000 M€ - for 2000 MW onshore wind à ~ 7,000 M€ - for 1000 MW PV à ~ 7,200 M€ - for 1500 MW biomass à ~ 9,600 M€ In total, for the 'foreseen' renewable expansion, the end customer will have to contribute via green certificates, and thus increased tariffs, something in the order of a total of ~ 50,000 M€ over 20 years, or about 1/5 of the GDP of 2000, or roughly 1/10 of the estimated GDP of 2030, or 0.7% of the average GDP/a over the period 2000-2030. This exercise also shows that the simulation results of 10,000 MW PV (with a similar support scheme) are quite unrealistic. Indeed, such support would add up to ~ 72,000 M€, which together with

13 Note that this is effectively equivalent to a feed-in tariff. 14 M€ stands for one million €. The comma represents thousands (English language convention). 1,000 M€ = one "milliard" in French and one "miljard" in Dutch.


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the above amounts to about ~ 115,000 M€ or ~ 1/3 of the average GDP/a of the period 2000-2030, or about 40% of our national debt.

b. European GHG Reduction Constraint In a second approach, an overall European GHG reduction target of 30% in 2030 compared to 1990 has been investigated.

15 After an estimate of the decline of the non-CO2 GHG, taking into account the

marginal abatement costs of all European countries, and by freely allowing European exchange of climate reduction efforts through flexible mechanisms, it is found how the CO2 reductions are distributed over the countries. In all scenarios here, no CCS is considered to be available.

-20%

-26%

32%

-30%

-12%

-1%

20%

-0,4 -0,3 -0,2 -0,1 0 0,1 0,2 0,3 0,4

EU - GHG constraint

Belgium - GHG Reference

Belgium - CO2 Reference

Belgium - GHG reduction without nuclear

Belgium - CO2 reduction without nuclear

Belgium - GHG reduction with nuclear

Belgium - CO2 reduction with nuclear

GHG = greenhouse gases Reference = Baseline

Hatched ////// : GHG emission change Full color : CO2 emission change

Orange = Imposed GHG constraint on EU level

Red: Baseline (no post-Kyoto constraint imposed) Blue: without nuclear

Green: with nuclear

In the Baseline (being the same as already considered; labeled as "Reference" in the figure), GHG emissions in Belgium would increase by 20% while CO2 emissions would increase by 32% compared to 1990. With the nuclear phase-out law implemented and without CCS (implying an increase of the Belgian marginal abatement cost to reduce energy-related CO2 compared to the current situation and to its EU neighbors), most reductions will take place abroad, with only a 12% reduction of GHG and a mere 1% reduction of CO2 on the Belgian territory. With nuclear power allowed (and without CCS), the cost to reduce energy-related CO2 in Belgium becomes much smaller, giving rise to a GHG reduction by 26% and a CO2 reduction amount of 20% on the Belgian territory. These results show that the nuclear phase-out law prevents cheap domestic CO2 reductions, leading/forcing Belgium to implement and finance reductions abroad. Under the hypothesis that Belgium will have to accept a similar GHG-reduction obligation as its European trade partners, which we take for simplicity equal to the EU level of 30%,

16 the European approach means that GHG

reductions can be obtained at lower costs than effectuated domestically. However, the emission reductions abroad must be paid for by Belgium via equivalent emission allowances, at a price of the equilibrium marginal abatement cost (MAC). The extra cost is approximately given by the colored triangular area OGE of the figure below and with a European emission allowance price of 200 €/ton CO2-eq in 2030 (being the equilibrium value found by PRIMES), the extra cost due to the nuclear

15 The CE2030 is grateful to Dr. Dominique Gusbin of the Federal Planning Bureau for having made these results available for incorporation in the final CE2030 report. 16 For the wealthier EU countries, amongst which Belgium, a burden sharing based on equal GHG abatement cost per personal income, could lead to an even more severe reduction obligation/responsibility. For details, see main report, Chapter 3. .


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phase out will be of the order of ~ 2,000 M€ in 2030.17

For the last five years 2025-2030 of the horizon considered in this report, i.e., after the nuclear phase out in 2025, these amounts will be of the same order, leading already to a cumulated extra cost of ~ 10,000 M€. Integrated from the post-Kyoto period 2010, with a first phase out in 2015, the next one in 2023 and a final one in 2025, till 2030, this would lead to an extra cost for CO2 abatement of about ~ 15,000 - 20,000 M€.

18

This extra cost is about 6% to 8% of the GDP of 2000, or 4% to 5% of the GDP of 2030. On an annual basis, during the period 2025-2030, this amounts to roughly 0.5% of the annual GDP of that period. For these GHG and CO2 reductions on a EU level, it is assumed that no flexible mechanisms outside the EU are applied. The 30% reduction of GHG is assumed to be effectuated within the EU. Concerning GHG reductions on a EU scale, Belgium could hope to bargain for a smaller GHG reduction obligation as part of a negotiated burden-sharing agreement, using the argument that its domestic abatement costs are very high due to the nuclear phase out.

19 Besides the fact that with the

horizon of 2030, and with a likely full use of flexible mechanisms within the EU by that time, such a lenient treatment will very unlikely be granted by the other EU member states and one should question whether such viewpoint is ethical at all. The correct attitude would be that Belgium takes the same burden in terms of GHG-reduction cost per personal income as its most important EU trade partners (thus, in terms of reduction responsibility). In doing so, it will then only reduce GHGs domestically in accordance with the lowest abatement cost, at the same time relying on buying emission allowances abroad, to satisfy the balance. In any case, because of the uncertainty on the future GHG reduction obligation for Belgium by 2030, Belgium should not adopt an ostrich attitude and prepare its energy system for a severe reduction, to be ready in time. Consequently, the costs for severe GHG reduction obligations will be very high, unless appropriate policy choices are made, as suggested in our recommendations. Modeling Caveats A possible re-injection of carbon-related revenues into the economy, may lead to some relief, but it turns out to be limited, and actually in this case of second order. First, the extra allowances to be bought abroad to mitigate the effect of the nuclear phase out, do not lead to revenues for the Belgian authorities. Furthermore, a re-injection into the economy (e.g., to lower labor charges) of its carbon-emission revenues for the GHG that Belgium is allowed to emit, may lead to a lower cost for the overall Belgian economy than if no re-injection had occurred, but, because of still existing distorting

17 The amount HD equals 20 Mton/a in 2030 since the Belgian GHG emissions in 1990 amounted to 144.3 Mton, and the triangular-like area ≈ (HD*HG)/2 (i.e., base*height/2) ~ 20Mton * 200 € / 2 = 2 000 M€. For details, see report, Chapter 6. 18 Expressed in constant €2000. 19 In fact, according to environmental economics logic, the decision to phase out nuclear power should lead to the contrary, i.e., a larger GHG commitment in terms of obligation for Belgium. See report, Chapter 3.


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taxes, the overall cost for the Belgian economy will nevertheless be larger than what PRIMES has computed. We recall that the above PRIMES results are subject to the following caveats: (1) the Belgian domestic scenarios only refer to energy-related CO2 emission reductions; (2) the estimated carbon values referred to above should not be interpreted as actual costs of policy implementation but rather as an indicator of the relative difficulty of achieving the constraints; (3) the CO2 abatement costs are a function of the type of policy instruments that are used to reduce the emissions; in the scientific economics literature, one accepts that subsidies, regulations and grandfathered tradable permits tend to increase the overall costs while CO2 taxes recycled via lower labor taxes are less detrimental for the economy than if no recycling would take place; and (4) the environmental benefits of taking appropriate actions to reduce the negative impacts of climate change are not taken into account. It is important to recall that the benefits depend on the world-wide carbon-reduction effort; so climate-change benefits for Belgium are only guaranteed if not only the EU, but all industrial (and developing) nations make an effort.

Security of Supply (SoS) Assuming severe GHG reduction obligations, and under a nuclear phase out without the availability of routine commercial CCS, the import dependency will be very high, especially for gas for electricity generation. This will require a careful policy for contracting the gas supply, via an optimal mix of long-term contracts and spot-market supply of gas. In addition, timely decisions for gas infrastructure (pipelines and storage) will be needed. As to electric power transmission, the three functions of the grid must be kept in mind: contracted import/export (i.e., trade), the balancing of massive correlated intermittent generation in Europe, and keeping sufficient reserve transmission capacity to cope with incidents (i.e., the reliability issue). Timely investment decisions for substantially increased cross-border transmission capacity will be necessary. In case of a nuclear phase out, the full electricity generation system must be replaced by 2030, and even more to cope with the expected electricity demand increase. These investment challenges require that the authorization permits should be granted in time and under a stable regulatory framework. Also, investors must get a fair return; for natural monopolies, the system operators must be allowed to transfer these costs to the customers. In case the nuclear phase-out law would be lifted, many of these SoS challenges would still remain, but the pressure would be considerably less, such that the investments are more easily absorbed by the economy. It must be understood that questioning the actual implementation of the nuclear phase-out law does not hamper the further build up of renewable investments, since that type of investment is not market driven but entirely "subsidy/support" driven. The build up of renewable sources is entirely a consequence of policy-makers' decisions. As already hinted, policy makers must understand what they promise and then abide by their promises.

Liberalized Markets It must be emphasized that in liberalized markets, the price is set by the short-term marginal cost.

20

Only in the long run, average price equals average cost21

, and only so in fully competitive markets. This means that higher prices in liberalized markets are not unusual if marginal costs increase. If production quotas are limited, then prices may go higher as is the case with current oil prices.

22 Gas

20 The marginal cost is the extra cost to produce one extra unit. 21 The return on investment for the shareholders is considered here as an opportunity cost, in the sense that a company can borrow money from the financial market (with a certain interest) or from its shareholders (at a certain return rate) who will only invest if the return is at least as high as it would be for other opportunities that exist somewhere else. 22 For the oil market, other factors such as risk premiums, available stocks, financial speculation etc. also play a role.


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prices tend to align with oil prices. These primary energy-price increases are reflected in higher electricity prices. In addition, the price of GHG emission allowances is added.

23

Examination of e.g., the wholesale prices in the NW-European market shows that the Belgian prices are in line with its immediate neighbors. This is due to enhanced import capacity as of 2005. For the day-ahead market, the coupling via BELPEX appears to have a beneficial effect as well. The wholesale market seems to operate correctly. Even with dominant local players, the liberalization process on the wholesale market seems to function on a NW-European scale. A well functioning retail market needs sufficient suppliers with reasonable market share. This should be the medium-term goal. Via the electricity exchanges, suppliers must be able to provision themselves at the correct price. Regulators must monitor this carefully. It must be stated, however, that given the overall price increases for gas and electricity, the distribution costs for infrastructure upgrade, and the extra levies, customer prices are not unreasonably high compared to the neighboring countries. A well functioning liberalized market requires efficient regulators and a correct understanding between governmental services, regulators, TSO's and market players. The fragmentation of responsibilities in Belgium is not efficient for a good market operation.

Cost of the Nuclear Phase-Out Law Considering the major challenges faced by the Belgian energy economy, it must be concluded that, especially in the light of the daunting challenges mentioned before, and mainly the very stringent GHG-reduction efforts expected, an actual implementation of the Belgian nuclear phase out turns out to be expensive. In fact, Belgium will pay a substantial amount for the premature closure of its nuclear power plants:

Ø By phasing out so much cheap base-load capacity, the electricity supply curve will shift to the left. Because of not-unlimited transmission capacity, phasing out 6000 MW will lead to an increase in electricity prices.

Ø Belgium gives up a cheap way to reduce CO2 emissions domestically; as a consequence, emission allowances must be purchased abroad.

Ø Allowing nuclear stations to continue would allow the state to bargain for a concession fee (basically skimming part of the revenues). Not doing this, amounts to an opportunity cost for the Belgian state;

Ø Giving up nuclear power increases our import dependency; this reduced security of supply has a cost.

Ø By postponing decommissioning, the decommissioning fund will grow substantially. Not taking advantage of this possibility leads to an opportunity cost of the order of about 1,000 M€.

Although not really an actual cost, but an important point in terms of interest for the Belgian state, letting a future government negotiate with nuclear plant owners by using the 'carrot' of a nuclear operation extension, can keep certain elements of the energy system under the control of the Belgian authorities.

This extra financial burden of a nuclear phase out appears to be too high a price to pay, even when considering a disadvantage of keeping nuclear power as an option, namely an increase of the nuclear waste. Indeed, in the final count, the amount of high level nuclear waste will be increased by the same proportion as the operation extension of the plants; i.e., if existing plants are allowed to operate for 60 years the increase will be 50%.

24 But this is a relatively minor incremental cost; and furthermore, it is

paid for by nuclear operators (reduction of their profit in a liberalized market). In any case, a further relying on nuclear power must continue to be subject to the following imperative requirements: - Strict safety regime as before, under international supervision.

23 Which reflect an opportunity cost. 24 The increase of the low-level and medium-level waste is relatively minor.


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- Guarantee that nuclear provisions are available when needed (foreign owner, but also utilization by government).

Overall Conclusion: a Diverse Energy Policy is Needed All things considered, we must conclude that no simple solutions exist; there is no silver bullet. The only reasonable option appears to be to go for an 'and-and' approach rather than for an exclusive 'either-or' one. It is to be avoided to put all eggs in the same basket, and a maximal diversity should be opted for. The Belgian energy policy will have to consist of a balanced mixture of contributing elements. First, if important post-Kyoto carbon-reduction limits are pursued, energy savings will have to be an important component of the policy. Then, a diversity of primary-energy sources and conversion technologies should be opted for, with a cost-effective integration of renewables, whereby the cost effectiveness is best geared by carbon prices rather than absolute objectives. Given the existing constraints and the costs reported, taking into account all hypotheses

25 and uncertainties involved,

and based on the combination of scientific, technical and economic arguments, we are led to conclude, that in case the nuclear phase out is implemented, the expected post-Kyoto constraint is expected to be extremely expensive and strongly perturbing for our economic fabric. Even after having incurred a major part of the very high costs, the risks of not satisfying a reliable energy provision under the assumed constraints, are indeed very large. The circumstances when the nuclear phase-out law has been voted into law have indeed changed significantly; the urgency for climate-change action is becoming more apparent and the era of very cheap oil and gas prices is almost certainly behind us. This facing with current reality and future expectations, requires a reconsideration of the overall Belgian energy policy, including nuclear electricity generation.

25 Assuming that CCS is not available.


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Recommendations

of the Commission Energy 2030

General Guiding Principles Major guiding principles must apply for the Belgian energy policy with horizon towards 2030. Because of its limited scale and impact, the existence of a European environmental policy, the European energy policy 'in the making', and the common European energy market, Belgium is recommended to fully align itself to the European energy framework. This applies to the domains of the common energy markets, energy efficiency, renewable energy, energy infrastructures and nuclear safety, amongst others. The transposition into Belgian law of the EU Directives and Regulations should always be undertaken in a timely manner. Belgium should use the EU context to establish a coherent energy policy of its own, and already start reflecting seriously (and even proactively) when EU policy documents are launched (Commission Communications etc). Also, Belgian ideas should be launched on an EU scale to have the scrutiny of the other EU members and to get support & momentum (if the proposed measures make sense) of the full EU. In addition, Belgium must 'profit' from the EU dimension to negotiate its primary-energy deals with producing countries; unilateral deals must be carefully reflected upon, but Belgium must not be too naive if other Member States go their own way. Given all challenges, i.e., the need for a reliable, clean and affordable energy provision already discussed in this report, and the scenario results & interpretation, it is clear that Belgium cannot afford to put all the eggs in the same basket. We must go for an 'and-and' approach; we do not have the luxury to have too many exclusions. For an effectively almost 100% energy-dependent country, diversity is the only helpful strategy: reduce energy demand, 'produce' indigenous energy (through renewables), choose for a sufficient fraction of storable primary energy in the portfolio, rely on a diversified mix of technologies and primary sources, coming from different geographical regions and all of this in an affordable way and sufficiently environmentally friendly. Aim for stable legislation and regulatory framework based on a coherent long-term vision. Set clear long-term targets and let the market actors then invest within that frame setting. The Belgian energy responsibilities must be streamlined and harmonized. Different philosophies and approaches seriously hamper a coherent energy policy. Amongst others, four typical examples can be given:

• Concerning transmission and distribution of electricity there is confusion. Everything equal and lower than 70 kV is a regional competence, but the lines with a voltage of 30 to 70 kV (both values included) are operated within the framework of the integrated TSO Elia.

• All tariffs are set by the Federal Authorities, regardless of which level is competent. • The introduction of liberalization for supply and retail has been at a different speed in the

Regions, not helping the effectiveness and efficiency of the whole transition. • The support schemes for green electricity and cogeneration differ in the Regions, hampering a

good development of renewable and CHP-based electricity generation in Belgium. For all these domains, independent of the political choice to put the responsibility at a particular level, the approaches should be harmonized, and even considered in a broader European context. Exchange of green and CHP certificates in Belgium and on a European scale is a good example.

Given the long lead times for implementation of infrastructure investment decisions, and with the concern for security of supply regarding all energy carriers, but especially electricity and gas, Belgium should prepare for a considerable post-Kyoto GHG reduction effort, thereby avoiding an ostrich attitude. Also, Belgium should not count/rely on 'generous' EU burden-shift escape routes since such attempts might in the end not be accepted by the other EU Member States (especially if high abatement costs are a consequence of deliberate own choices). Belgium should define its medium


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to long-term energy policy taking into account a substantial domestic GHG reduction effort and/or keeping in mind the possible costs for financing emission reductions abroad through, e.g., emission trading.

Concrete recommendations

1. Belgium must do all that is 'reasonably acceptable' to exploit its potential on energy savings.

First and foremost, a behaviorally conscientious attitude with respect to energy use should be advocated through education and general information transfer, in schools and towards the public at large. Energy is a scarce good and should be highly valued; automatic reflexes for unwise/inadvertent use of energy are to be discouraged. Demand for energy services

26 should possibly be mitigated and

the desired level of energy services should be provided by using efficient technology. Timely transposition of all EU efficiency-related directives is called for and novel, effective, efficient and non-conflicting own supplementary measures must be considered. In particular, matters such as energy-performance standards for buildings must be implemented earnestly and strictly enforced, as required by the related EU directive. Especially given the long-term consequences of this sector for energy efficiency, these transpositions should be done in a harmonized way and in collaboration with the building sector. This energy-performance concept includes the appliances within the buildings.

27 Determinate action is required now, but short-term

expectations should be tempered because of the long time constant in the building sector. Even in the time frame of 2030, although considerable progress can be made, miracles cannot be expected. Special attention is required for the education & training of more energy-technical-oriented architects and energy-conscientious contractors. In line with the current EU directives, Public Service Obligations regarding an energy-savings (and not only electricity-savings) target should be put, based on market-compatible measures, implemented by e.g., distribution grid operators, and the results must be closely monitored. A comprehensive impact analysis of a net energy-savings target of …1.5…% per year requirement (compared to business as usual projections) must be studied as part of the strategy. Quality Cogeneration is to be continually encouraged and supported to implement the energetic potential based on the heat demand existing at the time of implementation. Transport-related energy use is linked to the more global issue of mobility. Air & noise pollution, GHG emissions and road congestion are major problems in this context, especially for Belgium with a logistic function in Europe. This requires a holistic approach, including road, rail, water and air transport, passenger and freight transport, private and public transport, congestion control, road safety etc. Well thought-through measures, without taboos must be considered. Solving the mobility issue appropriately, may lead to energy savings and emission reductions. As examples, we mention the following (not all necessarily equally efficient) measures:

a. To discourage 'superfluous' use of road vehicles, road-congestion charges and road taxes (per driven km) may have to be levied;

b. The offer of public transport and non-motorized transport means in priority areas should be increased;

c. To reduce emissions of vehicles, the annual traffic tax on heavily polluting vehicles, as a function of their emissions, may be considered;

d. Increasing fuel efficiency standards, based on agreements with car manufacturers can be encouraged. Targets should be ambitious, but cost efficient and realistic. Belgium should

26 By "energy services" is meant the activities and applications we wish to enjoy: heat rooms to comfortable temperatures, keep food and drinks cool, drive kms, provide drive power and process heat in industry, etc. This concept here is different from the "services" provided by so-called "energy service companies (ESCOs)". 27 Although separate standard and labeling directives exist, to put pressure on the manufacturers and to better inform the potential buyers of efficient equipment.


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play a stimulating role in the EU to establish the criteria based on sound cost-benefit analyses.

Industry must be incited to further concentrate on energy efficiency, both energy-intensive and the smaller industries. The voluntary and audit covenants are welcome tools when cleverly combined with the allocation of emission allowances. For all of the above, general strict rules must be set, with 'appropriate' exceptions or compensations for especially sensitive segments or sectors (energy-intensive sector, particular types of transportation). The main determinant here is the international extent of the post-Kyoto efforts. If the efforts are limited to the EU (and even the EU + USA), there are severe limits on the carbon-reduction efforts that can be imposed on certain sectors.

2. To reflect scarcity of energy as an economic good as well as the external costs due to various energy-conversion processes, to avoid wasting of energy and keep sufficient pressure for rational use of energy, and to optimize load time management, energy price increases must be fully passed on to the customer.

A pilot project on 'real time pricing'

28, to assess the potential of the instrument should be

undertaken. Rebates and special lower tariffs on energy should be avoided, unless there are justified reasons to do so and unless other means for social correction have been exhausted. It may be necessary to foresee certain financial compensations for the lower income groups. Also, appropriate measures may have to be foreseen such that lower income groups can equally benefit from energy-efficiency measures. Detailed but neatly arranged information on the price breakdown (commodity, transmission & distribution charges, levies, (excise) taxes & VAT) on the invoices is to be optimized/provided. To optimize demand-side management on the retail side, ample attention to metering and interaction between supplier and customer is needed. Combined with the progressive introduction of distributed generation, sufficient investment for the modernization of the distribution grids for electricity and gas (towards eventually a smart grid) is inescapable. The cost for these infrastructure investments will be high and must be imputed to the customers. Connections to the high voltage or high pressure networks for electricity and gas, respectively, must contain price signals reflecting congestion and other costs in certain areas. TSOs should have the permission by the Regulator to charge them.

3. According to the present analysis, the achievement of stringent post-Kyoto targets of the order

of 15-30% by 2030, for domestic reduction in Belgium without nuclear power and in the absence of CCS, is expected to be extremely expensive. (Reaching these post-Kyoto targets will already maximize the technical potential use of renewables and a considerable part of energy savings as shown by the energy intensity decrease.) Furthermore, if similar European reduction targets are considered with the possibility of emissions trading, also without nuclear and CCS in Belgium, GHG abatement for Belgium will likewise be very expensive, unless the EU burden sharing turns out to be very favorable for Belgium.

Non-nuclear and non-CCS scenarios result in an overwhelming dependence (90% in instantaneous power terms) of natural gas for electricity generation and conflicts with the objective of security of supply.

28 Real-time pricing assumes that customers have appropriate meters for gas and electricity, whereby an instantaneous and thus fluctuating price, at any moment of the day, rather than an average or fixed tariff, is paid.


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To alleviate these burdens, and in addition to relying on energy savings and renewables, Belgium is therefore advised to

- reconsider the nuclear phase out, and - to stimulate the timely development of CCS

Lifting the Nuclear Phase Out When reconsidering the nuclear phase out, to keep sufficient pressure on the energy system towards the transition to a more sustainable energy basket, a negotiated agreement with the owners of the Belgian nuclear power plants is to be sought for, to make them pay a “correct”

29 concession

fee/rent. The thereby collected revenues could be used by the government for stimulating investments in energy savings & demand-side management, for development in renewable energy, for development & research in emerging energy technologies and carriers.

30 The Dutch Borssele

agreement, explicitly established via a Covenant and the establishment of a sustainability fund, may serve as an exemplary source of inspiration. As part of this agreement, earlier agreements that were made in the context of the nuclear phase out should be revisited. The operational lifetime of the existing plants should be left non-limited a priori

31, in the sense that

the prime requirement should be the continued safe operation of the plants. The safety of plants is to be thoroughly examined on a ten yearly basis (by means of the 10-year overhauls) and the state of the plants (thereby requiring possible upgrading investments) must be approved by the nuclear supervisory bodies (amongst which the Nuclear Regulator), possibly confirmed by an international audit.

32

Operation of nuclear power must continue to live up to internationally accepted standards, for safety aspects, radiation protection, waste management, proliferation, and be subject to both national and international scrutiny and supervision (through bodies such as the 'Recognized Safety Authority', FANC/AFCN, NEA/OECD, IAEA, Euratom, WANO). Although the current nuclear liability coverage is already substantial, it is recommended that in an EU or OECD context, Belgium advocates the idea to set up an EU or OECD-wide but nuclear operator/owner-funded and -managed liability fund to cover the extra liability in case of a severe accident. This nuclear liability partnership should be funded pro rata of the nuclear installed capacity within the EU or OECD.

29 The level of such fee/rent is to be evaluated by an independent international commission, as discussed under point 6 of these recommendations. 30 According to economic theory, this is not the most efficient way of spending these revenues. The magnitude of the rent or tax revenue may be larger by several factors than the needs for subsidies for renewables, energy savings and demand-side management. Caution must be expressed against over-subsidizing because of this earmarked money; any justifiable investment —including for renewables, energy savings and demand-side management— must pass a cost-benefit test, also accounting for its environmental benefits. The remainder of this nuclear rent may be devoted to other valuable means, such as lowering labor charges or reducing the national debt. 31 Note that "non-limited" is to be distinguished from "unlimited". 32

J.P. van Ypersele (JPvY) disagrees with the idea contained in this paragraph that the nuclear plants operational lifetime should not be constrained at all. The reasons invoked by the law of 2003 to limit the lifetime of existing plants are still valid in JPvY’s view. However, JPvY observes that the Belgian authorities have taken very few measures to avoid a large increase of CO2 emissions when the nuclear power plants are closed down, in particular if ambitious energy-efficiency improvements and carbon capture and storage (CCS) techniques are not implemented by then. The indicative numbers coming out of the PRIMES modelling study prepared by the Federal Planning Bureau for this report reflect this lack of foresight and political courage. If Belgium wants to reduce its greenhouse gas emissions by factors of 2 to 6 in the coming decades to meet the climate challenge, the present trends in energy consumption (not only electricity) are clearly unsustainable. Given the time lost since 2003, and the time needed to obtain results, JPvY thinks that the operational lifetime of those Belgian nuclear power plants which can tolerate it without reduction in safety or large investments should be extended now by five years only (over the 40-year lifetime decided in the law of 2003), with significant amounts collected through the “Borssele” system to fund part of the transition of the Belgian energy system towards a much lower energy usage, a higher renewable energy usage, and much lower greenhouse gas emissions (such as described in the “backcasting” scenarios developed by the Federal Planning Bureau for 2050 at the request of Minister Tobback). It would also allow for ambitious measures to be taken to facilitate this transition, without increasing too much the final consumers’ energy bills. This five year extension only makes sense if the delay is not just used to save time and continue doing almost nothing in other areas of energy, transport, and climate policy. JPvY is convinced that the tax or rent revenues from the “Borssele” system should preferentially be used to fund the energy transition evoked above, in the most cost-effective way, as the budgets needed for the transition will most likely be much larger than the “Borssele” funds.


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In case new nuclear units are considered, a clear and transparent regulatory framework must be set. The economics of such project must be left to the investors' market. To support such framework, a participatory process with societal stakeholders should be undertaken, based on a broad cost-benefit analysis, with the aim towards a "sustainable" energy provision. Such process should lead to advises upon which policy makers can base themselves to set the conditions for new nuclear build.

33

Carbon Capture and Storage (CCS) Although lacking power-plant manufacturers, Belgium must collaborate strongly internationally on the development of Carbon Capture and Storage (CCS). A commitment must be made to have at least one experimental pilot carbon capture plant operating no later than 2030 on Belgian territory, privately or publicly funded.

34 Administrative and

scientific research on possible geological CO2 storage sites must be amplified strongly, so as to know clearly by 2015 what the possibilities for CO2 storage in Belgium are, with the possibility to then launch a pilot research program in situ, if justified by the results of the research. Screening of potential gas-storage sites in nearby/neighboring countries and study of transport costs of CO2, not neglecting the possible competition/interaction with natural-gas flexibility requirements, is to be undertaken in order to have a reasonable idea of long-term possibilities.

4. Because of limited domestic potential of renewables, Belgium should implement the EU directives in a clever and justified way to contribute to a healthy European energy mix and environmental-burden reduction.

Towards an efficient long-term perspective, Belgium should not commit to quota for local ‘production’ of renewable energy, but rely on market mechanisms where carbon value is the best guide for the expansion of renewable energy in Belgium and abroad. As a first step, one could accept and should plead for (perhaps ambitious) quota (in % terms) for supply of renewable energy to the end customers coupled to full EU exchangeability of green certificates or certificates of origin, so that investors are stimulated to invest at the best locations in Europe.

35

In a transition period, judicious local production of renewable energy at acceptable locations must be steered through the penalty value of the green certificates. Depending on the source, subsidy must be tailor made; over-subsidy leads to improper use of public money. Blending of biofuels for transportation should be aligned on a European scale and the impact of excise tax breaks for the public finances must be comprehensively evaluated. The cost effectiveness for CO2 abatement of the full life cycle and the sustainability of the supply chain (taking into account

33 J.P. van Ypersele strongly disagrees with this paragraph about a new nuclear plant. He really does not think that new nuclear units should be built in Belgium. In his opinion, nuclear energy should not play a major role in the efforts to reduce greenhouse gas emissions at world level. The last IPCC report (IPCC WG3, 2007) puts much more emphasis on the potential of energy efficiency, carbon capture and storage, and renewable energy to reduce global emissions, than it did to a nuclear expansion. In the long term, we have to contribute in the development of a world energy system that relies much less on stocks of fossil and fissile fuel, because they are inherently finite. We need instead to learn to harness the flow of solar (and other renewable) energy which equals about 8000 times the total world energy consumption per year. It is important to capture that renewable flow in the most efficient way, and some of that is probably best done out of the Belgian territory. Harnessing this flow will reduce the risk of “running out” of fuel (the Sun will indeed continue to provide its energy to us for another 5 billion years), reduce the risk of proliferation of nuclear material, reduce the risk of large scale accidents or nuclear terror activities, and reduce the amount of nuclear waste we leave to future generations. To make this possible, we need to dramatically increase energy efficiency, and manage demand so that energy usage per capita converges towards sustainable levels, taking into account local circumstances. In the transition period to such an efficient world energy system relying mostly on renewable energy, and as advocated by the European Union, we urgently need to use carbon capture and storage on our fossil fuel plants, and participate in the diffusion of this technology in all countries with large fossil-fuel reserves. Building a new nuclear plant in Belgium would only postpone the needed transition towards a more sustainable world energy system. 34 Note that the experimental nature of such plant does not permit to rely on it for routine carbon capture. 35 This means that all suppliers must demonstrate that at least x% of the electricity delivered to their end customers originates from renewable sources, regardless of where these are generated. With such schemes, and free exchangeability of European green certificates or certificates of origin, Belgium may be subject to the same level of renewable obligation (e.g., 20%) as the EU. It must be understood that these 20% need not be produced domestically, however.


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possible competition with the food chain, deforestation, and other applications), should be carefully assessed, however. Belgium should reconsider its offshore wind policy and be more forthcoming in the concession allocation of sites. In order to be serious about offshore wind power development, the authorities should re-examine the sites of the 'Wenduine Bank' and the 'Vlakte van de Raan', as these sites may offer a reasonable degree of technological success at an acceptable cost. Far offshore sites are not to be dropped, but should be developed meticulously. Through a carefully designed staged process, an international leading role for far offshore can be established. 1) In the context of the current projects, it should be encouraged to use different technological options, which are to be observed very carefully (measurements, maintenance, corrosion, etc) during a sufficiently long period to be defined on a technical basis, and during which careful comparisons with international projects are made. 2) Continue up to a few hundreds of MW only when the results of the first phase are successful. 3) Make an in-depth study of the grid connections: link with the possible HV cable to the UK, study of the connection with “Supergrid”

36, possibility of organizing a common connection

point offshore, high-voltage-network absorption & extension and power-generation back-up study, with clear cost figures before embarking on >900 MW plans. If prospects are positive, go for it with strong determination; if prospects range from dubious to negative, have the realism to call it off and reorient. The costs for sea cables for far offshore investments, starting from the pilot plant all the way to the massive build up, could be socialized

37 if the costs remain acceptable to society. Here, however,

contribution from the above mentioned 'nuclear phase-out repeal fund' could be a welcome financial injection.

5. On security of supply, four aspects are to be focused on as priorities.

Diversity of supply of primary sources and technologies (type and origin) is the first and foremost rule. Especially the gas provision must be carefully observed. An optimal mixture of long-term and spot-market contracts must be strived for. A comprehensive study to find the appropriate energy mix (including renewables, gas, oil, coal, uranium), based on the portfolio theory must be effectuated for the Belgian situation. A stable investment climate must be guaranteed for competitive market players to have sufficient new electricity-generation capacity, to keep a substantial refinery capacity and to have sufficient gas-storage capacity. For supported technologies, such as renewables, governments must guarantee that commitments for support made are honored. Transmission and distribution networks must be 'allowed' to invest in extensions, adaptations, and preventive maintenance, so as to avoid blackouts and to allow the connection of renewables and to facilitate the European market; the Regulator must accept the costs involved being transmitted to the customers; environmental and construction permits must be delivered timely by the competent authorities.

6. The liberalization process for electricity and gas in Belgium must be developed in line with the common European energy market concept.

A stable and transparent regulatory framework, properly harmonized between the Regions and the Belgian Federal level, and at the EU level, is called for. Efficient regulators, sufficiently independent of the government (but properly held accountable for their actions), are expected to enforce and supervise regulation. Harmonization of Belgian regional and federal regulatory decisions is imperative.

36 Supergrid is an initiative to connect all sides for offshore wind along the Atlantic coast and beyond. 37 In the sense that eventually, costs may have to be transmitted to the final electricity customers.


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Both for domestic and international regulatory level, review/recourse/appeal by/to the European Commission must be defended by the Belgian Member State at the European Union level. One single wholesale market, at least in NW-Europe must be advocated, by establishing sufficient cross border transmission capacity. Regulators must oversee potential abusive behavior, while allowing the investments for building cross-border lines as a basic element for market development. Imposed regulated prices at the wholesale level are advised against, but possibilities of partnership between large energy consumers and producers should be envisaged (guaranteeing security on long-term pricing). Sufficient Retail market access should develop over time to reach a good mix of suppliers in Belgium. Regulated capped prices at the retail level are advised against. Strict supervision by the Regulator is necessary. Vertical unbundling is necessary in the sense that only generation and retail can remain inside the same company. The transmission and distribution activities for electricity and gas must be legally unbundled (as prescribed by the EU Directive). Full ownership unbundling does not seem to be necessary as long as strict corporate governance rules are applied. The presence of large shareholders is an advantage to raise capital for infrastructure investments. If such approach proves to be impossible or unrealistic in practice, other routes such as 100% ownership unbundling or the establishment of an Independent System Operator (ISO)

38, should be examined.

An independent multi-international examination on the issue of alleged “unreasonable” windfall profits as a consequence of earlier depreciated generating capacity now operating in a liberalized environment (so-called possible stranded benefits) must be undertaken. The experts commission must preferentially be populated by non-European experts, i.e., well recognized energy-economics and/or corporate-financing university professors and Regulators of OECD countries with liberalization experience (e.g., USA, Canada and/or Australia). Both the Belgian Regulators and the generator concerned must be heard by this commission to express their viewpoints. It must be recognized, though, that the existence of these “inframarginal rents”

39 is independent of the number of electricity-

generating operators.

7. Belgium should devote much more research & development means in energy.

To maximally profit from economies of scale, substantial financial incentives must be given to research groups for participation in European projects. European energy research priorities have been identified [CEU, 2005 & 2006]. Supplementary Belgian energy research, development & demonstration should be prioritized:

- behavioral research on public willingness to opt for rational use of energy and ways to stimulate it;

- energy research should cover all relevant sectors such as transportation, residential, commercial & service sectors, industry, gas and electricity sectors;

- individual R&D grants for selected manufacturers to develop further 'super efficient' equipment;

- clever interaction of suppliers and customers through smart grids for electricity and gas, comprising active demand-side management and distributed generation;

- further research on renewable energy, such as phased offshore wind-energy development, high-efficiency conversion of biomass, advanced grid-integrated PV and others;

- comprehensive system and grid integration of non-dispatchable generation; - carbon-capture pilot plant and CO2 storage research; - nuclear-system development for further improvement of the nuclear route; - energy-system model development should be supported to have a strong Belgian basis

in order to acquire sound mastery of the ins and outs of comprehensive energy

38 In the sense as defined in the EU Commission energy package of January 10, 2007. The concept of ISOs has not been proven anywhere, however, as far as investment incentives, maintenance etc. is concerned. 39 See Informative Box in Report


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modeling. Own Belgian model development work is to be encouraged, whereby later European integration with other models should be kept in mind from the outset. Interaction within international/European frameworks is therefore to be encouraged.

8. Education & Training in energy

Although not actually studied, the CE2030 nevertheless expresses its concern about appropriate education in energy matters, both for the public at large and for energy professionals. High-school education programs should contain an important segment on the scientific & technical aspects of energy provision, the overall energy issue, and the relationship with prosperity, development and sustainability etc. Non-biased education based on facts and figures and the laws of nature is called for. The authorities are invited to make an effort to stimulate (advanced) studies in energy science and engineering. Lack of a sufficiently capable professional pool of experts will hamper us in meeting the energy-related challenges faced in the future.

9. Belgium should establish a sustained/permanent Strategic Energy Watching Brief

Rather than solely relying on ad-hoc Committees (such as the AMPERE Commission and this CE2030 Commission), it is recommended to establish a 'permanent' and structural follow-up process to guarantee conscientious observance (or disregarding) of the recommendations of 5 to 8 year interval Major Review Exercises. This Watching Brief must be organized such that it involves at least the Federal and Regional Energy Administrations and Energy Regulators, the Federal Planning Bureau, Energy & Environmental Scientists & Economists, perhaps enlarged with other stakeholders of society. This Watching Brief exercise is best supervised by an independent core group. A limited-size but formal follow-up document to the government should be established on an annual basis. To make this follow up successful, sufficient and efficient gathering of correct and coherent energy-related data must be transferred timely to the Federal Economy Administration, which must be given sufficient means to establish a reliable database.


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Part I

Context,

Issues to be Addressed,

and

Elements of Solution


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1. Scope, Boundary Conditions & General Hypotheses

1.1 The Commission ENERGY 2030, its Mission and the Scope of Activities The Commission ENERGY 2030 has been formally established by a Royal Decree issued on December 06 2005 (publication date MB/BS December 19 2005, p 54239), under the auspices of the Federal Minister responsible for Energy, Marc Verwilghen. The terms of reference state that the CE2030 is expected to develop a report outlining the strategic choices for the Belgian energy policy on the medium and long-term time scale. More specifically, the terms of reference ("note de cadrage / situeringsnota" available at http://www.ce2030.be) can be paraphrased as follows. «The essential objective of this study is to submit a scientific and economic analysis, necessary to guide Belgium’s energy policy choices towards the year 2030. It will stress the economic, technical, social and environmental aspects of the different options or scenarios of investment policy in production, storage, and transport, considering the different sources and types of renewable energy and the aspects of security of supply and energetic independence. It also will have to taken into account the competitiveness of enterprises, the evolution of regional and national demand for energy, the observance of environmental commitments and the maintaining or the development of the technological know how. The evaluation of the scenarios concerning energy policy will at least cover the following items:

Ø A worked out evaluation of the economic and environmental impacts of the different options of energy policy in the medium and in the long term;

Ø The updating of the conclusions40

of the previous Commission on the Analysis of the Modes of Production of Electricity and the Re-evaluation of Energy carriers « Commission AMPERE », set up by Royal Decree of 19th April 1999, by integrating in it, an analysis of the economic-, social an environmental costs;

Ø An analysis of the instruments that have to be implemented in a liberalized market in order to reach the objectives of the energy policy of the country; this analysis specifies the feasibility of the different options, taking into consideration the possible private and public investments and the attitude of the actors in a liberalized market;

Ø The measures that have to be taken in order to prevent large-scale electric blackouts. The study will elaborate different alternative scenarios, representative for the strategic options to be analyzed and if possible quantify the advantages and the disadvantages from an economic, social and environmental point of view. In addition, one also will have to evaluate the plausibility of these scenarios (availability of investments, be it private or public so as to delineate the options, the behavior of the operators in a liberalized market …). In conclusion the study submits a proposal of strategic options in the medium and in the long term.» Before embarking on our journey, it must be stressed that this report will try to provide most economic consequences of the choices made for the energy system. However, it is not straightforward to find out what the exact overall cost of energy provision would be for the entire economy. This could be done approximately, but on a time horizon of 2030, it seems to be questionable to do this sort of evaluations, since especially the future change in industrial fabric of our Belgian society is unknown.

40 The Royal Decree states literally as one of the objectives that the CE2030 should "update the techno-economic data of the AMPERE Commission". This has been done throughout this report, supplemented with the techno-economic data available from the European-type AMPERE study, EUSUSTEL, run over the years 2005-2006, http://www.eusustel.be. However, as clarified in the "terms of reference" document, it is to be specified that an important objective is to update the conclusions of the AMPERE Commission in the light of this new study. Note also that the CE2030 study is broader than AMPERE in that it considers all energy sources, carriers and sectors, and makes some reflections on the liberalization process.


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Indeed, the long-term nature of our modeling, with the horizon towards 2030, makes it difficult to make a broad 'analytic' economic analysis, as the future Belgian economy will be strongly determined by the European economy and its own economic structure at that time, prescribed by the degree of innovation, the future weight and evolution of our industrial and service sectors, etc. Will Belgium still have a strong industrial sector in 2030, or will we become a major service-oriented country, centered about the EU institutions? In that sense, the economic importance of energy provisions is difficult to pinpoint in exact numbers. Furthermore, there does not seem to be a simulation model available to perform that task.

41

But based on the information provided here, policy makers should be well informed on the economic energy-related picture and be able to make the appropriate policy choices.

1.2 The External Review Process and the Final Report As part of the CE2030 process, the preliminary report, publicly released on November 17, 2006 and available at http://www.ce2030.be, has undergone a thorough review by several Review Panels. The following organizations/institutions have participated in the review: * Belgium:

• the Federal-Regional consultation cell (ENOVER/CONCERE) • Central Council for the Economy (enterprises & unions) • National Bank of Belgium • the members of the Regulatory Forum (CREG, VREG, CWaPE, IBGE/ BIM) • Federal Council for Sustainable Development (CFDD/FRDO) • Belgian Academy Council for Applied Sciences (BACAS)

* International: • International Energy Agency (IEA) • Directorate General Energy of the European Commission (CEU - DG TREN)

The CE2030 first wishes to thank the review panels for the efforts made and the time devoted to the analysis of the preliminary CE2030 report. The information exchange and their formal advise have been most useful in the reflection process towards this final report. The CE2030 has analyzed and evaluated the comments made by the Review Panels and has taken into account the relevant and pertinent remarks for this final version of its Report. Although some comments have been more to the point than others, most of them have been useful, since each question, remark or comment has made us think again and double check the data used. As a consequence of this process, the report has been completely restructured and about half the report has been rewritten and supplemented. Therefore, this final report is substantially different from the preliminary report. The original idea of the review process has been to have an independent review of a preliminary report, in much the same sense as the "refereeing process" for scientific manuscripts submitted to scientific journals. Some panels have done that job carefully (and properly strict according to the Scientific Method), with the result that many of their remarks were pertinent. These remarks have been taken into account to a large extent. Nevertheless, this does not mean that we have accepted all comments/critique as being valid or justified. In those cases, however, we have clarified our position and have tried to better explain what we mean and have in mind. Other panels (especially the regulators and the regions) have focused to a large extent on the short term picture. This is natural as these bodies usually have to concentrate on the next few years up to maximum ten years. The CE2030 much appreciates the comments made, especially to check the

41 The model HERMES can only project forward for about a 10 year time period.


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correctness of our starting point, but towards the longer term, some of the remarks made have to be put in perspective. Yet some other panels have suffered from focus and have regrettably diluted their message by giving a totally split advise, often not based on factual arguments, but more on "general philosophical principles". Furthermore, the independence of these panels is open for debate, as large parts of the advice of one panel have been copy-pasted into the advice document of a different panel. Nevertheless, the CE2030 has tried to study the comments carefully, and has taken all valuable comments on board. Finally, after signaling a few minor points, the international reviews (by the IEA and the CEU) of the preliminary report, were very positive. The CE2030 appreciates that the exercise performed in Belgium has been recognized abroad as an important piece of work towards a solid national and European energy policy. The review reports of all panels will be made available at the CE2030 website: http://www.ce2030.be . As already announced, the CE2030 final report has been substantially rewritten, compared to its preliminary report. Amongst others, many so-called Informative Boxes have been added, clarifying particular subjects. As to the contents, we believe that the report and its analysis are now more robust. Three major changes/additions have been made:

ü an EU-wide exercise of greenhouse-gas reduction, in which Belgium participates, has now been analyzed, in addition to the domestic CO2 reductions considered before. As a consequence, the CE2030 has a better grasp of the consequences of stringent GHG emission reduction constraints by 2030;

ü the security of supply issue for especially gas and electricity towards 2030 has been

developed considerably more than in the preliminary report; ü it has been tried to better justify what the expected cost implications are of particular

energy policy choices.

1.3 The Energy Scene; Approach & Philosophy of the CE2030

It is difficult to overestimate the role of energy in our society. Simply stated, energy is effectively a 'conditio sine qua non' in the sense that without energy, the whole societal fabric as we know it today would simply collapse. We do not say that our affluent societies need to continue consuming as much primary or final energy as they do today, but it seems natural that our future activities will increasingly rely on more energy services than we currently utilize. Taking into account the expected skyrocketing demand for energy in the emerging economies (amongst which especially China and India) over the years to come, it is clear that tensions on the global energy market will only rise. The world-wide demand for energy will certainly increase throughout this century; this will have to be met by a mix of primary energy sources (including renewables) and better technologies for 'production', conversion and end-consumption. If most of the energy services continue to be satisfied through the use of fossil fuels, then we will have to cope with the threat of Climate Change and the concern for Clean Air, and the fact that hydrocarbons are dominantly concentrated in a particularly geopolitically often unstable region, with possible consequences for the strategic security of energy supply. Although it is accepted that enough energy is physically available, the challenge consists of providing that energy at affordable conditions. Add to that that Belgium has not been 'blessed' with primary


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energy sources, i.e., no 'stocks' at all and a very limited potential of renewable 'streams' due to its geographical location. As many segments of our economy are highly dependent on energy, it is clear that more expensive energy amounts to a net loss for our economy. The above effectively hints what the CE2030 pragmatically considers as a sustainable energy provision. Although many philosophical reflections can be contemplated with regard to this actually abstract concept, we opt for a practical and pragmatic interpretation. In what follows, a sustainable energy provision is one whereby energy provision is at the same time (i.e., simultaneously) reliable & secure, provided through clean & safe processes, and at affordable cost & prices. These three elements are in turn the great challenges to overcome in the energy theater. [D'haeseleer, 2005]

42

Given the global situation and challenges, it is of uttermost importance that a country like Belgium organizes its energy provision such that we secure a future sustainable energy provision. Key elements towards that goal will be ambition and creativity, but common sense and a vigilant realism are equally important. On the demand side, obvious wasting of energy should be avoided, energy loss and leakage is to be limited, and energy conversion should be as efficient as techno-economically possible and socially acceptable. On the supply side, diversity of supply of imported primary sources, in nature (taking into account their storability) and in geographical origin, can mitigate possible supply perturbations. Also, although limited, indigenous renewable fluxes must be captured whenever justified, as they can reduce import dependency albeit on a very moderate scale when limiting their origin to the Belgian territory. In addition, sufficient 'high-quality' energy-conversion equipment, adequate transport capacity and 'intelligent' distribution equipment must be installed to be able to reliably deliver the end-energy carriers to the consumers. This applies especially to the timely and reliable delivery of electricity (avoiding interruptions and blackouts), but also of gas in 'all' (i.e., 'winterish') circumstances. Towards that end, a stable, transparent, and well harmonized regulatory framework for the domestic energy market, as part of a wider European markets must be ensured. All these issues will be addressed in this report. It must be clear that we no longer have the luxury to be complacent about a firm energy provision or to focus on one single issue, as might have been the case in the 1990s, when energy was very cheap and we lived in a quite stable (post cold war) world and regulatory (i.e., 'regulated') environment. Given the current-day circumstances, challenges and threats, we have no choice but to look at the overall picture, in all corners, and viewed from all angles. Matters are becoming more serious and urgent; there is no place for lightheadedness or loose wishful thinking! At this stage, it can already be said that there is no silver bullet to 'solve' the energy issue, but that the only reasonable 'solution' will consist of a variety of approaches, implemented and utilized according to the best of our ability, and in a well organized, transparent and efficient manner. Keeping all this in mind, the CE2030 has approached its task against the following background and with the following principles. 1.- Belgium is considered to be part of a common European energy market, liberalized according to the EU directives (and the anticipated follow ups towards a full fledged integrated market by 2030). This means that market forces should be allowed to function properly, with all market players operating on a level-playing field, and that the authorities are not expected to intervene haphazardly at will. In this framework, authorities have a crucially important role to play, but at their proper place. (Its role is elaborated on in point 2, hereunder.) According to the European common market philosophy, no distinction should be made in principle between energy-market actors from other EU members states and those from domestic origin. One should, in principle, not distinguish between e.g. French, Dutch and German generated electricity, compared to Belgian generated electricity, as it is not appropriate to distinguish between Flemish and Walloon, or for that matter province-related origin. 2.- Through legislation, authorities are expected to set a clear and stable regulatory framework for ambitious but well thought through policy goals concerning market functioning, health and environmental protection, and security of supply. The long-term stability of this legal framework is to be stressed, as is a minimum harmonization of the Belgian regional and federal energy legislation.

42 For an in-depth review of the meaning of sustainability, reference is made to [Laes, 2006], chapters 1 & 2, and references therein.


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Obviously, the overall Belgian framework has to be in line with European rules. In addition, the authorities must rely on strong, independent and efficient regulators which supervise the market and intervene when abuse occurs. The authorities are expected to set certain norms and standards or quota, and then let the market players try to find the most efficient way to comply with them. The overall guideline should be to maximize the efficiency of our energy theater, subject to well-justified constraints, and with healthy vigilance towards unexpected perturbations. As to the constraints, this applies, e.g., to maximum emission levels of greenhouse gasses (and especially CO2), of a variety of pollutants, to setting maximum standards on radioactive effluents and radiological doses. For all these, however, the authorities have to carefully reflect on the values set: for health and safety related values, sufficiently strict but realistic values are to be imposed (obtained via, e.g., comparative risk and cost/benefit analysis, and aligned with European or worldwide accepted standards). Given these basic principles, the CE 2030 has the conviction that no energy-conversion method should a-priori be excluded from, nor favored in the energy mix, based on emotional arguments. Any technology should be equally considered at the outset, but will then have to satisfy a variety of minimal criteria and requirements (usually expressed by the regulatory norms and standards) before being considered for actual implementation. 3.- The CE2030 is well aware of the current legislation in Belgium and Europe, and will use that as a starting point for its reflections. However, given the horizon of 2030, the CE2030 will not deal with short-term regulatory issues and focus on the long-term picture. However, wherever the short-term influences the path towards a long-term energy strategy, throughout this study the CE2030 will take the liberty to suggest some regulatory adaptations or new legal initiatives. In addition, policy recommendations will be made. It belongs to the prerogatives of the authorities (starting from the parliament(s) downward) then to decide what to do with it.


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2. Current Situation in Belgium and Historic Evolution As stated above, it is not the aim of this report to provide an exhaustive overview of the energy situation in Belgium. That information can be found elsewhere. First and foremost, the prime reference to be mentioned is the IEA 2005 Review of Belgium [IEA, 2006a]. The IEA Review deals with the whole Belgian energy economy, i.e., all sectors and all energy carriers and primary energy sources. It gives a quite accurate and complete picture of the state of affairs end 2005 and is highly recommended as background document for this report. In addition to a state of affairs, the international independent panel of experts gives a critical review of the Belgian situation and provides a series of pertinent recommendations. Although the CE2030 report shares many of the recommendations, it should be recognized that the IEA Review serves a different purpose than the CE2030 report. The IEA experts have made a picture of the present situation and concentrate on a horizon of the next five to ten years, as another Review will take place in five years. The CE2030 report has a much longer time horizon, and will deliberately bypass short-time issues, unless they affect the longer term energy future of the country. General information is also available from the Supporting Documents [DG Energy, 2006; Dufresne, 2006]

43 In addition, relevant information can be obtained from the website of the Ministry of Economic

Affairs, DG Energy at http://mineco.fgov.be à Energy. Additional interesting information on the current state of affairs in Belgium for electricity and gas, can be found in the Indicative Programs for Electricity Generation [CREG, 2005], the Indicative Plan for Supply of Gas [CREG, 2004], the Development Plan 2005-2012 for electricity transmission [ELIA, 2005]. Also as general background documents, we mention the report of the AMPERE Commission [AMPERE, 2000] and the Fraunhofer study [Fraunhofer, 2003].

43 See Supporting Documents; annexed to this Report.


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2.1 Historic Evolution of Overall Energy Characteristics

2.1.1 Total Primary Energy Supply & Total Final Energy Consumption for all Carriers & Sectors

Certain statistical indicators conventionally attribute some 'energy production' to the Belgian economy, such as the NACE code 23 on "manufacture of coke, refined petroleum products and nuclear fuel". However, since all energy products need primary energy that is imported from abroad, it is fair to say that since 1993, when the last Belgian coal mine has been closed, and as far as energy 'stocks' are concerned, Belgium is effectively energy dependent for about 100%. Only the currently small amount of renewable 'flows' reduces the import dependency to somewhat less than 100%. In statistics, care has also to be taken on the generation of electricity from hydro power. In many data the output of pumped hydro is also considered as being hydro-electricity, which is in fact incorrect. Rather than using the terminology hydro-output, pumped storage should be accounted for as indirect electric energy storage, compared to gas storage. 2.1.1.1 Total Primary Energy Supply (TPES) As a consequence of what precedes, Belgium had no choice but to rely heavily on primary fuel diversification, as far as origin and nature is concerned. The evolution of the total primary energy supply (TPES) of Belgium from 1973 to 2003 according to IEA figures is shown in Figure 2.1. [IEA, 2006a]

Figure 2.1. Evolution of the total primary energy supply (TPES) for Belgium since 1973 [IEA, 2006a]. 1 toe = 41.868 GJ = 11.63 MWh.

From the recent IEA Review [IEA, 2006a], the following values can be taken for the years 1990, 2002 and 2003 (so right after the price increases of especially the fossil fuels oil and gas that started in 1999).


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_________________________________________________

1990 2002 2003

Mtoe Mtoe Mtoe

Coal 10.7 6.3 5.9

Oil 18.7 22.9 24.8

Natural Gas 8.2 13.4 14.4

Bio (+ waste) 0.7 0.9 1.2

Nuclear 11.1 12.3 12.3

Wind/Sun/Other 0.0 0.0 0.0 Elec

Import/Export -0.3 0.7 0.6

Total 49.1 56.5 59.2

_________________________________________________ Table 2.1. Total primary energy supply Belgium [IEA, 2006a]. Import of electricity is considered as positive. 1 toe = 41.868 GJ = 11.63 MWh.

As is obvious from the longer-time perspective as shown in Figure 2.1, the strong increase from 2002 to 2003 is a somewhat of a misrepresentation of reality. The Belgian statistics of the Directorate Energy of the Ministry of Economic Affairs give also results for 2004 and 2005. It is important to note that these numbers deviate somewhat from those quoted by the IEA. Therefore, the reader is urged to concentrate only on the orders of magnitude and the trends. (The deviations are in fact due to a difference in methodology, but they are not relevant in the scope of the CE2030 report.) The balance for 1998-2004 is given in Table 2.2. [Mineco, 2006] _______________________________________________________________________________

ktoe (LHV) 1973 1980 1990 2000 2003

2004 2005

Coal 11,777 11,339 10,602 8,382 6,210 6,427 5,454 Oil 27,268 23,019 18,265 23,690 24,153 22,448 22,227 Natural Gas 7,162 8,935 8,191 13,405 14,441 14,610 14,152 Nuclear 20 3,270 11,132 12,548 12,345 12,328 12,401 Others (primary electricity)

(1)

-50 -203 -297 +413 +580 +707 +586

Renewables and waste

(2)

- - - 969 1,210 1,201 1,385

Total

46,177

46,360

47,893

59,407

58,939

57,721

56,205

(1) The sign (-) means an exporting balance, the sign (+) means an importing balance. (2) Data obtained from electricity producers and from the yearly IEA/Eurostat questionnaire on renewable energy; including industrial waste and non renewable urban waste. Source : FPS Economy, DG Energy (2006)

______________________________________________________________________________ Table 2.2. Nature of primary energy in Belgium for the period 1973 - 2004. [Mineco, 2006] 1 toe = 41.868 GJ = 11.63 MWh.

Most noticeable during the last decennium is the absolute and relative decrease of coal in favor of natural gas, even until 2005. During the nineties and early 2000, this is understandable because of the cheap gas prices until about 2003, the investments made in CCGT and gas boilers for space heating and the 'discouraging' signals of the Kyoto protocol for coal. Although the gas prices have gone up considerably since 2003, and the merit order of electric power plants has changed (even taken into account the opportunity cost of CO2 emission certificates in the European Trading Scheme), bringing coal back to baseload at the expense of gas-fired units, taken over the whole year, coal still loses market share, mainly because of the restructuring of the Belgian steel industry.


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By means of a pie chart, as shown in Figure 2.2a, it can be seen what the Belgian primary energy mix is made up of. The exact percentages are shown in the figure; in orders of magnitude, we have: oil 40%; gas 25%; nuclear 20%; coal 10%, which points to a quite well balanced mix, although the dominance of oil, and the absence of renewable sources are to be noticed.

Figure 2.2.: Primary fuel mix in Belgium (2005) in the overall energy provision (left; part 'a') and in electricity generation (right;

part 'b'). [IEA, 2006a] 1 toe = 41.868 GJ = 11.63 MWh.

On the right hand side of Figure 2.2, the mix for electricity generation is presented (to be discussed below). Again in orders of magnitude, nuclear 50-60%; gas 25%; coal 15%. Here, in contrast to the overall energy economy, the effective absence of oil is to be noticed. On the other hand (but as expected), the absence of renewables is in line with part 'a' of the figure. 2.1.1.2 Total Final (Energy) Consumption (TFC) In contrast to Figure 2.1 above, Figure 2.3 shows the historic evolution and repartition over the different carriers of the total final consumption (TFC) of energy. For Combined heat and power (CHP), the end-energy products are electricity and heat (and not the gas or fuel delivered at the site of the CHP).


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Figure 2.3. Evolution of the total final (energy) consumption in Belgium since 1973, split up per energy carrier [IEA, 2006a]. As common unit, Mtoe = 106 toe has been chosen; 1 toe = 41.868 GJ = 11.63 MWh.

The steady increase of electricity and gas as end-energy carriers is highly noticeable (growth by 30% over the period 1973-2003), as is the decrease of coal (decrease by 70% over the period 1973-2003). Oil seems to be roughly constant, but in absolute terms, there is a considerable (running time-averaged) steady growth. Figure 2.4 gives the repartition of total final (energy) consumption over the different sectors. As of 1983, it seems that effectively all sectors (perhaps somewhat less for the residential sector) have grown substantially in final energy use.


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Figure 2.4. Evolution of total final (energy) consumption in Belgium since 1973, split up per sector [IEA, 2006a]. 'Other' includes the service & commercial sector and the agricultural sector. As common unit, Mtoe = 106 toe has been chosen; 1 toe = 41.868 GJ = 11.63 MWh.

Split up per energy carrier, the total final (energy) consumption in Belgium in 1990, 2002 till 2005 was as follows [FPS Economy, DG Energy, 2007; and IEA, 2006a]: _______________________________________________

1990 2002 2003

2004

2005

Mtoe Mtoe Mtoe

Mtoe

Mtoe

Coal 3.5 2.6 2.6 2.4 2.1

Oil 17.3 20.6 22.0 20.3 20.3

Natural Gas 6.8 11.0 11.2 11.5 10.9

Bio (+ waste) 0.3 0.4 0.5 0.5 0.5

Electricity 5.0 6.7 6.9 6.9 6.9

Heat 0.2 0.5 0.5 0.5 0.5

Total 33.2 41.7 43.4 42.0 41.1

_______________________________________________ Table 2.3. Total final (energy) consumption in Belgium, split up per energy carrier [FPS Economy, DG Energy, 2007; and IEA, 2006a] 1 toe = 41.868 GJ = 11.63 MWh.

Conversely, split up per sector, the total final (energy) consumption for the years 1990, 2002 [IEA, 2006a] and 2005 [FPS Economy, DG Energy, 2007] is as follows.


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____________________________________________________________________ Total Final (Energy) Consumption Belgium, 1990, 2002 and 2005 (per sector) 1990 2002 2005 industry (energetic & non-energetic) 13.6 Mtoe 17.2 Mtoe 16.2 Mtoe transport 7.9 Mtoe 9.8 Mtoe 9.8 Mtoe resid., tert. & agric. 11.7 Mtoe 13.9 Mtoe 15.1 Mtoe TOTAL 33.2 Mtoe 40.9 Mtoe 41.1 Mtoe _____________________________________________________________________ Table 2.4. Total final (energy) consumption in Belgium, split up per sector for 1990 and 2002 [IEA, 2006a]. More details are available in Annex A of [IEA, 2006a]. These numbers are according to the IEA/OECD methodology; the method used by the Belgian authorities (2005) and Eurostat differ, resulting in somewhat different numbers. [FPS Economy, DG Energy, 2007] 1 toe = 41.868 GJ = 11.63 MWh.

2.1.2 Salient Features of Oil Supply and Demand44

The evolution of the consumption of petroleum products (including refinery fuel) in Belgium over the period 1983 to 2005 is presented in Figure 2.5. [IEA, Oil information, 2006]. The Belgian oil consumption includes also marine bunkers

45

Figure 2.5. Historic evolution of the oil consumption in Belgium over the period 1983 - 2003. [IEA Oil information, 2006]

Belgium imports crude oil, all of it goes to the four refineries in the Antwerp region (two large ones: Total Raffinaderij Antwerpen and Esso Belgium, and two smaller ones: Belgian Refining Corporation and Petroplus Refining). Their output of intermediate and refined products serves partly the Belgian market, with the balance being exported. On the other hand, a considerable amount of refined products is imported for final consumption.

The recent evolution of the primary consumption (defined as the primary supply, minus refinery losses, and now excluding the marine bunkers) is as shown in Table 2.5. [IEA, 2006a]

44 As we use numbers from different sources, there might be small discrepancies in the numbers. As said before, only the orders of magnitude and the trends are to be concentrated on. 45 "Marine bunkers" cover the amount of fuel delivered to sea/ocean going ships of all flags (including war ships) engaged in international traffic.


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__________________________________________________________________

2000 2001 2002 2003 2004 2005

Primary oil consumption (Mtoe) 23.7 24.0 22.3 24.1 22.4 22.2

Change from previous year 1.4% -7.1% 8.1% -7.0% -0.9% ________________________________________________________________ Table 2.5. Primary oil consumption in Belgium. [IEA, 2006a + own calculations] 1 toe = 41.868 GJ = 11.63 MWh

Shown somewhat differently, now subdivided per sector, the recent evolution of final oil consumption reads as follows (Figure 2.6)

Figure 2.6. Evolution of the sectoral final consumption of petroleum products in Belgium. [FPS Economy, DG Energy] 1 toe = 41.868 GJ = 11.63 MWh

The origin of the crude oil delivered to Belgium in 2005 is distributed geographically as shown in Table 2.6. [FPS Economy, DG Energy 2007] In recent years the North Sea (Norway and the UK) and Russia have become our main suppliers of crude oil, where before it was the Middle East. However, it must be noted that as oil products can be easily shipped all over the world, this geographical distribution can easily change.

Import of crude oil

2005 kton %

Middle East 10,136 31.7

Saudi Arabia 5,267 16.5

Iran 4,514 14.1

Russia 13,433 42.0

American Continent (Venezuela) 810 2.5

Africa 953 3.0

Western Europe 6,632 20.7

Norway 2,749 8.6

OPEC Countries 11,288 35.3

Total 31,965 100.0

Table 2.6. Geographical origin of crude oil imports to Belgium in 2005 [FPS Economy, DG Energy]

1 toe = 41.868 GJ = 11.63 MWh.


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A major advantage of petroleum products is their storability. That makes them very convenient for transportation, and for other applications where storability is a major issue (e.g., diesel engines for emergency electricity generation in hospitals, computer centers, a.o.). Also, for security of supply on a national scale, the storability of oil is important. As of 2005, the Belgian authorities are in charge of the strategic oil stock (through a so-called 'oil stockholding agency') required by the IEA. This strategic International Energy Program (IEP), established by the IEA after the first oil crisis in 1973-1974, requires that net importing countries hold oil stocks equal to 90 days of net oil imports of the previous year. Detailed balances on the oil flows in Belgium can be found in [IEA, 2004a], and [Mineco, web].

2.1.3 The Belgian Natural Gas Supply and Demand

As is the case with oil, Belgium is a net importer of natural gas, and our dependence is again 100%. In fact, we import two sorts of gas, with a considerable difference in quality. The so-called high calorific gas (or H-gas), consists mainly of methane (CH4) and some minor amounts of higher hydrocarbons and it has a 2 vol-% of non-energetic gas content (about 1% CO2 and 1% N2). In contrast, the so-called low calorific gas (or L-gas) contains about 10%-pts less methane and a somewhat different composition of higher hydrocarbon gasses, but next to the about 1% CO2, it contains about 14% nitrogen (N2). The L-gas is exclusively coming from the Dutch Slochteren gas field. The numbers may vary slightly from time to time, and are dependent on the origin. So again, the numbers must be interpreted with some 'rough brush'. [Cerbe, 1999; CREG, 2004]

The following numbers are conventionally taken in Belgium [CREG, 2004]46

:

H-gas à 11.63 kWh/Nm3 (HHV)

L-gas à 9.77 kWh/Nm3 (HHV)

The above is to be distinguished from the higher heating value (HHV) and the lower heating value (LHV). The HHV expresses the full energy contents of the gas, including the vaporization heat (or 'latent heat') recovered from condensing the water vapor in the combustion products. The LHV, in contrast, is a measure for the energy contents with the water still present as vapor in the exhaust gases. Both H-gas and L-gas are each characterized by their own HHV and LHV. The values given above for H- and L-gas are the HHV, as indicated. Their respective LHV are conventionally taken to be a factor 0,896 higher than their HHV, for both gases. [CREG, 2004]

47

Note that usually, efficiencies for power plants or boilers are expressed in terms of the LHV. This is the reason that condensing boilers are often quoted to have efficiencies larger than 100%. Primary natural gas supply in Belgium has fluctuated over the years 1973 - 1990 (see Figure 2.1), but since then, it has grown more or less steadily. (See Table 2.7.)

________________________________________________________________________________

1973 1980 1990 2000 2003 2004 2005

Primary gas supply (Mtoe) 7.1 8.9 8.2 13.4 14.4 14.6 14.15 ________________________________________________________________________________ Table 2.7. Evolution of primary gas supply in Belgium according to [FPS Economy DG Energy, 2007] 1 toe = 41.868 GJ = 11.63 MWh.

The Belgian natural gas consumption over the last five years, according to the Belgian Ministry of Economic affairs, is as shown in Table 2.8.

46 Nm3 stands for Normal cubic meter (sometimes also abbreviated as Ncm), being the volume of gas at 1 atm = 1.013 bar and 0°C. (In some cases, 15°C is taken as standard temperature). 1 kWh = 3.6 MJ. 47 Besides natural gas, also petroleum products and coal have a HHV and a LHV. The ratio HHV/LHV for gasoline is about 1.1, for diesel about 1.07 and for coal about 1.02 to 1.03.


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in PJ (HHV) 2001 2002 2003 2004 2005

Total Final Consumption 476.8 483.0 488.3 503.0 483.8

Industry 197.2 215.0 204.0 205.9 186.0

Residential & Equivalent 245.1 235.9 245.0 257.4 256.6

Non-energetic uses 34.5 32.1 39.3 39.7 41.2

Power Plants

(1)

135.1

147.2

184.0

181.8 188.9

(1) autoproducers and CHP included. Table 2.8. The total natural gas consumption in Belgium. [FPS Economy DG Energy, 2007] 1 toe = 41.868 GJ = 11.63 MWh.

Viewed graphically, the gas-consumption evolution in relative terms looks like Figure 2.7.

Figure 2.7. Evolution of the Belgian gas consumption per sector. [FPS Economy DG Energy, 2007]

At present (actually 2005), and in terms of order of magnitude, the repartition of the gas consumption is roughly 1/3 for the three sectors shown above (although the electricity sector has grown the most since 1990. More accurately, the numbers are: Electricity generation 28 % Industry 35% Domestic & Service/Commercial 37 % Note that the gas used for electricity generation is effectively mainly H-gas, while for the domestic & service/commercial sectors the ratio of H-gas/L-gas is roughly 50/50, whilst industry uses about 4 to 5 times more H-gas than L-gas. Overall, Belgium uses currently about 3 times as much H-gas as L gas. (For more details, see [CREG, 2004].) This remark on H/L gas is not superfluous, since both sorts of gas must be transported by pipeline. As will be illustrated below, both networks, H-gas and L-gas are completely separate. Conversion from H-gas to L-gas is possible through injection of nitrogen in so-called 'blending' stations; the reverse is clearly not possible. All L-gas originates from the Netherlands, although some H-gas can also be imported through the Netherlands (in which case the Netherlands are used as transit country). The current long-term take-or-pay contract for L-gas (owned by Distrigas), expires in 2016 (with a likely extension till 2020); the question is open whether this contract will be extended after that, by whom and to what extent. As an alternative, the present L-gas pipelines could be used for H-gas, meaning that the energetic capacity would increase by about 20%, compared to the previous L-gas in those pipelines.

48

48 Transition from L to H-gas is possible without major obstacles. In principle, no replacement of (the 'multi-quality') appliances would be necessary, but all burners should be checked for safety reasons.


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A typical characteristic of a gas market is that gas demand can fluctuate very strongly. Between the peak demand and the lowest demand, a factor of 4-5 is not unusual, depending especially on the meteorological circumstances. For deliveries in the distribution grid, the fluctuations may even be more than a factor of 20. See Figure 2.8. This means that for a country like Belgium, without any own gas wells, storage capacity of gas is very important.

Figure 2.8. Variability of daily gas delivery to end clients in Belgium for the year 2004, expressed in [GWh/day]. Bottom part represents delivery at transmission (high pressure) level for e.g., electric power plants; top part is delivery at distribution (low pressure) level. [Figaz/s, 2004]

For seasonal storage, Belgium has one large underground aquifer reservoir in Loenhout, and two smaller ones in Anderlues and Péronnes, being previous coal mine sites. According to [IEA, 2006a] these latter ones have not been used since 2000, and are being mentioned as possible (far-) future carbon sequestration sites. For peak shaving, an LNG storage site with regasification capability is present in Dudzele. Finally, the LNG terminal in Zeebrugge represents a respectable amount of storage.

49

Following [http://www.fluxys.net] the following numbers apply (Table 2.9):

Type Storage Capacity Total Injection Capacity Total Emission capacity

Loenhout50

Aquifer 580 Nmcm 250,000 Ncm/h 500,000 Ncm/h

PSP Dudzele51

LNG 55 Nmcm 769 cm LNG/day 500,000 Ncm/h

Zeebrugge LNG Terminal

52

LNG 261,000 cm LNG 12,000 cm LNG/h 950,000 Ncm/h

Table 2.9. Gas storage in Belgium; seasonal storage, peakshaving and LNG terminal. 'cm' stands for cubic meter; 'mcm' stands for million cubic meter. The gas stored in Loenhout is H gas.

49 Daily fluctuations are mainly covered by allowing the pressure to fluctuate, provided by the so-called 'linepack'. 50 www.fluxys.net. Fluxys is currently examing the possibility to increase both storage, injection and emission capacities significantly of the Loenhout underground storage facility on a relatively short term. The proposal has to be submitted to CREG and the relevant authorities 51 www.fluxys.net. The Fluxys Peak Shaving Plant in Dudzele is being supplied by LNG coming from the terminal and transported by means of LNG trailers. 52 www.fluxyslng.net. Fluxys LNG has decided to make huge investments in order to increase the total throughput capacity to 9 Nbcm/year as from 2007. For example, a fourth storage tank is currently being built at the LNG Terminal. This will increase storage capacity with 57%. In addition, total emission capacity will be increased to 1.7 Nmcm/h.


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The monthly changes of the gas consumption in Belgium, as well as the changes in stored gas are shown in Figure 2.9.

Figure 2.9. Typical monthly fluctuation of the storage (left; injecting (-) and releasing (+)) and total consumption (right) in Belgium. [IEA, 2004b]

To guarantee security of supply, some flexibility in the gas market is necessary. According to [CREG, 2004], about 30% of the industrial gas demand can be switched to heating oil, at least in principle. Industry takes advantage of that possibility to be able to participate in price arbitrage of gas versus liquid fuel, and not so much for security of supply reasons. Nevertheless, this is an interesting possibility for crisis or incident management. Depending on the local storage volume of the liquid fuel, interruptions of 1 to 4 days are possibly to be bridged. Similarly, an 'in-principle' flexibility exists with respect to electricity generation, when so-called multi-fuel units are present or when a swap is possible between different generation units. (This is the so-called virtual gas storage.) However, this is often a mere theoretical possibility since in practice, this option is heavily dependent on the price ratio of gas to coal, and gas to liquid fuel (including the cost for CO2 emission certificates). Indeed, when gas is expensive, the merit order for electricity generation is such that the base- and mid-load is guaranteed by coal, and not by gas. Hence switching is not an option. Also, in principle, CCGT can run on fuels like jet fuel, if liquid storage facilities are present. But, except in peak circumstances, there is no reason to assume that jet fuel will be cheaper than gas per unit of generated kWh-electric. (Otherwise jet fuel would be used rather than gas, on a regular basis.)

53 Furthermore, switching cannot occur instantaneously, but it requires some time depending on

the case at hand. In the past, the Belgian gas market has been supplied through long term “take-or-pay” contracts concluded by its historical gas operator Distrigas, which had contracted supplies from different sources, mainly from three regions, Norway (H-gas), Algeria (LNG - H-gas) and the Netherlands (mostly L-gas). Some supplies have also been provided through the spot market with LNG imports

53 But clearly, if spot prices for gas would have a tendency to skyrocket on a frequent basis, then CCGT operators will want to take advantage of this, by taking measures to allow switching. All depends on the economics of such actions.


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stemming from time to time from Abu Dhabi, Nigeria and recently from Qatar, and with gas from the United Kingdom delivered via the Interconnector. However, the flow of imports from the UK will more and more reverse in the other direction, due to the changing status of this gas producer from net gas exporter to net gas importer. In recent years, Russian gas has also been delivered through the German entry point. Today it is still a marginal supplier for Belgium (4.9% through Germany) whereas on average 24% of European gas consumption is already imported from Russia. But considerable interest of the Russian counterpart for the Belgian “gas place” is noticeable. It goes without saying that the Russian Federation will evolve gradually to play a very important role in the Belgian gas supply. The situation for 2005 was as shown in Figure 2.10 [FPS Economy, DG Energy 2007]

Imports of natural gas by country in 2005

32%31%

5%

14%19%

Algeria

Netherlands

Norway

Germany/Russia

Others (UK)

Figure 2.10. Origin of Belgian gas supply in 2005. [FPS Economy DG Energy, 2007]

In the future, it is expected that the numbers will change more and more, whenever long-term contracts expire and new contracts (of whatever sort) are concluded. Gas supply is heavily dominated by pipeline transport (sometimes also called transmission) and distribution. The (high-pressure) transport grid, which is operated by the TSO Fluxys, is shown in Figure 2.11. [CREG, 2004]


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Figure 2.11. The transport/transmission grid for gas in Belgium. The distinction between the H-gas grid (in brown) and the L-gas grid (in blue) is to be stressed. (From [CREG, 2004 -- after Fluxys.).

The density of gas pipelines is notably different in the Regions in Belgium, and even more so for the distribution (low-pressure) pipe lines. The same consequently applies to the supply & demand of gas. Brussels only has L-gas, and is responsible for about 6% of the natural gas demand, for 10% of the population. Wallonia represents almost 27% of the natural gas market for 31% of the population, whilst Flanders has a bit less than 68% of the Belgian gas market for 58% of the population. More specifically for 2004: [IEA, 2006a] Brussels 5.9% Wallonia 26.6% Flanders 67.5%

More detailed information on the gas flows in Belgium can be found in [IEA, 2004b], [CREG, 2004] and [Mineco ,web].

2.1.4 The Belgian Coal Supply and Demand

Belgium's only indigenous energy resource is coal. Because of its high production cost, preventing it from competing with imported coal, mines were gradually closed down. Since 1993, Belgium imports all of the coal it utilizes. Imports are diversified across several importers. For the year 2005, coal consumed in Belgium was imported from the following countries (Table 2.10).


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Coal (tons) 2005

Australia 2,950,657

South Africa 2,081,141

USA 1,714,328

Canada 269,390

Russia (CIS) 944,268

Poland 436,109

Germany 154,973

Others 252,194

Table 2.10. Origin of Belgian coal imports in 2005 in absolute numbers [ton]. [FPS Economy DG Energy, 2007])

In percentage of total coal imports, this represents (Figure 2.12):

Coal imports by country in 2005

19%

24%

33%11%

3%

2% 3%

5% Australia

South Africa

USA

Canada

Russia (CIS)

Poland

Germany

Others

Figure 2.12. Origin of Belgian coal imports in 2005 in relative terms.[FPS Economy DG Energy, 2007]

The main consumers are the power generation plants (44.2%), coke oven plants (41.2%) and the steel industry (8.7%). The domestic use of heating coal represents a mere 2.9% of the total demand. All this is shown in Table 2.11.

kton 1998 1999 2000 2001 2002 2003 2004 2005

Iron & steel industry 5,213 5,227 5,326 5,462 4,020 4,201 3,967 3,450

Industry 738 680 775 631 510 486 566 534

Domestic use 328 286 312 342 319 254 225 214

Electricity Production 5,019 3,681 4,309 3,723 4,086 3,618 3,348 3,045

Coking plants 3,885 3,850 3,855 3,911 3,725 3,369 3,647 3,374

Table 2.11 Evolution of coal deliveries by sector. [FPS Economy DG Energy, 2007]

2.1.5 The Nuclear Fuel Cycle in Belgium

Belgium has no natural uranium that can be mined economically. In the past, there was a limited production of about 40 tons/year from imported phosphates. This has been terminated because of economic reasons while uranium prices were low. Synatom, which is responsible for all aspects of the fuel cycle, secures the uranium supply through medium-and long term contracts with exporters from Australia, Canada, Russia and central and southern Africa. The uranium fuel-element fabrication plant FBFC in Dessel has a production capacity of 400 ton U/a (more than enough to meet the country’s needs). The mixed oxide fuel (MOX) factory of Belgonucléaire, also in Dessel, has been shut down in 2006.


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The nuclear-generated electricity production has remained nearly constant over recent years, as shown in Table 2.12.

Year Nuclear* Electricity

Production (TWh)

Nuclear * Share

(% of total electricity production)

Availability Factor

(%)

2000 48.2 57.4 90.7 2001 46.3 58.2 88.1 2002 47.4 57.7 89.8 2003 47.4 56.0 89.0 2004 47.3 55.4 88.3 2005 47.6 54.7 89.2

(*) gross production

Table 2.12 Nuclear energy production, nuclear share and availability factor. [FPS Economy DG Energy, 2007]

2.1.6 Renewables in Belgium

In Belgium the share of the total primary energy supply (TPES), coming from renewable sources is small and estimated at 2.3% in 2004, a rise of 14% comparing to 2003. The evolution over the period 1973-2003 can be represented as shown in Figure 2.13.

0

1

2

1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003

% o

f T

PE

S

Hydro Geothermal Solar, Wind etc. Combustible Renew. and Waste

Figure 2.13. Renewable Energy as a Percentage of Total Primary Energy Supply, 1973 to 2003. [FPS Economy, DG Energy ,

2007]

Compared with the share of renewables of the 26 IEA countries Belgium had in 2004 the fifth smallest part of TPES supplied by renewables. Biomass is by far the most important source (97%), while hydro was accounting for 2%. In Flanders, generation from renewable sources is expected to rise to 6% by 2010, being at 2% in 2004. In Wallonia, the objective for 2010 is a raise to 8% at the horizon 2010. In both regions there is a fast growing electricity generation coming from wind energy. Brussels-Capital has, because of its limited surface and electricity generation capacity, very limited renewable energy facilities, being mainly solar thermal demonstration projects.


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2.1.7 Electric Energy in Belgium

2.1.7.1 Important Figures The generation capacity for electricity in Belgium (expressed as the net rated power of the power plants), up to 2004, is as follows (Table 2.13):

MW 2004 2003 2002 1999 1994

Nuclear 5,801.5 5,761.0 5,761.0 5,713.0 5,528.0

Classic thermic 6,800.3 6,800.1 6,845.9 7,226.4 7,427.5

Biogas 25.9 25.9 25.9 11.8 1.8

Waste and recuperation steam 201.3 200.1 196.9 147.1 124.0

Cogeneration 1,340.8 1,339.6 1,272.7 1,057.4 410.1

Hydraulic 107.6 107.6 106.0 97.0 95.5

Pumping stations 1,307.0 1,307.0 1,307.0 1,307.0 1,307.0

Wind 92.8 66.9 31.0 9.3 5.2

BELGIUM 15,677.2 15,608.2 15,546.4 15,569.0 14,899.1

Table 2.13. Composition of the Belgian generation capacity (so-called developable power) up to 2004. [BFE-FPE, 2004]

Notice that by the end of 2006, wind generation has grown to 193 MW. Concerning CHP, the number for 2005 turns out to be artificially inflated since almost no real CHP has been installed in 2005 (because of uncertainty in legislation on CHP certificates in Flanders). The increase by 2005 is mainly due to 'The Zandvliet Power' unit on the site of BASF Antwerp Nord.

54

As far as the generated electric energy is concerned, the evolution in Belgium can be graphically represented as shown in Figure 2.14a and b.

54 This unit is a typical gross 400 MW CCGT with steam bleeding foreseen. Most of the time, this unit runs in simple CC mode without steam bleeding and Pe,net = 385 MWe. During a minor fraction of the year, useful heat is tapped from the unit (leading to a lower electric output then). When operating in cogen mode, its electric output is 359 MWe, whilst steam is delivered at 19 bar. The primary energy saving is a mere 5.70% compared to separate generation. The possibility of such steam-bleeding provision is certainly to be applauded, but should be carefully treated in the statistics (i.e., not simply as MWe, but by providing the Q/E energy ratio on an annual basis).


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Figure 2.14a. Evolution of the Belgian generated electric energy up to 2003. [BFE-FPE, 2003]

Figure 2.14b. Evolution of the (gross) Belgian generated electric energy from 1998 up to 2005. [FPS Economy, DG Energy] In table form, giving also the respective % of the generation mix in 2005, we have (Table 2.14):

GWh

1998 1999 2000 2001 2002 2003 2004 2005 %

in 2005

Nuclear 46,165 49,017 48,157 46,349 47,360 47,379 47,312 47,596 54.7

Hydro, pumping, wind 1,508 1,502 1,713 1,676 1,546 1,404 1,736 1,831 2.1 Combustible renewables and waste 1,062 1,208 1,219 1,458 1,655 1,609 1,760 2,250 2.6

Coal 14,187 9,939 12,916 9,936 10,029 9,638 9,147 8,199 9.4

Gas 17,739 21,820 19,091 18,608 20,499 23,579 23,812 25,409 29.2

Liquid combustible 2,580 1,035 797 1,665 972 1,007 1,675 1,740 2.0

Total 83,241 84,521 83,893 79,692 82,061 84,616 85,442 87,025 100.0

Table 2.14. Composition of the (gross) Belgian electricity-generation 'fuel' mix up to 2005. [FPS Economy, DG Energy]

Structure of electricity gross production (GWh) 1998-2005

20000

30000

40000

50000

60000

70000

80000

90000

100000

1998 1999 2000 2001 2002 2003 2004 2005

GW

h

Liquid combustible

Gas

Coal

Combustiblerenewables andwasteHydro, pumping, wind

Nuclear


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Besides its convenience for end use, the major handicap of electricity, with respect to the provision of electric power, is that electric energy is almost not storable as such. Hence, generation has to match demand increased by the grid losses at all instants in time. If local generation is insufficient, influx from neighboring zones within the same synchronous area will occur. The TSO is responsible for the balance within its control area. (The Elia control zone is somewhat larger than Belgium as it comprises also part of Luxemburg.) If there is an unbalance between generation and demand within a synchronous zone, the frequency of the alternating electric power system will decrease

55, requiring

intervention by the grid operators such as the automatic activation of the so-called primary reserve. If really pressing, TSO’s will have to initiate deliberate power cuts in some areas (known in the jargon as 'load shedding' or even 'rolling blackouts').

56 In addition, to keep the overall electric grid stable, the

voltage levels need to be controlled appropriately, by what is called local 'reactive' power adjustments.

57

To have an idea of the generated peak and the international exchanges, Figure 2.15 gives an idea of the variation of electric-power peak demand in Belgium.

55 This is the so-called (P-f) relationship. If there is a lack of 'active' power P, then the rotors of all generators in the synchronized UCTE area will slow down, with a decrease of the frequency f as a consequence. 56 Such unannounced 'load shedding' or 'rolling blackout' recently occurred on November 04 2006, originating from an incident in northern Germany, but affecting a large part of NW Europe, 57 Reactive (i.e., inductive or capacitive) power adjustments are implemented via changes of excitation for synchronous generators, through capacitor banks or through power-electronics control measures. Note that reactive power cannot easily be transported; hence the need for local adjustments. This issue is known as the (Q-V) relationship, in which Q stands for the reactive power and V for the voltage. Note that most major (sudden) blackouts whereby the system actually 'crashes', have historically not occurred because of an imbalance of active power at moments of peak-demand, but rather at moments of low demand —i.e., in summer time, and especially during holidays— often due to reactive power imbalances, or as a consequence of extreme/severe weather conditions.


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Figure 2.15. Daily and monthly variation of electric power demand in Belgium. Examples for 2003 are given. [BFE-FPE, 2003] For the top figures, a weekday (conventionally the third Wednesday of the month) is chosen. The dark blue is the demand, the light blue is the generated power delivered to the hydro-pump stations in Coo-Trois Ponts. The bottom figures are weekends in summer time (to illustrate the minimal demand situation); the light blue represents Saturdays, the blue line refers to Sundays.

Peak demand in Belgium is situated in wintertime (usually in December or in January) in the late afternoon, between about 17.00-18.00h. In summer time, the peak demand is in the afternoon, especially on hot days, because demand for air-conditioning. In 2003, compared to a peak demand of 13.6 GW, the peak demand in August seems to have been of the order of 10.7 GW at about noon time. The numbers for the month of July of 2006 are even more 'dramatic', i.e., 12.11GW (on July 5, 11.45h to 12.00h). An overview of the evolution of the peak demand in Belgium is given in Figure 2.16. [IEA, 2006a and ELIA]

Figure 2.16. Historic evolution of the Belgian peak demand. ([IEA, 2006a and ELIA)

In contrast, the peak of the generated electric power in Belgium is given in Figure 2.17. [BFE-FPE 2004]


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Yearly evolution of produced peak power

Figure 2.17. Historic evolution of the Belgian peak electric power generation. [BFE-FPE, 2004]

Since demand is larger than generation, especially so since 2000, the balance needs to be imported. The numbers for the last 7 years are shown in Table 2.13.

GWh 2000 2001 2002 2003 2004 2005 2006 Import 11,645 15,818 16,658 14,664 14,567 14,328 18,719 Export 7,319 6,712 9,070 8,254 6,789 8,024 8,696

Balance 4,326 9,106 7,588 6,410 7,778 6,304 10,023 Table 2.13 : Balance of Electricity exchanges 2000-2006. [FPS Economy, DG Energy + Elia] 2.1.7.2. Comments on Electricity Generation and Transmission a. International Electrical Energy Exchanges It is interesting to note that since 2004 (taken over the year) Belgium no longer seems to be a net transit country for electric energy from France to the Netherlands. (see [BFE-FPE, 2003 and 2004], and [ELIA, 2005a and 2006]) Also note that although on an annual energy basis, France is a net exporter, it has recently occurred several times in the past that France was a net importer during several days. This means that France was not able to cover its own peak demand. The lesson to be learnt from this is that even net exporting countries (on an annual basis) may need import at some instants in time and thus generically relying on import from other countries might not always be possible.

58 Indeed, if all neighbors would also rely on import for peak demand, the whole system would

break down.

58 Specific rules are prescribed by UCTE, for sufficient coverage of demand in each control area, appropriately taken into account contracted import, and setting requirements for primary, secondary and tertiary reserve. See http://www.ucte.org.


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(GWh) 2004 2005 2006 Evolution

2005-2006

France %

Import 7,591.0 6,750.3 10,636.2 57.57%

Export 1,179.7 2,220.6 1,981.1 -10.79%

The Netherlands

Import 4,630.1 5,073.8 5,603.6 10.44%

Export 4,052.9 4,430.1 5,017.8 13.27%

Luxemburg

Import 2,380.8 2,366.4 2,0478.8 4.75%

Export 1,576.7 1,373.2 1,696.9 23.57% Table 2.14. Electric energy exchanges between Belgium, the Netherlands, France and Luxemburg in 2004, 2005 and 2006. [ELIA, 2005a and 2006]

The balance of electricity exchanges does not mean that Belgium is not able to provide its own electricity generation most of the time, although it is becoming more difficult to cover its own peak. However, the margin has decreased dramatically over the last years due to the increased demand, on the one hand, and the almost halted investments in dispatchable power plants, on the other hand. The exchanges are related to the prices in neighboring countries versus those in Belgium and a better functioning of the global French-Belgian-Dutch electricity market due to enhanced transmission capacity and a change of the capacity allocation on the French-Belgian border. An illustrative picture of the exchanges in North-Western Europe is given in Figure 2.18.[Global Insight, 2006]

Figure 2.18. Simplified picture of the electric energy exchanges related to Belgium in the N-W European market, and indication of the average electricity price [Global Insight, 2006]. Note that the numbers differ slightly from those of Table 2.14.

b. Electricity HV Grid Infrastructure The above makes the bridge with the Belgian high voltage grid. An up-to-date map of the Belgian grid is shown in Figure 2.19. [IEA, 2006a]


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Figure 2.19. The Belgian electric transmission system, with specification of the location of the (larger) power generation units. ([IEA, 2006a], obtained from ELIA. A detailed map can be obtained from the website http://www.elia.be)

The existing grid has historically been developed to support national electricity transmission and to procure international assistance in case of incidents, next to some large long-term contracts.

59 It is

important to notice from Figure 2.19 that there is currently no direct link between Germany and Belgium. Part of Luxemburg (Sotel) is incorporated in the Elia control area, while the other part is incorporated in the RWE-Netz control area (Germany). Due to the phase angle of the voltages, both systems are normally not connected, although in case of emergency, a connection is feasible. The total capacity on the southern border has recently been increased from 2200 MW to 2900 MW; after 2006 this cross-border capacity is planned to become 4700 MW by 2009. [IEA, 2006a] It must be stressed that international high-voltage connections are of uttermost importance in the current context of a common European liberalized electricity market. In addition, the utilization of more and more fluctuating (weather driven) sources in concentrated areas requires an even stronger European grid. Hence, this historic 'reliability-based' system is currently not really dimensioned to deal with all these issues. Indeed, the European coupled grid has to serve now three distinct functions: - trading of electric power across the border of control areas; - allowing power flows due to imbalances caused by massive localized (and hence correlated) fluctuating sources such as wind-generated power; - leaving enough spare capacity to manage incidents (reliability issue). The use of the physical capacity of the grid interconnections occurs in the reverse direction of the sequence just given: a minimal margin is to be kept for emergency situations (reliability issue); then, sufficient margin is to be kept for 'evening out' fluctuating sources, and only the remaining part is available for trade. Hence, considerable work, investments and time is needed to achieve the so-called copper plate! In an Informative Box, a more detailed overview of these major challenges is given.

59 Which all have been abolished at the present time.


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Informative Box: The major challenges for the future of the electrical grids

1. Part of the problem is that electric power flows do not obey contractual paths. Kirchoff’s laws are explaining the basic functioning of electrical networks. Kirchoff’s first law states that no loss can occur at a junction, resulting in the fact that the sum from all ingoing currents must equal the outgoing as shown in the example:

I1+I2= I3+I4+I5

The second of Kirchoff’s law states how the distribution takes place, depending from the resistance of the connecting lines. As a result currents cannot be redirected in a particular way and obey always to these 2 fundamental laws following the path that minimizes the impedance ('resistance').

2. The handling of power flows due to imbalances caused by highly concentrated fluctuating sources as large wind farms is a good example. In both cases, when wind generation is too large compared to the prediction, or in case of a sudden drop in wind-generated power (usually also because of too high wind speeds, such that wind turbines have to be disconnected suddenly from the grid), substantial flow corrections take place. The European network has regularly to face these issues with the concentrated (18 GW) wind capacity in north-east Germany. This type of situation is not dramatic as long as one is upfront aware of it and if appropriate measures are taken. One possibility is to install so-called phase shifters (i.e., some sort of electric 'valve') on the border lines to keep uncontracted flows (often also called loop flows) out. This option has been chosen by Belgium. [ELIA, 2005b] Other mitigating measures are improved wind predictions, if successful, and shorter gate closure times on the power exchange markets. [3E, 2006] This type of technical problems can be solved, albeit with necessary investments and at a non-negligible additional cost.

3. The same reasoning applies a-fortiori for unplanned shut downs of large generating units, such as nuclear plants of 1 GW and more. An unexpected shut down occurs about once a year, and the unannounced simultaneous shut down of more than one plant is not very likely. However, the electric grid should be ready (and it is) to cope with such instant loss of generation. The UCTE system is designed in such a way that it can cope with immediate stop of two of the largest nuclear power plants, i.e., 3000 MW. The reserve power needed to cover this loss is distributed across the UCTE zone and is the so-called primary reserve, which each of the TSO’s has to contribute, in proportion to the power installed in its control area.

4. Finally on grid related matters, it is instructive to mention two investment paradoxes

concerning cross-border high-voltage lines in a liberalized market. If insufficient cross-border transmission capacity exists, then congestion on particular borders may occur, which in turn may allow certain (usually historic incumbent) electricity generators to abuse their local market dominance. This may lead to higher prices in the region dominated by that player (e.g., Belgium). Hence, the necessity to enhance cross-border capacity. If one invests in additional cross-border capacity, congestion disappears, and local consumers may then be tempted to buy their power abroad. Because of the threat to buy elsewhere, the dominant player will adjust his prices and put them at a similar level as the neighboring countries. After


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the local price decrease, there is no longer a need to go shopping across the border, which means that the cross-border capacity will not be used.

60

This is the first paradox: an investment in cross-border capacity in order for it not to be used! The second paradox is that investment in cross-border transmission capacity and higher (regulated) transmission tariffs (to pay for the investments) may be needed to obtain lower production prices and finally a lower cost for the end consumer.

Finally, some numbers on the Belgian electricity demand are presented. In contrast to overall final energy demand, final electricity demand has been growing steadily over the last 20+ years. This is shown in Figure 2.20

: final electricity consumption GDP total primary energy consumption

Figure 2.20. Evolution of the primary energy demand, electricity demand, both compared to the gross domestic product (GDP) from 1981 to 2004. [BFE-FPE, 2004]

Over the last 20 years, the growth rate has been situated between roughly 2 and 4%/a. This is illustrated in Figure 2.21.

Figure 2.21. Average annual growth rate of electricity demand shown for the past 50 years. The vertical bars show the average annual growth rate over 5 years, while the blue curve gives the sliding annual average over 5 years. [BFE-FPE, 2003]

In numbers, and repartitioned over the different sectors, we have for the last 8 years:

60 This paradox applies to the capacity reserved for international trade; it does not refer to the reliability issue or to the balancing of large fluctuating power differences.


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Final electricity demand

TWh 1998 1999 2000 2001 2002 2003 2004 2005

Industry 38.1 37.6 39.89 39.2 38.9 40.0 40.3 39.4

Transport 1.4 1.4 1.4 1.5 1.5 1.5 1.5 1.7

Residential 23.4 23.5 23.7 24.4 25.9 26.0 26.5 26.0

Other 11.8 12.0 12.5 13.1 12.1 12.2 12.2 13.1

Total 74.0 74.5 77.5 78.1 78.5 79.7 80.6 80.2

Table 2.15. Final electricity demand in Belgium; subdivided per sector from 1998 - 2005. "Other" includes the service & commercial, and agricultural sectors. [Mineco, 2007]

In percentages, the rough repartition is as follows: - industry 1/2 - residential 1/3 - other (tertiary) 1/6 This repartition shows the dominance of industry in electricity consumption and explains the importance of reasonable industrial electricity prices in Belgium.


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2.2 Energy Prices in Belgium End-energy prices for consumers, small and large, are influenced by a number of factors. First, the market price for a particular energy product is dominantly 'steered' by the marginal production cost.

61

The marginal cost may be pushed up by withholding of production capacity by dominant cheap producers (e.g., OPEC), leading to an increase of the price.

62 For gas it is expected that it remains

competitive mainly in markets where oil is the substitute and for this reason, delivered gas prices will stay close to delivered oil prices.

63 It is everybody's guess what the resource prices (crude oil and gas)

will do in the future, but they largely determine the price of the downstream products such as refinery products and electricity. Part of the price are also transmission and distribution costs, and other services (billing, administration, etc) provided by actors in the overall chain from production to end consumer. In addition, part of the marginal cost is the certificate requirements imposed by the authorities. For fuels, the so-called CO2 allowances often play an important role.

64 Indeed, regardless of the fact that

they have been given for free ('grandfathered') to many industrial sectors, including the energy sector, they have a market price and they are characterized by an opportunity cost. Following a similar reasoning, the cost for CHP and green certificates is normally transferred to the end consumers. Finally, there are levies and taxes, which can be quite substantial for certain energy carriers. It is noted that VAT is paid only by final consumers as private citizen, whereas enterprises (including single-person enterprises and independents) recover the VAT. Along the same lines, discounts to the end consumers influence the prices. Some instructive comments on price versus marginal cost for production of certain electricity generation technologies are illustrated hereunder.

• Since renewably generated end energy is part of the overall mix, the price for it is dominantly set by the mix, which in turn is determined by the marginal cost of production of the whole system. E.g., the price may be set by gas-fired plants; only in some rare cases it may be set by wind-generated electricity. The latter has occurred in Denmark in December 2003, where for several hours the spot price for electricity was zero. [IEA, 2005] This may seem 'logical' since the marginal cost of wind-generated electricity is zero, but it is actually a consequence of the fact that there has been an over investment in generating capacity for that grid control region (as a consequence of an over-generous subsidy policy), together with the fact that cross-region transmission capacity is limited such that congested lines prohibit multi-region equilibration of prices.

• Likewise, much of the time, the prices for electricity in France are not determined by the low

nuclear marginal cost, but by the gas or coal plants in Germany (as long as there is no transmission-line congestion) between France and Germany.

• As a last comment, it is important to distinguish between longer-term 'contractual' prices for

consumers (large and small), perhaps split up in baseload components and peak components, or in day- and night tariffs, respectively, and the so-called spot prices and forward prices on energy exchanges. Also, although not yet an issue in Belgium due to a lack of advanced metering possibilities, there exists a future possibility to opt for real-time pricing (i.e., following the instantaneous overall marginal cost) up to the final customer level.

61 See the Informative Box on "Price versus Cost" for an explanation of some of the costs & price concepts. 62 In addition, a risk premium (e.g., because of geopolitics in the case of oil), financial speculation and market-power 'abuse' by some dominant actors may sometimes play a role. 63 Also, it is expected that contract linkage to oil prices (so-called oil-indexed contracts) will still be 'demanded' for quite some time by the large gas producers. (Cfr. World Gas Conference, Amsterdam 2006, A. Miller Gazprom) 64 These emission permits are formally called EUA, for European Union Allowance. For the time being, the European Emission Trading Scheme only covers CO2.


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Informative Box: Price versus Cost

The price of a good is the amount of money that a buyer pays for that good (or service). It is paid to the producer (supplier) of the good (service). In economics the behavior of suppliers of goods (services) is modeled by the market supply-curve while consumers' behavior is represented by the market demand curve. The intersection point of both curves determines the (equilibrium) price. It can be shown that in a competitive market the price of a good equals the sum of all (long-run) costs (including production costs, personnel costs, dividends paid to shareholders, ...). In the short run, the price is determined by the (short-run) marginal cost. One of the assumptions of the model of a competitive market is that producers have free entry in the market. If price rises above costs, then new entrants will enter the market and prices will lower. In a contestable market there thus exists an entry threat and by the same mechanism, prices converge to costs made for producing the good: a producer will not increase the price since there is a threat that new entrants will enter the market.

Perfect competition

Quantity

Pri

ce Supply

Demand

Most markets do not fulfill all assumptions of the competitive model. An extreme violation of the assumptions is found in the monopolistic market. In such a market there is only one producer who is able to raise prices above costs (i.e., the producer has market power). He can do so by choosing the quantity (Q1 or Q2) he wants to produce and supply to the market. As such the monopolistic producer can earn a monopoly rent.

Monopoly

Quantity

Pri

ce

Demand

Q2 Q1

Markets are seldom 'pure' monopolies; however, there exist markets with a dominant producer. This is, e.g., the case in many deregulated markets where the incumbent producer has remained dominant. This dominant producer could also manipulate prices above costs and potentially earn a monopoly rent, i.e. it has market power. The degree of market power depends on its market share, but also on the responsiveness of the demand function to price changes. Economists measure market power by a so-called Lerner index. Note that this index is often biased by the presence of other types of rents

65.

Another kind of rents - due to producers having different production technologies - are the infra marginal rents (see box on (infra) marginal rents, windfall profits and mothballing).

65 see F. Coppens, "Scission ou centrales virtuelles, la solution au problème du producteur dominant", Revue de L'énergie n° 572


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In the context of energy markets the scarcity rent is important. This rent is due to existing capacity limits implying a particular form of the supply curve (i.e. with a vertical end). If demand exceeds available capacity then the price can rise above costs:

Capacity constraint

Quantity

Pri

ce Supply

Demand

Qmax

Until recently, the environmental costs of energy consumption were not included into the production costs. They were 'external' costs. The implementation of the Kyoto protocol tries to take the costs of greenhouse gas emissions into account and internalizes these external costs. In a perfectly competitive market this results in a cost increase or an upward shift of the supply curve. The figure below shows that this results in higher prices:

Perfect competition

Quantity

Pri

ce Supply

Demand

Finally the government can impose levies and taxes, also to be included in the consumer price.

2.2.1 Wholesale Energy Price Evolution & Influencing Factors

2.2.1.1 Wholesale Primary Energy Prices a. Crude Oil The 'mother of all energy prices' is the crude oil price. The evolution since 1861 and during the last 30 years is shown in Figure 2.22. [BP 2006; Davies, 2006]


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0

20

40

60

80

100

1860 1870 1880 1890 1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000

$/b

$2005/b

1861-1944 : US average ; 1945-1985 : Arabian light posted at Ras Tanura ; 1986-2005 : Brent dated.

Rockefeller

(1875)

Dissolution of

the Standard

Oil (1911)

Rockefeller's

supervision

Founding of

OPEC (1960)

Yom

Kippur war

Iranian

revolution

(1979)Iraq

invaded

Kuwait

(1990)

Supervision by the "Majors"

Asian

financial

crisis

Invasion

of Iraq

(2003)

Figure 2.22a. : Crude oil prices since 1861 (expressed in money of the day and in $2005).

[ BP, 2006].

Figure 2.22b. Evolution of the crude-oil price between 1975 and 2005, in nominal terms (money of the day) and in real terms as corrected by the CPI and PPI. [Davies, 2006]

Figure 2.22 shows the prices in real terms as well as corrected for inflation, whereby Figure 2.22b is characterized by two indices, the 'consumer price index' (CPI)

66 and the 'producer price index' (PPI)

67.

As obvious from Figure 2.22b, prices were very low in the 19-nineties (with a very low in December 1998) with an unmistakably rising trend since then. The recent price evolution is given in Figure 2.23, showing a peak price in mid August 2006 of about 78 $/bbl. Over the last year, Brent crude-oil prices

66 CPI = a measure for the average change of the prices paid by private consumers for a market basket of consumer goods and services. 67 PPI = a measure for the level of prices at the wholesale or producer stage (based on several thousand commodity prices).


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have been within a 52.5 - 78 $/bbl band, clearly high compared to historic prices, even taken into account correction for inflation.

30

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80

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7

3/0

3/0

7

USD/b

EUR/b

Figure 2.23 Spot Brent crude oil price in $/bbl and €/bbl for the period 03 January 2005 - April 30 2007 (from Bloomberg).

It should be noted that the exchange rate €/$ can significantly influence the variations. At present, with the current €/$ exchange rate of about 1.3, there is an advantage for Euro-currency users, as can also be seen on Figure 2.23. The maximum price expressed in € equals about 61 €/bbl. This observation goes with a warning though in that a reversed exchange rate, of say $/€ = 1.25 (which has occurred in the not too distant past) would 'have led' to an oil price of 97 €/bbl. b. Natural Gas As explained, gas prices are indexed to oil, with a lag period of one to several months. The import price to the EU for piped gas and LNG shows a considerable rise from early 2005 onwards, as shown in Figure 2.24. This is to be compared with the Figure 2.22.

0

1

2

3

4

5

6

7

8

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2S06

LNG import prices into Europe

Selected NG pipeline import prices into Europe

USD/MBtu

Figure 2.24. LNG and natural gas pipeline import prices into Europe (EU15 member states average). (Source : IEA (2007), Energy prices & taxes, 4th Quarter 2006, Table 13.)


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c. Coal Although it is common 'saying' that coal prices are low and remain unchanged, it may be noted that coal prices have gone up considerable during the last few years (See Fig 2.25; the plot shows the period 1990-2006). Expressed in €, coal prices have fluctuated between 44 €/ton and 56 €/ton between January 2005 and September 2006.

0

10

20

30

40

50

60

70

80

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 1Q06

EU15 member states Belgium

+ 2Q06

USD/t

Figure 2.25. Variation of the steam coal prices in EU-15 and Belgium between 1990 and 2006 (From IEA, 2007, Energy prices

& taxes, 4th Quarter 2006, Table 13.)

d. Uranium Uranium-fuel prices were roughly constant and on average of the order of 5 €/MWhe (including the back-end costs) in Europe [IEA, 2005a] during more than a decade. From late 2004 on, Uranium raw material price went up drastically, partially because the stock of large amounts of enriched Uranium and Plutonium from military stocks, which came on the market after the collapse of the Soviet Union in 1991, is diminishing sharply and that on the other hand demand for uranium is soaring thanks to a renewed interest for nuclear power. The evolution of the raw material ("yellow cake") U3O8 prices since 1948 can be seen in Figure. 2.26.

Figure 2.26 Constant 2006 US$ vs. Current US$ Spot U3O8 Prices. (From The UX Consulting Company, 2007.)


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According to the International Atomic Energy Agency, worldwide 441 nuclear reactors were operating mid 2006, totalling 370 GWe capacity and generating around 16% of the world's electricity. Recent expansion has been most heavily concentrated in Asia with China, having currently 4 reactors under construction and planning a 5-to-6-fold capacity expansion over the next 15 years, and India which is currently building 6 more, scheduled to be operational before mid 2009 and added to the 17 it has already. The soaring uranium price also reflects supply constraints in Australia and Canada due to bad weather conditions and the time needed to realise new investments in uranium mines.

Informative Box: Relative Cost of Nuclear Fuel as Part of Nuclear Electricity Cost The relative cost of "nuclear fuel" as part of the cost for nuclear electricity generation is relatively small since nuclear power is mainly capital dominated. Therefore, the fluctuations of uranium prices do not have a big impact on the final nuclear electricity generation cost. It is important though to distinguish between the cost of the nuclear resource material (usually referred to as "yellow cake") U3O8 and the cost of the nuclear fuel cycle, which encompasses the nuclear fuel elements that will be put into the reactor and the "downstream", "back-end" or waste-management part. According to the IEA World Energy Outlook 2007 [IEA, 2006d], in its Figures 13.7 and 13.8, the fuel(-cycle) cost amounts to 7% to 14% of the total electricity cost, depending on the assumed discount rates and the assumptions for capital investment.

68 [IEA, 2006d] considers furthermore that about

25% of the fuel-cycle cost is for waste management. To produce then the PWR nuclear fuel elements, starting from U3O8, over conversion and enrichment to pellet sintering & assembly, the following numbers apply: uranium resource cost ~ 25% of total fuel cost, conversion ~ 5%, enrichment ~ 30%, fuel assembly ~ 15%. All this leads to a contribution of 1.75% to 3.5% of the U3O8 resource cost to the overall nuclear kWh cost. With these numbers, a doubling of the so called (total) nuclear fuel-cycle cost would lead to an increase of the kWh price by 7% to 14%, whereas a doubling of the resource U3O8 purchasing price, would lead to an increase of the kWh price by about 2% to 4%. An increase by a factor of 10 of the (total) nuclear fuel-cycle cost would lead to an increase of the kWh price by 63% to 126% (or thus roughly by a factor 1.6 to 2.3), whereas an increase by a factor of 10 of the resource U3O8 purchasing price, would lead to an increase of the kWh price by about 18% to 36% (or thus roughly an increase by 1/5 to 1/3). In some countries, the cost for the back end takes up a larger part of the fuel-cycle cost, so that the relative influence of U3O8 price fluctuation is even smaller than indicated here.

2.2.1.2. GHG Emission-Trading-Scheme Prices As of January 01 2005, the European Union has introduced an emission-trading scheme (ETS) for greenhouse gas (GHG) allowances,

69 under a cap and trade system with the aim to reduce mainly

CO2 emissions in the European Union, so as to live up to the Kyoto commitments. Allowances have been allocated (for free, called 'grandfathering') to large fossil-burning facilities, amongst which the electricity generation sector, through so-called National Allocation Plans (NAPs).

70 During the first

period running from Jan 2005 - end 2007, only CO2 is concerned; in the Kyoto commitment period 2008-2012, all GHG are concerned. The price evolution of the allowances is shown in Figure 2.27. Noteworthy is the crash in April 2006 because of lower reported actual emissions compared to what had been allocated to many players all over Europe. Since then, it seems that the price 'stabilized' for a while between 16 and 18 €/ton CO2

68 In general, one can say that nuclear fuel represents about 1/6 or ~ 15% of total electricity cost; for coal this is 1/3 to 40% and for gas one has 2/3 to 3/4. 69 Formally, on talks about European Union Allowances, or EUA 70 http://ec.europa.eu/environment/climat/emission_plans.htm


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after which the spot price for allowances to be handed in at the end of 2007 (the end of the first period) it decreased further even to below 1 €/ton; whereas the futures price for delivery in December 2008 has reached a level above 20 €/ton in May 2007.

Figure 2.27a. CO2 emission allowance trading in Europe: prices and exchanged volumes. (Source: Powernext, European Climate Exchange (ECX), Point Carbon. In : Lettre trimestrielle de la Mission climat de la Caisse des Dépôts, January 2007, nr 8.)

Figure 2.27b. CO2 emission allowance trading in Europe: prices and exchanged volumes. (Source: Fortis; Energy & Environmental Markets; CO2 Weekly, May 25, 2007) 2.2.1.3 Wholesale Electricity Prices Figure 2.28 shows a comparison of the wholesale forward prices for continuous delivery of 1MW during 1 calendar year, expressed in €/MWh, between the Belgium and the neighboring countries France, Germany and the Netherlands. Several general tendencies can be drawn from this figure. 1. Electricity wholesale prices have globally remained constant until the beginning of 2005; after that a remarkable price increase is observed; 2. Prices in Belgium and the Netherlands were situated well above those in Germany and France until the end of 2004. As of the beginning of 2005, however, the Belgian prices have

Emission rights exchanged over the counter Emission rights exchanged on the stock exchange Future price for delivery in dec 2008 Spot price


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converged towards those of France and Germany. This is because of the available cross-border capacity between France and Belgium has increased. The price convergence occurred before the actual activation of the new capacity as the market anticipates on future technical developments using forward contracts. 3. Two signatures can be seen in the price evolution of these wholesale electricity prices: first there is the gas price influence, as shown in Figure 2.24; in addition, there is the price of the CO2 emission certificates, as is clear from Figure 2.27 (see especially for the peak in July 2005, and the dip in April 2006).

Figure 2.28. Wholesale forward prices electricity. [G. Camps, CREG Press Conference July 05 2006]

A comparison with also the UK is shown in Figure 2.29, over the time period January 2005 till March 2007. From this figure it is clear that, for a considerable period of time, prices in the UK have been substantially higher than the prices in N-W Continental Europe because of the high gas prices and unilateral gas-dominated electricity generation, in addition to being an isolated market from electric viewpoint (import capacity only 3 % of the demand). Due to relatively warm winter conditions in 2006-2007, gas prices have decreased considerably (but likely only temporarily on the medium-term time scale [IEA, 2007 Natural Gas Market Review 2007]), with a resulting lower electricity price. It is furthermore shown also that continental prices crept up in the summer of 2006 after 'recovery' of the CO2 certificates, after which they started to decline as a consequence of "cheaper" gas prices in the fall of 2007. The reason for higher prices in the Netherlands is because of congestion in the B-NL direction. Usually, the Belgian prices are somewhat higher than the French ones, for an amount about equal to the transmission fee over the cross-border lines.


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Figure 2.29. Wholesale forward prices power baseload (Cal 08) (B, NL, DE, UK & FR).


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2.2.2 Energy Prices at the Consumer Level

In what follows, only some exemplary (but representative) elements of the price at the consumer level are given. Detailed figures can be found in the recent study by [Global Insight, 2006], and [CREG, 2006a,b]. Interesting information is also found in [IEA, 2006a], [VOKA, 2006] and [ANRE, 2005]. 2.2.2.1 Comparison of Belgian Prices with Neighboring Countries Following [Global Insight, 2006], the recent evolution of industrial and domestic consumer prices is shown in Figure 2.30. These prices are without taxes, levies or VAT. Furthermore, because of the market opening at different speeds between the Flemish Region and Wallonia and Brussels, averaged Belgian prices give a slightly distorted picture for the regions.

Figure 2.30. Evolution of Belgian electricity prices for industry and domestic (Dc) consumers. [Global Insight, 2006]

Compared to our neighboring countries, which average is set to 100% at any time, price variation is as shown in Figure 2.31.

Figure 2.31. Comparison of Belgian electricity prices with the average of our neighboring countries (set at 100%). [Global Insight, 2006]


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2.2.2.2 Breakdown of Belgian Electricity Prices When looking at the breakdown of the end-consumer price for large industrial, intermediate and domestic consumers, the following picture appears for January 2007 (on average — for details, see [Eurostat

71]):

€c/kWh

Large Industry (Cat Ii)

Intermediate Industry (Cat Ig) Vl - Wal

Domestic (cat Dd) Vl - Wal

Commodity price 88% 77% - 78% 47% - 39%

Transmission fee 5% 7% - 8.5% 5% - 6%

Distribution fee 0 1% - 3.5% 20% - 31%

Levies & Taxes 7% 15% - 10% 11% - 6%

VAT 0 0 17% - 17%

Total 6.57 Ave* 7.85 Ave

** 14.86

Cat Dd: 7,500 kWh/a (of which 2,500 kWh during night); Cat Ig: 24 GWh/a; Cat Ii: 175 GWh/a * Average price for Belgium; total price in Wallonia (Wal) about 2-3 % lower than in Flanders (Vl) ** Average price for Belgium; total price in Wallonia (Wal) about 20 % higher than in Flanders (Vl) Table 2.16. Breakdown of industrial and domestic electricity prices in Belgium

For final domestic consumers, taxes, levies and VAT make up about 1/4 of the total price. For industrial users, this is smaller, in large part because there is no VAT. For domestic consumers, levies and taxes are charged for about 1€c/kWh; they cover charges for things such as the Regulator, clean up of old (research-related) nuclear waste & decommissioning, a Kyoto contribution, a contribution for Public Service Obligation, an energy levy for financial balance of Social Security, a contribution for green electricity and CHP certificates, a.o.. The contribution for renewables is about 0.2-0.3 €c/kWh, while that for CHP is currently 0.1€c/kWh. Both are expected to rise when more renewables and CHP will be supported. Next to the levies and taxes, there are subsidies/discounts, most notably 100 kWh of free electricity for each family and each family member. (This is only the case in Flanders. Also is the alleged compensation for the losses of the municipalities, the so-called Elia tax, which is understood to disappear in the future). In addition, the socially weak get lower tariffs.

2.2.3. Evolution and Breakdown of Belgian Liquid Fuel Prices

For liquid fuel prices, it is instructive to look at the long-term price evolution of gasoline, diesel and heating oil, in current and in constant money. (Table 2.17.) It is clear that gasoline and diesel prices are higher than ever before, while this is not the case for heating oil (retail prices). The reason is the influence of excises and VAT. This is shown in Table 2.18.

71 http://epp.eurostat.ec.europa.eu/portal/page?_pageid=0,1136239,0_45571447&_dad=portal&_schema=PORTAL


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Table 2.17. Overview of gasoline, diesel and heating oil prices for some selected years. [G. van de Werve, BPF, 2007]

As is obvious from this Table 2.18, about 60% of the gasoline price consists of taxes (or said differently, the taxation level is 145%). For Diesel, the numbers are a bit lower, almost 50% of the end price consist of taxes, or a taxation level of about 90%. For heating oil, there are effectively no excise taxes, such that the taxation level is 'a mere' 25%.

Table 2.18. Price breakdown of gasoline, diesel and heating oil prices in April 2007. [G. van de Werve, BPF, 2007]

Since 1987, maximum liquid fuel prices are set through a so-called Program Contract. This measure allows adaptation of the prices to the ex-refinery prices on international markets, but it does so with some averaging and delay in order to dampen the fluctuations. Because of rising heating oil and gas prices in 2005-2006, the government has decided to give discount checks to the customers. In the long run such policies tend to mask scarcity of those products and reduce incentives of consumer to use fuel efficiency.


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2.3 Legal & Regulatory Framework The work in this report starts from the current legal and regulatory situation, on a European, national and Regional level. This includes the directives/regulations, laws and decrees on liberalization of the electricity and gas markets, on the Kyoto commitment and the EU Emission Trading Scheme, on energy efficiency, renewables and CHP obligations, and the Belgian nuclear phase-out law, amongst others. However, as the horizon of the CE2030 is the year 2030, details of the current legislation must be taken 'with a grain of salt' since the current legislation will very likely be changed/adapted and complemented over the coming two to three decades. The current legislation is to be considered as a starting point, and of course has to be abided by as long as it is in effect, but for the longer term, the CE2030 must rather consider it as setting the general framework with guiding principles. Furthermore, the CE2030 will permit itself to make recommendations for adapted or changed legislation. An overview of current legal and regulatory framework has been provided on the web site of the CE2030 [http://www.ce2030.be] and the web sites of the CREG [http://www.creg.be], VREG [http://www.vreg.be], CWaPE [http://www.cwape.be] and IBGE/BIM [http://www.ibgebim.be] are equally recommended.


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3. Challenges The population has no need for classical energy sources as such, but it wishes to enjoy energy services (such as comfortably heated dwellings, the possibility to cool food and beverages, the possibility to travel sufficiently fast to different places, etc). With which energy sources or energy-conversion technologies that happens, is not really of interest to the consumer. The most important thing is that those services are available whenever the customer wishes to call upon them (hence, reliability), that this has no side effects for health and environment (e.g., sufficiently clean), and that all this is available at an acceptable price level (thus affordability).

Establishing an energy provision system that is sustainable (in a pragmatic sense) is not an easy task and is characterized by a variety of challenges. Generally speaking, the following concrete elements must be pursued [D'haeseleer, 2005; CEU, 2005b]:

- avoiding unnecessary waste of energy, and strive for an energy conversion that is as efficient as possible (and reasonable). This aspect stresses energy saving where possible and meaningful (i.e., cost-efficient);

- ensuring reliable and secure energy supply routes for the future; - guaranteeing that energy services are provided with a minimum use of scarce resources; i.e.,

at minimal total cost (including external costs — to be discussed shortly); - limit energy-related pollution and waste flows into the environment;

- limit hazards and risks to human health from energy use. Because of the future uncertainties for a clean, reliable and affordable energy provision, it looks like there is no “silver bullet” and that we will have to keep all options open; it is expected that many energy-conversion technologies can contribute only to a limited extent, certainly in Belgium. We will have to rely on a reasonable mix of fuels and conversion technologies if we wish to reach a sustainable energy-provision system.

3.1 Security of Supply We remark that the notion of reliable energy provision, or thus a guaranteed security of supply, actually has three facets. First, there is what could be called the strategic security of supply, intimately related to energy import dependency. Here, the issue at stake is the timely availability of sufficient primary energy (mostly fossil or nuclear fuels). In this regard, especially those regions that have no or insufficient domestic primary energy sources need to remain alert at all time concerning their strategic energy supply. Especially because of the concentration of most primary fossil sources in the Middle East and the former Soviet Union, geopolitical circumstances and lack of timely investment in 'production' facilities upstream could hamper a guaranteed and timely delivery. For nuclear fuel, the strategic security issue is less of a problem, because of a world-wide distribution of resources, and because of the large amount of energy stored in nuclear fuel (of the order of one to a few years of production of electricity per batch of fuel elements for nuclear reactors). Most of the renewable energy is indigenous, and each kWh or Joule 'produced' via renewable sources need not be imported as a primary source .

72

Renewable energy contributes therefore to strategic security of supply. Although this is no guarantee in the long run, the broadly accepted but often forgotten wisdom should be an important guideline: diversify sufficiently and do not put all the eggs in the same basket. To secure a fluent and continued delivery of imported primary sources, it is important to spread the risks sufficiently and aim for a diverse portfolio: pay attention to stable long-term contracts with reliable partners make sure that a considerable fraction of primary energy is well storable.

72 Note that biomass can be grown domestically but it can be imported as well.


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The second and third aspects are related to the continuous delivery of power73

, and this both for supply of electricity (i.e., avoiding blackouts) and the guaranteed supply of sufficient gas flow. In this context (and this is the second aspect), sufficient investment in electricity generation in the country and in neighboring countries, gas-production equipment in gas-producing countries and electricity and gas transport capacity (especially peak capacity) is a necessity. In liberalized and 'over'-environmentally regulated markets, this could give rise to 'late' investment actions, as has been shown in California in the early 2000s. This is usually referred to as 'adequacy' of investments. To cope with fluctuating and non-dispatchable powers sources (such as e.g., wind), sufficient investment in reserve capacity is required (both in dispatchable generating capacity and in transmission capacity). The third element, refers to the avoiding of blackouts or interruption of delivery of power, and is called the 'reliability' issue. This issue is related to (in)sufficient maintenance, appropriate diagnostics, unforeseen circumstances, stretching too far the limits of what is technically reasonable for the existing equipment, assure sufficient fall back positions whenever a component fails

74.

3.2 Clean Energy Provision As to the issue of a clean energy provision, especially aspects such as health, safety and environmentally friendliness require attention. In practice, this means that a sufficient air quality should be guaranteed (which encompasses constraints for the emissions of NOx, SOx, volatile organic compounds (VOC) and very fine dust PM10

75, and the avoidance of ozone, amongst others) and that

the CO2 emissions should be decreased. About the radiological aspects of nuclear energy, there exists less of a consensus; while an important part of the population considers everything related to radioactivity rather skeptical and disapproves of it, the majority of knowledgeable experts claiming to rely on rational arguments, put these dangers into perspective and consider them as acceptable. Before dealing with the most pertinent challenge on the environmental scene, we introduce first the concept of external costs and 'optimal' level of environmental burden according to environmental economics principles. [Field, 2002]

3.2.1 Internalizing External Costs as a Means Towards a Sustainable Energy Provision

The Concept of External Costs Under the assumption of full information, it seems straightforward to “force” a sustainable energy provision. If one were to succeed in computing the cost of all adverse effects of the energy provision system and one would manage to incorporate those additional costs into the market price, then one could expect that society would “automatically” converge to a sustainable energy provision. This is the issue of internalizing the external costs. Put quite generally, external costs (sometimes called costs “for third parties”) are those “costs” which are made when consuming or producing goods or services and which are not paid for by the market parties (i.e., the consumers and the producers). Often, it concerns costs which are related to environmental degradation and which are being borne by the society at large. The total cost for society, after the external costs have been appropriately evaluated and incorporated —the latter being called the “internalization” of the external costs— is called the social cost.

76

73 “Power” is considered here as the “flow” of energy; i.e., actually as the time derivative of energy. It is not solely related to electric power. 74 This is usually referred to as being N-1 secure. The so-called N-1 rule signifies that the system still has to function whenever one component fails. 75 PM10 is particulate matter with a size smaller than 10 micrometer. 76 Note that "social" cost refers to the sum of private cost (the usual cost considered) and the external cost (which is usually not incorporated in the cost). The terminology "social cost", as utilized further in this report, has no relationship to "social aspects" of energy costs (in the sense of employment, the social weak classes, etc.).


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To make sure that the users of goods and services take the external costs into account, one can make use of different instruments ranging from regulations on the technology to be used to taxes on external costs or a combination of both. The market price can already contain certain taxes and subsidies (as well as possibly monopoly margins) that need to be accounted for before adding an external tax. It is best to impose the externality tax as close as possible to the source of the externality so that a maximum of flexibility (correcting fuel quality, processes and level of output) is offered to correct the external damage. The computation of the external costs due to emissions or discharges of “pollutants” (such as CO2, NOx, SOx, radioactive isotopes, etc) is actually —at least in principle— equivalent with the determination of the Marginal Damage cost, represented by MD. This marginal damage cost is the extra cost per unit extra discharge of the pollutant. This curve MD is often an increasing function of the amount of emissions; the larger the emission, the bigger the rise in damage. See the curve labeled MD in Figure 3.1. To decrease the environmental damage cost, one can take measures to diminish the emissions. This could be done by substituting the type of fuel —e.g. from coal to natural gas for electricity generation— or by implementing technological fixes or by using a completely different technology (e.g., more efficient conversion- or production technologies, environmental-technical measures such as exhaust cleaning facilities), or one could also decrease the level of consumption of energy. In general, these measures are not without cost, and usually these costs increase the further one wants to reduce the environmental damage. To characterize these costs, one uses the so-called Marginal Abatement cost curve, abbreviated as MAC. As is evident from Figure 3.1, there are costs related to the emission of undesirable substances, but also to the reduction of them. Economically seen, the most efficient or optimal level of emissions is given by the point e*, where the marginal damage cost (MD) equals the marginal abatement cost (MAC), equal to s. Only for that point, the area under the two “triangular” surfaces b + c is minimal. It is clear that one must look for a compromise between emission and abatement of it. For an emission level larger than e*, society suffers welfare losses since the MD exceeds the MAC; for an emission level smaller than e*, avoided MD are lower than MAC, so society (globally seen) has spent too many resources, that could have been allocated more efficiently somewhere else. Hence, from a welfare point of view, e* is the optimal level of emissions.

Figure 3.1. The marginal damage function (MD) and the marginal abatement cost function (MAC) as a function of the emission level of a particular pollutant, expressed in ton. The point e* is the most “optimal” emission point, where the marginal abatement cost equals the marginal damage cost, equal to s. The total cost for society equals the area of the triangular surfaces b + c.

For energy-related emissions, it seems that the damage is a linear function of the concentration of pollutants. [CEU, 1995 & 1999] Hence, the marginal damage function is roughly constant. If one were to set a pollution (e.g., a CO2) tax equal to the value of the constant marginal damage cost, the system would naturally converge towards the most efficient point e*. If the total amount of emissions is to be reduced (and we assume for simplicity that local concentration limits are not exceeded), then this type of reasoning on marginal-cost functions furthermore leads to


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the result that the emission reduction efforts must be distributed such that the marginal abatement costs are equal. This is the so-called equi-marginal cost principle. Consider the example of Figure 3.2 for the case of two power plants (one with a cheap reduction potential MAC2, and one with an expensive reduction potential MAC1), belonging to the same electricity-generation company. Assume that these plants currently both emit an amount of e0. Consider now the case that the generation company is required to reduce the total emission level from 2e0 to 2eZ. Clearly, rather than reducing the emissions from e0 to eZ in each plant (leading to a total abatement cost of e0eZB1+e0e2A2, the company will choose to reduce the emissions in plant 1 to e1 only, whereas the emissions will be reduced to e2 in plant 2. The points e1 and e2 are determined by the equal marginal abatement costs C1 and C2, and they are a simple consequence of the rule that one should always reduce the next ton of the pollutant where it is the cheapest. It is easily seen that the total abatement cost, given by the sum of the two triangular-like areas e0e2C2 and e0e1C1 is the smallest possible and clearly smaller than e0eZB1+e0eZA2.

Figure 3.2. Equi-marginal principle, and explanation of emission trading. (See text.)

An instrument that, in a first approximation,

77 can be proven to be as effective as a pollution tax, is an

emission-trading scheme. In such scheme, a fixed emission cap is set for a whole group of emitters (e.g., for a country or a sector), but it is left to the emitters to distribute the reductions "automatically" according to the equi-marginal principle. Consider again the example of Figure 3.2 for the case of two power plants, but now belonging to two different electricity generation companies. To reduce the total emission level from 2e0 to 2ez, a maximum number of emission rights of 2ez are made available, whereby each plant gets a number of emission permits

78 eZ allocated. The plants are allowed to sell

the emission rights to each other; it is clear that trading of certificates will occur in the direction from plant 1 to plant 2, such that the latter is willing to reduce to level e2 while the former can remain at level e1. The price of the emissions will be situated between A' and B', and trading will occur until the equilibrium price C' has been reached. If this principle is applied to a multitude of facilities, it is guaranteed that the total cap of emissions will not be exceeded and at a minimal cost for society. If the permits are traded in a perfect and transparent market with many facilities participating, then the permit price should be equal to the equi-marginal abatement cost (like point C' in the above example). In practice, however, the permit price may fluctuate considerably, because of a variety of factors (such

77 In an economy with other taxes, one needs to take into account the interactions of the externality taxes with the rest of the economic system. This has three important implications: a) if there are revenues from carbon taxes, then it is best to use these for a reduction of the most distorting taxes in the economy (labor taxes and sometimes capital taxes); b) preference must be given to an instrument that generates revenues, so emission taxes or auctioned tradeable permits are preferred to grandfathered emission permits; c) even when externality tax revenues are used for a reduction of labor taxes, the overall cost of emission reduction increases and this means that it may be economically optimal to reduce the environmental quality objective. 78 The words emission "rights", emission "permits", emission "allowances" and emission "certificates" are all to be considered as synonyms.


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as distorted initial allocation of permits, speculation, lack of transparency and information, etc). What we have explained above applies to other "entities" as well, like industrial sectors, countries etc. It must be noted that the MAC curves can change in time, due to a variety of actions. As an example, the MAC curve of a country can suddenly change as a consequence of a decision to phase out nuclear power. Each moment a nuclear plant is shut down permanently, a cheap way of reducing GHG is suddenly given up, and the MAC curve shifts to the right in the context of Figure 2.3. Typical Numerical Values of External Costs for Energy Conversion Technologies In practical terms, it is useful to give an estimate for external costs of some typical technologies. Details can be found in [Albrecht, 2006]; here we only give some summary information. The first table (Table 3.1), gives the external cost for electricity generation units, in €/MWh. The second table (Table 3.2) focuses on transport-related external costs, and is expressed in €/pkm. Values for freight transport are given in [Albrecht, 2006]. It must be noted that these numbers apply to currently existing technologies; the numbers for 2030 will certainly be different. In any case, only the order of magnitude should be considered.

Coal plants without gas cleaning 81 Coal plants with gas cleaning 32 Gas plants 28 Combined cycle gas plant (STEG) 11 Oil plant 142 CHP gas (turbine) 8.3 CHP gas (engine) 19 CHP oil 61 Waste burning with energy recovery 80 Wind 1 PV 5 Hydro 2.2 Nuclear 0.7

Table 3.1. External costs of electricity production in € per MWh for Flanders (2002).79

Urban transport € per passenger kilometer

Brussels car (petrol) 1.6 Brussels car (diesel) 3.85 Brussels urban bus (diesel) 1.45

Extra-urban transport € per passenger kilometer

Belgium car (diesel) 1.2 Belgium car (petrol) 1.15 Belgium coach (diesel) 0.16

Table 3.2. Air pollution costs due to passenger transport in Belgium.80

For information, the social cost, as a sum of the private cost and the external cost, for the current electricity generation technologies, as reported in the framework of the DG Research EUSUSTEL project [ http://www.eusustel.be ] has been included in Annex 2.

79 Source: Torfs, R., De Nocker, L., Schrooten, L., Aernouts, K. and Liekens, I. (2005). "Internalisatie van externe kosten voor de productie en de verdeling van elektriciteit in Vlaanderen" (MIRA/2005/02, April 2005) 80 Source: European Commission (2003). External Costs. Research results on socio-environmental damages due to electricity and transport (EUR 20198), p.14


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3.2.2 The Enhanced Greenhouse-Gas Effect and Climate Change

3.2.2.1 The Climate-Change Issue in General An environmental constraint that will put a definite mark for the next few years, but also in the long run, is undoubtedly the enhanced greenhouse effect. It is a global issue, because the most important anthropogenic greenhouse gases (such as CO2) remain several decades and become well-mixed in the atmosphere. Therefore, a ton of CO2 emitted in Brussels has the same climate effect as a ton of CO2 emitted in Tokyo or elsewhere. Another important characteristic of the climate problem is that greenhouse gases are emitted in a broad range of human activities, which means that there exist no “simple” solutions. Besides water vapor, carbon-dioxide (CO2) is the most important greenhouse gas (GHG). It is the most important anthropogenic GHG, as the amount of water vapor is not significantly affected by human activities. Since these gases absorb the long-wavelength heat radiation re-emitted by the earth, an increase of the concentration of those gases leads to a global temperature increase on earth. This effect is called the enhanced greenhouse effect [IPCC, 1996; IPCC, 2001a; Houghton, 2004]. The gas of most concern is undoubtedly CO2, as it is the gas that is released when burning fossil fuels and when forests are cleared. Since the industrial revolution (about 1800), the CO2 concentration in the atmosphere has increased by more than 30%. See Figure 3.3.

Figure 3.3. Evolution of the atmospheric concentration in CO2 over the past 1000 years. The vertical scale is in parts per million (ppm). [IPCC, 2001a]

According to observations, this has contributed to a noticeable temperature increase, as shown in Figure 3.4. [IPCC, 2007a]. The IPCC concluded that it is very likely that average NH temperatures during the second half of the 20th century were warmer than any other 50-year period in the last 500 years and likely the warmest in at least the past 1300 years.


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Figure 3.4. Records of Northern Hemisphere temperature variation during the last 1300 years with 12 reconstructions using multiple climate proxy records shown in color and instrumental records shown in black.(IPCC 2007a Technical Summary, Figure TS20)

Even at this moment, it must be recognized that uncertainties remain about the quantification of the enhanced greenhouse effect. Although still many questions remain unanswered, the numerical simulations, on the one hand, and the experimental (historical) evidence of the increase in temperature are such that the Intergovernmental Panel on Climate Change (IPCC), being a UN recognized international team of climate experts, recently concluded that “most of the observed increase in global average temperatures since the mid-20th century is very likely due to the observed increase in anthropogenic greenhouse gas concentrations.” (IPCC, 2007a). This is an advance since the IPCC (2001a) conclusion that “most of the observed warming over the last 50 years is likely to have been due to the increase in greenhouse gas concentrations”. A convincing argument is presented in Figure 3.5. The temperature observations are represented by the black curve. Numerical simulations have been performed to compare reality with computational models. The blue-shaded bands show simulation results when only natural 'forcings' have been used, whereas the red-shaded bands show the results when a combination of both natural and anthropogenic 'forcings' is used. The agreement with the observations is much better in the latter case. Hence the responsibility of man-caused GHG emissions.


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Figure 3.5. Comparison of observed continental- and global-scale changes in surface temperature with results simulated by climate models using natural and anthropogenic forcings. Decadal averages of observations are shown for the period 1906 to 2005 (black line) plotted against the centre of the decade and relative to the corresponding average for 1901–1950. Lines are dashed where spatial coverage is less than 50%. Blue shaded bands show the 5–95% range for 19 simulations from five climate models using only the natural forcings due to solar activity and volcanoes. Red shaded bands show the 5–95% range for 58 simulations from 14 climate models using both natural and anthropogenic forcings. {IPCC, 2007a, Figure SPM 4}

The climate experts of the IPCC are mostly concerned with the rate of increase of CO2 as a consequence of human activities: as shown in Figure 3.3, during the last two hundred years, the CO2 concentration in the atmosphere has increased by the same amount (from 280 to 360

81 ppmv) as

during the previous twenty thousand years (from 200 to 280 ppmv). The atmospheric concentration of carbon dioxide in 2005 exceeds by far the natural range over the last 650,000 years (180 to 300 ppm) as determined from ice cores. This concentration will continue to increase until the day human emissions are not larger than the absorbing capacity of natural systems (oceans, soils, and vegetation). These absorb today somewhat less than half of human emissions, and this proportion is projected to decrease. As long as concentration increases, surface temperature will increase in response. Sea level will also rise, because of water thermal expansion and land ice melting). Hydrological changes will also take place. These changes in climate will be associated to a variety of impacts on human systems (water resources, agriculture, health, hydro-electricity, power plant cooling, fisheries …) and natural systems (glaciers, ecosystems, water currents,…) (See [IPCC, 2007b]). The IPCC reports provide the information needed to assess the risks associated to different greenhouse gas concentration levels. For global temperature above approximately 1.5 degrees

81 In 2005, the CO2 concentration had already increased to 379 ppmv.


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Celsius higher than the present temperature, i.e., approximately 2°C higher than the pre-industrial temperature, there are already significant risks to ecosystems and risks due to increasing extreme climate events (heat waves, floods, more intense tropical storms). The last IPCC report concluded for example that “approximately 20-30% of plant and animal species assessed so far are likely to be at increased risk of extinction if increases in global average temperature exceed 1.5-2.5°C [above the 1980-1999 temperature]” (IPCC 2007b). On the basis of the first IPCC report in 1990, which contained similar information with less confidence, many scientists pleaded 15 years ago for the precautionary principle: the risks are too high to ignore the enhanced greenhouse effect. This led to the UN Framework Convention on Climate Change (UNFCCC), adopted in 1992. The ultimate objective of that Convention is to “achieve […] stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system” (Article 2 of the UNFCCC). There is no universally-agreed interpretation of this language into emission trajectories. One way to proceed would be to agree in a global temperature not to be exceeded, then to translate this into greenhouse gas concentrations, and finally emissions. The European Union is the only group of countries which, as early as in 1996, has taken an official position on what the Article 2 of UNFCCC meant in their view: maintain the temperature increase below a 2°C increase over the pre-industrial value. The EU Environment Council recognized in March 2005 that this required stabilization of GHG concentrations well below 550 ppmv of CO2-equivalent

82. Given that today's concentration of CO2 is

already above 370 ppmv, it shows that very stringent CO2-emission reduction measures will be necessary in the mid-term future. The EU Council declared in March 2005 that it believed [on the condition that they are not alone to act] that «reduction pathways by the group of developed countries in the order of 15-30% by 2020 and 60-80% by 2050 compared to the baseline envisaged in the Kyoto Protocol should be considered». In March 2007, the EU Spring Council went a step further and concluded that “Developed countries should continue to take the lead by committing to collectively reducing their emissions of greenhouse gases in the order of 30% by 2020 compared to 1990. They should do so also with a view to collectively reducing their emissions by 60% to 80% by 2050 compared to 1990. In this context, the European Council endorses an EU objective of a 30% reduction in greenhouse gas emissions by 2020 compared to 1990 as its contribution to a global and comprehensive agreement for the period beyond 2012, provided that other developed countries commit themselves to comparable emission reductions and economically more advanced developing countries to contributing adequately according to their responsibilities and respective capabilities. “[…] The European Council […] decides that, until a global and comprehensive post-2012 agreement is concluded, and without prejudice to its position in international negotiations, the EU makes a firm independent commitment to achieve at least a 20% reduction of greenhouse gas emissions by 2020 compared to 1990.”

83

82 EU Environment Council conclusions, 10 March 2005 : (The Council REAFFIRMS that, with a view to meeting this objective, overall global annual mean surface temperature increase should not exceed 2°C above pre-industrial levels; (…) Recent scientific research and work under the IPCC indicate that it is unlikely that stabilisation of concentrations above 550 ppmv CO2 equivalent would be consistent with meeting the 2°C objective and that in order to have a reasonable chance to limit global warming to no more than 2°C, stabilisation of concentrations well below 550 ppmv CO2 equivalent may be needed;(…) Recent scientific research and work under the IPCC indicate that keeping this long-term temperature objective within reach will require global greenhouse gas emissions to peak within 2 decades, followed by substantial reductions in the order of at least 15% and perhaps by as much as 50% by 2050 compared to 1990 levels; (…) In view of the global emission reductions required, global joint efforts are needed in the coming decades, in line with the common, but differentiated responsibilities and respective capabilities, including significantly enhanced aggregated reduction efforts by all economically more advanced countries. Without prejudging new approaches for differentiation between Parties in a future fair and flexible framework, the EU looks forward to exploring with other Parties possible strategies for achieving necessary emission reductions and believes that, in this context, reduction pathways by the group of developed countries in the order of 15-30% by 2020 and 60-80% by 2050 compared to the baseline envisaged in the Kyoto Protocol should be considered. 83

“Developed countries should continue to take the lead by committing to collectively reducing their emissions of greenhouse gases in the order of 30% by 2020 compared to 1990. They should do so also with a view to collectively reducing their emissions by 60% to 80% by 2050 compared to 1990. In this context, the European Council endorses an EU objective of a 30% reduction in greenhouse gas emissions by 2020 compared to 1990 as its contribution to a global and comprehensive agreement for the period beyond 2012, provided that other developed countries commit themselves to comparable emission reductions and economically more advanced developing countries to contributing adequately according to their responsibilities and respective capabilities. It invites these countries to come forward with proposals for their contributions to the post-2012 agreement. The European Council emphasises that the EU is committed to transforming Europe into a highly energy-efficient and low greenhouse-gas-emitting economy and decides that, until a global and comprehensive post-2012 agreement is concluded, and without prejudice to its position in international negotiations, the EU makes a firm independent commitment to achieve at least a 20% reduction of greenhouse gas emissions by 2020 compared to 1990.” (EU Spring Council, 9 March 2007).


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The latest IPCC (2007c) report will require further reinforcements of the reduction objectives if a 2°C maximum temperature increase is sought: to maintain the ultimate global temperature increase below the 2 to 2.4°C range (above the pre-industrial value), concentrations of GHG need to stabilize between 445 and 535 ppm CO2-eq, global emissions of CO2 would need to peak between 2000 and 2015, and they would need to be reduced by 50 to 85% by 2050 with respect to 2000

84. The good news is that

the same report estimates that the reduction (compared to the baseline) of average annual GDP growth rates until 2050 due to macro-economic costs for multi-gas mitigation consistent with emissions trajectories towards stabilization at the above levels are estimated at less than 0.12% (see Table SPM.4 and SPM.6 of the SPM of IPCC 2007c). The Kyoto protocol, which commits developed countries to reduce their emissions by an average of 5% in 2008-2012 compared to 1990 is nothing more than a small first step. Future emission reductions will have to be much stronger and will require ambitious policies, in all countries. It will be necessary to manage energy demand, enhance energy efficiency, decarbonize our energy provision, and reduce deforestation (see [IPCC, 2007c]). Actually, the situation is even more alarming. Still according tot the IPCC, due to the huge inertia of the climate system, we will not be able to stabilize temperature quickly and we will have to complement mitigation (reduction of emissions) with adaptation to the consequences of the part of climate change that we will not be able to avoid. The recent 'Stern review' quantifies the costs of impacts under a 'business as usual' scenario: «If we don’t act, the overall costs and risks of climate change will be equivalent to losing at least 5% of global GDP each year, now and forever. If a wider range of risks is taken into account, the estimates of damage could rise to 20% of GDP or more.» [Stern, 2006] According to the current projections, the long-term consequences of the enhanced greenhouse effect in the absence of mitigation are far from negligible. [IPCC, 2007a]. Over the period from 1990 till 2100, we would be confronted with a global average temperature increase of 1.1 to 6.4 °C in the absence of climate policies. This projected increase is much larger than the observed increases during the 20-th century. As far as the sea level is concerned, matters are not any better. Still according to the same report, the average sea level would rise by at least 20 cm to 60 cm between the years 1990 and 2100, and possibly several meters over the following centuries. In the mean time, the international community has decided not to wait for the realization of these projections, with the argument “better safe than sorry”. Through the Kyoto protocol

85 and over the

period 2008-2012, the EU has committed itself to reduce its GHG-emissions to 92% of what they were in 1990.

86 Belgium has committed itself to -7.5% reduction (and the 'industrial world'

87 has originally

agreed to reduce by 5.2%.). More information on the ins and outs of climate change can be found in [Houghton, 2004; IPCC 2007a, 2007b and 2007c; Stern 2006; and van Ypersele, 2006]. 3.2.2.2 Flexible Mechanisms to Justify Emission Reductions The climate change issue is of a global nature (as opposed to local air pollution concerns). Hence, the overall aim must be to reduce GHGs on a worldwide scale. It is therefore not necessary to reduce the GHG emissions everywhere by the same percentage, as long as the global result is realized. Because the degree of development of countries differs (developing, industrialized, emerging, prosperous, re-orienting, etc, both in- and outside Europe) there is justifiably a need to devise a 'fair' allocation of the burden between countries. In what follows, we first focus on the long-term issue, i.e. the post-Kyoto framework; the actual agreements in the context of the Kyoto Protocol are discussed thereafter. We hereby assume that the EU as a group has accepted a particular 'appropriate' post-Kyoto reduction limit of GHG emissions.

84 See Table SPM.5 in the Summary for policy makers of the WG3 contribution to the 4th IPCC Assessment Report (AR4), available on www.ipcc.ch or www.climate.be/ipcc. 85 See http://www.unfccc.int 86 The exact reference year for most gases is 1990 and 1995 for hydrofluorocarbons; perfluorocarbons and sulphur hexafluoride are expected to be fixed officially at the end of 2006. 87 Technically called the 'Annex 1 countries'.


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From a welfare perspective, the environmental economics equi-marginal principle should apply. Emission reductions should take place there where they are the cheapest (see § 3.2.1.). However, it is important to make a distinction between the obligation of a country: - to reduce GHG emissions on its own territory (which we will henceforth refer to as 'domestic' reductions); and - to bear the responsibility (including financially) that somewhere else somehow GHG reductions take place. Within the EU, then, a burden sharing between its members can be considered. This is usually referred to as the burden sharing/differentiation within the European 'bubble'. Two major (extreme) approaches could be contemplated when a so-called bubble is considered. A first one would start from the marginal-abatement cost curves from the countries and would set different reduction limits per country, guided by the equi-marginal principle. If the EU were one solid "corporate" entity, without local interests, just like one company with two power plants, as in the example above in § 3.2.1, then the reduction limits of each country could be set as explained in Figure 3.2: country 1 should reduce up to point e1 while country 2 must reduce up to point e2. In this philosophy, is seems logical that each country reduces its emissions domestically. It must be noted, however, that the country with the lowest MAC bears the highest cost, as the full abatement cost is given by the area under the curve. For the case of Figure 3.2, the triangular-like area e0e2C2 is clearly larger than the area e0e1C1. But, the EU is not a corporate entity and the Member States (MS) have their own local interests. One could therefore be inclined to say that the total abatement cost per inhabitant should be equal

88 for all

EU countries, leading to a reduction responsibility for country 2 such that it can emit an amount in-between e2 and eZ (here taken for simplicity halfway between), e.g., e2+(eZ-e2)/2 = (e2+eZ)/2. Country 1 would then have to guarantee an emission reduction of eZ+(e1-eZ)/2 = (eZ+e1)/2.

89 However, in order to

have the emissions reduced where it is the cheapest, country 1 will do the emission reduction e0-e1 domestically, while it should be allowed to finance emission reductions beyond this point in country 2. Country 2 from its side, will be willing to reduce its emissions domestically by e0-e2 as long as somebody else pays for these last emissions beyond the point e2+(eZ-e2)/2 = (e2+eZ)/2. This financing abroad of emission reductions, can also be accomplished through the exchange of emission permits (often referred to as "emission trading"; being already explained above, but further considered below). This first approach seems simple and "fair", but there is a problem in that the marginal abatement cost curves are not really known in advance and would have to be "estimated". In a second approach, one would set the same emission reduction limit for every MS of the EU, but in terms of responsibility.

90 The MS are then not obliged to reduce the emissions domestically; one

Member State can finance emission reductions in other Member States91

, by means of certain arrangements or emission trading. In this second approach, there is no need to know the MAC curves of all the countries involved; knowing its own MAC curve suffices. This approach is clearly the best whereby ("idealized") emission trading will automatically lead to a distribution of the reduction in line with the equi-marginal principle. Based on the abatement costs of the different countries, those with the lowest abatement cost will see the biggest reductions in % on their territory reduced. In practice, a combination of the two approaches is to be expected, as neither approach takes into account particular circumstances of the different countries, such as historical elements, the level of prosperity of a country, etc. Indeed, it may be unfair to some regions/countries if they all have to make an effort as explained above. It should perhaps be more equitable if the level of prosperity of the

88 Another option would be to aim at equal total abatement cost relative to per capita income, since equal absolute abatement costs have different consequences in rich compared to poor countries. 89 More generally, one could say that country 2 must guarantee an emission reduction of e2+ξ(eZ-e2)=eZ-(1-ξ)(eZ-e2) while country 1 must guarantee an emission reduction of e1-ξ(e1-eZ)=eZ+(1-ξ)(e1-eZ), where ξ represents a fraction between 0 and 1. 90 This percentage wise reduction limit is then translated into absolute emission reductions (in Mtons), e.g., based on the given percentage of domestic emissions, or as the overall EU absolute reduction amount in Mton, scaled relatively per number of inhabitants of the MS. 91 Or even outside the EU, as will become clear when CDM and ET are explained.


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region/country (e.g., expressed in income per capita) were taken into account to shift the biggest burden to the strongest shoulders. Furthermore, historic and structural circumstances may play a role as well for distinguishing the national targets. In this regard, it must be recognized that some deliberate and voluntary policy choices and constraints imposed by a country upon itself should, as a rule, not be invoked to bargain for less stringent emission reduction limits, quite the contrary. Three examples come to mind. If a country (e.g., to "protect" its domestic coal industry) were to decree that all new electric power plants must be coal fired, then it is logical that that country must accept a stricter reduction commitment (in terms of obligation/responsibility) than the other countries.

92

Similarly, if a country, to protect its car-manufacturing industry, refuses to introduce commonly accepted speed limits, that attitude should in fact be penalized by a more stringent reduction obligation. Still along the same line, if a country deliberately decides to phase out its nuclear power, then it deliberately increases its own marginal abatement cost (because it renounces an existing cheap CO2 reduction option), that should not be invoked to obtain a less stringent CO2 reduction commitment. In this last case, also a tougher reduction commitment could be defended just as with the other two cases. However, in this "sensitive" case, it is perhaps advisable to enforce the same reduction limits as would be justified in the absence of a nuclear phase out. Having said all that, and in contrast to the above, other types of policy choices of Member States could justify less stringent reduction limits within a bubble. Indeed, a country that sets extremely ambitious domestic targets for its own emission-free energy-'production' sources (e.g., well above the renewable EU targets envisaged

93), or that decrees that all its newly bought vehicles should be zero-emission

vehicles, all paid for by its inhabitants, either directly or via levies, could make a case to enjoy less a stringent GHG-reduction obligation.

94

A methodology that has served as one of the inputs to the negotiations during the current Kyoto burden sharing, is the so-called 'triptych approach'. [Phylipsen et al., 1998] In that approach, three categories of emissions, based on what its authors call the main issues, namely standard of living, fuel mix, economic structure and competitiveness of internationally oriented industry, are distinguished: in the power-producing sector, the internationally oriented energy-intensive industry and the domestic sector. An important influencing factor in this triptych allocation approach is that the development of nuclear power is treated according to national preferences, but in a "mitigating" sense: a country with a nuclear phase out is considered to have a very expensive power sector, and therefore is allowed to an overall relaxing of its imposed reduction in terms of %.

95 This has as a consequence that, according to

this methodology, a nuclear phase-out country (in the paper by [Phylipsen et al., 1998] this was the case with Sweden), is allowed to transfer the costs of its own choices/preferences to its neighbors. A de facto externalization of the national climate policy to the other countries in the bubble takes place. The final burden sharing agreement within the EU did take into account arguments as just mentioned, but it was the result of a political negotiation between the MS. The EU burden sharing agreement agreed upon for the Kyoto protocol is as shown in Table 3.3. (see e.g., [Bollen & Van Humbeeck, 2002; Pepermans et al., 1999]).

92 Because otherwise the country in question, after having increased the CO2 emissions considerably (in its own country but also in the EU as a whole), could still do most of its efforts abroad at a reasonable cost, letting then the other countries also pay for its "decision". 93 But only considering newly invested projects since 1990, so as to avoid historic renewable generation such as, e.g., hydro-energy in mountainous regions. 94 Since by doing so, that country has decreased its (and the EU's) emissions considerable, allowing other countries to benefit from the fact that there still exist low-cost abatement options in that country. 95 Note that this is exactly the opposite of what it should be as explained above.


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Member State Commitment

Austria -13.0% Belgium -7.5% Denmark -21.0% Finland 0.0% France 0.0% Germany -21.0% Greece +25.0% Ireland +13.0% Italy -6.5% Luxembourg -28.0% Portugal +27% Spain +15.0% Sweden +4.0% The Netherlands -6.0% United Kingdom -12.5%

Table 3.3 Burden sharing within the EU-15 for the Kyoto protocol.

It has been shown in [Eyckmans, 2002] that this burden sharing was not guided by an equi-marginal abatement-cost efficiency principle. Countries such as the Netherlands and Belgium were considered to have a reduction share that was relatively too high. Germany and Denmark supposedly got away too 'easily'. See also [Bollen & Van Humbeeck, 2002]. But as argued above, the equi-marginal cost principle should not necessarily be the ideal guiding principle for setting the reduction limits (for which a country is responsible); it is the correct guiding principle for where the reduction actually is to take place physically. Once a burden sharing agreement has been agreed upon, one way or the other, there are different so-called flexible mechanisms that can be relied upon to finance emission reductions elsewhere. Joint implementation (JI) and the Clean Development Mechanism (CDM) constitute a possibility by which countries (after having received approval by UN services) can invest in clean technologies abroad to reduce GHG emissions. JI applies to projects in countries that are also committed to Kyoto reductions; CDM applies to projects with countries that have no Kyoto-reduction obligation (the latter case are mostly developing countries). The avoided emissions abroad can be subtracted from the obligations to be obtained domestically. In emission trading (ET), a maximum number of emission rights are distributed (often called 'allocated') to parties and those with GHG reduction requirements have the option to reduce emissions themselves, or to buy emission rights from somebody else. Likewise, those acquiring emission permits can use them to justify their own emissions or they can sell them. As explained above, emission trading is an efficient way to reduce emissions. It is often mentioned that a major practical problem in such a scheme is the initial allocation of emission permits or allowances. However, this issue is effectively the same as specifying the emission limit, and thus the same arguments as exposed above apply. On January 1 2005, the EU started its own "internal" Emission Trading Scheme (EU ETS) within the EU

96. This EU-ETS, as currently applied, differs from the emission trading approach as usually

considered under the Kyoto Protocol flexible mechanisms. The EU-ETS applies to company actions, whereas the Kyoto ET is based on government actions.

97 The EU-ETS is currently going through a

first "experimental" phase from 2005 till the end of 2007, after which a real ETS market must exist during the Kyoto commitment period from 2008 till the end of 2012. It is left up to the countries (but to be approved by the EU Commission), to allocate the initial allowances

98 to its different sectors or

companies. This can be done for free (which is called "grandfathering") or these allowances can be auctioned, at the applicable market price, or a combination of both. In principle, the share of auctioned permits should gradually increase. In the first phase of the EU-ETS, many governments overallocated emission allowances to certain sectors. The overgenerous allocation distorted the functioning of this market; not scarcity but a too low level of scarcity (i.e., abundance) was apparent. In such case, the allowance price is very low and it consequently dropped suddenly by more than a factor of two in April 2006, after publication of real

96 A detailed account of the ETS can be found in [Delbeke, 2006] 97 In additional legislation, the EU has foreseen a linkage between the Kyoto flex mechs though and its own ETS. 98 The emission "permits", "rights" or "certificates" in the EU-ETS are called European Union Allowances (EUA).


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emission data by countries and sectors. Also, since there is no banking of allowances to the next period, the price of the allowances to be handed in at the end of 2007 is expected to go to zero at the end of 2007. To avoid over-allocation during the real Kyoto commitment period, the CEU has been much more strict recently in approving the allocation schemes of the MS. It is likely that in the future more and more emission allowances will be auctioned

99 so as to assure that there is scarcity of allowances, which in

turn would lead to a more "correct" market price. Auctioning has the extra benefit that governments collect revenues which they can use for implementing certain policies. That way also, an effective externality tax is levied on the polluters. It should be noted that these sorts of flexible mechanisms allow countries and companies to 'bypass' more expensive emission reductions domestically, and to make others reduce their emissions. This is not without cost either, however. There is a clear cost involved, either to finance the JI or CDM projects abroad, or to pay the price for the emission certificates. Also, as an example, in § 3.2.2.3 a split of the Belgian effort between Flanders, Wallonia and Brussels, will be explained. One will see that it does not add up to the required -7.5% commitment for Belgium. Hence, even if the Regions do what they are supposed to do, the Federal State will have to participate in JI/CDM projects for a total cost of ~30-60 M€, for CO2 prices of 15 to 30 €/ton, respectively. The mechanics of the flexible mechanisms is explained more in detail in Annex 3. See also [Bollen & Van Humbeeck, 2002]. 3.2.2.3 The Kyoto Protocol and Belgium Under the framework Convention UNFCCC, each year, the Belgian state is required by to report a so-called national inventory report. Detailed information can be found in those reports. [NIR, 2007] In what follows, some tendencies are summarized to give the reader an idea of the order of magnitudes involved for Belgium. Figure 3.6 shows the evolution of GHG and CO2 emissions in Belgium, referenced to 100% in 1990. In 2005, Belgium had supposedly a GHG emission level of 97.9, meaning that there is a surplus-emission of 5.4%-pts still with respect to the required reduction level of -7.5%. Compared to a linear path towards the Kyoto-target, a surplus-emission of 3.6%-pts is noticeable.

Figure 3.6. Evolution of CO2 and GHG emissions in Belgium since 1990. [NIR, 2007]

99 Article 10 of the current ETS directive of the EU [CEU, 2003b] foresees a maximum of 5% auctioning of allowances for the first period 2005-2007, whereas for the period 2008-2012, the possibility to auction 10% is foreseen.


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Some comments are in order here. A careful reading of the numbers over the recent years has shown a 'repeated' adjustment of the level of 1990 upward, with a large adjustment in the reporting of April 2005, due to an allegedly forgotten pre-1990 emission of SF6. In addition, according to the IEA [IEA, 2006a], the numbers reported by Belgium may be uncertain as it seems that the CO2 emission factors used by Belgium for this reporting differ from those found in the IEA database (also submitted by Belgium, albeit by a different administration, it seems), in the sense that IEA GHG numbers for Belgium are worse than what Figure 3.6 may lead us to believe. As specified in footnote 4 of Chapter 4 of [IEA, 2006a], the Belgian reported numbers to the UNFCCC for CO2 due to fuel combustion for 2003 (in the 2005 submission) are 116.1 Mt (a 'mere' 5.6% increase compared to 1990), whereas the IEA statistics give 120 Mt (or an 11% increase). It remains to be seen which numbers are actually correct. Next to the most important GHG CO2, there are other GHG: methane (CH4), nitrous oxide (N2O) and the group of fluorinated gasses (further abbreviated as F-gases), consisting of the HFCs, PFCs and SF6. According to Belgium's reporting to the UN in 2007 [NIR, April 2007], the Belgian GHG-emission basket of 2005 consisted of 85.7% of CO2, 5.4% of CH4, 7.7% of N2O and 1.1% of F-gases (not adding up to 100% due to rounding-off errors). All details are given below in the Tables of Annex 4. Figure 3.7 shows this composition and how the emissions of these gases have changed since the reference year, being 1990, except for the F-gases for which the reference year is 1995. Furthermore, of the CO2 emissions, in 2005, 92% is energy related. From these numbers it is evident that the Belgian GHG issue is mainly an issue of emissions of CO2, and mainly energy related. Table 3.4 summarizes the situation for 2005 and the reference year (1990 for most gases & 1995 for F-gases).

100

Figure 3.7 Composition and change of Belgian GHG basket 2005. In the RHS figure, the changes with respect to the reference year are given. [NIR, 2007]

100 Note that the numbers of the reference year have not remained constant with reporting years, due to recalculations. The numbers given here deviate therefore from the numbers given in earlier NIR's and in [Min Env, 2006]


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Table 3.4 Evolution of GHG emissions in Belgium in the reference year and the year 2005. Constructed from [NIR, 2007]

The distribution of energy-related CO2 emissions per sector in 2005 in Belgium is as follows. (Figure 3.8a & b)

Figure 3.8. Energy-related CO2-emission distribution over the different sectors in 2005 in Belgium. Part (a) shows the share of the largest sectors; part (b) gives the changes from the reference year in CO2-eq. [NIR, 2007]

The evolution in time shows that the CO2 emissions of coal have steadily decreased while those due to oil and also gas have increased (for oil, the increase started about 1980). See Figure 3.9.

Figure 3.9. Evolution of CO2 emissions in Belgium per fuel [IEA, 2006a]

101 LUCF = Land Use Change and Forestry. This sink is not considered in this table.

GHG emissions [Mton/a] Reference year 2004 % change

CO2 emissions energy-related 110.1 113.7 + 3.3

CO2 emissions other 8.9 9.7 + 9.0

CO2 emissions total 119.0 123.4 + 3.7

CH4 10.8 7.8 - 27.8

N2O 12.0 11.0 - 8.33

F-gases 5.0 1.64 - 67.2

Total GHG (without LUCF)101

146.8 143.8 - 2.0


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As a consequence of the regional distribution of GHG emissions as shown in Figure 3.10, and the reportedly historically-integrated lower abatement cost in Wallonia compared to Flanders, a re-repartition of the burden has been agreed upon. The regional reduction targets are: Flanders - 5.2% Wallonia - 7.5% Brussels + 3.375% Federal balance, to be obtained from abroad via emission permits (JI and CDM)

102

Figure 3.10. Evolution of GHG emissions in the three regions of Belgium [NIR, 2007]

The evolution of CO2 emissions of the electricity sector in Belgium, together with the additional emissions that would have taken place if nuclear power had been replaced according to the mix coal/gas at any moment, are shown in Figure 3.11.

EVOLUTION CO2 EMISSIONSwith addition of the avoided emissions (classic mix) as a consequence of nuclear

production

0

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'80 '81 '82 '83 '84 '85 '86 '87 '88 '89 '90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05

Mton CO2

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80TWh

Fictive CO2

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Figure 3.11. Evolution of the electricity production and electricity-generation caused CO2 emissions in Belgium. The purple bars show the CO2 emissions that would have occurred if nuclear power had been absent and if electricity generation had been taken care of by a mix gas/coal proportional to the mix at that time.

102 JI applies to projects in countries that are also committed to Kyoto reductions; CDM applies to projects with countries that have no Kyoto-reduction obligation (the latter case are mostly developing countries)


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For completeness, the full inventory of GHG in the years 2004 and 2005

103, according to the NIR

submitted in April 2006 and 2007, respectively, are provided in Annex 4. Similar tables are (or will become) available for each year since 1990 on the web site http://www.klimaat.be http://www.climat.be. For easy reference, the tables of 1990 have also been included in Annex 4.

103 As of May 01 2007, the inventory sheets of 2005 (as submitted in 2007) seem to be less complete than those of 2004 that were submitted in 2006. For that reason, we provide the latest years of both submissions.


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3.3 Affordable Energy Provision and Competitiveness Even if we could dispose of a sufficiently stable guarantee of delivery, even then, the energy provision should be affordable. Here, both the prices of the primary sources themselves and the costs for energy-conversion technologies are important. Demand and supply will play a role; it is evident that we will never empty the oil and gas fields until the last drop, but at some point in time, oil and gas will become so expensive that it becomes “unreasonable”

104; i.e., that they will no longer be used and be

replaced by then cheaper alternatives. The overall rationale behind this reasoning is as follows. In the end, we wish to see a maximization of prosperity for society. Globally seen, everybody benefits from that. Or put differently, if the economy of a particular country underperforms, it will always be the lower part of the societal ladder that “foots the bill”, by compromising on hygiene, on health, on equilibrated nutrition, etc, often with negative consequences for their life expectancy. Therefore, it is of uttermost importance that the economic resources are used appropriately: subsidizing non-cost-effective energy options or prohibiting potentially cost-effective energy technologies, etc does not lead to a judicious spending of the scarce resources and is therefore a wasting. Or still said differently, for a certain spending of financial means, the economically most optimal approach will lead to the best result. In terms of e.g., possible harmful consequences for the environment, this means that we will have the lowest amount of damage (or the largest avoidance of discharge or emission) for a given spending. The CE2030 considers the social aspect of energy provision as being part of the economic dimension. All scarce resources must be utilized in the most efficient way, and prosperity for society should be maximized (subject to obvious and/or reasonable constraints) and the acquired welfare must then be distributed in an equitable way, such that all members of the population could benefit from a well-functioning economy. The social issues go much broader than just energy issues; governments must develop a broad social framework for its citizens. The energy-provision issue must not be singled out for social-policy purposes, but citizens must get equal and fair access to all energy-related opportunities. If imperfections exist, authorities should correct these distortions, and possibly compensate. However, priority must go to a broad social framework; energy-related interventions should be limited in time (except for the right to have access to a certain minimum of energy supply). Competitiveness has been kept by the European Union as one of the main pillars of its new energy 'policy' initiatives. Clearly, for a small country without any resources (energy and other) like Belgium, competitiveness is at least as important. As a consequence, it is imperative that the burden on our enterprises is similar to that of our trade partners, within the EU and abroad. Hence, Belgium should make serious efforts to rationalize its energy use and lower environmental burden, but it must always do so in an economically optimal way and try to do so in concert with the European partners. Standpoints that go beyond that must certainly be reflected upon carefully, and again, in full cooperation with European Members States. In any case, we must opt for the minimal social cost options.

104 In this sense, but also in the short run because of geopolitical instability and other influences, one should note that security of supply is also coupled with price evolution; one could say that reliable energy provision only holds when “reasonable” prices apply. See further below.


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4. Demand for Energy & Energy Saving Our future energy system should be designed to meet the demand for energy services in the decades to come. Policymakers can allow free market forces to generate a series of equilibria or can consider various options to interfere with the unconstrained matching of demand and supply. A source of uncertainty relates to the evolution of energy demand. The future demand for energy will depend on economic growth rates, autonomous energy efficiency improvements, the diffusion of new energy-savings technologies, the evolution of our industrial base, changes in purchasing power as well as in lifestyle, etc. From an investment perspective, energy savings can (partly) avoid the construction of new power generation units and transmission lines/pipes for electricity and gas. But since energy savings can have a positive cost, the complete cost of a saved kWh should be carefully considered.

4.1 Energy Intensity/Efficiency and Demand for Energy Services

To address the issue of energy demand and the possibility of energy saving properly, one must distinguish between two aspects: energy intensity and the demand for energy services. First, there is the amount of energy utilized per unit of activity or product. This is usually called the energy intensity. This concept can be used at the micro scale of a single activity or particular product, but it is often utilized on a more aggregated level of a group of activities or the overall product of a sector or an economy (added value per sector or gross domestic product; etc). In many instances, a measure that is effectively the inverse of intensity is utilized, called the energy efficiency. The energy intensity can be improved , i.e., reduced, or the efficiency increased, by applying more efficient energy technologies (appliances, equipment, facilities, systems, etc), the simultaneous generation of different useful energy streams (as is the case in combined heat and power ―or CHP― installations) and avoiding “visible” or evident energy losses (whereby heat insulation is a prime example). The level of energy intensity can also fluctuate due to structural changes in important economic sectors. An expansion of basic chemical activities can lead to an increase of industrial energy intensity, although the energy efficiency of the new plants can be extremely high. Second, there is the amount of energy services (or, the number and sort of activities) that one wants to enjoy. This demand for energy services has to do with income levels, desired comfort levels, awareness of and attitude towards new technologies and systems, responsiveness to new incentives and opportunities etc. The demand for energy services can be reduced by lowering the thermostat in a building or by investing in additional insulation, extinguishing the lights when leaving a room, the available living or working area in dwellings and offices. Other evolutions such as the growth of international tourism, growth of kilometers driven and of space-conditioned (i.e. heated and/or cooled) building floor area can boost the demand for energy services. To contain aggregated demand, several instruments are applicable. Each instrument —technical regulation, market-based instruments, voluntary approaches— has its merits as well as its disadvantages and pragmatic policymakers should envisage a well-balanced mix of instruments. Especially with respect to energy efficiency, policymakers frequently consider standards to ensure technology-driven efficiency improvements of energy-conversion technologies and more efficient construction practices.

Undoubtedly, there still exists a large technological savings potential before the limits of the second law of thermodynamics will have been reached. Indeed, new buildings can generate efficiency gains up to 70% when compared to existing old buildings. The heating energy needs of the 6000 passive solar buildings in Europe, mainly located in Germany, is reported to be 75% lower than normal ([WEO, 2006d], p.264). When assessing the potential of new technologies to save energy, it is however useful to distinguish the technically realizable potential from the market potential. It is the market success of the new technologies —speed of diffusion and final market share— that will determine their ecological impact (here, energy savings). As a matter of fact, it is often the case that the upfront investment costs of the most energy-efficient equipment or construction measures exceed that of standard equipment or measures. Since these


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more efficient technologies make it possible to consume less energy over the lifetime of the system, the additional investment cost can be recovered after some time. When future energy savings are compared to initial investment costs, the use of the appropriate discount rate to reflect “time preference” is of crucial importance. A high discount rate will strongly reduce the actual value of energy savings in the far away future. In principle, every economic agent has a unique discount rate for every possible investment decision. Private companies will base their investment decisions on the relevant opportunity cost of capital in their sector of activity, while households consider comparable investment opportunities as well as foregone consumption possibilities (even of basic necessities of life). Public authorities frequently select a discount rate close to the long-term interest rate. Although there is no consensus on the most appropriate discount rate, especially medium to low-income household groups implicitly use a high discount rate (up to 40%). With drastic energy savings, the payback time of new energy-saving technology can be relatively short. But for other technologies and measures, the payback time will be too long to convince investors and/or consumers. Even with a short payback time and considerable net-savings —in monetary terms— the fast diffusion of a new technology is not guaranteed. Customers may decide not to purchase the new technologies for various reasons (habits, reluctance or lack of time to consider various alternatives, uncertainty about the long-term reliability of the new technologies, reputation effects, complementarities, etc). Energy systems can be locked-in into dominant designs that exclude more efficient technologies for reasons such as system compatibilities. These lock-in effects or barriers reduce the technical efficiency of the energy system. Since these technical inefficiencies co-evolved with market institutions, the creation of a more efficient system requires adopted institutions. Two typical examples are the introduction of frequency-controlled electric motors and the building-construction sector. Because of fear for the unknown, the introduction into the market of frequency-controlled electric motors is much more slowly than desired, and although there are ample energy savings to be “captured” in the building-construction sector, the number of new buildings per year in our regions is limited, since we have the habit to build dwellings for the duration of 80-100 years. One should also mention that the non-careful application of many of these (often power electronics-controlled) technologies or of CHP can lead to non-desirable side effects for the electric grid, such as harmonics, or loss of voltage stability. These problems are certainly not unsolvable, but it is necessary to do sufficient research to recognize the problems and to come up with satisfactory solutions, albeit usually with a higher cost. Especially with respect to energy-saving electrical equipment and appliances, the overall economic and environmental consequences of energy savings investments also depend on the evolution of the electricity supply system. When fossil-fuel generation is replaced by renewable and nuclear generation, greenhouse gas emissions from the overall electricity system will be strongly reduced. With an increasing share of fossil-based capacity, even spectacular energy-savings in the use of electrical equipment and appliances do not guarantee a reduction of greenhouse gas emissions. Finally, massive investments in energy-saving technologies can possibly generate positive externalities. When the latter investments make it possible to avoid investments in expensive new capacity, all customers —including those who did not invest in energy savings— will benefit from avoided electricity price increases.

4.2 The Cost of a Saved Energy Unit

4.2.1 The Cost of a Saved kWh Cost effectiveness of energy savings To match the demand for and the supply of energy (services), a reduction of demand is in principle interchangeable with an expansion of supply. From an economic point of view, society faces welfare losses at the margin when the marginal cost of additional new capacity in € per kWh exceeds the marginal cost to reduce demand by one kWh. To maximize welfare, demand should be reduced until


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the marginal cost of demand reduction equals that of capacity expansion. Alternative allocations with more or less investments in demand reduction and/or capacity expansion yield welfare losses. It is extremely difficult to determine the optimal investment in demand reduction because nobody can gather all relevant information surrounding current and future energy systems. Economic and technological models therefore use aggregated cost estimates of demand reductions per economic (sub)sector as well as of capacity expansion, to provide crude estimates of the economic consequences of demand-side efforts. The cost concepts in these models can significantly depart from operational cost concepts used by utilities and related energy companies. The latter operate on markets that are distorted by taxes, levies and subsidies. Private companies also want to recover transaction and administrative costs that follow from energy system regulation, market restrictions, environmental and other objectives, etc.

Informative Box: The cost-effectiveness of demand-side measures in WEO2006 [IEA, 2006d] A recent global assessment of demand-side investments is presented in World Energy Outlook 2006 (OECD/IEA). Under the so-called Alternative Policy Scenario of WEO2006, the impact of demand-side investments on energy needs and CO2 emissions between 2005 and 2030 is estimated. Under this scenario, global demand for energy can be reduced by 10% when compared to a reference scenario. To realize this potential, the world —especially consumers— needs to invest 954 billion $ (2005) in more efficient electrical equipment and appliances between now and 2030. The resulting energy savings allow an electricity supply disinvestment of over 2 000 billion $ (2005) over the same period. Demand-side measures clearly reallocate the investment burden from energy companies to households and service companies. Close to 70% of the investments in electrical equipment and appliances will take place in OECD-countries, with investments up to 288 billion $ (2005) foreseen in Europe. It is important to note that these investments are not concentrated in the beginning of the period of analysis but are spread over the full period; in 2030 additional investments in OECD countries equal 140 billion $ (2005). As the energy saving gains from the investments in 2030 are realized after 2030, the comparison of additional investment costs to energy savings is incomplete. In the same scenario, additional demand-side investments in industry amount to 362 billion $ (2005). In the transport sector, an additional 1 076 billion $(2005) needs to be invested between 2005 and 2030. For OECD-countries, the resulting additional cost per vehicle is between $400 and $800, compared to vehicle prices in the reference scenario. In total, consumers face an increased investment burden of 2.4 trillion $ to generate the 10% energy savings but are rewarded by nominal energy savings in their energy bills of 8.1 billion $ between 2005 and 2030. Surprisingly, these energy savings are not discounted in WEO2006 and the former comparison is therefore biased. The use of a 0% discount rate in WEO2006 is motivated by the observation that “there is no generally accepted discount rate (p.194).” Although no sensitivity analysis is provided, the authors of WEO2006 argue that even with a discount rate up to 20%, the total group of consumers, at least on a collective basis (p.194) would realize net-gains when compared to the reference scenario. In WEO2006, necessary interventions to overcome the problem of financing initial capital requirements are recommended but the possible cost of this type of interventions is not considered. Especially for the low to medium income groups, these interventions can be essential to realize the technological potential.

A partial result from WEO2006 (see Box The cost-effectiveness of demand-side measures in [IEA, 2006d]) is that the investment required to save 1 kWh in the residential and services sectors in non-OECD countries is around 0.015 US$ and between 0.03 and 0.045 US$ in OECD-countries. These figures are based on national experiences and should be compared to an electricity price between 0.09 and 0.15 US$ in OECD-countries. When this result would be representative for the global energy system, an unprecedented investment boom to save energy should be under development. Unfortunately, this is not what we observe. It is therefore quite possible that the positive national experiences with specific energy-savings technologies mainly result from generous government subsidies, the provision of low-cost investment capital, targeted and sustained information campaigns, costless technical assistance, the selection of the technologies, etc. Without these specific framework conditions, investors and consumers could behave differently (see Informative Box: Lovins versus Joskow)


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DSM and IRP in the liberalized market In the European liberalized market, regulators need to balance specific national energy-savings goals with the new framework for competition between utilities and subsequent market access conditions. Before the liberalization of the market, national utilities would have been obliged through IRP (Integrated Resource Planning

105) to enforce energy-saving programs (most often called DSM –

Demand Side Management – programs) upon their customers, through advertising, providing rebates for energy efficient appliances, subsidies, stimulating audits etc. However, IRP is fundamentally incompatible with a liberalized market in which several national utilities have been transformed into companies with a European scope. In EU legislation IRP has effectively been replaced by so-called 'governmental measures for public service obligations' (PSO). PSOs can be used to impose specific energy-savings targets upon natural monopolies such as Distribution System Operators (DSOs) that serve the national markets. For the European Commission, PSOs should be non-discriminatory and transparent.

Informative Box: Lovins versus Joskow In a well known joint article in Scientific American [Fickett, et al., 1990], Lovins from RMI and Joskow from EPRI give their vision on the possibilities to savings and their related costs. As seen in the figure of this box, they 'agreed to disagree' in the same article. The lower curve is the one of RMI, the upper one that of EPRI. They represent the potential electricity savings (expressed in % of consumption in the US in 1990) versus the gross cost of a saved kWh. So the cost saving of a saved kWh is not yet subtracted.

Comparison of electric energy saving cost curves according to EPRI (upper) and RMI (lower) [Fickett, et al.,1990].

Globally speaking, there is a difference of a factor of 5 between the average costs of saved kWh as calculated by EPRI versus RMI. The curve of EPRI deals with a 10-year scope. On the contrary, the RMI-curve is valid for an unlimited horizon, but based on the then available technologies: this is the 'ultimately' reachable technical potential. In an equally well known and noteworthy analysis of the cost of a saved kWh, based on field data of actual DSM programs, Joskow & Marron [Joskow & Marron, 1992] argue that the cost curves as presented by both RMI and EPRI, are strong underestimations of the real costs. J&M stress the fact that both the EPRI- and RMI-curves give a technical saving potential, in which a total substitution (or upgrading) of all apparatus by the best available technology is assumed. The curves are upper limits of what is achievable by realistic means.

105 Whereby generators cannot build new electric power plants unless they prove that it is not more cost effective to reduce demand instead.


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4.2.2 Market Barriers & Market Failures Since the oil shocks of the 1980s, the benefits from energy savings have been advocated in most developed countries although the low international energy prices during the 1990s gradually eroded the sense of urgency. Nevertheless, more than 25 years after the first oil shocks total energy end use is still growing. Between 1990 and 2003, total energy end use in Belgium did grow by 28% while the growth of energy use in the residential and service sectors was close to 30% (Table 2.4). The higher electricity price of the last years could not avoid that the final electricity demand in the Belgian residential sector did increase by 13% between 1998 and 2004 (Table 2.15). In the baseline scenario used by the Commission Energy 2030 (to be explained below), the final energy demand in the residential sector only grows by 6% between 2000 and 2030. In the alternative scenarios with additional efforts because of higher prices, a reduction between 3 to 22% compared to the baseline scenario is assumed. Although a substantial technical potential of energy savings is available, one must wonder why energy demand is still growing, especially at times of high international energy prices. Promising technologies to save energy apparently face a slow market diffusion while the resulting energy savings can be more than compensated by a growing demand for (other) energy services. It is customary to blame the disappointing progress so far on various types of 'market barriers' (see e.g., [Blok, 2006]) such as

- (perceived) risk (technical & financial); - imperfect information; - hidden costs (ranging from overhead costs to costs of disruptions to production); - limited access to capital; - split incentives (e.g., landlord versus tenants); - bounded rationality (e.g., lack of management attention). Although market barriers indeed limit the diffusion of new technologies, it is essential to stress that no single market operates in a full information model without capital scarcities and with only risk-averse profit-maximizing investors/consumers. In fact, the combination of incomplete information and capital scarcities as well as rent-seeking opportunities from market barriers did trigger important schools of economic thinking (institutional economics, public choice,…). Just like most economic systems and markets, most market barriers have not been created by an authority but emerged spontaneously over time to be institutionalized or locked-in [Unruh, 2000]. Since market barriers are an essential part of economic reality, efforts to eliminate, compensate or scale down existing market barriers risk to be of limited effectiveness and/or rather expensive. The existence of incomplete information or capital scarcities does not mean that a market is not efficient and that government intervention is required. Market barriers should be distinguished from market failures. According to Sutherland [1996, 2000] market failures result when costs and benefits are not carried by those who have decided on it. A typical example of such a market failure is the existence of external effects such as non-compensated and uncontrolled pollution damage. There are however other market failures surrounding energy systems. Non-contestable or non-accessible markets provide rent-seeking opportunities for monopolists/oligopolies and hence yield welfare losses, while the undersupply of specific public goods can be another argument for government intervention. The existence of monopolies or oligopolies is not by definition a market failure (e.g. natural monopolies): regulators will only intervene when the resulting welfare losses are by no means justifiable and can be removed easily. Regulators typically intervene when specific public goods are underprovided. New policy challenges can lead to new policy goals comparable to public goods. "Energy security" can be interpreted as a new public good, comparable to environmental protection programs. When the market cannot deliver a sufficient level of energy security, regulators can intervene to ensure a higher level. Since energy savings can contribute to a higher level of energy security, governments can select targeted interventions to improve the diffusion of energy-saving technologies.


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When there are sound public policy arguments to stimulate the diffusion of energy-saving technologies, the economic consequences of the selected policy instruments should be integrated in the analysis. Technical standards such as energy-efficiency standards intervene with market dynamics and can have price consequences. Since energy-efficiency standards impose technical efficiency as the dominant characteristic of a given product, consumers strongly valuing other product characteristics such as design and practical features can face significant welfare losses (e.g. a family with 3 children can prefer a large but less efficient car over a smaller but more efficient one). Without the efficiency standards, markets would select products based on all product characteristics. Especially for low-income groups, the price increases from excluding the least-efficient appliances from the market can be problematic. The latter observation explains why low-income groups use very high discount rates when evaluating investments in new appliances and technologies. Public policy to eliminate market barriers and market failures should start from the formulation of clear and consistent objectives. Since most markets are characterized by types of barriers and to a lesser extent by market failures, government intervention should be carefully considered. When inappropriate intervention triggers significant welfare costs, market failure has been replaced by government failure.

4.3 Energy Demand and the CE2030 In the modeling approach of the CE2030 with PRIMES (to be explained below), energy prices mainly steer the final energy demand. The results show that higher assumed energy prices as well as more expensive climate policy targets, reduce final energy demand when compared to model results from low price or less challenging climate policy scenarios. Empirical studies confirm that periods with high energy prices result in higher energy efficiency levels for the most important household appliances (although market response can be lagged). Similarly, lower energy prices block the incentives to further invest in energy efficiency improvements. As the consequences from higher energy prices and tougher technical standards overlap, the results presented from the simulations should not be interpreted as scenarios that do not consider measures to accelerate energy savings.

4.4 Historical Energy Demand in Belgium The absolute numbers on primary and final energy demand in Belgium, split per sector and per energy carrier, have been given in Section 2.1. To get some feeling of what those figures mean, it is important to relate those numbers to the economic output and to the population. This results in indicators such as energy intensity and energy use per capita. The historical record of Belgium, compared to its close neighbors, shows that Belgium consumes a substantial amount of energy. This must be concluded from Figures 4.1 and 4.2.


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* Except Luxembourg and Norway

Figure 4.1. Evolution of the primary energy intensity in Belgium compared to that of its neighbors. It is expressed toe/GDP (with the GDP expressed in k$ of 2000 and bases don power purchasing parity) [IEA, 2006a]. 1 toe = 41.868 GJ = 11.63 MWh

1

2

3

4

5

1975 1980 1985 1990 1995 2000 2005 2010

Belgium France Germany Netherlands IEA Europe*

Figure 4.2. Evolution of the primary energy per capita in Belgium compared to that of its neighbors. It is expressed toe/person [IEA, 2006a]. 1 toe = 41.868 GJ = 11.63 MWh

The numbers beyond 2003 are estimates. Both on a GDP basis and on a per capita basis, Belgium consumes substantially more primary energy. Especially per capita basis, Belgium seems to be roughly at the level of the Netherlands, although it looks like Belgium did worse after 1995 (when energy prices were very low). Germany seems to have benefited from the unification at the end of the eighties, although this is perhaps not the only reason for the lower level throughout the 1990. France has been characterized by a relatively low level.

106

Looking at the energy intensity, Belgium is also higher than its close neighbors. It is common to relate that to its very energy-intensive industrial sector (needing a lot of energy for the production of many base products with moderate added value). [VOKA, 2006] However, although this is indeed corroborated by the energy intensity per sector, as shown in Figure 4.3,

107 it seems that the

transportation sector is the real culprit. To a large extent, this may be due to its freight transport. Somewhat surprisingly, the residential/commercial sector seems to give similar results as the

106 Even though its primary energy consumption figures are artificially higher (distorted) by the convention of nuclear-plant efficiency to convert electricity to primary energy. 107 These numbers are only available up to 1998. From [IEA, 2001]


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Netherlands. France is low on all accounts, showing that energy efficiency and nuclear power are not necessarily antagonists.

Figure 4.3. Evolution of the energy intensity per sector compared to that of its neighbors. Only results up to 1998 are available [IEA, 2001]

To put Belgian demand in a somewhat wider perspective, Figures 4.4-4.6 give results for 1998 based on IEA data. This shows that Belgium is indeed an outlier with respect to its primary energy consumption. For electricity consumption, though, it seems that Belgium is not too much out of line.


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Energy demand per head, GDP per head and electricity demand per head (on basis of data

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Figure 4.4. Classification with increasing prosperity (expressed as GDP per capita) from left to right of 31 entities (quasi continuous curve in the middle referring to the right-hand ordinate scale), of total primary energy demand per capita and per year (upper saw-tooth curve referring to left-hand ordinate scale graduated in kWh/capita and per year), and total electricity demand (lower saw-tooth curve referring to right-hand ordinate scale graduated also in kWhe/cap.year) [Source IEA, Statistics, 1998/1999]. See also [Geeraert, 2005].

Total primary energy supply and electricity demand as function of GDP(ER)

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Figure 4.5. Total primary energy supply and electricity consumption per capita as function of GDPER. That graph was drawn on basis of data by OECD/IEA [Source IEA, Statistics, 1998/1999]. ER stands for 'exchange rate'.


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Primary energy and electricity consumption as function of GDP(PPP) per capita

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Figure 4.6. Total primary energy demand (= supply) per capita and per year and total electricity consumption as a function of GDP per capita expressed in Purchasing Power Parity for the same countries represented on Figure 4. Names are omitted to increase readability. The upper curve is the power regression for total primary energy supply (right-hand scale), the lower curve draws the evolution of total electricity supply (left-hand scale). Figure 6 is based on OECD/IEA data [Source IEA, Statistics, 1998/1999]. PPP stand for 'purchasing power parity'. See also [Geeraert, 2005].

An interesting account on the historic evolution of energy consumption during the past 30 years in 11 IEA representative countries is provided in [IEA, 2004]. Belgium is not part of this extensive exploration because of lack of sufficiently detailed data.

4.5 The Fraunhofer Study on Management of Energy Demand In 2003 a study on energy demand-side management was Commissioned by the Secretary of Energy to study the possibilities of energy savings in Belgium. [Eichhammer, 2006; Fraunhofer, 2003]. The time horizon of the study was 2020. Two modeling exercises with the model MED-PRO from ENERDATA were considered. In a first so-called benchmarking approach, the potential of Belgian energy savings were derived from a comparison with other countries. Such scenario was chosen because «it is a very pragmatic view of what the actual potential is, i.e. in the real economic world, with real decision makers and actual behaviors, and barriers but with different policies across Europe as regards energy efficiency». [Eichhammer, 2006] According to the authors of the Fraunhofer study, that «would certainly give a very realistic economic potential up to 2020». In a second approach, the so-called economic potential scenario, «economic potentials for energy efficiency in Belgium were derived by making use of demand reduction potentials that have [been] established in numerous studies within Belgium and in other countries, as far as applicable to the Belgium context (on the basis of the existing literature and expertise of the consortium). This is, in a certain manner, also a kind of benchmarking approach as it is based on the comparison with best practice, but more in an ideal world, i.e. neglecting the existence of different barriers (economic, social and behavioral). Realizing the potentials estimated in the second way in the time frame of 2020, would require certainly a very dedicated energy efficiency policy over the next 15-20 years. This scenario has net zero costs to the economy on a lifecycle basis (not taking into account barriers, i.e. transaction costs for the removal of barriers), though it requires in certain cases investment costs, which in itself can constitute a barrier, if not enough capital is available.»


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The results of the Fraunhofer Study should be compared to the evolution of energy demand under a reference scenario. According to this reference scenario, final energy demand would increase by 16% between 2001 and 2020 in Belgium. Under the benchmarking scenario, final energy demand in 2020 would be 5% lower than in 2001, or 18% lower when compared to the reference scenario. With the economic potential scenario, final energy demand in 2020 is 12% below the level of 2001, or 25% lower compared to the final energy demand in the reference scenario. The Fraunhofer Study certainly gives some thought-provoking results. However, in the light of what we have discussed above, it still remains an open issue what is meant by a real economic potential. Unfortunately, the Fraunhofer scenarios nowhere include cost figures, in the sense that even a basic overview with all the costs and benefits of the demand reductions is lacking

108 Given the spectacular

results with the benchmarking and economic potential scenario —in contrast to the upward evolution of final energy demand during the latest years—, this is very surprising. In the Fraunhofer Study, a specific measure such as an efficiency standard for refrigerators falls under the economic potential scenario when other studies consider this measure as cost-effective. Especially with respect to appliances, the Fraunhofer Study collects findings of previous GEA, Novem and Ademe end-use studies. An Ademe study of 2000 apparently reported that it is cost-effective for consumers to purchase appliances that use approximately 50% less energy than older models ([Fraunhofer, 2003], pp.186-187). Based on this and comparable studies, the Fraunhofer researchers then define cost-effective technical efficiency standards for all appliances (see [Fraunhofer, 2003], Table 7-13 on page 187). The latter values then constitute the cost-effective efficiency scenario. Information on the economic methodology used in all these different studies is however completely lacking. There is only one singly reference to the use of 8% discount rates in older SAVE-studies. When the Ademe study on refrigerators would be based on a 0% discount rate, this assumption is implicitly included into the cost-effective efficiency scenario of the Fraunhofer Study. In terms of transparency, this approach is regrettable. When comparing the benchmarking approach to the economic potential scenario, the Fraunhofer study suggests that only in the economic potential scenario very dedicated energy efficiency policies are required. It is not clear why the same dedication is less needed in the benchmarking scenario. The latter scenario refers to real energy savings from specific programs in other countries. But the ‘real policymakers’ responsible for these savings had as well to overcome various barriers and provide incentives to stakeholders. From this perspective, both scenarios are as expensive and challenging but especially the measures in the benchmark scenario have been successfully tested in other countries. Whether or not the successful tests can withstand an economic assessment is another question. The Fraunhofer study proposes a set of 20 so-called 'top measures' to improver energy savings in Belgium. It recognizes that already many instruments exist, and encourages that existing instruments are put to work appropriately. At the time of the study, the EU Directive on the 'Energy Performance in Buildings' had been published but not yet transposed into Belgian law/decree, and the concept of 'voluntary agreements and benchmarking/audit covenants' was introduced, but not yet actively applied. Since the Fraunhofer study was finished, some important changes have taken place. First, there are the higher fuel prices. Second, some important European Directives have taken effect, such as that on the GHG Emission Trading Scheme

109, and on the one on Energy Efficiency and Energy Services.

The former puts a price on CO2 emissions and they represent a penalty on emissions.110

As such, this mechanism will put a downward trend on energy demand in those facilities subject to the directive (especially larger industries). The second directive on energy efficiency creates an institutional frame for energy efficiency improvements in all sectors and for energy services at the European level. In this frame it requires an indicative target of 9% improvement of energy efficiency in 9 years and an

108 Also, the way CHP criteria are handled in the Fraunhofer study is 'questionable'. The rejection of the quality criterion and the advocating of the so-called splitting of the CHP and condensing parts seriously hurt the credibility of the study. Pleading for public support for generation units which do not save primary energy compared to the best available technology is equivalent to a bad use of scarce resources. 109 This mechanism is explained in Part III. 110 This is actually independent of the way emission allowances are initially allocated because these allowances are property rights and have an opportunity cost.


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evaluation methodology to measure the savings achieved. In the follow-up of the Directive the EU Member States will be required to realize the economic potentials for the improvement of energy efficiency through national Energy Efficiency Action Plans (EEAPs). The first of these EEAPs must be submitted by June 30, 2007, and will be assessed by the Commission by January 01, 2008. The CE2030 endorses most of the proposed 'top measures'. Hereunder, the CE2030 states its important umbrella recommendation on energy demand and savings. The detailed Fraunhofer list of 'top measures' is listed and commented upon in Annex 5. In Part II of this CE2030 study, cost figures will be provided for scenarios with substantial demand reductions. CE2030's umbrella recommendation on energy savings-implementation in Belgium As much as possible, Belgian legislation must subscribe to the European legislation. There exists an interesting framework of EU directives on energy efficiency. Existing and new directives are to be transposed timely. Although energy efficiency belongs to the 'competences' of the Belgian Regions, it is strongly recommended to have a harmonized approach within Belgium and if possible with other European countries. This improves mobility and better accommodates multi-site enterprises. For reference, the most important existing EU directives related to energy efficiency are listed here. Directive(s) on Energy labeling household appliances http://europa.eu/scadplus/leg/en/lvb/l32004.htm Directive on Fuel economy in passenger vehicles http://europa.eu/scadplus/leg/en/lvb/l32034.htm Directive on Energy performance in buildings http://europa.eu/scadplus/leg/en/lvb/l27042.htm Directive on Cogeneration http://europa.eu/scadplus/leg/en/lvb/l27021.htm Directive on Energy end-use efficiency and energy services http://europa.eu.int/eur-lex/lex/LexUriServ/site/en/oj/2006/l_114/l_11420060427en00640085.pdf


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Part II

Exploring the Future

— Scenario Analysis—


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5. Definition of Scenarios

5.1 Scenario Model: PRIMES

5.1.1 PRIMES Description

In this study, the PRIMES model is used in order to quantitatively examine the energy outlook of Belgium in the period 2005-2030.

The PRIMES model in a nutshell111

The PRIMES model was developed under research projects funded by the European Commission Joule programme. The design was influenced by the previous generation of energy models (EFOM, MIDAS and MEDEE). The PRIMES model was developed to make energy projections, evaluate scenarios and analyse the impact of energy policy measures. The PRIMES model can be used to simulate trends in supply, demand, prices and emissions of pollutants for the various fuels, taking account of the fact that international energy prices and macroeconomic variables (GDP, disposable income, inflation, interest rates and so forth) are incorporated exogenously. PRIMES is a partial equilibrium model because changes in the energy supply and prices and constraints on the emission of pollutants cannot in turn influence the economic sphere. PRIMES is a market-driven model which simultaneously simulates a balance between supply and demand both at European level and for the 35 countries individually. Equilibrium is reached when prices ensure a balance between demand and supply for the different forms of energy. Convergence towards equilibrium occurs iteratively. Based on an estimate of the prices for the various forms of energy, PRIMES provides an initial estimate of demand. This determines the requisite capacity and level of the various forms of energy. The choice of production technology is then determined endogenously on a "least production costs" basis. PRIMES calculates the production costs which, after duties are added, provide an initial estimate of energy prices. Prices are then compared to the previous iteration and the convergence process terminates once they are sufficiently close. If not, a fresh estimate of demand is made and the back coupling process continues. Demand comprises a series of non-linear equations. The model for final energy demand is based on a bottom-up approach (engineering approach), but includes a minimisation of energy users' costs. The model uses a detailed sector breakdown, allowing for 24 different energy forms. The model distinguishes between 9 branches of activity in the industrial sector. Each segment is broken down into different subsectors (some 30 subsectors in all, including recycling); at the subsector level, various kinds of energy use are distinguished according to the production process (blast-furnaces, electrical furnaces, electrolysis, etc). For the residential sector, 5 different types of buildings are distinguished according to the heating system used (central heating, partial central heating, electric heating, district heating and independent gas heating). In addition to the type of heating, the model also considers three kinds of household energy use: hot water, cooking and specific electricity use. Household demand depends on different variables, including disposable household income, the number of degree-days, the type of heating system, and parameters that reflect the technology and features of the house insulation. Within the tertiary sector, a distinction is made between the commercial sector, the non-market sector and trade services. Various types of energy use are considered, according to the technology used. The model also considers energy consumption for the agricultural sector separately. PRIMES distinguishes between passenger and freight transport. Four means of transport are considered: air, rail, road and sea. For road passenger transport, a distinction is made between public transport (buses) and private transport (cars and motorcycles). Between six and ten different

111 Taken almost literally from Annex F from [FPB, 2006 - Sept]


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technologies are considered for cars, trucks and buses. A lesser number of technologies is considered for rail, air and sea transport. The total transport volume is determined by the growth in income and GDP. The distribution among the various forms of transport depends on their relative prices, which are in turn influenced by the technology of new investments and the existing fleet. The energy supply in PRIMES consists primarily of three modules for electricity and steam generation, oil refining and other transformation sectors. To accommodate the demand curves, the module for electricity and steam generation determines the choice of the production processes, the extension and decommissioning of the required means of production and the choice of fuel. The model takes account of a large number of technologies for electricity production (by combining the various technologies, fuels, sizes and forms, a choice of more than 900 power stations is possible). Particular attention is focused on the combined heat and power production, renewable energy sources and new forms of energy. Refineries operate nationally, but capacity, market share and prices are determined by competition at European level. For primary energy, the model determines the optimum share of imports and domestic production to be able to meet demand. The model considers the global petroleum market as being exogenous. A key feature of the model is a tariff module ensuring a balance between demand and supply. This module calculates the revenue that the sector requires (on the basis of total expenses and other accounting expenses) and allocates charges to users in accordance with the Ramsey pricing principle. The consumer price is then deduced by adding distribution and transport costs, margins and duties. The PRIMES model is being developed and managed in the University of Athens (NTUA) by a team under the coordination of Prof. P. Capros. For some of the hypotheses, the NTUA makes use of the output of other universities or scientific institutions, like for example international energy prices (on the basis of POLES, supplemented by the world energy model PROMETHEUS and revised by a number of experts) and the modeling of the transport activity (on the basis of SCENES, a European transport network model). More details about the PRIMES model can be found on the following web site: http://www.e3mlab.ntua.gr/downloads.php It must be stressed that PRIMES only deals with the energy system and therefore only accounts for energy-related CO2 emissions. (Other GHG are not considered by PRIMES.) Given the technical features and design of PRIMES, imposing a CO2 constraint is equivalent to incorporating a variable which reflects the economic costs imposed by this constraint. This shadow variable is the marginal abatement cost (also referred to as 'carbon value') that is associated with the emission constraint. (For details, see [CEU, 2004; FPB, 2006 - Sept])

5.1.2 Some Elements of the PRIMES database

In this section, some elements on the PRIMES database are given. As this database is not fully open in the public domain, information on it can only be released to a limited extent. Most power generation technologies referred to in [FPB, 2006 - Sept] and this CE2030 report are aggregates of more detailed technologies. The model results we have at our disposal relate to aggregates and not to individual technologies. For instance, the aggregate “wind offshore” combines various wind “technologies” whose production costs differ according to their location (impact on utilization rate), their size, etc. Consequently, it is not possible to establish a direct link between the techno-economic data of individual technologies (more than 60 power technologies in the PRIMES database) and the model results. Moreover, the investment costs may vary according to whether a new plant is built on greenfields or on an existing site. Given this particular feature of the model, it is not possible to give an extensive description of all power generation technologies. Instead, we have plotted the evolution of the investment costs (which is the most important cost parameter, together with the fuel costs) of some key power generation technologies (see Figures 5.1 and 5.2; expressed in normalized units or in €/kW). Investment costs


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relate to new plants on greenfields. Regarding wind, we have selected for Figure 5.1 those turbines with an annual utilization rate of 2100 hours for onshore wind and of 2630 hours for offshore wind. Figure 5.1 shows the hypotheses regarding the decrease in investment costs of four key renewable technologies. This reflects an a-priori assumed evolution in time for the investment cost of certain renewable technologies. Figure 5.2 shows a similar graph for some renewable technologies in comparison with coal- and gas-fired technologies. These types of curves are to be distinguished from experience of learning curves (See Informative Box.). The version of PRIMES used here does not make use of learning curves.

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People interested to go deeper into the details of the techno-economic characteristics of power plants are invited to visit the website of the European research project EU-SUSTEL which provides useful information on that issue, including comparisons between different sources (http://www.eusustel.be ).

Informative Box: A few Elements on Learning Curves or Experience Curves In contrast to the time-evolution curves as shown above, "experience" or "learning" curves reflect that usually investment costs decrease as a consequence of increased experience. The investment costs can be plotted on a semi-log scale as a function of the installed power. In many cases, and applicable to many technologies, a straight line will appear, so that a so-called Progress Ratio (PR) and Learning Rate (LR) can be identified. The PR is a parameter that expresses the rate at which costs decline for every doubling of cumulative production. E.g., a PR of 0.8 or 80% equals a learning rate (LR) of 0.2 or 20% and thus a 20% cost decrease for each doubling of the cumulative installed capacity. [Junginger, 2005]. The figures below show some examples taken from the literature. It illustrates that learning does indeed occur, but they also express a cautionary note in that one should be careful not to blindly extrapolate. The gas-turbine example in the figure hereunder expresses the fact that during the R&D phase a LR of 20% was noticeable, whereas during commercialization, this decreased to 10%. [Nakicenovic,1998] (To compare with current-day prices, one can assume an average inflation rate of about 2 to 3% in the US during the last 15 years. The result would be a factor ~ 1.5 higher in today's money.)

The figure below demonstrates the effect of over-subsidizing on the price of wind-turbine prices. From the start of the "generous" feed-in tariffs for wind in Germany, the decrease of wind-turbine prices has come to a halt, or prices even increased. [Junginger, 2005]


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In a recent special issue of The Energy Journal, the use of endogenous learning of technologies has been addressed. [TEJ, "Endogenous Technological Change and the Economics of Atmospharic Stabilisation", IAEE, Special Issue, March 2006] Although it is possible to show that learning may lead to cheaper abatement costs for CO2, it must be stressed that everything depends on the actual progress of learning. The figures above show that even with learning, careful attention is needed when extrapolating.

In Figure 5.3a, a comparison of the production costs of three power generation technologies is provided. It is based on the techno-economic data used in PRIMES. (Note that the duration of operation of power plants is an output of the model, not an input.) In the PRIMES database, the total investment cost of one new nuclear power plant in Belgium is set equal to 1800 €/kW for operation after 2020 (expressed in € of 2005). This figure includes the financial charges paid during the construction of the plant (8 years – interest rate of 8.5%) which adds up to the overnight investment cost of the power plant. It also includes the decommissioning costs (12 to 15% of the plant costs). The figure used for the total investment cost assumes that one new nuclear unit can be constructed on an existing site; consequently investment costs are taken to be lower than for a new nuclear power plant on greenfields where site preparation costs have to be included (e.g., total investment costs for greenfield situations are roughly 2440 €/kW in 2005 and 2230 €/kW in 2020) [Ref. Nov 2005 database PRIMES --Newtec.xls-- not publicly available]. This approach applies to all power generation technologies, including renewables. This cost reduction applies to a single additional unit and not to the others. This should be compared with the database of the TIMES-EE model [Ref. University of Stuttgart; IER], where for the year 2020, a total investment cost for an EPR-type reactor of about 1660 €/kW has been assumed (not specifying whether this includes site preparation costs). Therefore, the PRIMES figures are very likely not an underestimate. In the scenarios, the competitiveness of nuclear compared to other power-generation options depends on the assumptions on capital costs, fixed costs and variable costs (part of which is the fuel cost). Figure 5.3a compares the power generation costs for three different types of power plants operating 7800 hours per year with the techno-economic data and fuel prices as used in the scenario analysis, but with different carbon values. In order to assess the sensitivity of nuclear power generation costs to capital costs, we have also plotted alternative generation cost figures corresponding to other assumptions as to the investment cost of nuclear.


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discount rate = 8,5% et 7800h/an

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Figure 5.3a. Electricity generation cost for different technologies as a function of the carbon value , based on the figures used in the PRIMES database. [Ref D. Gusbin, FPB]

There are many other parameters one can vary and the ranking could be different (e.g., cost parameters of coal- and gas-fired plants, fixed and variable costs of nuclear plants, discount rate, load factors …). (See e.g., [IEA, 2006d]) However, the cost parameters of nuclear must be very unfavorable in order not to be a cost-effective option for base load electricity production when the carbon value is higher than 50 €/t CO2. Figure 5.3b shows the ranking when the nuclear fuel cost is increased by 50% compared to the cost used in Figure 5.3a (12 €/MWh instead of 8 €/MWh).

discount rate = 8,5% et 7800h/an

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Figure 5.3b. Electricity generation cost for different technologies as a function of the carbon value, based on the figures used in the PRIMES database. The nuclear-fuel cost is 150% of the cost assumed in Figure 5.3a. [Ref D. Gusbin, FPB]

discount rate = 8.5% and 7800h/yr

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Informative Box: Energy savings in the PRIMES model: potentials, modeling and interpretation of results Reference: Annex G [FPB, 2006 - Sept] Introduction Detailed technological models, often based on bottom-up approaches, point to the existence of energy saving potentials that may be achieved without extra cost to the energy system (i.e. fuel savings more than counterbalance the additional investment costs associated to the purchase of more efficient equipment). However, there is no evidence in real evolution (i.e. energy consumption statistics) about the realization of such cost-efficient energy saving potential: this is often referred to as the efficiency gap. Microeconomic analyses suggest that the gap can be explained by specific conditions prevailing in the markets (e.g. lack of information) and by the differentiated behavior of economic agents. This issue is underlined in the recent report: the Stern Review “The Economics of Climate Change”: “…Even where measures to reduce emissions are cost-effective, there may be barriers preventing action. These include a lack of reliable information, transaction costs, and behavioral and organizational inertia. The impact of these barriers can be most clearly seen in the frequent failure to realize the potential for cost-effective energy efficiency measures”. Modeling energy consumption and savings in PRIMES The PRIMES model not only represents a detailed set of technologies for the transformation and consumption of energy but also models market mechanisms and the behavior of economic agents. The latter feature is particularly relevant when modeling the decisions of households in regard of investments and level of energy consumption (i.e. intensity of use of equipment): decisions depend both on technological and behavioral components. Technological components are necessary to capture the physical constraints on energy use and savings, while behavioral components are necessary to explain consumer expectations and their influence on equipment choice as well as to explain the influence of energy prices on energy consumption. The dynamic of equipment penetration and replacement is also driven by the capital turnover. Based on studies made by Ecofys and the Wuppertal Institute for the European Commission, the PRIMES model specifies, for each “use/technology” pair, an ultimate energy saving potential that corresponds to the use of the best available technology. However, as underlined above, the fraction of the ultimate energy saving potential that will be implemented by the model depends not only on (fuel) prices and (equipment) costs but also on behavioral indicators. One of these behavioral indicators is the discount rate. Based on empirical observations, small consumers use high subjective discount rates whereas industry uses comparatively lower discount rates. More precisely, the following figures are used in PRIMES: 8% for large utilities, 12% for industrial and commercial activities and 17.5% for household’s investments. Higher discount rates mimic the fact that most households opt for short payback periods. The presence of behavioral indicators explains why all the cost-efficient energy saving potential is not implemented and why significant fuel price increases are required to realize it: price signals alone may be too muted to have a significant impact (Stern Review, 2006). Appropriate policies and measures are required to remove existing market barriers and imperfections that impede the efficient use of energy and make price signals work properly, and to shape consumers’ behavior towards more energy savings. Relevant policies and measures include regulatory measures (e.g. minimum standards for buildings and appliances), financial measures but also information and education. However, these policies and measures have a cost, a cost for the public finances and for the consumers. The analysis of the economic impact of these policy instruments would require fully capturing cost elements that are sometimes difficult to estimate and that are presently outside the scope of the PRIMES model. Of course, it is possible to evaluate, with the PRIMES model, the impact of targeted actions that improve the perception of energy consumers of energy costs by changing the behavioral parameters so that


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more efficient solutions are chosen despite of higher initial costs. That is what has been done in the scenarios “with additional measures” in the study [FPB, 2006 - July] and in the “energy efficiency” scenarios for DG TREN. However, the evaluation is limited to the impacts on the energy system, the emissions and the energy related costs; it does not provide a complete representation of the economic effects. Interpretation of PRIMES results As stressed in [FPB, 2006 - Sept] (but also in the various reports drafted by NTUA for the European Commission), the carbon values do not represent costs of policy implementation; they are only indicative of the relative difficulty of achieving targets. The carbon values represent the marginal abatement costs for CO2 reductions of 15% and 30% in 2030 compared to the 1990 level, i.e. the cost of the last ton reduced in order to achieve the reduction objectives. In the scenarios without nuclear and CCS, the flexibility of the power and steam generation sector to respond to CO2 constraints becomes narrow (essentially some further development of RES up to the limits set) and some changes are rather expensive (solar PV). Consequently, the focus is more on the demand side where, given the inertia of the system (reflected through appropriate behavioral indicators), higher carbon values are required in the absence of specific policies. High carbon values simply reflect the higher costs involved in the different sectors. This result can be seen as an overestimation of the actual cost of energy savings if one expects appropriate policies to take place in order to remove market failures and barriers to behavioral change. But it is most probably not if policy makers do not take strong action now to that effect. References The PRIMES energy system model: short description (http://www.e3mlab.ntua.be) European Energy and Transport: Scenarios on key drivers, European Commission - DG TREN, September 2004. European Energy and Transport: Scenarios on energy efficiency and renewables, European Commission - DG TREN, January 2007. Stern Review, The Economics of Climate Change, December 2006. (http://www.hm-treasury.gov.uk/independent_reviews/stern_review_economics_climate_change/ sternreview_index.cfm)

5.2 Goal of the Scenario Exercises To get some idea of where the future might take us regarding our energy system, it is customary to run a set of scenarios. Rather than to base our future policies on simple 'excel-type' analyses, whereby one merely adds up all best available technologies on the demand and supply side, a scenario analysis relies on a self-consistent computer model that simultaneously takes into account a variety of conditions and requirements and this in a fully coherent way. The model normally optimizes the energy system such that it chooses the most economically efficient options first. Scenarios are not to be considered as predictions of the future. Hence, they are not forecasts! They are 'projections' towards a possible future, consistent with the algorithm of the energy model used, its database, and the boundary conditions and hypotheses taken at the outset. The results of scenario runs are to be interpreted as trends on how the energy economy would evolve, and as such they often serve as 'orange blinking light warnings' to signal what might happen, according to the features of the model and the prescribed constraints and assumptions. The usual sequence of a scenario analysis is as follows. To start with, a first scenario is run. Although this merely serves as "a" first scenario with which all the other scenarios will be compared, it is customary to choose a 'continued policy' scenario. This is then called the reference scenario or the baseline scenario. It must be stressed, however, that this reference or baseline scenario is not to be considered as "thé Reference", in the sense that it is the preferred or desired scenario. Often it will be the case that this first scenario is not really sustainable and that other, more stringent, measures or constraints must be introduced as boundary conditions or hypotheses to outline a different future.


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In summary then, a scenario analysis is an exercise to find out how sensitive the energy system is with respect to changing boundary conditions and hypotheses (often reflecting new policy choices such as imposed taxes, maximum limits on emissions, different fuel prices, etc). From the overall tendency of the energy system reaction, and the consequences for security of supply, environmentally friendliness and overall cost, well informed conclusions can be drawn. In this Part II of the CE2030 Report, the scenarios are defined, with justification of the chosen variants, after which the scenarios' results are summarized. At a later stage, Part III of this report reflects on the scenario results, taking into account the broader energy theatre in Belgium. This part takes into account that a model is an approximation of 'reality' and the results must be scrutinized and checked for reasonableness and against expert judgment. Consequently, Part III stresses the major challenges ahead.

5.2.1 Philosophy of the Baseline

The scenario analysis chosen in this report starts from a first scenario called the baseline scenario. The baseline is of the 'continued policy' type and is set up to let the energy system evolve starting from the legally binding legislation and measures. In our analysis performed here, all regulation up till 01.01.2005 has been taken into account. This means that the baseline is not necessarily expected to reach the targets set by policy makers, such as e.g., x% of renewables or y% of CHP. Rather, this sort of baseline scenario can in principle evaluate whether the current regulation is sufficient to reach the hoped for targets and objectives. As already set above, the baseline is not designed to outline a desired future. On the contrary, the baseline will be shown to be unsustainable so that other scenario runs must be considered.

5.2.2 Philosophy behind the Alternative Scenarios

In contrast to the baseline scenario, the alternative scenarios considered in this report impose desired targets or quota as constraints on the model, and it is then examined how the energy system tries to satisfy those constraints. It will be recalled that within the constraints imposed, the model will be guided by an economically optimal choice to satisfy the given demand for energy services

112. From an

analysis of the options chosen by the model, policy makers can then obtain inspiration as to which measures can be used to reach the desired objectives. For the purpose of the CE2030 report, it has been chosen to focus on the expected constraints that will be imposed to fight the Climate-Change challenge. Indeed, the energy provision situation has changed dramatically over the last few years. For a country like Belgium, which energy import dependency is currently almost 100%,

113 and which possesses a limited obvious renewable-energy

potential, matters are even worse than for many other countries. The fact that energy prices have skyrocketed, that most primary energy sources originate from geopolitically often unstable regions, and that the climate-change issue not only seems to have been 'proven' but is believed to accelerate, requires us to be serious about the future commitments on climate change and to possibly reconsider the wisdom of decisions taken previously against a different background. In defining the alternative scenarios, we have been led by the expected post-Kyoto emission reduction limits to be imposed by the EU. As will be explained more in detail below, we focus on a 30% GHG reduction in 2030 compared to 1990 at the EU level. To investigate what that means for Belgium, two approaches are considered:

1.- a domestic reduction of energy-related CO2 emission, and the cost of such implementation; 2.- a European-wide reduction of GHG and identification of the in Belgium implemented reductions and the cost of such combined approach.

112 By "energy services" is meant the activities and applications we wish to enjoy: heat rooms to comfortable temperatures, keep food and drinks cool, drive kms, provide drive power and process heat in industry, etc. This concept here is different from the "services" provided by so-called "energy service companies (ESCOs)" or "audit bureaus". 113 Here 'long-term import dependency' is meant, whereby nuclear fuel is considered to be imported.


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In both cases, the influence of a nuclear phase out is considered as an important factor; also the effects of the availability or not of carbon capture and storage (CCS) are investigated.

The first approach, with the constraint imposing energy-related CO2 reductions on the Belgium territory will demonstrate how difficult it is to obtain reductions beyond ~15% in the case of a nuclear phase out and if CCS is not available. In addition, running scenarios for an imposed reduction by 15% and 30%, next to the baseline in which effectively no post-Kyoto constraints are imposed, will allow to get an idea of the efforts required over the full range 0%-15%-30% if Belgium is faced with different reduction requirements (other than 0, 15 or 30) as a consequence of burden sharing and if Belgium makes use of the flexible mechanisms foreseen under future post-Kyoto agreements. In the second approach, which focuses on a 30% reduction of GHG on a European level, reductions of non-CO2 gases and CO2 are first implemented in those countries where it is the cheapest according to the lowest marginal abatement cost. The distribution of the implemented reductions is determined by the principle of equal marginal abatement costs. An important comment is in order concerning these alternative scenarios. The first approach on domestic energy-related CO2 reductions only, has the advantage of transparency, but it ignores non-CO2 GHG and the efforts that Belgium has to do abroad to satisfy its emission cut responsibility, unless this is taken into account in a separate reflective analysis. The second EU-wide approach, on the other hand, seems to take into account everything (given that all details —especially the MAC curves for all GHG— of all EU countries are correctly represented in the model), but it may give the erroneous impression that the efforts by Belgium are moderate or even small compared to the other EU countries, in certain cases. These scenarios will indeed show that the emission reductions actually effectuated on the Belgian territory are indeed small compared to the EU as a whole when nuclear power in Belgium is phased out and when CCS is not available. This is a consequence of a large MAC for Belgium in those cases, compared with the EU MAC. However, this must by no means be interpreted as that the GHG-emission reduction objective for Belgium after 2012 will be small! As explained above (see Section 3.2.2.2.), all EU Members States are expected to carry a responsibility burden commensurate with its level of prosperity (per inhabitant). This means that Belgium is to reduce by the same relative amounts (e.g., expressed as Mton CO2-eq per inhabitant) as its most important trading partners, but that it is cheaper for Belgium to finance reductions abroad, either directly or indirectly via purchasing emission rights on the international market. To show the difference of domestic reductions versus reductions elsewhere, we consider the following qualitative sequence of situations as shown in Figure 5.4 and Figure 5.5. (The actual MAC curves for Belgium and the EU are shown below in Section 5.3.4.2.) Figure 5.4 refers to the situation for which Belgium is allowed to seek the cheapest emission reductions in the EU. The EU MAC curve is supposed to be (considerably) lower than the Belgian curve.

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(c)

(d)

Figure 5.4. Qualitative determination of the cost to finance emission reduction domestically or within the EU. On the abscissa, emission reductions in % are meant. See text for explanation.

It is assumed that Belgium must reduce its emissions by an amount od as indicated by the vertical line in Figure 5.4a. The EU must likewise reduce its (relative) emissions by an amount od (e.g., both by 30%). The cost to do so domestically is the area of the triangular surface oda. As the last emission reductions (near point a) in Belgium are quite expensive, Belgium will want to reduce its domestic emissions to oe, whereby the same emission reduction of y% will then be done elsewhere in the EU. (See Figure 5.4b.) Belgium will therefore not have to spend the cost of edba, but it will have to pay for

the cost of dfgc, if Belgium can simply finance projects abroad (Figure 5.4c)114.

By reducing emissions abroad according to the equi-marginal principle, Belgium will have saved the yellow area in Figure 5.4d. If, however, Belgium relies on buying emission rights to pay for its reduction commitments, it must purchase the emission rights at a price which we assume to be |be|=|cf| on Figure 5.4b. The amount paid for emission rights is therefore equal to the amount dfhc=debh. Belgium will then have financially saved an amount equal to bha. In Figure 5.5, it is shown what happens if the MAC of Belgium becomes suddenly more expensive due to e.g., a nuclear phase out. “Old” stands for the MAC curve if no nuclear phase out is implemented and “new” stands for the MAC curve with a nuclear phase out. (These curves are merely schematic, since a sudden nuclear phase out will lead to a leftward shift of the MAC —but the overall reasoning remains the same). After following a similar reasoning as above, Figure 5.5c and Figure 5.5d clearly show the overall cost Belgium will have to pay in the “old” (yellow area) and “new” (blue area) situation, whereby in the latter scenario an additional z% of the emission reduction is done elsewhere in the EU. The differences in costs are then summarized in Figure 5.5e, showing that Belgium will not have to spend the cost of the green area kebm, but it will have to pay additionally for the cost of the red areas omh and fljc. It is easily found that even with financing reductions abroad, the cost of fulfilling the GHG reduction commitments under a nuclear phase out is more expensive than if nuclear power were allowed to continue: the red areas in Figure 5.5f are larger than the green area. Furthermore, if emission trading is opted for, it is important to recognize that the price P of emission certificates in case of a nuclear phase out in Belgium has increased compared to Figure 5.4; this means that the phase out in Belgium increases the cost of a climate policy for all countries in the EU bubble. (Practically speaking, in a later part of this report it will be demonstrated that the EU allowance

price would increase from 190 €/ton to 200 €/ton, i.e., an increase by 5%115). The extra cost for

Belgium to abide by its GHG-reduction obligations, due to a nuclear phase out in Belgium, will be estimated below in Section 6.3.3.2. The extra cost for the EU as a whole, although not estimated explicitly, will experience an overall cost increase of 5%.

114 And if the foreign project partners do not bargain on their share of gains from trading. 115 Under the assumption that the EU does not take refuge to CDM outside the EU, and that CCS is not available in the EU for routine commercial application.


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(a) M A C B - new

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Figure 5.5. Qualitative determination of the cost to finance emission reductions domestically or within the EU in case of a nuclear phase out in Belgium. On the abscissa, emission reductions in % are meant. See text for explanation.


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5.3 Description of the Scenarios Implemented

5.3.1 Introductory Considerations

The idea of the current scenario exercise here is to present a clear picture of the reaction of the energy system to certain imposed constraints and to indicate what the burden on the energy economy might be. As said above, a first scenario, the Baseline, is run according to the current legislation and policy measures on energy, transport and the environment. Recent trends and structural changes are assumed to continue. Different (alternative) scenarios are then run, with different constraints and hypotheses, with the aim to see how the energy system adjusts to those imposed constraints and how the new results differ from the Baseline. As such, the impact of the new constraints and boundary conditions can be evaluated.

5.3.2 The Baseline — Basic Hypotheses

5.3.2.1 Belgian Baseline part of the European Baseline The Baseline as defined for the CE2030 activities is in accordance with, and actually part of, the European Baseline developed for the EU Commission, DG TREN in November 2005 and published in May 2006, and developed with the PRIMES model. The European PRIMES Baseline treats the 25 EU countries

116, of which Belgium is one. The Belgian Baseline considered in the CE2030 activities, is a

further detailed zooming in on the Belgian energy scene (as a part of the European system). Detailed information on the concept and the results of the European PRIMES series of Baselines is found in [CEU, 2003; 2004; 2006a]. The difference between the 2003/4 Baseline and the updated one of 2005/6 is to be found in much higher fuel prices, and an update of the policy measures in many countries. In addition, the updated PRIMES version has as feature a (simplified) endogenous treatment of electricity and gas imports and exports, as well as trade in fuels between countries. The same EU Baseline has also been utilized recently in the European studies EUSUSTEL [EUSUSTEL, 2007] and EURELECTRIC [EURELECTRIC, 2007]. Identically the same Baseline as here has been used for a parallel study, commissioned by the Federal Minister for the Environment, B. Tobback, to help define the Belgian climate policy [FPB, 2006 - July]

117 and in the Working Paper 1-07 of the FPB [FPB, 2007], which gathers some key findings of

this latter study and the one it carried out for the CE2030. The specifics on the current Belgian PRIMES Baseline, including the results to be discussed below (as well as the discussion of all other CE2030 scenarios to be considered) can be found in the comprehensive report [FPB, 2006 - Sept] which is part of the Supporting Documents of this CE2030 Report. The discussion of this Chapter and the following are largely based on the results presented in the FPB report just mentioned. In practical terms, the Belgian Baseline incorporates the nuclear phase out as specified in the law of January 2003,

118 and takes into account the measures that should lead towards satisfying the Kyoto

protocol, without, however, imposing the 7.5% GHG-emission reduction as such. In any case, no post-Kyoto reduction limits are being imposed.

119

Other typical features of the PRIMES Baseline, can be found in the references given above, especially [FPB, 2006 - Sept].

116 Sometimes extended to 28 or 30 countries. 117 A previous Belgian exercise based on the 2003/2004 PRIMES baseline, has been performed by the Belgian Planning Bureau [FPB, 2004a]. 118 Belgian Official Journal (BS/MB Feb 28 pp 9879-9880). 119 The Baseline does assume a flat carbon emission permit price of 5 €'00/ton CO2 to reflect somewhat the European emission trading scheme for the sectors affected, and to include a variety of measures not easily explicitly translated into the model.


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5.3.2.2 Economic Activity and Demand for Energy Services The assumed 'plausible' evolution for the Belgian demographic evolution and economic activity is given in Table 5.1. [FPB, 2006 - Sept] These projections were based on EU forecasts, and long-term projections with the European economy model GEM-E3. [CEU, 2006a]. Figure 5.6 shows the assumed evolution of the GDP (which is also kept constant for the alternative scenarios).

Gross Domestic Product

0

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Figure 5.6. Assumed evolution of the Belgian GDP. (Plot obtained from information in Table 5.1.)


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Macro-economic assumptions for Belgium, 2000-2030

2000 2010 2020 2030 '90-'00 '00-'10 '10-'20 '20-'30

Annual % Change

Population (in Million) 10.246 10.554 10.790 10.984 0.3 0.3 0.2 0.2

Household size (inhabitants per household) 2.42 2.28 2.16 2.08 -0.6 -0.6 -0.5 -0.4

Gross Domestic Product (in MEuro'00) 247924 302858 370146 431665 2.2 2.0 2.0 1.5

Household Income (in MEuro'00/capita) 12904 14887 17226 19396 1.8 1.4 1.5 1.2

SECTORAL VALUE ADDED (in MEuro'00) 231229 280534 339665 393763 2.0 2.0 1.9 1.5

Industry 46407 53371 62492 71457 1.7 1.4 1.6 1.3

iron and steel 2630 2714 2753 2757 -3.1 0.3 0.1 0.0

non ferrous metals 1028 1295 1436 1477 -0.4 2.3 1.0 0.3

chemicals 9553 12219 14866 17565 4.5 2.5 2.0 1.7

non metallic minerals 2134 2125 2455 2691 0.2 0.0 1.5 0.9

paper, pulp and printing 3268 3927 4672 5345 1.1 1.9 1.8 1.4

food, drink and tobacco 5137 6107 7011 7764 -0.1 1.7 1.4 1.0

engineering 16236 18257 21593 25114 2.4 1.2 1.7 1.5

textiles 2587 2232 2200 2194 -0.3 -1.5 -0.1 0.0

other industries 3835 4495 5507 6548 2.8 1.6 2.1 1.7

Construction 11622 13123 14985 16653 1.4 1.2 1.3 1.1

Tertiary 162581 203552 250349 292506 2.2 2.3 2.1 1.6

market services 62659 78140 96924 115204 3.6 2.2 2.2 1.7

non market services 52285 64005 75402 81171 1.5 2.0 1.7 0.7

trade 43967 57722 74027 92013 1.1 2.8 2.5 2.2

agriculture 3669 3685 3997 4118 3.7 0.0 0.8 0.3

Energy sector and others 8509 7936 8762 9553 2.0 -0.7 1.0 0.9

INDUSTRIAL PRODUCTION

iron and steel (in ktn) 11636 11924 12040 11970 0.2 0.2 0.1 -0.1

integrated steelworks 8910 8376 8250 7846 -1.5 -0.6 -0.2 -0.5

electric processing 2726 3548 3790 4124 10.0 2.7 0.7 0.8

Table 5.1 Macro-economic hypotheses for Belgium 2000-2030 according to the PRIMES Baseline [FPB, 2006 - Sept]


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The input assumptions for the transportation-sector evolution are expressed in passenger-km and ton-km and come from the EU SCENES transport network model. [SCENES, web] This model accounts for the capacity of existing networks and for infrastructure projects described in the TEN-T (Trans-European Transport Networks). [TEN, web] The input data are summarized in Table 5.2. Those data have been considered as given in the CE2030 scenarios to follow. A lower transportation activity would lower primary energy use and lower the cost of climate policy. However, most sources expect a strong increase of freight transport needs and a more limited increase of passenger transport (except air transport). An increase in road transport will result from an increase of activities during off-peak periods. As a result, no further investments are needed. With different assumptions (level of transport activity or modal allocation), PRIMES would evaluate then the impact on energy consumption and emissions. An imposed "modal shift" in transport has not been analyzed in the PRIMES runs for the CE2030 study.

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Transportation-sector assumptions for Belgium, 2000-2030

2000 2010 2020 2030 '90-'00 '00-'10 '10-'20 '20-'30

Annual % Change

Transport activity

Passenger transport activity (Gpkm) 135.8 155.6 173.1 189.1 2.0 1.4 1.1 0.9

Public road transport 13.2 13.0 12.1 11.3 2.0 -0.1 -0.7 -0.6

Private cars 106.3 121.7 135.5 147.6 1.8 1.4 1.1 0.9

Motorcycles 1.0 1.2 1.4 1.5 -1.6 1.4 1.4 1.2

Rail 8.6 9.4 9.9 10.3 1.7 0.9 0.5 0.4

Aviation 6.5 10.0 13.8 17.9 8.2 4.4 3.3 2.6

Freight transport activity (Gtkm) 65.9 78.9 92.1 103.5 3.2 1.8 1.6 1.2

Trucks 51.0 62.1 74.0 84.2 4.1 2.0 1.8 1.3

Rail 7.7 7.8 8.0 8.1 -0.9 0.2 0.2 0.2

Inland navigation 7.2 9.1 10.2 11.2 2.8 2.3 1.1 1.0

Travel per person (km per capita) 13258 14742 16039 17218 1.7 1.1 0.8 0.7

Freight activity per unit of GDP (tkm/k€ '00) 266 261 249 240 1.0 -0.2 -0.5 -0.4

Source: SCENES, DG TREN (EC)

Gpkm: billion of passenger-kilometers (Giga = 109)

Gtkm: billion of ton-kilometers (Giga = 109)

Table 5.2 Hypotheses on transport activity for Belgium 2000-2030 according to the SCENES model [FPB, 2006 - Sept]

From these assumptions, the PRIMES model derives the need for energy services in those sectors, after which the market dynamics then assigns the appropriate energy technologies on the demand and the supply side. The demand for energy services is affected by energy prices (including the cost for carbon emissions in case of carbon constraints, in PRIMES represented by a 'carbon value') through estimated price elasticities. Price elasticities are estimated on the basis of econometric analyses which reflect current sensitivity (or current consumption behavior) of economic agents to changes in energy prices. E.g., in the CO2 constrained alternative scenarios to be discussed below, the 'carbon value' makes the model change the level of transport activity in reaction to higher energy costs. In other words, the transport activity in the CO2 constrained cases is not the same as in the baseline, and this affects energy consumption and emissions of the transport sector.

120 A study of a "modal" shift for transportation goes beyond the energy issue and should be undertaken in the realm of a full rethinking of the overall mobility issue (including logistics aspects of the economy, major infrastructure rethinking and investments, other approaches for residential and office, service & commercial building implantation and construction, and work-organization philosophies, etc) and this is well beyond the mandate of the CE2030. Also, a full European-wide approach should be considered as transit-type transportation is not negligible for a country like Belgium.


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5.3.2.3 Fuel Price Assumptions for the Baseline Mainly to reflect the tendency of high(er) fuel prices, the PRIMES baseline of 2003/4 has been revised. Background material on high fuel prices has been discussed in this report in Section 2.2. (See also [FPB, 2006 - Sept].) It is not the goal of this fuel-price evolution, to consider this as a 'forecast' of energy prices. (It may be noted, though, that the fuel prices assumed here are not unreasonable as is clear from a comparison with the prices assumed in [IEA, 2006d].) The important point on these fuel-price assumptions is that 'given these fuel prices', the Baseline will react accordingly. The price evolution assumed for the Baseline is as shown in Figure 5.7. [FPB, 2006 - Sept].

01 02 03 04 05 06 07 0

1 9 9 0 1 9 9 5 2 0 0 0 2 0 0 5 2 0 1 0 2 0 1 5 2 0 2 0 2 0 2 5 2 0 3 0$ 05/b oe

O i l - b a s e l i n e G a s - b a s e l i n e C o a l - b a s e l i n eO i l - r e f P P 9 5 G a s - r e f P P 9 5 C o a l - r e f P P 9 5G a s - H G P s c P P 9 5

Source: NTUA (2005), PP95

refPP95: reference scenario in the PP95

HGP sc PP95: High Gas Price scenario in the PP95

Figure 5.7. Comparison of international energy prices present baseline vs. scenarios in the PP95, 1990-2030 ($05/boe) [FPB, 2006 - Sept] boe =bbl oil equivalent

The price evolution for the Baseline is shown in solid line, for oil, gas and coal. To see the difference with the previous baseline, and the earlier scenario work of the FBP (the so called PP95 study), these earlier prices have been shown in dashed line. [FPB, 2006 - Sept] Three important points are to be noticed. 1) All prices are considerably higher than in earlier projections. 2) It is assumed that the oil prices will decrease till 2010, to start climb again (gradually) after that towards about 60$/boe (in constant $ of 2005). 3) The gas prices are supposed to follow the oil prices. Nuclear fuel prices include also the back-end costs. The overall simulation results are quite sensitive to the nuclear fuel cost. See Figure 5.3 and the Informative Box in Section 2.2.1.1.d. In a variant to the Baseline, a situation with monotonously increasing prices is considered. This is discussed below.


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5.3.2.4 Specific Assumptions on PRIMES Modeling for Belgium and the Baseline in Particular

121

a. Rationale Behind the Baseline or Reference Projection As already mentioned above, the purpose of the baseline is by no means to provide the most likely or most realistic picture of the Belgian energy system by 2030. The baseline rather simulates the impacts on the energy system and related CO2 emissions of current trends and policies as implemented in Belgium up until the end of 2004

122. The baseline reflects current knowledge on policies on energy

efficiency, renewables123

or climate change without assuming that specific targets are necessarily met. The possible gaps between the results of the baseline and policy targets (indicative or binding) show the challenges policy makers will be facing in the years to come as well as the need to go one step further if the target is to be met

124.

In addition to its role as reference projection, the baseline also serves as a benchmark for the assessment of alternative policy scenarios, as it allows to determine quantitatively the impact of alternative policies and measures. The definition of the baseline summarized above is standard and similar to the one used in other long term energy outlooks like the World Energy Outlook of the International Energy Agency, the World Energy and Technology Outlook of DG Research of the European Commission or the European Energy and Transport trends to 2030 of DG TREN of the European Commission. b. Transport Activity Energy demand in the transport sector is driven by several factors, one of which is the level and modal allocation of transport activity. Passenger transport activity is given in passenger-kilometers (pkm) whereas freight transport activity is given in ton-kilometers (tkm). Both indicators are disaggregated according to the mode of transport, namely public road transport, private cars (and motorcycles), rail (including tram and metro) and aviation for passenger transport and trucks, rail and inland navigation for freight transport. In the baseline, the evolution and modal allocation of transport activity are exogenous. Figures come from a European study

125 carried out in the framework of the mid-term implementation of the European

Commission White Paper “European Transport Policy for 2010: time to decide”, end of 2005. This study examines four policy scenarios for the transport sector in the European Union. In the PRIMES scenario analysis, the results of the “Partial Implementation scenario” (or P-scenario) are used for the baseline. However, in the alternative scenarios where a high carbon price is introduced (i.e. with a constraint on energy-related CO2 emissions), transport activity reacts to price increases and shows lower levels than in the baseline (see Table 31 p.85 of [FPB, 2006 - Sept]). c. Natural Gas Supply in 2030 The availability of natural gas supply in 2030 is implicitly ensured in the PRIMES modeling via the assumptions on the evolution of international gas prices. The latter are determined upstream by the

121 The CE2030 is very grateful to D. Gusbin & D. Devogelaer of the Federal Planning Bureau, for having provided the material for this section in a FPB working note "Further information on the long term energy scenarios for Belgium with the PRIMES model", May 2007. The text in this section has almost literally been copied from that note. 122 See for instance, European Commission, European Energy and Transport: Trends to 2030-update 2005, DG TREN, May 2006, [CEU, 2006a] 123 Policies aiming at promoting renewable energy sources include for instance subsidies on capital costs and preferential electricity selling prices. 124 Examples of targets are: the 7.5% reduction of GHG emissions specified in the Kyoto Protocol, the 6% target for renewables in electricity supply, the National Emission Ceiling (NEC) for acid pollutants… 125 See http://ec.europa.eu/transport/white_paper/mid_term_revision/assess_en.htm


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POLES model126

and result from the equilibrium between demand and supply (reserves, production …) at global level. d. Modeling of Renewables Penetration in the Power Sector In the baseline scenario, the development of renewable energy sources reflects improvements of energy technologies on the one hand and policies in place on the other hand. In the model database, the effects of improvements of renewable energy technologies are a reduction in capital and fixed costs over time and an increase in efficiency rates. These improvements reflect both “autonomous” technical progress (as a result of for example long term research effort) and “endogenous” progress (also so-called learning by doing). The endogenous progress is driven by anticipations about an increasing volume of new installations (under baseline trends)

127.

In the carbon constraint cases, renewable energy technologies deploy further as compared to the baseline because they emit no CO2 emissions. One can then expect that a higher deployment of RES may enable faster technology progress than the one considered in the baseline, and therefore a more rapid decrease in capital costs. This effect is taken into account in the post-Kyoto scenarios (i.e. the contribution of the “endogenous” progress term described above is amplified). This leads to lower overall costs of meeting the CO2 targets as compared to a situation where the costs of renewable technologies remain equal to their values in the baseline. As regards the policies in place, the supporting mechanisms of the Regions aimed at promoting the renewable energy sources for electricity production are simulated by the model via the introduction of a subsidy on capital costs (irrespective of the scenario). This subsidy improves the competitiveness of RES relative to other power generation technologies. However, the subsidies decrease over time to account for the steady reduction in capital costs and in order to maintain the budget devoted to subsidies within reasonable ranges. Finally, the cost of subsidies is recovered in the electricity tariffs. The application of both methodologies is illustrated below on two (generic) renewable power technologies:

Onshore wind power: the rate of subsidy to capital cost is set equal to 14% and 7% respectively in 2010 and 2020, leading to “actual” production costs close to 50 €/MWh in both years.

Offshore wind power: the rate of subsidy to capital cost is set equal to 26% and 13% respectively in 2010 and 2020, resulting in net costs for the producers of the order of 60 €/MWh in both years.

In the period up until 2020, the subsidies range from 5 to 50 €/MWh, according to the technology. It is worth noting that these figures are below the present values of the green certificates in the Regions which are close to the total production costs of the technologies (i.e. 100% subsidy). e. Modeling of Biomass Supply and Uses Biomass energy uses can be allocated in three groups each of them being modeled differently in PRIMES: (1) biomass for power and steam production (i.e. power plants (including co-combustion), CHP plants and industrial boilers), (2) biomass for space heating in the residential and tertiary sectors, and (3) biomass for the production of biofuels. According to the energy statistics for the year 2000, the first group represents about three quarters of total biomass consumption in Belgium and the third one, the remaining quarter. Of course the allocation between these 3 groups should evolve notably over time due to the development of biofuels in the transport sector and the promotion of renewable energy sources for electricity production

128. Therefore, the first two types of biomass use are likely to become

the most significant. In the baseline scenario as well as in all alternative scenarios, no upper bound was put on biomass supply on the Belgian territory (total supply combines domestic production and imports). The penetration of biomass in the Belgian energy system results from different mechanisms and assumptions according to the type of use.

126 See for instance chapter 1 of the report: European Commission, World Energy and Technology Outlook-2050, WETO-H2 [CEU, 2006d] 127 For more details, see for instance the description of the PRIMES model on http://www.e3mlab.ntua.gr/downloads.php 128 In the baseline, the respective shares become 55%, 40% and 5% in 2030.


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For electricity and steam production, the PRIMES model uses biomass supply curves that are calibrated to data provided by ECN (Energy Research Centre of the Netherlands)

129. A fuel supply

curve relates the price or unit cost of a fuel to the required fuel quantity. Fuel supply curves have a steep slope beyond a certain quantity of demand reflecting cost increases when moving to less favorable production sites or to more expensive fuel supplies. As far as the production of biofuels is concerned, the demand for biomass is determined by the share of biofuels in the transport sector, a share that is fixed exogenously in the model

130. In the scenario

analysis for the Commission Energy 2030, the share of biofuels is assumed to follow a similar trend in all scenarios, namely 2.1% in 2010, 6.4% in 2020 and 8% in 2030. Biomass consumption for heating in the residential and tertiary sectors is essentially determined on the basis of the boiler costs (investment, operating…) and the biomass costs, relatively to other heating technologies. The total demand of biomass is computed as the sum of the demand for the three types of uses. In all scenarios studied, the total demand never exceeds the biomass supply estimated in [De Ruyck, 2006]. f. Electricity Imports In the baseline (or reference projection), electricity imports and exports between European countries are determined endogenously by running the European interconnected version of the PRIMES model. Consequently, the evolution of the net electricity imports of Belgium takes into account the evolution of capacity surplus abroad (especially in France), the evolving level of interconnection capacities, the power price differentials between EU countries and differences in load curve patterns. Due to time constraints

131, only the Belgian PRIMES model was run for the alternative scenarios. In

this simplified picture, the net electricity imports of Belgium are exogenous and set equal to the levels of the baseline. Consequently, the scenario analysis performed with the PRIMES model for the Commission Energy 2030 does not deal with the possibilities of reducing CO2 emissions in Belgium by increasing the imports of (CO2 free) electricity. This policy option is to be analyzed downstream of the modeling results. 5.3.2.5 Maximum Assumed Potentials To reflect part of the Belgian reality into the scenarios, maximum 'technical potentials' have been imposed on the PRIMES model. These potentials apply to the Baseline and to all other scenarios run afterwards. It must be stressed, however, that the CE2030 Commission decided not to impose too many and too strict constraints of all kinds and sorts on the model, but to allow PRIMES to fill in what it believes should be made as investments. To reflect the reality that the first projects are usually the most attractive, a gradually increasing cost function has been applied, but limitations due to e.g., required grid extensions have not been imposed. Similarly, we have not imposed exogenous growth-rate limitations, although such might certainly be justified. Indeed, for renewables, such as wind turbines and PV systems, it is likely that the manufacturers will not be able to deliver at a rate that the model sometimes predicts. The same applies to the observed strain on coal-fired plants construction because of a loss of manufacturing capability in Europe, together with an expected demand for new coal-fired units. The issues relating to renewables, will have to be addressed in the qualitative interpretation of the results in Section 6.3.2.1. Reasonable limits on growth rates for renewables have been considered by [De Ruyck, 2006].

129 Similar cost curves are used for other renewable power technologies (wind, solar PV…). The ECN study is confidential. 130 This parameter is determined in collaboration with DG TREN on the basis of available information from the Member States on the development of this energy option. 131 Running the European version of the PRIMES model for each alternative scenario was unthinkable within the framework of this study. Indeed, doing so would have required not only more time (due to the more complex structure of the European model) but also the definition of alternative policy contexts in the other EU countries.


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The following potentials were taken: [De Ruyck, 2006] - wind onshore: Max 2,026 MW - wind offshore: Max 3,800 MW - PV: Max 10,000 MW - Biomass: No constraint; but electric capacity limited by a "cost supply curve". The limitations for onshore wind are based on detailed and recently updated studies. In the case of offshore, a total potential of some 13 GWe has been identified on the very long term. For 2030, a limitation up to 3800 MWe has however been taken, owing to the given concessions, growth limitations in terms of installing this capacity and the consequent grid penetration, and limitations in terms of overcapacity. For PV systems it has been assumed that in principle 100 km

2 might be feasibly to be covered with PV

cells on roofs, highways, etc. At these limits, the grid penetration rate of intermittent power production is getting so high that overcapacity starts to occur under low demand and high wind/sun conditions, and further penetration is unlikely without major electric storage capacity before 2030. As will be discussed in Section 6.3.2, it is not reasonable to expect that the integration of these intermittent sources can occur without any major investment for back up and balancing. Installing more than about 900 MW offshore wind would, for example, require a major investment in the high-voltage grid in West Flanders. If the investment would be done by open air lines, the cost would be of the order of 150 M€; in case of cables, the cost would be roughly 700 M€, which more than doubles the investment per kWe. [R. Belmans; personal communication]. For massive PV installation, a similar reasoning applies to costs for the distribution grid (see Section 6.3.2). However, since these numbers are based on less tangible expert-judgment estimates, these sorts of limitations have not been imposed on PRIMES. The PRIMES results will be qualified against the reality of these major investments, which have to be interpreted as major cost-'challenges' to be overcome if one wants to fill in the full 'technical' potential. The domestic biomass potential from arable and forest lands is limited by the available surface areas in Belgium, which amount to 14,000 and 7,000 km

2, respectively. The amount of biomass energy

which can be produced in both cases varies between 1 and 5 GWhth per km2, which sets an average

limit of 60 TWhth if the entire available surface is used for energy purposes. According to [LIBIOFUELS, 2005], up to 10% of the arable land is acceptable for energy production, leading to 1,400 km

2 and some 4.2 TWhth. The availability of forest residues should be higher and is assumed

here to be 30% of the total forest area, leading to 2,100 km2 and 6.3 TWhth. The availability of the

domestic biomass cultivation is therefore estimated at some 10.5 TWhth, eventually extendable by higher acceptable surface shares and increasing yields beyond 2030. According to the Ampere report [AMPERE, 2000], biomass energy from dry biomass residues (other than forest) is in the range of 9 TWhth/a, originating to a large extent from municipal waste. Energy from wet biomass residues leading to biogas can be estimated at 3 TWhth/a, coming mainly from sludge and manure. In summary, 22.5 TWhth or 80 PJth energy should be obtainable from domestic sources, to be converted into either heat, electric power, or biofuel suitable for transport. Further biomass penetration calls for massive import. Import of biomass is virtually unlimited because of the small size of our country. The reality of a high biomass demanding Europe or even World, however, leads to considerable increase of the cost. In practice, it has therefore been proposed to limit the imports to 180 TWhth, or some 30% of the primary energy consumption, subject to a growth limitation of 11% per year. This should be compared with a more conservative European limit of 15% primary energy from domestic biomass and less import than


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that. Such limitations have, however, not been imposed to PRIMES, where a cost supply curve has rather been assumed. The results from both approaches are compared in section 6.3.2. The biomass cost supply curve used in PRIMES was prepared by the ECN (Energie Centrum Nederland) in 2005. ECN prepared similar curves for all renewable energies in the EU member states, as input for PRIMES. These curves are based on ECN's ADMIRE-REBUS techno-economic market model. It must be observed that when looking into the details of this work no real limit on the biomass feedstock supply is observed for Belgium till 2030 (as for many other Member States). Limits are rather emerging from limited availability of e.g. co-firing plants, biomass CHP and other capacity where costs increase. There is no limitation whatsoever on direct heat supply from biomass. It should be mentioned that within the present limitations our import dependency in 2030 for biomass is already high, and that higher impact on the conclusions would mean enormous amounts of biomass import and high pressure on a (soaring?) biomass cost. We should also not forget the pressure on the environment caused elsewhere by massive use of biomass for energy. Already now, criticism is heard about imports of biomass for power plants such as Les Awirs 4 and much care must be taken to guarantee this biomass to be obtained in a sustainable way. It should at the same time be stressed that Belgium plays a leading role in creating such certification mechanisms. It should finally be stressed that the repartition of biomass over electricity, CHP, heat and transport is controlled by PRIMES through its optimization process. There are no imposed quota in the considered scenarios, and biomass finds its way as well in electricity, CHP and heat production. Net biomass import is already partly exporting our problems, and net green electricity import from biomass is even more controversial: by importing green electricity we even lose the added value of making it ourselves and it also implies transport losses/costs. It seems better to increase import of biomass and take into account all the costs for conversion towards green electricity at the domestic level and thereby creating an added value, rather than to import green electricity which is likely even less attractive in economic terms. An argument towards green electricity import can be found in the balancing of wind and solar energy over areas beyond the Belgian borders, but this implies almost automatically a fair balance between import and export. The sole advantage of such an import/export scenario is an increased availability of the green electricity and less impact on balancing costs. Net import of green electricity has therefore not been considered as a possible option in the PRIMES scenarios. 5.3.2.6 Greenhouse Gases in PRIMES As PRIMES is an energy model, only energy-related CO2 emissions are considered by the model. The other greenhouse gases are not dealt with in PRIMES. In addition, it should be noted that aviation bunkers are included in PRIMES, whereas this is not the case with marine bunkers. (See [FPB, 2006 - Sept] and Table 3.3.) The way the non-CO2 GHG are dealt with in our CE2030 analysis, is explained below.

5.3.3 Baseline-Like with Soaring Fuel Prices Before launching into a set of alternative scenarios, it is interesting to first consider a fuel-price adjusted baseline. Therefore, as a first exercise, it is examined how the results of the Baseline change if even higher fuel prices had been chosen from the outset. These higher, often referred to as 'soaring', fuel prices are shown in Figure 5.8. The fuel prices of the Baseline proper have been shown in dashed lines for comparison. The 'soaring price' for oil is about 100 $'05 per barrel of oil equivalent in 2030. In this exercise, all other parameters, beside the fuel prices, have been kept the same as in the Baseline.


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Oil-Soaring

Oil-Base

Gas-Medium

Gas-Soaring

Gas-Base

Coal-Soaring

Coal-Base

0

20

40

60

80

100

120

1990 1995 2000 2005 2010 2015 2020 2025 2030

$ of 2005 per barrel of oil equivalent

Figure 5.8 Assumed 'soaring fuel prices' compared to Baseline prices (1990-2030) [FPB, 2006 - Sept]

As a matter of fact, this so-called sensitivity-analysis scenario with soaring fuel prices also can be viewed to encompass a particular policy decision. The results obtained by PRIMES would be the same if this scenario had been considered as a 'security of supply' scenario, in which an import tax (on a European-wide level) had been imposed on oil and gas. In both cases there will be a downward pressure on the use of oil and gas, forcing even more energy savings and endogenous renewable energy, and improving the security of supply. The difference between the soaring fuel prices (in the literal sense) and the import tax, is that money is exported to the oil & gas producing countries, in the first case, while it remains here in our country in the case of a tax.

5.3.4 The Concrete Scenarios Considered

5.3.4.1 Overview In contrast to the Baseline, which projects into the future based on the currently decided policies and measures, some alternative scenarios are set up with certain constraints to "shape" the energy future into a certain direction. As one of the major driving forces, or influencing factors, for the future energy provision, the GHG reductions imposed by the Climate-Change threat are of paramount importance and act as natural constraints for a scenario analysis. It is then the aim to see how the system responds to considerable GHG reduction limits and what the consequence is on security of supply and the cost for energy provision. Since the Baseline does not assume any post-Kyoto GHG reductions, with the nuclear phase out implemented, it is to be expected (and that will be shown below) that the Baseline is not quite sustainable from a Climate-Change point of view. The CE2030 has therefore taken the approach to use Climate Change as the determining challenge by imposing constraints on the energy system. In the alternative scenarios to be discussed, we impose a CO2 or CHG constraint, on the Belgian energy system or on that of the EU, respectively. We then find out what the consequences are and how the system responds to it. Few other constraints are considered, since we wish to see how the PRIMES model traces out the energy future in a fully consistent manner, according to the simple rule that it first takes those options that are most economically efficient. From studying the "natural" behavior of the energy system under the post-Kyoto constraint, policy makers may then be guided by focusing on those measures that are in line with the scenario trace.


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In the alternative scenarios, we keep in mind that the EU will impose a GHG reduction of 30% in 2030 compared to 1990. (The reason for this 30% reduction is discussed in the following section.) To see what that means for Belgium, we consider a variety of alternative scenarios. To demonstrate in a transparent way how difficult it is to reduce energy-related CO2 emissions domestically, we have run a first set of scenarios that impose an energy-related CO2 cut by 15% and by 30% in 2030 compared to 1990. The emission cuts are to take place in all sectors of the energy system, and all sectors will be influenced, but the emission cuts will first take place there where it is the cheapest to do so. Although only representing about 16% of the final energy-use (See Chapter 2), the electricity sector will be shown to be of paramount importance for satisfying the GHG constraint. Indeed, two electricity-generation related 'switches' exist for alleviating (or complicating) the reduction of GHG, and especially energy-related CO2. These 'switches' are nuclear electricity generation and Carbon Capture and Storage (CCS). Hence, eight CO2 reduction scenarios have been considered: -15% and -30%, each of them with and without the nuclear power option and the availability of CCS. Together with the Baseline, this gives a spectrum of results ranging from a domestic post-Kyoto limit of 0% over 15% to 30%, for the latter cases each time with and without nuclear and CCS. This will in fact show that very deep domestic CO2 reductions, in the absence of nuclear power and CCS, are effectively impossible by 2030. This "proof ex absurdo" will advise which domestic cuts seem reasonable and how we should make use of the flexible mechanisms. Led by the wisdom of the previous exercise that drastic domestic CO2 reduction targets will be very difficult in Belgium (and certainly so without nuclear power or CCS), it is important to see how the GHG-reduction efforts can be reduced in the EU by using the flexible mechanisms. For its final report, the CE2030 has been able to benefit from a post-scenario comparative analysis carried out by the Federal Planning Bureau [FPB, 2007], based on its earlier scenario work in 2006. [FPB, 2006 - July; FPB, 2006 - Sept] In that approach, one GHG reduction limit is imposed on the entire EU, which is then considered as one region, in which CO2-emission reductions take place according to the lowest MAC. From that exercise it can be found where the actual emission reductions should take place. Assuming a national emission reduction cut similar in % terms as the EU, but in terms of responsibility, it can in principle be figured out how a nuclear phase out influences the domestic reduction cuts, as well as the cost for relying on emission trading. The following subsections provide all the relevant elements for the construction of the scenarios. 5.3.4.2 Post-Kyoto Scenarios It should be clear that at this moment, it is everybody's guess as to what the future imposed GHG reductions by 2030 might be for Belgium. However, because of the long-term strategy needed and the appropriate preparation for investment decisions, we cannot afford to be too optimistic, in the sense that we can close our eyes and hope/pretend that the future CO2-reduction burden will be easy. With such attitude we may have to face a serious surprise if matters turn out differently, as the time to adjust then will simply not be there. It does not seem unreasonable to assume that the EU might have to commit to a decrease in GHG by 30 to 40% by 2030 compared to 1990, as recent EU official statements seem to point to that direction. In the Green Paper on Energy [CEU, 2006b] the following statement can be read: «In order to limit the forthcoming rise of global temperatures at the agreed target of maximum 2 degrees above pre-industrial levels, global greenhouse gas emissions should peak no later than 2025, and then be reduced by at least 15%, but perhaps as much as 50% compared to 1990 levels.» The most firm declarations have been made early 2007, first in the EU Commission Energy & Climate package of January 10 2007 [CEU, 2007a,b], and later confirmed by the EU Summit of March 8/9 2007 [Council EU, 2007]. We quote from this last document:

132

132 Underlined emphasis has been added.


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- 30. «The European Council reaffirms that absolute emission reduction commitments are the backbone of a global carbon market. Developed countries should continue to take the lead by committing to collectively reducing their emissions of greenhouse gasses in the order of 30% by 2020 compared to 1990. They should do so also with a view to collectively reducing their emissions by 60% to 80% by 2050 compared to 1990.»

- 31. «In this context, the European Council endorses the EU objective of a 30% reduction in greenhouse gas emissions by 2020 compared to 1990 […] provided that other developed countries commit themselves to comparable emission reductions and economically more advanced developing countries to contribute adequately according to their responsibilities and respective capabilities. […]» - 32. «[…] the EU makes a firm independent commitment to achieve at least 20% reduction of greenhouse gas emissions by 2020 compared to 1990.» Recently, the UK has confirmed its commitment to have the carbon emissions reduced by 60% in 2050 compared to 1990. [DTI, 2006] In what follows below, and for the sake of argument, we shall assume here that the EU might commit to a 30% GHG reduction by 2030 compared to 1990. a. Greenhouse Gases versus CO2 and Flexible Mechanisms We recall from earlier sections (cf. Section 3.2.2) that the climate-change challenge is to reduce GHG and not only CO2. The latter is dominant, however, since about 86% of all GHG in Belgium is CO2 and of that CO2, 92% is energy related. It must be recalled that the PRIMES model only deals with energetically-related CO2 emissions, and so, one must get some kind of idea on how the non-CO2 gas emissions might evolve in the future. Regardless of how the future Belgian climate policy is actually carried out with regard to the EU commitments, it is the goal of the CE2030 to clarify the consequences for an energy provision that should also be kept affordable and guarantees a firm security of supply. In what follows, we first will try to get an idea of the order of magnitude for actual GHG and energetically-related CO2 reductions that may have to be expected on the Belgian territory by 2030. Since in some cases the marginal abatement cost in Belgium will be considerably larger than abroad, we will rely on the flexible mechanisms for reducing the burden of domestic reduction. Two approaches are considered below. In a first one, we try to "guestimate" what domestic energy-related CO2 emission reduction Belgium might be faced with. Here it is assumed that flexible mechanisms will only be used or allowed to a limited extent. This is a pragmatic estimate, so as to be ready for reality on the energy-provision scene when faced with it. In a second approach, we look at the overall European efforts and try to find out how an ideal distribution of emission reduction should take place in Europe, thereby allowing the flexible mechanisms to run their full course. a.1 Focus on the Belgian Territory It is instructive to estimate what can be expected from the non-CO2 GHG reductions in Belgium and Europe over the years to come. It should be noted, however, that these estimates are very uncertain and are by no means guaranteed. This will be clear from what follows. Projections up to 2020 have been communicated by Belgium in the 4-th National Communication in the framework of the UNFCCC. [National Climate Commission, 2006a, b.; FPB, 2006-July] These communicated numbers, for a so-called scenario "with measures" —basically based on the currently existing measures— are shown in Table 5.3, except for the last column. In the last column, projections for a scenario "with extra measures" are reported.


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[Mton CO2-eq/a] Base year 2000 2010 2020 2020 vs base

year 2020

with extra measures

Non-energy CO2 9.1

(100) 10.2 (112)

10.1 (111)

10.2 (112)

12.5%

Industrial processes 8.5 9.6 9.2 9.3 9.9%

Fugitive + Waste 0.6 0.6 1.0 0.9 48.5%

CH4 10.8 9.8 7.9 7.5 -30.6% 7.4

N2O 12.2 12.9 11.3 11.1 -9.1% 10.4

F gases 4.8 1.3 2.7 3.6 -25.2% 2.3

Table 5.3. Projections of the non-CO2 energetically related GHG, according to the 4-th Communication [National Climate Commission, 2006a, b.; FPB, 2006-July]

Table 5.4 shows a deviating (internationally) computed estimate for the GHG other than energetically-related CO2 for similar conditions as the Baseline.

133 [FPB, 2006-July]

[Mton CO2-eq/a] Base year 2000 2010 2020 2020 vs base

year

Non-energy CO2 13.1

(100) 11.9 (91)

12.9 (98)

12.2 (93)

-6.9%

Industrial processes 12.5 11.4 11.9 11.2 -10.9%

Fugitive + Waste 0.6 0.5 1.0 1.0 59.7%

CH4 10.8 9.8 8.9 9.0 -16.8%

N2O 12.2 12.9 13.5 13.2 8.6%

F gases 4.8 1.2 1.8 2.1 -56.6%

Table 5.4. Projections of the non-CO2 energetically related GHG, according to model projections [FPB, 2006-July]

It does not seem obvious to draw firm conclusions from these tables. Sometimes (e.g., for CH4 and N2O), Table 5.3 gives more optimistic reductions; for other gases (non-energy CO2 and F gases), it is the other way around. For the purposes of this CE2030 report, we need furthermore estimates up to 2030, and also for other scenarios than the Baseline scenario, i.e., with stringent GHG-reduction requirements. It seems reasonable to assume that under a post-Kyoto reduction pressure, the reduction efforts of non CO2 GHG gases will be larger than mentioned in the here above mentioned tables. For the situation in which the nuclear phase out is implemented in Belgium (resulting in a large marginal abatement cost (MAC) for energy-related CO2), an expected cost-reduction relationship for all GHG for the year 2020 in Belgium is presented in Figure 5.9. [FPB, 2006-July]

133 This has been done by the NTUA, Athens Greece, with a different model than PRIMES, and the IIASA, Laxenburg, Austria with the model GAINS. For details, see [FPB, 2006-July].


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Figure 5.9. Marginal abatement cost (MAC) or Carbon Value (CV) for Belgium in 2020, split per group of GHG. This plot assumes that the nuclear phase out in Belgium is implemented. In ordinate, the reduction in % with respect to the base year (1990 or 1995) is given, the abscissa gives the CV in terms of an auxiliary variable in €/ton CO2-eq in 2030, whereby the CV in 2020 can be read from Figure 5.10. Source NTUA; taken from [FPB, 2006-July] The previous plot and some other plots to follow, make use of a MAC-conversion plot shown in Figure 5.10. This conversion plot has been introduced for simplicity of figure labeling, and is a consequence of the changing MAC with time. The rule for conversion is explained in the figure caption of Figure 5.10.

Figure 5.10 Conversion plot of CV values over the coming years. The ordinate is expressed in €/ton CO2-eq. The legend refers to CV values in 2030. From the figure, it follows that a CV of 200 €/ton in 2030 corresponds to an actual CV of 150 €/ton in 2025 or 120 €/ton in 2020. For the logic behind this CV conversion and more details, see [FPB, 2006-July].

MAC curves for the case without a Belgian nuclear phase out are not available as such. However, because of the very large fraction of nuclear generated electricity in Belgium, the MAC for energetically-related CO2 reduction diminishes drastically. This will become clear from the other curves and results discussed below.


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Based on the above information, and keeping in mind the reality of negotiations within the EU regarding "burden sharing" and possible own imposed limitations on the use of flexible mechanisms, we now try to get an idea on the magnitude of energetically related CO2 reductions to be established domestically. Note that the higher the EU reduction limits imposed, the higher the pressure also on the other GHG to reduce more drastically, compared to a baseline. We now calculate backwards what kind of energy-related CO2 reductions could be expected on the Belgian territory. The following are just rough guesses to get a feeling for the numbers involved. à Start from an EU commitment of - 30% GHG emissions; à assume that Belgium might negotiate such that the EU bubble for burden sharing leads to a commitment for Belgium of - 25% GHG emissions. This means that Belgium would be able to have a commitment that is 1/6 or ~ 17% lower than the EU as a whole. (Compare that under the current Kyoto bubble agreement, the EU has to reduce by 8%, while Belgium has committed to -7.5%.) à assume that the emissions of F-gases reduce to zero by 2030 (which is the most stringent case thinkable); à assume that the CH4 and N2O can be reduced by 25% to 40%; à assume the same rate of decrease of non-energy-related CO2 emissions and energy-related CO2

emissions. When doing the arithmetic, these assumptions/guesses would lead to a requirement of energy-related CO2 reductions for Belgium by 19% to 22%. If we furthermore assume/guess that of this requirement about 5%-pts can be covered with the use of flexible mechanisms (which amounts to roughly one quarter via emission trading, JI or CDM) we end up with about -15% domestic energy-related CO2 emissions. If we now keep in mind that the EU requirement by 2030 might go deeper than 30%, it is possible that stiffer domestic energy-related CO2 reductions will be required, perhaps up to 20%. It is therefore not unreasonable to keep in mind that the energy system of 2030 should be able to cope to domestic energy-related CO2 emissions of the order of, say 10-20% compared to 1990. Note that the more flexible mechanisms are made use of, the more is to be paid for, e.g., through buying emission rights abroad. As explained in the next Section, we will also consider a European approach. Doing so, we will base ourselves on the Working Paper 1-07 published by the FPB in January 2007 [FPB, 2007] in which an overall reduction of 30% of GHG is imposed. Making use of an ideal emission-reduction exchange within the EU, the domestic reductions will then turn out to be quite small. If faced with similar reduction obligations (in terms of responsibility) as the EU, then Belgium will have to seek refuge in buying extra emission certificates. This will also be elaborated in Section 6.3.3. Under less ideal international emission-reduction exchange (than with a simulation model), the real domestic decrease of energy-related CO2 reduction might still be of the order of 10% (or more). a.2 European-Wide Approach In a second type of philosophy, we look at the marginal abatement costs (MAC) for GHG in the whole EU and compare them with those in Belgium. It is then the intention to have the emission reduction take place there where it is the cheapest, i.e., where the MAC is the lowest. The domestic reductions are then determined by having an equal MAC for all countries and sectors. Figure 5.11 shows the MAC curve for GHG reduction in the EU-30. As already mentioned, this plot makes use of the MAC-conversion plot shown in Figure 5.10. The rule for conversion is explained in the figure caption of Figure 5.10.


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Figure 5.11. Marginal abatement cost (MAC) or Carbon Value (CV) for the EU in 2020, split per group of GHG. This plot assumes a nuclear phase out in those countries where it is currently legally foreseen. In ordinate, the reduction in % with respect to the base year (1990 or 1995) is given, the abscissa gives the CV in terms of an auxiliary variable in €/ton CO2-eq in 2030, whereby the CV in 2020 can be read from Figure 5.10. Source NTUA; taken from [FPB, 2006-July]

Furthermore, NTUA has constructed the MAC curves for GHG emission reduction in the EU and in Belgium for the years 2015, 2020, 2025 and 2030. In the left hand-side (LHS) plots below (Figure 5.12 and Figure 5.13), the amount of reduction expressed in terms of Mton CO2-eq/a is compared to the base year (effectively 1990), while the right-hand side (RHS) figures compare to the baseline. Again, the ordinate refers to the carbon value (CV) of 2030, expressed in €/ton CO2-eq; use is to be made of Figure 5.10 for the conversion to the other years.

134 These plots have been taken from [FPB, 2006-

July] where more information is available. Figure 5.12 applies to the EU.

134 These curves are to be read as follows, focusing, e.g., on Fig 5.12 LHS. Following Figure 5.12, a CV of 80 €/ton in 2030 is equivalent to ~ 50 €/ton in 2015 and ~ 62 €/ton in 2020. Then, the 2030 curve of Figure XX6 LHS tells us that it will cost 80 €/ton to reduce the 1200-th Mton in 2030 compared to the base year. From the 2020 curve, it will cost 62 €/ton in 2020 to reduce the 900-th Mton, and from the 2015 curve, it will cost 50 €/ton in 2015 to reduce the 800-th Mton.


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Figure 5.12. The marginal abatement cost curves for the years 2015, 2020, 2025 and 2030 for all GHG in the EU. These plots assumes a nuclear phase out in those countries where it is currently legally foreseen. The ordinate is the Carbon Value (CV) in 2030 expressed in €/ton CO2-eq. For obtaining the CV in the other years, refer to Figure 5.10 and the footnote below. Source NTUA; taken from [FPB, 2006-July]

Figure 5.13 applies to the Belgian territory.

Figure 5.13. The marginal abatement cost curves for the years 2015, 2020, 2025 and 2030 for all GHG in Belgium. These plots assume that the nuclear phase out in Belgium is implemented. The ordinate is the Carbon Value (CV) in 2030 expressed in €/ton CO2-eq. For obtaining the CV in the other years, refer to Figure 5.10 and the footnote below. Source NTUA; taken from [FPB, 2006-July]

A comparison of the two frames of Figure 5.13 clearly gives an indication of the cost of a nuclear phase out in Belgium, by not taking advantage of cheap existing CO2 reduction means. Recall that both frames give the MACs assuming that the Belgian nuclear phase out is implemented. But on the LHS, the comparison is made with the base year (1990), when nuclear electricity generation was still keeping a considerable amount of CO2 emissions out of the atmosphere. On the RHS, on the other hand, the comparison is with the baseline, which assumes a nuclear phase out implemented; in that baseline, nuclear power is largely replaced by gas- and coal-fired stations. The shift of the curves in


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Figure 5.13 is mainly due to the nuclear phase out.135

Concentrating on the year 2030, one sees from the RHS frame that it costs 80 €/ton to reduce the CO2 emissions by 30 Mton/a

136 in 2030 compared

to the baseline (in which the CO2 emissions had gone up considerable), which, according to the LHS frame, merely means that that 80 €/ton is necessary to keep the CO2 emission at the same level as in the base year (0 Mton of avoided emissions). b. Domestic Reduction of Energy-Related CO2 Concretely and along the philosophy explained above, a first set of scenarios concentrates on domestic reductions of energy-related CO2 emissions in Belgium. This type of scenarios clearly demonstrates in a transparent way how the Belgian energy system reacts to a local CO2 constraint. In the interest of clarity, in these scenarios, no other GHG, and no flexible mechanisms in Europe are considered. The domestic scenarios require a reduction of energy-related CO2 by 15% and 30% in 2030 compared to 1990. For each, two cases are considered: one with the nuclear phase out implemented and one without a nuclear phase out (the actual implementation of both the phase out and the lifting of it will be discussed under point d., below); and in one set of runs with CCS thought to be commercially available and another set in which it is assumed that CCS is not quite routinely available commercially. In summary, the following alternative domestic scenarios are considered. Post-Kyoto -15% CO2 in Belgium by 2030 compared to 1990 - nuclear phase out; no CCS available - nuclear phase out; with CCS available - no nuclear phase out; no CCS available - no nuclear phase out; with CCS available Post-Kyoto -30% CO2 in Belgium by 2030 compared to 1990 - nuclear phase out; no CCS available - nuclear phase out; with CCS available - no nuclear phase out; no CCS available - no nuclear phase out; with CCS available c. European-Wide Reduction of GHG Based on Equi-marginal Abatement Cost Benefiting from a comparative analysis performed by the Belgian Planning Bureau [FPB, 2007], it is possible to evaluate how the Belgian GHG emission reductions will take place in a European context, based on the equi-marginal abatement cost principle. The following scenarios have been considered: Post-Kyoto -30% GHG in the EU by 2030 compared to 1990 No CCS assumed to be available With and without implementing the nuclear phase out in Belgium. Each of these alternative scenarios will then be compared with the Baseline, both for domestic reduction of CO2 and the whole set of GHG. d. The Nuclear Option The CE2030 considers it as self-evident to consider the effects of relaxing the nuclear phase-out requirement to find out its effect on the ease or difficulty of satisfying the GHG constraints. Compared

135 The effect of a nuclear phase out or not in Belgium on the MAC curves for the EU is not well visible on the EU scale as can be seen from Figure 5.12. It turns out that the difference due to a Belgian nuclear phase out or not in the EU in 2030 (if the EU opts for a GHG reduction of 30% in 2030) is a CV of 200 €/ton with the Belgian nuclear phase out versus 190 €/ton if the Belgian nuclear phase out is lifted. 136 More correctly stated: to reduce the 30-th Mton that year, it will cost about 80 €/ton.


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to the nuclear phase-out route as incorporated in the Baseline, it is considered in this 'thought exercise' to lift the phase-out obligation as follows. All existing units are allowed to prolong their operation after the age of 40 year, given the condition that they keep satisfying all safety requirements for 'proper' operation

137.

In that regard, based on expert judgment, the following reasonable assumptions have been made for the existing units: - the four youngest units (Doel 3&4, and Tihange 2&3) can have an extended operation time of in total 60 years, without extra costs compared to the usual 10-year overhauls; - the three oldest units (Doel 1&2, and Tihange 1) can have an extended operation time of in total 60 years, but on the condition that extra investments take place. Taking into account the design, and previous overhauls, it is estimated that Tihange 1 might need an extra 1/4 refurbishment investment compared to the cost of a new unit. For Doel 1&2, an extra investment of 30% has been taken. In addition to allowing the existing units to have a prolonged operation time, the possibility is left to the model to invest in one extra new nuclear unit of 1700 MW after 2020. It will do so if the investment is cost-effective. e. Carbon Capture and Sequestration as a Switching Variable As is obvious from the literature, [IEA, 2004d

138, 2006b, 2006d, 2006e; IPCC, 2005], the CO2-

'mitigation' technology of capturing and storing CO2, might be available as a commercially viable option as after 2020 - 2030. However, it is by no means certain that this technology will be 'up and running' at full speed. For Belgium, especially the storage part seems to be uncertain to questionable by that time [Van Tongeren, et al., 2004; Pamplona & Mathieu, 2002; Piessens et al., 2007], also if safety issues on accidental release of CO2 are taken into account and consideration is taken of timely construction and operation permits. Concerning storage, the Policy Support System for Carbon Capture and Storage PSS-CSS funded by the Belgian Science Policy Office has compared the three reservoir types in Belgium: aquifers, recovery of enhanced coal bed methane and abandoned coal mines. The PSS-CSS put in evidence the thorny aspects of the geological and technical reservoir uncertainties, the high costs of initial projects, the lack of proper regulation or government support and the low level of R&D funding. Export of large CO2 quantities from Belgium to storage facilities in deep North Sea saline aquifers is unlikely to be considered as usual business by the 2030 horizon, even if some encouraging storage exploring tests are presently conducted. Note that these CCS technologies will only mainly be applied to large centralized electricity generation units (coal-fired units and CCGTs). CCS is not really an option for decentralized generation technologies, neither for vehicles. Because of the uncertainty surrounding CCS, it has been decided to consider a 'switch' in the post-Kyoto and nuclear versus non-nuclear scenarios: once with CCS available and once with CCS assumed not available.

5.3.5. Summary of Scenarios In summary, the whole range of scenarios can be presented as follows

139:

137 To be evaluated by the competent safety authorities. 138 Some numbers in this IEA report may be somewhat outdated, but it gives a good overview of the issues. The most recent numbers can be found in [IEA, 2006e] 139 Adapted from [FPB, 2006 - Sept] and [FPB, 2007]


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Summary of scenarios

Baseline:

Bpk00: base scenario in which no post-Kyoto reduction limit is imposed in Belgium and where a decommissioning

of nuclear plants takes place. Fuel prices are those of the 'standard'-baseline prices in Figure 5.7

Bpk00-h: baseline-type scenario in which no post-Kyoto reduction limit is imposed in Belgium and where a

decommissioning of nuclear plants takes place. Fuel prices are those of the 'soaring' type as shown in Figure 5.8

Domestic energy-related CO2-reduction scenarios


and where a decommissioning of nuclear plants takes place









and decommissioning of nuclear plants








European-wide GHG-reduction scenarios

EUpkGHG30s: scenario in which the EU reduces its GHG emissions by 30% in 2030 compared to the 1990

level, decommissioning of nuclear plants in Belgium and CCS is not available in the period 2020-2030 in the EU

EUpkGHG30ns: scenario in which the EU reduces its GHG emissions by 30% in 2030 compared to the 1990

level, lifetime extension of existing Belgian nuclear plants + possibility of having 1 new nuclear unit of 1700 MW

after 2020 in Belgium; CCS is not available in the period 2020-2030 in the EU

The following conventions have been applied: B: stands for Belgium pk: stands for post Kyoto 00, 15 or 30: stand for the imposed Post-Kyoto reduction n: means nuclear option open s: means no CCS allowed (abbreviation of the French "sans") h: high fuel prices


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6. Results of the Scenarios The FBP report [FPB, 2006 - Sept] contains a systematic analysis of the PRIMES results which serve as input for the presentation of the scenario results. The most pertinent data are extracted and discussed in the present section, without repeating the FBP discussion and the details which can be found in annex D of the FPB report. The interested reader is invited to consult this document, available as a Supporting Document to this CE2030 Report.

140

6.1 PRIMES Baseline Scenario; Belgian Results In this CE2030 report, only the main results and messages are highlighted. Most figures and tables speak for themselves; we draw attention to what we believe is to be kept in mind for further comprehension of the 'story' and for drawing conclusions. We discuss the scenarios results in a different sequence than presented in [FPB, 2006 - Sept] to reflect somewhat a plausible cause-effect relationship in the energy system.

141 In principle, it starts

with the prices of the primary fuels, which, after taking into account the imposed constraints put on the energy system, is translated into a final energy demand by consumers (through demand for energy services and the utilization of energy-conversion technologies), largely based on the prices for the secondary carriers

142. An important user of energy-conversion technology on the supply side is the

electricity-generation sector. The price/cost of electricity generation is clearly reflected in the choice of energy carrier preferred by the end users.

143 Taxes and levies play an important role in the change of

diversity of demand carrier, which is clearly reflected in the end consumption of fuels for vehicles. All of this together then determines the primary energy basket of the country, and its import dependency. We recall that in contrast with the other scenarios to be discussed below, the Baseline has no post-Kyoto-requirements, it fully implements the nuclear phase out, and CCS would be available within the time horizon under consideration. Fuel prices are 55$/bbl in 2005 and increase to 60$/bbl in 2030 in real terms. A 'subsidy' for renewable energy has been included. Since PRIMES is not able to include the often complex and various subsidy mechanisms, an overall and guaranteed subsidy has been included through an average and equivalent reduction in investment costs.

6.1.1 Final Energy Demand in the Baseline

Figure 6.1 and Table 6.1 present an overview of the evolution of the total final energy demand and subdivided per sector. Figures 6.2 and 6.3 further zoom in on particular aspects. The final energy demand seems to rise appreciably until 2015 after which it roughly 'saturates' (and even somewhat declines). In parallel, the corresponding energy intensity reduces considerably, but this is overcompensated by economic growth.

140 The responsibilities are to be clearly distinguished. The FBP is responsible for its report; the CE2030 bears the responsibility of this current report. 141 Although matters are much more complicated because of continual feedback (and similar but different arguments could be used to opt for the presentation sequence by [FPB, 2006 - Sept]). 142 By carriers we mean electricity, heating oil, gasoline, diesel, gas, etc. Sometimes the words 'energy vector' is used as well. 143 It must be pointed out, however, that PRIMES computes the price of electricity on a cost+ base, and not according to the marginal cost, as would be the case in a liberalized market. See also [FPB, 2006 - Sept] and [CEU, 2003].


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Final Energy Demand; Total & per Sector

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Figure 6.1.a Baseline. Final energy demand; total and subdivided per sector (1 toe = 41.868 GJ = 11.63 MWh) [Primes, Nov 2005]


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Figure 6.1.b Baseline. Total final energy demand intensity (1 toe = 41.868 GJ = 11.63 MWh) [Primes, Nov 2005]

As is obvious from Figure 6.2, the tertiary sector continues to grow, as is the case with the transport sector (although the latter starts to level off as of 2020). The industrial sector seems to level off, but the decrease of energy-intensive industry versus the other industries, shown in Figure 6.3, is remarkable.


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Final Energy Demand per Sector

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Figure 6.2. Baseline. Final energy demand per sector; magnified version of Figure 6.1. (1 toe = 41.868 GJ = 11.63 MWh) [ PRIMES, Nov 2005]

Final Energy Demand; Industry

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Figure 6.3. Baseline. Final energy demand for industrial sector; split up between energy-intensive industry and other industries. (1 toe = 41.868 GJ = 11.63 MWh) [PRIMES, Nov 2005]

Table 6.1 shows the numbers involved for each of the sectors. The change in the two industrial types of sectors is indeed considerable.


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_______________________________________________________________________________

2000 2030 Increment 2000-2030

Mtoe share Mtoe share Mtoe %

Industry 13.8 37% 13.9 34% 0.1 1%

energy intensive 10.2 27% 8.8 22% -1.4 -14%

other indust sectors 3.6 10% 5.0 12% 1.4 39%

Residential 9.5 26% 10.0 24% 0.5 6%

Tertiary 4.2 11% 5.8 14% 1.6 39%

Transport * 9.7 26% 11.3 28% 1.6 17%

private cars 4.3 12% 4.0 10% -0.3 -7%

trucks 3.5 9% 4.9 12% 1.4 40%

Total 37.1 40.9 3.9 10% Source: PRIMES

* including also aviation, rail, inland navigation and public road transport Table 6.1. Evolution of the final energy demand in the baseline (per sector). Numbers do not exactly add up due to rounding off.

For 'transport' only two subcategories have been considered in this Table. (1 toe = 41.868 GJ = 11.63 MWh) Adapted from [FPB, 2006 - Sept]

Table 6.1 also shows the different evolution in passenger transport with private cars and freight transport by truck. This breakdown is also shown in Figure 6.4. Since 2005, private cars & motorcycles gradually decrease their consumption, whereas trucks and aviation increase their consumption considerably. Indeed, it turns out that according to PRIMES the car efficiency would improve substantially, from 40 toe/Mpkm in 2000 to 27 toe/Mpkm in 2030 (a decrease by about 1/3)

144, thereby

more than offsetting the increase in demand for transportation service.

Final Energy Demand; Transport

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FED_aviat ion

Figure 6.4. Baseline. Final energy demand for transport sector; split up between private cars, trucs and aviation (rail; public road transport and inland navigation not shown as being negligible). (1 toe = 41.868 GJ = 11.63 MWh) [PRIMES, Nov 2005]

144 This is caused mainly by the implementation of the ACEA agreement between the European Commission and the car manufacturers.


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Alternatively, Figure 6.5 shows the breakdown of the final energy demand per final-energy carrier. It is obvious that in this baseline, oil tends to decrease as of 2010, while electricity and gas (the latter as final energy for heating purposes) increase substantially. The heat from CHP is considered to be final energy, not the gas or the biomass delivered to the CHP user.

Final Energy Demand per energy carrier

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FED_heat CHP

FED_other (bio)

Figure 6.5. Baseline. Final energy demand per end-energy carrier. (1 toe = 41.868 GJ = 11.63 MWh) [PRIMES, Nov 2005]

Table 6.2 shows the numbers involved for each of the carriers. The expected increase in electricity is to be observed in particular.

2000 2030 Increment 2000-2030

Mtoe share Mtoe share Mtoe %

Solids 3.4 9% 1.9 5% -1.5 -43%

Oil 16 43% 16 39% ≈ 0 ≈ 0%

Nat. Gas 9.6 26% 11.3 28% 1.7 18%

Electricity 6.7 18% 9.1 22% 2.4 36%

Other 1.4 4% 2.6 6% 1.2 89%

Total 37.1 40.9 3.9 10% Source: PRIMES

'Other' includes heat and RES. Table 6.2. Evolution of the final-energy demand in the baseline (per carrier). Numbers do not exactly add up due to rounding off. (1 toe = 41.868 GJ = 11.63 MWh) Adapted from [FPB, 2006 - Sept]

Finally on energy demand, it is noteworthy to indicate the average annual growth percentages, considered over a decade. This is shown in Figure 6.6.


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Baseline

Average Annual Growth Rate of Final Energy Demand

-0.2

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Avera

ge g

row

th

[%]

1 = decade 1990-2000; 2 = decade 2000-2010 3 = decade 2010-2020; 4 = decade 2020-2030 Figure 6.6 Average annual growth rate of final energy demand (in [%]) averaged over a decade. [PRIMES, Nov 2005]

The decade 1990-2000 is the past, and was characterized by a substantial average growth rate of almost 2%/a, mainly because of very low fuel prices, and no effective climate-change related constraint yet. The growth over the next three decades for the Baseline is projected to slow down steadily from 0.8% p.a. to 0.3% p.a. and even -0.1% p.a., respectively, mainly due to the combination of higher fuel prices, structural changes in industry and saturation effects. It will be interesting to show how these growth percentages change in the alternative scenarios, when post-Kyoto constraints are imposed.


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6.1.2. Electricity Generation in the Baseline

6.1.2.1 Installed Generation Capacity in the Baseline According to the Baseline scenario, the installed power generation capacity in Belgium is supposed to increase from about 15 GW in 2000 to 23 GW in 2030. The split up in the various means to generate electricity is shown in the Figures 6.7 and 6.8. As is clear from the figures, nuclear power disappears, while installed gas capacity first increases (and then levels off because of the high gas prices). Coal-fired capacity starts to take off in 2020, since there is no post-Kyoto limit on CO2 emissions. In this Baseline scenario, wind-based generation capacity is projected to climb to 2.4 GW in 2030, while CHP signs up for 5.1 GWe. Biomass and Waste capacity amounts to 1.3 GW in 2030 and PV solar capacity is small in 2030 with altogether 209 MW, which needs some 1.4 km

2 of solar-cell area.

Installed Generation Capacity

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Figure 6.7. Baseline. Evolution of the installed electric power generation capacity in MW. [PRIMES, Nov 2005]

Installed Generation Capacity

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Figure 6.8. Baseline. Evolution of the installed electric power generation capacity in MW. Magnified version of Figure 8.7. [PRIMES, Nov 2005]


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6.1.2.2 Generated Electric Energy in the Baseline Installed capacity as discussed in the previous subsection gives the possibility to generate electric power during a certain period, depending on the marginal cost of the generation means. For classical generation technologies, it is effectively the fuel cost that determines the merit order, and thus the overall annual load factor of a particular unit. Intermittent renewable power technologies, such as wind and sun, have the advantage that their marginal cost is zero, but the disadvantage is that they are uncontrollable. Therefore, generating capacity is a measure for the rated (or effectively maximum) power that can be generated, but is not directly a good measure for the generated electric energy.

145

To set the mind, with the current fuel prices, typical 'effective number of operating hours' (ENOH)

146

are: - nuclear ± 7500 to 8000 h - coal ± 6000 to 7000 h - gas ± 4000 to 5000 h - wind ± 1600 to 2400 h - sun ± 800 to 1000 h. These numbers clearly depend on the relative fuel prices for nuclear, coal and gas, and on meteorological conditions for wind and sun. (The first three are typical orders of magnitude; not necessarily those obtained by PRIMES; the two last ones have been imposed.) The generated electric energy for the Baseline is shown in Figures 6.9 and 6.10. The strong leveling off of gas-fired electricity is due to a smaller ENOH in the later years due to higher gas prices. In terms of electric energy generated, the renewables wind and sun represent a much lower percentage of the total than in installed capacity. In 2030, renewables (without the biomass and waste fraction) produce about 6 TWh/a or thus a good 5%; including biomass and waste, they reach about 12%. A rough order of magnitude for further reference of generated electricity is 2000 2010 2020 2030 80TWh/a 90 TWh/a 100 TWh/a 110 TWh/a (exact 82.6) (exact 94) (exact 104.5) (exact 111.7)

Electric Energy Generated

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Figure 6.9. Baseline. Evolution of the electric energy generated in GWh. Sun PV is negligible on this scale. [PRIMES, Nov 2005]

145 Clear distinction is to be made between 'power' and 'energy'. Energy is power delivered during a particular duration. In simple terms, power is like the water running out of the faucet; energy is like the amount of water that has accumulated in the bathtub. 146 ENOH = the amount of energy produced (MWh) / the installed capacity (MW) =[h]. This is sometimes also called the 'full load equivalent' (FLE) hours.


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Electric Energy Generated

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Figure 6.10. Baseline. Evolution of the electric energy generated in GWh. Magnified version of Figure 8.9. Sun PV is negligible on this scale. [PRIMES, Nov 2005]

The amount of electric energy generated by CHP (including biomass) is expected to be 20.3 TWhe/a in 2030, with an amount of thermal energy produced equal to 19.1 TWhth/a, meaning that the E/Q ratio is roughly equal to 1 (a doubling compared to 2000; when it was about 1/2). As to the role of renewables, it must be observed that the results shown here include a considerable fraction of waste. The share of renewables & waste in the generation of electricity amounts to about 12% in 2030. It is reminded that in the baseline scenario no targets or objectives in terms of imposed percentages of renewables are included; only the effect of subsidy measures is included. The baseline includes the effect of subsidies such as green certificates or other. However, since PRIMES is not able to include the often complex subsidy mechanisms as such, an overall and guaranteed equivalent subsidy has been included in the investments in renewables. To bridge towards a next Section on CO2 emissions, we here give the CO2-related indices that characterize the electricity- (and steam) generation sector according to this Baseline exercise:

2000 2010 2020 2030 Carbon intensity (t CO2/GWh) 246 212 213 395 CO2 emission index (2000 = 100) 100 102 112 197

Table 6.3. Baseline. CO2 indicators for electricity generation. [FPB, 2006 - Sept]

Especially the dramatic increase between 2020 and 2030 is noticeable, nearly a doubling. This is due to the replacement of nuclear power by coal-fired units.


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6.1.3 Primary Energy Demand in the Baseline

The primary energy demand (also called Gross Inland Consumption, abbreviated GIC) follows from a combination of the fuel prices, the final energy demand and the energy conversion sector (especially the electricity sector). Its evolution is graphically summarized as shown in Figure 6.11.

Primary Energy Demand (GIC)

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Figure 6.11.a Baseline. Primary Energy Demand or, Gross Inland Consumption (1 toe = 41.868 GJ = 11.63 MWh) [PRIMES, Nov 2005]

Primary Energy Demand intensity

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Figure 6.11.b Baseline. Primary Energy Demand Intensity (1 toe = 41.868 GJ = 11.63 MWh) [PRIMES, Nov 2005]

Just like the final energy demand (FED), the primary energy demand (GIC) towards 2030 of Belgium seems to stabilize in this Baseline scenario, but the GIC shows a well noticeable decrease from 2015 onwards, leading to a decrease of about 0.5%/a between 2020 and 2030. (Recall from Figure 6.6 that the FED only decreased by a mere 0.1%/a over the last decade.) The decrease in the 'GIC total' after about 2015 is actually misleading due to an artificial (but nevertheless widely utilized) convention in the statistics. Indeed, primary energy from fossil sources, of nuclear origin, and coming from renewable 'streams' are all put under the same denominator. Because of the nuclear phase out as


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assumed in the Baseline, 'low-efficiency' primary conversion units (with efficiency of 33%) are replaced by 'more efficient' coal- and gas-fired units for electricity generation. For the renewables based on hydro, wind and solar origin, on the other hand, the real conversion efficiency is not retained

147, but a

straight conversion efficiency of 100%, i.e., 1TWhe = 0.086 Mtoe = 3.6 PJ, is assumed. For biomass, the actual conversion efficiency is utilized. As was the case for the Final Energy Demand, the GIC intensity shows a continuous decreasing trend (Figure 6.11.b), which means increasing efficiency, but which is to a large extent compensated by economic growth. Figure 6.11 shows the whole picture, and allows seeing the evolution of the primary share of each component compared to the total. To magnify these relative effects, Figure 6.12 shows the same figure as Figure 6.11, but now enlarged.


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Figure 6.12. Baseline. Primary Energy Demand (GIC) of the Baseline; magnified version of Figure 6.11 (1 toe = 41.868 GJ = 11.63 MWh) [PRIMES, Nov 2005]

Noteworthy is that oil is roughly steady, but starts to decrease slightly after 2010. The most eye-catching are the decline of nuclear (as imposed by the phase out), the gradual decline of coal until the nuclear phase out has occurred, after which it really takes off, and the steady rise of natural gas until about 2020, when coal takes over as a major electricity generation fuel. However, gas keeps its place as second in the overall primary energy demand. The share of renewables & waste in the GIC amounts to about 5% in 2030. A summary of energy-related figures of the baseline is given in Table 6.4. We have highlighted a few figures to draw attention.

147 For wind-energy conversion, an efficiency of about 40-45% applies (taking into account the Betz limit), while for PV, industrial overall efficiencies are of the order of 10-15%. For hydro power, ≥ 95% is reasonable.


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2000 2030

Share in

2030

10//00 (%)

20//10 (%)

30//20 (%)

Gross inland consumption (Mtoe) 57.2 55.4 100% 0.5 -0.3 -0.5

Solids 8.2 11.5 21% -2.5 -2.1 8.3

Oil 21.9 21.2 38% 0.6 -0.4 -0.5

Natural gas 13.4 19.5 35% 1.6 1.9 0.3

Nuclear 12.4 0.0 0 0.4 -3.6 -

Electricity (import) 0.4 0.3 1% 5.2 -3.2 -3.2

Renewable energy forms 0.9 2.9 5% 5.9 4.4 2.2

Primary energy intensity of the GDP (toe/M€’00)

230.6 128.4 -1.4 -2.3 -2.0

GIC/capita (toe/inhabitant) 5.6 5.0 0.2 -0.6 -0.7 Short term Import dependency (%) 77.7 95.3

Source: PRIMES

//: average annual growth rate Table 6.4. Primary-energy related indicators; adapted from [FPB, 2006 - Sept] (1 toe = 41.868 GJ = 11.63 MWh)

Table 6.4 shows in numbers what has been shown graphically in Figure 6.11.b: the primary energy intensity has declined considerably, mainly due to a rise in GDP (whilst primary-energy demand has remained roughly steady). Also noticeable is that the so-called 'short-term' import dependency (which considers nuclear primary energy as 'home grown')

148 increases substantially, with a close to 100%

dependency in 2030. Indeed, in this baseline scenario, the nuclear phase out is mainly compensated by gas and coal.

6.1.4 CO2 Emissions in the Baseline

Figures 6.13 and 6.14 show the evolution of CO2 emissions in the Baseline (in which, it is recalled, there is no post-Kyoto limit imposed). An obvious increase is observed from 2020 to 2030, due to a replacement of nuclear-generated electricity by coal-fired plants.

Energy-related CO2 emissions

0,0

20,0

40,0

60,0

80,0

100,0

120,0

140,0

160,0

2000 2005 2010 2015 2020 2025 2030

Year

CO

2 e

mis

sio

n [

Mto

n/a

]

CO2 emissions total

Electr sector

Industry

Residential

Tertiary

Transport

Energy branch

Figure 6.13. Baseline. Evolution of the energy-related CO2 emissions. [PRIMES, Nov 2005]

148 Short term means about one to two years; clearly, considered on the longer term, nuclear fuel needs to be imported as well.


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The amplified Figure 6.14 shows that the emissions from most sectors remain more or less steady, except the electricity-generation sector, while those from industry decrease to a 'reasonable extent'. All of this is clearly insufficient for a post-Kyoto policy, but the fact that none of them

149 (not even the

transport sector beyond 2010) increases, is encouraging. A major problem lies with the electricity generation sector, however. Indeed, in this Baseline scenario, the CO2 emissions remain effectively constant until about 2020, when the nuclear phase out takes effect and nuclear-based electricity generation is replaced by coal-fired generation.

Energy-related CO2 emissions

0,0

10,0

20,0

30,0

40,0

50,0

60,0

2000 2005 2010 2015 2020 2025 2030

Year

CO

2 e

mis

sio

n [

Mto

n/a

]

Electr sector

Industry

Residential

Tertiary

Transport

Energy branch

Figure 6.14. Baseline. Evolution of the energy-related CO2 emissions. Magnified version of Figure 6.13. [PRIMES, Nov 2005]

Compared to 1990 levels (the Kyoto-reference year), the increase until 2030 is shown in the following graph (Figure 6.15) [FPB, 2006 - Sept].

-10

-5

0

5

10

15

20

25

30

35

2000 2010 2020 2030

Mt of C

O2

supply side industry and buildings transport total

Source: PRIMES

Supply side = power and steam sector + other energy transformation sectors

Figure 6.15 Baseline. Changes in energy-related CO2 emissions compared to 1990 levels. [FPB, 2006 - Sept]

149 Disregarding the electricity sector, clearly.


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Informative Box: Impact of lower transport activity on energy consumption and energy- related CO2 emissions of the transport sector The impact of alternative assumptions regarding the evolution of transport activity on energy and emissions is evaluated and contrasted to the Baseline. Alternative evolution of transport activity The alternative assumptions are based on the “Extended scenario” of the European ASSESS study based on the SCENES transport network model. This scenario assumes a lower evolution of total passenger and freight transport activity as well as different allocations among transport modes as a result of the implementation of a package of measures. This scenario was used as input to the post-2012 scenarios with additional measures in the recent climate study for Minister Tobback [FPB, 2006 - July]. It is referred to in the following as the “lower evolution” scenario. Figure 1 shows the differences between the baseline evolution of transport activity and the evolution according to alternative assumptions.

0

25

50

75

100

125

150

175

200

2000 2010 2020 2030

Gp

km

/Gtk

m

Passenger : baseline evolution Passenger: low er evolution

Freight : baseline evolution Freight: low er evolution

Figure 1: Transport activity according to the scenario

Impact on energy consumption and CO2 emissions of transport Figure 2 illustrates the impact on energy consumption and CO2 emissions in the transport sector.

2000

4000

6000

8000

10000

12000

14000

16000

2000 2010 2020 2030

kto

e

0

5

10

15

20

25

30

35

Mt

of

CO

2

Energy cons: baseline Energy cons: low er evol. transp. act.

CO2 em: baseline CO2 em: low er evol. transp. act.

Figure 2: Impact on energy and CO2 emissions

Source: Based on information provided by the FPB.


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6.1.5 Baseline; Closure The present baseline scenario is clearly not 'sustainable' because the CO2 emissions increase quite considerably, especially after 2020. Recall that no CO2-reduction targets were set for this baseline. As a matter of fact, in the baseline, no targets whatsoever have been set. Only the decided measures up till 01.01.2005 have been taken into account. From the baseline, it can be figured out whether the targets projected by policy makers did materialize. It turns out that even with the subsidies for renewables in place, there was only a limited growth in green energy. In contrast, because of the relatively high fuel prices and the strain put on the system because of the nuclear phase out, energy savings already led to a substantial decrease in energy intensity of some 2% per year, thereby more or less compensating the economic growth. Final energy demand therefore remained roughly constant. Sustainability calls for alternative scenarios, where a substantial post-Kyoto constraint is the major driver because Climate Change is considered as the major challenge to tackle. As will be seen from the results, the post-Kyoto pressure automatically leads to extra pressure on energy savings, and renewable energy in particular. A more in depth analysis than what has been possible in this report can be found in [FPB, 2006 - Sept]. Also, in Annex D of that Supporting Document, further detailed numbers on the baseline have been provided.

6.2 Soaring Fuel Prices-Affected Baseline-Type Scenario — Results As explained before, the 'soaring' fuel-prices-scenario is a variant in which the oil and gas prices (the latter being linked to the former) skyrocket to about 100 $'05/bbl in 2030. As to the reaction of the energy system, the effect is the same as if there would be an energy import tax levied on oil and gas (perhaps as part of a European energy tax) with the intention to improve security of supply and to force the system to decrease consumption and/or to utilize other (less expensive, more secure as regards supply and better storable) primary energy sources. The differences in Primary Energy Consumption (or Gross Inland Consumption, GIC) and Final Energy Demand (FED) with the Baseline are shown in Figure 6.16.


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Baseline vs Soaring Price

GIC & FED Comparison

33000

38000

43000

48000

53000

58000

63000

2000 2005 2010 2015 2020 2025 2030

Year

GIC

&

F

ED

[k

toe/a

]

GIC_tot BL

FED_tot BL

GIC_tot Soar BL

FED_tot Soar BL

Figure 6.16. Comparison GIC and FED of the Baseline and the scenario with 'soaring' fuel prices. (1 toe = 41.868 GJ = 11.63 MWh) [PRIMES, Nov 2005]

First of all, the higher fuel prices lead to a decrease in final energy demand, at a rate shown in Figure 6.17 as compared to the Baseline. Clearly, the higher fuel prices have a mitigating effect on growth of final energy demand.

Soaring Prices

Average Annual Growth Rate Final Energy Demand

-0,5

0

0,5

1

1,5

2

1 2 3 4

Decade

Avera

ge g

row

th

[%]

Baseline Soaring Prices

1 = decade 1990-2000; 2 = decade 2000-2010 3 = decade 2010-2020; 4 = decade 2020-2030 Figure 6.17. Average annual growth rate (in [%]) averaged over a decade. Comparison of Baseline with 'soaring fuel price' scenario. [PRIMES, Nov 2005]


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Table 6.6 shows the impact on the different sectors. Mainly industry and residential & tertiary sectors react to this fuel-price increase, especially for oil and gas. The transport sector remains nearly untouched because of the high excise taxes already existing.

150

Reduction with respect to Baseline gas oil electricity total industry -4% -18% +1% -2% residential, services & agriculture -6% -12% ≈ 0 -6% transport -0.5% -0.5% total -5% -6% ≈ 0 -3%

Table 6.6. Comparison FED in sectors and carriers of Baseline versus 'soaring‘ prices. Only rounded-off figures have been shown.[ PRIMES, Nov 2005]

Electricity use increases in industry, because a shift in primary fuel also takes place in the electricity sector, where gas is replaced by coal

151. Relatively speaking, electricity becomes a bit cheaper than

the other carriers, leading to an increase in electricity consumption. Figure 6.18 shows the dominant changes taking place in the electricity sector, whereas Figure 6.19 shows how the changed final energy demand and fuel mix in the electricity sector translate into a changed primary energy basket.

Baseline vs Soaring Price

Electricity Generation Nat Gas & Coal

0

10000

20000

30000

40000

50000

60000

70000

2005 2010 2015 2020 2025 2030

Year

Ele

ctr

icit

y G

en

era

tio

n [

GW

h/a

]

Nat Gas BL

Nat Gas Soar BL

Coal BL

Coal Soar BL

Figure 6.18. Changes in natural gas-fired and coal-fired electricity generation; comparison of the Baseline and the scenario with 'soaring' fuel prices. [PRIMES, Nov 2005]

150 Meaning that the change in price at the pump is relatively minor when the primary oil becomes more expensive. 151 Recall that in both scenarios, the nuclear phase out is implemented, leaving mainly gas- and coal-fired electricity generating units from 2020-2025 on.


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Baseline vs Soaring Prices

GIC for oil, gas and coal

0

2500

5000

7500

10000

12500

15000

17500

20000

22500

25000

2000 2005 2010 2015 2020 2025 2030

Year

GIC

[k

toe

/a]

GIC_oil BL

GIC_oil Soar BL

GIC_gas BL

GIC_gas Soar BL

GIC_coal BL

GIC_coal Soar BL

Figure 6.19. Comparison in the composition of the primary energy basket (GIC); comparison of the Baseline and the scenario with 'soaring' fuel prices. (1 toe = 41.868 GJ = 11.63 MWh) [ PRIMES, Nov 2005]

Finally, the energy-related CO2 emissions evolve as shown in Figure 6.20. The fact that the CO2 emission is effectively the same in 2030, is a consequence of the decrease in final energy demand being overshadowed by the fuel switch to coal as a consequence of the nuclear phase out and the expensive gas prices, from 2020 on.

CO2 Emissions

100.0

110.0

120.0

130.0

140.0

150.0

2005 2010 2015 2020 2025 2030

Year

CO

2 e

mis

sio

n

[M

ton

/a]

CO2_tot BL

CO2_tot Soar BL

Figure 6.20. Comparison of the energy-related CO2 emissions between the Baseline and the scenario with 'soaring' fuel prices. [PRIMES, Nov 2005]

More information on the 'soaring' fuel-price scenario, is available in [FPB, 2006 - Sept].


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6.3 Alternative Scenarios; Results

6.3.1 Results of Domestic Energy-Related CO2 Reduction Scenarios

6.3.1.1 The Scenarios Revisited in a Nutshell For convenience, we recall the eight alternative scenarios as defined earlier in Section 5.3.4.2.b and summarized in Section 5.3.5.

Summary of alternative scenarios for domestic reduction of energy-related CO2

Bpk15: reduction of energy-related CO2 emissions by 15% in 2030 compared to 1990; nuclear phase out; CCS allowed

Bpk15n: reduction of energy-related CO2 emissions by 15% in 2030 compared to 1990; nuclear allowed; CCS allowed

Bpk15s: reduction of energy-related CO2 emissions by 15% in 2030 compared to 1990; nuclear phase out; CCS not allowed

Bpk15ns: reduction of energy-related CO2 emissions by 15% in 2030 compared to 1990; nuclear allowed; CCS not allowed

Bpk30: reduction of energy-related CO2 emissions by 30% in 2030 compared to 1990; nuclear phase out; CCS allowed

Bpk30n: reduction of energy-related CO2 emissions by 30% in 2030 compared to 1990; nuclear allowed; CCS allowed

Bpk30s: reduction of energy-related CO2 emissions by 30% in 2030 compared to 1990; nuclear phase out; CCS not allowed

Bpk30ns: reduction of energy-related CO2 emissions by 30% in 2030 compared to 1990; nuclear allowed; CCS not allowed

The idea behind the domestic alternative scenarios is to find out how the Belgian energy system would react to post-Kyoto emission-reduction limits for energy-related CO2. The Commission 2030 does not suggest one limit or the other, but by choosing these domestic CO2 scenarios, it assumes that the reduction limit imposed upon Belgium might lie somewhere between the two 'simple' limits chosen: a 15% and 30% domestic reduction of energy-related CO2 compared to the level of 1990.

152

As will be recalled from the scenario definition (and in contrast to the baseline), now there is a particular target set that the model had to satisfy, namely a stringent reduction of energy-related CO2 by 2030. No further or new measures than those in the baseline are enforced. The CO2 constraint will put pressure on the system to effectuate considerable energy savings and to lead to a breakthrough for renewable build up. In these alternative scenarios, there are no imposed quota for renewable energies and energy savings; these technologies are put on the same level as other technologies to satisfy the expected and very stringent post-Kyoto target reductions in the different scenarios. As will be seen from the results, the CO2-reduction target strongly increases the contribution from renewables leading to roughly the same (and in this way justified) effect of imposing quota in real life. Given such post-Kyoto reductions, it is then the aim to find out what is the influence of imposing or relaxing different 'constraints' on the system, on the distribution of the CO2 emissions in the different sectors of the Belgian economy, and what might be the orders of magnitude of the costs involved. In what follows, very often a comparison with the Baseline is (to be) made; hence it is at all times important to understand how the Baseline has been constructed and to keep in mind what its results are. As a reminder, the Baseline is effectively a 'post-Kyoto unconstrained case', with the nuclear phase out implemented as foreseen in the law of January 2003.

153

152 The relationship with the other GHG and the (probably formally surviving) post-Kyoto Flexible Mechanisms has been addressed in Chapter 5. 153

And without pre-specified quota or targets, but with a subsidy for renewables.


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It is important to focus on the most salient and pertinent features/characteristics of this analysis. We will therefore point to a few 'eye-catching aspects' that the reader should keep in mind towards the conclusions of this report. An interpretation beyond the bare numbers will moreover be undertaken in a later part of this report, as a 'reality check', 'common-sense test' or a 'coming to grips with the challenges'. In a sense, the post-Kyoto constraint will dominate the scenarios. Two other 'parameters' will turn out to have significant effects as to how the post-Kyoto limits are to be satisfied. First, there is the availability or not of the technology & implementation of CO2 capture and storage. Although there is reason to believe that this CO2-mitigating option might lead to some temporary breathing space in some decades from now, it is by no means certain ([Van Tongeren, 2004; Piessens et al., 2007; Pamplona & Mathieu, 2002; IEA, 2004d, 2006d, 2006e; IPCC, 2005]) that this option will be fully routinely commercially/operationally available in Belgium by 2025. Especially the storage part seems to be uncertain on this 'short' time scale.

154 That option might be fully available in the period

some time beyond 2030, but perhaps not much earlier than that.155

The precautious attitude is therefore not to rely on this option as a certitude, but to consider it as a 'welcome possibility' if it would become available in time.

156 157

The second dominant 'parameter' is the nuclear phase out in Belgium. As legal matters stand now, the phase out will be implemented, unless the 'force-majeure' clause of Article 8 is invoked by Royal Decree, or if the law were to be changed by Parliament.

158 To see the impact of the phase-out

decision on the energy system, the phase-out constraint is relaxed (i.e., withdrawn) in some scenarios. To be able to concentrate on the difficulties imposed on the energy system, a study of the non-nuclear scenarios should therefore be the prime focus of the interpretation exercise. Consequently, the reader is advised to first concentrate on the -15% & -30% post-Kyoto, non-nuclear, non-CCS scenarios. The numbers produced by those scenarios should give indications of the degree of challenge —or even (non-)realism— of such combination of constraints. The other alternative scenarios provide then hints/options on how post-Kyoto might be reachable with less stringent requirements. In this regard, it should be kept in mind, however, that the CCS option is not in our own hands, since it is impossible to foresee its breakthrough; whereas the nuclear phase-out law is the result of our own decisions, and is not irreversible (at this stage).

6.3.1.2. Abatement Cost to Reach Post-Kyoto Reductions

Before launching into the bulk of the results, it is instructive to first focus on some technicalities used by the PRIMES model to satisfy the prescribed pot-Kyoto constraints. To reach a certain post-Kyoto reduction limit, PRIMES introduces a 'carbon value', being a measure for the marginal cost (cost of the last ton CO2 reduced) to reduce CO2 emissions. On the energy system, this carbon value acts similarly to a CO2 tax, in the sense that the system will reduce its emissions until the marginal abatement costs (which are increasing functions of increasing emission reduction and generally differ from sector to sector) are equal to the carbon value.

159 The

system searches for a particular carbon value, commensurate with the imposed CO2 reduction. Note that this carbon value is different from an actual CO2 tax, however, in that money is not necessarily collected by the government. It is perhaps more appropriate to consider it as the equilibrium market value of 'emission allowances' if such a system had been made obligatory for all sectors. In any case,

154 A distinction needs to be made between theoretical 'guestimates' for storage possibility and actual full-fledged storage implementation (with careful considerations of the sealing aspects, safety, timely construction & operating permits, etc). 155 At a later stage, we will consider what Belgium might do to help accelerate successful operation of CCS in Belgium. 156 Recall, however, that investment decisions for power plants and other major facilities need to be taken well ahead of time, whereby the time lapse between 'first intentions' and 'contract signing & actual ordering' (and thus having obtained all permits) of constructing a major facility might be between 5-10 years and often longer. 157 Based on estimated evolution of investment & operational costs for CCS, PRIMES will 'seek refuge' in this technology to cope with the post-Kyoto constraints. PRIMES, however, does not take into account the specific Belgian situation of storage. These issues are further addressed below, in Part III. 158 This clause, related to security of supply, will be focused on below in Part III. 159 See our discussion in Section 3.2.1. on External Costs, including marginal abatement costs and emission taxes.


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this carbon-value parameter reflects the marginal cost of CO2 emission reduction, and thus the degree of difficulty or ease of achieving a particular post-Kyoto constraint (which would limit the number of emission allowances allocated to the energy system). The average cost per ton reduced is lower than the marginal cost, however.

160

Figures 6.21a and 6.21b show the carbon values for the post-Kyoto limits of -15% and -30%, respectively. Note that the vertical scale is different in both cases. As a first remark, it must be noticed that the scenarios no nuclear & no CCS (represented by the yellow bars in the figures; under numbers 3 and 7) turn out to be the extremely 'demanding' in terms of carbon value. The -15% case comes up with a carbon value

161 of roughly 520 €/ton CO2 (in terms of

barrel-of-oil cost, this would be comparable with an equivalent energy-price increase at the marginal unit of ~ 200 $/bbl), whereas the -30% case demands a carbon cost of more than 2100 €/ton CO2 (comparable with an equivalent energy-price increase at the marginal unit of ~ 830 $/bbl).

Carbon value Post-Kyoto -15%

0

100

200

300

400

500

600

1 2 3 4

Scenarios -15%

CO

2 v

alu

e

[EU

R/t

on

CO

2]

no nuc; with CCS

nuc allowed; with CCS

no nuc; no CCS

nuc allowed; no CCS

1 = Bpk15; 2 = Bpk15n; 3 = Bpk15s; 4 = Bpk15ns Figure 6.21a. Carbon values for the post-Kyoto -15% scenarios. Adapted from [FPB, 2006 - Sept]

160 See also Sections 3.2.2.2, 5.2.2 and 5.3.4.2a for further relevant material on this issue. 161 This is thus the equi-marginal abatement cost at which the system settles.


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Carbon value Post-Kyoto -30%

0

500

1000

1500

2000

2500

5 6 7 8

Scenarios -30%

CO

2 v

alu

e [E

UR

/to

n C

O2]

no nuc; w ith CCS

nuc allow ed; w ith CCS

no nuc; no CCS

nuc allow ed; no CCS

5 = Bpk30; 6 = Bpk30n; 7 = Bpk30s; 8 = Bpk30ns Figure 6.21b. Carbon values for the post-Kyoto -15% scenarios. Adapted from [FPB, 2006 - Sept]

As a second observation, the carbon values increase non linearly with the required reduction: a doubling of the reduction constraint from -15% to -30% leads to a 3 to 4 fold increase of the carbon value. This is in agreement with steeply increasing marginal abatement costs, with increasing reductions. Third, relaxing the nuclear phase-out constraint, while still not relying on the CCS option (nrs 4 and 8 in Figures 6.21a and 6.21b, respectively), would already substantially alleviate the pressure on the Belgian energy system. Carbon values would reduce by a factor 4 to 5. As a final observation, we see that routine commercial CCS availability would help considerably to reduce CO2 emission abatement costs. The combination of CCS with a nuclear continuation (nrs 2 and 6) would lead to moderate efforts for CO2 abatement. The above suggests also that the options in the electricity sector will largely influence the CO2 abatement efforts in the other sectors. That this is indeed the case will be demonstrated below in the Section on cost consequences. The marginal abatement cost for CO2 reduction, here called the carbon value, is an indication of the effort to reduce energy-related CO2 emissions in Belgium. Some comments are in order though. As will be recalled, our post-Kyoto limits refer to domestic reduction of energy-related CO2 emissions. The non-CO2 GHG have not been considered, nor have we allowed usage of ('international exchange') flexible mechanisms such as 'Joint Implementation', 'Clean Development Mechanism' or 'Emission Trading Schemes'. As has been explained before in Chapters 3 and 5, a too stringent situation in Belgium (i.e., through an enforced nuclear phase out and the non-availability of fully commercial CCS by 2030), and as has just been shown, will lead to extreme costs for domestic CO2 abatement. This will certainly give rise to a refuge reaction via the use of flexible mechanisms, effectively meaning that Belgium will finance emission reductions abroad. This EU-wide approach will be dealt with in the EU-based scenarios to be discussed below. It will then be part of the evaluation to check what is best for the country: cheap domestic reductions with domestic constraints such as a nuclear phase out relaxed, or paying for more expensive reductions abroad, if such domestic constraints are enforced. In any case, the scenarios here allow getting an idea what kind of effort domestic CO2 reductions in the order of 15% and 30% require.


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The burden on the Belgian economy might be alleviated if the carbon value were an effective tax, or if the (fictitious domestic) emission allowances would have been auctioned.

162 In this way, the

government receives revenues, which it could then re-inject into the Belgian economy, e.g., by reducing social-security charges on labor. However, it must be stressed here that such economy-interaction effect with re-injection of the revenues is possible only if taxes or auctioning are implemented. Otherwise that is not the case. Furthermore, the issue is not as simple as it looks like. The choice of instruments is a complex issue, however, because in an economy with other taxes, one needs to take into account the interactions of the externality taxes (i.e., CO2 or GHG taxes or allowance revenues) with the remainder of the economic system. This has three important implications:

1) re-injecting the revenues into the economy is only relevant if there are important labor and other (distorting) taxes; 2) but if there are important labor and other taxes (which is effectively the case), the cost to the economy of any environmental improvement is higher than presented in a partial equilibrium model like PRIMES, even if the revenues are recycled; 3) so it is risky to state that costs become lower because of re-injection of revenues, but this is only part of the story.

Figure 6.22 illustrates these points qualitatively.

Abatement Cost with and without Revenue Recycling

GHG emission reduction [ton]

(arbitrary units)

MA

C [€

/to

n]

(a

rbit

rary

un

its

)

Cost economy after recycling

PRIMES cost

Cost economy with (labor) taxesand without recycling

Emission reduction quotum

Figure 6.22. Qualitative explanation of the effect of re-injecting external tax revenues into the economy to offset other taxes.

The curves indicated in Figure 6.22 are marginal abatement cost curves to reduce e.g., CO2 emissions. The black vertical line indicates the reduction limit set. The pink curve indicates the marginal abatement cost to the energy system as computed by an equilibrium model like PRIMES. Because of other (distorting) taxes in the economy, such as labor and capital taxes, the abatement cost to the overall Belgian economy is considerably higher than the cost for the energy system as computed by PRIMES. By re-injecting externality revenues into the economy to offset some of the distorting taxes, the overall cost to the economy is reduced, as indicated by the blue curve. However, the cost to the economy is still higher than the abatement cost to the energy system as found by PRIMES.

162 In these domestic PRIMES scenarios, no international emission trading is taken into account; but the carbon value can be considered as the CO2 allowance price for domestic emission trading.


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Taking into account that higher abatement costs should result in a lower domestic reduction target, the above can be rephrased as follows:

a) if there are revenues from carbon taxes, then it best is to use these for a reduction of the most distorting taxes in the economy (labor taxes and sometimes capital taxes); b) in order to be able to ‘recycle’, preference must be given to an instrument that generates revenues, so emission taxes or auctioned tradable permits are preferred to grandfathered emission permits; c) but even when externality tax revenues are used for a reduction of labor taxes, the overall cost for the whole economy of emission reduction increases and this means that it is economically optimal to reduce the domestic reduction objective as a consequence of a vertical shift of the Marginal Abatement Cost curve (MAC curve).

163 For a given objective in terms of emission

reduction responsibility for Belgium, financing of reductions abroad is then more appropriate. In summary, the recycling of external tax revenues may lead to an overall reduction of the cost for the whole economy. However, unless all distorting taxes in the economy are done away with, the cost to the overall economy will be higher than the energy system cost as projected by models like PRIMES. But, it may be more efficient for the economy to effectuate a simple tax reform without considering energy taxes. In any case, a full-scale analysis, taking into account all kinds of distorting taxes, is required before drawing definitive conclusions. The issue of revenue recycling is still controversial, as can also be seen from the Informative Box.

Informative Box: Recycling environmental tax revenues and the double dividend Revenues from environmental taxes can be used to lower distortionary taxes such as existing taxes on labor and capital. ‘Distortionary’ taxes by definition distort economic decisions. In the case of labor taxes, the choice between working time and leisure time is influenced and higher taxes lead to a lower supply of labor and hence to a lower level of economic activity. Similarly, lower labor taxes will stimulate the supply of labor. From a neo-classical perspective, a higher net-wage (per hour) will trigger a higher supply of labor i.e. the (uncompensated) wage elasticity of labor supply is positive. Empirical overviews confirm that the elasticity of labor supply is positive in European economies (Evers et al., 2005). These findings suggest that increasing net-wages by lowering labor taxes will increase aggregated labor supply and hence economic activity. As a result, a double dividend consisting of lower remaining externalities and a higher level of economic activity can be reached. This presentation covers however only part of the story and neglects that stringent conditions need to be met in order for a tax reform to yield a double dividend (Bovenberg, 1999). To illustrate this, we make use of the stylized presentation by Bovenberg and De Mooij (1994) where; w = h*(1-tL)/p (1), with w as net-wage or after-tax wage with h as gross-wage or before-tax wage (h equals labor productivity) with tL as the labor tax rate with p as the general price level in the economy In equation (1), employers will pay a gross-wage per hour that in equilibrium equals the productivity per hour. The gross-wage is taxed and the rational individual is furthermore aware of the purchase power consequences from inflation; he/she knows that the purchasing power of a fixed net-wage is negatively impacted when the general price levels rise. A higher p in (1) will lower the purchasing power from an unchanged net-wage. Hence, the inflationary consequences from the imposition of environmental taxes such as CO2 taxes will lower the supply of labor and hence economic activity. A first conclusion is that the economic cost of environmental taxes always exceeds the total abatement costs over all sectors of emissions. In addition to the interactions in (1), new environmental taxes can lower the profitability of capital in energy-intensive environments and this can lead to capital reallocations. Especially in capital-intensive economies, the burden of environmental taxes can fall predominantly on capital. Although equation (1) is a very simplified presentation of reality, a lower level of economic activity due to environmental taxes can even confront the regulator with a shrinking tax base.

163 More generally speaking, and with reference to Figure 3.1, a higher abatement cost may suggest to reduce the overall environmental quality limit, e.g., on a European scale.


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Fortunately, the environmental tax revenues can be recycled back into the economy by lowering existing labor taxes, tL in equation (1). So when we focus solely on equation (1), the green tax reform will lead to a higher net-wage and hence a higher supply of labor on condition that the lowering of labor taxes has a stronger impact on w than has the increase of the general price level. Lower labor taxes however risk to insufficiently compensate capital owners for their efficiency losses, so the total economic impact of the green tax reform can still be negative under the scenario of full tax revenue recycling. In reality, full tax revenue recycling is highly unlikely due to transaction costs involved with tax collection and recycling institutions. To conclude; a double dividend is a possibility, not a certainty. Finally, the specific format of the reduction of labor taxes is of crucial importance. When social contribution paid by employers are lowered, the impact on net-wage will depend on the existence and nature of the collective agreements, as well as on the power balances between workers and employers with respect to translating lower social charges into higher wages. Lowering social contributions by workers and income taxes can have a more direct impact on observed net-wages and the supply of labor. Given the existence of problematic unemployment and activity traps in rich welfare states – implying that leaving unemployment support schemes leads to lower net-incomes – the labor tax reform should especially focus on the lower income groups. Further reading: Evers, M., de Mooij, R. and Van Vuuren, D. (2005). What explains the variation in estimates of labor supply elasticities? CESifo Working Paper No.1633 (www.CESifo-group.de) Bovenberg, A.L. (1999). Green tax reforms and the double dividend: an updated reader’s guide. International Tax and Public Finance 6, 421-443 Bovenberg, A.L., and de Mooij, R. (1994). Environmental levies and distortionary taxation. American Economic Review 84(4), 1085-1089

In any case, the carbon value, whether implemented as a tax (in which case it appears as a cost for those affected), or as the result of emission allowances (in which case they appear as property rights with an opportunity cost, regardless of whether they were grandfathered or auctioned) will be charged through the prices of electricity, heat and wholesale & consumer products. As this may seriously affect our international competitiveness (unless appropriate accompanying measures such as decreases of labor charges are taken), care should be taken with these amounts of carbon values, demanding for in-depth analyses on competitiveness and some European and even worldwide harmonization of measures if one wants to avoid massive carbon leakage. Carbon leakage stands here for two phenomena. First, there is the transfer of CO2-intensive productions abroad (to non post-Kyoto signatories) that will then be imported, resulting in worldwide sometimes higher CO2 emissions. Second, prices of oil may decrease when more efforts are made to save oil in some parts of the world, leading to an increase in consumption in other parts of the world.

6.3.1.3 Summary of Results Compared to the Baseline

Some of the most relevant results of the alternative scenarios for domestic energy-related CO2 reduction for the year 2030 have been summarized in Tables 6.7 and 6.8. The former shows the relative differences with the Baseline; the latter gives absolute figures or relative shares. The reader is invited to carefully look at the results of these tables. The most stringent scenarios, i.e., no nuclear & no CCS, have been highlighted. In the following sections, we will zoom in on some of the results presented in these tables, whilst taking into account the evolution towards 2030. As before, the logic of the discussion will be to start with addressing final energy demand, which is expected to react first to the post-Kyoto requirements. This FED will be shown, both in amount, and for all carriers and sectors. This already takes into account fuel or carrier switches, based on the relative price and the carbon value and content. Then we zoom in on how the electricity sector adapts itself to the circumstances, after which we are ready to make the balance for the primary energy consumption (or gross inland consumption). Next we tackle the issue of CO2-emission distribution over the different sectors. To finish this chapter with a section on the energy-related cost involved in the different sectors.


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As mentioned before, a more detailed systematic comparative analysis than is given here is provided in [FPB, 2006 - Sept]


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. Year 2030; % compared to Baseline

Bpk15 Bpk15n Bpk15s Bpk15ns Bpk30 Bpk30n Bpk30s Bpk30ns

Gross inland consumption (GIC)

Supply of biomass 16.9 2.4 22.4 11.7 23.9 10.3 20.3 22.2

Natural gas imports 6.9 -9.3 9.7 -10.8 6.5 -13.5 -2.4 -22.1

Prim energy intensity of GDP -5.4 8.7 -19.6 6.7 -9.3 5.5 -29.2 -2.3

Final energy demand

Final energy demand / tot -7.6 -2.6 -19.3 -5.3 -14.2 -9.1 -31.9 -17.3

Industry

Energy consumption -10.0 -5.3 -20.9 -8.6 -16.7 -12.3 -29.7 -19.4

CO2 emissions -24.6 -18.8 -45.5 -27.0 -45.4 -40.6 -58.7 -51.0

Energy related costs/toe 46.1 10.4 99.3 18.8 89.3 40.0 334.8 76.7

Residential


CO2 emissions -1.0 -7.6 -34.2 -12.8 -25.0 -19.1 -54.7 -37.0


Tertiary


CO2 emissions -9.9 -4.9 -27.6 -8.2 -20.2 -13.7 -46.3 -28.0


Transport

Energy consumption -2.3 0.4 -12.7 -1.7 -7.1 -5.0 -26.2 -12.0

CO2 emissions -2.2 0.5 -12.9 -1.7 -7.3 -5.0 -26.7 -12.3

Solids -51.4 -36.1 -80.4 -52.3 -76.0 -67.6 -89.4 -82.9

Oil -7.7 -4.3 -22.7 -7.9 -16.4 -12.8 -37.4 -22.7

Gas -6.2 -4.1 -22.7 -7.2 -19.6 -15.5 -42.3 -28.1

Electricity -0.5 9.9 -0.6 12.4 4.5 14.6 -5.1 15.9

Heat -16.6 -9.3 -22.5 -13.7 -22.6 -18.7 -33.0 -25.4

Other 12.1 1.5 28.5 1.3 47.2 37.7 44.0 30.2

Electricity production

Electricity generation 0.2 9.6 -2.5 11.8 5.8 15.1 -7.4 15.0

Use of biomass 16.4 -4.5 15.2 15.0 5.6 -19.1 3.6 13.3

Installed power capacity 11.0 19.7 30.4 21.4 24.3 26.2 40.7 38.8

CO2 emissions -76.2 -82.9 -48.4 -75.5 -87.6 -93.9 -64.5 -75.7

Average poduction costs 43.6 -14.5 20.4 -17.3 64.6 1.0 86.0 -9.5 Table 6.7. Summary of results of the alternative scenarios. Relative comparison to baseline in 2030. Collated from [FPB, 2006 - Sept]


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Table 6.8. Summary of results of the alternative scenarios. Absolute figures and relative shares in 2030. Collated from [FPB, 2006 - Sept].

Year 2030; Other key results

Bpk15 Bpk15n Bpk15s Bpk15ns Bpk30 Bpk30n Bpk30s Bpk30ns Baseline

Structure of GIC (%)

Coal 13.9 3.0 1.7 2.5 12.5 3.1 0.8 1.3 20.8

Oil 38.0 33.6 39.0 33.1 36.8 32.6 37.1 31.4 38.6

Natural gas 39.9 29.5 48.3 29.5 41.5 29.0 48.8 28.2 35.3

Nuclear 0.0 27.4 0.0 27.9 0.0 28.2 0.0 30.5 0.0

RES 8.2 6.5 11.0 7.0 9.2 7.1 13.3 8.7 5.3

Biomass supply (PJ) 112 98 117 107 119 106 115 117 96

Short term import dependency (%) 92.8 69.6 90.5 68.7 91.9 68.4 88.7 65.3 95.3

Structure of elec. generation (%)

Nuclear 0.0 51.9 0.0 50.9 0.0 49.4 0.0 49.5 0.0

Fossil fuels 77.3 28.6 71.7 28.8 77.3 32.7 67.2 28.2 88.2

RES 22.7 19.5 28.3 20.3 22.7 17.9 32.8 22.3 11.8

Wind 15.0 13.5 15.4 13.4 14.1 13.0 16.2 13.0 5.0

Biomass 7.3 5.5 7.4 6.5 6.3 4.4 7.0 6.2 6.3

Solar PV 0.05 0.05 5.1 0.04 1.9 0.04 9.0 2.7 0.05

Hydro 0.41 0.41 0.42 0.37 0.39 0.35 0.44 0.36 0.41 Net CO

2 emissions in

power sector (Mt) 12.4 8.9 27.0 12.8 6.5 3.2 18.6 12.7 52.4

CO2 emissions captured (Mt) 31.7 4.0 0.0 0.0 39.7 14.6 0.0 0.0 0.0

% of electricity from CHP 14.3 16.3 14.5 15.0 12.8 9.6 14.1 12.4 18.2

Installed power capacity (MW) 25524 27539 29998 27912 28592 29029 32367 31913 22999

Nuclear 0 7775 0 7775 0 7775 0 7775 0

Wind onshore 2045 1976 2058 2045 2049 2045 2049 2049 1388

Wind offshore 3800 3791 3800 3800 3800 3800 3800 3800 1019

Solar PV 209 209 5903 209 2477 209 9880 3792 209

Biomass 1568 1413 1631 1575 1587 1345 1570 1518 1310

Coal fired 3940 0 0 0 3706 837 0 0 7054

Gas fired 12142 11704 12562 11834 12434 11823 11844 11992 11240

Structure of transport consumption (%)

Gasol. & diesel 73.5 73.1 75.7 73.4 74.8 73.9 79.2 75.5 72.1

Biofuels 6.4 6.4 6.6 6.4 6.5 6.4 6.8 6.5 6.3

Kerosene 17.5 17.9 15.0 17.5 15.9 17.0 11.1 15.1 18.8

Electricity 1.0 1.0 1.2 1.1 1.1 1.1 1.3 1.24 1.0

Other 1.5 1.5 1.5 1.6 1.6 1.6 1.5 1.5 1.7

Structure of residential cons. (%)

Fossil oil 25.7 26.3 20.7 25.1 22.7 23.7 15.9 19.6 28.1

Natural gas 41.7 39.8 38.7 39.3 40.4 38.8 34.6 35.6 41.1

Electricity 30.1 31.7 37.0 33.3 33.8 34.8 43.6 41.5 28.8

Other (incl. biomass) 2.5 2.2 3.6 2.3 3.0 2.6 5.6 3.3 1.9

Carbon value (in €/t CO2) 123 60 524 105 320 186 2150 490 5

Carbon value (in $/bbl) - approx. 47 23 202 40 123 71 827 188 2


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6.3.1.4 Final Energy Demand a. General Observations on Total and Sectoral Energy Demand Evolution As a first reaction to the post-Kyoto constraints, the final energy demand in the whole energy economy is expected to decrease. The evolution of the total energy demand and its intensity for the post-Kyoto limits of -15% and -30% are shown in Figures 6.23 and 6.24, respectively, and in each case compared to the Baseline and the ‘soaring’ fuel-price scenario.

Final Energy Demand


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Figure 6.23.a. Final energy demand for the post-Kyoto -15% scenarios in comparison with the Baseline and the ‘soaring’ fuel prices. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]



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Figure 6.23.b Final energy demand intensity for the post-Kyoto -15% scenarios in comparison with the Baseline and the ‘soaring’ fuel prices. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


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Final Energy Demand


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Figure 6.24.a Final energy demand for the post-Kyoto -30% scenarios in comparison with the Baseline and the ‘soaring’ fuel prices. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]



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Figure 6.24.b Final energy demand intensity for the post-Kyoto -30% scenarios in comparison with the Baseline and the ‘soaring’ fuel prices. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006] As expected, the very high carbon values in the ‘no nuc & no CCS’ scenarios, force effectively all sectors (see Figures 6.21a and 6.21b and Table 6.8) to decrease their final energy demand substantially. The tertiary sector, the residential sector and industry, in that order, will have to take the lion’s share, with a reduction ranging from 20% to 40% compared to the baseline. The transport sector only reduces ‘moderately’ in the -15% case (since it is cheaper to reduce demand in other sectors),


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whereas it is forced to seriously cut down on consumption (by roughly ¼ compared to the Baseline) in the -30% case. This is shown in Figures 6.25 and 6.26 for the -15% and -30% cases, respectively, where the influence of the nuclear phase out is exemplified, but without relying on CCS. (The cases

with CCS available are illustrated in [FPB, 2006 – Sept].)

Figure 6.25. Changes in final energy demand per sector compared to the Baseline for the scenarios -15% and no CCS, but with and without nuclear power. From [FPB, 2006 – Sept].

Figure 6.26. Changes in final energy demand per sector compared to the Baseline for the scenarios -30% and no CCS, but with and without nuclear power. Note the different scale compared to Figure 6.25. From [FPB, 2006 – Sept].

With reference to Table 6.1, Table 6.9 shows the results broken down for the industry sector and the transport sector.

-29.7

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BPK30s -29.7 -36.3 -40.7 -26.2

BPK30ns -19.4 -19.9 -18.4 -12.0

changes in final energy demand- industry

changes in final energy demand- residential

changes in final energy demand- tertiary

changes in final energy demand- transport

-20.9-22.0

-23.7

-12.7

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-5.7

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BPK15ns -8.6 -5.7 -3.5 -1.7

changes in final energy demand- industry

changes in final energy demand- residential

changes in final energy demand- tertiary

changes in final energy demand- transport


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Year 2030 Baseline Bpk15s Bpk15ns Bpk30s Bpk30ns

Mtoe % diff Mtoe % diff Mtoe % diff Mtoe % diff Mtoe % diff

Industry 13.9 - 11.0 -21 % 12.7 -9 % 9.7 -30 % 11.2 -19 %

energy intensive 8.8 - 6.3 -28 % 7.7 -13 % 5.5 -38 % 6.5 -26%

other indust sectors 5.0 - 4.6 -8 % 4.9 -2 % 4.2 -16 % 4.7 -6 %

Transport * 11.3 - 9.9 -13 % 11.1 -2 % 8.3 -26 % 10.0 -12 %

private cars 4.0 - 3.9 -3 % 4.0 ≈0 % 3.4 -15% 3.9 -3 %

trucks 4.9 - 4.1 -16 % 4.8 -2 % 3.7 -24 % 4.1 -16 % Source: PRIMES

* Including also aviation, rail, public road transport and inland navigation

Table 6.9. Comparison of final energy demand to the baseline for subsectors in industry and transport for the scenarios -15% & -30%, without CCS, but with and without nuclear. % diff refers to the percentage difference with respect to the year 2030. Colors indicate the different contrasts: background -15% versus -30%, and the baseline; colored numbers indicate with or without nuclear. Small differences in percentages are possible due to rounding off. (1 toe = 41.868 GJ = 11.63 MWh) [PRIMES, July 2006]

In the cases considered, the efforts in the industrial energy intensive sector, and for trucks in the transport sector are the largest. Compared to Table 6.1, we see, however, that the evolutionary decrease in the Baseline of the energy intensive sector is amplified by the post-Kyoto constraints. As to the trucks, the decrease compared to the Baseline, as given in Table 6.9, is only a mitigation of the expected increase that was noticed in the Baseline. (The number in 2000 was 3.5 Mtoe —see Table 6.1 and Figure 6.4.) To allow further study of the influence of the nuclear and CCS constraints/availability, Figures 6.27 and 6.28 contrast the absence of each of the two. The solid lines are the same in both figures. From these figures, it is obvious that the absence of CCS leads to a larger reduction of demand than the absence of nuclear power when stringent post-Kyoto limits are set (30%); the reverse is true for moderate reductions (-15%). These effects are related to the respective carbon value.

Final Energy Demand; no nuc

Alternative Scenarios -15% vs -30%

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Figure 6.27. Final energy demand for the post-Kyoto scenarios without nuclear power in comparison with the Baseline. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


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Final Energy Demand; no CCS

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Figure 6.287. Final energy demand for the post-Kyoto scenarios without CCS in comparison with the Baseline. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]

Figures 6.29 and 6.30 show the different average growth rates for the scenarios in comparison with the Baseline and with the other alternative scenarios; as before, the average is taken over a period of a decade. These pictures confirm what was shown in the evolutionary graphs in Figure 6.27 that the strongest reduction in the 'no nuc & no CCS' scenarios occur during the decade 2010-2020, after which the final-energy demand reduction effectively stabilizes. In other words, to be able to reach the post-Kyoto limits, it is more cost effective for the sectors to start reducing their end energy demand relatively early and then stay at that level, than to wait longer and having to cut more deeply.

-15% Scenarios


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1 = decade 1990-2000; 2 = decade 2000-2010 3 = decade 2010-2020; 4 = decade 2020-2030 Figure 6.29 Average annual growth rate (in [%]) averaged over a decade. Comparison of Baseline with the '-15% post-Kyoto scenarios'. Whenever a bar seems to be missing, the growth rate is zero. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


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-30% Scenarios


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1 = decade 1990-2000; 2 = decade 2000-2010 3 = decade 2010-2020; 4 = decade 2020-2030 Figure 6.30 Average annual growth rate (in [%]) averaged over a decade. Comparison of Baseline with the '-30% post-Kyoto scenarios'. Whenever a bar seems to be missing, the growth rate is zero. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]

b. Fuel Mix and Carrier Contribution in General and the Transport and Residential Sectors Each carrier reduces proportionally, except for coal that is losing most of its market share, while electricity increases its share. This is more pronounced in the 30% case than in the 15% case. In the 30% case, oil and gas also lose a few percentage points of their share, mostly so in the ‘no nuc & no CCS’ case. Hence, the paradox is that in this ‘squeezing’ scenario for the electricity sector, the burden in the other sectors is relatively larger, leading to a reduction of the share in oil and gas, while that of electricity increases. (For details, see [FPB, 2006 – Sept].) From Table 6.8 no spectacular changes in the fuel structure for transport can be observed. In contrast to the heat and power sector, a minimum contribution from biofuels has been imposed in PRIMES to be about 8% of the gasoline and diesel consumption found throughout all scenario's. It must be observed that the contribution from air traffic (kerosene) is substantial and that electricity and hydrogen do not penetrate in the transport sector.

In the residential sector, no massive penetration of biomass is observed under the 'other' fuels (2 to 5%) —see Table 6.8. No subsidy has been assumed in this application and only CO2 abatement is present as an incentive. It is recalled that there is no ceiling on biomass for heat applications. A strong contribution from electricity is observed in this sector which corresponds with an increased application of heat pumps in the most CO2 abatement demanding scenarios. 6.3.1.5 Electricity Generation Sector As already stressed during our discussion of the Baseline, there is a fundamental distinction between installed power (also called 'capacity') and produced electric energy. In a set of figures below, we illustrate the difference for the whole Belgian electricity system, and for intermittent renewables, in particular. Figure 6.31 shows the evolution of the electrical generation capacity, for all scenarios. Clearly, all alternative scenarios require more generating capacity than the Baseline. This is due to the projected maximum breakthrough of wind power in all scenarios, as compared to the Baseline. The largest installed capacity is projected to be those in the 'no nuc & no CCS' scenarios, because of the low capacity factor of PV. See Table 6.8.


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Electricity Generation; Installed Capacity

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Figure 6.31. Evolution of the installed electrical generation capacity for all alternative scenarios in comparison with the Baseline. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006].

To understand the build up of generating capacity in all scenarios, it is important to recognize the difference in the 'yes-or-no nuclear' scenarios. According to the phase out, actual decommissioning would start in 2015, with a second step in 2023 and the last one in 2025.

164 The 'nuclear-allowed'

scenario, on the other hand, continues with operation of the existing units, and is allowed to invest in one new unit of 1700 MWe after 2020, if PRIMES decides to do so. This is shown in Figure 6.32.

164 Figure 6.32 might give the wrong impression that there is still "some" nuclear electricity generation beyond 2025. This is not the case in reality, but a consequence of a linear connection in the plots between the points generated by the model (in 5 year intervals). In 2025, there is still a bit of nuclear generation, as the units Doel 4 and Tihange 3 still operate part of that year. In 2026, there would no nuclear generation left, but in the plot a straight line is drawn between the point in 2025 and the zero point in 2030.


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Electricity Generation; Installed Nuclear Capacity

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Figure 6.32.Difference in evolution of nuclear capacity in the nuclear and no-nuclear scenarios. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]

The following plots in Figure 6.33 and 6.34 concentrate on wind power and PV, respectively, and contrast the capacity build up of the alternative scenarios with the Baseline.

Electricity Generation; Wind-Driven Installed Capacity

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Figure 6.33. Difference in evolution of wind capacity in the baseline and the other scenarios. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


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Electricity Generation; Installed PV Capacity

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Figure 6.34. Difference in evolution of PV capacity in the Baseline and the other scenarios. Note the different scale with that of Figure 8.32. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]

As recalled above, it is important to evaluate the amount of electrical energy that can be produced with an amount of installed power. From Figure 6.35, it can be seen that wind has a greater 'value' than PV as far as utilization of its capital investment is concerned. The fact that the curves for PV energy in Figure 6.35 are exactly on top of each other is a consequence of the fact that the effective number of operation hours (ENOH) of PV has been assumed to be 1000h and the choice of the scales in MW and GWh. The wind curve for energy is obtained via a multiplication factor of about 2850h.

Installed Capacity vs Generated Electricity Wind versus PV

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Figure 6.35. Difference in installed power and generated electrical energy for wind and PV. Scenarios 'no nuc & no CCS'. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


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The overall variation of installed electric generation capacity and actual electricity generated between the various scenarios in 2030 as projected by the PRIMES simulations is shown in Figure 6.36. It can be seen that both the installed capacity and the generated electric energy can change considerably, from 23 GW in the Baseline to 32.4 GW in scenario Nr 7 (-30%; no nuc-no CCS), and from 103.5 TWh in Scenario 7 to 128.6 TWh in scenario 6 (-30%; with nuc; no CCS). Clearly, allowing nuclear power in the generation mix, limits the amount of installed power, but shifts consumption of energy to the electric carrier.

Installed Capacity vs Generated Electric Energy

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] G

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era

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ic E

nerg

y [T

Wh

]

Capacity -15%

Generated Energy -15%

Capacity -30%

Generated Energy -30%

Capacity Baseline

Generated Energy Base

1 = Bpk15; 2 = Bpk15n; 3 = Bpk15s; 4 = Bpk15ns 5 = Bpk30; 6 = Bpk30n; 7 = Bpk30s; 8 = Bpk30ns 9 = Baseline Figure 6.36. Difference in installed power and generated electrical energy in 2030 for the overall Belgian system for all scenarios. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]

Even though there is a massive build up of capacity in especially the 'no nuc, no CCS' scenarios, it must be recognized that most of the energy is still generated by gas-fired stations, as shown in Figure 6.37. In both the -15% and the -30% scenarios, the renewable fraction would be considerable, with some 31 TWh out of 109 TWh in the -15% case (i.e., ~ 28%), and 34 TWh out of 103.5 TWh in the -30% case (i.e., ~ 33%). About 5.5 TWh and some 9.4 TWh, would be produced by PV in the -15% and -30% cases, respectively.


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Generated Electricity Renew, coal & gas

-- no nuc; no CCS --

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Year

Gen

era

ted

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h]

Renew -15% Renew -30% Coal -15% Coal -30%

Gas -15% Gas -30%

Figure 6.37. Difference between the evolution of generated electrical energy for the 'no nuc-no CCS' scenarios, based on coal, gas and renewables. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]

Finally on electricity generation, we mention the strange variation of the CHP contribution in the various scenarios as projected by PRIMES. The largest contribution of CHP can be found in the baseline; adding post-Kyoto constraints significantly reduces the relative contribution from CHP in the generation mix. This is in part because for this type of distributed generation facilities, CCS is not possible, since they are too small. When nuclear power is present, then there is no need to use gas-based CHP to reach the post-Kyoto targets. See Figure 6.38. More details can be found in Table 6.10 in relation to the contribution of CHP in CO2-emission reduction.

CHP Contribution in Electricity [%]

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Baseline

1 = Bpk15; 2 = Bpk15n; 3 = Bpk15s; 4 = Bpk15ns 5 = Bpk30; 6 = Bpk30n; 7 = Bpk30s; 8 = Bpk30ns 9 = Baseline Figure 6.38. Contribution of CHP for the different scenarios in 2030, as a fraction of generated electric energy. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


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A final comment on hydrogen in the electricity sector is appropriate. Hydrogen as a fuel does not appear in any of the scenarios, except in the -30% no nuc, no CCS scenario, where according to the PRIMES tables some 13% of electricity is generated from H2 as a 'fuel'. It must be remarked, however, that it actually concerns natural gas fed to high-temperature fuel cells, in which internal reforming to H2 takes place. So, the primary fuel is actually natural gas rather than hydrogen.

6.3.1.6 Primary Energy Demand

The amount and composition of the primary energy demand (or Gross Inland Consumption; GIC) is a consequence of final energy demand and the fuel mix used in mainly electricity generation. The evolution for the -15% and -30% scenarios is given in Figures 6.39 and 6.40, respectively. These figures are to be compared to Figures 6.23 and 6.24, for the final energy demand (FED). The increase in the nuclear scenarios is due to the convention of 33% efficiency, further pushed by the new nuclear unit of 1700 MW past 2020.


Post Kyoto -15%

30000

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50000

60000

70000

2000 2005 2010 2015 2020 2025 2030

Year

GIC

[

kto

e/a

]

Baseline no nuc; with CCS with nuc; with CCS

with nuc; no CCS no nuc; no CCS

Figure 6.39.a. Evolution of the primary energy demand (or GIC) for all -15% scenarios compared to the baseline. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


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Primary Energy Demand Intensity

Post Kyoto -15%

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in

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sit

y

[kto

e/M

eu

ro]


with nuc: no CCS nu nuc; no CCS

Figure 6.39.b Evolution of the primary energy demand intensity for all -15% scenarios compared to the baseline. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


Post Kyoto -30%

30000

40000

50000

60000

70000

2000 2005 2010 2015 2020 2025 2030

Year

GIC

[

kto

e/a

]



Figure 6.40.a Evolution of the primary energy demand (or GIC) for all -30% scenarios compared to the baseline. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]


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Primary Energy Demand Intensity

Post Kyoto -30%

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[kto

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Figure 6.40.b Evolution of the primary energy demand intensity for all -30% scenarios compared to the baseline. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006]

The composition of the GIC can be found in Table 6.8. Noteworthy in that Table is also the short-term import dependency of the non-nuclear scenarios as projected by PRIMES, which is of the order of 90% as compared to about 70% for the nuclear scenarios.

165

6.3.1.7 Distribution of CO2-Emission Reductions over the Sectors

In Section 6.1.4, the energy-related CO2 emissions for the Baseline have already been discussed. a. Options for CO2 Reduction Both Table 6.10 and the discussion in the present section has been mainly taken over from [FBP, Sept-2006]. In Table 6.10, the relative contribution of CO2 reduction options (or measures) in the different scenarios is being summarized through the use of a selection of indicators. CO2 reduction options are grouped into four broad categories: energy savings, carbon-free production technologies or energy forms, cogeneration of heat and electricity (CHP) and carbon capture and storage (CCS). The comparison of the -15% with the -30% scenarios unravels some major differences, more specifically in the energy savings made in the final energy demand, in the installation of solar PV, in the CHP used for electricity production, in the use of renewable energy sources in the final demand sectors and finally, in the amount of CO2 emissions captured and stored. Final energy savings are much larger in the -30% scenarios. This is due to the fact that, given the stricter reduction target and higher carbon values needed to meet it, it becomes cost-effective for the demand side to put in more effort. These enlarged efforts are translated into larger energy savings. Compared to the final energy consumption recorded in the baseline, energy savings represent 3 to 19% in 2030 in the -15% reduction scenarios and 9 to 32% in the -30% reduction cases.

165 Below we will argue that the non-nuclear numbers below 90% (to a large extent due to PV-generated electricity) are too optimistic. Our statement should actually be '90% and higher'.


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Bpk15 Bpk15n Bpk15s Bpk15ns Bpk30 Bpk30n Bpk30s Bpk30ns Energy savings

Final energy demand 3117 1081 7893 2161 5802 3717 13068 7086

(ktoe) of which

industry 1371 735 2920 1189 2321 1710 4182 2693

residential 904 292 2210 583 1683 966 3659 21984

tertiary 592 86 1342 194 1044 483 2352 1063

transport 249 -32 1421 194 754 558 2875 1346

Fuel input elec/steam 1101 10685 4579 10525 279 9494 5653 10588

Nuclear (MW) 0 7775 0 7775 0 7775 0 7775 RES for electricity wind on 657 588 670 657 661 657 661 661 (MW)

wind off 2781 2772 2781 2781 2781 2781 2781 2781

solar PV 0 0 5694 0 2268 0 9671 3583

biomass 258 103 321 265 277 35 259 207

CHP (%)1 14.3% 16.3% 14.5% 15.0% 12.8% 9.6% 14.1% 12.4% RES in FED (ktoe) 118 14 277 13 460 368 428 295

CCS (%)2 72% 31% 0% 0% 86% 82% 0% 0%

CV (€/t CO2) 123 60 524 105 320 186 2150 490

Source: PRIMES 1 share of electricity produced in CHP units 2 share of (gross) CO2 emissions from electricity and steam production that is captured with the CCS technology

Table 6.10: Contribution of CO2 reduction options in the -15% and -30% constraint, year 2030, difference from baseline (except for CHP and CCS where absolute figures are shown), from [FPB, 2006 - Sept]

Converted to the sector level, we see that industry and the residential sector are the largest contributors to energy savings in absolute terms. In relative terms

166, however, the contribution of

industry, the tertiary and the residential sectors are comparable for a given scenario whereas transport contributes far less in all 15% reduction cases. To illustrate this statement, we calculate that energy savings in the Bpk15 scenario represent about 10% of the final energy consumption in all sectors but transport where they are estimated at 2%. Moving from 15% to 30% for the emission reductions, energy savings increase proportionally more in transport than in the other sectors. In other words, when the CO2 emission reduction constraint becomes more stringent, transport has to come up with a larger relative effort whereas proportionally less stress is put on the other sectors, especially in the scenarios where CCS is not included. Fuel savings in the power- and steam-generation sector relate to the consumption of fossil fuels and biomass in thermal power plants. The imposition of carbon values has effects on fuel choices in the power and steam sector. These effects are, however, highly sensitive to the availability of nuclear and/or CCS. As expected, fuel savings are the highest in the scenarios including the nuclear option and the lowest in the scenarios where CCS is assumed to be available but where nuclear power plants are decommissioned. Turning to carbon-free power-production technologies, we see that when nuclear is an option (extended lifetime and/or new investment), either in the -15% or in the -30% case, the maximum assumed capacity is used for production. Also, both CO2 reduction constraints lead to the maximum (assumed) potentials of wind power, be it on- or offshore and irrespective of the scenario.

167 The use

of solar PV, on the other hand, is much larger in the -30% scenarios. This can be subscribed to the fact that the 30% reduction entails a larger carbon value, and that at this new carbon value, solar PV

166 I.e., taking into account the shares of the sector in the total final energy demand. 167 Except for a minor difference of 50 MW in the scenario Bpk15n.


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becomes commercially attractive. More remarkable is the result of the Bpk30s scenario where the maximum (assumed) capacity is almost reached. The constraints on CO2 emissions lead also to additional investments in biomass-fired power plants, that are comparable in all scenarios except the ones where nuclear and CCS are accounted for. Surprisingly, and as already mentioned, the share of combined heat and power in electricity production

168 is lower in all CO2 reduction scenarios than the share projected in the baseline in 2030

(i.e. 18%). Moreover, CHP seems to reach smaller shares in electricity production in the 30% reduction scenarios than in the 15% reduction cases. It should be recalled that fossil fuel inputs (CHP uses mainly natural gas in the baseline) become more expensive in the alternative scenarios due to the carbon values imposed on fossil fuel consumption in relation to the carbon content of fuels and the global level of CO2 reduction aimed at. Furthermore, the electric capacity of CHP units is usually below 300 MW so that CCS is not applicable to them. The combination of the above two factors explains the decrease in the share of CHP especially when the CVs are the highest: the role of CHP in limiting CO2 emissions (through better conversion efficiencies) is partly overruled by unfavorable gas prices and CO2 emissions that cannot be reduced at the source in the present state and expected development of the CCS technology. In this connection, Table 6.10 underlines the significant role CCS could play in achieving the CO2 reduction constraints if it becomes available and reliable by 2020. Furthermore, the CCS technology is far more exploited in the -30% cases due to the stricter constraint and the subsequent higher carbon value which has an effect on its relative price. Finally, the use of renewable energy sources (mainly biomass and solar thermal) in the final energy demand is higher than in the baseline and significantly higher in the -30% scenarios than in the -15% reduction cases. Nevertheless, their share in final energy demand remains small: it is estimated to be at most 4%, since most of the renewable energies are found in the production of electricity.

b. Total and Sectoral CO2 Emissions The overall absolute result for the CO2 emissions for the alternative domestic scenarios is in fact simple: the CO2 emissions have been reduced to a level of 85% and 70% of those in 1990 for the scenarios -15% and -30%, respectively. For each of the post-Kyoto scenarios then, the reduction compared to the Baseline is the same for all. The important thing to know is where, for each of these scenarios, the greatest effort in terms of reduction is occurring. Because of the philosophy behind a carbon value in the PRIMES model, which is based on reaching an equi-marginal effort for that particular carbon value, reductions will take place first where they are the cheapest to implement. Because of its importance to understand these reductions, we take the liberty to show the plots from [FPB, 2006 - Sept]. Figure 6.41 shows the evolution of the emissions in all scenarios considered, and for the whole energy system, starting from 1990. Clearly all alternative scenarios go to their required emission limits of 85% and 70%. (Note that the ordinate axis is in Mton and not in %.)

168 CHP relates here mainly to industrial CHP, the possible development of micro generation in the residential sector is beyond the scope of the present analysis. The secondary importance of micro CHP for residential use has been clarified by [Verbeeck, 2007].


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60

80

100

120

140

160

1990 1995 2000 2005 2010 2015 2020 2025 2030

Bpk15 Bpk15n Bpk15s Bpk15ns Bpk30

Bpk30n Bpk30s Bpk30ns Baseline

Figure 6.41 Evolution of the CO2 emissions for all scenarios considered, for the whole energy system [Mton] From [FPB, 2006 - Sept].

Especially noticeable is the 'overshoot' in the scenarios in the 'no nuc - no CCS' scenarios Bpk15s & Bpk30s. This is due to the power sector, as will be shown shortly. For the electricity sector, the evolution is remarkable as shown in Figure 6.42, because of the different constraints put mainly on that sector (i.e., nuclear phase out and the probably non-availability of CCS). For this sector, the end effort in 2030 is different depending on the scenario. Especially the two scenarios 'no nuc - no CCS' (Bpk15s & Bpk30s) are interesting to comment upon. In fact, the difference between both scenarios is relatively minor and the reduction effort is all together rather minor, compared to the other scenarios. The former is notwithstanding the fact that the -30% scenario is much more expensive than the -15% scenario (due to expensive PV investments); the latter is because these scenarios are so costly on the electric-sector side that it is simply too expensive to have a major effort in that sector, as there is a lack of cheap CO2-reduction options given that all assumed RES potential has been reached. Consequently, the burden is shifted to the other sectors where the abatement costs are relatively lower. A second feature of these stringent scenarios in this sector is the (shallow) 'U-shape' behavior. This is because 'affordable' abatement options are running out after 2020, so that the burden is shifted to the other sectors.


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0

20

40

60

80

1990 1995 2000 2005 2010 2015 2020 2025 2030



Figure 6.42 Evolution of the CO2 emissions for all scenarios considered, for the electricity sector. [Mton] From [FPB, 2006 - Sept].

The other three sectors are depicted in Figures 6.43-6.45. They have to carry most of the burden for the most stringent scenarios 'no nuc - no CCS' (Bpk15s & Bpk30s). The industrial sector and the residential & tertiary sectors decrease their emissions with respect to 1990 substantially (depending on the scenarios), whereas the transport sector only manages to go back to the level of 1990 for the most stringent scenario ‘-30%, no nuc - no CCS' (Bpk30s).

0

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20

30

40

1 2 3 4 5 6 7 8 9



1 = 1990; 2 = 1995; 3 = 2000; 4 = 2005; 5 = 2010; 6 = 2015; 7 = 2020; 8 = 2025; 9 = 2030 Figure 6.43 Evolution of the CO2 emissions for all scenarios considered, for industry. [Mton] From [FPB, 2006 - Sept].


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10

20

30

40

1 2 3 4 5 6 7 8 9



1 = 1990; 2 = 1995; 3 = 2000; 4 = 2005; 5 = 2010; 6 = 2015; 7 = 2020; 8 = 2025; 9 = 2030

Figure 6.44 Evolution of the CO2 emissions for all scenarios considered, for the residential & tertiary sector. [Mton] From [FPB, 2006 - Sept].

20

25

30

35

1990 1995 2000 2005 2010 2015 2020 2025 2030



Figure 6.45 Evolution of the CO2 emissions for all scenarios considered, for the transport sector. [Mton] From [FPB, 2006 - Sept].

As a final, but important point on CO2 emissions, we consider the amount of CO2 to be captured in these scenarios. First, it is interesting to note that coal generation in the different scenarios (except for the Baseline) is only used when the possibility of CCS exists. If there is no CCS, then there is no coal-fired electricity generation. Figure 6.46 depicts the amount of coal-fired electricity generated (in [TWh/a]) and the amount of CO2 that is captured and thus needs to be stored (expressed in [Mton/a]) both for the year 2030. Figure 6.46 shows that there is also CCS applied to gas-fired units (as is clear from scenario 2, where some CO2 is captured, but where no coal fired generation is left by 2030.).


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Relation CO2 capture & Elec from Coal

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Scenario Number

CO

2 c

ap

ture

d &

Ele

c f

rom

co

al

CO2 captured [Mton CO2]

Coal-Generated Elec [TWh]

1 = Bpk15; 2 = Bpk15n; 3 = Bpk15s; 4 = Bpk15ns 5 = Bpk30; 6 = Bpk30n; 7 = Bpk30s; 8 = Bpk30ns 9 = Baseline Figure 6.46 Relationship of coal-fired electricity and CCS for the year 2030. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006].

In principle, a similar plot as Figure 6.46 could be made for all 5-year intervals that PRIMES utilizes in its modeling. If integrated over time, then the cumulative amount of CO2 to be stored in each of the scenarios is as follows

169

● Scenario pk15 (no nuc, with CCS) 146 - 235 Mton ● Scenario pk15n (with nuc, with CCS) 9 - 19 Mton ● Scenario pk30 (no nuc, with CCS) 277 - 397 Mton ● Scenario pk30n (with nuc, with CCS) 108 - 155 Mton These numbers show the enormous challenge that CCS would have to cope with in the non-nuclear scenarios. The amount of CO2 to be captured and stored would be between roughly 200 and 400 Mton up to 2030, in the corresponding -15% and -30% scenarios, respectively. With these huge amounts that need to be handled, it is not unreasonable to state that routine commercial "disposal" of this CO2 will be "difficult, if not quasi impossible". These numbers, together with the state of technology of CCS and the possibilities of storage in Belgium, leads the Commission Energy 2030 to conclude that it would be very risky indeed to assume that CCS will be readily available.

170 This

explains the CE2030's skepticism towards the routine and commercial availability of fully fledged CCS for outlining Belgian's energy policy.

6.3.1.8 Price and Cost Considerations

In this Section, the energy-related price and cost aspects to society are discussed for each scenario and for the different sectors. Recall that Section 6.3.1.2 dealt with the marginal abatement cost for the domestic post-Kyoto CO2-reduction scenarios. The numbers presented there already give a first indication of the efforts needed to reach the imposed post-Kyoto limits, if the full constraint is effectuated by domestic reductions of energy-related CO2, without taking into account the other GHG or emission trading. Here, the actual effect of such type of reduction on the end users is illuminated. In this section, we compare the expected energy prices that correspond to the different scenarios. The ‘cost to society’ of the different options can nevertheless be very different from the price increase.

169 The range originates from a linear interpolation or a stepwise approach between every 5-year interval. 170 The transport issue of CO2 has been addressed above in Section 5.3.4.2.e.


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There are two ways to have a rough approximation of the ‘costs’ of the different scenarios. For a given set of technologies allowed (say without CCS and without nuclear), one could for a given year compute the average cost of carbon reduction in a given year. This corresponds to the area under the marginal abatement cost function for carbon. The second approach is to compute the change in consumer and producer surplus on the different user markets of energy (industry, tertiary, residential). The simplest case is illustrated in the following Figure 6.47 where the green area represents the ‘cost’ of the abatement constraint. (We hereby neglect other external effects, taxes, subsidies and monopolistic margins). As can be seen in this figure, the increase in user price corresponds in this example to a real cost increase (the green triangle).

171

For the different consumers, higher prices correspond to higher costs though.

Marg Cost=P°

Q of final energy

Final energy market and measurement

of the cost of a constraint

Q°Q1

P1

P°

Marg Cost of production with

constraint

Demand for final energy

Price

Marg Cost

Figure 6.47. Relationship between prices and costs. See text. [Ref. S. Proost]

Tables 6.11 and 6.12 summarize the comparison of the energy-related prices in 2030 compared to the year 2000 and compared between the different scenarios. In these tables, four sectors are considered: the power sector (electricity and heat from CHP), industry, the residential and the tertiary sector. All these numbers are to be interpreted subject to the assumptions, constraints and the limitations behind and of the models (including the databases) and the scenarios.

171 But the reader will easily understand that the same price increase (same height of the triangle) can correspond to different cost increases (areas of triangles can be very different if slope of demand and marginal cost curves are very different). Whenever there are important taxes, subsidies or other external effects than climate change (say conventional air pollution), price changes and cost changes do no longer have the same sign.


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Power sector Industry Tertiary Residential

[€2000 per

(MWhe+ MWhth)]

[€2000/toe]

Energy price per

added value [(*)]

[€2000/toe]

Energy price per

added value [(*)]

[€2000/toe]

Energy price per

household [(**)]

Values for 2030

In 2000: 37

In 2000: 540

In 2000: 0.16

In 2000: 820

In 2000: 0.021

In 2000: 960

In 2000: 2200

Baseline 51 (36%) 660 (24%) 0.13 (-19%) 1100 (31%) 0.021 (1%) 1600 (63%) 3000 (39%)

Bpk15 73 (96%) 970 (81%) 0.17 (6%) 1500 (83%) 0.027 (27%) 2000 (110%) 3500 (62%)

Bpk15n 43 (17%) 730 (37%) 0.14 (-16%) 1100 (36%) 0.022 (3%) 1600 (71%) 3000 (40%)

Bpk15s 61 (64%) 1300 (150%) 0.20 (27%) 2100 (150%) 0.031 (48%) 2600 (170%) 3800 (78%)

Bpk15ns 42 (13%) 790 (47%) 0.14 (-12%) 1200 (43%) 0.022 (6%) 1700 (79%) 3100 (43%) SOURCE: PRIMES SIMULATION RESULTS Rounded figures; Between brackets (% change between 2000 and 2030) [(*)] €2000 energy related prices / €2000 added value = dimensionless fraction [(**)]energy related expenditures per household in €2000 1 toe = 41.868 GJ = 11.63 MWh Bpk15 = post Kyoto -15%; no nuc; CCS allowed Bpk15n = post Kyoto -15%; nuc allowed; CCS allowed Bpk15s = post Kyoto -15%; no nuc; no CCS Bpk15ns = post Kyoto -15%; nuc allowed; no CCS Table 6.11. Comparison of the prices in 2030 compared to those of 2000 in the power sector, industry, the tertiary and residential sectors and this for all post-Kyoto -15% scenarios and the Baseline. The numbers between brackets represent the relative increase between 2000 and 2030; the difference with the baseline is obvious from the numbers. Attention should be paid to the units in each column. Adapted from [FPB, 2006 - Sept]

The Baseline has been indicated with a yellow background, and the most stringent scenario, 'no nuc & no CCS' has been highlighted in pink and red. For the power sector, a price/cost indicator is constructed that is expressed per kWh, whereby the sum of electric and thermal energy has been taken.

172 As is clear from Table 6.11, the scenarios with

nuclear power give a smaller price for the power sector than even the Baseline, which had no post-Kyoto limit but which implements the nuclear phase-out law. It is interesting to note that the scenario Bpk15 (with CCS allowed) has a higher power-sector price than Bpk15s (in which no CCS is allowed). The reason is that there are no 'cheap' reduction possibilities left in the 'no nuc & no CCS' Bpk15s scenario in the power sector (since the assumed maximum potential for wind has been exhausted and PV is too expensive), shifting the burden of the reduction to the other sectors. This is evident from Table 6.11, when looking at the other sectors. As expected and as will be shown below, the overall price of the energy system is higher in the Bpk15s scenario than in the Bpk15 scenario. For the -30% case, Table 6.12 applies. In this case, because of the very stringent conditions (and correspondingly large carbon values), the Bpk30s 'no nuc & no CCS' scenario is the most expensive one in all sectors. The extra prices compared to the Baseline are substantial. These are unmistakable observations. Also here, the overall prices of energy provision are higher in the Bpk30s scenario than in all other scenarios.

172 Although an extensive discussion can be set up on the appropriateness of the allocation of costs over the electric and the thermal side of a CHP [IEA, 2005a] , which reflects the difficulties of the 'allocation problem', here a simple approach has been taken. Therefore the reader should focus on the changes of this cost indicator, rather than absolute numbers.


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Power sector Industry Tertiary Residential

[€2000 per

(MWhe+ MWhth)]

[€2000/toe]

Energy price per

added value [(*)]

[€2000/toe]

Energy price per

added value [(*)]

[€2000/toe]

Energy price per

household [(**)]

Values for 2030

In 2000: 37

In 2000: 540

In 2000: 0.16

In 2000: 820

In 2000: 0.021

In 2000: 960

In 2000: 2200

Baseline 51 (36%) 660 (24%) 0.13 (-19%) 1100 (31%) 0.021 (1%) 1600 (63%) 3000 (39%)

Bpk30 83 (120%) 1300 (130%) 0.20 (27%) 2000 (140%) 0.032 (53%) 2500 (160%) 4000 (89%)

Bpk30n 51 (38%) 930 (73%) 0.16 (-1%) 1400 (73%) 0.026 (22%) 2000 (100%) 3300 (56%)

Bpk30s 94 (150%) 2900 (440%) 0.40 (150%) 5000 (510%) 0.058 (180%) 5000 (420%) 6100 (180%)

Bpk30ns 46 (23%) 1200 (120%) 0.18 (15%) 1800 (120%) 0.029 (40%) 2400 (150%) 3600 (66%) SOURCE: PRIMES SIMULATION RESULTS Rounded figures; Between brackets (% change between 2000 and 2030) [(*)] €2000 energy related prices / €2000 added value = dimensionless fraction [(**)]energy related expenditures per household in €2000 1 toe = 41.868 GJ = 11.63 MWh Bpk30 = post Kyoto -30%; no nuc; CCS allowed Bpk30n = post Kyoto -30%; nuc allowed; CCS allowed Bpk30s = post Kyoto -30%; no nuc; no CCS Bpk30ns = post Kyoto -30%; nuc allowed; no CCS

Table 6.12. Comparison of the prices in 2030 compared to those of 2000 in the power sector, industry, the tertiary and residential sectors and this for all post-Kyoto -30% scenarios and the Baseline. The numbers between brackets represent the relative increase between 2000 and 2030; the difference with the baseline is obvious from the numbers. Attention should be paid to the units in each column. Adapted from [FPB, 2006 - Sept]

As will be recalled, the Baseline considered here has the nuclear phase out incorporated. It would be interesting to see what the prices of the post-Kyoto scenarios would be regardless of the nuclear issue. This is shown in Table 6.13, where the difference in price for the power sector between an adjusted baseline (identical to the Baseline but with nuclear power unconstrained) and the post-Kyoto scenarios is shown.

Bpk15n Bpk15ns Bpk30n Bpk30ns

8.6% 5.0% 28% 15%

Table 6.13. Comparison of the prices/costs in the power sector, between the scenarios indicated and an adapted baseline, in which nuclear power would have been allowed. Adapted from [FPB, 2006 - Sept]

These numbers show that post-Kyoto constraints are posing a burden on the energy system in terms of cost and prices, but Tables 6.11 and 6.12 also show that nuclear power acts as a relief to mitigate these prices. The numbers for the transport sector have been collected together in Table 6.14, in a somewhat different structure. The -15% and -30% cases are shown in vertical columns, whereas the scenarios Bpkαβ, Bpkαβn, Bpkαβs and Bpkαβns are shown in the horizontal rows, with αβ being 15 or 30. Results for passenger transport and for freight transport are shown.


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Transport -15% Transport -30%

[€2000/pkm] [€2000/tkm] [€2000/pkm] [€2000/tkm] Values for 2030

In 2000: 0.26

In 2000: 0.32

In 2000: 0.26

In 2000: 0.32

Baseline 0.29 (11%) 0.35 (10%) 0.29 (11%) 0.35 (10%)

Bpk15-30 0.29 (14%) 0.35 (11%) 0.30 (16%) 0.37 (18%)

Bpk15-30n 0.29 (11%) 0.34 (9%) 0.30 (15%) 0.36 (13%)

Bpk15-30s 0.32 (22%) 0.40 (25%) 0.44 (71%) 0.61 (94%)

Bpk15-30ns

0.29 (13%) 0.35 (10%) 0.31 (21%) 0.39 (24%) SOURCE: PRIMES SIMULATION RESULTS Rounded figures; Between brackets (% change btwn 2000 and 2030) Pkm = passenger-km; tkm = ton-km

Bpk15-30 = post Kyoto -15% or -30%; no nuc; CCS allowed Bpk15-30n = post Kyoto -15% or -30%; nuc allowed; CCS allowed Bpk15-30s = post Kyoto -15% or -30%; no nuc; no CCS Bpk15-30ns = post Kyoto -15% or -30%; nuc allowed; no CCS

Table 6.14. Comparison of the prices in 2030 compared to those of 2000 in the transport sector, for passenger and freight transport. The numbers between brackets are the relative difference between 2000 and 2030; the difference with the baseline is obvious from the numbers. Adapted from [FPB, 2006 - Sept]

This table confirms earlier observations showing that the transport sector is only moderately affected in all scenarios except the Bpk30s scenario ('no nuc, no CCS'). This means that to a large extent, the CO2 reductions are not to be expected in the transport sector, but that reductions are to be taken up mostly by the other sectors. Finally, to wrap up the section on prices and cost, we give an overview of the overall CO2 emissions in the overall energy sector, and the split up of the emissions in the power sector (Figure 6.48) and the end-consumption sectors (Figure 6.49). Also the respective costs are indicated.

Figure 6.48 Average power and heat production prices/costs vs. CO2 emissions in 2030. From [FPB, 2006 - Sept]

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Figure 6.49. Total energy related costs of final consumers per unit of GDP vs. CO2 emissions in 2030. From [FPB, 2006 - Sept]

The extra cost of the non-nuclear scenarios is obvious compared to the nuclear-allowed scenarios or the Baseline (without nuclear but without CO2 constraint). More details on the prices and marginal cost of the scenarios (e.g., also the intermediate year in 2020) is available in [FPB, 2006 - Sept]. It must be pointed out that the numbers in the previous tables and figures of this Section are for the Belgian case at hand. The numbers are not generic in the sense that they give cost comparisons for nuclear, versus CCS, versus renewables, versus demand reduction, etc, in general. The numbers given apply to the case with the limitations regarding potential on renewables, the sectorial fabric, the existing nuclear units which operational life can be extended without major difficulties, and for the time horizon of 2030. However, these numbers are appropriate for Belgian policy making, since this is the situation that Belgium has to cope with. In conclusion, the inescapable conclusion of these numbers is that a combination of the post-Kyoto constraints of 15% to 30% reduction of energy-related CO2 emissions, with a nuclear phase out and without the availability of carbon capture & storage (CCS) is basically not really bearable by our economy. This is reflected in the carbon values and the costs evaluated by the model. The system reacts to a maximum possible; demand is reduced wherever that is the most cost efficient option, then to meet the required demand, supply choices are made which are sometimes extremely expensive.

173

6.3.1.9 Wrap up of Simulation Results of the Alternative Scenarios for Domestic CO2 Reduction The collection of results as simulated by the PRIMES model and presented here in this Section 6.3.1 for the alternative scenarios and in Section 6.1 for the Baseline, shows that the Belgian energy system would be able to respond to moderate to severe post-Kyoto limits, but at a considerable to very large cost, especially if nuclear power is not allowed to be part of the solution. The possible relief provided by CCS should be welcomed to allow clean fossil to come back into the picture and to reduce the overall cost, but full commercial availability in Belgium within the required timescale of 2025-2030 appears to be a very risky assumption.

173 Note also that for these post-Kyoto cases, less CO2-related external costs have to be incorporated as they have been (partly) taken into account through the carbon values.

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Under these domestic CO2 reduction scenarios, in both the -15% and the -30% cases, renewable energies cover a considerable part of the energy mix, with a very large contribution from solar PV in the absence of nuclear and CCS. Also, the energy savings in these CO2-reduction scenarios are substantial both in energy-intensity terms as in absolute final energy consumption. An important conclusion regarding these domestic CO2 reduction scenarios is that CO2 abatement is a strong driver both for renewable energy expansion and for energy savings, regardless of the assumptions about nuclear or CCS. From the scenario numbers shown, it is clear that domestic energy-related CO2 reductions up to 15% by 2030 compared to 1990 may be feasible, but it already becomes very expensive in the absence of nuclear and CCS. A domestic reduction of energy-related CO2 by 30%, may be doable if nuclear and CCS are available; it would be very expensive if nuclear or CCS would be available; it would be effectively impossible if nuclear and CCS are not available. However, the PRIMES results discussed above are according to its algorithm, its database and the assumptions and constraints put on it. These results require further interpretation, however, as some of the results would lead to daunting challenges, both with respect to implementation and cost. In the next section, 6.3.2, the PRIMES results of the domestic CO2 reduction scenarios will be checked against "engineering common sense & realism", will be shown to lead to even higher costs to implement and will be confronted with the security of supply and import dependency issues. In Section 6.3.3, a European wide approach to reduce GHG emissions will be considered. The analysis will show that much of the expected GHG-reduction obligation will be effectuated abroad, reducing the pressure on the domestic energy system. However, implementing GHG reductions abroad come at a cost, which will turn out to be much higher under the nuclear phase out than with nuclear power allowed.

6.3.2 Critical Post-Scenario Evaluation of Domestic Energy-Related CO2 Reduction Scenarios As mentioned above, the simulation results of PRIMES must be further evaluated so as to face the challenges evoked by these results and to consider the degree of "realism" behind these numbers. The results of these scenarios provide a comprehensive picture for the future trends of the energy system, and the efforts and costs involved. However, a scenario analysis has its limitations, because it is impossible to simulate a full complex reality. In the present section, additional aspects are discussed, so that the scenario results together with the elements raised here provide a better understanding of the real challenges posed on the Belgian energy economy if serious domestic energy-related CO2 cuts are imposed. We recall that this study focuses on the year 2030 and on the decisions to be taken now to get there in a satisfactory way. We do not dwell on events occurring today, unless they have an impact on the longer-term future. Concerning the current state of affairs on regulatory aspects, we refer to the IEA in-depth review [IEA, 2006a], the indicative plans for electricity and gas [Ref., CREG, 2004, 2005], the development plan of ELIA [ELIA, 2005b] and the websites of DG Energy of the Federal Ministry of Economic affairs [http://mineco.fgov.be/energy/home_en.htm], the Regional Administrations, Flanders [http://www.vlaanderen.be à leefmilieu, natuur en energie], Wallonia http://www.wallonie.be/nl/themes/energie/index.html], Brussels IBGE/BIM [http://www.ibgebim.be] and the Regulators CREG [http://www.creg.be], VREG [http://www.vreg.be] and CWaPE [http://www.cwape.be]. The first part of this report provides important background material for the remainder of the report. As the Belgian energy policy is supposed to be in line with the overall European one, the two green papers on energy and the 'energy package' of January 10 2007, released by the European Commission [CEU, 2001 & 2006b, 2007b] will be kept in mind throughout our discussion, and the recommendations towards a Belgian energy policy.


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Below, the following elements will be addressed. First the results produced by PRIMES will be scrutinized with respect to the challenges they pose, or whether they are credible from a realistic point of view,

174 especially with regard to the renewable build up. In a second section, the realism of Carbon

Capture and Storage (CCS) is reflected upon, while the third section addresses considerations on security of supply. The fourth section then deals with practical post-Kyoto aspects.

6.3.2.1 Renewables Potential and Market Penetration & Diffusion As has been explicitly stated in Chapter 5 where the scenarios have been defined, it was opted for not to put too many constraints on the scenario runs in order to see where the system would take us if it had the freedom to fill in certain pre-supposed potentials. Afterwards it is then necessary to judge the degree of reality behind the numbers and/or to face the challenges. Two typical aspects have to be considered in this regard. The degree of manufacturing capability has not been considered, although the enormous growth rates worldwide may lead to much slower implementation and market diffusion than may be hoped for. Second, the investment costs of the transmission and distribution grids have not been imposed on the models. This means that the potentials for capacity given to the models may have been too rosy.

175

a. Growth Rate of Renewables and Market Diffusion It will be recalled from Section 5.3.2.5, and as explained in [De Ruyck, 2006], that the following maximal limits for the potential have been considered in the PRIMES simulatons: - wind on shore Max 2,026 MW (consisting of 1600 MW + 426 MW in an 'extra measure' option) - wind offshore Max 3,800 MW (consisting of 900 MW + 2900 MW in a 'grid-extension' option) - PV solar Max 10,000 MW - Biomass No limit (cost curve for electricity production) Concerning biomass, in PRIMES, a cost supply curve has been used to express the increasing cost of electricity from biomass. Biomass for heat production is not limited by biomass supply, but does not break through massively in the PRIMES simulations. All biomass consumption in the different PRIMES scenario results range from 96 PJ (reference scenario) to max 119 PJ (Bpk30 scenario). This is to be compared to the supply potentials estimated by [De Ruyck, 2006], i.e., 80 PJ for domestic biomass and 136 PJ for imported biomass. In all scenarios, Belgium would import biomass from abroad. De Ruyck [De Ruyck, 2006] also suggests averaged growth limitations in the range of 13% for wind and 25% for solar PV. These figures seem conservative when compared with growth rates of 32% for wind and some 40% for PV observed in Europe, but these take into account the challenges of far offshore wind (grid extension), and the fact that as potential limits are getting closer, growth rates will slow down. When analyzing the PRIMES results in detail (see Figures 6.33 to 6.35) one finds temporary extreme growth rates (up to 99% for PV and 68% for wind in 2010-2020), but rapidly decreasing after booming. On the average and over a long period of time, the overall growth rates do not exceed these specified in [De Ruyck, 2006], at least for wind and biomass. It should also be stressed that consequently wind and biomass virtually reach their potential limits in all scenarios except for the baseline (see summary Table 6.8). The possible growth in solar PV is more subject to discussion, since the PRIMES results indicate much higher growth scenarios than intuitively expected. According to Table 6.8 solar PV 'booms' in the -30% CO2 scenarios when nuclear phase out is assumed, and in particular when CCS is not

174 It is stressed here immediately that this is not necessarily a shortcoming of the simulation model. 'Unexpected' results may occur because of deliberately not imposing too many constraints on the model to find out how the system would react. This is explained under the treatment of this subject. 175 Note that in contrast to renewables, an 'artificial' limitation has been put on nuclear power, as the maximum new capacity has been limited to a single unit of 1700 MW.


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considered. To achieve the latter figure, a continuous growth of 40% per year must be taken from now till 2030. Note that results from a DLR study commissioned by Greenpeace [DLR, 2006] (see Section 7.2) are less ambitious with an average growth rate of 29%, which is not that much in excess of the 25% tentatively considered by [De Ruyck, 2006], and less than some of the CE2030 scenarios. Average growth rates for wind and biomass are comparable to the DLR study. The PRIMES results for wind and sun are given in Tables 6.15 and 6.16. Wind-generation [MWe] (2005) 2010 2020 2030

Baseline 113 1031 1478 2407 Bpk15 113 1019 3377 5845 Bpk15n 113 1019 2629 5768 Bpk15s 113 1137 3377 5858 Bpk15ns 113 1137 3318 5845 Bpk30 113 1187 3377 5849 Bpk30n 113 1137 3377 5845 Bpk30s 113 1187 3377 5849 Bpk30ns 113 1019 3377 5849 Table 6.15 Evolution of wind generation capacity according to PRIMES. See also Figure 6.33 [PRIMES, Nov 2005; July 2006]


PV-generation [MWe] (2005) 2010 2020 2030

Baseline 4 26 95 209 Bpk15 4 26 95 209 Bpk15n 4 26 95 209 Bpk15s 4 26 2515 5903 Bpk15ns 4 26 95 209 Bpk30 4 26 1333 2477 Bpk30n 4 26 95 209 Bpk30s 4 26 7239 9880 Bpk30ns 4 26 2105 3792 Table 6.16 Evolution of PV generation capacity according to PRIMES. See also Figure 6.34 [Ref. PRIMES, July 2006]


The growth rate of wind till 2010 (basically 'tomorrow') has clearly been overestimated due to the lead time of the offshore projects, and even till 2020 (yellow colored build up of wind power) it will very likely be slower. However, by 2030, it seems that the potential can be realized from the growth-rate point of view. (The fact that PRIMES overshoots the maximum limit by a few tens of MW is a minor issue.) The conclusion on wind energy is that from the growth-rate point of view probably more capacity based on fossil fuel will be needed than projected by PRIMES, between now and, say 2025, resulting in an increase of CO2 emissions during that period. In the absence of both nuclear and CCS (red color in the Table), solar PV booms and calls for continuous growth rates close to 40%. Such enormous growth rates may be questionable in reality. Suppressing either CCS or nuclear in the 30 % reduction cases may lead to growth rates (dirty-green color) which are effectively in line with the DLR prognosis [DLR, 2006] (see Section 7.2), which represent still very daunting growth rates. The other scenarios do not call for this type of expensive solar energy.


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b. Grid Investments for Renewables Accommodation For renewable investment purposes, PRIMES utilizes an increasing cost function signifying that the cheapest opportunities are considered first and that the burden for later investments is more expensive (although the investment cost of the technology itself decreases over the years). However, this is a generic continuous function that also takes into account back-up costs (at least to some extent), but it does not take into account the specific Belgian (and even more general) context of grid extensions. We assume here that the incorporation of the onshore wind power potential is taken care of by the PRIMES cost function. Even, up to about 800-900 MW offshore, we consider that the PRIMES approach will lead to results that are in the right ball-park. However, as mentioned in Chapter 5 and in [De Ruyck, 2006], offshore wind beyond 900 MW requires substantial investment for network reinforcement to transport the electrical energy to the load centers in land. The Belgian coastal region already has a generation surplus being transported to higher load areas. An additional input on this side of the grid requires transmission grid investments [Elia, 2005]. As an example, the cost for connecting 3800 MW offshore wind farms —the maximum limit for offshore wind power potential as assumed in the PRIMES simulations— is estimated in an Informative Box, below. The cost for connecting large amounts of PV installations to the distribution network is considered as well, in a different Informative Box.

Informative Box. Connection of 3800 MW offshore wind farms to the network A connection up to 800 MW is practicable on the 150 kV network. The other 3000 MW has to be connected to the 380 kV network. Therefore, the construction of a double link from both Izegem and Eeklo North to the coast, with substations in Izegem, Zomergem and Zeebrugge is minimally required. Depending on the netto import/export from Belgium, the transit fluxes and the amount to which these can be controlled by means of phase shifters, further network reinforcements might be needed. Cost estimates 1. Up to 800 MW Reinforcements of the 150 kV network will cost between 12 and 24 million €, depending on the division of power flow between Slijkens and Zeebrugge and the choice for either overhead lines or undergrounding on the 380 kV level. 2. 3000 MW over 380 kV overhead lines (probably 100% N-1 capable) The construction of 2 overhead lines (about 90 million €) and 3 substations (about 45 million €) amounts to about 135 million €. This brings us to a total cost (for 150 kV + 380 kV) of around 150 million €. Because of the public opposition to overhead lines and the long permitting process, the construction of underground cables seems however more probable. 3. 3000 MW over 380 kV cables (60% N-1 capable for 2 cables; 100% N-1 for three cables) The type of cables used on the 380 kV level, cost about 6 times as much as classical overhead lines per MVA. Depending on the equalness of the flux division and the North-South and South-North transit flows, two or three double cables will have to be installed. The total reinforcement cost if two double cables (and 2 necessary Mvar compensators) are sufficient, amounts about 390 million €. When a third double cable is needed (and 1 or 2 Mvar compensators), total costs will increase to about 700 million €. Note that the estimate made in [ELIA, 2005] applies to 2000 MW, and that the configuration considered is not N-1 capable. Furthermore, different configurations are considered there (1 to 4 platforms). Furthermore, the intermittency and unpredictability of wind power imply an increasing need for balancing services. According to Greennet-Europe (www.greennet-europe.org), a wind penetration of


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25 to 30% of total electricity generation increases balancing costs with 1.5 to 2 €/MWh. Depending on consumption, this amounts to a yearly balancing cost between 150 and 200 million €. This is very much depending on the price of natural gas as this energy source is key for fast balancing.

Informative Box. Connection of massive PV installations to the network For massive PV installation on roofs, the distribution grid is to be considered. It seems reasonable that for PV up to about 400 MW, the distribution grid is supposed to be able to absorb these local injections without too many problems.

176 We assume that the costs involved are sufficiently represented by the

PRIMES cost function. However, when a massive build up beyond that point is envisaged, the distribution grid requires a serious adaptation. An estimate is that the distribution grid adaptation might require about 2 G€ over a 10 to 20 year period. Part of this is due to new protection equipment that will be needed for the two-side power flow and the voltage control that will be needed in the distribution grid (tap changing in the distribution grid). Furthermore, intelligent metering is needed for instance to assess the input from distributed generation. Clearly this is not only needed for photovoltaic systems. It is however a “conditio sine qua non” for a further penetration of all kinds of distributed generation, of which photovoltaics will be a major contributor. Such advanced metering is also enabling Demand Side Participation. Which part of the lump sum is attributed to which technology is not essential. It has to be clear that the distribution grid has to change dramatically to enable the energy sources coming out of the different scenarios.

If these limitations had been imposed on PRIMES, the results would have been even more costly than is now the case. With an effective limit of about 3000 MW wind power (2026 MW on shore and 900 MW offshore) at 'acceptable cost', it follows that all but one post-Kyoto scenario (-15% and -30%) already overshoot that value as of 2020. (See Table 6.15.) We are not saying that this wind-energy build up is impossible, but the cost will be substantially higher than projected by PRIMES. It is to be expected that for most scenarios, PRIMES would have tried to find other solutions, but for the 'no nuc & no CCS' scenarios, the problems will be substantial. Further demand reduction will be imposed, but at a very high cost. For PV, the observation on distribution grid extension for massive build up leads to the conclusion that the brown and red colored lines in Table 6.16 are effectively non-existing (certainly if the growth-rate limitation of the previous subsection is taken into account). Also here, if we had put these extra constraints on PRIMES, the costs would really have skyrocketed, meaning that such scenarios in reality are basically impossible. c. Subsidy Requirements for Renewables Accommodation Electricity generation by RES is currently not cost-effective, which is clearly visible when comparing the cost price of electricity from RES with the cost price of electricity from large-scale thermal units working on fossil fuels or uranium. According to [IEA, 2005a], cost prices of onshore wind-power generation substantially vary, being probably due to differing capacity factors. According to the report, generation costs vary between 50 $/MWh (Greece) and 144 $/MWh (Czech Republic). The average amounts to 84 $/MWh. The cost of electricity from a “classic” power plant is significantly lower. Therefore, almost every European country implemented a mechanism for supporting RES. The three Belgian regions opted for a (different) system of green certificates. On the one hand, generators receive a certificate for each MWh of green electricity produced. On the other hand, suppliers are facing certificate obligations. In Flanders, certificates are currently traded at a price of about 110 €/MWh (VREG, Marktrapport – De Vlaamse energiemarkt in 2006, 14/05/2007). This additional cost is completely or partly passed through from supplier to consumers. For instance, some suppliers pass

176 Although the necessary investments for safety are to be taken, to avoid that distribution cables are under voltage when maintenance and repair work is undertaken.


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through 75% of the extra cost. Taking this percentage as a point of departure —which is a conservative estimation— the total cost of the green certificate system in Flanders in 2006 amounts to about 107 M€. Within the CE2030 scenarios, RES support is modeled as a subsidy on capital costs that decreases over time and is completely recovered in the electricity tariffs. For onshore wind power, the rate of subsidy to capital cost is set equal to 14% and 7% respectively in 2010 and 2020, leading to “actual” production costs close to 50 €/MWh in both years. For offshore wind power, the rate of subsidy to capital cost is set equal to 26% and 13% respectively in 2010 and 2020, resulting in net costs for the producers of the order of 60 €/MWh in both years. In the period up to 2020, the subsidies range from 5 to 50 €/MWh, according to the technology. These figures are far below the present values of the green certificates in the Regions, which are close to the total generation costs of the technologies (i.e. 100% subsidy). For instance, for offshore wind, a guaranteed certificate price of 107 €/MWh is foreseen (for a 20 year period). For photovoltaics in Flanders this is even 450 €/MWh. It is important to recognize that the commitments for green certificates may be overwhelming. Policy makers must realize what they promise, so as to remain correct to investors, on the one hand, and with regard to the offers they ask from the final energy consumers, being reflected in higher energy tariffs/prices, on the other hand. To make an estimate of the subsidies "promised", we consider the guaranteed buy back price that ELIA is supposed to pay. For simplicity, we take the values that apply to Flanders

177 (

http://www.elia.be ) This means: - wind offshore 107 €/MWh for the first 216 MW of each project - wind offshore 90 €/MWh for the remaining MW of a wind farm - wind onshore 80€/MWh - biomass 80 €/MWh - PV 450 €/MWh Suppose that these are subsidies in real terms, and that these certificates are granted for the full lifetime, then the results are as follows: - the current 846 MW of offshore wind farms with concession (3 projects): 3 x 216 MW x 107 €/MWh x 3500 h/a x 20 a à 4,850 M€ 198 MW x 90 €/MWh x 3500 h/a x 20 a à 1,250 M€ - the next 3000 MW offshore wind power à ~ 21,000 M€ - for 2000 MW onshore wind: 2000 MW x 80 €/MWh x 2200 h/a x 20 a à ~ 7,000 M€ - for 1000 MW PV 1000 MW x 450 €/MWh x 800 h/a x 20 a à ~ 7,200 M€ - for 1500 MW biomass 1500 MW x 80 €/MWh x 4000 h/a x 20 a à ~ 9,600 M€ In total, for the 'foreseen' renewable expansion, the end customer will have to contribute via green certificates (and thus increased tariffs) something like a total ~ 51,000 M€ over 20 years or about 1/5 of the GDP of 2000, or roughly 1/10 of the estimated GDP of 2030, or 0.73% of the average GDP/a over the period 2000-2030.

178

This exercise also shows that the simulation results of 10,000 MW PV (with a similar support scheme) are quite unrealistic. Indeed, such support would add up to ~ 72,000 M€, which together with the above, amounts to about ~ 115,000 M€ or about ~ 1/3 of the average GDP/a of the period 2000-2030, or about 40% of our national debt.

177 Since the system in Wallonia is a combined one with CHP, based on avoided CO2 emissions. 178 GDP(2000) = 248 G€2000 and GDP (2030) = 432 G€2000.


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6.3.2.2 Carbon Capture and Storage Near the end of Section 6.3.1.7, we have given the amount of CO2 that needs to be captured and stored following the domestic CO2-reduction scenarios. For the -15% and -30% scenarios, the results were 200 Mton and 400 Mton up to 2030, respectively, especially when nuclear power is phased out. This shows the considerable challenge posed on especially the CO2 storage part. Because of the price evolution of liquid and gaseous fossil fuels, the relatively low prices of coal, combined with the still massive reserves of coal and the storability of coal, much research is currently being done to capture CO2 from the exhaust gases

179 and to store it underground. Carbon capture and

storage (CCS) is hoped to be a bridging technology for this century before 'other' solutions for energy conversion are found. Interesting references, amongst others are [IEA, 2004, 2006; IPCC; 2005; ECN, 2006]. For the capture part, in-principle solutions exist, especially chemical absorption with MEA

180 or in an

integrated gasification combined cycle, although these techniques must still be proven in the field on a real-scale basis. Several pilot projects are currently being launched and it may be expected that this technology can be fully commercially available by 2020-2025, albeit at an additional cost (of about 20 to 40%). The problem for Belgium situates itself in the underground storage part. It seems indeed very unlikely that storage in Belgium can become a reality before 2030. [Piessens et al., 2007; Ph. Mathieu - ULg, private communications; B. Leduc, private communication]. According to the Policy Support System for Carbon Capture and Storage (PSS-CSS), funded by the Belgian Science Policy Office, there seems to exist a theoretical potential for CO2 storage, but there are a substantial number of uncertainties (even disregarding safety and license/permits considerations) meaning that full fledged commercial operation of CO2 storage in Belgium is effectively not a realistic option by 2030. The following possibilities seem to exist, with the theoretical guesstimate of storage capacity between brackets: - Abandoned coal mines (15-30 Mton in Flanders and some 10s Mton in Wallonia). Coal-mine reservoirs may be used on the short term but their intrinsic size is too small for large sources such as power plants. The sealing issue requires careful further research. Also, more administrative information on the abandoned coal mines is to be re-established. See e.g., www.naturalsciences.be/geology/research/geoenergy - Recovery of Enhanced Coal Bed Methane -- ERCBM (some 100s Mton) Due to the low permeability of the coal layers in Belgium, the development of this solution will be slow. This technique is currently being tested in Poland in the RECOPOL project. This requires, however, still much R&D and is certainly not competitive at the moment. - Aquifers (maybe 100 Mton) in Flanders. This is technically feasible but there remain a lot of uncertainties that relate to the poor knowledge of the deep surface in general and need further data. Furthermore, it seems plausible that if an aquifer for gas storage is found in the Kempen/Campine, that this will almost certainly be used to store natural gas to provide flexibility in the gas market. The economic value of a storage site for natural gas will be much higher than a CO2-waste storage site. Note that a coal fired unit with net power output of about 800 MW needs to capture and store about 5 Mton/a of CO2. Recall also from Figure 6.46 that for the non-nuclear scenarios in which CCS is allowed, PRIMES relies on 30 to 40 Mton of CO2 capture and storage for the year 2030. For the whole period, the numbers are 200 Mton - 400 Mton as mentioned before.

179 In Integrated Gasification Combined Cycles, the CO2 is captured 'upstream', from the syngas (and thus not literally from the exhaust gases). 180 MEA = mono-ethanol-amine


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From expert judgment, it must be concluded that the PRIMES numbers cannot be accommodated by reality. Fully commercial/operational CCS is only to be expected at the earliest between 2030 and 2050, if it is successful.

181 It would be irresponsible to assume that CCS would be available and to

think that there is an escape route from CO2 emissions. We must therefore conclude that the scenarios with CCS allowed are interesting exercises, but should not be withheld for actual policy making. Having said that, Belgium should launch a major research project in order to help demonstrating actual implementation of CCS. It should be taken as a commitment that Belgium operates one coal fired plant with carbon dioxide capture together with a major pilot project test and try out carbon storage in Belgian underground. Conclusion on Renewables Potentials and CCS The above analysis leads to two conclusions: - because of additional real-life constraints due to technology manufacturing & market penetration and the necessary grid extensions, the presumed build up of massive renewables as projected by the PRIMES simulations, are either unrealistic or will cost much more than the simulations lead us to believe; - considering the real 'on (and 'under') the ground situation' in Belgium, relying on CCS as solution for the CO2 issue by 2030 is wishful thinking. This means that effectively only the alternative scenarios without CCS should be considered for evaluation of the real challenges faced by the Belgian energy system (i.e., those scenarios labeled with an "s"). 6.4.2.3 Implications for Security of Supply and Energy Dependence From the PRIMES results for imposed domestic energy-related CO2 reduction, as presented in Table 6.8 above, we can extract the following part that is relevant for security of supply and import dependency of primary fuels for the Belgian system in 2030. See Table 6.17.

181 In principle it is possible to transport CO2 abroad, e.g., to the Netherlands where depleted gas fields could become available. However, the Netherlands themselves will need their gas fields for storage, pushing prices up if those fields are opened up for competition. The Belgian prices will be somewhat higher because of transportation costs (which are not very large, but nevertheless not negligible [Ref. IEA, 2004d]).


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Table 6.17. Primary energy import dependency according to the PRIMES runs. Excerpt of Table 6.8.

Attention is drawn especially to the short-term import dependency, by putting it in red in the Table. The qualifier "short term" refers to a period of up to two years.

182 It must be noted, however, that it

concerns here energy dependence considered over one year. These numbers for import dependency are not synonym for the degree of Security of Supply (SoS). As explained in Section 3.1, and as will be elaborated more in detail in Chapter 9; SoS is much broader than what import dependency suggests. To put it simply, a low import dependency is not a guarantee for continued energy delivery, but a large energy-import dependence makes all challenges substantially larger. The numbers of Table 6.17 must therefore be qualified for four reasons:

1. they refer to energy on an annual basis; 2. the instantaneous dependence in terms of power (seen as a "flow") is substantially larger

because of the presence of intermittent sources; 3. some domestic CO2 reduction scenarios considered, and displayed in Table 6.17, are

unrealistic, since real life emission allowance trading within the EU will take place, reducing the pressure on the Belgian system. Especially the Bpk30s scenario (30% CO2 reduction, with no nuc & no CCS) is a mere thought experiment. For SoS policy reflection, a scenario

182 Although in principle also nuclear fuel is imported, for "short-term import dependency", nuclear energy is supposed to be from domestic origin. The availability of nuclear fuel worldwide is discussed in Chapter 9.

Year 2030; Other key results

Bpk15 Bpk15n Bpk15s Bpk15ns Bpk30 Bpk30n Bpk30s Bpk30ns Baseline

Structure of GIC (%)

Coal 13.9 3.0 1.7 2.5 12.5 3.1 0.8 1.3 20.8

Oil 38.0 33.6 39.0 33.1 36.8 32.6 37.1 31.4 38.6

Natural gas 39.9 29.5 48.3 29.5 41.5 29.0 48.8 28.2 35.3

Nuclear 0.0 27.4 0.0 27.9 0.0 28.2 0.0 30.5 0.0

RES 8.2 6.5 11.0 7.0 9.2 7.1 13.3 8.7 5.3

Biomass supply (PJ) 112 98 117 107 119 106 115 117 96

Short term import dependency (%) 92.8 69.6 90.5 68.7 91.9 68.4 88.7 65.3 95.3

Structure of elec. generation (%)

Nuclear 0.0 51.9 0.0 50.9 0.0 49.4 0.0 49.5 0.0

Fossil fuels 77.3 28.6 71.7 28.8 77.3 32.7 67.2 28.2 88.2

RES 22.7 19.5 28.3 20.3 22.7 17.9 32.8 22.3 11.8

Wind 15.0 13.5 15.4 13.4 14.1 13.0 16.2 13.0 5.0

Biomass 7.3 5.5 7.4 6.5 6.3 4.4 7.0 6.2 6.3

Solar PV 0.05 0.05 5.1 0.04 1.9 0.04 9.0 2.7 0.05

Hydro 0.41 0.41 0.42 0.37 0.39 0.35 0.44 0.36 0.41

Installed power capacity (MW) 25 524 27 539 29 998 27 912 28 592 29 029 32 367 31 913 22 999

Nuclear 0 7 775 0 7 775 0 7 775 0 7 775 0

Wind onshore 2 045 1 976 2 058 2 045 2 049 2 045 2 049 2 049 1 388

Wind offshore 3 800 3 791 3 800 3 800 3 800 3 800 3 800 3 800 1 019

Solar PV 209 209 5 903 209 2 477 209 9 880 3 792 209

Biomass 1 568 1 413 1 631 1 575 1 587 1 345 1 570 1 518 1 310

Coal fired 3 940 0 0 0 3 706 837 0 0 7 054

Gas fired 12 142 11 704 12 562 11 834 12 434 11 823 11 844 11 992 11 240


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between the baseline and the scenario Bpk15s is more reasonable. See also the discussion in Section 6.3.1.9.;

4. based on the analysis on renewable market diffusion and electric grid extension (applicable to massive PV and offshore wind expansion, as explained in Section 6.3.2.1) some of the projected breakthrough of intermittent renewable sources may not take place in reality.

All in all, this means that the import dependency is more like the result for the baseline, i.e., about ~ 93 - 95%. Along this line of thought, electricity generation would be dependent on gas for more than 80% and in peak moments (when wind is absent) over 90% also. In subsections a and b, below, we discuss some obvious consequences of these domestic reduction scenarios for both gas provision and for electricity. A more general discussion on Security of Supply will be taken up in Chapter 9. a. Impact of the Domestic CO2 Reduction Scenarios on Natural Gas Demand As natural gas is potentially used for electricity generation and as its combustion generates CO2 emissions, all alternative scenarios (with/without nuclear electricity generation and with/without CCS technology) have an influence on natural gas demand and hence gas imports. This is illustrated in the three figures below. The reader is reminded that for SoS purposes, the situation between the baseline and the Bpk15s scenario should be looked at. Figure 6.50 shows the evolution of gas demand in the final consumption sectors, according to the scenarios considered.

0

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Baseline

Bcm/y Mtoe/y

Figure 6.50: Final gas demand (industry, residential, tertiary, transport) according to the domestic CO2-reduction scenarios. Ref. PRIMES and [BFP, 2006 - Sept]. 1 Bcm (billion cubic meters) = 1 G m3= 0.8859 Mtoe = 885.9 ktoe

The share of electricity generated from gas varies considerably from one scenario to another, the highest share being observed when there is no nuclear allowed and no CCS available. This trend is shown in Figure 6.51.


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0

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Bcm/y Mtoe/y

Figure 6.51: Gas demand used for electricity generation according to the domestic CO2-reduction scenarios. Ref. PRIMES and [BFP, 2006 - Sept]. 1 Bcm (billion cubic meters) = 1 G m3= 0.8859 Mtoe = 885.9 ktoe Under these no-nuc & no CCS hypotheses, electricity generation itself is the lowest of all scenarios (since a cheap generation means has been forbidden) but it relies first on gas. The total gas demand (including that for electricity generation) and thus also import on an annual basis, is shown in Figure 6.52.

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Bcm/y Mtoe/y

Figure 6.52: Total gas demand according to the domestic CO2-reduction scenarios. Ref. PRIMES and [BFP, 2006 - Sept]. 1 Bcm (billion cubic meters) = 1 G m3= 0.8859 Mtoe = 885.9 ktoe

However, as said above, the relative percentages of gas demand as part of the overall Primary Energy Supply and Electricity Generation portfolio (as shown explicitly in Table 6.17) are based on yearly average electricity generation and total annual heating demand. These relative contributions could become much higher under circumstances when there is no wind on a cold evening, thereby restraining the alternatives to gas. The combination of no wind, no PV


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(evening), no nuclear (not allowed), no coal (CCS not available), and a winter period, could lead to a situation where more than 90 % of electricity generation relies on gas while also final demand for gas (for heating needs) is very strong. The consequences of this very large gas dependency in a broader context are examined in Chapter 9. b. Impact of the Domestic CO2 Reduction Scenarios on Electricity Generation in Belgium The evolution of the final electricity demand (industry, residential, tertiary and transport) in the baseline scenario, the high price scenario and the alternative scenarios is represented in Figure 6.53.

40000

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GW

h

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Higher prices

Bpk15

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Bpk15s

Bpk15ns

Bpk30

Bpk30n

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Bpk30ns

Figure 6.53: Final electricity demand according to the domestic CO2-reduction scenarios. Ref. PRIMES and [BFP, 2006 - Sept].

As said before, for SoS purposes, the situation in-between the baseline and the Bpk15s scenario should be looked at. On the scale of the figure, there is hardly a distinction between the baseline (in which there are no post-Kyoto requirements and with the nuclear phase out implemented) and the scenario with soaring fuel prices. In 2030, the electric energy demand in the baseline in 2030 amounts to 105.2 TWh/a. The final electricity demand in 2030 for scenario(s) Bpk15s (and Bpk30s), i.e., assuming a nuclear phase-out and no availability of CCS, is mainly focused on to analyze the Belgian security of supply in a later section, since for that (those) scenario(s), electricity demand remains reasonable, but they will turn out to be the most challenging as far as new investments are concerned. In all scenarios considering a continuation of nuclear generation, the final electricity demand is higher than in the nuclear phase-out scenarios, but the generation investment challenges are more moderate because of the still existing ~ 6 GW of nuclear power capacity at that time. For a domestic reduction of CO2 emissions by 15% by 2030 without nuclear and without CCS (Bpk15s), electricity demand equals 104.6 TWh/a. If domestic CO2 emissions have to be reduced by 30% in 2030 under the same conditions (Bpk30s), the final electricity demand equals 99.9 TWh/a. This comes down to an increase in electricity demand between 2005 (being 83.6 TWh/a) and 2030 of 21.0 TWh (25.1%) and 16.3 TWh (19.5%), respectively. For the scenarios assuming continuation of nuclear generation with still no CCS available, i.e., Bpk15ns and Bpk30ns, electricity demand equals to 118.4 TWh/a and 122.0 TWh/a, respectively. This comes down to an increase in electricity demand between 2005 (being 83.6 TWh/a) and 2030 of 34.8 (or 41.6%) and 38.4 (or 45.9%), respectively. In the PRIMES simulations, it has been assumed that net electricity import gradually decreases from 7.5 TWh/a in 2005 to 3.7 TWh/a in 2030 (based on an assumption that current overcapacity in Europe would dry up). This import is assumed to be frozen and is kept the same for all scenarios.


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Apart from this import, new investments must be made to deliver the electricity demand as computed and as shown in Figure 6.53. The needed capacity for the domestic CO2 reduction scenarios has been displayed in Figure 6.31, and Tables 6.8 and 6.17 above. To fix the mind, the total capacity in 2030 has been repeated in Table 6.17. The first numerical row in Table 6.18 gives the installed capacity in 2030 for each of the scenarios. These numbers are to be compared with the generation capacity of 15,000 MW (or 15 GW) in 2005 as utilized by PRIMES. This means that compared to 2005, not counting decommissioning of existing units by 2030, an extra capacity investment for about 6 GW to 12 GW will be needed. As shown by the bottom numerical row, though, these figures are optimistic, in the sense that also a very substantial part of the existing electricity generation capacity will have to be replaced. Behind those numbers, it has been assumed that in case of a nuclear phase out all existing generation capacity will be decommissioned by 2030.

183 When nuclear power is allowed, then there

would still be a capacity of 6.1 GW available in 2030, which no longer needs to be invested in. The numbers in Figure 6.31 and Table 6.7 take into account the effective number of operating hours for all units (fluctuating sources, overhaul & maintenance in effectively all units), and the necessary back up capacity.

Scenarioàààà BL Soaring Bpk15s Bpk15n Bpk15 Bpk15ns Bpk30s Bpk30n Bpk30 Bpk30ns

2030 Total

Installed Capacity

[GW]

23.0 23.2 30.0 27.5 25.5 27.9 32.4 29.0 28.6 31.9

2030 New

Investments [GW]

23.0 23.2 30.0 21.4 25.5 21.8 32.4 22.9 28.6 25.8

Key: n: nuclear allowed / s: CCS not allowed / BL = baseline Table 6.18. Variation of installed electric generation capacity for the domestic scenarios in 2030. For comparison, the installed capacity in 2005 equals 15 GW. [FPB, 2006 – Sept; PRIMES, Nov 2005; PRIMES, July 2006].

The columns for the Baseline (BL) and the scenario -15% without nuclear and without CCS have been highlighted, since under those conditions, the results of those scenarios seem plausible with what might be expected in reality. As said before, the likely future (keeping in mind that emission trading would take away some of the pressure to reduce CO2 domestically —see further the discussion on the EU-related scenarios) may be in-between the results of the baseline and the scenario Bpk15s. In any case, effectuating the investment required over the next 25 years will be very challenging.

The consequences for SoS for electric powering a broader context are examined in Chapter 9.

6.3.3 Post-Kyoto Reduction Scenarios in a European Context

In this Section, we consider what we call the European approach of GHG emission reduction. Subsection 6.3.3.1 deals with the results of the scenarios whereby a reduction limit for GHG emissions by 2030 is imposed on the EU as a whole. Under the pressure of the increased cost of GHG emissions, and based on a known set of technologies and expected behavior by the actors in the different sectors of society, the model will reduce GHG emissions first there, where it is the cheapest. As a consequence, it is found on how Belgium reacts to this via GHG and CO2 reductions on its territory (often also referred to here as "domestic" reductions). It basically starts from the marginal abatement cost (MAC) curves for all GHG as we presented them in Section 5.3.4.2.a, and distributes the domestic reduction efforts accordingly. The direct effects on energy demand in the different

183 It seems obvious that the existing coal-fired plants will be shut down by 2030. For the CCGTs, a life time of 25 years is assumed. Although some very recent CCGTs (e.g., Zandvliet Power) may in principle and perhaps be refurbished to last longer than 25 years, this seems unlikely from an economics viewpoint. Indeed, by that time, efficiencies may have gone up to …62%... compared to 56-57% net today and combined with the low specific investment cost and very large fuel cost of a new CCGT, investing in a new CCGT would seem to be a more sound decision.


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sectors, on the electricity generation mix and the domestic CO2 reductions are discussed and illustrated. Subsection 6.3.3.2 treats the consequences of this type of European approach for Belgium, and focuses thereby on security of supply, and on the cost consequences. As far as this last element is concerned, two types of costs need to be considered: the costs for the domestic reductions in Belgium, on the one hand, and the "expected" costs for buying GHG emission allowances abroad, to compensate for the domestic reductions, if Belgium is to commit to the same GHG-reduction responsibility as its most important neighboring EU trade partners, on the other hand. The material of this section, with the exception of sub-section 6.3.3.2,b.2, relies heavily (and sometimes even using a translational paraphrasing of certain paragraphs) of the first part —up to 2030— of the very instructive report by the FPB. [FPB, 2007] Much credit for the comparison presented here goes to the authors of the mentioned FPB report.

184

6.3.3.1 Influence of EU GHG Constraint on Belgian Energy Situation Concretely, to perform the simulations, it is assumed that a generalized emission trading scheme exists for all European countries and for all activities. The value of such an emission permit is called the Carbon Value (CV) and it gives the equilibrium marginal abatement cost to reduce emissions. In this European approach, it is taken as a given that Europe commits to reduce its GHG by 30% by the year 2030 in comparison with 1990. It is assumed furthermore that these reductions must take place on European territory and that Flexible Mechanisms outside Europe cannot be invoked. Two major scenarios will be considered: a first one with nuclear phase out in Belgium effectuated by 2025; in a second scenario, the nuclear phase-out law is assumed to be lifted and one new nuclear unit of 1700 MW is allowed to be built in addition to the existing nuclear plants. For the sake of transparency of the results and the following comparison, CCS has not been kept as an emission-reduction option in Europe and Belgium by 2030 in this analysis. In a separate section, it will be analyzed what the impact of such technology would be. a. Marginal Abatement Costs For an imposed GHG emission reduction of 30% by 2030 at the level of the EU, and according to the existing legislation and measures up to 01.01.2005, the marginal abatement cost (or Carbon Value) are estimated to be about 200 €/ton CO2-eq in 2030. This value thus assumes a Belgian nuclear phase out after 40 years of operation of its nuclear plants. This European CV is not very dependent on the Belgian nuclear framework: phase out, or not. This is because the total of Belgian GHG emissions amounts to a mere 4% of the European amount. If Belgium were to lift its nuclear phase out and allows the construction of one extra nuclear power plant of 1700 MW, then the European CV would decrease to 190 €/ton CO2-eq. b. Reduction of GHG and Energy-Related CO2 in Belgium b.1 Overall Emission Reductions The consequences of a European approach to reduce GHG are shown in Figure 6.54. The reductions on Belgian territory, i.e., the "domestic" reductions, are compared with the situation in the EU and with the baseline. (The "baseline" is referred to as "Reference" in this Figure.)

184 However, the final responsibility for what is written here in the CE2030 report falls under the responsibility of the CE2030.


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-20%

-26%

32%

-30%

-12%

-1%

20%

-0,4 -0,3 -0,2 -0,1 0 0,1 0,2 0,3 0,4

EU - GHG constraint







GHG = greenhouse gases




Green: with nuclear Figure 6.54. GHG emission reductions inside Belgium, for an imposed EU-wide reduction of 30% GHG by 2030 compared to 1990. The top bar (orange) shows the EU requirement to reduce GHG by 30%; the next two bars (red) refer to the increase in GHG (hatched) and CO2 (full) in Belgium according to the baseline. The blue bars consider the domestic reductions in GHG (hatched) and CO2 (full) in the case of no nuclear, whereas the green bars consider the domestic reductions in GHG (hatched) and CO2 (full) in the case of with nuclear. Note that the baseline185 (red bar) is not sustainable. Ref. [FPB, 2007]

The top horizontal bar of Figure 6.54 shows the requirement (orange, hatched) to reduce EU GHG emissions by 30%. The next two bars, in red, indicate the increase in both GHG emissions (hatched) and CO2 emissions (solid fill) in Belgium for the baseline. Note that no post-Kyoto constraints were imposed in this baseline. The blue and green bars, refer to the cases with the Belgian nuclear phase-out law implemented (without nuclear), or lifted (with nuclear), respectively. As before, the hatched bars refer to GHG; the "solid fill" bars refer to CO2. In the case of a nuclear phase out (blue), the domestic reductions of GHG in Belgium amount to a decrease by 12% in 2030 compared to the level of 1990. For energy-related CO2 reductions on Belgian territory, there is only a decrease of merely 1% in 2030 compared to the 1990 level. Compared to the baseline, there is a respective reduction by 32%-pts or 27% of GHG, and a reduction by 33%-pts or 25% of the energy-related CO2. This very small domestic reduction effort of both GHG and energy-related CO2 within Belgium is a consequence of the very high abatement cost in Belgium in the case of a nuclear phase out. It is much cheaper to reduce emissions abroad than in Belgium. If, however, the nuclear phase-out law would be revoked, with the additional possibility to construct a new nuclear plant of 1700 MW (the green case in Figure 6.54), then the emission reductions on Belgian territory would be 26% for GHG and 20% for energy-related CO2. Compared to the baseline, the domestic reductions are dramatic: 46%-pts or 38% of GHG, and 52%-pts or 40% for energy-related CO2.

185

The word "reference" in the figure is synonym of "baseline"


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Although electricity only represents about 20% of the final energy consumption in Belgium, the nuclear issue has a major impact on the domestic CO2 reductions. The nuclear issue only influences energy-related CO2 emissions; it hardly affects the non-CO2 GHG (basically only by lowering the overall European CV by 5% from 200 €/ton CO2-eq to 190 €/ton CO2-eq). The results of Figure 6.54 show unequivocally that, although a Belgian change in nuclear attitude results in a minor decrease of the EU-wide CV (from 200€/ton to 190€/ton), the domestic abatement cost inside Belgium is considerably lower with nuclear power allowed to continue operation compared to when it is phased out. The consequences of this are shown below in § 6.3.3.2. Figure 6.55 shows the evolution of CO2 and GHG reduction in time, for the scenarios considered.

Figure 6.55a: Evolution of the CO2 reduction effectuated in Belgium for the -30% EU constraint case, with and without nuclear power in Belgium. Ref. [FPB, 2007]

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Figure 6.55b: Evolution of the GHG reduction effectuated in Belgium for the -30% EU constraint case, with and without nuclear power in Belgium. Ref. [FPB, 2007]

b.2 Contribution of Sectors to Domestic CO2 Abatement Al energy-'producing' and -consuming sectors contribute to the GHG emission reductions in each of the scenarios. The relative contribution of each sector is shown in Figure 6.56. In relative terms (i.e., with respect to each other), the final-energy sectors contribute more to the domestic reduction efforts when nuclear power is not allowed. In absolute terms, however, their contribution is expected to remain almost unchanged (in line with what has been said above). The difference is especially found in the electricity generation sector. Compared to the baseline and without nuclear power, the total domestic CO2 reduction is 35.2 Mton/a in 2030; with nuclear power allowed, the domestic reduction would be 55.4 Mton/a.

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Figure 6.56. Contribution of the different sectors to the Belgian domestic reduction of CO2 in 2030 in comparison with the baseline [Mton/a]. Ref. [FPB, 2007]

b.3 The role of Nuclear as a Cheap Abatement Cost Option If nuclear power would be allowed and thus the nuclear phase out would be lifted, the carbon price (CV) becomes an incentive for nuclear power. From a marginal abatement cost (CV) on of 50 €/ton CO2-eq, nuclear power is the most competitive electricity generation option, even if the price of nuclear fuel is doubled, or if the total investment cost is increased by 50%. This is shown by Figure 6.57 for a discount rate of 8.5% and an operation time of 7800 h/a and the projected fuel prices of 2020. This figure compares only newly built plants; it does not consider existing plants for which the generation costs are lower than indicated in the figure.

r = 8,5% and 7800h/a

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Carbon Value (CV) expressed in €/t CO2

Figure 6.57. Comparison of base load electricity generation cost in 2020 for new investments [€/kWh]. Ref. [FPB, 2007]

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Energy -0,6 -0,5

Pow er sector -21,3 -39,6

2030 - GHG constraint w ithout nuclear 2030 - GHG constraint w ith nuclear


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b.4 Impact of CCS If it had been assumed that CCS would available in Europe by 2030, then the two GHG reduction scenarios give different results. In that case, the marginal reduction cost for CO2 abatement amounts to 100 €/ton CO2 in 2030. For Belgium, this lower MAC results in smaller GHG reductions. Depending on whether CCS is available on Belgian territory, and depending on the nuclear policy, emission reductions vary between 4% and 25% in 2030 compared to 1990. The reduction of 4% corresponds to the case no nuclear and no CCS in Belgium; the reduction of 25% refers to the situation with nuclear and with routine CCS available in Belgium by 2030.

186

The remainder of the Sections below follows the original assumption that CCS is not fully routinely commercially available in Europe. c. Final Energy Consumption / End Energy Demand The reduction of GHG in the end-energy sectors is a consequence of fuel-mix changes and a reduction of the demand for energy. This demand reduction, in turn, is a combination of a reduced demand for energy services and a better efficiency of the energy-consuming equipment. c.1 Final Energy Consumption per Sector Figure 6.58 shows the resulting reduction in energy consumption for the different scenarios in the different sectors. In total, the reduction of final-energy consumption, i.e., the energy savings, amounts to 11% in case nuclear power is not allowed and 9% if the nuclear option is available, compared to the baseline.

187 Compared to the final-energy consumption in 1990, the savings are 14% and 12%,

respectively. The reason for somewhat lower savings when nuclear power is allowed is because the electricity sector is then less penalized by the implementation of a carbon value, and electricity is a convenient substitute for fossil fuels in some energy applications.

Units [ktoe] ; 1 toe=41.686 GJ=11.63 MWh "Reference" = Baseline

Figure 6.58. Change of the final-energy consumption [ktoe] in the different sectors according to the scenario. Ref. [FPB, 2007]

186 The difference of 21%-pts between the upper limit of 25% and the lower limit of 4% reductions is for about 1/3 due to CCS and 2/3 due to nuclear power. 187 These numbers cannot immediately be read from the figure; some preliminary arithmetic is necessary.

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Tertiary 3370 5763 5027 5274

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1990 2030 - Reference

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At the level of the sectors, the energy savings compared to 1990 are comparable in the industry and the residential & service sectors, namely 12% in the scenario without nuclear and 8 to 12% in the case with nuclear. However, in the transport sector, the energy savings in response to the Carbon Value are considerable lower, being abut 5% in both scenarios. The lower sensitivity of the transport sector is due to the already very large levies & taxes in that sector (see Section 2.2.2) with respect to which additional levies (due to CO2 abatement) are felt relatively less, on the one hand, and also by the existing lower price elasticities in that sector, on the other hand. c.2 Final Energy Consumption per Energy Carrier Besides a considerable amount of energy savings, there is also a switch in end-energy carrier, especially to the advantage of electricity and renewables, and to the disadvantage of coal, but also of gas in the scenario with nuclear. This is shown in Figure 6.59.

NOTE: "Other" = heat, steam and renewable sources.

Figure 6.59. Change of the energy mix in the final energy demand according to the scenario. Ref. [FPB, 2007]

d. Electricity Generation As expected and as shown in Figure 6.60, the structure of the electricity-generation sector in Belgium will change considerably, according to the scenario, and both with respect to the year 2000 (when nuclear is still a substantial part of electricity generation) and to the baseline (in which the nuclear phase out is assumed to be effectuated, but with no post-Kyoto constraint imposed). In both post-Kyoto scenarios, coal disappears from the scene. (It will be recalled that CCS is not considered in these scenarios).

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Gas 22% 28% 28% 23%

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NOTE: RES = renewable sources; Other = oil products, "derivative" gases.

Figure 6.60. Difference in electric energy generated in Belgium in 2030 [GWh/a], and its composition with respect to primary energy, according to the scenarios. Ref. [FPB, 2007]

In the scenario without nuclear, the annual electric energy generated increases at an average rate of about 0.9%/a between 2000 and 2030. (In the baseline, the average rate is 1%/a). Electricity is mostly generated from natural gas (72%) and 1/4 by means of renewable energy, mainly wind energy and biomass. In the scenario with nuclear power allowed, the annual electric energy generated increases at an average rate of about 1.4%/a between 2000 and 2030. The contribution from natural gas is reduced to only 27%, compared to 44% in the baseline and 72% in the non-nuclear case. In absolute terms, natural gas for electricity generation has been doubled though (see Figure 6.60). The relative contribution of renewable energy sources (RES) has diminished to 21%, compared to 25% in the scenario without nuclear. In absolute terms, however, the amount of renewable-based electricity is comparable though. Nuclear-generated electricity signs for 51% of the electricity structure. 6.3.3.2 Consequences for Belgium of EU-wide GHG-Reduction a. Import Dependency and Security of Supply a.1 Electricity-Generation Basket To get a good grasp of the energy mix and thus the import basket of Belgium, it is important to first focus a bit more on the electricity sector, since, on the one hand, that sector will determine to a large extent the dependence on natural gas, while it is important for short time security of supply, since at any time supply has to satisfy demand, on the other hand. Therefore, Figure 6.61 shows the relative importance of each primary source in the electricity mix.


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2000

58%

2% 16%

19%

5%

2030 - Reference

12%

42%

44%

2%

2030 - GHG constraint w ithout nuclear

25%

0%

72%

3%

2030 - GHG constraint w ith nuclear

51%

21%0%

27%

1%

Figure 6.61. Structure of the electric energy generated in Belgium in 2030, according to the scenarios. [%]

Ref. [FPB, 2007]

The percentages have been quoted above and are obvious from the figure. Especially the two bottom panels are to be compared, since they show the relative influence of nuclear power on especially gas dependence. The gas dependence reduces from about 70% to roughly 30%. It must be noted, however, that the breakdown of primary energy sources for electricity generation is based on annual energy amounts (being the power integrated over the period of one year). In terms of instantaneous power generated, the mix may be quite different, whereby gas may be very dominant (>90%) for certain periods of time, when meteorological conditions are less favorable for wind-generated power. Because of the limited storability of gas, this very substantial dependence on gas may be a cause for concern, especially in the electricity sector. In case of difficulty, the only relief may come from electricity import. But, if all neighboring countries are likewise dependent on natural gas supply, and if meteorological conditions are similar, import of electricity might not be readily available. The influence of the electricity generation mix has its consequences also for the overall energy dependence of the country. This is discussed in the next Subsection.


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a.2 Structure of the Primary Energy Needs of Belgium The changes within the alternative EU scenarios, regarding the final energy consumption and the electricity generation, also have their effect on the structure of the primary energy provision of Belgium. Since Belgium, with the exception of renewable sources (domestic generation of biomass, wind and solar), does not have any own energy sources (such as fossil and uranium) at its disposal, it is obliged to import them. This import concerns coal, natural gas and petroleum products, uranium in case nuclear power is utilized, and biomass when the demand exceeds domestic production. Since the import of oil and gas encompass great economic and geopolitical risks, considerable concern is raised, not only for security of supply reasons, but also more generally, for the 'health' of our economy. To just mention one aspect, price fluctuations can lead to hesitations on many different markets, they hamper investments and can jeopardize the competitiveness of the companies. Figure 6.62 displays the change in import dependency of primary energy sources, according to the different EU scenarios considered.

NOTE: OIL IMPORTS INCLUDE THE MARITIME BUNKERS THAT ARE NOT PART OF THE PRIMARY ENERGY DEMAND (=ENERGY NEEDS OF

THE COUNTRY)

Figure 6.62. Change of the energy needs and energy import of Belgium, according to the scenarios [ktoe]. Ref. [FPB, 2007]

In the scenarios shown in Figure 6.62, our import basket remains dominated by oil. It should be noted, however, that although the level in 2030 in all cases is above the level of 1990; there is some stabilization (and even a slight decrease) of the import with respect to the year 2000 (not shown on the figure). From the projections, it follows more and more that oil is mainly used in the transport sector. This evolution is a consequence of two opposing trends: on the one hand, transport activity increases; on the other hand, the market share of oil decreases in the other sectors, and the energy efficiency of vehicles improves. As already pointed out, the alternative scenarios lead to minor changes in the transport sector and therefore lead to little change in the oil import. Regardless of the scenario, the gas import increases substantially by 2030, especially in the scenarios without nuclear power. Indeed, that gas import is especially needed for the electricity sector and some sectors for final energy consumption (i.e., heat production in industry and the residential sector). As already alluded to in the discussion on the electricity-generation basket, the nuclear phase-out issue is an important factor for natural gas dependence. In the scenarios without nuclear power, the demand for gas in the end-use sectors diminishes as a consequence of implementation of energy-

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saving measures, but in the electricity sector the market share of gas rises substantially. (See also Figure 6.60 and 6.61). In 2030, more than 50% of natural gas import is designated for the electricity sector. Conversely, without nuclear power, and seen from the electricity sector, more than 70% of the energy mix in that sector originates from gas import on an annual basis. If considered on an instantaneous basis (taking into account the intermittent nature of especially wind) during some periods of time, this gas-import dependence can become close to ± 90% unless one chooses to import the lacking electricity.

188

But also in the scenario with nuclear power, the overall energy system is more dependent on natural-gas import than in the past. The electricity sector, however, is less vulnerable now than in the non-nuclear scenario since the share of natural gas in that sector is now limited to 27% (see also Figure 6.61). Finally, the imposed constraints for GHG reductions lead to an increase in renewable energy 'production' in Belgium. In energy terms, and on an annual basis, this domestic 'production' improves our primary energy-import basket. For our energy dependence (on an annual basis), this is a positive evolution, which is, however, to some extent offset by the intermittent character of many of these renewable sources, leading to an important electric-system challenge in terms of instantaneous electric power delivery. In the scenarios considered here, the share of renewable energy sources (in terms of energy on an annual basis) as part of the total primary energy consumption, increases to about 7%-8%, compared to only 1.5% in 1990. This is shown in Figure 6.63.

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Figure 6.63. Change of the share of renewable energy sources (on an annual energy basis) as part of the total energy consumption in Belgium, according to the scenarios [in %]. Ref. [FPB, 2007] b. Cost Consequences of the EU scenarios b.1 Cost for Domestic GHG Abatement in Belgium To get some idea of the cost of the EU-based GHG constraints for domestic reductions in Belgium, we provide here some figures that indicate the change in energy costs depending on the scenarios considered. For the electricity sector, Figure 6.64 shows how the average generation cost of electricity (and steam) changes with the scenario considered. In the baseline, the cost increases by 36% between 2000 and

188 Note, however, that periods characterized by very low wind speeds, may simultaneously affect relatively large parts of Western-Europe. Hence, wind generation would then be low almost everywhere, such that neighboring countries are faced with similar problems.


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2030, especially as a consequence of the nuclear phase out combined with increasing prices in mainly gas (and somewhat of coal). In the scenario without nuclear, the average generation cost increases even more (+ 63% between 2000 and 2030), while the CO2 emissions of the sector decrease by 41% compared to the baseline. As we recall from Figure 6.54, in this scenario, the energy-related CO2 emission in Belgium is 1% lower than the level of 1990 (blue curve in Figure 6.64). This evolution is a consequence of the following combination of elements: a larger usage of natural gas, with considerably higher gas prices (because it also incorporates the price of emission permits that reaches 200 €/ton CO2-eq in 2030), a much larger electricity system in terms of capacity (i.e., higher investment cost), while at the same time the electricity generation decreases due to a lower demand.

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In the scenario with nuclear energy allowed, the average electricity generation cost also increases compared to the year 2000 (+17%), but the increase is much smaller than in the baseline or in the scenario without nuclear energy. The most important reason is that the existing nuclear power stations, which are basically completely depreciated, have a much lower average electricity-generation cost than new power stations, regardless of the type. In fact, in 2030, the current 7 nuclear units would generate about 40% of the electricity. This element assures that there is less need for more expensive electricity generation means (such as gas and intermittent renewable sources). These cost considerations also show that the existing nuclear power stations are a cheap way of reducing CO2 emissions in Belgium, avoiding the need to reduce emissions abroad and thus avoiding the need to buy emission permits on the European emission-allowance market. Said otherwise, closing nuclear power stations amounts to a large opportunity cost. For the usual final-energy consumption sectors, the following figures (Figure 6.65-6.68) show the energy costs for each of the scenarios considered. To understand the cost changes, it is important to mention that these energy costs include costs related to the energy-conversion equipment (fixed and variable costs), the costs of purchasing fuel and electricity. It is recalled that in the PRIMES model, the electricity price is related to the average generation cost.


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Figure 6.65. Energy cost per unit added value and CO2 emissions for industry. Ref. [FPB, 2007] (*) Costs are in €2000 per thousand €2000 of added value.

Figure 6.66. Energy cost per unit added value and CO2 emissions for the service & commercial sector. Ref. [FPB, 2007] (*) Costs are in €2000 per thousand €2000 of added value.

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Figure 6.67. Energy spending/expenditure per family and CO2 emissions for the residential sector. Ref. [FPB, 2007] Costs are in €2000.

Figure 6.68. Total cost per passenger-km & per ton-km and CO2 emissions for the transport sector. Ref. [FPB, 2007] (*) Costs are in €2000. b.2 Cost of Purchasing Emission Allowances Abroad Figure 6.54 has shown that domestic reductions of GHG and CO2 on the Belgian territory are considerably smaller than the 30% GHG reduction limit prescribed on a European scale. Especially when nuclear energy is phased out in Belgium, the marginal abatement cost (MAC) is too high to reduce emissions domestically. As a consequence, and to fulfill its reduction obligations in terms of responsibility, emissions that are not reduced domestically must be reduced abroad, e.g., via the purchasing of emission allowances. It

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is recalled that the scenarios represented in Figure 6.54 all assume that a fully fledged emission trading scheme exists, in all sectors, and for all GHG emissions. This is also how PRIMES works for energetically-related CO2 emissions. Therefore, with such basically unlimited flexibility, an equitable burden sharing within the EU is basically a non-redistribution of the responsibilities.

189 (Recall from Section 3.2 that an unequal burden

sharing for emission-reduction responsibility only makes sense if the flexible mechanisms can only be used to a minor or limited extent, or in case of discrepancy of welfare between countries.) Therefore, fully in line with a full-scope emission trading scheme on a European scale, it seems reasonable to assume that Belgium will have to accept at least (see footnote) a 30% reduction-responsibility limit. It is sometimes argued that because of its high marginal abatement cost, certainly if the nuclear phase out is implemented, Belgium might get away with a lower burden sharing within the EU. But as explained above, such argumentation is based on an erroneous interpretation of equi-marginal reduction, in that domestic effectuation of reduction is not the same as reduction responsibility. Even if such lower burden sharing would be attained upon the strict condition that these reductions are to be obtained domestically, with no permission to participate in flexible mechanisms, it would still mean that the other EU countries would pay, e.g., for the Belgian phase out. If Belgium on top of that, would be allowed to participate in flexible mechanisms, then Belgium would really benefit from a very light burden. In the light of the uncertainty on this burden sharing, and the fact that we are looking at a horizon of 2030 (when flexible mechanisms are expected to be used at full speed), taking into account that all EU countries will defend their case, and considering the long lead times for decisions in the energy scene, it is only reasonable to consider here the case that Belgium will be faced with a GHG-reduction responsibility of 30% in 2030 compared to 1990. That means that besides the costs of domestic reductions, which have been considered for the different sectors in Section b1 just above, and which will be considered more globally and approximately here, Belgium will have to buy a certain number of emission certificates (on the EU certificate market). The cost for emission reduction to be carried by Belgium is explained via Figure 6.69. The horizontal line represents the price of the emission permits (or allowances) in the EU. The segment OA is the required emission reduction responsibility for Belgium. Belgium will only reduce its domestic emissions up to point D instead of point A, thereby carrying a domestic cost represented by the area ODC. It will therefore avoid the domestic reduction cost DCBA, but it will have to purchase emission certificates for a cost of the area AEC'D', instead. The amount saved by using emission certificates is the triangular area CEB.

Figure 6.69. Explanation of the cost to reduce emissions by an amount OA ton GHG/a. (Note that on the abscissa, "volume" actually stands for tons of GHG to be reduced.) The ordinate is €/ton, and the curvilinear curve represents the marginal abatement cost. In this example, the MAC curve for a continued use of nuclear power is assumed to be given.

189 Here we temporarily disregard the fact that some EU countries are less well off than others. If the prosperity of EU countries would be taken into account, with a philosophy that the strongest shoulders should carry the biggest weight, then the type of rich countries such as Belgium might be requested to carry an even larger % burden than the EU.


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In 1990, the amount of GHG emitted in Belgium was 144.3 Mton/a. According to Figure 6.54, a reduction of 26% would take place in the "with nuclear" case in 2030 (compared to 1990). This translates into a GHG reduction amount of 37.5 Mton/a in 2030. In 2030, the price of the Carbon Value, or thus the emission certificated price is 200 €/ton CO2-eq.

190 This value determines the point C

in Figure 6.69. To find an order of magnitude of the domestic abatement cost, we roughly assume that ODC in Figure 6.69 is a triangular area. The cost for domestic reduction in 2030 is then approximately ~ 37.5 Mton/a * 200 €/ton / 2 = or 3.75 G€. Because of the overestimation, we take as a figure about ~ 3 G€. Compared to the GDP of Belgium

191 of 2030, this would amount to about 0.7%.

The cost for purchasing emission certificates in this non-nuclear phase-out case, is given by the area AEC'D', which is equal to AECD. Assuming a 30% reduction responsibility for Belgium, this means that for 4% of 144.4 Mton must be bought abroad. The cost of this would be about ~ 5.8 Mton * 200 €/ton or 1.2 G€, or rounded roughly 1 G€. The total cost of GHG abatement in the year 2030 with nuclear power allowed would then be of the order of ~ 4 G€, or roughly 1% of the GDP. This total cost is represented by the total area OCEADO of Figure 6.69. Based on the evolution of GHG reduction as shown in Figure 6.55b, the GHG emission reduction is roughly constant from 2025 onwards. Assuming that the CV is about the same in 2025 as in 2030

192,

this means that about the same cost figure applied during each year from 2025 till 2030. In the earlier years, the cost is expected to be somewhat cheaper because less reductions take place (albeit that the CV value may be a bit higher then). Averaged over a 5-year period, the GHG abatement cost is therefore similar to 2030, also as a percentage of GDP. To find out what the extra cost of a nuclear phase out means, we consider the different panels of Figure 6.70. Now, an extra MAC curve has been added, portraying an increase due to the nuclear phase out

193, since a cheap CO2-reduction means is given up. Starting on the top left, the top panels

give the situation with nuclear power, as explained above. The middle two panels give the situation in case of a nuclear phase out, whereas the bottom panels give the difference between the two. The last panel therefore gives the extra cost due to a nuclear phase out (this is the balance between less domestic reductions, but at a higher marginal cost and the extra emission certificates that must be purchased abroad). The extra cost in 2030 is therefore given by the triangular area OGE. From Figure 6.54, the difference in domestic reduction, reflecting the amount HD, equals 14 %-pts, or about 20 Mton/a. Again with a cost of a CV of 200 €/ton, the extra cost is about ~ 20 Mton/a * 200 €/ton / 2 or 2 G€/a in 2030. The extra cost due to a nuclear phase out adds about 0.5% of GDP. Also in this case, the cost can be assumed to be constant over the period 2025-2030. The given figure is therefore a good order of magnitude of the average annual cost in that period. Integrated over these 5 years, this amounts to about 10 G€. Before that period, especially because the nuclear phase out would occur stepwise from 2015, 2023 and 2025, the extra costs would be smaller. As a rough estimate, for the period 2015-2025, the total integrated cost over that 10-year period will be of the order of 5 to 10 G€. In summary (and subject to the assumptions given earlier), the extra cost due to the nuclear phase out is estimated at 15 to 20 G€ over the period 2015-2030, which amounts to roughly 5-7% of the average GDP of one year of that period. On an annual basis, an extra cost of 0.5% seems a reasonable estimate. As to a possible re-injection of GHG-related revenues, the issue has been discussed in an earlier Section 6.3.1.2. The bottom line there was that the overall cost to society will be larger anyway than

190 For simplicity, we ignore that there is a small difference in the EU emission-allowance price between "with nuclear in Belgium (190 €/ton)" and "without nuclear in Belgium (200 €/ton)". We take as "averaged" figure 200 €/ton. 191 According to Table 7.1, the GDP in 2000 equals 248 G€ in 2000 and is projected to rise to 403G€ in 2025 and 432 G€ in 2030, all expressed in €_2000. 192 This assumption is based on a combination of Figures 5.10 and 5.12. 193 In reality, a shift of the MAC curve to the left should be added.


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what the PRIMES simulations show. Furthermore, it must be recognized that all emission permits purchased on the international certificate market do not lead to revenues for the Belgian economy.

Figure 6.70. Explanation of the extra cost due to a nuclear phase out if Belgium were to be responsible for a reduction of the emissions by an amount OA ton GHG/a. (Note that on the abscissa, "volume" actually stands for tons of GHG to be reduced.) The ordinate is €/ton, and the curvilinear curves represent the marginal abatement cost for the cases with and without nuclear power. The EU permit price is given by the horizontal line.


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7. Comparison with other Studies & Authoritative Documents 7.1 Tobback Climate Study In parallel with this CE2030 study, the Federal Planning Bureau (FPB) has developed a different PRIMES-based study as part of the report, "The Climate Policy beyond 2012", by order of the Environment Minister Tobback. [FPB, July - 2006] It must be stressed that those PRIMES results have little relationship with the activities of the CE2030 and the study performed by the FPB for our purposes, because of a totally different aim and boundary conditions. First, the time horizon is 2020 instead of 2030. Some elements have been extended to 2030, but they have been incorporated in the EU-wide scenarios reported here in this final CE2030 report. Second, it must be recognized that by 2020, less stringent GHG reduction limits are expected than in 2030. Therefore, the conclusions of that study have little to do with the results presented here. Third, all scenarios for that study implement the nuclear phase out, but since the time horizon is only 2020, only about 1/4 of the nuclear installed capacity would have been taken out of service. This means that the situation is not nearly as critical as in 2030, after a complete phase out, and when more stringent CO2 limits are likely to be imposed. Fourth, because of the limited time horizon 2020, the assumed fuel prices (oil and gas) are only 80% of what they would be in 2030. Fifth, that study considers reductions of all GHG in a European context, whereas this final CE2030 report presents PRIMES scenarios for domestically energy-related CO2 reductions, and the Belgian consequences of an EU commitment. The Tobback study starts with an analysis of GHG emission reductions in Belgium according the principle of equal marginal abatement costs throughout Europe, and then explores the impact of specific policies and measures to achieve further reductions. Effectively, this equal marginal abatement costs approach gives rise to a lower burden sharing for domestic CO2-reduction commitments for Belgium as a consequence of higher Belgian abatement costs (which are to a large extent due to the by 2020 already executed partial nuclear phase out). In this report, thanks to the FPB [FPB, 2007], the results of the Tobback study have been generalized. However, rather than counting on a favorable burden sharing for Belgium, we have taken the attitude that Belgium should commit to similar GHG reduction obligations in terms of responsibility. Those CO2 emission reductions not effectuated domestically, because of being too expensive, will be compensated for through the purchasing of emission allowances abroad. Sixth, that study assumes revenues from the CO2-abatement policy, being the integral/sum of the marginal abatement costs, which are then re-injected into the Belgian economy. This can only be done if indeed CO2 taxes are imposed (or emission certificates are auctioned) so that revenues are collected. Note, however, that the choice of instruments is a complex issue because: 1) re-injecting the revenues into the economy only matters if there are important labor and other taxes; 2) but if there are important labor and other taxes (which is effectively the case), the cost to the economy of any environmental improvement is higher than presented in a partial equilibrium model like PRIMES even if the revenues are recycled; 3) so we run the risk of stating that costs become lower because of re-injection of revenues, but this is only part of the story. Seventh, the scenario ‘designated’ -30% in that study reaches only a CO2 reduction of 25%, by qualitatively invoking the flexible mechanisms, because of steeply rising CO2 abatement costs. In our case, we force the PRIMES model to satisfy the imposed reduction, but only afterwards make the relationship with GHG reductions on an EU level. In conclusion, the PRIMES part of the Climate Policy study calls on the same energy model, but addresses different issues than in our study, where the behavior, the reliability of the energy system


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and the security of supply issue, with all its intricacies, is primordial. As regards the climate issue, the two studies complement rather than contradict each other. See also [FPB, 2007] for more explanation on the relationship of the two studies.

7.2 DLR Study (Commissioned by Greenpeace) A scenario study similar to the present exercise has been prepared by the German DLR Institute in Stuttgart. [DLR, 2006] The study was commissioned by Greenpeace. Results became available in the course of CE2030 activity. Their 'Energy revolution' scenario leads to about - 30% GHG emissions in 2030, which makes results comparable with the CE2030 Bpk30x scenarios, even if the approach and software used (PlaNet) is quite different. In contrast to the CE2030 scenarios, energy savings in all sectors have been imposed to achieve the GHG emission reductions. Nuclear being obviously absent from their scenario, the best comparison is to be made with the Bpk30 and Bpk30s. Figure 7.1 makes a comparison for the renewable energies contributions from both studies. As can be seen on this figure, the CE2030 scenarios are even more optimistic for wind, somewhat less for biomass, and —in particular— far more booming for PV in three out of the four scenarios shown. In the DLR case, an average growth rate for PV of 29% is observed, which is not that much in excess of the 25% maximum considered by CE2030 in its "reality-check" post-scenario analysis. The DLR assumes green electricity import which was not even considered in CE2030.

Comparison DLR (Greenpeace) - CE2030 for

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Comparison DLR (Greenpeace) - CE2030 for primary

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Corresponding annual energy intensity reductions are shown on Figure 7.3. The intensity reductions obtained in the CE203 scenarios are in excess of the reductions from DLR in the case of nuclear phase out, and equal in the case of no CCS and nuclear allowed. All these reduction rates are to be considered as challenging, with costs increasing exponentially with reduction rate.

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Differences in both studies therefore mainly reside in the cost figures of the scenarios, and mainly in the cost of reducing the energy intensity from 1.6% per year to 2.9% per year over a long continuous period of time. The DLR study sounds optimistic in assuming deep saving costs in the range of 45 €/MWh, whereas PRIMES predicts much higher costs which contribute to the extreme high carbon values observed. This DLR scenario furthermore seems to underestimate the importance op security of supply on the electricity side. Of the 90 TWh electricity demand assumed in 2050, 20 TWh (or 22%) would be thermally generated in Belgium, 38 TWh (or 42%) would be generated by domestic renewables, whereas 32 TWh (36%) would be imported renewable electricity (according to a preceding European Energy Revolution study by DLR [DLR, 2005]) being imported PV electricity from North-Africa. Because of the high variability of most of these renewable sources, the security of supply challenging in terms of power

194 (instead of energy) will be overwhelming, if not virtually impossible.

7.3 IEA WEO 2006, EU Climate Package, Stern Report, IPCC AR-4, IEA Review of Germany and the UK Energy Review Without going into detail, it is remarkable that since the last two or three years many organizations have considered nuclear power as one of the elements that may be, or will be, needed towards a secure, affordable and sufficiently clean energy provision. Although the "endorsement" of nuclear varies in the nuances, it is clear that there is a major shift in attitude. The following documents should be mentioned.

• For the first time, the IEA WEO 2006 [IEA, 2006d] clearly stipulates that nuclear power will have to be part of the solution;

• In its Energy Package of January 10 2007, the European Commission has recognized explicitly that it wil be very difficult to find an acceptable solution for the EU energy provision towards 2030, under a stringent GHG limitation, without nuclear;

• The widely publicized Stern Report [Stern, 2006]; although not mentioning nuclear power explicitly in its Executive Summary (always talking about carbon-free technologies), it is clear from the main report that nuclear power is considered as one of the possibilities (together with renewables and CCS);

• Because of the very challenging situation on the combined climate-change and energy scenes, in its Fourth Assessment Report (AR-4), the Intergovernmental Panel on Climate Change (IPCC) has recently considered that nuclear energy may have a role to play (together with other low-carbon technologies) as part of the solution against Climate Change. [IPCC, 2007c]

• The recent IEA 2007 Review on Germany [IEA, 2007b], after studying the whole German energy picture, states literally: "For these reasons, we strongly encourage the government to reconsider the decision to phase out nuclear power";

• The UK Energy Review, published in 2006 [http://www.dti.gov.uk/energy] and for which currently a public consultation is taking place, has clearly opted for a continuation of nuclear power as part of the UK energy policy. [DTI, 2006; 2007].

194 Here "power" as a flux, flow or, more accurately, as the time derivative of energy is meant.


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Part III

The Broader Energy Picture in Belgium


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8. Some Elements of the Belgian Liberalized Energy Markets In this section, we offer some reflections to guide certain policy decisions on liberalized energy markets, on the one hand, and give some considerations to be kept in mind when reading the results of PRIMES, on the other hand.

8.1 General Observations on the Belgian Liberalized Markets Recall that Part I of this report provides the basic elements of the Belgian energy situation. The IEA Belgium 2005 Review [IEA, 2006a], in addition gives a photograph of the current situation on the Belgian market (actually somewhat more than a year ago). We remind the reader also that we focus on the Belgian energy situation with a horizon of 2030, meaning that as a rule short-term issues are not addressed, unless they have an impact in the long run. We assume that (North-West) Europe will (have to) function as a common energy market and that national policies will have to be commensurate. In that regard, we take it for granted that for conduit-guided energy carriers (such as electricity and gas) unbundling will be enacted by that time and that electricity, generation and supply/delivery are competitive branches, while grid management (investment, maintenance & operation), both for transmission and distribution, being natural monopolies, should be under the regulatory control of the authorities.

195 Likewise for the gas sector, shippers and suppliers should be in the free-market branch,

while the networks are to be a regulated activity. It has become clear that there is no unbundling needed between the generation (shipper) branch and the supply branch. Only the grids have to be taken out of the competitive sphere. The question of the geographic scale of competitiveness should be raised. Although one still has a natural reflex to focus on national territories (in many cases similar to the control areas of a particular TSO), recent understanding of the energy markets seems to indicate that local market dominance of a particular player is not necessarily to be rejected, as long as the market dominance is not abused. This applies in particular to electricity generators. To avoid market-power abuse, it is necessary to have sufficient cross-border transmission capabilities, on the one hand, and a strict but correct regulatory supervision, on the other hand.

196

Related to the above issue, the philosophy of price formation is to be addressed. In a full fledged (sufficiently large) open market, backed up by sufficient transmission capacity (cross border and also domestic), in which there is sufficient competition, the prices are in principle determined by the short-run marginal generation unit in the overall geographic area that is considered to be the common-market area.

197 For us, this is especially the North-Western European market, consisting of France,

Germany, the Netherlands and Belgium & Luxembourg. As matters stand today, the price is set either by gas-fired units or by coal-fired units taking into account the price of the CO2 emission allowances. The provided price information given in Section 2.2.1 of this report shows that the evolution towards a real NW-European market seems to be in the making. It must be stressed that the wholesale prices are not set by cheap nuclear electricity in France or Belgium. This even leads to yet another paradox. A dominant local player with cheap base-load generation means should not lower his prices below the market price, because in doing so, he could squeeze out competitors who do not possess such cheap generation capacities.

195 Whether this is to be guaranteed through legal unbundling or ownership unbundling (and how this is to be considered with blocking minorities) is left to legal experts; in any case must sufficient corporate governance be guaranteed. If legal unbundling does not work, then full ownership unbundling and the possibility of establishing an Independent System Operator (i.e. an operator without assets; usually referred to as ISO), is to be studied carefully. The idea of an ISA has been launched by the CEU in its Energy Package released on January 10, 2007. 196 See the Informative Box in Section 2.1.6.2.b of Part I for what we called there the paradoxes of cross-border transmission. 197 Appropriately corrected for the transmission fee.


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Informative Box. Price Formation in a Liberalized Electricity Market The general relationship between cost and price has been explained in an Informative Box in Section 2.2. Here, the principles for the electricity market are recalled. It must be recalled that in a liberalized market, the price is set by the market. Assuming a fully competitive market, the price is set at the intersection of the demand and the supply curve, whereby the latter is the (short-run) marginal-cost curve for production. Hence, the market price is determined by the cost required to produce the last unit, e.g., electric kWh. This does however not mean that the market price disregards the costs ‘suffered’ earlier for investment. On the contrary, fixed costs have an impact on investment and investments determine the (short run) marginal cost curve of the future. For perfectly competitive electricity markets, the following picture applies:

Determination of the market price in a competitive market. The price is determined by the intersection of the demand curve and the supply curve whereby the latter equals the marginal cost curve for generation. In addition, the full cost of each unit is shown.

The above, only refers to the price set for the commodity itself. In addition, extra costs will be added for transmission,

198 distribution and administrative costs. This will lead to a higher price. To stay with

the electricity market, the first and the last steps of the chain, i.e., generation and supply, are supposed to be competitive, whereas the intermediate steps, transmission and distribution, are monopolistic with regulated tariffs. The gas market is in this regard similar to the electricity market.

In this regard, the issue of earlier written off nuclear power plants and cheap operation of nuclear power is often cited as a relevant issue in the discussion. [CREG, 2006a; Global insight, 2006] This is related to the issue of stranded benefits as opposed to stranded costs, an issue that was common talk when gas prices were very cheap in the nineties, and when possessing nuclear power was considered to be a handicap. Today, the swing is in the other direction, and nobody knows how this will evolve in the future. A similar reasoning applies to earlier written off coal-fired plants. The CE2030 is aware of these elements, and it observes that the viewpoints of the above references are disputed by corporate finance experts of the operator concerned. The CE2030 recommends that an independent international expert panel of corporate finance experts and energy economists (from academia and regulators, from OECD countries with liberalization experience, preferentially from far overseas —e.g., USA, Canada, Australia) be convened to advice on these issues, after hearing and interacting with all sides, amongst which the Belgian Regulator and the operator concerned. This issue of Infra marginal rents is explained in the Informative Box "Infra-Marginal Rent, Windfall Profits, Mothballing".

198 Transport and transmission are synonyms


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Informative Box: Infra- Marginal rents, Windfall Profits, Mothballing In an economic context, a marginal cost is the cost to produce one extra unit of a particular product; in the electricity generation context, the marginal unit is known as the last unit that is put into operation. The market price is set by the marginal unit of the overall electricity generation system considered (see Informative Box "price versus costs"). The rent or profit gained on the marginal unit of a particular producer is called the marginal rent. The rent gained on previous units is the infra marginal rent. These concepts can be clarified by an example. Assume that the electricity market price is 35 €/MWh in a low demand period and 50 €/MWh during a peak load hour and that there is a generation system with two types of plants: type A plants with a generation cost of 25 €/MWh and type B plants with a generation cost of 37 €/MWh. Assume furthermore that total capacity of type A equals 5 GW and that capacity of type B equals 3 GW. If demand during a particular hour of the day equals 4 GW then type A capacity is sufficient and the marginal unit is a type A plant. The marginal rent equals (35-25)=10 €/MWh. When demand is high (e.g., 7GW) then the marginal unit is a type B plant and the marginal rent equals (50-37)=13 €/MWh. However, the rent gained on the type A plant is higher due to the difference in generation costs. This difference in generation costs gives rise to an infra marginal rent, i.e., on the unit 'below' the marginal unit, of (37-25)=12 €/MWh. Total gains on type A capacity equal the marginal rent plus the infra marginal rent thus (13+12)=25 €/MWh.

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Infra marginal rents thus exist because different technologies with different costs are used simultaneously. Windfall profits are profits that are earned unexpectedly, through circumstances beyond the control of the company concerned. This unexpectedness is sometimes used in the political sphere as a justification to impose a tax on that profit. Whether infra marginal rents are windfall profits depends on their unexpectedness. An example often given is that the internalization of the cost of greenhouse gas (GHG) emissions for gas and coal fired plants will generate an extra profit on nuclear generation plants and therefore should be taxed. Since these emissions costs are part of the generation costs of fossil fuel plants, these windfall profits are to be considered as an additional infra marginal rent for nuclear generation. This is illustrated below.


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The term mothballing is used to describe the preservation of a production facility without using it to produce. Mothballed facilities are kept in working order so that production may be restored quickly when needed. E.g., some older coal fired electricity plants in Belgium are mothballed and can be used in case of urgent need. Companies that deliberately and unreasonably mothball certain plants in order to artificially reduce cheap generation capacity so as to push up the market price, may have to be subjected to a so-called mothball fine imposed by the Regulator.

In Belgium the term mothballing has recently been used in a different context. It refers to gains earned from plants that are fully depreciated and thus do not incur fixed costs. As such, owners of these depreciated plants earn an extra profit. This extra profit is yet an extra (infra) marginal rent, actually of the windfall-profit type, as can be seen from the graph below.

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As for windfall profits, ideas have also been launched to tax this extra revenue (erroneously referred to as a "mothball tax").

On price formation, policy makers should also understand that increasing fossil fuel prices and levies/taxes are reflected in the prices. The first factor is to be accepted (with little chance to be corrected in the medium term since it is the marginal unit that determined the price); the second factor is in the hands of policy makers themselves. There should always be a good reason to impose taxes/levies and once decided so, policy makers should not feel uneasy about subsequent price increases. We recall likewise the observation made in Part I on transmission and distribution tariffs. The regulators are advised to accept the costs for major investments in the grids (domestic and cross-border transmission, and for smart-grid adaptation on the distribution side) to ameliorate the later functioning of them in supporting the market and the entry of all kinds of generation. This means that transmission and distribution fees might have to increase now, to be able to reduce overall customer prices later. Furthermore, the Commission Energy 2030 pleads for the medium term to launch an experiment for going towards real-time pricing with smart metering for electricity and gas, so as to provoke appropriate demand responses. Customers must feel the economic value of energy carriers. A decoupling of the price signals for consumers through social tariffs should be done for a limited group only and after careful reflection and in well thought-through circumstances.


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Concerning European mergers in which Belgian energy players are involved, the Belgian authorities should reflect on how the energy-related interests of the Belgian nation can be guaranteed. Clearly, such decisions must fit in a European approach, but it should be checked whether a golden share or supervision by European Commission services, to guarantee a sufficient supply security in Belgium in any circumstances in the future, should be called for.

199 In that regard, the idea of stronger European

regulatory powers should be endorsed. Finally, some words on sufficient investment in capacity in liberalized markets are appropriate. For generation capacity, it is currently recognized that market signals might be insufficient to guarantee timely investments. [L. Meeus, K.U. Leuven, private communication; Cramton & Stoft, 2006]. A first condition for timely generation investment is a correct and stable regulatory framework, but if current market design is inadequate, then adjustments must be considered (after which regulatory stability clearly must return). Experts argue in favor of forward-capacity-market arrangements (in addition to energy markets) to guarantee sufficient investment. As a response to the 2003 black-out in Italy, the EU security of supply Directive

200 was introduced to boost investment in

infrastructure in Europe. Member states can now intervene choosing a number of regulatory measures to stimulate investment in generation capacity. However, measures should be market based and non-discriminatory (and could include measures such as contractual guarantees and arrangements, capacity options or capacity obligations). Regarding transmission capacity, the point on tariffs and investment has been made above. However, an additional element must not be forgotten. Sufficient 'functional' international transmission capacity is not evident, as three functions need to be fulfilled by the transmission lines: 1) as a resort in case of incident, to allow instant in- or efflux of power across the border (the function for which the current transmission capacity was dimensioned); 2) to allow trade of electricity; and 3) to equalize imbalances of massively concentrated and correlated fluctuating generation sources such as wind power. It must be recognized that items 1) and 3) eat up a considerable margin of the transmission capacity for trade. Appropriate action, such as phase-shifting transformers, embedded HVDC links, coordinated redispatch together with further investment is to be contemplated. However, one should never compromise on the reliability criterion that the system still has to function whenever one component fails.

201

8.2 Liberalized Markets and the PRIMES Scenarios The version of PRIMES incorporates elements of liberalized markets in Europe. Import and export of energy carriers (fuels and electricity) is accounted for based on price signals in neighboring countries and the available transmission & transport capacity. [FPB, 2006 – Sept, footnote 12]. The behavior is based on a fully competitive and transparent European market. Electric transmission capacity is represented by the equivalent DC-load capacity. [Ref. Capros, 2006, private communication]. Electricity prices are computed via the Ramsey-Boiteux principle [FPB, 2006 – Sept, footnote 23], which is effectively a cost-plus approach. These elements are to be kept in mind when interpreting the PRIMES results. To mention a few deviations from reality, we can list the following points of attention. In fully competitive markets, prices are not determined on a cost-plus basis, but are set by the marginal generation unit. However, even this is only the case in fully competitive markets, and in reality strategic behavior of players should be taken into account, which makes it even more complicated. Also, cross border transmission occurs through several parallel lines, and local congestion may lead to redistribution of power flows (a.o., loop flows). Instantaneous equalizing of imbalances through fluctuating flows is not taken into account. Finally, we mention that investment in liberalized markets is not 'automatic', and requires time 'in the field' between decision, obtaining of the necessary permits/licenses, construction and operation.

199 A recent ruling by the European Court of Justice seems to jeopardize the idea of a golden share. 200 Directive concerning "measures to safeguard security of electricity supply and infrastructure investment". Available from http://register.consilium.eu.int/pdf/en/05/st03/st03654.en05.pdf 201 This is usually referred to as the N-1 rule.


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The mentioned items are not a criticism of models such as PRIMES, but serve as a blinking light to keep enough interpretative distance and not to lose oneself in the fine-details of the PRIMES results. Some birds-eye view perspective is necessary, without clearly forgetting the physical-technical requirements.


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9. Import Dependency, Security of Supply & Reliability

9.1 General Considerations The general issue of Security of Supply (SoS) has been discussed in Section 3.1. As has been explained in that Section, there are three elements to be considered when dealing with security of supply:

• strategic security of supply of primary sources, mostly in terms of 'energy', and often also referred to as energy (import) dependence;

• adequacy of investment for continued delivery of 'power'; • reliability to assure avoidance of sudden black outs.

The implications on the primary-energy basket and the electricity sector, of a stringent climate-change policy and the intention to phase out nuclear power in Belgium, have been illustrated in Chapter 6; in Section 6.4.2.3, the effects of a stringent domestic CO2-emission reductions were illustrated; in Section 6.4.3.2, the consequences for Belgium in the context of a European-wide limit on GHG reduction have been explained. In this chapter, some distance with respect to the performed PRIMES scenarios is taken, although they still serve as a general guide to project our energy consumption towards 2030, and the SoS issue is discussed in a more general framework. The following subjects will be discussed below. First, some general considerations are offered in this Section and then two detailed accounts on the SoS issue are given for natural gas supply and for electric power delivery, respectively. Then in two smaller sections we say a few words about oil and uranium resources. Finally, we end this chapter with a section on portfolio analysis. According to the BP Annual Energy Review of June 2006 [BP, 2006] the so-called R/P ratio (Reserve/Production), thereby "freezing" both numbers, at the end of 2005 are:

202

Ø oil 40.6 years Ø gas 65.1 years Ø coal 155 years

These R/P ratios, especially for oil and gas have remained almost the same for the last 20 years, showing that production and reserves

203 tends to follow demand, and respond favorably to the

investments made. The long-term availability of oil and gas by 2030 is disputed by some people, who claim that the Hubbert peak for oil production is about to be reached in a few years. [Ref. http://www.odac-info.org/; http://www.peakoil.net] This would mean that we are not necessarily running 'out of oil', but that we are running 'short of oil' since production would not be able to follow. These claims are in turn disputed by other connoisseurs in the field, who claim that sufficient supply will be available, if investments for exploration and exploitation are committed to timely [Davies BP, 2006; P. Terzian, private communication]. For gas, the physical presence of reserves and resources is believed to be guaranteed for a longer time. Having dealt with the physical presence and the production rate in normal circumstances, it must be addressed whether these fossil fuels will be delivered in time when and where needed. It should be recalled that certainly by 2030 both oil and gas will come from currently geo-politically sensitive regions.

202 The BP Statistical Review 2007, released on June 12 2007, gives the following numbers: oil 40.5y; gas 63.3y; coal 147y. 203 "Reserves" are those quantities that can be recovered with reasonable certainty from known reservoirs/deposits under existing economic and operating (i.e., technological) conditions. They are to be distinguished from the (ultimately recoverable) "resources".


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According to [BP, 2006], at the end of 2005, the geographical distribution of oil was as follows: Middle East 62%, Europe & Eurasia, 12% Africa 10%, South & Central America 9%, North America 5% and Asia Pacific 3%.

204 Towards 2030, the dominance of the Middle East will be even more pertinent than

today. For oil, there is "relatively" less worry concerning SoS, since the IEA obliges its members to keep a stock of three months. Also, local stocks of oil are usually foreseen, so that short-time interruptions of supply can usually be coped with. But, oil-fired applications are sensitive to interruptions, and lack of sufficient oil is more than a nuisance and a serious inconvenience; however, it is not 'life threatening'. Oil availability has more to do with oil-price setting than with actual physical delivery. For gas, the concentration is even more pronounced. Most gas reserves are present in Russia (in 2006 estimated as 48 trillion cubic meter, or Tm

3), Iran (27 Tm

3) and Qatar (26 Tm

3)205

. See Figure 9.1. [BP, 2006] The challenge for those countries to make the necessary investments in time and to keep the gas flowing will be considerable.

Major gas reserves

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Figure 9.1. Geographical distribution of the major natural gas reserves. From [BP, 2006]

In contrast to oil, lack of sufficient gas delivery is a major issue. Especially insufficient flow to fire the electric power plants, would lead to a substantial perturbation [Belmans, 2005; see also FPB, 2004b]. Timely gas delivery would indeed be crucial for an energy economy like the Belgian one where a nuclear phase out has been implemented. The gas supply issue for the Belgium is discussed in the next Section. Concerning the SoS issue on an international scale, the reader is advised to consult the IEA World Energy Outlook 2006 [IEA, 2006], which devotes some space to oil and gas investments, and the authoritative IEA Natural Gas Review 2007 [IEA, 2007] (concentrating on "Security in a globalizing market to 2015).

204 Numbers do not add up to 100% due to rounding off. 205 This is to be compared with Norway, the Netherlands and the UK with 84.9 Tm3 , 49.6 Tm3 and 18.7 Tm3, respectively.


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9.2 Security of Supply of Natural Gas for Belgium It will be recalled that the impact of a post-Kyoto policy on the primary energy basket, and gas in particular, in Belgium has been discussed above in Sections 6.4.2.3 and 6.4.3.2. Here the discussion is continued albeit from a somewhat broader view. For more details, see the Supporting Document [Dufresne, 2007].

9.2.1 The Consequences of Phasing Out Nuclear and Coal-Fired Power Stations

As discussed in Chapter 6, the PRIMES model estimates gas requirements by economically optimizing the cost of the energy system under different scenarios. For instance, in the CE2030 Baseline scenario with nuclear phase-out (and without post-Kyoto constraint), PRIMES replaces the decommissioned nuclear power plants from 2015-2020 on with a generation mix mainly based on coal and gas. In a similar approach on the nuclear phase out, in its indicative plan for natural gas supply 2004-2014 [CREG, 2004], the CREG published a forecast of the consequence of a complete switch from nuclear energy to gas (executing the nuclear phase-out law, to be achieved between 2015 and 2025). This switch induces an increase of gas consumption by the electricity generation sector of 5.1 Bcm/a at the end of the period (for an electricity generation of 43.9 TWh —see Table 9.1).

206 If in parallel with the

nuclear phase out, the currently operating coal-fired power stations (1573 MW) would be decommissioned and would be compensated entirely by a switch to natural gas CCGT, ensuring the same electricity generation (4800 h/a with 38 % efficiency for coal-fired plants), this would represent an additional gas consumption of some 1.2 Bcm/a (assuming 60 % efficiency for the CCGT). Based on the present electricity generation system of Belgium (and thus not taking into account the expected increasing electricity demand —see the next Section on electricity SoS aspects), a complete swap from coal-fired and nuclear power plants to natural gas CCGT would thus require some 6.3 Bcm/a of supplementary gas supplies in 2025-2030. This amounts to roughly an equivalent volume as the current gas consumption of the Belgian electricity generating sector. Concerning the influence of this switch on the peak load requirements of gas, the estimate made by the CREG (see Table 9.1) can be used as a reference. Indeed, the CREG has estimated that the required additional peak flow capacity reaches 710 k.m³/h

207 in 2025 under the assumption that all

nuclear power plants are exclusively replaced by gas-fired generation plants. As underlined by the CREG, although substantial investment would be needed to cope with that, this is manageable as long as plans are initiated in due time. However, this will require a constructive collaboration between the authorities (regulator(s), the responsible bodies at the federal, regional, province and municipal level, the administrations, all playing a role for providing/approving the necessary construction, environmental, operation permits) and the investors. Courageous and decisive decisions will have to be taken since these considerable investments will be reflected in the transmission tariffs; it will be a challenge to find the proper equilibrium between the public interest and a fair return for investors.

206 This has to be compared to the CE2030 Baseline scenario where the replacing power plants use mixed energy sources including natural gas of which consumption increases with some 2.8 Bcm/a between 2005 and 2030 in the electricity generation sector. 207 1 k.m3/h stands for 1000 m3/h.


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Nuclear power plants Swith to CCGT * Nuclear power plant

Closing date

Capacity MWe

Electricity generation

GWh

Annual gas consumption **

M.m³(n)/y

Peak flow natural gas k.m³(n)/h

Doel 1 12/02/2015 392.5 2980 346 48

Tihange 1 01/10/2015 962.0 7304 847 118 Doel 2 01/12/2015 434.5 3299 383 53 Doel 3 01/10/2022 1006.0 7639 885 124

Tihange 2 01/02/2023 985.0 7479 867 121 Doel 4 01/07/2025 985.0 7479 867 121

Tihange 3 01/09/2025 1015.0 7707 893 125

Total 5780.0 43888 5088 710

* Annually 90.3 % of electricity generated using nuclear power is covered by natural gas. Bearing in mind the back-up, a peak flow must be provided for the use of combined cycle gas turbine (CCGT) power plants amounting to 96.2 % at peak times.

** Account is taken of a forecast increase in capacity of 42 MWe in 2005.

Table 9.1: Switch from nuclear to gas based electricity generation according to the nuclear phase-out law over the period 2015-2025. [CREG, 2004]

9.2.2 Average Gas Demand versus Peak Gas Demand

It has to be kept in mind that the results given by scenario exercises often refer to yearly average consumptions. The year-based numbers obtained with PRIMES were presented in Chapter 6. However, gas consumption varies during the year, a can be seen from the example in Figure 2.8. The variations occur mainly in the distribution network and are due to fluctuating consumption in the residential and service & commercial sectors, where gas is especially used for heating. Direct deliveries to large industrial consumers and to electricity generators through the transmission network, fluctuate mainly on a weekly basis, reflecting the industrial use. For those large consumers, there is also a slight seasonal decrease from February to August, and an increase towards the winter season, partially induced by the electricity generation sector. Note that the range of variation may become larger as important climate changes become more concrete, thereby influencing gas consumption for heating purposes. On the other hand, gas consumption from the (large energy consuming) industries may reduce as the economy evolves to more services supplies, an evolution which may simultaneously be partly offset because of increases of electricity-equipment requirements. The further influence on gas consumption depends on the electricity generation plants used and how far gas-fired plants are used for base load or for peak supply.

9.2.3 Potential Future Gas Supplies for Belgium As before, all this gas demand in Belgium has to be imported. Figure 9.2 represents the potential gas demand and how so far it is covered by contracted supplies. To set the mind, the gas demand in the PRIMES scenarios is considered. Global gas demand is given in the baseline scenario and the higher fuel prices scenario as well as the magnitude in 2030 of total gas demand generated by the different alternative scenarios is represented by the oval disk.

208 As explained before, future gas demand will

likely be situated in-between the baseline and the -15% no nuc & no CCS scenario, the latter one being represented by (H) on Figure 9.2. The future gas demand is therefore situated near the high side. On the supply side, the origins of past imports (2000 & 2005) are represented in stacked columns. The expected capacity of the Zeebrugge terminal is also given: its capacity has been rising from 4.5 Bcm/a to 9 Bcm/a and Fluxys has already announced the project to bring this capacity to 18 Bcm/a [Pétrostratégies n°994 - 12/2006]. In 2005, about 59 % of the aggregated supply portfolio gas volume of the active suppliers on the Belgian market was still contracted through long-term contracts with producers (> 5 years). From the remaining 51%, 15 % is mainly under contracts with producers

208 For simplicity, only the alternative scenarios with domestic energy-related CO2 reduction are considered.


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expiring within 5 years, 2 % under contract of more than 1 year while the remaining 24 % were delivered under short term contracts [CREG - Annual report 2005].

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Sources : SPF Economie - Evolution du marché de l'énergie en 2005 (origins of imports), SYNERGRID - Flux de gaz naturel en Belgique (total imports) & own estimates. Figure 9.2. Potential gas demand and its supplies.209

Future gas supplies rely on several assumptions, the main one being that Distrigas, the historical supplier of the Belgian market, will still dedicate the volumes of its subscribed long-term contracts to the Belgian market. However, it should be kept in mind that within a liberalized market, there is no guarantee that all these volumes will effectively be delivered to the Belgian market, the relevant market for all operators (including Distrigas) having been enlarged to the European market. As commercial operator, Distrigas designs a portfolio of gas acquisitions which suits its gas sales in Belgium and outside Belgium. The same remark applies to other operators which will supply the Belgian market (nowadays it concerns Gaz de France Négoce and Wingas GwbH).

Potential gas supplies could still come from: - the Netherlands: the long term contract concluded with the Netherlands still represents 5.8 Bcm/a

in (H) gas eq 210

until 2016 when the contract with Gasunie ends. Distrigas has the possibility to extend its duration till 2020. Beyond 2020, the probability of extending this contract for a longer period will be small, the Dutch authorities having expressed their concern to preserve their declining gas reserves;

- Norway provides some 6 Bcm/a to the Belgian markets and has still sufficient gas reserves to

continue to do it for the next two decades. Actually, Norwegian gas deliveries have been contracted with Distrigas until 2010, 2011 and 2018, respectively. However it is worth mentioning that with the United Kingdom becoming a net gas importer, Norwegian gas has a new outlet market over there;

209 Total imports for 2000 and 2005 include volumes which are re-exported to Luxemburg. Spot markets include volumes from the UK (in 2005 0.4 Bcm/a) and other hubs which origins cannot be clearly identified. 210 CREG (2004) - Proposition de plan indicatif d'approvisionnement en gaz naturel, p. 62.


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- Algeria: the long term contracts concluded with Algeria (4.5 Bcm/a) have reached an end in 2006 and have not been renewed. However, Sonatrach has already expressed its interest in having access to the Zeebrugge terminal for the further deployment of its LNG exports [Ref: Pétrostratégies n°995 - 12/2006];

- a first contract has been concluded between Rasgas (Qatar) and Distrigas for import at the LNG Zeebrugge terminal of 2.75 Bcm/a for 20 years beyond 2007. Nevertheless, it is not guaranteed that this volume will end up in the Belgian market.

Until 2015, all these contracts are more or less sufficient to satisfy the expected gas demand (including some spot transactions). Beyond this time horizon, more than 50% of the demand has to be covered with new gas contracts. Indeed, besides these contracts concluded by the historical supplier, gas is, and will, also be provided by other gas suppliers. Consequently, it is even more complicated to make some guess of which volumes could reach the Belgian market since with the liberalization of the European gas markets, the relevant market for (formerly "national") operators has been extended to the European market.

9.2.4 Several Stakes behind an Adequate Gas Supply Besides concluding supply arrangements, security of supply has also to do with transmission capacities (LNG reception and network infrastructure) and flexibility measures as available storage. 9.2.4.1 LNG Import Infrastructure The capacity of import infrastructure has been extended at the Zeebrugge terminal. However, concerning the security of supply of the Belgian market, it should be underlined that: - increased capacity does not guarantee increased supply: the infrastructure is there but has to be

supplied by gas which relies on the initiative of buyers and also sellers. Indeed, LNG gives flexibility and increases the opportunities for its owner to sell gas in many places. In a context where gas demand increases worldwide and many new LNG re-gasification terminals are projected and/or installed, some competition could appear for this gas supply. In this respect having some LNG supplies benefiting from the frame of long term contracts is also interesting to secure some volumes;

- the LNG Zeebrugge terminal is an entry point to a well functioning hub which can be used for

arbitrage operations between several markets by operators who manage their gas acquisition portfolio in parallel with their sales which are not necessarily injected into the Belgian market;

- in view of a further important increase of the import capacity of the LNG Zeebrugge terminal, an

appropriate adjustment of security measures should be envisaged (e.g. technical incidents, terrorism, ..);

- the LNGRV (LNG regasification vessel technology) as developed by e.g. Exmar and which gives

the opportunity to directly deliver natural gas from the vessel on (after regasification on board) increases also the reception capacity of the place where such a vessel unloads. Another stake is relative to the capacity of the local transmission system and to the capacity of the consumer market to absorb almost instantaneously the delivered gas volumes. The presence of the Zeebrugge hub is therefore very important in order to manage these supplementary gas volumes in an optimal way.

9.2.4.2 Gas Storage Requirements

Gas has the advantage that it can be stored to a reasonable extent, which is quite interesting regarding the seasonality of demand in the medium term and also the variability of gas demand in the short run

211. To have a storage infrastructure at one's disposal, gives some flexibility for supply to

adequately respond to demand variation, and this more and more in a context where gas supplies will

211 Similarly to an electricity network, a gas network has also to be balanced on short delays to ensure a good working of the gas transmission within the network.


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be imported from more distant suppliers. (The nearby British and Dutch productions are rather on a declining trend. Moreover, their proximity has given so far the opportunity to benefit from very flexible conditions in delivered gas volumes, the Groningen gas field being used as "back-up" storage). Relying on more LNG also means that one has to adapt a batch flow of gas supply to a continuous flow of gas injection into the network, whereby an LNG storage capacity plays the role of a buffer between incoming and sent out gas. The capacity of the LNG storage is also important for the good operation of the reception terminal. In response to the decision to increase the capacity of the Zeebrugge terminal to 9 Bcm/a, a fourth tank is currently being built, thereby increasing the (buffer) storage capacity with 57 %. In the Belgian case, storage capacity is limited to LNG storage in Dudzele (55 Mcm of working gas for peak shaving) and to underground storage in the region of Loenhout (580 Mcm of working gas to be increased to 700 Mcm around 2009-10). Some prospects have been engaged by a joint initiative of Fluxys and Gazexport (100 % subsidiary of Gazprom) to develop another underground storage in the region of Poederlee which shares the same geological underground structure with Loenhout. The storage of an expected capacity of 300 Mcm should be operational in 2012. Nevertheless, when benchmarking storage capacities in Belgium with those in neighboring countries, it appears that the Belgian storage possibilities are rather limited (limited available sites). On this matter, it could be useful to prospect in neighboring countries (France, the Netherlands, Germany and even the United Kingdom) for seasonal storage capacity and to reinforce collaboration. However, considering these neighboring countries, their capacity to make some gas storage available is limited: Germany and France have the highest storage capacity compared to their consumption (22-23 %) but the declared available capacity is actually only about 0.3-0.4 % of technical capacity in France (0.35 Bcm) and Germany (0.73 Bcm). The Netherlands have a quite high ratio of storage compared to their consumption but it is also reserved for public service operation and for production; moreover, the two major Dutch sites are located in the North, in the region of Groningen. The British market has a very low storage capacity and has first to adapt to its new status of gas importer and to develop some gas storage for the balancing of its own market (increased capacity to 10 Bcm within the next five years). 9.2.4.3 Gas Supply and Liberalized Markets Even if some sources state that a reduction of the share of long-term gas contracts is a good thing for competition, flexibility and hence security of supply

212, this position has to be put into perspective since

relying significantly on spot transactions is not always convenient. The availability of long-term contracts has also certain advantages: - it reduces uncertainty for the parties engaged in the contract but also for instance for the TSO

which has to adapt the network infrastructure. Indeed, gas transmission needs a specific (and heavy) infrastructure that cannot be improvised: compliance with permission procedures and regulations is required and takes time;

- it secures the volumes concerned by the contract (possibly with some flexibility in the volumes

delivered during the year); - upstream producers faced with huge investments are also seeking to subscribe long-term

contracts in order to reduce financial uncertainty (often referred to by gas producing countries as "security of demand").

The European Council, considering that "long-term contracts have played a very important role in securing gas supplies for Europe and will continue to do so", explicitly asks to report long-term contracts (with a duration of more than 10 years). Indeed, gas supply contracts are explicitly taken into account in the non-exhaustive list of instruments to enhance the security of gas supply. It is expected that long-term contracts will continue to drive the gas supply up to the horizon of this report.

212 In: CREG - Plan indicatif d'approvisionnement en gaz naturel 2004 (English version of the indicative guidelines pp. 4-5).


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9.2.4.4 The Developing Role of Russian Gas

Some fear has been expressed about Russia as a trusty gas and energy supplier for the European market. Today it is still a marginal gas supplier to Belgium (4.9 % through Germany) whereas on average 24 % of European gas consumption is already imported from Russia. However, an interest of the Russian counterpart for the Belgian "gas place" is well noticeable: - through its 100% subsidiary Gazexport, in June 2006 Gazprom has concluded a Memorandum of

Agreement with Fluxys to develop joint explorations for underground natural-gas storage possibilities in Poederlee, the objective being to establish a joint venture between Fluxys and Gazexport for the project;

- in December 2004, Distrigas & Co and Gazexport have concluded a contract for the transit of

Russian gas from Eynatten at the German border to Zeebrugge and its hub, for a volume of 2.5 Bcm/y until 2018;

- since 1995, Gazprom holds a 10 % share in the sub-sea Interconnector pipeline linking the

Zeebrugge terminal to the British Bacton terminal and as a shipper, it holds long-term capacity rights in both flow directions.

Even if these projects are probably first to be attributed to the position of Belgium as transit country on the route to the British gas market, it could also be considered as a first step to a further presence of the Russian supplier. In contrast to other European countries, relying on more Russian gas would lead to a more diversified gas supply for the Belgian market as Russia is currently still a marginal supplier. In the context of some long-term contracts coming to an end, there is a potential future for Russian gas that could be placed on the Belgian market. This is an option that should not be left behind regarding the gas volumes needed to balance the market, certainly when considering the CE2030 scenarios with the highest gas demand. (See Figure 9.2.) The question then remains whether the perceived "risk" of the Russian supplier is acceptable considering what happened with Russian gas supply in the beginning of 2006. Several professional observers underline that one should not extrapolate what they consider to be a punctual incident in the frame of Russia's policy to obtain market-conform prices from certain former Soviet Union member states. It is also crucial for Russia to be able to deliver huge quantities of gas to the European Union. Presently, 90 % of the Russian gas (126 Bcm/a) is destined for Europe (the Baltic states excluded). The long-term energy plan of the Russian Ministry of Fuel and Energy (Mintopenergo) has foreseen that Europe will remain the most important export destination for Russian gas at the horizon 2020 (74 % of the total gas exports). Russia will remain a key player for the European gas market as the greatest holder of world gas reserves, moreover located at the border of Europe. As analyzed by the “Observatoire Méditerranéen de l’Energie” (OME) in the context of the ENCOURAGED project

213, total gas supply potential

available to Europe is expected to increase to 715 Bcm/a by 2030 (of which 227 Bcm/a of LNG) with Russia still being the main potential supplier (207 Bcm/a) followed by Norway (120 Bcm/a) and Algeria (115 Bcm/a). Simultaneously, new supply potentials emerge from the Middle East (Qatar), the Caspian countries, Nigeria, Egypt and Libya. All this will require new pipeline and LNG infrastructure, including re-gasification capacities. To balance the still increasing European gas demand against a declining European production, OME expects European import requirements to increase from 304 Bcm/a in 2005 to 470 Bcm/a (low demand scenario) and 650 Bcm/a (high demand scenario) in 2030. According to the demand scenario, Russian gas deliveries would at the most represent a share of 32 to 44 % of imports in 2030 assuming that all the potential Russian gas exports are delivered to the European market. In view of the high rise of import requirements of the EU (and including Belgium), it is obvious that particular and continued attention should be given to timely investments in the upstream gas industry.

213 EC financed project by the DG-Research. Data from: Observatoire Médterranéen de l’Energie, OME News Letter n°33 - February 2007 - p.4.


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Enormous investments are required to bring new Russian fields on stream (IEA estimate: 17 billion $/y). In parallel, the possible establishment of a "GasTEC" (similar to OPEC) for gas around Russia and other important producers is clearly evoked from time to time. However, to counterbalance the strong negotiation power of such potential grouping (and even versus the Russian supplier on its own), the European Commission has strongly supported the idea that if it wants to achieve its energy and climate-change objectives developed in its latest "Energy-policy package" (of January 2007) [CEU, 2007b], it has to develop "effective energy relations with all its international partners, based on mutual trust, cooperation and interdependence. This means relations broadened in geographical scope, and deepened in nature on the basis of agreements with substantial energy provisions."

214 The only

advice which can be given is that Belgium should subscribe to a strong global European positioning on this matter.

9.2.4.5 Belgium as Transit Country

As gas needs a specific infrastructure for its transportation, it is also essential to have the sufficient capacity to transport the gas to the final country of destination. In this respect, Belgium is also an important country for the transit of gas mainly from the north to the south (from Norway to France, Spain, Italy and from the Netherlands to France) and increasingly from the east to the west, transporting Russian gas to the British gas market through the Interconnector which is now increasingly used in reverse flow. Indeed, with the United Kingdom becoming a net importer, the capacity in reverse flow from Zeebrugge to Bacton has been increased to 23.5 Bcm/a even if this gas pipe was originally installed to transport gas from the UK to the Netherlands and Germany. Presently, long-term contracted transit capacity on the Belgian territory is about 50 Bcm/a which almost represents three times the Belgian domestic gas consumption. This capacity has been subscribed by about 25 operators. All investments made on the Belgian gas transmission infrastructure have also to take into account the specific needs and further developments of the European gas markets. An appropriate and timely investment policy on the Belgian gas infrastructure can favor transit of gas through Belgium instead of other transit channels, reinforcing also the security of supply issue.

9.3. Security of Supply of Electric Power Delivery in Belgium

9.3.1 Some Basic Reminders In this section, the correct and timely provision of electric power is dealt with. As electric energy is not easily storable (at least in large quantities), supply must follow demand at all instances. If local electricity demand cannot be satisfied locally, then import may be a solution; or in more critical situations, contracted load cuts may have to be made, to possibly end up with unannounced load shedding as a final resort. These measures have their limits though. First it must be said that import as such is not necessarily bad, as market transactions should be allowed to run their course. However, because transmission capacity is not unlimited, it is important that a country (or a control area) can satisfy its own peak demand. As has been explained in Chapter 2, the coupled European high-voltage electricity transmission grid has to cope with three aspects:

• cross-border contracted flows (free trade in a liberalized market); • assure that balancing of unannounced power flows due to massive use of correlated

intermittent sources occurs; and • keeping enough reserve transmission capacity to deal with possible incidents (reliability

aspect).

214 Communication from the Commission to the European Council and the European Parliament: An energy policy for Europe. Brussels, 10.1.2007 - COM(2007) 1 final, p. 18-20, [CEU, 2007b]


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As to generation capacity in neighboring countries, it is obvious that the system will not work if every country (perhaps under the post-Kyoto pressure) speculates on large fractions of import, since in the end somebody will have to generate the electric power! In this section, we take some distance from the actual details of the simulated scenarios, and try to look at the broader picture. However, they give an order of magnitude on what can reasonably be expected in 2030 in response to certain policy choices. Therefore, the numbers are recalled here briefly. They basically apply to the domestic CO2 reduction scenarios as well as to the European GHG reduction approach. (Details can be found in sections 6.4.2.3 b and 6.4.3.2 a.1.) Compared to a current electricity demand of the order of 85 TWh/a, reasonable projections for electricity demand in 2030 in the cases without nuclear power are in the order of …105…TWh/a, i.e., an increase of the order of about 20-25%. This applies to cases in which no to 15% of CO2 emissions needs to be cut on the Belgian territory. In these non-nuclear cases, the expected generation capacity ranges from about 23 GW (without post-Kyoto constraint) to 30 GW (for a domestic CO2 reduction of 15%). This is to be compared with the about 15 GW in 2005. For these cases, effectively all this capacity needs to be built, both to cope with demand increase and decommissioning of all existing plants. If nuclear power were allowed to continue, and under expected domestic CO2 reductions, then electricity demand would rise up to on average 120 TWh/a, being an increase of the order of about 40%. For the 'with nuclear' cases, the required generation capacity would range from about 28 to 30 GW, but in this case, still about 6 GW (nuclear capacity) would continue to operate, such that only about 22 to 24 GW would be needed, as extra investments.

9.3.2 Options for Meeting the Increasing Electricity Demand

To satisfy the electricity demand in 2030, Belgium can either increase its domestic generation by investing in additional generation facilities or import more electrical energy from neighboring countries. Both options are assessed below, considering the impact on security of supply, the price and the environmental effects. 9.3.2.1 Domestic Generation

a. Starting Situation Although the CE2030 report deals with the situation in 2030, one should not forget that a continuous and smooth transition has to be made. Therefore, we analyze in a correct way the appropriate definition of adequate capacity, as it is often the case that these numbers are misrepresented. Examples of non-firm capacity are hydro-basins, installed capacity of wind power, and a large part of CHP. Indeed, the contents of the water basin is variable throughout the year and depends on precipitation; wind capacity is not delivering in case of too little or too much wind. CHP is heat-demand based, and as such not dispatchable. Furthermore, generation plants need to undergo planned maintenance, which can be scheduled, but only to a certain extent. Figure 9.3 shows the relationship between the theoretical reserve margin (on the abscissa) and the actual reserve margin (of the ordinate axis) for the European national electricity systems. [Capgemini, 2006; ETSO, 2006; UCTE, 2006; VOKA, 2006]


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Figure 9.3. Remaining capacity at peak load vs theoretical margin. From [Capgemini, 2006]

Normally the remaining capacity is supposed to be at least 5% (and 10% in some countries). The picture shows that Belgium not only finds itself in a region of low theoretical margin (x axis), with also very small the remaining capacity at peak (y axis). Belgium has improved slightly compared to last year (when the remaining capacity was negative) due to the start up of the CCGT Zandvliet Power. The picture also shows that France is not doing much better as far as remaining capacity is concerned. Currently relying on France as a massive provider of electric energy is not evident from these data. All this shows that Belgium is presently lacking investments (in contrast to what one is often led to believe according to vague intentions/announcements and erroneous arithmetical additions), and that a stable legislative and regulatory framework is called for. One must give the proper signals to investors to get the required capacity on line in a timely manner; otherwise, we will not even make it to 2030 in a reasonable fashion.

Informative Box. Currently known investments to assure replacing Doel 1,2 & Tihange 1 by 2015 It is not simple to prove or disprove that sufficient generating capacity would be available if the nuclear units Doel 1&2 and Tihange 1 would be shut down by 2015. What is certainly not possible at this moment is to guarantee that sufficient capacity will be available. The total capacity (or installed power) of these nuclear units amounts to 1800 MW. Assuming an effective number of operating hours of 8000h, they produce annually about 14.4 TWh. By 2015, electricity demand has been projected by PRIMES to increase from the current 85 TWh/a in 2005 to about 95 TWh/a (BL) to 102 TWh/a (Bpk15s and Bpk30s), with corresponding capacity increase from 15 GW in 2005 to about 18 GW (BL) to 24 GW (Bpk15s and Bpk30s). However, it is not sufficient to supply the required TWh/a, as this is simply the total electric energy production over the whole year. Said otherwise, it does not suffice to consider the average power on an annual basis. It is the instantaneous power that needs to be covered; the peak demand must be covered adequately. Therefore, it is of uttermost importance to have dispachable capacity available!


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Non-dispachable capacity is referred to as non-firm capacity, and has a much reduced value in the electric generation system. Currently, not many hard-wired data are actually available. In some circulating flyers & documents, a variety of projects is reported, but it often concerns only vague intentions and much non-firm capacity. In fact only 3 real things have been seen: the BASF CCGT (Zandvliet Power), a number of wind turbines and the CHP installation at INEOS. A number of other projects have merely been announced, few of them have actually been confirmed and none of them has been started. It is misleading to assert now that all those investments will be made. Also, electricity-demand increase and shutting down of old plants are usually deliberately not accounted for. Since the decision of the nuclear phase out, the peak demand has grown by 1 GW. In addition, a number of power plants are expected to be shut down in the near future. Taking into account what has been announced and what is dispatchable capacity, at this moment one can only correctly state that about only half the electric energy of Doel 1&2 and Tihange 1 seems to become available. This however assumes that gas-fired units would run about 8000 h/a, which is given the very high gas prices totally unrealistic or extremely expensive. This also ignores the fact that replacing nuclear power and replacing it by these units will increase the CO2 emissions considerably. In the end, it may be expected that the market will invest, but perhaps too slowly, so that we may have to rely on import.

Before addressing the issue of reliability, it must be said that major sudden black outs seldom occur because of lack of generating capacity. Lack of generating capacity does lead, however, to brownouts, or announced cuts of power, the so-called 'rolling black outs'. Such power cuts have plagued California in the period 2000-2001 and have resulted in a 'migration' of a substantial number of companies to the Texas region. Nevertheless, announced or unannounced, such power cuts are considerably more than a ‘nuisance’ and should be avoided whenever possible. Sudden black outs most often occur when the overall system load is small (often this happens in summer time or on holidays) and when then a major incident or perturbation occurs. If the system is not able to react with appropriate measures, often related to lack of reactive power control, the system might collapse. Sudden black outs and reliability are related to good maintenance, appropriate grid extensions for having sufficient back up, but also with sufficient controllable/dispatchable generation. In that regard, implantation of massive amounts of distributed generation is to be carefully considered. Both system operators and regulators have a joint responsibility, whereby the costs for appropriate grid maintenance and adaptation should be allowed to be transmitted to the customer. The authorities should set the required level of reliability and then create the circumstances for it to be reached.

Informative Box. Stable Framework for Investments; Influence of Nuclear Phase-Out Discussions Electricity-generation equipment investors base their decisions not solely on the content of the legislation but also on the feasibility of the legislation and policy proposals. Furthermore, investments in energy-conversion capacity are more and more considered from an integrated European perspective. Belgium investors can invest in the neighboring countries and vice versa. But clearly, a stable regulatory framework is very important. It is, however, erroneous to state that discussions about the nuclear phase-out law affect the stability on the investor's market. The following reasons can be given: - investment decisions in gas-fired CCGTs are not affected by the discussion on the nuclear phase out since the period from ordering to operation for CCGT is merely two to three years. By the time one has to invest, the picture on the possible 'yes-or-no' shut down of some nuclear units will be clear. The issue for investing in CCGT is more a problem of high fuel costs and the guaranteed deliverability of the gas, the latter certainly in case of a complete nuclear phase out. - investment in coal-fired generation is mostly affected by the uncertainties concerning environmental constraints (especially post-Kyoto), the nature of the commitments, and the qualifications of the post-Kyoto GHG emission-trading scheme.


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- investments in renewable energy in Belgium are independent of the nuclear issue, as they are subsidy driven (because of green certificates of feed-in tariffs in certain places in Europe) and not market driven. Also for renewables, it is important to have a stable subsidy framework. In the renewable case, it is the policy makers that have to guarantee stability and guarantee; they have to realize now what they promise. It would be unjustified to renewable investors that future governments change the rules retro-actively. This has nothing to do with the nuclear issue.

b. Renewable Energy Sources (RES) b.1 Generation Capacity Potential Because of its geographic characteristics —such as a short coast line, no great height differences and little sunshine— not al types of RES can be successfully implemented in Belgium (e.g. hydropower and geothermal energy). The CREG estimates the Belgian potential for electricity generation by means of RES to be about 8.2 TWh. According to the Bpk15s and Bpk30s CE2030 domestic CO2 reduction scenarios, this would not be sufficient to meet the increase in electricity demand —cf. Section 6.4.2.3.b: about 15.5 TWh and 11.2 TWh respectively— by 2030, and certainly not to replace old power plants and nuclear generation capacity. The PRIMES scenario results shown in Table 6.8 and Figure 6.30, and repeated in Tables 6.16 and 6.17, do, however, foresee sufficient generation capacity. Nevertheless, the capacity factor of RES, determining the amount of electricity that can be generated with a certain amount of installed capacity during a determined period of time, is usually low. Consequently, substantially more capacity investments are needed to generate an equal amount of power with RES in comparison with classic generation plants. This has clearly been illustrated in Figures 6.30-6.34. b.2 Impact on Security of Supply In the long run, electricity from RES yields a number of advantages with respect to strategic security of supply or energy import dependence. RES —except for imported biomass— reduce our dependency from the import of primary energy resources. However, on the short term, things look different. Since the network infrastructure was initially built to transport electricity generated by large and centralized power plants, the connection of several decentralized generation units is an extra challenge for TSOs. Another drawback of RES with regard to security of supply concerns the occurrence of power interruptions. Power interruptions can occur when large amounts of unannounced power coming from, for example, wind farms, flow through the network. The low capacity factor of RES is another drawback. c. Need for storable Fuel; Coal Fired Stations In a well-performing electricity generation system, it is necessary to be able to rely on a sufficient fraction of well storable fuel. Everything based on gas supply and renewables generation, is too vulnerable to continued instantaneous power delivery. Depending on the generation mix, It may therefore be advisable to examine the possibility to have a considerable fraction of the CCGTs operate on liquid, i.e., easily storable fuel (e.g., jet fuel or kerosene-type fuel). Clearly, such technical option is to be checked by the different generating companies, but it should certainly be encouraged by the authorities. This does not mean that these plants need to run on jet fuel frequently, but only that the possibility exists and that a "sufficient" stock of jet fuel is present on site. However, it is clear that this is only a very temporary measure. Alternatively, one could still allow that we use the (worldwide available) massive coal reserves, a fuel that takes some space, but which is easily storable. But in the long run, this can only be accepted if one succeeds to realize the already mentioned CO2 capture and storage options. But for that purpose, carbon capture and storage (CCS) need to be ready as a routine commercial technology. As a temporary measure for the coming decades, it is possible to reduce CO2 emissions by investing in new and more efficient coal fired plants. Indeed, an increase of 1%-pt in efficiency amounts to a reduction of a bit more than 2% of CO2. If current-day coal fired plants of efficiencies of 35-38% are


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replaced by modern coal fired plants of efficiencies of 48%, then the CO2-emission reduction is considerable, being of the order of ~ 20%. This is the philosophy used in Germany currently. If, in addition, these coal-fired plants are equipped to accommodate co-combustion of biomass (up to 10-15% in mass, meaning about ~ 10% in energy terms)

215, this would lead to yet another reduction of

~ 20%-pts of CO2. It must be stressed though that that these new plants should use "clean" wood-based biomass (certainly without pollutants) so as to avoid corrosion of the boiler. Furthermore, these new plants can foresee the space to later attach carbon capture equipment (e.g., through MEA chemical absorption of flue gases). Finally, investing in coal-fired generation, coupled with a GHG certificate trading scheme such as ETS, might make sense, since the ETS will guarantee that coal-caused emissions have to be offset elsewhere (where they are cheaper to obtain). Hence there is no urgent need to forbid 'all' coal-fired power plants —and even to force a 'premature' closure of existing ones because of the ETS scheme and the possibility to opt for biomass co-firing. It is recommended that authorities set a clear framework for possible coal-fired plant investments. It seems that the environmental permits are crucial here. As to the "classical pollutants", the Belgian/Regional regulation should be based on the EU "Large Combustion Plant Directive" [CEU, 2001b], and for CO2, it is recommended to stick to a rigorous application of the ETS and leave the decisions to the investors/operators. Also, decisions on permits should be provided within strict time limits. 9.3.2.2 Import of Electricity a. Import Potential

216

Current Belgian import capacity is significant and is able to cover the negative (generation) capacity margin. ETSO

217 reports for the Dutch-Belgian border a Net Transfer Capacity (NTC) value in winter of

2.4 GW and for the French-Belgian border an NTC value of 3.2 GW. Note that NTC values are direction specific and therefore the export capacity can be different from the import capacity. According to these NTC values, the Belgian import capacity would be equal to 5.6 GW. This level is sufficient to cover the current negative capacity margin. However, one has to be careful by summing up NTC values. Making this sum assumes the Belgian grid to be strong enough to manage high levels of electricity import. However, the simultaneously importable capacity as reported by UCTE

218 sheds another light on the Belgian situation. Only a

border capacity of 2.9 GW is simultaneously available for electricity import. This is mainly due to a flow from France to the Netherlands of about 2.5 GW. Nevertheless, 2.9 GW is enough to cover for today’s negative capacity margin. According to UCTE, the Belgian simultaneously available import capacity is expected to increase to 3.2 GW. In its development plan, the Belgian TSO already considers an increase to 3.7 GW.

219

Moreover, interconnections between Belgium and Germany and Belgium and the UK are under consideration. Possibly the French-Dutch transit flow through Belgium might decrease, when new interconnections in the Netherlands come available. NorNed, a submarine HVDC cable connecting the Dutch and the Scandinavian markets, will have a capacity of 700 MW

220. Another project connecting the Netherlands

to the UK, called BritNed, is still under consideration. This link might increase the Dutch cross-border capacity with 700 to 1320 MW, depending on the decided capacity

221. A new interconnection between

215 Using a factor 18/24 to take into account the lower heating value of biomass (18 GJ/ton) versus coal (24 GJ/ton). 216 [Buijs, 2007] 217 [www.etso-net.org] 218 [UCTE, System Adequacy Forecast 2007-2020, 2007] 219 [Elia, 2005, Federaal ontwikkelingsplan 2005-2012] 220 [www.tennet.nl] 221 [BritNed Development Ltd, Application for EU exemption, 2006]


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the Netherlands and Germany is also investigated222

. The resulting increase in total transfer capacity (TTC) from this new line will be between 1GW and 2.1 GW. The Belgian import capacity is also influenced by the France-UK interconnection. Traditionally, France exports electricity to the UK via a 2 GW submarine cable. Recently, the number of days with flows in the other direction is increasing. As the UK-France interconnection is located near the French-Belgian border these flows influence the available cross-border capacity between France and Belgium. E.g., In comparison with a French export of 2 GW to the UK, a French import of 1 GW from the UK limits the import capacity to Belgium with 900 MW in peak periods and with 500 MW in off-peak periods.

[ELIA,

2005] An additional element of concern is the increasing level of wind farms in northern Europe. UCTE and ETSO show [ETSO, 2007] a scenario for the year 2008 the consequences of strong wind power in northern Europe. The generated flows result in congested internal and cross-border lines. The Belgian grid turns out to be one of the affected areas. The influence on the import capacity is negative. As a final point it has to be stressed that transmission capacity is not sufficient as such. Even if import capacity is available, the exporting country needs to have sufficient capacity to export. As the generating adequacy of The Netherlands is relatively low as well, the capacity at peak moments may not be available. b. Impact on Security of Supply, Electricity Prices and the Environment The Belgian import capacity depends on what happens on the borders between the Netherlands, France, Germany, Switzerland and Great-Britain. For instance, if problems occur on one of these borders, the rescue codes of the TSOs concerned will be activated. As a result, electricity cannot flow anymore across the borders, at a great disadvantage of netto-importing countries. When demand and supply are not in balance, a disturbance —and possibly a power interruption— will occur. More import can consequently increase the chance of power interruptions. Furthermore, usually exporting countries themselves are confronted with a domestic increase of electricity demand and the associated need for extra generation capacity. France, for instance, will need all its current excess generation capacity to cover its own, domestic electricity demand within 3 or 4 years. As such, the security of supply of electricity that we import from France will suffer. With respect to the impact on prices, it can be noticed that electricity prices are the highest in those countries being a large net importer. The Netherlands, the UK and particularly Italy (the largest importer) have systematically higher electricity prices than France. Relying on import essentially implies you are living on ‘the waves’ of electricity prices. Furthermore, importing electricity has macro-economic consequences. An increasing dependency for electricity on foreign countries has negative effects on the trade balance. The larger the dependency, the stronger the trade balance deteriorates. When this deterioration cannot be compensated with extra income, Belgium becomes a poorer region. Finally, import can have positive as well as negative environmental effects. If import is limited to green electricity, it has a positive effect and will contribute to achieve the Kyoto goals. On the contrary, when electricity is for instance imported from Germany, this electricity is mainly generated by brown coal plants. In that case, global CO2 emissions can even rise. This might therefore be a solution on a Belgian scale but not on a EU-wide scale, unless the price of traded electricity incorporates the pollution-related damage (e.g., through the EU emission allowance trading scheme). See also [Voorspools & D'haeseleer, 2006; Delarue & D'haeseleer, 2007].

9.4. Availability of Nuclear Resources In contrast to what one is often led to believe, the availability of nuclear resources is very comforting. Indeed, first of all, as can be seen from Figure 9.4, the geographical distribution of the currently identified Uranium resources is reassuring. No single region in the world has a dominant position.

222 [IGU, Gas to power in Europe, 2005]


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Figure 9.4 Geographical distribution of Uranium resources. [IEA, 2006d]

It must be understood, that to a large extent resources depend on cost. The cost of U3O8 in relation to cost of fuel cycle and cost per kWh has been explained in an Informative Box in Section 2.2.1.1.d. Also, the recent price evolution of U3O8 has been shown there. Table 9.2 shows how the resource base increases depending on the price of U3O8.

Table 9.2 U3O8 resources depending on the price. From [IEA, 2006d]

Since the current annual consumption about 70 kton/a, this means, that depending on the price as shown in Table 9.2, the R/P ratio for Uranium equals 40y…80y…160y. If, furthermore, we look at other resources, according to [IEA, 2006d; NEA/IAEA, 2006a,b], one can schematically portray the future availability of U-resources as follows:

Ø Conventional resources: 12-15 Mton à 40…200 y Ø Non-conventional resources: - phosphate deposits ~ 22 Mton (at 100-120 $/kg) à 300 y - black schist & lignite ~ 4.2 Mton à 60 y - seawater ~ 4000 Mton (at ~ 300 $/kg) à 50,000 y Ø Breeders

238U-

239Pu à factor 50 to 70 more

Ø Breeders

232Th-

233U; at least 6 Mton Thorium and the breeding factor


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This schematic clearly demonstrates that the availability of Uranium or Thorium should not be a cause of concern. The availability of fission resources is several 10,000 years.

9.5 Portfolio Analysis On the supply side, a portfolio of primary sources is to be called for. Gas is acceptable as a primary fuel for electricity generation, but at most partially. In the absence of CCS by 2030, nuclear power should be allowed such that efficient coal-fired power plants can be tolerated even if stringent post-Kyoto limits apply. Oil should preferentially be reserved for transport. Renewables, to the largest 'reasonably acceptable' fraction possible, make up the balance. All this clearly assumes that first a considerable effort for energy savings on the demand side will have to be done. Having mentioned the word portfolio, it is interesting to mention relatively recent work in which so-called financial portfolio theory used by investors is applied to the generation mix of a country. This analysis evaluates the financial returns compared to the risks. Following this method, it is argued that one can prove that renewable contribution leads to a more beneficial impact on the portfolio contents than if just based on a static cost/benefit analysis. [Awerbuch & Berger, 2003] These analyses lead to results portrayed as shown in the following example.

223 See Figure 9.5.

Figure 9.5. Example of portfolio analysis result to illustrate the methodology. From [Awerbuch & Berger, 2003]

This same approach has recently been followed in the Netherlands to evaluate incorporation of renewable sources. [Jansen, et al., 2006]. There is much to be said about this evaluation methodology and it should be taken seriously. However, it seems that the results should not be taken at face value, since allegedly, insufficient care has been taken of actual behavior of fluctuating renewable sources, with fundamental distinctions between installed capacity, instantaneous power and generated energy per annum. [D. Gusbin, private communication, 2006] Although it is unmistakably clear that a mixed primary energy basket is to be opted for certainly with regard to electricity generation, it seems recommendable to suggest that a Belgian security of supply analysis, based on portfolio theory and insurance risks, be undertaken to pinpoint some numbers. In addition, this should be integrated with reality-based technical constraints as to grid extension.

223 This example is only meant to illustrate the methodology. The results should not be interpreted out of context.


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10. Reaching Post-Kyoto in Practice The PRIMES scenarios considered by the CE2030 had severe post-Kyoto limits imposed, i.e., -15% and -30% of domestic energy-related CO2 emissions by 2030 compared to 1990, on the one hand, and EU-wide GHG reductions by 30%, on the other hand. One might wonder what the value of those scenarios is, since post-Kyoto constraints should perhaps take into account possible burden sharing and a practical use of flexible mechanisms. To set the scene, the reader is invited to look back at the numbers provided in Section 3.3.2.3, where the GHG data situation and evolution for Belgium are presented. This can serve as an interesting starting point to have some idea of what the Belgian basket of GHG represents. It also shows how well or badly Belgium has been doing so far to satisfy the current Kyoto protocol agreements. The remainder of this section deals with the Post-Kyoto situation.

10.1 Announced GHG Reductions and EU Objectives It will be recalled from Sections 3.2.2.1 and 5.3.4.2 that the EU has expressed its intention to reduce GHG by as much as 30% by 2020, and that that should be part of a broad international agreement. In any case, the EU wants commit to a GHG emission reduction of 20% by 2020 even if there is no international agreement. This is effectively the reading of the EU Spring Council declaration of March 09, 2007. As we have already said above, at this moment, it is not clear what the future imposed GHG reductions by 2030 might be for Belgium. Nevertheless, from the standpoint of a long-term energy strategy needed and the appropriate preparation for investment decisions, we cannot afford to be too optimistic, in the sense that we can close our eyes and hope/pretend that the future GHG-reduction burden will be easy. If matters turn out differently, as is indeed very likely, the time to adjust at that time will simply be too short. With such attitude we may have to face a serious surprise. Based on the recent EU official statements with regard to 2020, it does not seem unreasonable to assume that the EU will commit to a decrease in GHG of the order of 30 to 40% by 2030 compared to 1990. As a consequence, throughout this report, we have taken as a working hypothesis that the EU might commit to a 30% GHG reduction by 2030 compared to 1990.

10.2 Non-CO2 GHG and the Use of Flexible Mechanisms CO2 is the most important GHG since about 86% of all GHG in Belgium is CO2 and of that CO2, 92% is energy related. It must be recalled that the PRIMES model only deals with energetically-related CO2 emissions, and so, one must get some kind of idea on how the non-CO2 gas emissions might evolve in the future. In Section 5.3.4.2.a.1&2 we have tried to get an idea of the order of magnitude for actual GHG and energetically-related CO2 reductions that may have to be expected on the Belgian territory by 2030. Since in some cases the marginal abatement cost in Belgium will be considerably larger than abroad, Belgium will rely on the flexible mechanisms for reducing the burden of domestic reduction. Two approaches have been considered. In a first one, a "guestimate" about what domestic energy-related CO2 emission reduction Belgium might be faced with, has been undertaken. In that philosophy, it is assumed that flexible mechanisms will only be used or allowed to a limited extent. This is a pragmatic estimate, so as to be ready for reality on the energy-provision scene when faced with it.


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In a second approach, we have looked at the overall European efforts and try to find out how an ideal distribution of emission reduction should take place in Europe, thereby allowing unlimited use of flexible mechanisms and let them run their full course. Referring to the "back of the envelope" estimate made in Section 5.3.4.2.a.1, we may conclude that, an EU reduction commitment of GHG by 30% in 2030 compared to 1990 on the EU level, and assuming only a limited use of flexible mechanisms, might lead to a reduction of about 15% domestic energy-related CO2 emissions for Belgium. It is therefore not unreasonable to keep in mind that the energy system of 2030 should be able to cope with domestic energy-related CO2 emission reductions of the order of, say 10 to 20% compared to 1990. In the European approach of an overall EU reduction of 30% of GHG but making full use of an ideal emission-reduction exchange within the EU, the domestic reductions will then turn out to be quite small. However, as explained in Section 3.2.2.2, it seems logical —although this is a hypothesis— that Belgium will have to accept a similar GHG-reduction commitment towards 2030 as the EU as a whole, but clearly in terms of GHG-reduction responsibility. Under such circumstances, Belgium will only reduce GHG domestically according to its marginal abatement cost, making up the balance through purchasing of emission allowances abroad. Under less ideal international emission-reduction exchange (than with a simulation model), the real domestic decrease of energy-related CO2 reduction might still be of the order of 10% (or more). It is important to stress again the importance of the two "switching" variables for reaching the post-Kyoto commitments: the continued use or not of nuclear power, and the commercial availability of carbon capture and storage (CCS). Although it concerns here two technologies for the electricity generation sector, their use or not has tremendous consequences for the end-use sectors. Because of the uncertainties with the development of CCS, the technical experts of the CE2030 do not consider it prudent to count on the routine availability of CCS. A possible continuation of nuclear power is in the hands of the policy makers.

10.3 Expected GHG and CO2 Reductions and the Cost Consequences The simulation results for GHG and CO2 reduction, along the two approaches explained in this report, are given in Chapter 6. A summary of the results has been grouped together in the Conclusions of this report, and in Section 12.2.1.1., as well as the cost implications.


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11. Socio-Economic Consequences The main philosophy behind the scenarios that have been considered in the context of the Commission ENERGY 2030 and its interpretation afterwards, is to provide policy makers with tendencies that are (reasonably) transparent and which are not too dependent on all kinds of 'loose' assumptions and non-linear feedbacks going beyond the energy system as a whole (both demand side and supply side). The impact on energy prices for the different economic sectors is provided, and other costs/burdens due to particular choices have been identified, but the influence on the overall economy has been left for qualitative interpretation. The costs of the different scenarios as computed by PRIMES, have been presented in Chapter 6, both for domestic CO2 reduction (Sections 6.4.1.2 and 6.4.1.8) and for EU-wide GHG reduction (Section 6.4.3.2). As has been said above, it is not straightforward to find out what the exact overall cost of energy provision would be for the entire economy. This could be done approximately, but on a time horizon of 2030, it seems to be questionable to do this sort of evaluations, since especially the future change in industrial fabric of our Belgian society is unknown. Indeed, the long-term nature of our modeling, with the horizon towards 2030, makes it difficult to make a broad 'analytic' economic analysis, as the future Belgian economy will be strongly determined by the European economy and its own economic structure at that time, prescribed by the degree of innovation, the future weight and evolution of our industrial and service sectors, etc. Will Belgium still have a strong industrial sector in 2030, or will we become a major service-oriented country, centered about the EU institutions? In that sense, the economic importance of energy provisions is difficult to pinpoint in exact numbers. Also, since the Belgian economy is so dependent upon its EU trading partners, the hypotheses made for the other EU MS in a modeling exercise are very important for the overall Belgian economic situation in 2030. Some attempts for EU modeling (commissioned by the EU) have nevertheless been performed very recently using the model GEM-E3, but these results have not yet been released publicly. Whereas those results may give acceptable indications for the EU as a whole, in the framework of this CE2030 assignment, it has proven to be impossible to investigate the degree of "representativity" or "accuracy" for the Belgian situation as part of that overall EU modeling exercise. The numbers given in Chapter 6 should suffice for a comparison between the different scenarios. The nuances on interpretation have also been given earlier in this report. In addition to the simulation results, other cost considerations due to the nuclear phase out (Section 12.2.1) and the subsidy burden for renewable energy if exaggerated (Section 6.4.2) have been presented elsewhere in this report. The total cost picture is summarized in the Conclusions of this report. Likewise, the future influence on employment is quasi-impossible to foresee; because of the same reason. The same holds for the influence of energy provision on employment for the whole economy. It has been addressed by [Proost, 2006b] that employment in a particular energy-related sector (whether it be renewable or nuclear) should not be used as an argument to promote one type of energy technology over another. Skilled labor has its own market price, and attracting skilled labor to a particular sector, simply withdraws that labor from a different sector. Based on real economic (i.e., opportunity) cost arguments, one can show that one should opt for the most economically efficient energy technologies, such that in the end, employment of the entire economy will benefit from it. Said otherwise, opting for a particular expensive energy technology with the argument that it creates jobs in that energy sector, will in the end lead to less employment for the whole economy. Having said that, however, one might wish to exploit a certain expertise to be able to export that technology abroad (e.g., wind-turbine energy in Denmark, nuclear energy in France), and there may be good arguments for government to support that, but that has nothing to do with energy provision but with industrial development. One should then carefully evaluate what the best sectors for support should be: chemical industry, software industry, high-quality-steel industry, etc. It is possible that an energy technology might be part of that industrial expertise, but that is not necessarily so.


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Whatever the (unknown) exact costs for our entire economy, it is certainly clear that some future energy options are considerably more expensive than others. One may hope for mitigating effects, economy-boost effects in certain sectors, double dividend effects if revenues of CO2 taxes or auctioning of emission allowances that are fed back into the economy, but all these effects remain to a large extent hopes and wishes, and have not been firmly demonstrated. Also, there might be positive effects in some segments of society, but also negative effects in other segments. Indeed, feedback effects such as influence on consumer index and inflation, the reaction of the European Central Bank, etc are difficult to predict. (As a matter of fact, these non-linear effects are not predictable.) In any case, a possible re-injection of carbon-related revenues into the economy, may lead to some relief, but it turns out to be limited, and actually in this case of second order. First, the extra allowances to be bought abroad to mitigate the effect of the nuclear phase out, do not lead to revenues for the Belgian authorities. Furthermore, a re-injection into the economy (e.g., to lower labor charges) of its carbon-emission revenues for the GHG that Belgium is allowed to emit, may lead to a lower cost for the overall Belgian economy than if no re-injection had occurred, but, because of still existing distorting taxes, the overall cost for the Belgian economy will nevertheless be larger than what PRIMES has computed. (See Section 6.4.1.2 for a more detailed explanation.) The CE2030 therefore wishes to consider the cost given in the above mentioned sections as a (albeit imperfect) guiding principle for careful decision making in these energy matters. These numbers give indeed an incomplete picture, but they are most valuable indicators. They should not be ignored! The CE2030 opts for cost-effective measures and solutions, or, at least one should not deviate from it too much. Because of the uncertainties, it might be justified to engage in a few 'experiments' and take a few 'risks'. But it should be clear that a country with a national debt of 93% of its GDP

224 should be

careful with risk taking and that we can afford less 'trying out' than countries like e.g., Denmark and the Netherlands, with debt rates of 36% and 53%, respectively.

224 Status at the end of 2005.


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12. The Nuclear Power Option Before embarking on a discussion of the nuclear issue in Belgium, it is important to make an important point. In many discussions with societal players about nuclear power in Belgium, it is often observed that (perhaps often unintentionally), but regrettably misleadingly, several issues are mentioned in the same breath, effectively a-priory putting a shadow on the acceptability and meaningfulness of nuclear power as a part of the energy mix. When the nuclear issue is subject of discussion, the following elements are brought up almost automatically:

• nuclear energy itself and its alleged "problems"; • the fact that the current nuclear operator allegedly makes unreasonable profits with power

stations already written off in a regulated market environment; • the fact that the liberalized market is not (perceived to be) functioning properly; • the fact that the operator and owner

225 of the Belgian nuclear power plants, being the largest

historic generator in Belgium, belongs for 100% to a French group. This is not the place to deal with each of these elements; that has been done elsewhere in this report. Here, we wish to stress that these four elements have to be examined independently, since they have a-priory no relationship to each other. As to the nature of nuclear power, its merits and disadvantages must be evaluated regardless of who is the owner/operator. Having said that, it is clear that after an independent examination of these four elements, it should be checked whether interactions between these four exist, how these interactions influence the overall picture and how such cross-influence could be tackled if that turns out to be harmful for a good functioning of our energy provision.

226 Very often, the authorities (EU Commission, Regulators) have

an important role to play to assure that there is no abuse of a particular combination of elements, if that were the case. In this section, only the nuclear issue as such is discussed.

12.1 The Nuclear Phase-out law Although this is not the place to make an in-depth analysis, it is instructive to make some observations on the existing nuclear phase-out law and the context in which it was enacted. These historic and circumstantial elements need to be taken into account when the future energy policy of Belgium is addressed. The Belgian nuclear phase-out law has been voted into law on January 31, 2003 and was officially published in the Belgian Official Journal on February 28.

227

As has been explained in [Ampere, 2000; Main report Chapter E] there does not exist a predefined technical lifetime of a nuclear power plant. The only actual lifetimes are an economic lifetime (always subject to stringent safety regulations) and a political lifetime (if the authorities decide that a plant must be closed). For the Belgian situation, the latter currently applies. Because of a political decision, nuclear power for electricity generation is supposed to be phased out by 2025.

225 For simplicity, in the remainder of the text, the words operator and owner are used interchangeably. However, both words are not synonyms in the strict sense. Of the four youngest Belgian nuclear units, Tihange 2&3 and Doel 3&4, SPE owns 4% , the balance being owned by ELECTRABEL/SUEZ. The units Doel 1&2 are owned 100% by ELECTRABEL/SUEZ, while Tihange 1 is jointly owned 50/50 by EDF and ELECTRABEL/SUEZ. 226 As always in this report, "energy provision" refers to the overall energy issue, including both the demand and supply sides. Energy supply, refers to the actual delivery issue of energy. 227 The bill was officially submitted to Parliament on July 08 2002 (Doc 50 1910/001). This bill also contains the 'explanatory memorandum'.


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Informative Box: Some Elements on the Lifetime of a Nuclear Power Plant As is explained in the main report of the AMPERE report (Section E.7), [http://mineco.fgov.be/ampere.htm] there is no such thing as a finite lifetime of a system; only components have a predetermined lifetime. A nuclear power plant is a system. Subject to stringent safety standards, the only real lifetime of a nuclear power plant is an economic one. Similar arguments are valid for refineries, airplanes, cars, and all other technical systems. Indeed, in a system, in principle all components can be replaced, and sometimes with even better quality than before. Some control functions can also be upgraded, like putting upgraded computers and more sophisticated automatic flight pilots in existing aircrafts. Also racing passenger cars are examples of systems with many upgraded components that function much better than the original car. At some point in time, however, it will be necessary to replace "too many" components such that the exercise becomes too expensive. In that case, the operator will want to shut down his reactor. At that point, the plant will have reached its economic lifetime. An extra special cautionary element for a nuclear power plant compared to other systems is that safety is of uttermost importance and must remain as good as ever, or should even be improved. There can be no compromise on that requirement. The safe state of a plant is to be guaranteed by competent safety authorities. It should be recalled that before the nuclear phase-out law in Belgium took effect (January 2003), there was no pre-defined operational lifetime of the Belgian NPPs. Every ten years, there was a major ten-year overhaul ("revision décennale"; "tienjaarlijkse revisie") after which the plant received the green light for another ten years. These ten-year overhauls still take place, but a "non-natural" limit has been legally imposed through the nuclear phase-out law: 40 years. However, technically speaking, no major difference is to be expected between the third and a possible fourth and fifth ten-year overhaul for the four youngest units Doel 3&4 and Tihange 2&3, so that no major investments (beyond the usual maintenance and replacement costs and as compared to the third ten-year overhaul) are expected. Commercial airliners undergo a major overhaul every 8-10 years, after which they receive a "clean bill of health". The most critical component for the actual duration of the operational life is the reactor vessel. The integrity of the reactor vessel (with regard to embrittlement due to neutron bombardment) is guaranteed for a duration of 60 years (and even more). The integrity of the reactor-vessel material is checked by putting samples very close to the reactor core, so that they receive 2-3 times more fluence than the vessel wall. Those samples are checked very regularly. In almost all Belgian units

228, the steam generators have been replaced (with now alloys that are

sufficiently corrosion resistant). Replacement of steam generators has become a routine operation, which suggests that plant decommissioning will also become a routine job as soon as a few plants have been dismantled. At present, 4 reactors are operational for longer than 40 years, the oldest one being 42 years; see http://www.iaea.org/programmes/a2/index.html. According to the USNRC (http://www.nrc.gov), early 2007, 47 reactors have received a license extension for operation to 60 years, 8 applications are under review and 27 submittals have been announced by letter of intent to the NRC. About 70 out of the 103 reactors wish to have a license until 60 years. As far as we know, there are no power stations for which a license renewal has been requested and that has been denied.

An analysis of the nuclear phase-out law, based on published documents, has been made by [Laes, 2006]. Here, it suffices to draw attention to a few elements. The political character of the phase-out law is evident from the timing. After the Ampere Commission had only been installed for three months, the new governing coalition formed after the elections agreed in its coalition agreement, and later in the governmental declaration, that a nuclear phase out should be implemented, resulting in a shut down of the Belgian nuclear power plants after 40 years of operation. The conclusions of the Ampere Commission were therefore not determinate for the phase-out law.

228 The replacement of the steam generators of Doel 1 has been announced and may take place in the near future.


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Careful examination of the explanatory memorandum and the law, shows that many arguments used to justify the phase-out law do not stand up to serious scientific scrutiny. Even stronger, particular arguments made by the Ampere Commission have been taken out of context and have been made improper use of in order to justify the end. In any case, the most worrisome element of the phase-out law is that the consequences of the phase-out law have not been investigated.

229 Note also, that the

explanatory memorandum recognizes that the nuclear phase-out law has implications for the post-Kyoto climate change commitments of Belgium: it makes explicit reference to the 'Triptych approach', in an attempt to transfer the GHG-reduction burden as a consequence of the nuclear phase-out choice to the other EU Member States. Regardless of who is right or wrong on whether nuclear power is acceptable or not, sober reflection on this nuclear phase-out law shows that there is actually no substantive reason for such a phase out. It is effectively guided by emotional arguments, translated into a political decision as a consequence of a circumstantial coalitional 'deal'. Indeed, if nuclear power as established here in our regions

230 were

indeed unsafe, unreliable etc, then it should be phased out immediately. The fact that the law allows operation for a period of 40 years shows that this is an artificial lifetime, independent of pertinent arguments. The law foresees in its article 9 that in cases of 'force majeure', when security of supply is threatened, the government can take the necessary measures by Royal Decree. At the present time, the overall situation on the international/global 'energy scene' has changed dramatically: the substantially risen fossil fuel prices & the unstable geopolitical situation, both severely influencing security of supply, and the accelerating concerning signals for climate change. This added to the fact that a careful evaluation at the time would have shown that a nuclear phase out would already have been extremely 'challenging', makes it almost impossible now to keep the closure calendar as foreseen in the law. The changed situation is reflected in the results of the PRIMES simulations. Starting from an 'honest and fair' Belgian contribution to commit to GHG-emission reduction,

231 and even with a substantial

push for energy savings (even perhaps beyond what first-order economic computations would allow for), it is difficult to see how a recall of the phase-out law can be avoided. The overall financial burden would be very large.

232 Taken into account the time needed for investments, it is not advisable to linger

too much if one wants to avoid unpleasant circumstances concerning our energy provision. A timely decision on the 'status' of the nuclear phase-out law is called for.

233

12.2 Considerations on the Future of Nuclear Power in Belgium Because of the special characteristics of nuclear power plants, it is justified to devote some special attention to electricity generation by nuclear means. Most of the background to this section is found in the more comprehensive treatment available as supporting document to this report [Streydio, et al., 2006]. In addition, many elements of what has been written in the AMPERE report [AMPERE, 2000, Chapter E] still apply, while further useful information on the prolongation of the operational lifetime of existing nuclear plants and pertinent guidelines for boundary conditions for new nuclear plants can be found in [Bataille & Birraux, 2003; ECN, 2005; VROM, 2006b]. An interesting recent account on the prospects for nuclear power has been published in Chapter 13 of the IEA's World Energy Outlook 2006 [IEA, 2006d]. See also [Keystone, 2007]. In the following subsections, a summary of some general observations can be made; furthermore, some guidelines can be given.

229 As a matter of fact, a first evaluation of a phase out had been made in the so-called 'post-Ampere scenarios' by [Proost & Van Regemorter, 2006]. The results of those scenarios were completely ignored, and no attempt has been made to make any further evaluations. 230 With the reactor designs as we have them (i.e., reactors of the PWR type), with our operational procedures and safety culture, with our previsions on waste management and proliferation. 231 Thereby allowing the possibility to effectuate reductions elsewhere in the EU, or via the purchasing of emission allowances. 232 For details, see Chapter 6 for both domestic reductions and a GHG reduction commitment in a EU context. See also the numbers quoted in the Conclusions of this report. 233 See an Informative Box in Chapter 9 that explains why questioning the nuclear phase out does not affect investments in renewable energy.


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12.2.1 The Cost of Phasing out Nuclear Power in Belgium In many places in this report, cost elements for an actual nuclear phase out in Belgium have been considered. Here, a summary of those cost aspects is provided. One of the main reasons why a nuclear phase out is so expensive is the expected imposed GHG reduction obligations that Belgium will have to face by 2030. However, there are other reasons why a nuclear phase out will turn out to be costly for Belgium. The following aspects will be addressed:

Ø Belgium gives up a cheap way to reduce CO2 emissions domestically; Ø Phasing out 6000 MW of cheap base load capacity will lead to an increase in electricity prices; Ø Allowing nuclear stations to continue would allow the state to negotiate a concession fee. Not

being able to do this, amounts to an opportunity cost for the Belgian state; Ø Giving up nuclear power increases our import dependency; this reduced security of supply has

a cost; Ø By postponing decommissioning, the decommissioning fund will grow substantially. Not taking

advantage of this possibility leads to an opportunity cost of the order of somewhat more than 1 G€.

Ø Although not really an actual cost, letting a future government negotiate with nuclear plant owners by using the 'carrot' of a nuclear operation extension, can keep certain elements of the energy system under the control of the Belgian authorities.

12.2.1.1 Extra Cost for GHG-Reduction Commitments It will be recalled that two types of approaches have been considered to explore the cost of a nuclear phase out if stringent GHG-reduction requirements are to be met. In a first approach only domestic reductions of energy-related CO2 emissions on the Belgian territory have been implemented. In a second approach, a European-wide Greenhouse-Gas reduction (GHG) obligation has been imposed, whereby part of these reductions is materialized in Belgium; the remaining obligations are to be satisfied by purchasing emission allowances abroad. a. Domestic CO2 Reduction Constraint If a nuclear phase out is implemented, and if CCS is not routinely commercially available by 2030, the scenario results show that domestic CO2 reductions are very expensive. The numbers, as produced by PRIMES under the given hypotheses, show that a domestic CO2 reduction of up to 15% would be barely tolerable; but also the 'unreasonableness' of a domestic 30% CO2 reduction scenario by 2030 (compared to 1990) is obvious. In fact, for the domestic reduction case of 30%energy-related CO2 emissions, this amounts to a proof "ex absurdo". Without nuclear power and without CCS, marginal CO2 abatement costs (or market price for CO2 permits, or 'Carbon Value', or CV) of up to 500 to 2000 €/ton CO2 for the -15% and -30% scenarios, respectively, are reported. These values, especially the latter ones, are indeed unreasonably high. Under these circumstances, Table 12.1 summarizes earlier obtained results for the costs to the different sectors, expressed as increased prices, per unit of energy utilized.


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Values for 2030

In 2000: 540

In 2000: 820

In 2000: 960

Baseline 660 (24%) 1100 (31%) 1600 (63%)


1300 (150%) 2100 (150%) 2600 (170%)


2900 (440%) 5000 (510%) 5000 (420%)

(Between brackets % change between 2000 and 2030) ; 1 toe = 41.868 J = 11.63 MWh Table 12.1. Energy prices per unit energy per sector, for domestic energy-related CO2 reductions;

Cases without nuclear and without CCS.

Considerable relief of this extremely heavy task to reduce domestic CO2 emissions can be further obtained if carbon capture and storage (CCS) would be available or if nuclear power were allowed to continue operation beyond 2015 and 2025. Under these relieving conditions, for the 15% CO2 reduction cases, marginal abatement costs (CVs) of about 50 to 100 €/ton result, whereas the -30% case still leads to CVs of the order of 200 to 500 €/ton. Still a 'respectable' end-energy demand reduction results, albeit at a lower cost. To go from 2000 to 2030, the projected energy-system costs for the end-use sectors are summarized in Table 12.2.




Values for 2030

In 2000: 540

In 2000: 820

In 2000: 960


CCCS CCS

730 (37%) 1100 (36%) 1600 (71%)


790 (47%) 1200 (43%) 1700 (79%)


970 (81%) 1500 (83%) 2000 (110%)


930 (73%) 1400 (73%) 2000 (100%)


1200 (120%) 1800 (120%) 2400 (150%)


1300 (130%) 2000 (140%) 2500 (160%)

(Between brackets % change between 2000 and 2030) ; 1 toe = 41.868 J = 11.63 MWh Table 12.2. Energy prices per unit energy per sector, for domestic energy-related CO2 reductions;

Cases with nuclear and/or CCS.

For the -15% case, the cost is 'slightly' higher than the cost in the baseline (although still up to 50% higher for industry) if nuclear power were allowed, whereby the no CCS case is yet somewhat more costly; the case without nuclear power but with CCS, has a system cost that is 2 to 4 times more expensive than the baseline. For the 30% reduction case, costs with nuclear power allowed range from about 2 to 4 times the cost of the baseline (compared to a factor 15 to 20 without nuclear power and without CCS), with the case with both nuclear and CCS available, being the cheapest. It must be noted, however, that these two ‘alleviating options’ are not equivalent. Carbon capture and storage is still to be developed and the CE2030 considers it as very risky to assume that CCS will be routinely commercially available by 2030 in Belgium (especially the storage part). See Section 5.3.4.2e and 6.4.2.2. Based on its examination of the issue for Belgium, the technical experts of the CE2030 believe that for practical purposes of planning the future Belgium


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energy system, it would not be judicious to count on the existence of CCS "off the shelf". Hence the importance of the no CCS scenarios. In contrast, nuclear power is currently operating in Belgium with a good track record, meaning that this is an option that the Belgian policy makers can make available to the electricity generation sector.

b. European GHG Reduction Constraint In the second approach, an overall EU-wide GHG reduction target of 30% in 2030 compared to 1990 has been considered. No flexible mechanisms outside the EU are applied. The 30% reduction of GHG is assumed to be effectuated within the EU. In all scenarios here, no CCS is considered to be available.

The simulation results show that the nuclear phase-out law prevents cheap domestic CO2 reductions, forcing Belgium to implement and/or finance reductions abroad (either directly or through the purchasing of emission-reduction allowances. Under the hypothesis that Belgium will have to accept a similar GHG-reduction obligation as its European trade partners, which we take for simplicity equal to the EU level of 30%,

234 the European approach means that GHG reductions can be obtained at lower

costs than effectuated domestically. However, the emission reductions abroad must be paid for by Belgium via equivalent emission allowances, at a price of the equilibrium marginal abatement cost (MAC). The extra cost is approximately given by the colored triangular area of the figure below, taken from the sequence of figures in Figure 6.70. The European emission allowance price would be 200 €/ton CO2-eq in 2030 (being the equilibrium value found by PRIMES), the extra cost due to the nuclear phase out will be of the order of ~ 2,000 M€ in 2030.

235 For the last five years 2025-2030 of the horizon

considered in this report, i.e., after the nuclear phase out in 2025, these amounts will be of the same order, leading already to a cumulated extra cost of ~ 10,000 M€. Integrated from the post-Kyoto period 2010, with a first phase-out in 2015, the next one in 2023 and a final one in 2025, till 2030, this would lead to an extra cost for CO2 abatement of about ~ 15,000 - 20,000 M€.

236

Figure 12.1. Extra cost for GHG abatement due to a nuclear phase out is given by the colored area; this is a qualitative picture.

This extra cost due to the nuclear phase out is about 6% to 8 % of the GDP of 2000, or 4% to 5% of the GDP of 2030. On an annual basis, during the period 2025-2030, this amounts to roughly 0.5% of annual GDP of that period. With respect to GHG reductions on a EU scale, Belgium could hope to bargain for a smaller GHG reduction obligation as part of a negotiated burden-sharing agreement (e.g., employing the Triptych philosophy), using the argument that its domestic abatement costs are very high due to the nuclear

234 For the wealthier EU countries, amongst which Belgium, a burden sharing based on equal GHG abatement cost per personal income, could lead to an even more severe reduction obligation or responsibility. For details, see Chapter 3. . 235 The amount HD equals 20 Mton/a in 2030 since the Belgian GHG emissions in 1990 amounted to 144.3 Mton, and the triangular-like area ≈ (HD*HG)/2 (i.e., base*height/2) ~ 20Mton * 200 € / 2 = 2 G€. For details, see 6.4.3.2.b.2. 236 Expressed in constant €2000.


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phase out.237

The correct attitude would rather be that Belgium accepts to take the same burden in terms of GHG-reduction cost per personal income as its most important EU trade partners (thus, in terms of reduction responsibility). Roughly speaking, that would mean that Belgium has to face a similar reduction quota in terms of % as the EU, but in terms of obligation. In doing so, it will then only reduce GHGs domestically in accordance with the lowest abatement cost, at the same time relying on buying emission allowances abroad, to satisfy the balance. In any case, because of the uncertainty on the future GHG reduction obligation for Belgium by 2030, Belgium should not adopt an ostrich attitude and prepare its energy system for a severe reduction, to be ready in time. Consequently, the costs for severe GHG reduction obligations will be very high, unless appropriate policy choices concerning nuclear power are made. 12.2.1.2 Higher Prices for Electricity In a liberalized well functioning market, the price is set by the last unit, i.e., the marginal production unit. This is shown by the intersection of the two black curves of Figure 12.2. (Figure 12.2 is a qualitative figure, only meant to show the principle. For illustrative purposes here, a relatively low load case —Demand curve— has been utilized.)

Figure 12.2. Illustrative figure to show the influence of a nuclear phase out on the price of electricity.

In case of an (overnight) nuclear phase out, the marginal cost curve would shift to the left, becoming the pink curve.

238 In an isolated market, the new price would be given by the new intersection point

marked "New market price" in Figure 12.2. Even in an open market, but with not-unlimited cross-border transmission capacity, and thus some type of increased congestion on these cross-border lines, electricity prices are expected to increase.

239

By phasing out so much cheap base load capacity, the electricity supply curve will shift to the left, in the long run being shifted back to the right but at a likely higher cost. (Certainly the long-run cost, including investment.) Because of likely limited transmission capacity, phasing out 6000 MW will almost certainly lead to an increase in electricity prices.

237 Note however, that according to environmental economics logic, the decision to phase out nuclear power should lead to the contrary, i.e., a larger GHG commitment in terms of obligation for Belgium. See Chapter 3. 238 One could argue that if the phase out takes place gradually that this capacity could be replaced by renewables with al almost zero marginal cost. However, as has been shown elsewhere in the report that would mean that a massive amount of investment of intermittent sources, which would be extremely expensive as investment cost, or alternatively, via the support schemes. A further issue is that firm baseload capacity would be replaced by non-dispachable power. This would mean that this intermittent power would not be available during about 2/3 of the time. 239 A way to avoid this is to increase substantially the cross-border transmission capacity. But that would have consequences for the security of supply issue.


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12.2.1.3 Concession Fee for Continued Operation Allowing nuclear stations to continue would allow the state to negotiate a concession fee. Not being able to do this, amounts to an opportunity cost for the Belgian state. As a precondition to lift the nuclear phase-out law, the authorities could negotiate with the owners to establish a sort of concession rent to be allowed to continue operation. Such rent should be based on the value of nuclear electricity with those plants, and should depend on the inframarginal rents.

240 A

different way is to put a levy on the revenues of these types of plants. It must be stressed that a fair concession rent should be established. The amount is best to be evaluated by an independent international Committee of Energy Economists & Financing Experts.

241 If the fee is too high, then the

owners would no longer be interested to continue operation of the plant; if the fee is too low, this amounts to an opportunity cost for the Belgian State. It seems plausible that as part of the deal, all earlier agreements that were concluded invoking the nuclear phase out as an inconvenience should be revisited. In addition, a correct treatment of the decommissioning funds, and possible use of it by the government should be considered in this conext. 12.2.1.4 Increased Import Dependency Giving up nuclear power increases our import dependency, roughly from about 65% to an overall 90-95%. This leads to two extra cost issues:

• the reduced security of supply, with sometimes instantaneous power dependency of more than 95% makes us more vulnerable to interruptions of continued delivery (especially of gas, in turn being "transmitted" to electricity) and this leads to an increased cost;

• whereas nuclear power is characterized by a rather cheap fuel cost, maintenance and part of the construction cost can be considered as domestic (Belgian) costs, gas dependence must be imported, leading to a higher burden on our financial balance.

242

12.2.1.5 Postponed Decommissioning of Nuclear Units In contrast to nuclear waste, which increases proportionally with the operation time, decommissioning does not become more expensive when it is delayed. On the contrary, because of the existence of a discount factor, decommissioning becomes cheaper. Said otherwise, because of interest, the existing decommissioning fund can grow substantially. See Figure 12.3.

Figure 12.3 Difference in decommissioning cost of the Belgian nuclear fleet after 40 years and 60 years.

240 Such inframarginal rents are sometimes erroneously called "mothball profits". See Informative Box in Chapter 8. 241 See Chapter 8 for suggestions on such an Expert Committee. 242 A similar argument could be used for all capital-intensive generation units (such as wind and PV).


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Figure 12.3 shows the annual cost for decommissioning (this is the sum of the numbers for all Belgian units). The figure is based on numbers available early 2004. The pink figure shows the costs for an operation period of 40 years. Using an annual discount factor of 3% in real terms, this cost figure has been shifted to the right by 20 years, but properly discounted. In total, the area under the pink curve, representing the amount needed for decommissioning after 40 years, amounts to about 2.6 G€, whereas the area under the dark-blue curve amounts to about 1.3 G€. This means that about 1.3 G€ does not have to be spent for decommissioning, possibly becoming available to finance other things. Taking into account the rough character of the estimate, disregarding this saving amounts to an opportunity cost of the order of 1 to 1.5 G€. 12.2.1.6 Negotiating Advantage with Respect to Foreign Owners It may be considered as an advantage of lifting the nuclear phase out during negotiations with foreign owners of the nuclear fleet to exert some pressure by using the nuclear phase out negotiating package as part of a deal to keep certain elements of the energy system under control of the Belgian authorities. This advantage is a consequence of the fact that the European Commission no longer accepts national circumstances in the framework of the European liberalization. Said differently, as long as electricity generators play according to the European rules, and can prove that there is no abuse of market power on a European scale (e.g., by demonstrating that its prices are aligned with its connected neighbors), there appears to be no real problem if there exists some local geographical dominance (i.e., as long as there is no abuse of local power). By putting the issue of lifting the nuclear phase out on the table, it may be possible to bargain for some particular engagements on Belgian territory, keeping or putting them under the supervisory control of the Belgian authorities. 12.2.1.7 Wrap up of Costs of a Premature Nuclear Phase Out Considering the major challenges faced by the Belgian energy economy, it must be concluded that, especially in the light of the very stringent GHG-reduction efforts expected, an actual implementation of the Belgian nuclear phase out turns out to be expensive, as too much opportunity will be missed. As explained above, Belgium will pay a substantial amount for the premature closure of its nuclear power plants. This extra financial burden, which can be avoided, appears to be too high a price to pay, even when considering a disadvantage of keeping nuclear power plants operating, namely an increase of the nuclear waste, which is considered in a following section.

12.2.2 Operational Extension of Existing Power Plants 12.2.2.1 Existing Operation of Nuclear Plants Independent of a Phase Out Under the current nuclear phase-out law, the last commercial nuclear reactor for electricity generation will have to be shut down by 2025. During these still about 20 years of operation: à The operation of the plants should continue under the same safety culture, with appropriate regulatory supervision, and continue to operate under the ALARA principle for radiation exposure of employees and the public. Maintenance must continue to live up to internationally recognized standards. à Nuclear waste management should abide by the same rules of volume minimization and appropriate waste treatment. For the long term, research, development and demonstration towards the underground disposal facility must continue, so as to prepare it for actual implementation.

243 The cost for nuclear-waste treatment is incorporated in the cost for

nuclear-generated electricity; the nuclear-waste cost is effectively internalized.

243 See also the SAFIR 2 Report [NIRAS/ONDRAF, 2001] and the international peer review [NEA, 2003]


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à Precautions against proliferation of fissile material are to be continued under the strict international safeguards programs and agreements under supervision of the international nuclear watchdogs EURATOM and the IAEA, and the Belgian authorities. à Precautions against terrorism, appropriately sharpened as a consequence of the changed international perception, must be continued. It must be recognized that the Belgian nuclear power plants, with firm containments, are very much 'terrorism'-resistant. à Sufficient funds are being built up for decommissioning of the nuclear plants. Based on a firm agreement between the owners of the plants and the Belgian State, guarantees must be given that the funds will be available in all circumstances.

Informative Box: Radioactive Waste Management in Belgium – Summary

ONDRAF/NIRAS manages two programs towards the implementation of a solution for the long-term management of radioactive waste (see also www.nirond.be). For category A waste (short-lived low-level and intermediate-level waste), the Federal Government decided on 23

rd June 2006 to opt for final surface disposal in Dessel. The program, currently in the

project phase, focuses on bringing the project proposed by the STOLA-Dessel partnership to the implementation stage, planned from 2011 onwards, with the intention of starting operation in 2016. The existing participative approach will be continued. For category B&C waste (high-level and/or long-lived waste), the Federal Government has not taken any decision yet: the studies are thus still at the stage of methodological research, development and demonstration, and focus on geological disposal in Boom Clay as a reference. ONDRAF/NIRAS will strive to initiate a societal dialogue about the long-term management of B&C waste and to obtain a decision-in-principle from the Government on that issue. Production forecast of conditioned radioactive waste of categories A, B and C until 2070 (end of the dismantling

activities of all the existing and currently planned nuclear facilities), for various operating lifetimes of the existing

nuclear power plants and in case of a possible construction of a European Pressurized Water Reactor (EPR), and

conditioned waste volumes in stock at Belgoprocess at the end of 2005 (all in m3).

Waste production until 2070 (various lifetimes of the power plants) Waste

category

40 years 50 years 60 years

if 1 EPR

(60 years)

Waste in stock

7 power plants

Operating waste 13 800 16 450 19 100 + 8 850

Dismantling waste 35300 35 300 35300 + 7 350

Others

Operating waste 4900 4 900 4900 0

Dismantling waste 16500 16 500 16500 0

A Total: 70 500 73 200 75 800 + 16 200 13 495

B Total: 8700 8 700 8700 + 300 3 966

C if reprocessing resumes Total: 2 100 2 600 3 000 + 590

if reprocessing is abandoned Total: 4 700 6 000 7 200 na 253

Origin of A waste: production of electricity, production and use of radionuclides, research and dismantling.

Origin of B waste: fabrication of nuclear fuel, reprocessing of spent fuel and dismantling.

Origin of C waste: fission products from reprocessing, spent fuel and possible excess fissile materials.

The costs of managing radioactive waste are paid for at cost price by the waste producers. The financing of the long-term management activities is covered by the long-term fund (FLT) that must ensure that ONDRAF/NIRAS will have in time the necessary means to cover its fixed costs and to cover its variable costs as they arise. It is based on a system of capacity reservation associated with tariff payments and contractual guarantees. For B&C waste, the current contractual assumptions are as


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follows: seven nuclear power plants, 40 years of operation, full reprocessing, disposal of category B (resp. C) waste as from 2046 (resp. 2073) onwards. On 31 December 2005, the total assets of the FLT for final disposal amounted to 88 MEUR2005, that is 50 MEUR2005 for surface disposal and 38 MEUR2005 for deep disposal, to be related to the estimated costs (undiscounted base costs and their respective margins for uncertainties):

§ surface repository of STOLA-Dessel for A waste: 360 to 490 MEUR2005;

§ deep repository for B&C waste: 890 to 1310 MEUR2005 in case of full reprocessing and 1250 to

2140 MEUR2005 in case reprocessing is abandoned (estimated costs currently being revised

following an evolution in repository concept).

Informative Box: Nuclear Provisions Definition: Nuclear provisions are established in order to cover all future obligations and the resulting expenses related to the decommissioning of nuclear power plants and the management of spent nuclear fuel. History: Nuclear provisions for dismantling have been built up since the mid-1980s following an agreement between the Belgian State and the then existing four electricity companies

244 with interests

in the Doel and Tihange nuclear power plants. The establishment of nuclear provisions for the management of spent nuclear fuel started in 1986 when the quantities used in the Belgian nuclear reactors exceeded the quantities covered by the reprocessing contracts signed at that time. Recent developments: The Act of 11 April 2003 entrusted Synatom with the management of the provisions and stipulated the creation of a Surveillance Committee for nuclear provisions that has broad advisory and control missions. Synatom was charged with four missions: - the definition of a decommissioning strategy (in close collaboration with the nuclear operator) and the development of scenarios for the treatment of spent nuclear fuel and nuclear waste; - the evaluation of the related future expenses; - the calculation of the necessary nuclear provisions; - the management of the funds corresponding to these provisions. In compliance with the Act, a number of actions have been taken by Synatom, including an agreement with the Belgian State and Electrabel, modifying the structure of the share ownership of Synatom and defining the solvency requirements and conditions for loans granted by Synatom to Electrabel and SPE. Also in compliance with the Act, Electrabel and SPE transferred the existing provisions in their accounts to Synatom. As stipulated in the Act, an elaborate financial reporting concerning the nuclear provisions is communicated to the Surveillance Committee on a quarterly and annual basis. Early 2005, the Surveillance Committee approved Synatom’s proposal for a revised methodology for: - the calculation of the nuclear provisions, - the definition of the scenarios, - the cost estimates, - the definition of the financial parameters (inflation of 2% and a discounting factor of 5%) used for calculating the nuclear provisions. In March 2007, the Surveillance Committee approved a revised version of the nuclear provisions, as presented by Synatom according to abovementioned Act that requires a review every 3 years. At the end of April 2007, the Belgian Parliament voted a revised edition of the Act that changes the composition of the Surveillance Committee and includes articles concerning the use of the funds corresponding to the nuclear provisions for energy saving and in renewables investments purposes. The methodology: The methodology used for calculating the nuclear provisions is based on the International Accounting Standards (I.A.S.). The estimation of the gross amount of future yearly cash

244 Ebes, Unerg and Intercom, which merged into Electrabel in 1990, and SPE.


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outflows is based on studies of internal and external experts. A discount rate of 5 % is utilized to determine the net present value of the future obligations. The dismantling provision and the provision for spent nuclear fuel are annually increased with an interest charge equal to this discount rate and, for the provision of spent nuclear fuel, an additional quantity charge (corresponding to the nuclear fuel used) is added to the provision. Level of nuclear provisions: At the end of 2006, the level of nuclear provisions for dismantling was 1521 MEUR and for the management of spent nuclear fuel 3021 MEUR. These amounts are fully compliant with the evaluation of the long term expenses including storage, conditioning and disposal of nuclear waste due to the electricity production. Guarantees: The Belgian legislators have put a mechanism in place to ensure that the entire provisions will be available within Synatom “at the right time”. This mechanism includes not only an extensive financial reporting and the respect of financial criteria, but also a “golden share” and the presence of 2 representatives of the Belgian Government in the Board of Synatom, preferential claims on the personal assets of the nuclear operator and the final responsibility of the nuclear operators if the amounts provisioned prove to be too low.

12.2.2.2 Continued Operation of Nuclear Plants after the Original Phase-Out Law Deadline In principle, all of the above elements continue to apply. There is no fundamental change because of longer operation of a nuclear power plant. As has been said before, and developed in the section on "lifetime of nuclear power plants" of [AMPERE, 2000, Chapter E], there is no predetermined technical lifetime of a power plant, including a nuclear one. Perhaps one special point of attention should be mentioned, although it is included in the above-mentioned points.

à When continuing beyond 40 years of operation, special attention should be paid to the planned overhaul, whereby lessons learned from so-called 'lifetime extensions' abroad should be taken into account. However, as already stated, there is nothing really different between the 10-year overhaul after 30 years and the one after 40 years. In any case, every 10-year overhaul should be done with the greatest attention so as to guarantee a continued safe operation. The safety authorities have to set the required standards and the operator has to meet them. If they cannot be met at a reasonable cost, the operation may then decide to close down the plant.

Informative Box: Cost of Increasing the NPPs Duration of Operation from 40 to 60 Years

According to the estimates of Vattenfall (Sweden) the cost of the extension from 40 to 60 years duration of operation for the 4 units of Ringhals is 1500 M€, which amounts to about 400 €/kW. These estimates are consistent with the analysis of UBS Investment Research dated March 2005 made under Vincent Gilles. The UBS model suggests that adding 10 years operation to a 1,400 MWe NPP (PWR type) costs a one-off 200 M€. In case of an operational extension of Doel 1 & 2 and Tihange 1, the costs will be finalized when the program of the fourth 10-year overhaul have been agreed with the Authorities.

12.2.3 New Nuclear Power Plants All of the above elements remain valid in the case of new nuclear build. It should be clear that the choice of reactor must be made by the investor, allowing international competition of reactor vendors to play its role, but subject to certain boundary conditions imposed by the authorities. The following is an example of appropriate boundary conditions.


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à The new reactor should be of the post-2nd generation. As generation iv reactors are not expected before 2030 or so, the choice might be generation iii, if an investment decision takes place before 2030. à The reactor should not be 'a first of a kind', but must be a proven design, with at least two other reactors having been built before. à Siting requirements must be conforming to the practices currently applicable, and should preferentially be done in consultation with the local authorities.

Informative Box: Learning curve of EPR NPP.

According to EdF the investment of cost of the future EPR plant to be constructed in Flamanville is 3,300 M€ (value of 2007). This unit is considered as a first of a kind. In the Charpin Report to the Prime Minister [July 2000], the extra cost of the first unit of a series of 10 identical units is estimated at 30%, 20% for the two next units, 10% for the 4

th unit and 0% for the

following units of the series. The above is in agreement with the Belgian experience acquired with cost reduction related to the reproduction of identical units. This cost decrease is due mainly to reduction of engineering cost, reduction of manufacturing cost for the major equipments produced as series of identical components, reduction of project management costs, reduced provisions for uncertainties and missing items. Note: in the case of a possible future Doel V unit, the site preparation cost will be reduced compared to other sites due to work already performed.

The general philosophy behind a justified energy policy of which nuclear power can be part is that there should be a level-playing field between the different energy-conversion means. Governments should limit themselves to setting clear rules and standards for all technologies, and let the market fill in what it feels to be appropriate. Support for one or the other technology should be transparent, as should be external costs of all kinds. As much as possible, external costs should be internalized to have really equal conditions. In such environment, artificial limitations such as phasing out nuclear (or coal fired plants) should be avoided. Subject to a vigilant concern for security of supply and with a redirection towards a sustainable energy provision, the outcome will then be the most economically efficient one, or at least sufficiently transparent. In the end, however, it is up to the people's elected representatives to set the strategic course for a well-thought through energy policy. In case new nuclear units are considered, a clear and transparent regulatory framework must be set. The economics of such project must be left to the investors' market. To support such framework, a participatory process with societal stakeholders should be undertaken, based on a broad cost-benefit analysis, with the aim towards a "sustainable" energy provision. Such process should lead to advises upon which policy makers can base themselves to set the conditions for new nuclear build.

245

245 J.P. van Ypersele (JPvY) strongly disagrees with this paragraph about a new nuclear plant. He really does not think that new nuclear units should be built in Belgium. In his opinion, nuclear energy should not play a major role in the efforts to reduce greenhouse gas emissions at world level. The last IPCC report (IPCC WG3, 2007) puts much more emphasis on the potential of energy efficiency, carbon capture and storage, and renewable energy to reduce global emissions, than it did to a nuclear expansion. In the long term, we have to contribute in the development of a world energy system that relies much less on stocks of fossil and fissile fuel, because they are inherently finite. We need instead to learn to harness the flow of solar (and other renewable) energy which equals about 8000 times the total world energy consumption per year. It is important to capture that renewable flow in the most efficient way, and some of that is probably best done out of the Belgian territory. Harnessing this flow will reduce the risk of “running out” of fuel (the Sun will indeed continue to provide its energy to us for another 5 billion years), reduce the risk of proliferation of nuclear material, reduce the risk of large scale accidents or nuclear terror activities, and reduce the amount of nuclear waste we leave to future generations. To make this possible, we need to dramatically increase energy efficiency, and manage demand so that energy usage per capita converges towards sustainable levels, taking into account local circumstances. In the transition period to such an efficient world energy system relying mostly on renewable energy, and as advocated by the European Union, we urgently need to use carbon capture and storage on our fossil fuel plants, and participate


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Informative Box: Hidden GHG emissions of nuclear power / Storm Van Leeuwen Allegations In a non-peer reviewed internet report, Storm Van Leeuwen presents a Life Cycle Analysis (LCA) of nuclear power systems from ore to electricity. [1-3; 5; 7] It tries to prove that the fuel cycle becomes excessively energy consuming as rich uranium ore reserves become exhausted and fuel supply is tending to decreasing ore grades. The author claims an energy debt (“cost”) of a nuclear power plant (NPP) between 3 and 10 years production, depending on ore characteristics but with neglect of dismantling “cost”. If dismantling is taken into account, full cost is between 9 and ~20 years of

production. In his slide show [3], the author claims lifetime carbon dioxide emissions on the whole production chain at 140 g CO2/kWhe. Reactions on the web site of an Australian academic demonstrate, for a particular Australian uranium mine with 0.05% ore grade, that applying the authors correlations to compute energy demand for mining and milling leads to utmost nonsense compared to reality, since one should need two 1 GW nuclear power stations to exploit the mine. A certified LCA on Vattenfall NPPs, using nuclear fuel from the fore mentioned uranium mine, demonstrates that embedded energy in construction is produced within less than a couple of months, and that nuclear waste disposal would just add one and half a month to that total. Storm, the author of the LCA article on the web, rebutted the arguments of the Australian academic (Sevior) and of Vattenfall as too specific and not representative for the nuclear systems as a whole. In conclusion, the Storm’s LCA of nuclear systems is focalising on producing uranium for nuclear power stations on basis of ever lower grade ore. The used procedure and computations are not transparent and can thus not been verified by a reviewer. Storm’s results pretend that up to half of the electricity produced over the life cycle should be designated to embedded consumers. There are peer reviewed LCAs of NPPs available in the literature that deny that claim. [10] The results of the Belgian CO2-project are in line with the peer reviewed LCAs and refute Storm’s results. [11; 13]

References: [1] Storm Van Leeuwen, Jan, Willem and SMITH, Philip: “Nuclear Energy: the Energy Balance; Chapter 2: From ore to electricity; Energy production and uranium resources”, sixth revision (24 pp). http://www.stormsmith.nl/report20050803/Chap_2.pdf [2] Storm Van Leeuwen, Jan, Willem and SMITH, Philip: “Nuclear power – the energy balance”, summary (6 pp). www.stormsmith.nl/ [3] Storm Van Leeuwen, Jan, Willem: “Climate change and nuclear power”, 2006 (53 slides). [email protected] ; http://ihp-lx2.ethz.ch/energy21/CERN-3Apr06.pdf [4] Melbourne University, nuclearinfo.net: “Everything you want to know about Nuclear Power”, reaction on [1]. www.nuclearinfo.net/Nuclearpower/SLSPredictOD [5] Storm Van Leeuwen, Jan, Willem: “Rebuttal of a Media Release by the University of Melbourne” Wednesday 21 December 2005 (7 pp). www.nuclearinfo.net/Nuclearpower/SLRebuttal [6] Sevior and Flitney: “Response to Jan Willem Storm van Leeuwen” (4 pp). www.nuclearinfo.net/Nuclearpower/SLRebuttalResp [7] Storm Van Leeuwen, Jan, Willem: “Rebuttal Storm2 to response by Martin Sevior and Adrian Flitney”, 15 February 2006 (12 pp). www.nuclearinfo.net/Nuclearpower/SSSRebuttal [8] Sevior, Martin: “Response to rebuttal 2 from Jan Willem Storm van Leeuwen”, June 2

nd , 2006 (6 pp).

www.nuclearinfo.net/Nuclearpower/SeviorSLSRebuttall [9] nuclearinfo.net: “Energy Lifecycle of Nuclear Power” (2pp + xls-sheet 051124 in annex from SETTERWALL, Caroline). http://www.nuclearinfo.net/Nuclearpower/WebHomeEnergyLifecycleOfNuclear_Power [10] Voorspools, Kris, R. et al.: “Energy content and indirect greenhouse gas emissions embedded in ‘emission-free’ power plants: results for the Low Countries”, Applied Energy 67 (2000) 307-330. [11] Huybrechts, D., VITO: “Broeikasgasemissies en energiegebruik voor levering van energiedragers vanaf de ontginning tot aan de eindgebruiker”, 1997/PPE/R/073 (76 pp).

in the diffusion of this technology in all countries with large fossil-fuel reserves. Building a new nuclear plant in Belgium would only postpone the needed transition towards a more sustainable world energy system.


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[12] Mortimer, Nigel: “World warms to nuclear power”, December ‘89/January ’90 issue of the SCRAM Safe Energy Journal (3 pp). www.no2nuclearpower.org.uk/articles/mortimer_se74.php [13] D’haeseleer, W. et al., 2000: “De oorsprong van CO2-emissies ten gevolge van energieconversie: een analyse van wieg tot graf”, E tijdschrift – 116

e jaargang – speciaal nummer (herfst 2000) (102 pg). Texte

également disponible en Français.

Informative Box: Generation-IV Nuclear Power Reactors Generation-IV reactors are a revolutionary type of reactors with innovative fuel cycle technologies. They may be available for commercial application around 2030-2040 to respond to the following main sustainability criteria and future market conditions:

• incorporate advanced nuclear safety; • to be resistant to proliferation in addressing nuclear non-proliferation and physical

protection against aggression; • to be highly economic and competitive; • produce minimal waste and optimal use of natural resource utilization.

Six designs are presently selected with multiple criteria in mind:

(i) Sodium cooled Fast Reactor (SFR) (ii) Very High Temperature gas Reactor (VHTR) (iii) Super Critical Water cooled Reactor (SCWR) (iv) Lead cooled Fast Reactor (LFR) (v) Gas cooled Fast Reactor (GFR) (vi) Molten Salt Reactor (MSR).

These criteria are as follows:

• both small and large NPP-designs were retained matching the different power plant needs in various markets, e.g. large NPPs mostly for developed countries using a well established electricity transmission network, smaller NPPs mostly designed for local or regional markets with less developed electricity infrastructure;

• avoiding the energy conversion thermal losses by aiming at higher thermal efficiencies, i.e., 45% and well above, as well as aiming towards providing process heat next to electricity as energy products. Water desalination and hydrogen production being typical examples of such new markets;

• better use of natural resources and minimization of radioactive waste arising through the use of recycling of spent fuel (closed fuel cycle) in four of the Generation-IV designs and especially by using fast spectrum reactors. The use of such fast spectrum reactors provides a means to make about 100 times better use of the mined uranium compared to today’s Generation-II and even Generation-III NPPs while also providing a means to reduce with a comparable factor the amount of radioactive waste to be disposed of.

The six Generation-IV NPP-designs are very different and also present different challenges to be investigated in the ongoing R&D-programs. The figure below shows the expectations of availability of each of these Generation-IV designs, suggesting that some of the Generation-IV designs are aimed for from the year 2030 on, whereas others may still need significant additional R&D and would only become available well after the year 2040. Full commercial and routine availability is still to be proven. (Note that Accelerator-Driven Systems (ADS) which are sub-critical fast reactors coupled to particle accelerators are not part of the retained Generation-IV technologies.) More information on the different generations of nuclear reactors is provided in Annex 6.


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LWR-alike NPPs Gas-cooled high-

temperature NPPs Fast Spectrum NPPs Other technology

> 2025

> 2035

> 2045


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12.3 Nuclear Liability Nuclear operators are liable for nuclear accidents up to a certain point. This liability is already substantial but nevertheless limited. (See Informative Box.) It is often argued that this amounts to a hidden subsidy. Therefore, to supplement the current nuclear liability coverage, it is recommended that in an EU or OECD context, Belgium advocates the idea to set up an EU or OECD-wide but nuclear operator/owner-funded and -managed liability fund to cover the extra liability in case of a severe accident. This nuclear liability partnership should be funded pro rata of the nuclear installed capacity within the EU or OECD. See also [Vanden Borre, 2001].

Informative Box: Nuclear Liability

This issue is dealt with internationally by the conventions of Paris and Brussels. In Belgium, the situation is currently as follows: - amount to be covered by the nuclear operator: 297.5 MEUR - amount to be covered by the Belgian state: 0 EUR - amount to be distributed over the participating countries: 163 MEUR The amount of 297.5 is a consequence of the law of July 11 2000, changing the law of July 22 1985 concerning the legal liability regarding nuclear energy (according to which the responsibility of the nuclear operator was limited to 99 MEUR). This modification was established in anticipation of a revision of the conventions of Paris and Brussels. A revision of the earlier mentioned conventions changes these amounts as follows: - amount to be covered by the nuclear operator: up to minimal 700 MEUR (whereby each country can go higher if it decides to do so); - amount to be covered by the state where the accident occurs: between 700 MEUR (or higher) and 1200 MEUR; - amount to be distributed over the participating countries: between 1200 and 1500 MEUR. Ratification of these revised conventions of Paris and Brussels has not yet taken place. This is foreseen by the end of the year 2007 (after submittal of the bill at the beginning of the new legislature). An increase of these liability-related responsibilities of the operators only has a limited influence on the insurance premium and consequently on the cost of a nuclear kWh. This can be explained by the fact that a risk is being insured. A risk is the product of the consequences with the probability that an accident occurs. The larger an accident, the smaller the probability (as has been shown is several nuclear-related and other studies). Therefore, the increase of the liability ceiling has only influenced the covered risk to a limited extent. It is therefore a false impression that a ceiling on the liability amount represents a large cost evasion by the nuclear operators. The ceiling of the liability amount has to do with the capacity of the insurance market. This capacity increases with time. It is important to mention that all mentioned amounts are based on the accident of Chernobyl. The large damage in this accident was caused by the fire of the graphite core, which has caused large turbulence and updraft and hence a large dispersion of radioactive material. Furthermore, the Chernobyl plant had no containment building. The Belgian reactors and most reactors worldwide do not have a graphite core and do have a containment building. In these reactors, it is impossible that a fire of similar dimensions as in Chernobyl takes place, and the containment building will contain most of the radioactive material. Even in case of a very serious accident, damage as occurred with Chernobyl, is virtually impossible. For nuclear reactors of the third generation (e.g., EPR), a serious accident would only require evacuation op people within a radius of 1.5 km. For reactors of the fourth generation, there would effectively be no need for evacuation.


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12.4 Nuclear Power, Energy Efficiency and Renewables

If we believe the 'mechanics' put into PRIMES, which according to some is already rather favorable to take up energy-efficiency measures and to allow for demand reduction,

246 then it seems that the

amount of energy-demand reduction as portrayed in the PRIMES results is only possible at a 'considerable' economic cost. Saying otherwise, if one were to impose such energy-demand-reduction measures through regulation etc, then that is not impossible, but the costs will remain (perhaps reduced by the dynamics of the market through further and quicker development of new technologies, but most often also enhanced by hidden transaction and administration costs). According to PRIMES, and not surprisingly for the Belgian situation from now to 2030, allowing nuclear power is the cheapest way to obtain severe post-Kyoto limits. However, although the nuclear option will certainly decrease the overall system cost, and therefore the system-enforced final-energy-demand reduction, one should still strive to encourage energy efficiency as much as is reasonable, i.e., sufficiently ambitious and in 'clever' ways, but without loosing sight of the extra costs that this might imply. In order to estimate that properly, an overall cost estimate (including overall costs for the whole economy, including external costs —environmental, and all kinds of hidden costs, including security of supply aspects) should be undertaken. However, no reliable overall long-term simulation model exists to provide useful projections. It is often claimed that a nuclear phase out must be used as a 'crowbar' to force our energy economy into a direction of more energy savings and more renewable energy. This is known as a typical contrasting approach, nuclear power versus the so-called more sustainable routes, energy efficiency

247 and renewable energy. This philosophy is disputed by others, with arguments based on

standard economic theory, since this approach implicitly acknowledges that the so-called more sustainable routes are more expensive, and can only enter the market if its 'adversary' is eliminated. This is also shown by the PRIMES results; the non-nuclear scenarios are much more expensive for the energy economy than the nuclear-allowed ones. In principle, energy savings and renewables should not be considered as being opposite to nuclear power. If energy savings and renewables make sense (and are indeed economically justified), then they should be advocated regardless of whether or not nuclear power is present.

248 Certainly, market

failures should be eliminated, and perhaps, energy savings and renewables need some initial support for market introduction, but in the end they should be economic (taking into account external costs), and be able to stand on their own. Otherwise, society would be wasting economic resources. A healthy approach is that both energy saving and renewables, on the one hand, and nuclear power, on the other hand, can be part of the overall energy mix. By means of its authorities, society should set appropriate boundary conditions (with a stable regulation and preferentially in line with European rules) and then let the market decide which routes to take. Whenever the authorities believe to have good reasons to support one or the other technology (perhaps because of security of supply, or to accelerate market diffusion) via subsidies, enforced minimal quota, state-guaranteed loans, etc, then that should be done in a transparent way, so that the overall picture is clear. Given the current situation in Belgium, with a questionable nuclear phase-out law on the books, doing away with that phase-out law, clearly is the most economically efficient way to reduce greenhouse gases. One could then argue that some of the economic system savings obtained by having nuclear power might be shared to stimulate energy efficiency by launching market introduction of efficient technologies and renewables. To stimulate and even incite parallel approaches on the demand side and the supply side, and to keep the financial equation in balance, one should consider a win-win

246 A claim that is disputed by others who believe that PRIMES should be more voluntaristic for demand-side technologies. This discussion goes back to the 'accounting-based spreadsheet-like engineering economics' viewpoint versus the 'standard economics' viewpoint. See Chapter 4. 247 Generally speaking, by 'energy efficiency' and 'energy savings', we mean improved end-use technologies, CHP or cogeneration and more efficient supply-side technologies. 248 The high energy efficiency in France, shown in Figures 4.1 and 4.2, contradict the "common" perception.


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situation in much the same way as has been done in the Netherlands with regard to the Borssele nuclear power plant. In a mutual agreement (formally established through a 'Covenant' [VROM, 2006a]), the Borssele plant

249, which started operation in 1973, and which was supposed to be shut

down first in 2003 and then in 2013, as part of political decisions, has now received permission to continue operation until the year 2033, with thus a total operation time of 60 years. According to the compromise or deal, the owners of the power plant commit themselves to spend an amount of 250 M€ to accelerate the transition to a more so-called 'sustainable energy provision' (200 M€ for sustainable projects and 50 M€ fed into a special fund), as a sort of compensation for the permission to continue to operate the plant. The government from its side has promised to make a special effort to promote the transition towards such more sustainable energy provision by matching this amount with also 250 M€. A similar approach, using the Dutch Borssele agreement as an exemplary source of inspiration, could be sought for in Belgium. In the interest of a more balanced primary energy mix and thus security of supply, and a substantial post-Kyoto contribution for reducing CO2 emissions, one should continue operation of the existing power plants (and permit new plants if investors believe that that should be done)

250, but negotiate an agreement to make them pay a “correct” concession fee/rent. The thereby

collected revenues could be used by the government for stimulating investments in energy savings & demand-side management, for development in renewable energy, for development & research in emerging energy technologies and carriers.

251

It must be noted that the operational lifetime of the existing plants should be left non-limited a priori

252,

in the sense that the prime requirement should be the continued safe operation of the plants. The safety of plants is to be thoroughly examined on a ten yearly basis (by means of the 10-year overhauls) and the state of the plants (thereby requiring possible upgrading investments) must be approved by the nuclear supervisory bodies (amongst which the Nuclear Regulator), possibly confirmed by an international audit.

253

As part of this agreement, earlier agreements that were made in the context of the nuclear phase out should be revisited.

249 Of the PWR type; with net power output of 450 MWe 250 But, see also footnote 245 by JPvY. 251 According to economic theory, this is not the most efficient way of spending these revenues. The magnitude of the rent or tax revenue may be larger by several factors than the needs for subsidies for renewables, energy savings and demand-side management. Caution must be expressed against over-subsidizing because of this earmarked money; any justifiable investment —including for renewables, energy savings and demand-side management— must pass a cost-benefit test, also accounting for its environmental benefits. The remainder of this nuclear rent may be devoted to other valuable means, such as lowering labor charges or reducing the national debt. 252 Note that "non-limited" is to be distinguished from "unlimited". 253



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Part IV

Conclusions & Recommendations


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Summarizing Conclusions

of the Commission Energy 2030 The Energy Issue is a Daunting Challenge The goal of a comprehensive energy-provision strategy for Belgium must be to offer energy services

254 for a variety of applications, but in a 'sustainable' manner. Viewed pragmatically, a

'sustainable energy provision' relies on an energy basket that simultaneously guarantees a firm security of supply, at an acceptable cost for our society,

255 and in an environmentally friendly way.

Against the current situational background of the following elements:

• oil & gas prices that fluctuate strongly and can be very high; • the anticipated soaring energy-demand on a worldwide scale to give poorer nations a well-

deserved energy provision, in turn leading to possibly severe tensions on the world energy-supply scene;

• the lack of own energy resources, and therefore the very large import dependency for oil and gas from geopolitically unstable regions, with very strong oil dependence for transport, home heating and chemicals, and strong gas dependence for industrial applications and electricity generation;

• the geographical reality of our country, considerably limiting the natural influx of renewable flows;

• expected substantial post-Kyoto GHG- and CO2-emission reduction obligations; • the existing nuclear phase-out law, starting in 2015 and fully executed in 2025; • the creation of a common liberalized European energy market; • the huge investments needed worldwide to replace existing and ageing energy

infrastructure, to develop further production investments for oil and gas, to extend transmission networks for electricity and gas;

and the high degree of uncertainty with many of them, the CE2030 must conclude that the future energy provision for Belgium represents a daunting challenge over the coming 25 years and beyond.

A European Approach is Imperative As a result of its analysis of the current situation in Belgium, Europe and worldwide, and the scenarios performed and studied, the CE2030 has the conviction that Belgium cannot afford to solely think nationally in energy matters, albeit that national responsibilities should not be evaded. Indeed,

• concerning import dependency and security of supply (especially towards an optimal mix of long-term contracts and spot-market supply of gas, and gas storage capability; exchange of electrical fluxes to smoothen out imbalances);

• for establishing a real competitive energy market (especially on the wholesale level for gas and electricity);

254 By "energy services" is meant the activities and applications we wish to enjoy: heat rooms to comfortable temperatures, keep food and drinks cool, drive kms, provide drive power and process heat in industry, etc. This concept here is different from the "services" provided by so-called "energy service companies (ESCOs)". 255 The CE2030 considers the social aspect of energy provision as being part of the economic dimension. All scarce resources must be utilized in the most efficient way, and prosperity for society should be maximized (subject to obvious and/or reasonable constraints) and the acquired welfare must then be distributed in an equitable way, such that all members of the population could benefit from a well-functioning economy. The social issues go much broader than merely energy issues; governments must develop a broad social framework for their citizens. The energy-provision issue must not be singled out for social-policy purposes, but citizens must get equal and fair access to all energy-related opportunities. If imperfections exist, authorities should correct these distortions, and possibly compensate. However, priority must go to a broad social framework; energy-related interventions should be limited in time (except for the right to have access to a certain minimum of energy supply).


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• since most of the energy-conversion infrastructure is owned by international shareholders and is operated in function of the European market, and perhaps more so in the future;

• for making its GHG-reduction commitments acceptable (to basically finance reduction emissions elsewhere);

• to demonstrate sufficient weight on the international scene for negotiations with equipment manufacturers, for launching large R&D programs, …;

• to push through necessary but difficult decisions and commitments, that are unpleasant/hard to make on a national level (similar to e.g., the Maastricht criteria);

a European-wide approach is imperative. The CE2030 is therefore of the firm opinion that Belgium has to fully subscribe to a European energy policy, thereby relying on an appropriate regulatory EU framework. Conclusions of Scenario Analysis The CE2030 has carefully studied the energy-provision issue for Belgium. It has done so by exploring and studying the relevant scientific, technical and economic energy-related literature, through consultation of experts in the field. Moreover it has examined the feasibility and economic costs of different scenarios with the time horizon of 2030, obtained by the PRIMES energy model.

256

All sectors (industry, residential & commercial & service sector, transport sector, electricity sector) as well as all primary and final energy carriers (oil, gas, coal, renewables, uranium, electricity, heat) have been studied. Because of the circumstances, mainly induced by the climate-change threat, the electricity sector plays a crucial role, however, in that important switches (nuclear power and carbon capture & storage) are situated in that sector and because the gas supply for that sector is of utmost importance. Nevertheless, the interaction between all sectors and carriers is properly taken into account. The CE2030 has furthermore reflected attentively upon the comments made by the Review Panels, and has taken into account the pertinent remarks in its final report. All scenarios considered assume a reasonable projection of future demand for energy services (related to GDP growth, demographics, etc), identical to the recent PRIMES scenarios published by the European Commission DG TREN in May 2006. The results are clearly related to this basic hypothesis; a slower growth will lead to less pressure on the energy system; if growth turns out to be higher, then reality may be more demanding than what the model results show.

Baseline Scenario

A first so-called baseline scenario (basically a further endogenous future energy-system development, designed to allow comparison with later alternative scenarios) implements all energy- and climate-related policy measures and instruments agreed upon until 01.01.2005. It assumes no extra policy measures and does not impose any post-Kyoto constraints on greenhouse gases (GHG). In this scenario, the nuclear phase out is assumed to be fully effectuated.

257 258

In the baseline projections, despite a considerable increase of energy-service demand, the final energy demand itself (at the level of the consumer) increases only moderately. This means that relatively cheap options for energy efficiency are taken up, leading to a considerable decrease by 2030 in energy intensity

259 by 30% compared to the value in 2005 for all sectors. In the baseline

256 The actual scenario runs with the energy-system model PRIMES have been executed by the University of Athens (NTUA). The scenarios were defined by the CE2030 after discussion with experts of the Belgian Federal Planning Bureau (FPB), which was responsible for the detailed scenario analysis. At the present time, there is no appropriate modeling alternative since the PRIMES approach has been selected by the FPB and the renewed version of MARKAL/TIMES was not ready for detailed examination within the CE2030 framework. Moreover, PRIMES is a widely recognized European model, frequently used by the European Commission as a tool for helping to design its energy policy. 257 The Baseline is not designed to meet medium-term targets (e.g., in 2012); in principle, it provides a means to check whether the measures are sufficient to meet the targets. 258 Assumed fuel prices start from 55$/bbl in 2005, to become 60$/bbl in 2030. Gas prices are coupled to oil prices. All prices are expressed in constant terms in $2000. 259 Being the energy demand per unit GDP.


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scenario, coal-based electricity generation basically replaces most of the nuclear capacity and increases fivefold between 2020 and 2030. Overall CO2 emissions increase substantially from 116 Mton/a in 2005 to 140 Mton/a in 2030 (being an increase by 32% compared to 1990). In this baseline scenario, the higher oil & gas prices and the nuclear phase out put a certain pressure on the energy system, but the absence of a post-Kyoto limit allows a 'convenient' escape route through the massive installation of coal power plants for electricity generation. Clearly, the Baseline is not sustainable with regard to CO2 emissions. A variant to this baseline, assuming 'soaring' oil prices up to 100 $/bbl in 2030, does not lead to a dramatic difference. The final energy demand is slightly lower but the overall CO2 emission remains at the same level as in the baseline. Alternative Scenarios with Post-Kyoto Obligation To contrast with the baseline, several 'alternative' scenarios have been considered in order to find out what the effect of certain policy choices & technology-availability options are. Two types of scenarios have been examined. In a first approach only domestic reductions of energy-related CO2 emissions on the Belgian territory have been implemented. In a second approach, a European-wide Greenhouse-Gas reduction (GHG) obligation has been imposed. Part of these reductions has been materialized in Belgium; the remaining obligations are to be satisfied by purchasing emission allowances abroad. a. Domestic CO2 Reduction Constraint Two post-Kyoto targets of 15% and 30% of domestically energy-related CO2 reductions in 2030 compared to 1990 have been investigated, with for each case the implementation of the nuclear phase-out law, and the possibility for Carbon Capture and Storage (CCS) as additional 'turn-on/switch-off' variables. Such scenarios have the advantage of being transparent and they show the degree of difficulty to meet the imposed constraints domestically. The scenario results show indeed that domestically effectuated CO2 cuts up to 30% are not affordable for Belgium if nuclear power is phased out and if carbon capture & storage (CCS) turns out to be unavailable. This is a proof 'ex absurdo'. Without nuclear power and without CCS, marginal CO2 abatement costs (or market price for CO2 permits, here called 'Carbon Value', or CV) of up to 500 to 2000 €/ton CO2 for the -15% and -30% scenario, respectively, are reported. For the same increasing energy-service demand as in the baseline, these very high carbon values force a drastic final-energy demand reduction, well beyond those demand reductions doable at reasonable cost, and thereby imposing a high cost on our economy. With such pressure on the energy system, final energy demand for the 15%-reduction case diminishes by 20%, and the energy-related cost in 2030 compared to the year 2000, would increase by 150% in industry, 150% in the tertiary sector and by 170%, in the residential sector, compared to 24%, 31% and 63%, respectively, in the baseline.

260

For the 30% CO2 reduction case, these numbers are much more dramatic. The final energy reduces by somewhat more than 30%, while the energy-related cost in 2030 would increase by an astounding 440%, 510% and 420%, for industry, tertiary and residential sector, respectively, again compared to 24%, 31% and 63% in the baseline.

261

Primary-energy import dependency (in terms of average energy per year) amounts to about 90% for both cases.

262 Gas dependency for electricity generation is about 80-85%, again in average annual

energy terms, but more than 90% when the installed wind and photo-voltaic (PV) capacities are not able to deliver power.

260 Expressed in €2000/toe. 261 Expressed in €2000/toe. 262 Import dependency in the Baseline (also with the nuclear phase out implemented) amounts to 95%.


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60

70

80

90

100

110

120

130

140

150

160

2000 2005 2010 2015 2020 2025 2030 2035

Year

FE

D in

ten

sit

y [

kto

e/M

eu

ro]







Values for 2030

In 2000: 540

In 2000: 820

In 2000: 960

Baseline 660 (24%) 1100 (31%) 1600 (63%)


1300 (150%) 2100 (150%) 2600 (170%)


2900 (440%) 5000 (510%) 5000 (420%)


If a nuclear phase out is implemented, and given expected technological evolution, the scenario results show that domestic CO2 reductions are very expensive. The numbers, as produced by PRIMES under the given hypotheses, show that a domestic CO2 reduction of up to 15% would be barely tolerable; but also the 'unreasonableness' of a domestic 30% CO2 reduction scenario by 2030 (compared to 1990). After having utilized the other 'solution paths', such as energy savings and renewable energy, to a maximum reasonable extent according to PRIMES, substantial relief of this extremely heavy task to reduce domestic CO2 emissions can be further obtained if carbon capture and storage (CCS) would be available or if nuclear power were allowed to continue operation beyond 2015 and 2025. For the 15% CO2 reduction cases, marginal abatement costs (CVs) of about 50 to 100 €/ton result, whereas the -30% case still leads to CVs of the order of 200 to 500 €/ton. Still a 'respectable' end-energy demand reduction occurs, albeit at a lower cost. To go from 2000 to 2030, the projected energy-system costs for the end-use sectors are as follows. For the -15% case, the cost is 'slightly' higher than the cost in the baseline (although still up to 50% higher for industry) if nuclear power were allowed, whereby the no CCS case is yet somewhat more costly; the case without nuclear power but with CCS, has a system cost that is 2 to 4 times more expensive than the baseline. For the 30% reduction case, costs with nuclear power allowed range from about 2 to 4 times the cost of the baseline (compared to a factor 15 to 20 without nuclear power and without CCS), with the case with both nuclear and CCS available, being the cheapest. The import dependency reduces to about 65-70% when nuclear power is allowed.

263

263 Here, import dependency over a time scale of about one to two years is meant. Nuclear generated electricity is considered of domestic origin on this time scale.


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Values for 2030

In 2000: 540

In 2000: 820

In 2000: 960


CCCS CCS

730 (37%) 1100 (36%) 1600 (71%)


790 (47%) 1200 (43%) 1700 (79%)


970 (81%) 1500 (83%) 2000 (110%)


930 (73%) 1400 (73%) 2000 (100%)


1200 (120%) 1800 (120%) 2400 (150%)


1300 (130%) 2000 (140%) 2500 (160%)


It must be noted, however, that these two ‘alleviating options’ are not equivalent though. Carbon capture and storage is still to be developed and it is very risky to assume that it will be routinely commercially available by 2030 in Belgium (especially the storage part). Nuclear power is currently operating, meaning that this is an option that the Belgian policy makers can make available to the electricity generation sector. To give the system model some liberty to find an outcome, not too many constraints on potentials were imposed. In a post-model interpretative analysis, a pertinent situation sketch, concentrating on the challenges revealed, has qualified these simulation results. By confronting the challenges revealed with plausible ‘real-life’ difficulties, such as taking into account the grid-extension costs for massive expansion of offshore wind capacity (> 900 MW) and PV installed power (> several 100 MW), the rate of technology manufacturing, and the offers asked from the consumers to pay extra for a particular new type of energy provision, the situation will be more critical, both for import dependency and system cost. The system cost to adapt the high voltage network for 3,800 MW offshore wind power is estimated to be about 700 M€; the adaptation of the distribution grid to accommodate more distributed generation, amongst which massive utilization of PV, is estimated to be about 2,000 M€ over a period of 10-20 years. The commitments for green certificates may be overwhelming and policy makers must realize what they promise, so as to remain correct to investors, on the one hand, and with regard to the offers they ask from the final energy consumers, being reflected in higher energy tariffs/prices, on the other hand. Assuming that the current legal framework of guaranteed buy-back prices

264 is kept, are in constant €

and if paid during 20 years, then the following daunting cost figures would apply: - the current 846 MW of offshore wind farms with concession à ~ 6,000 M€

265

- the next 3000 MW offshore wind power à ~ 21,000 M€ - for 2000 MW onshore wind à ~ 7,000 M€ - for 1000 MW PV à ~ 7,200 M€ - for 1500 MW biomass à ~ 9,600 M€ In total, for the 'foreseen' renewable expansion, the end customer will have to contribute via green certificates, and thus increased tariffs, something in the order of a total of ~ 50,000 M€ over 20 years, or about 1/5 of the GDP of 2000, or roughly 1/10 of the estimated GDP of 2030, or 0.7% of the average GDP/a over the period 2000-2030. This exercise also shows that the simulation results of 10,000 MW PV (with a similar support scheme) are quite unrealistic. Indeed, such support would add up to ~ 72,000 M€, which together with

264 Note that this is effectively equivalent to a feed-in tariff. 265 M€ stands for one million €. The comma represents thousands (English language convention). 1,000 M€ = one "milliard" in French and one "miljard" in Dutch.


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the above amounts to about ~ 115,000 M€ or ~ 1/3 of the average GDP/a of the period 2000-2030, or about 40% of our national debt.

b. European GHG Reduction Constraint In a second approach, an overall European GHG reduction target of 30% in 2030 compared to 1990 has been investigated.

266 After an estimate of the decline of the non-CO2 GHG, taking into account the

marginal abatement costs of all European countries, and by freely allowing European exchange of climate reduction efforts through flexible mechanisms, it is found how the CO2 reductions are distributed over the countries. In all scenarios here, no CCS is considered to be available.

-20%

-26%

32%

-30%

-12%

-1%

20%

-0,4 -0,3 -0,2 -0,1 0 0,1 0,2 0,3 0,4

EU - GHG constraint







GHG = greenhouse gases Reference = Baseline




Green: with nuclear

In the Baseline (being the same as already considered; labeled as "Reference" in the figure), GHG emissions in Belgium would increase by 20% while CO2 emissions would increase by 32% compared to 1990. With the nuclear phase-out law implemented and without CCS (implying an increase of the Belgian marginal abatement cost to reduce energy-related CO2 compared to the current situation and to its EU neighbors), most reductions will take place abroad, with only a 12% reduction of GHG and a mere 1% reduction of CO2 on the Belgian territory. With nuclear power allowed (and without CCS), the cost to reduce energy-related CO2 in Belgium becomes much smaller, giving rise to a GHG reduction by 26% and a CO2 reduction amount of 20% on the Belgian territory. These results show that the nuclear phase-out law prevents cheap domestic CO2 reductions, leading/forcing Belgium to implement and finance reductions abroad. Under the hypothesis that Belgium will have to accept a similar GHG-reduction obligation as its European trade partners, which we take for simplicity equal to the EU level of 30%,

267 the European approach means that GHG

reductions can be obtained at lower costs than effectuated domestically. However, the emission reductions abroad must be paid for by Belgium via equivalent emission allowances, at a price of the equilibrium marginal abatement cost (MAC). The extra cost is approximately given by the colored triangular area OGE of the figure below and with a European emission allowance price of 200 €/ton CO2-eq in 2030 (being the equilibrium value found by PRIMES), the extra cost due to the nuclear

266 The CE2030 is grateful to Dr. Dominique Gusbin of the Federal Planning Bureau for having made these results available for incorporation in the final CE2030 report. 267 For the wealthier EU countries, amongst which Belgium, a burden sharing based on equal GHG abatement cost per personal income, could lead to an even more severe reduction obligation/responsibility. For details, see main report, Chapter 3. .


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phase out will be of the order of ~ 2,000 M€ in 2030.268

For the last five years 2025-2030 of the horizon considered in this report, i.e., after the nuclear phase out in 2025, these amounts will be of the same order, leading already to a cumulated extra cost of ~ 10,000 M€. Integrated from the post-Kyoto period 2010, with a first phase out in 2015, the next one in 2023 and a final one in 2025, till 2030, this would lead to an extra cost for CO2 abatement of about ~ 15,000 - 20,000 M€.

269

This extra cost is about 6% to 8% of the GDP of 2000, or 4% to 5% of the GDP of 2030. On an annual basis, during the period 2025-2030, this amounts to roughly 0.5% of the annual GDP of that period. For these GHG and CO2 reductions on a EU level, it is assumed that no flexible mechanisms outside the EU are applied. The 30% reduction of GHG is assumed to be effectuated within the EU. Concerning GHG reductions on a EU scale, Belgium could hope to bargain for a smaller GHG reduction obligation as part of a negotiated burden-sharing agreement, using the argument that its domestic abatement costs are very high due to the nuclear phase out.

270 Besides the fact that with the

horizon of 2030, and with a likely full use of flexible mechanisms within the EU by that time, such a lenient treatment will very unlikely be granted by the other EU member states and one should question whether such viewpoint is ethical at all. The correct attitude would be that Belgium takes the same burden in terms of GHG-reduction cost per personal income as its most important EU trade partners (thus, in terms of reduction responsibility). In doing so, it will then only reduce GHGs domestically in accordance with the lowest abatement cost, at the same time relying on buying emission allowances abroad, to satisfy the balance. In any case, because of the uncertainty on the future GHG reduction obligation for Belgium by 2030, Belgium should not adopt an ostrich attitude and prepare its energy system for a severe reduction, to be ready in time. Consequently, the costs for severe GHG reduction obligations will be very high, unless appropriate policy choices are made, as suggested in our recommendations. Modeling Caveats A possible re-injection of carbon-related revenues into the economy, may lead to some relief, but it turns out to be limited, and actually in this case of second order. First, the extra allowances to be bought abroad to mitigate the effect of the nuclear phase out, do not lead to revenues for the Belgian authorities. Furthermore, a re-injection into the economy (e.g., to lower labor charges) of its carbon-emission revenues for the GHG that Belgium is allowed to emit, may lead to a lower cost for the overall Belgian economy than if no re-injection had occurred, but, because of still existing distorting

268 The amount HD equals 20 Mton/a in 2030 since the Belgian GHG emissions in 1990 amounted to 144.3 Mton, and the triangular-like area ≈ (HD*HG)/2 (i.e., base*height/2) ~ 20Mton * 200 € / 2 = 2 000 M€. For details, see report, Chapter 6. 269 Expressed in constant €2000. 270 In fact, according to environmental economics logic, the decision to phase out nuclear power should lead to the contrary, i.e., a larger GHG commitment in terms of obligation for Belgium. See report, Chapter 3.


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taxes, the overall cost for the Belgian economy will nevertheless be larger than what PRIMES has computed. We recall that the above PRIMES results are subject to the following caveats: (1) the Belgian domestic scenarios only refer to energy-related CO2 emission reductions; (2) the estimated carbon values referred to above should not be interpreted as actual costs of policy implementation but rather as an indicator of the relative difficulty of achieving the constraints; (3) the CO2 abatement costs are a function of the type of policy instruments that are used to reduce the emissions; in the scientific economics literature, one accepts that subsidies, regulations and grandfathered tradable permits tend to increase the overall costs while CO2 taxes recycled via lower labor taxes are less detrimental for the economy than if no recycling would take place; and (4) the environmental benefits of taking appropriate actions to reduce the negative impacts of climate change are not taken into account. It is important to recall that the benefits depend on the world-wide carbon-reduction effort; so climate-change benefits for Belgium are only guaranteed if not only the EU, but all industrial (and developing) nations make an effort.

Security of Supply (SoS) Assuming severe GHG reduction obligations, and under a nuclear phase out without the availability of routine commercial CCS, the import dependency will be very high, especially for gas for electricity generation. This will require a careful policy for contracting the gas supply, via an optimal mix of long-term contracts and spot-market supply of gas. In addition, timely decisions for gas infrastructure (pipelines and storage) will be needed. As to electric power transmission, the three functions of the grid must be kept in mind: contracted import/export (i.e., trade), the balancing of massive correlated intermittent generation in Europe, and keeping sufficient reserve transmission capacity to cope with incidents (i.e., the reliability issue). Timely investment decisions for substantially increased cross-border transmission capacity will be necessary. In case of a nuclear phase out, the full electricity generation system must be replaced by 2030, and even more to cope with the expected electricity demand increase. These investment challenges require that the authorization permits should be granted in time and under a stable regulatory framework. Also, investors must get a fair return; for natural monopolies, the system operators must be allowed to transfer these costs to the customers. In case the nuclear phase-out law would be lifted, many of these SoS challenges would still remain, but the pressure would be considerably less, such that the investments are more easily absorbed by the economy. It must be understood that questioning the actual implementation of the nuclear phase-out law does not hamper the further build up of renewable investments, since that type of investment is not market driven but entirely "subsidy/support" driven. The build up of renewable sources is entirely a consequence of policy-makers' decisions. As already hinted, policy makers must understand what they promise and then abide by their promises.

Liberalized Markets It must be emphasized that in liberalized markets, the price is set by the short-term marginal cost.

271

Only in the long run, average price equals average cost272

, and only so in fully competitive markets. This means that higher prices in liberalized markets are not unusual if marginal costs increase. If production quotas are limited, then prices may go higher as is the case with current oil prices.

273 Gas

271 The marginal cost is the extra cost to produce one extra unit. 272 The return on investment for the shareholders is considered here as an opportunity cost, in the sense that a company can borrow money from the financial market (with a certain interest) or from its shareholders (at a certain return rate) who will only invest if the return is at least as high as it would be for other opportunities that exist somewhere else. 273 For the oil market, other factors such as risk premiums, available stocks, financial speculation etc. also play a role.


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prices tend to align with oil prices. These primary energy-price increases are reflected in higher electricity prices. In addition, the price of GHG emission allowances is added.

274

Examination of e.g., the wholesale prices in the NW-European market shows that the Belgian prices are in line with its immediate neighbors. This is due to enhanced import capacity as of 2005. For the day-ahead market, the coupling via BELPEX appears to have a beneficial effect as well. The wholesale market seems to operate correctly. Even with dominant local players, the liberalization process on the wholesale market seems to function on a NW-European scale. A well functioning retail market needs sufficient suppliers with reasonable market share. This should be the medium-term goal. Via the electricity exchanges, suppliers must be able to provision themselves at the correct price. Regulators must monitor this carefully. It must be stated, however, that given the overall price increases for gas and electricity, the distribution costs for infrastructure upgrade, and the extra levies, customer prices are not unreasonably high compared to the neighboring countries. A well functioning liberalized market requires efficient regulators and a correct understanding between governmental services, regulators, TSO's and market players. The fragmentation of responsibilities in Belgium is not efficient for a good market operation.

Cost of the Nuclear Phase-Out Law Considering the major challenges faced by the Belgian energy economy, it must be concluded that, especially in the light of the daunting challenges mentioned before, and mainly the very stringent GHG-reduction efforts expected, an actual implementation of the Belgian nuclear phase out turns out to be expensive. In fact, Belgium will pay a substantial amount for the premature closure of its nuclear power plants:

Ø By phasing out so much cheap base-load capacity, the electricity supply curve will shift to the left. Because of not-unlimited transmission capacity, phasing out 6000 MW will lead to an increase in electricity prices.

Ø Belgium gives up a cheap way to reduce CO2 emissions domestically; as a consequence, emission allowances must be purchased abroad.

Ø Allowing nuclear stations to continue would allow the state to bargain for a concession fee (basically skimming part of the revenues). Not doing this, amounts to an opportunity cost for the Belgian state;

Ø Giving up nuclear power increases our import dependency; this reduced security of supply has a cost.

Ø By postponing decommissioning, the decommissioning fund will grow substantially. Not taking advantage of this possibility leads to an opportunity cost of the order of about 1,000 M€.

Although not really an actual cost, but an important point in terms of interest for the Belgian state, letting a future government negotiate with nuclear plant owners by using the 'carrot' of a nuclear operation extension, can keep certain elements of the energy system under the control of the Belgian authorities.

This extra financial burden of a nuclear phase out appears to be too high a price to pay, even when considering a disadvantage of keeping nuclear power as an option, namely an increase of the nuclear waste. Indeed, in the final count, the amount of high level nuclear waste will be increased by the same proportion as the operation extension of the plants; i.e., if existing plants are allowed to operate for 60 years the increase will be 50%.

275 But this is a relatively minor incremental cost; and furthermore, it is

paid for by nuclear operators (reduction of their profit in a liberalized market). In any case, a further relying on nuclear power must continue to be subject to the following imperative requirements: - Strict safety regime as before, under international supervision.

274 Which reflect an opportunity cost. 275 The increase of the low-level and medium-level waste is relatively minor.


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- Guarantee that nuclear provisions are available when needed (foreign owner, but also utilization by government).

Overall Conclusion: a Diverse Energy Policy is Needed All things considered, we must conclude that no simple solutions exist; there is no silver bullet. The only reasonable option appears to be to go for an 'and-and' approach rather than for an exclusive 'either-or' one. It is to be avoided to put all eggs in the same basket, and a maximal diversity should be opted for. The Belgian energy policy will have to consist of a balanced mixture of contributing elements. First, if important post-Kyoto carbon-reduction limits are pursued, energy savings will have to be an important component of the policy. Then, a diversity of primary-energy sources and conversion technologies should be opted for, with a cost-effective integration of renewables, whereby the cost effectiveness is best geared by carbon prices rather than absolute objectives. Given the existing constraints and the costs reported, taking into account all hypotheses

276 and uncertainties involved,

and based on the combination of scientific, technical and economic arguments, we are led to conclude, that in case the nuclear phase out is implemented, the expected post-Kyoto constraint is expected to be extremely expensive and strongly perturbing for our economic fabric. Even after having incurred a major part of the very high costs, the risks of not satisfying a reliable energy provision under the assumed constraints, are indeed very large. The circumstances when the nuclear phase-out law has been voted into law have indeed changed significantly; the urgency for climate-change action is becoming more apparent and the era of very cheap oil and gas prices is almost certainly behind us. This facing with current reality and future expectations, requires a reconsideration of the overall Belgian energy policy, including nuclear electricity generation.

276 Assuming that CCS is not available.


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Recommendations

of the Commission Energy 2030

General Guiding Principles Major guiding principles must apply for the Belgian energy policy with horizon towards 2030. Because of its limited scale and impact, the existence of a European environmental policy, the European energy policy 'in the making', and the common European energy market, Belgium is recommended to fully align itself to the European energy framework. This applies to the domains of the common energy markets, energy efficiency, renewable energy, energy infrastructures and nuclear safety, amongst others. The transposition into Belgian law of the EU Directives and Regulations should always be undertaken in a timely manner. Belgium should use the EU context to establish a coherent energy policy of its own, and already start reflecting seriously (and even proactively) when EU policy documents are launched (Commission Communications etc). Also, Belgian ideas should be launched on an EU scale to have the scrutiny of the other EU members and to get support & momentum (if the proposed measures make sense) of the full EU. In addition, Belgium must 'profit' from the EU dimension to negotiate its primary-energy deals with producing countries; unilateral deals must be carefully reflected upon, but Belgium must not be too naive if other Member States go their own way. Given all challenges, i.e., the need for a reliable, clean and affordable energy provision already discussed in this report, and the scenario results & interpretation, it is clear that Belgium cannot afford to put all the eggs in the same basket. We must go for an 'and-and' approach; we do not have the luxury to have too many exclusions. For an effectively almost 100% energy-dependent country, diversity is the only helpful strategy: reduce energy demand, 'produce' indigenous energy (through renewables), choose for a sufficient fraction of storable primary energy in the portfolio, rely on a diversified mix of technologies and primary sources, coming from different geographical regions and all of this in an affordable way and sufficiently environmentally friendly. Aim for stable legislation and regulatory framework based on a coherent long-term vision. Set clear long-term targets and let the market actors then invest within that frame setting. The Belgian energy responsibilities must be streamlined and harmonized. Different philosophies and approaches seriously hamper a coherent energy policy. Amongst others, four typical examples can be given:

• Concerning transmission and distribution of electricity there is confusion. Everything equal and lower than 70 kV is a regional competence, but the lines with a voltage of 30 to 70 kV (both values included) are operated within the framework of the integrated TSO Elia.

• All tariffs are set by the Federal Authorities, regardless of which level is competent. • The introduction of liberalization for supply and retail has been at a different speed in the

Regions, not helping the effectiveness and efficiency of the whole transition. • The support schemes for green electricity and cogeneration differ in the Regions, hampering a

good development of renewable and CHP-based electricity generation in Belgium. For all these domains, independent of the political choice to put the responsibility at a particular level, the approaches should be harmonized, and even considered in a broader European context. Exchange of green and CHP certificates in Belgium and on a European scale is a good example.

Given the long lead times for implementation of infrastructure investment decisions, and with the concern for security of supply regarding all energy carriers, but especially electricity and gas, Belgium should prepare for a considerable post-Kyoto GHG reduction effort, thereby avoiding an ostrich attitude. Also, Belgium should not count/rely on 'generous' EU burden-shift escape routes since such attempts might in the end not be accepted by the other EU Member States (especially if high abatement costs are a consequence of deliberate own choices). Belgium should define its medium


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to long-term energy policy taking into account a substantial domestic GHG reduction effort and/or keeping in mind the possible costs for financing emission reductions abroad through, e.g., emission trading.

Concrete recommendations

1. Belgium must do all that is 'reasonably acceptable' to exploit its potential on energy savings.

First and foremost, a behaviorally conscientious attitude with respect to energy use should be advocated through education and general information transfer, in schools and towards the public at large. Energy is a scarce good and should be highly valued; automatic reflexes for unwise/inadvertent use of energy are to be discouraged. Demand for energy services

277 should possibly be mitigated and

the desired level of energy services should be provided by using efficient technology. Timely transposition of all EU efficiency-related directives is called for and novel, effective, efficient and non-conflicting own supplementary measures must be considered. In particular, matters such as energy-performance standards for buildings must be implemented earnestly and strictly enforced, as required by the related EU directive. Especially given the long-term consequences of this sector for energy efficiency, these transpositions should be done in a harmonized way and in collaboration with the building sector. This energy-performance concept includes the appliances within the buildings.

278 Determinate action is required now, but short-term

expectations should be tempered because of the long time constant in the building sector. Even in the time frame of 2030, although considerable progress can be made, miracles cannot be expected. Special attention is required for the education & training of more energy-technical-oriented architects and energy-conscientious contractors. In line with the current EU directives, Public Service Obligations regarding an energy-savings (and not only electricity-savings) target should be put, based on market-compatible measures, implemented by e.g., distribution grid operators, and the results must be closely monitored. A comprehensive impact analysis of a net energy-savings target of …1.5…% per year requirement (compared to business as usual projections) must be studied as part of the strategy. Quality Cogeneration is to be continually encouraged and supported to implement the energetic potential based on the heat demand existing at the time of implementation. Transport-related energy use is linked to the more global issue of mobility. Air & noise pollution, GHG emissions and road congestion are major problems in this context, especially for Belgium with a logistic function in Europe. This requires a holistic approach, including road, rail, water and air transport, passenger and freight transport, private and public transport, congestion control, road safety etc. Well thought-through measures, without taboos must be considered. Solving the mobility issue appropriately, may lead to energy savings and emission reductions. As examples, we mention the following (not all necessarily equally efficient) measures:

a. To discourage 'superfluous' use of road vehicles, road-congestion charges and road taxes (per driven km) may have to be levied;

b. The offer of public transport and non-motorized transport means in priority areas should be increased;

c. To reduce emissions of vehicles, the annual traffic tax on heavily polluting vehicles, as a function of their emissions, may be considered;

d. Increasing fuel efficiency standards, based on agreements with car manufacturers can be encouraged. Targets should be ambitious, but cost efficient and realistic. Belgium should

277 By "energy services" is meant the activities and applications we wish to enjoy: heat rooms to comfortable temperatures, keep food and drinks cool, drive kms, provide drive power and process heat in industry, etc. This concept here is different from the "services" provided by so-called "energy service companies (ESCOs)". 278 Although separate standard and labeling directives exist, to put pressure on the manufacturers and to better inform the potential buyers of efficient equipment.


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play a stimulating role in the EU to establish the criteria based on sound cost-benefit analyses.

Industry must be incited to further concentrate on energy efficiency, both energy-intensive and the smaller industries. The voluntary and audit covenants are welcome tools when cleverly combined with the allocation of emission allowances. For all of the above, general strict rules must be set, with 'appropriate' exceptions or compensations for especially sensitive segments or sectors (energy-intensive sector, particular types of transportation). The main determinant here is the international extent of the post-Kyoto efforts. If the efforts are limited to the EU (and even the EU + USA), there are severe limits on the carbon-reduction efforts that can be imposed on certain sectors.

2. To reflect scarcity of energy as an economic good as well as the external costs due to various energy-conversion processes, to avoid wasting of energy and keep sufficient pressure for rational use of energy, and to optimize load time management, energy price increases must be fully passed on to the customer.

A pilot project on 'real time pricing'

279, to assess the potential of the instrument should be

undertaken. Rebates and special lower tariffs on energy should be avoided, unless there are justified reasons to do so and unless other means for social correction have been exhausted. It may be necessary to foresee certain financial compensations for the lower income groups. Also, appropriate measures may have to be foreseen such that lower income groups can equally benefit from energy-efficiency measures. Detailed but neatly arranged information on the price breakdown (commodity, transmission & distribution charges, levies, (excise) taxes & VAT) on the invoices is to be optimized/provided. To optimize demand-side management on the retail side, ample attention to metering and interaction between supplier and customer is needed. Combined with the progressive introduction of distributed generation, sufficient investment for the modernization of the distribution grids for electricity and gas (towards eventually a smart grid) is inescapable. The cost for these infrastructure investments will be high and must be imputed to the customers. Connections to the high voltage or high pressure networks for electricity and gas, respectively, must contain price signals reflecting congestion and other costs in certain areas. TSOs should have the permission by the Regulator to charge them.

3. According to the present analysis, the achievement of stringent post-Kyoto targets of the order

of 15-30% by 2030, for domestic reduction in Belgium without nuclear power and in the absence of CCS, is expected to be extremely expensive. (Reaching these post-Kyoto targets will already maximize the technical potential use of renewables and a considerable part of energy savings as shown by the energy intensity decrease.) Furthermore, if similar European reduction targets are considered with the possibility of emissions trading, also without nuclear and CCS in Belgium, GHG abatement for Belgium will likewise be very expensive, unless the EU burden sharing turns out to be very favorable for Belgium.

Non-nuclear and non-CCS scenarios result in an overwhelming dependence (90% in instantaneous power terms) of natural gas for electricity generation and conflicts with the objective of security of supply.

279 Real-time pricing assumes that customers have appropriate meters for gas and electricity, whereby an instantaneous and thus fluctuating price, at any moment of the day, rather than an average or fixed tariff, is paid.


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To alleviate these burdens, and in addition to relying on energy savings and renewables, Belgium is therefore advised to

- reconsider the nuclear phase out, and - to stimulate the timely development of CCS

Lifting the Nuclear Phase Out When reconsidering the nuclear phase out, to keep sufficient pressure on the energy system towards the transition to a more sustainable energy basket, a negotiated agreement with the owners of the Belgian nuclear power plants is to be sought for, to make them pay a “correct”

280 concession

fee/rent. The thereby collected revenues could be used by the government for stimulating investments in energy savings & demand-side management, for development in renewable energy, for development & research in emerging energy technologies and carriers.

281 The Dutch Borssele

agreement, explicitly established via a Covenant and the establishment of a sustainability fund, may serve as an exemplary source of inspiration. As part of this agreement, earlier agreements that were made in the context of the nuclear phase out should be revisited. The operational lifetime of the existing plants should be left non-limited a priori

282, in the sense that

the prime requirement should be the continued safe operation of the plants. The safety of plants is to be thoroughly examined on a ten yearly basis (by means of the 10-year overhauls) and the state of the plants (thereby requiring possible upgrading investments) must be approved by the nuclear supervisory bodies (amongst which the Nuclear Regulator), possibly confirmed by an international audit.

283

Operation of nuclear power must continue to live up to internationally accepted standards, for safety aspects, radiation protection, waste management, proliferation, and be subject to both national and international scrutiny and supervision (through bodies such as the 'Recognized Safety Authority', FANC/AFCN, NEA/OECD, IAEA, Euratom, WANO). Although the current nuclear liability coverage is already substantial, it is recommended that in an EU or OECD context, Belgium advocates the idea to set up an EU or OECD-wide but nuclear operator/owner-funded and -managed liability fund to cover the extra liability in case of a severe accident. This nuclear liability partnership should be funded pro rata of the nuclear installed capacity within the EU or OECD.

280 The level of such fee/rent is to be evaluated by an independent international commission, as discussed under point 6 of these recommendations. 281 According to economic theory, this is not the most efficient way of spending these revenues. The magnitude of the rent or tax revenue may be larger by several factors than the needs for subsidies for renewables, energy savings and demand-side management. Caution must be expressed against over-subsidizing because of this earmarked money; any justifiable investment —including for renewables, energy savings and demand-side management— must pass a cost-benefit test, also accounting for its environmental benefits. The remainder of this nuclear rent may be devoted to other valuable means, such as lowering labor charges or reducing the national debt. 282 Note that "non-limited" is to be distinguished from "unlimited". 283



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In case new nuclear units are considered, a clear and transparent regulatory framework must be set. The economics of such project must be left to the investors' market. To support such framework, a participatory process with societal stakeholders should be undertaken, based on a broad cost-benefit analysis, with the aim towards a "sustainable" energy provision. Such process should lead to advises upon which policy makers can base themselves to set the conditions for new nuclear build.

284

Carbon Capture and Storage (CCS) Although lacking power-plant manufacturers, Belgium must collaborate strongly internationally on the development of Carbon Capture and Storage (CCS). A commitment must be made to have at least one experimental pilot carbon capture plant operating no later than 2030 on Belgian territory, privately or publicly funded.

285 Administrative and

scientific research on possible geological CO2 storage sites must be amplified strongly, so as to know clearly by 2015 what the possibilities for CO2 storage in Belgium are, with the possibility to then launch a pilot research program in situ, if justified by the results of the research. Screening of potential gas-storage sites in nearby/neighboring countries and study of transport costs of CO2, not neglecting the possible competition/interaction with natural-gas flexibility requirements, is to be undertaken in order to have a reasonable idea of long-term possibilities.

4. Because of limited domestic potential of renewables, Belgium should implement the EU directives in a clever and justified way to contribute to a healthy European energy mix and environmental-burden reduction.

Towards an efficient long-term perspective, Belgium should not commit to quota for local ‘production’ of renewable energy, but rely on market mechanisms where carbon value is the best guide for the expansion of renewable energy in Belgium and abroad. As a first step, one could accept and should plead for (perhaps ambitious) quota (in % terms) for supply of renewable energy to the end customers coupled to full EU exchangeability of green certificates or certificates of origin, so that investors are stimulated to invest at the best locations in Europe.

286

In a transition period, judicious local production of renewable energy at acceptable locations must be steered through the penalty value of the green certificates. Depending on the source, subsidy must be tailor made; over-subsidy leads to improper use of public money. Blending of biofuels for transportation should be aligned on a European scale and the impact of excise tax breaks for the public finances must be comprehensively evaluated. The cost effectiveness for CO2 abatement of the full life cycle and the sustainability of the supply chain (taking into account

284 J.P. van Ypersele strongly disagrees with this paragraph about a new nuclear plant. He really does not think that new nuclear units should be built in Belgium. In his opinion, nuclear energy should not play a major role in the efforts to reduce greenhouse gas emissions at world level. The last IPCC report (IPCC WG3, 2007) puts much more emphasis on the potential of energy efficiency, carbon capture and storage, and renewable energy to reduce global emissions, than it did to a nuclear expansion. In the long term, we have to contribute in the development of a world energy system that relies much less on stocks of fossil and fissile fuel, because they are inherently finite. We need instead to learn to harness the flow of solar (and other renewable) energy which equals about 8000 times the total world energy consumption per year. It is important to capture that renewable flow in the most efficient way, and some of that is probably best done out of the Belgian territory. Harnessing this flow will reduce the risk of “running out” of fuel (the Sun will indeed continue to provide its energy to us for another 5 billion years), reduce the risk of proliferation of nuclear material, reduce the risk of large scale accidents or nuclear terror activities, and reduce the amount of nuclear waste we leave to future generations. To make this possible, we need to dramatically increase energy efficiency, and manage demand so that energy usage per capita converges towards sustainable levels, taking into account local circumstances. In the transition period to such an efficient world energy system relying mostly on renewable energy, and as advocated by the European Union, we urgently need to use carbon capture and storage on our fossil fuel plants, and participate in the diffusion of this technology in all countries with large fossil-fuel reserves. Building a new nuclear plant in Belgium would only postpone the needed transition towards a more sustainable world energy system. 285 Note that the experimental nature of such plant does not permit to rely on it for routine carbon capture. 286 This means that all suppliers must demonstrate that at least x% of the electricity delivered to their end customers originates from renewable sources, regardless of where these are generated. With such schemes, and free exchangeability of European green certificates or certificates of origin, Belgium may be subject to the same level of renewable obligation (e.g., 20%) as the EU. It must be understood that these 20% need not be produced domestically, however.


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possible competition with the food chain, deforestation, and other applications), should be carefully assessed, however. Belgium should reconsider its offshore wind policy and be more forthcoming in the concession allocation of sites. In order to be serious about offshore wind power development, the authorities should re-examine the sites of the 'Wenduine Bank' and the 'Vlakte van de Raan', as these sites may offer a reasonable degree of technological success at an acceptable cost. Far offshore sites are not to be dropped, but should be developed meticulously. Through a carefully designed staged process, an international leading role for far offshore can be established. 1) In the context of the current projects, it should be encouraged to use different technological options, which are to be observed very carefully (measurements, maintenance, corrosion, etc) during a sufficiently long period to be defined on a technical basis, and during which careful comparisons with international projects are made. 2) Continue up to a few hundreds of MW only when the results of the first phase are successful. 3) Make an in-depth study of the grid connections: link with the possible HV cable to the UK, study of the connection with “Supergrid”

287, possibility of organizing a common connection

point offshore, high-voltage-network absorption & extension and power-generation back-up study, with clear cost figures before embarking on >900 MW plans. If prospects are positive, go for it with strong determination; if prospects range from dubious to negative, have the realism to call it off and reorient. The costs for sea cables for far offshore investments, starting from the pilot plant all the way to the massive build up, could be socialized

288 if the costs remain acceptable to society. Here, however,

contribution from the above mentioned 'nuclear phase-out repeal fund' could be a welcome financial injection.

5. On security of supply, four aspects are to be focused on as priorities.

Diversity of supply of primary sources and technologies (type and origin) is the first and foremost rule. Especially the gas provision must be carefully observed. An optimal mixture of long-term and spot-market contracts must be strived for. A comprehensive study to find the appropriate energy mix (including renewables, gas, oil, coal, uranium), based on the portfolio theory must be effectuated for the Belgian situation. A stable investment climate must be guaranteed for competitive market players to have sufficient new electricity-generation capacity, to keep a substantial refinery capacity and to have sufficient gas-storage capacity. For supported technologies, such as renewables, governments must guarantee that commitments for support made are honored. Transmission and distribution networks must be 'allowed' to invest in extensions, adaptations, and preventive maintenance, so as to avoid blackouts and to allow the connection of renewables and to facilitate the European market; the Regulator must accept the costs involved being transmitted to the customers; environmental and construction permits must be delivered timely by the competent authorities.

6. The liberalization process for electricity and gas in Belgium must be developed in line with the common European energy market concept.

A stable and transparent regulatory framework, properly harmonized between the Regions and the Belgian Federal level, and at the EU level, is called for. Efficient regulators, sufficiently independent of the government (but properly held accountable for their actions), are expected to enforce and supervise regulation. Harmonization of Belgian regional and federal regulatory decisions is imperative.

287 Supergrid is an initiative to connect all sides for offshore wind along the Atlantic coast and beyond. 288 In the sense that eventually, costs may have to be transmitted to the final electricity customers.


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Both for domestic and international regulatory level, review/recourse/appeal by/to the European Commission must be defended by the Belgian Member State at the European Union level. One single wholesale market, at least in NW-Europe must be advocated, by establishing sufficient cross border transmission capacity. Regulators must oversee potential abusive behavior, while allowing the investments for building cross-border lines as a basic element for market development. Imposed regulated prices at the wholesale level are advised against, but possibilities of partnership between large energy consumers and producers should be envisaged (guaranteeing security on long-term pricing). Sufficient Retail market access should develop over time to reach a good mix of suppliers in Belgium. Regulated capped prices at the retail level are advised against. Strict supervision by the Regulator is necessary. Vertical unbundling is necessary in the sense that only generation and retail can remain inside the same company. The transmission and distribution activities for electricity and gas must be legally unbundled (as prescribed by the EU Directive). Full ownership unbundling does not seem to be necessary as long as strict corporate governance rules are applied. The presence of large shareholders is an advantage to raise capital for infrastructure investments. If such approach proves to be impossible or unrealistic in practice, other routes such as 100% ownership unbundling or the establishment of an Independent System Operator (ISO)

289, should be examined.

An independent multi-international examination on the issue of alleged “unreasonable” windfall profits as a consequence of earlier depreciated generating capacity now operating in a liberalized environment (so-called possible stranded benefits) must be undertaken. The experts commission must preferentially be populated by non-European experts, i.e., well recognized energy-economics and/or corporate-financing university professors and Regulators of OECD countries with liberalization experience (e.g., USA, Canada and/or Australia). Both the Belgian Regulators and the generator concerned must be heard by this commission to express their viewpoints. It must be recognized, though, that the existence of these “inframarginal rents”

290 is independent of the number of electricity-

generating operators.

7. Belgium should devote much more research & development means in energy.

To maximally profit from economies of scale, substantial financial incentives must be given to research groups for participation in European projects. European energy research priorities have been identified [CEU, 2005 & 2006]. Supplementary Belgian energy research, development & demonstration should be prioritized:

- behavioral research on public willingness to opt for rational use of energy and ways to stimulate it;

- energy research should cover all relevant sectors such as transportation, residential, commercial & service sectors, industry, gas and electricity sectors;

- individual R&D grants for selected manufacturers to develop further 'super efficient' equipment;

- clever interaction of suppliers and customers through smart grids for electricity and gas, comprising active demand-side management and distributed generation;

- further research on renewable energy, such as phased offshore wind-energy development, high-efficiency conversion of biomass, advanced grid-integrated PV and others;

- comprehensive system and grid integration of non-dispatchable generation; - carbon-capture pilot plant and CO2 storage research; - nuclear-system development for further improvement of the nuclear route; - energy-system model development should be supported to have a strong Belgian basis

in order to acquire sound mastery of the ins and outs of comprehensive energy

289 In the sense as defined in the EU Commission energy package of January 10, 2007. The concept of ISOs has not been proven anywhere, however, as far as investment incentives, maintenance etc. is concerned. 290 See Informative Box in Report


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modeling. Own Belgian model development work is to be encouraged, whereby later European integration with other models should be kept in mind from the outset. Interaction within international/European frameworks is therefore to be encouraged.

8. Education & Training in energy

Although not actually studied, the CE2030 nevertheless expresses its concern about appropriate education in energy matters, both for the public at large and for energy professionals. High-school education programs should contain an important segment on the scientific & technical aspects of energy provision, the overall energy issue, and the relationship with prosperity, development and sustainability etc. Non-biased education based on facts and figures and the laws of nature is called for. The authorities are invited to make an effort to stimulate (advanced) studies in energy science and engineering. Lack of a sufficiently capable professional pool of experts will hamper us in meeting the energy-related challenges faced in the future.

9. Belgium should establish a sustained/permanent Strategic Energy Watching Brief

Rather than solely relying on ad-hoc Committees (such as the AMPERE Commission and this CE2030 Commission), it is recommended to establish a 'permanent' and structural follow-up process to guarantee conscientious observance (or disregarding) of the recommendations of 5 to 8 year interval Major Review Exercises. This Watching Brief must be organized such that it involves at least the Federal and Regional Energy Administrations and Energy Regulators, the Federal Planning Bureau, Energy & Environmental Scientists & Economists, perhaps enlarged with other stakeholders of society. This Watching Brief exercise is best supervised by an independent core group. A limited-size but formal follow-up document to the government should be established on an annual basis. To make this follow up successful, sufficient and efficient gathering of correct and coherent energy-related data must be transferred timely to the Federal Economy Administration, which must be given sufficient means to establish a reliable database.


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Available at http://www.kuleuven.be/ei à publications à 1999 Phylipsen, G.J.M., J.W. Bode, K. Blok, H. Merkus, B. Metz (1998), "A Tryptych sectorial approach to burden differentiation; GHG emissions in the European bubble", Energy Policy, Vol 26, Nr 12, pp 929-943 Piessens, K., M. Dusar, B. Laenen, Ph. Mathieu, J.-M. Baele (2007), "Contribution of the PSS-CCS group", Royal Belgian Institute of Natural Sciences - Geological Survey of Belgium, VITO, ULg and FPMs; working document, private communication Proost, Stef & Denise Van Regemorter (2001), "What do the AMPERE results imply for future electricity production in Belgium – an analysis with MARKAL model", Revue E Tijdschrift, Vol 117, pp 41-48, available at: http://www.ce2030.be/secure/documents/infodoc/Post- Ampere%20MARKAL%20paper%20Proost%20E%20Tijdschrift.pdf Proost, Stef (2006a), "Energy and environmental developments in the transport sector", Supporting Documents CE2030. Proost, Stef (2006b), "Should labour content matter in the choice of electricity generation technology?", Supporting Documents CE2030. SCENES, EU project, information available at http://www.iww.uni-karlsruhe.de/SCENES/; http://www.transforum-eu.net/IMG/pdf/scenes.pdf. Socolow, Robert H. and Stephen W. Pacala (2006), "A Plan to Keep Carbon in Check", Scientific American, Vol. 295, August, pp 968-972 Stern, Sir Nicholas (2006), "Stern Review on the Economics of Climate Change", HM Treasury, UK, Available at http:// www.sternreview.org.uk Streydio, J-M, P. Tonon and P. Klees (2006), "Nuclear power solutions in Belgium; Key to an energy mix." Contributory report for the 2030 Energy Commission, Supporting document CE2030 report Sutherland, R.J. (1996), “The economics of energy conservation policy”, Energy Policy, Vol. 24, pp 361-370 Sutherland, R.J. (2000), “ ‘No cost’ Efforts to Reduce Carbon Emissions in the U.S.: An Economic Perspective”, The Energy Journal, Vol. 21, pp 89-112 TEN-T, EU Project. Information available at http://ec.europa.eu/ten/transport/projects/index_en.htm; http://ec.europa.eu/ten/transport/projects/doc/2005_ten_t_en.pdf UCTE (2006), "System Adequacy Forecast 2006 - 2015", available from http://www.ucte.org Unruh, Gregory C. (2000), “Understanding Carbon Lock-In", Energy Policy, Vol. 28, pp 817-830 Vanden Borre, Tom (2001), "Efficiente preventie en compensatie van catastroferisico's; Het voorbeeld van de schade door kernongevallen", Interscientia Rechtswetenschappen, Antwerpen- Gronigen. (In Dutch) Van Tongeren, P., B. Laenen & H. Weyten (2004), "Geotechnische en financiële aspecten van ondergrondse CO2-opslag in Vlaanderen", VITO rapport 2004/MAT/R/036, VITO, Mol, maart Van Ypersele, Jean-Pascal (2006), "Post-Kyoto Targets: A Climatologist's View", Power Point presentation for the CE2030 June 13, 2006; Supporting Documents to the CE2030. Verbeeck, Griet (2007), "Optimisation of extremely low energy residential buildings", PhD thesis, Katholieke Universiteit Leuven, Faculty of Engineering, Leuven, Belgium, May.


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(ISBN 978-90-5682-801-1) VOKA (2006), "Elektriciteit nu en in de toekomst; Strategisch product voor burgers en bedrijven", VOKA / Vlaams Economisch Verbond, juni, Antwerpen Voorspools, K, and W. D'haeseleer (2006), "The modeling of electric generation of large interconnected systems: how can a CO2 tax influence the European generation mix?" Energy Conversion & Management, Vol47, pp 1338-1358 VROM (2006a), "Convenant kerncentrale Borssele", Den Haag, NL; available at http://www.vrom.nl/pagina.html?id=23664 VROM (2006b), "Randvoorwaarden voor nieuwe kerncentrales"; Available at http://www.vrom.nl/pagina.html?id=24579


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— SUPPORTING DOCUMENTS —

Essays on particular topics &

Report on detailed scenario description

Available at http://www.CE2030.be


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Part A: Energy-Related Issues Addressed

Document FOD/SPF Energy, Min Econ Affairs

Documents submitted by L. Dufresne

Document submitted by J. Albrecht

Slides submitted by J-P. van Ypersele

Documents submitted by S. Proost

Documents submitted by J-M Chevalier

Document submitted by W. Eichhammer

Document submitted by R. Belmans

Document submitted by J. De Ruyck

Documents submitted by P. Klees, J-M. Streydio & P. Tonon

Document submitted by B. Leduc

PART B: Scenario Description

Detailed description PRIMES scenarios; document provided by the Federal Planning Bureau:

"Long term energy and emissions' projections for Belgium with the model PRIMES; Input for the Commission Energy 2030", Belgian Federal Planning Bureau, D. Devogelaer, D. Gusbin, September. All available at http://www.ce2030.be.


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Part C. Extra General Bibliographical References Demande maîtrisée de l’électricité. Elaboration d’une projection à l’horizon 2020. Working paper du Bureau du Plan. Belgique-Octobre 2004. http://www.plan.be/nl/pub/wp/WP0419/WP0419fr.pdf Etude de l’AEN « Agence pour l’énergie nucléaire ». Développement des compétences dans le domaine de l’Energie nucléaire. Rapport 2004. Ce rapport fait partie d’une longue série de rapports publiés régulièrement par l’AEN. http://www.nea.fr/html/nsd/reports/2004/nea5589-competences.pdf (synthèse) France Livre Blanc sur les énergies de Nicole Fontaine, Ministre déléguée à l’Industrie – 07 novembre 2003 http://www.industrie.gouv.fr/energie/politiqu/pdf/livre-blanc-integral.pdf Développement durable; Changement climatique et transition énergétique: dépasser la crise -- rapport Sénat http://www.senat.fr/rap/r05-426/r05-4261.pdf United Kingdom Our Energy Future – Creating a Low Carbon Economy, White Paper UK, Feb 2003 http://www.dti.gov.uk/energy/energy-policy/energy-white-paper/page21223.html The Energy Challenge UK Energy Review July 2006 http://www.dti.gov.uk/energy/review Netherlands Energy Report 2005; Now for Later http://www.minez.nl/content.jsp?objectid=34330 Germany Energieversorgung für Deutschland http://www.bundesregierung.de/Content/DE/Artikel/2006/03/__Anlagen/statusbericht-fuer-den-energiegipfel-am-3-april-982229,property=publicationFile.pdf EU Strategy paper on Internal Electricity Market http://europa.eu.int/comm/energy/electricity/florence/doc/florence_10/strategy_paper/strategy_paper_march_2004.pdf Renewable Energy Evolution in Belgium 1974-2025, G. Palmers, et al., SPSD II Report, Brussels, June 2004 http://www.belspo.be/belspo/home/publ/pub_ostc/CPen/rappCP23_en.pdf Optimal Offshore Wind Energy Developments in Belgium, F. Van Hulle, et al., SPSD II Report, Brussels, 2004 http://www.belspo.be/belspo/home/publ/pub_ostc/CPen/rappCP21_en.pdf See also the SPSD site: http://www.belspo.be/belspo/home/publ/rappCPen_en.stm Coûts de référence de la production électrique, Paris, 2004 http://www.industrie.gouv.fr/energie/electric/se_ele_a10.htm Projected Costs of Generating Electricity, 2005 Update, IEA Paris 2005 To be bought from: http://www.iea.org/bookshop/add.aspx?id=196 The Cost of Generating Electricity, Royal Academy of Engineering, London, 2004 http://www.raeng.org.uk/news/publications/list/reports/Cost_of_Generating_Electricity.pdf http://www.raeng.org.uk/news/publications/list/reports/Cost_Generation_Commentary.pdf


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Analysis of Electricity Network Capabilities and Identification of Congestion, IAEW , TWTH Aachen, Report for the CEU, 2001 Available at http://europa.eu.int/comm/energy/electricity/publications/index_en.htm Securing the Public Interest in Electricity Generation Markets; The Myths of the Invisible Hand and the Copper Plate, L. J. de Vries, PhD thesis, Delft, The Netherlands, 2004 http://www.library.tudelft.nl/dissertations/2940/f_161827_true_EN.html Energiewirtschaftliche Planung für die Netzintegration von Windenergie in Deutschland an Land und Offshore bis zum Jahr 2020 (Energy-economic planning for grid integration of wind energy on land and offshore until 2020), DENA Studie, 2005, http://www.deutsche-energie-agentur.de/page/index.php?id=2764&L=0 (Deutsch) http://www.deutsche-energie-agentur.de/page/index.php?id=2764&L=4 (English) Greenpeace reports Energy Revolution: a sustainable pathway to a clean energy future for Europe http://www.greenpeace.nl/raw/content/reports/energy-revolution-a-sustainab.pdf Energy Revolution: a sustainable pathway to a clean energy future for Belgium http://www.greenpeace.org/raw/content/belgium/nl/press/reports/energy-revolution-a-sustainab-2.pdf Other interesting documents, not available on the web (although the IEA documents can be bought on line from www.iea.org ): IEA, World Energy Investment Outlook, Paris, 2003 IEA, Power Generation Investment in Electricity Markets, Paris, 2003

General information

IPCC documents (e.g., Assessment Reports) http://www.ipcc.ch National Climate website http://www.klimaat.be/inventemis/inventaris8.html http://www.klimaat.be/inventemis/inventaris1.html General site http://www.klimaat.be/

National allocation plans: http://www.europa.eu.int/comm/environment/climat/emission_plans.htm


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Annex 1.

Preliminaries. Power versus Energy; Capacity and Effective Number of Operating Hours

Electric energy is not easily storable and certainly not in large quantities. It may be stored in a different energy shape (for instance pumped storage or batteries), but the balance between demand (increased by the grid losses) and generation has to be kept at every instant in time. A generator set has a so-called rated power, i.e., the power it can deliver on a continuous basis, without being overloaded. This does not mean that it actually delivers that power. It has the capacity to deliver the power. A 400 MW CCGT can deliver 400 MW, but may be shut down for a longer period, due to high gas prices. Wind-energy systems can only operate when wind is available. A nuclear power station normally operates continuously, due to the very low marginal costs of the fuel. The product of instantaneous power output and the time that power is delivered gives the energy supplied by a unit. E.g., a nuclear power plant with a rated power of 1 GW and 8000 h of operation per year, supplies 8 TWh of electric energy during that year. An offshore wind farm with the same rated power but with 3500 h of equivalent operation, delivers 3.5 TWh. Installing the same wind farm inland at a poor wind location (with only 1000 to 1500 h of equivalent operation) has an annual electric energy production of 1 to 1.5 TWh. The effective number of operating hours (ENOH) for a fluctuating generation source is defined as the amount of electrical energy produced divided by the installed power; it is the number of hours the facility would operate at rated conditions to produce the same amount of electrical energy. This number divided by the number of hours per year is the capacity factor. As generation has to follow demand in a dynamic way, the rate of change of the output of a power plant is also of key importance. This is generally expressed in MW/min. For nuclear-power plants, this is very low, while for open cycle gas turbines, this value is extremely high, making them very much suited for covering peak demand. On the level of a system, one can refer to either MW/s or MW/h, depending on the scale looked at. The reader must hence be careful to distinguish between units like MW, MWh and MW/h. Similarly, consumers require instantaneous power delivery; energy is simply the amount of (mostly varying) power consumed during a certain period. Likewise, the same distinction exists between thermal power (heat rate) and thermal energy (amount of heat delivered). Finally, in English, a 'cogeneration' unit is often called a 'Combined Heat & Power' (CHP) facility, whereby here 'power' is considered as synonym of electrical power or energy. This is a confusing habit, as a CHP unit can deliver both electrical and thermal power (in the sense of energy per unit of time) and electric and thermal energy (in the sense of power delivered during a certain period). A typical conceptual error in statistics is that CHP units are often characterized by their electrical rated power. As CHP is heat-demand driven, it is important to know what both the thermal and electrical output are, because it replaces an electric plant and a boiler. In addition, depending on the operation time during which the thermal power is delivered, it is important to know how much thermal energy versus electrical energy has been produced. Special caution is needed when CCGT with some steam bleeding for process heat is considered, as these units very often simply run as combined cycles, then having nothing to do with CHP.


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Annex 2. External Costs for Electricity Generation The figures presented in this annex have been taken from the final report of the EU project EUSUSTEL: "European Sustainable Electricity; Comprehensive Analysis of Future European Demand and Generation of European Electricity and its Security of Supply" [ http://www.eusustel.be ] The figure captions and the legend give the relevant elements. For more details, the reader is advised to visit the EUSUSTEL website; final report, chapter 6.

Figure A2.1 Total Social Electricity Generation Cost in 2010. Two discount rates have been used, 5% and 10%. Likewise, two values for CO2 cost, 10€/ton and 20€/ton, are given.

Figure A2.2 Total Social Electricity Generation Cost in 2030. Two discount rates have been used, 5% and 10%. Likewise, two values for CO2 cost, 10€/ton and 20€/ton, are given.


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Figure A2.3 Total Social Electricity Generation Cost in 2010. Two discount rates have been used, 5% and 10%. The following are considered from left to right (each time with two capacity factors): PV open space (10/20); PV roof (10/20); Wind onshore 15/25); Wind offshore (25/40).

Figure A2.4 Total Social Electricity Generation Cost in 2030. Two discount rates have been used, 5% and 10%. The following are considered from left to right (each time with two capacity factors): PV open space (10/20); PV roof (10/20); Wind onshore 15/25); Wind offshore (25/40).


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Annex 3. The Flexible Mechanisms under the Kyoto Protocol291 The Kyoto Protocol has also foreseen in four flexible mechanisms that allow reaching the commitments at lower costs: joint action or bubbles, tradable permits, joint implementation and the clean development mechanism. Joint action (Bubbles)

The Protocol also provides an arrangement for Annex-I countries that have agreed to jointly fulfill their commitments as stated in article 3 of the Protocol. This is for example the case for the EU countries

292.

The countries that participate in a bubble are deemed to have met their commitments provided that their total combined greenhouse gas emissions do not exceed the total of their assigned amounts. The reallocation of emissions between these countries must be set out in an agreement that remains in operation for the duration of the commitment period

293.

The principle of creating a bubble The general idea is that the emission reductions, to which countries participating in a bubble have committed themselves in Kyoto, are redistributed among these countries, such that the global commitment of those countries is achieved at a lower cost. This is illustrated with a simplified example. Take two countries that have committed themselves to

reduce their CO2 -equivalent emissions with 10% by the year 2010, compared to the 1990 emission

levels. Assume that these countries decide to form a bubble. The total emission reduction effort to be

realized equals the increase in CO2 -equivalent emissions between 1990 and 2010 – i.e. the increase

under a business-as-usual scenario – plus 10% of the 1990 emission levels. This amount corresponds to the length of the horizontal axis in Figure A3 (the distance AE ). The next step is then to take into account the cost of emission reductions in both countries. For both countries, this information is captured by their marginal cost curve for emission reductions, which shows the additional cost it takes to reduce emissions with one additional ton. These are the curves

MCLow and MCHigh for the country with the low and the high marginal costs, respectively294

. In Figure

A3 the emission reduction realized in country Low is measured from left to right on the horizontal axis, the emission reduction in country High is measured from right to left on the horizontal axis. Each point on the horizontal axis then corresponds to a distribution over both countries of the total emission reduction effort to be realized. For example, in the point C both countries, each on their own, reduce their emissions to a level that is 10% below the 1990 level. In that case, the total cost of implementing the Kyoto Protocol corresponds to the sum of the areas ABC (the total cost in country Low) and EDC (the total cost in country High). With the bubble mechanism, the same reduction effort AE can be achieved at a lower cost. Indeed, looking at Figure A3 learns that some tons of emission reduction, now realized in country High, can be realized in country Low at a lower cost. This is the case for the units between C and F . Note that the point F is characterized by equal marginal costs for both countries. This is a feature of a cost-efficient solution, i.e. a solution where total costs are minimized. In,Figure A3 the total cost of achieving the emission reduction is reduced with an amount corresponding to the area BDG . Shifting reduction efforts in this way is called burden sharing,

291 This annex is an adapted version of § II.A.2 of [Pepermans et al., 1999]. 292 Other Annex-I countries are in the process of also making bubble agreements. The most important one may probably be the one bringing together the United States and Russia. 293 If the participating countries to such an agreement fail to achieve their combined level of emission reductions, then each participating country will be responsible for its own agreed upon level of emissions. Furthermore, if the countries belonging to a regional economic integration organisation (such as the EU) come to an agreement to act jointly, then any alteration to the composition of the organisation after the adoption of the Protocol will not affect the existing commitments under the Protocol. 294 To simplify the figure, the marginal abatement cost is drawn as a straight line, but in general, the marginal abatement cost has a convex shape.


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because, in addition to a reduction in the total cost of the emission reduction, there is also a shift in the ‘per country’ cost from country High to country Low. For country Low, the cost increases with the area CBGF , whereas for country High, the cost reduces with the area CDGF . This sharing of the burden is accepted by country Low either because it is imposed and can be enforced by some kind of authority (such as the European Union) or because it receives a compensation (side-payment) from country High to do so.

A C E

G

MCHigh

Euro per ton of

emission reduction in

country Low


country High

MCLow

P

D

F

B

Euro per ton of


country High


country Low

Figure A3: Illustration of the bubble concept and burden sharing. Application within the European Union The bubble-principle was accepted in Kyoto after strong pressure from the European Union. The EU has already reallocated its joint Kyoto-commitment over the Member States. In terms of Figure A3, it is the intention of the EU to move from a point such as C towards a point that is closer to F.

The reallocation of efforts within the EU is summarized in Table A3. The reallocation is based on the principle that the most industrialized EU-countries have to make the largest reduction efforts, whereas the least developed EU-countries are given the opportunity to increase their emissions in order to be able to maintain an acceptable level of future economic development. Of course, this does not necessarily result in a cost-minimizing outcome. There are however some deviations from this principle which are more in line with the cost-efficiency argument. For example, Sweden is allowed to

increase its CO2 -equivalent emissions because of its decision to shut down nuclear sites (which

produce no CO2 )295

.

295 If the Swedish government replaces its nuclear sites with fossil fuel sites, then this will inevitably lead to increased greenhouse gas emissions. Under the European bubble, the Swedish emissions are allowed to increase with 4%, which is lower than the increase that would result in the absence of the Kyoto-agreement.


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France, already having a large nuclear power capacity – and therefore a relatively low level of CO2 -

equivalent emissions – is allowed to stabilize its emissions. For Germany the emission reduction commitment of -21.0% looks huge, but taking into account the large emission reduction potential in the former East Germany, makes the commitment more realistic.

Member State Commitment

Austria -13.0% Belgium -7.5% Denmark -21.0% Finland 0.0% France 0.0% Germany -21.0% Greece +25.0% Ireland +13.0% Italy -6.5% Luxembourg -28.0% Portugal +27% Spain +15.0% Sweden +4.0% The Netherlands -6.0% United Kingdom -12.5%

Table A3: Reallocation of the Kyoto-commitment within the EU

The conclusion is that, in order to reach the emission reduction objective at a minimal cost, other flexible mechanisms will also need to be implemented. The Protocol lists the possibility of tradable permits, joint implementation and the clean development mechanism. Tradable Permits The Parties included in Annex B of the Protocol may participate in emissions trading for the purposes of fulfilling their commitments under Article 3 of the Protocol. Any such trading shall be supplemental to domestic actions for the purpose of meeting quantified emission limitation and reduction commitments under that Article. Any amount of emission reduction units acquired from another Annex-I party is added to the assigned amount of the acquiring party. Any amount of emission reduction units transferred to another Annex-I party is subtracted from the assigned amount for the transferring party. The principle of tradable permits The principle of tradable permits is fairly simple. On the basis of the commitment under the Kyoto Protocol, countries are allowed to emit a given amount of greenhouse gases. For example, in 2010

country High is allowed to emit an amount of CO2 equal to the 1990 emission level minus 10%296

. For

each ton that country High is allowed to emit, it receives an emission permit. These emission permits can be traded on a market. Assume that emission permits are distributed in country Low in the same manner. Then Figure A3 can be used to illustrate that trade opportunities exist for both countries. In Figure A3, the initial allocation of emission reduction efforts corresponds to the point C . The total cost of emission reductions for both countries can be further reduced by allowing for bilateral trade of emission permits among the countries. In Figure A3, country High is willing to buy emission permits from country Low. Country High is willing to pay a price for an emission permit for one additional ton of

CO2 as long as the price for this permit is lower than the marginal cost, i.e. the additional cost that

country High needs to make to reduce emissions with one ton. Country Low is willing to sell emission permits as long as it receives a price that is at least equal to the marginal cost, i.e. the cost that country Low needs to make to reduce emissions with one ton.

296 For the sake of the argument, we only consider CO2

, but the principle can be applied to all greenhouse gases.


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For example, in point C , any price between B and D will result in trade that is mutually beneficial. Assume that the price is P . At that price, country High is willing to buy emission permits and country

Low is willing to sell emission permits, and as long as MCHigh is above MCLow , there will be trade.

These insights can be generalized to a market with more than two countries, but to make it work in practice, some problems remain to be solved. First, it needs to be decided how the permits will be distributed, both among and within countries. The permits have a value – they are traded at a positive price – and therefore, the initial distribution of the permits among and within countries is important. Second, who will buy or sell the permits? Will it be the government or the firms? If the government acts as the trader, then there may be an information problem in the sense that the government may not have the necessary information on emission reduction costs in order to make the system work efficiently. Firms are more likely to have the necessary information on emission reduction cost to make the system function. Third, one needs to decide on the fine that is to be paid if emissions increase above the allowed level on the basis of the permits. If the fine is too low, then there is no incentive to reduce emissions, if the fine is too high then this might prevent flexible and efficient action in the case of special occasions (for example an extremely cold winter). Finally, it needs to be decided whether emissions are transferable over time (banking). Allowing for banking introduces additional flexibility and stimulates efficiency but it can also lead to the malfunctioning of the system. For example, if countries now use all their future emission permits, then this must lead to the bankruptcy of the system.

Joint Implementation (JI)

The parties included in Annex-I may transfer to, or acquire from, any other Annex-I party emission reduction units resulting from projects aimed at reducing emissions by sources or enhancing removals by sinks of greenhouse gases in any sector of the economy, provided that some conditions are fulfilled. The central idea is that a state or a company can also meet its obligations to reduce or limit emissions through bilateral co-operation with foreign partners. In that way the investor acquires credits that can be used according to the regulations in the donor country. Any amount of emission reduction units acquired from another Annex-I party is added to the assigned amount of the acquiring party. Any amount of emission reduction units transferred to another Annex-I party is subtracted from the assigned amount for the transferring party.

Disadvantages of the Joint Implementation mechanism

Joint implementation has some disadvantages compared to the tradable permits system. First, joint implementation is an essentially bilateral mechanism – two countries work together on one specific project – and this is less efficient than a tradable permits mechanism, which is multilateral. This is because a bilateral mechanism does not exploit all opportunities to trade because of the strategic behavior of the parties involved

297.

Second, the JI mechanism will only work when the national commitment to reduce emissions is translated effectively in emission reduction efforts imposed on the firms. If this is not the case, then firms will have no incentive to co-operate in JI projects. Finally, there is a large administrative cost involved in implementing the JI mechanism. Emission reductions must be measured for each JI project, which implies a complete understanding and measurement of the projects’ industrial process, each emission reduction must be certified by experts,... In this respect a tradable permits system is simpler, firms buy and sell permits to emit and there is no need to measure industrial processes with respect to their emissions.

The Clean Development Mechanism (CDM)

297 The term ‘strategic’ does not refer to the time period that is considered, but rather to the fact that the way in which the two parties act depends on the (expected) actions or decisions taken by the other parties.


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Under the Clean Development Mechanism, Annex-I countries can invest in projects in developing countries that result in emission reductions or limitations. The purpose of the mechanism is to assist the developing countries in achieving sustainable development and to assist the developed countries in achieving their emission reduction targets. Sometimes this mechanism is called ‘joint implementation between developed and developing countries’. Any certified emission reduction acquired from a developing country is added to the assigned amount of the acquiring party. Certified emission reductions obtained between 2000 and 2008 can be used to achieve compliance in the first commitment period.

Advantages of the Clean Development Mechanism

Two important advantages can be listed. First, the CDM allows the industrialized countries to meet their emission reduction commitment at a lower cost. From an economic point of view, it is efficient to give countries with emission targets a maximum of flexibility concerning the location of emission reductions. As greenhouse gas emissions mix globally there is no hot-spot problem, and thus, the cheapest measures should be taken first regardless where they take place. Second, CDM involves a transfer of technology from the donor country to the guest country. This may lead to further greenhouse gas emission reductions in the guest country as this technology is spread.

Disadvantages of the Clean Development Mechanism

Essentially, the disadvantages of JI also apply to the CDM. First, there is the large administrative cost, second there is the lack of multilateral co-operation and finally, there is the problem of proper incentives.


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Annex 4. National Inventory of Greenhouse Gases SUMMARY 2 SUMMARY REPORT FOR CO2 EQUIVALENT EMISSIONS Belgium

(Sheet 1 of 1) 2004

2006

GREENHOUSE GAS SOURCE AND SINK CO2 (1) CH4 N2O HFCs PFCs SF6 Total

CATEGORIES

Total (Net Emissions) (1)

125.734,08 7.915,96 11.210,10 1.467,59 306,22 65,96 146.699,91

1. Energy 116.648,61 648,70 2.259,77 119.557,08

A. Fuel Combustion (Sectoral Approach) 116.501,84 223,45 2.259,77 118.985,06

1. Energy Industries 29.358,29 8,95 342,86 29.710,10

2. Manufacturing Industries and Construction 29.354,24 55,18 259,07 29.668,49

3. Transport 26.451,52 67,54 829,10 27.348,15

4. Other Sectors 31.243,33 91,67 827,74 32.162,74

5. Other 94,45 0,11 1,01 95,57

B. Fugitive Emissions from Fuels 146,77 425,25 0,00 572,03

1. Solid Fuels 0,00 13,51 0,00 13,51

2. Oil and Natural Gas 146,77 411,74 0,00 558,52

2. Industrial Processes 9.818,48 8,75 3.396,05 1.467,59 306,22 65,96 15.063,05

A. Mineral Products 5.516,59 0,00 0,00 5.516,59

B. Chemical Industry 2.334,28 0,01 3.396,05 0,00 0,00 0,00 5.730,34

C. Metal Production 1.651,51 8,74 0,00 0,00 0,00 1.660,25

D. Other Production NE 0,00

E. Production of Halocarbons and SF6 0,00 306,22 0,00 306,22

F. Consumption of Halocarbons and SF6 1.467,59 0,00 65,96 1.533,55

G. Other 316,10 0,00 0,00 0,00 0,00 0,00 316,10

3. Solvent and Other Product Use NE 249,65 249,65

4. Agriculture 0,00 6.330,35 5.026,89 11.357,24

A. Enteric Fermentation 3.908,43 3.908,43

B. Manure Management 2.418,43 873,00 3.291,43

C. Rice Cultivation 0,00 0,00

D. Agricultural Soils(2) 3,49 3.929,45 3.932,94

E. Prescribed Burning of Savannas 0,00 0,00 0,00

F. Field Burning of Agricultural Residues 0,00 0,00 0,00

G. Other 0,00 224,44 224,44

5. Land-Use Change and Forestry(1) -1.173,41 0,00 0,00 -1.173,41

6. Waste 440,40 928,15 277,75 1.646,30

A. Solid Waste Disposal on Land 0,00 814,86 814,86

B. Wastewater Handling 66,14 267,42 333,55

C. Waste Incineration 440,40 0,00 10,33 450,73

D. Other 0,00 47,16 0,00 47,16

7. Other (please specify) 0,00 0,00 0,00 0,00 0,00 0,00 0,00

0,00

Memo Items:

International Bunkers 27.810,25 1,99 1.314,39 29.126,63

Aviation 3.814,06 1,33 9,21 3.824,60

Marine 23.996,19 0,66 1.305,18 25.302,02

Multilateral Operations 0,00 0,00 0,00 0,00

CO2 Emissions from Biomass 2.903,02 2.903,02

(1) For CO2 emissions from Land-Use Change and Forestry the net emissions are to be reported. Please note that for the purposes of reporting, the signs

for uptake are always (-) and for emissions (+). (2)

See footnote 4 to Summary 1.A of this common reporting format.

GREENHOUSE GAS SOURCE AND SINK CO2 CO2 Net CO2 CH4 N2O Total

CATEGORIES emissions removals emissions /

removals

emissions

Land-Use Change and Forestry

A. Changes in Forest and Other Woody Biomass Stocks 5.267,92 -8.069,62 -2.801,70 -2.801,70

B. Forest and Grassland Conversion 0,00 0,00 NE NE 0,00

C. Abandonment of Managed Lands 0,00 0,00 0,00 0,00

D. CO2 Emissions and Removals from Soil 0,00 0,00 1.628,29 1.628,29

E. Other 0,00 0,00 0,00 0,00 0,00 0,00

Total CO2 Equivalent Emissions from Land-Use Change and Forestry 5.267,92 -8.069,62 -1.173,41 0,00 0,00 -1.173,41

Total CO2 Equivalent Emissions without Land-Use Change and Forestry (a)

147.873,32

Total CO2 Equivalent Emissions with Land-Use Change and Forestry (a)

146.699,91

(a) The information in these rows is requested to facilitate comparison of data, since Parties differ in the way they report emissions and removals from

Land-Use Change and Forestry. Note that these totals will differ from the totals reported in Table 10s5 if Parties report non-CO2 emissions from LUCF.

CO2 equivalent (Gg )


Table A4.1. Overview of all GHG emissions in Belgium for the year 2004 submitted in 2006, according to [NIR, 2006].


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SUMMARY 2 SUMMARY REPORT FOR CO2 EQUIVALENT EMISSIONS Inventory 2005

(Sheet 1 of 1) Submission 2007 v1.1

BELGIUM

GREENHOUSE GAS SOURCE AND CO2 (1) CH4 N2O HFCs

(2)PFCs

(2)SF6

(2)Total

SINK CATEGORIES

Total (Net Emissions) (1) 122.958,54 7.832,81 11.048,85 1.454,05 140,97 43,04 143.478,26

1. Energy 113.668,72 616,54 2.086,28 116.371,55




3. Transport 25.517,15 61,79 836,66 26.415,60

4. Other Sectors 30.518,77 90,00 793,03 31.401,80

5. Other 95,22 0,11 1,01 96,34

B. Fugitive Emissions from Fuels 146,74 408,23 NA,NE,NO 554,97

1. Solid Fuels NA,NO 11,78 NA,NE,NO 11,78

2. Oil and Natural Gas 146,74 396,45 NA,NE,NO 543,19

2. Industrial Processes 9.545,32 43,68 3.409,84 1.454,05 140,97 43,04 14.636,91

A. Mineral Products 5.451,10 NA,NO NA,NO 5.451,10

B. Chemical Industry 2.241,18 2,44 3.409,84 NA NA NA 5.653,46

C. Metal Production 1.535,12 41,24 NA NA,NO NA,NO NA,NE,NO 1.576,37

D. Other Production NE NE

E. Production of Halocarbons and SF6 140,97 140,97

F. Consumption of Halocarbons and SF6 (2) 1.454,05 NO 43,04 1.497,09

G. Other 317,92 NA NA NA 317,92


4. Agriculture 6.242,78 5.016,12 11.258,89



C. Rice Cultivation NA,NO NA,NO


E. Prescribed Burning of Savannas NO NO NO

F. Field Burning of Agricultural Residues NA,NO NA,NO NA,NO

G. Other NA,NO 223,82 223,82

5. Land Use, Land-Use Change and Forestry(1) -370,10 NO NO -370,10

A. Forest Land -2.094,61 NO NO -2.094,61

B. Cropland 576,05 NO NO 576,05

C. Grassland 1.148,46 NO NO 1.148,46

D. Wetlands NE,NO NO NO NE,NO

E. Settlements NO NO NO NO

F. Other Land NO NO NO NO

G. Other NE NE

6. Waste 114,59 929,81 287,16 1.331,56

A. Solid Waste Disposal on Land NA,NO 823,25 823,25

B. Waste-water Handling 65,98 271,77 337,75


D. Other NA 40,59 NA 40,59

7. Other (as specified in Summary 1.A) NA NA NA NA NA NA NA

Memo Items: (4)

International Bunkers 27.301,50 1,36 7,74 27.310,60

Aviation 3.565,44 1,36 7,74 3.574,54

Marine 23.736,06 NE,NO NE,NO 23.736,06

Multilateral Operations NE NE NE NE


Total CO2 Equivalent Emissions without Land Use, Land-Use Change and Forestry (5) 143.848,37

Total CO2 Equivalent Emissions with Land Use, Land-Use Change and Forestry (5) 143.478,26

(2) Actual emissions should be included in the national totals. If no actual emissions were reported, potential emissions should be included. (3) Parties which previously reported CO2 from soils in the Agriculture sector should note this in the NIR. (4) See footnote 8 to table Summary 1.A.


(1) For CO2 from Land Use, Land-use Change and Forestry the net emissions/removals are to be reported. For the purposes of reporting, the signs for removals are always

negative (-) and for emissions positive (+).

(5) These totals will differ from the totals reported in table 10, sheet 5 if Parties report non-CO2 emissions from LULUCF. Table A4.2. Overview of all GHG emissions in Belgium for the year 2005 submitted in 2007, according to [NIR, 2007].


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SUMMARY 2 SUMMARY REPORT FOR CO2 EQUIVALENT EMISSIONS Belgium

(Sheet 1 of 1) 1990

2006

GREENHOUSE GAS SOURCE AND SINK CO2 (1) CH4 N2O HFCs PFCs SF6 Total

CATEGORIES

Total (Net Emissions) (1)

117.649,87 10.824,81 12.010,34 433,98 1.753,32 1.662,60 144.334,92

1. Energy 110.129,55 858,06 1.739,96 112.727,57




3. Transport 19.947,07 102,49 352,10 20.401,66

4. Other Sectors 27.215,24 128,81 789,09 28.133,14

5. Other 166,31 0,05 1,63 167,98

B. Fugitive Emissions from Fuels 85,32 560,77 0,00 646,09

1. Solid Fuels 0,00 35,64 0,00 35,64

2. Oil and Natural Gas 85,32 525,12 0,00 610,44

2. Industrial Processes 8.614,14 0,00 3.933,84 433,98 1.753,32 1.662,60 16.397,89

A. Mineral Products 5.334,60 0,00 0,00 5.334,60

B. Chemical Industry 918,02 0,00 3.933,84 0,00 0,00 0,00 4.851,86

C. Metal Production 1.945,99 0,00 0,00 0,00 0,00 1.945,99

D. Other Production NE 0,00

E. Production of Halocarbons and SF6 0,00 1.753,32 1.559,36 3.312,68

F. Consumption of Halocarbons and SF6 433,98 0,00 103,25 537,23

G. Other 415,54 0,00 0,00 0,00 0,00 0,00 415,54


4. Agriculture 0,00 7.245,13 5.797,87 13.043,00



C. Rice Cultivation 0,00 0,00


E. Prescribed Burning of Savannas 0,00 0,00 0,00

F. Field Burning of Agricultural Residues 0,00 0,00 0,00

G. Other 0,00 237,15 237,15

5. Land-Use Change and Forestry(1) -1.431,14 0,00 0,00 -1.431,14

6. Waste 337,32 2.721,61 292,56 3.351,49

A. Solid Waste Disposal on Land 0,00 2.629,98 2.629,98

B. Wastewater Handling 84,62 270,27 354,89


D. Other 0,00 6,96 0,00 6,96

7. Other (please specify) 0,00 0,00 0,00 NE NE NE 0,00

0,00

Memo Items:


Aviation 3.095,64 1,08 2,26 3.098,98

Marine 13.303,08 0,37 726,61 14.030,06

Multilateral Operations NE 0,00 0,00 0,00


(1) For CO2 emissions from Land-Use Change and Forestry the net emissions are to be reported. Please note that for the purposes of reporting, the signs

for uptake are always (-) and for emissions (+). (2)

See footnote 4 to Summary 1.A of this common reporting format.

GREENHOUSE GAS SOURCE AND SINK CO2 CO2 Net CO2 CH4 N2O Total

CATEGORIES emissions removals emissions /

removals

emissions

Land-Use Change and Forestry

A. Changes in Forest and Other Woody Biomass Stocks 4.880,06 -7.983,52 -3.103,47 -3.103,47

B. Forest and Grassland Conversion 0,00 0,00 0,00 0,00 0,00

C. Abandonment of Managed Lands 0,00 0,00 0,00 0,00

D. CO2 Emissions and Removals from Soil 1.774,35 -102,02 1.672,33 1.672,33

E. Other 0,00 0,00 0,00 0,00 0,00 0,00

Total CO2 Equivalent Emissions from Land-Use Change and Forestry 6.654,41 -8.085,55 -1.431,14 0,00 0,00 -1.431,14

Total CO2 Equivalent Emissions without Land-Use Change and Forestry (a)

145.766,06

Total CO2 Equivalent Emissions with Land-Use Change and Forestry (a)

144.334,92

(a) The information in these rows is requested to facilitate comparison of data, since Parties differ in the way they report emissions and removals from

Land-Use Change and Forestry. Note that these totals will differ from the totals reported in Table 10s5 if Parties report non-CO2 emissions from LUCF.



Table A4.3. Overview of all GHG emissions in Belgium for the year 1990 submitted in 2006, according to [NIR, 2006].


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SUMMARY 2 SUMMARY REPORT FOR CO2 EQUIVALENT EMISSIONS Inventory 1990

(Sheet 1 of 1) Submission 2007 v1.1

BELGIUM

GREENHOUSE GAS SOURCE AND CO2 (1) CH4 N2O HFCs

(2)PFCs

(2)SF6

(2)Total

SINK CATEGORIES

Total (Net Emissions) (1) 117.649,87 10.824,81 12.010,34 433,98 1.753,32 1.662,60 144.334,92

1. Energy 110.129,55 858,06 1.739,96 112.727,57




3. Transport 19.947,07 102,49 352,10 20.401,66

4. Other Sectors 27.215,24 128,81 789,09 28.133,14

5. Other 166,31 0,05 1,63 167,98

B. Fugitive Emissions from Fuels 85,32 560,77 NA,NE,NO 646,09

1. Solid Fuels NA,NE 35,64 NA,NE 35,64

2. Oil and Natural Gas 85,32 525,12 NE,NO 610,44

2. Industrial Processes 8.614,14 IE,NA,NE,NO 3.933,84 433,98 1.753,32 1.662,60 16.397,89

A. Mineral Products 5.334,60 NA,NE NA 5.334,60

B. Chemical Industry 918,02 NA,NO 3.933,84 NA NA NA,NE 4.851,86

C. Metal Production 1.945,99 IE,NA,NO NA NA,NO NA,NO NA,NE,NO 1.945,99

D. Other Production NE NE

E. Production of Halocarbons and SF6 1.753,32 1.559,36 3.312,68

F. Consumption of Halocarbons and SF6 (2) 433,98 NO 103,25 537,23

G. Other 415,54 NA NA NA,NE 415,54


4. Agriculture 7.245,13 5.797,87 13.043,00



C. Rice Cultivation NA,NO NA,NO


E. Prescribed Burning of Savannas NO NO NO

F. Field Burning of Agricultural Residues NA,NO NA,NO NA,NO

G. Other NA,NO 237,15 237,15

5. Land Use, Land-Use Change and Forestry(1) -1.431,14 NO NO -1.431,14

A. Forest Land -3.205,49 NO NO -3.205,49

B. Cropland 470,85 NO NO 470,85

C. Grassland 1.303,50 NO NO 1.303,50

D. Wetlands NE,NO NO NO NE,NO

E. Settlements NO NO NO NO

F. Other Land NO NO NO NO

G. Other NE NE

6. Waste 337,32 2.721,61 292,56 3.351,49

A. Solid Waste Disposal on Land NA,NO 2.629,98 2.629,98

B. Waste-water Handling 84,62 270,27 354,89


D. Other NA 6,96 NA 6,96

7. Other (as specified in Summary 1.A) NA NA NA NE NE NE NA,NE

Memo Items: (4)


Aviation 3.095,64 1,08 2,26 3.098,98

Marine 13.303,08 0,37 726,61 14.030,06

Multilateral Operations NE NE NE NE


Total CO2 Equivalent Emissions without Land Use, Land-Use Change and Forestry (5) 145.766,06

Total CO2 Equivalent Emissions with Land Use, Land-Use Change and Forestry (5) 144.334,92

(2) Actual emissions should be included in the national totals. If no actual emissions were reported, potential emissions should be included. (3) Parties which previously reported CO2 from soils in the Agriculture sector should note this in the NIR. (4) See footnote 8 to table Summary 1.A.


(1) For CO2 from Land Use, Land-use Change and Forestry the net emissions/removals are to be reported. For the purposes of reporting, the signs for removals are always

negative (-) and for emissions positive (+).

(5) These totals will differ from the totals reported in table 10, sheet 5 if Parties report non-CO2 emissions from LULUCF. Table A4.4. Overview of all GHG emissions in Belgium for the year 1990 submitted in 2007, according to [NIR, 2007].


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Annex 5. The Fraunhofer Study on Energy Saving Measures

Belgium Energy Savings Policy Study: Top 20 Measures according to [Fraunhofer, 2003]

The Fraunhofer measures are listed in oblique font and possibly commented upon [between square brackets] by the CE2030. Buildings FH. Implementation of Energy Performance Standards for buildings (new + renovation) which are well-controlled and harmonized across the regions. Such a measure might also target the phase-out of old heating and hot water boilers in existing buildings according to the example of the current Energy Performance Standard in Germany. [CE2030. Implementation is underway. Exists in Flanders; Wallonia and Brussels will follow soon. But harmonization and proper control/checking remains to be seen. Not only boilers should be targeted, but all dated equipment should be recommended to be replaced.] FH. A transparent and well-controlled Public Service Obligation for Power Grid Companies. Similar to the Energy Efficiency Commitment, this obligation should also target measures for existing buildings. [CE2030. Should be limited to Distribution Grid Companies. Exists in Flanders.] FH. Governing by example (federal, subsidized institutes such as schools and hospitals, regions, provinces & municipalities). [CE2030. As long as this occurs in the most cost-effective way] FH. A rate structure for grid companies which gives them the incentive to invest in local energy efficiency and distributed generation when this is cheaper than investing in grid expansion. [CE2030. This is perhaps a left over of an IRP-like philosophy. According to unbundling rules, grid operators are not allowed to invest in generation. It should be recommended, however, that grid operators can handle different connection tariffs based on the geographic location in the grid, and preferentially treat distributed generation only if that ameliorates congestion. Conversely, distributed generation in the wrong place is to be discouraged by tariffs.] Transport FH. Fuel taxation: harmonization with neighboring countries, account for externalities. [CE2030. Is already the case; fuel excises in Belgium are already considerable and not too different from neighboring countries. Moreover, current higher fuel prices mitigate transport consumption; but the relative effect of extra taxes will perhaps be moderate because already high. Excise taxes should however be targeted more towards diesel engines as opposed to gasoline engines.] FH. Investment in freight rail and road/water/rail intermodality infrastructures funded through road tolls, especially for heavy vehicles. FH. Taxation on vehicles according to CO2 emissions specification. [CE2030. These measures are clearly suboptimal; see [Proost, 2006]] Industry FH. Sufficiently ambitious negotiated agreements/benchmarking covenants (above autonomous progress). Regional harmonization between benchmarking covenants and negotiated agreements). FH. Preparation of the transition from agreements to the EU emission trading for companies participating in the trading scheme, which is obligatory from 2008. Clarification of relation between


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agreements and possible EU and national taxation schemes, in particular for companies NOT participating in the trading scheme (principle of equal treatment). Especially benchmarking agreements are not obsolete by emission trading as they can pave the way for the allocation of emissions. Second, if the cap is too large, there will be little demand and the effectiveness of such a scheme might only materialize after 2010 and the first Kyoto commitment period. Thus industry must, possibly up to 2010, reduce emissions rather through agreements than trading. [The CE2030 believes that Emission Trading should be allowed to function, properly. It must have priority over covenants. But the allocation of allowances must be carefully reflected upon, with a sufficiently stringent cap. A possibility of auctioning of allowances should be supported over the entire European Union, whereby a particular fraction of allowances could be offered at reduced prices or for free proportional to the efficiency performance within the covenants.] FH. Redesign existing energy efficiency subsidy schemes + auditing procedures, to enhance monitoring and auditing schemes by giving consistently feedback to companies in the form of benchmarks. [CE2030. unclear what is exactly meant] Electric Appliances FH. Strong role for information, rebates, procurement at national level (and regulation if EU does not wish to lead). [CE2030. Before launching this sort of DSM programs, careful reflection on the administrative and transaction costs must be undertaken. Also if this route is taken, the most energy-efficient appliances should benefit the most.] FH. Information/Communication Technologies ICT: Differentiated measures according three operating modes: normal, standby and off-mode. Cross-Cutting FH. CHP: Package of measures (appropriate market + policy conditions, grid access, appropriate calculation procedures for quality CHP, independent advice..). [CE2030. This has been implemented to a large extent, through CHP certificates and adaptation to recent EU-directive follow ups. Further harmonization within Belgium between the Regions is called for, to improve transparency. However, the CE203 strongly recommends sticking to the 'quality criterion' for financial support; it advises strongly against the splitting methodology of a condensing and non-condensing part. Independent advice is available through NPOs supported by government subsidies.] FH. Energy/CO2 taxation (with the exception of industrial branches engaged in sufficiently ambitious negotiated agreements/benchmarking covenants). Taxation must be seen as a complement to many other measures in this list in order to prevent rebound effects. It is also considered in this report that taxation can coexist with an emission trading scheme. Taxation levels could be derived from the consideration of budget coefficients. Admissible price increases at consumer level in potential scenarios

2012 2020 2012 2020

Industry 9% 9% 11% 16%

Residential 15% 23% 22% 31%

Tertiary 6% 13% 19% 33%Transport 11% 20% 12% 28%

Benchmark Economic potential

[CE2030. This proposal does not make much sense. What are 'budget coefficients'? The first principle is that an identical CO2 tax for all CO2 emissions must be set. When there are already other instruments employed than a CO2 tax, one has to check whether the residual CO2 emissions are taxed or not, etc. Also, if a correct CO2 tax is set, this can only be introduced on a European scale. But, it is fair to say that a CO2 tax has been overtaken by the Emission Trading Scheme. Revenues for government could be obtained via auctioning of allowances.]


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FH. A drastic change in budgets for R&D towards Energy Efficiency (mainly for buildings and industry) + especially serious budgets for Demonstration Projects (building sector + industry). [CE2030. It is not evident that demonstration projects should be supported strongly. It seems better to invest in R&D for a full systems approach (including interactions & feedbacks, better control, holistic concepts) and in innovation.] FH. Permanent, competent information desks (especially for professionals in the building sector (architects and engineers) and for industrial companies (including promoting of EU-initiatives such as Green Light, Motor Challenge, …). [CE2030. This is to be recommended only if those desks can operate efficiently without too much administrative overhead.] FH. Information and sensibilization for households by a meshed network of advisory centers, possibly fully incorporated into the obligatory yearly RUE action plans of the electricity grid managers. Monitoring and Evaluation of policy measures (enough staff and resources for especially controlling the Verification Office for Benchmarking Agreements, the future Energy Performance Standards of Buildings, the Public Service Obligation, and the Energy Use of Public Authorities). FH. Much improved data collection (Detailed sectoral and even process yearly energy balances, especially for industry; measured End-Use Consumption Data; yearly Ownership Data of Appliances;...) [CE2030. This is strongly emphasized by the CE2030, but may not be easy in the current unbundled market structure. To be reflected upon how this can be implemented.]


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Annex 6. Four Generations of Nuclear Fission Reactors Nuclear reactor designs are categorized according to technological generations. Each generation incorporates evolutionary improvements with revolutionary concepts to take the next step in reactor technology. Generation I were the prototype commercial reactors of the 1950-1960s. With the exception of the gas-cooled reactors in the UK, (uranium fuel, graphite as moderator and CO2 as coolant), none is still running today. Generation II are the commercial reactors deployed in the 1970-1980s. They are still in operation today. They typically use enriched uranium-fuel and are mostly cooled and moderated by water. They are essentially of the PWR, BWR, CANDU and WWER type representing the major share of operational NPPs today. The Doel and Tihange plants are of Generation II. Generation I and II reactor safety systems are “active” because they rely on active electrical and mechanical control of equipment and backup power supplies. The next two generations of nuclear reactors (III and IV) are currently being developed in several countries. Generation III are “evolutionary” reactors designed in the mid 1990s. The European Pressurized Reactor EPR (i.e., a LWR type of reactor) belongs to this category and the first units are being built in Olkiluoto in Finland and in Flamanville in France. They capitalized the experience and expertise gained during the operation of the Generation II with enhanced safety and competitiveness. They will be in operation from 2010 on. They are designed to provide:

• a standardized design for each NPP-type to expedite licensing, reduce capital cost and reduce construction time;

• a simpler and more rugged design, making them easier to operate and less vulnerable to operational upsets;

• higher availability and operating life typically of 60 years; • even more reduced possibility of core melt accidents; • minimal effects on the environments; • reduced fuel use and reduced amount of waste.

Many Generation III NPPs (such as EPR) incorporate passive or inherent safety features that require no active controls or operational intervention to avoid accidents in the event of malfunction. They rely especially on gravity, natural convection or resistance to high temperature. Generation IV. These “revolutionary” reactors will have innovative fuel cycle technologies and might become commercially available in the time frame of 2040 and responding to following four main sustainability criteria and future market conditions:

• to be highly economical and competitive; • incorporate till enhanced nuclear safety; • to be resistant to proliferation in addressing nuclear non-proliferation and physical protection

against aggression issues; • produce minimal waste and optimal use of natural resource utilization.


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They will tend to have closed fuel cycles and burn the long-lived actinides. They are expected to have full actinides recycle. These innovative nuclear systems are expected to offer basically two advantages:

(i) generate cheap electricity with increased safety and performance while optimizing the waste management for sustainable development.

(ii) generate heat for hydrogen production preparing for the hydrogen economy, desalination of sea water, district heating and process heat to address new industrial needs.

The US-DOE initiated in the year 2000 an industrial study, the Generation IV International Forum (GIF) aimed at identifying the reactors technologies, developing a technology roadmap for different types of reactors (the Generation IV) and organizing the R&D required, in order to comply with the four sustainability criteria mentioned above for Generation IV NPPs. During a two year’s process involving some 100 international experts, a down selection of 6 so called Generation IV reactors designs was obtained allowing to initiate collaborative R&D among 12 member countries of the GIF with the OECD-Nuclear Energy Agency (NEA) and the IAEA as permanent observers and with the other European countries participating through the European Commission Euratom organization. The six Generation IV designs are the following:

Ø Sodium cooled Fast Reactor (SFR); Ø Very High Temperature gas Reactor (VHTR); Ø Super Critical Water cooled Reactor (SCWR); Ø Lead cooled Fast Reactor (LFR); Ø Gas cooled Fast Reactor (GFR); Ø Molten Salt Reactor (MSR).

These six designs were selected with multiple criteria in mind: - better use of material resources and minimization of radio active waste arising trough the use of

recycling of spent fuel (closed fuel cycle) in four of the Generation IV design and especially by using fast spectrum reactors. The use of such fast spectrum reactors provides a means to make about 100 times better use of the mineral uranium compared to today’s Generation II and even Generation III NPPs while also providing means to reduce with a comparable factor the amount of radioactive waste to be disposed of;

- avoiding the energy conversion thermal losses by aiming at higher thermal efficiencies, e.g. 45%

and above, as well as aiming towards providing process heat together with electricity as energy products. Water desalination and hydrogen production represent typical examples of such new markets;

- both small and large reactors designs were retained matching the different power plant needs in

various markets, large NPPs for developed countries using well established electricity transmission and distribution networks, smaller NPPs being mostly designed for local or regional markets with less developed electricity infrastructure.

The aim is to deploy the first commercial Generation IV thermal reactor during the decade 2030-2040 and the commercial Generation IV fast reactors during the period 2040-2050. The planning for the end of the demonstration period is as follows: 2020 for SFR and VHTR; 2025 for SCWR, LFR and GFR and 2030 for MSR. It should be noted that as an international contribution to the socio economic energy problems raised above, the IAEA launched in 2000 the “INternational PROject on innovative nuclear reactors and fuel cycles (INPRO). INPRO has 22 state members and counts Euratom as a member. Belgium is not represented in this international body.


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To work on EPR or any other reactor of Generation III is necessary to close the gap with the development of the generation IV reactors and on a longer period with nuclear fusion that may allow the European future energy independence and security of supply. Beyond the benefit of the intrinsic advantages (safety, security and competitiveness) of Generation III, the participation in the EPR design, construction and operation are milestones essential to maintain a technological know how and a mastership in an energy system that guarantees security of supply, is environmentally friendly at affordable cost for society. Ref: Luc Van den Durpel (Listo bvba) and Georges Van Goethem (CEU DG Research), private communications. For information, see http://www.gen-4.org.

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