The Future Role of Coal in Europe

Final Report The Future Role of Coal in Europe

commissioned by: EURCOAL et. al.

Friedrich Seefeldt Marco Wünsch Dr. Michael Schlesinger

Berlin & Basel, 30.06.2007

Chief Executive Officer (CEO) Christian Böllhoff

President of the Administrative Board Gunter Blickle

Founded 1959, in Basel, Switzerland

Legal Form AG according to Swiss Law Registry: DE-Berlin HRB 87447 B

Occupation European-wide, Prognos develops practical strategies for enterprises, organisations and the public sector on the basis of authorative and objective analyses.

Working Languages German, English, French

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Acknowledgement

This study has been carried out between July 2005 and June 2007 by order of the European Association for Coal and Lignite , EURACOAL.

Significant financial contributions have been provided by: • DEBRIV, Deutscher Braunkohlen-Industrie-Verein e. V. (German Lignite Industries Association) • RWE Power AG, Essen, DE • Vattenfall Europe Mining & Generation, Cottbus, DE • E.ON Kraftwerke GmbH, Hannover, DE • Public Power Corporation, Athens, GR • Matra Erömü Részvénytársaság, Visonta, HU • Czech Confederation of the Coal and Oil Producers (ZSDNP), Praha, CZ • Czech Coal A.S., Praha, CZ • Polish Hard Coal Employer’s Association (ZPGWK), Katowice, PL • Confederation of Polish Lignite Industry, Bogatynia, PL

Beside the above mentioned, following organisations have been kindly supporting this work by their expertise and data basis: • Siemens Power Generation, Erlangen, DE • GVSt Gesamtverband des deutschen Steinkohlenbergbaus, (Association of German Hard Coal Producers), Essen, DE • VDKI Verein Deutscher Kohlenimporteure e.V. (Association of German Coal Importers), Hamburg, DE

Country specific input has been given by following subcontractors: • NAPE, National Conservation Energy Agency, Warsawa, PL • Prof. Dr. Jan Keppler, Université Dauphine, Paris, FR

At Prognos the study was accompanied, discussed and assisted by Dr. Claudia Funke, Frank Peter, Vincent Rits, Chanthira Srikandam, Philip Sowada and Deborah Sill.

We gratefully acknowledge the valuable contributions, assistance and support that has been provided by the above mentioned.

Basel and Berlin, June 2007

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Contents

0 Executive Summary ...... 8

1 Target & Structure...... 14 1.1 Target...... 14 1.2 Structure...... 14 1.3 Focus ...... 15 2 Coal in Europe: Overview...... 17 2.1 Coal Consumption ...... 17 2.1.1 Primary Energy Consumption: The Role of Coal ...... 17 2.1.2 Coal Production ...... 19 2.1.3 Resources and Reserves ...... 21 2.1.4 Coal Imports ...... 23 2.1.5 Coal Prices ...... 26 2.2 The Role of Coal in Power Generation ...... 29 2.2.1 Final Demand of Electricity...... 29 2.2.2 European Power Markets...... 30 2.2.3 Capacities ...... 32 2.2.4 Outlook on Future Capacities...... 34 3 FRC Scenario Framework ...... 37 3.1 Scenario Overview...... 37 3.2 Fuel Prices ...... 38 3.3 Policy...... 40 3.3.1 General Situation...... 41 3.3.2 Nuclear Energy Policy ...... 42 3.3.3 Renewable Energy Policy...... 45 3.3.4 The Role of CHP ...... 49 3.4 Climate Protection Policy ...... 49 3.5 Carbon Prices ...... 53 4 FRC Technology Platform ...... 56 4.1 Power Plant Technologies ...... 56 4.1.1 Natural Gas Combined Cycle (NGCC)...... 56 4.1.2 Nuclear Power Plants ...... 57 4.1.3 Pulverised Coal-Fired Steam Cycle (PC) ...... 58 4.1.4 Integrated Coal Gasification Combined Cycle (IGCC) ...... 61 4.1.5 Fluidised Bed Combustion (FBC)...... 61 4.1.6 Pressurized Pulverized Coal Combustion (PPCC)...... 62 4.1.7 Externally Fired Combined Cycle (EFCC)...... 63 4.2 Carbon Capture Technologies ...... 63 4.2.1 Pre-Combustion Capture...... 64 4.2.2 Post-Combustion Capture ...... 65 4.2.3 Oxyfuel Combustion ...... 66 4.2.4 Cost Assumptions for CCS Technologies ...... 67 4.2.5 Transport and Storage of CO 2...... 68 5 FRC Scenario Results...... 69 5.1 FRC Power Generation...... 69 5.1.1 Power Generation at high fuel prices ...... 70 5.1.2 Power Generation at Moderate Fuel Prices ...... 73 5.2 Power Plant Capacities...... 74

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5.3 The introduction of CCS Technology...... 77 5.3.1 CCS as Technology Option ...... 77 5.3.2 Economic Logic of CCS...... 78 5.3.3 Strategic Introduction of CCS...... 80 5.4 Carbon Emissions...... 84 5.4.1 Carbon Emissions at High Gas Prices ...... 85 5.4.2 Carbon Emissions at Moderate Gas Prices ...... 86 5.4.3 Carbon Emissions in Overview...... 88 5.5 Cost of Power Generation...... 91 6 Appendix A: FRC Model Concept...... 94 6.1 FRC Model Logics...... 94 6.1.1 Power Plant Parc...... 94 6.1.2 Capacity Decision and ROE Concept ...... 95 6.1.3 Merit Order Concept ...... 96 6.1.4 Renewables and CHP ...... 96 6.2 FRC Conceptual Design ...... 98 6.3 Critical Discussion of the FRC Model ...... 100 7 Appendix B: Glossary, Definitons, Literature ...... 101 7.1 Glossary...... 101 7.2 Geographic and Political Clusters...... 103 7.3 European Union: Groups and Neighbours...... 105 7.4 Definitions ...... 105 7.5 Literature ...... 106 8 Appendix C: FRC Figures...... 110 8.1 EU 27 ...... 111 8.1.1 Power Generation...... 111 8.1.2 Generation Capacities ...... 115 8.1.3 Primary Energy Input...... 116 8.1.4 CO 2 Emissions...... 116 8.1.5 Cost of Power Generation ...... 117 9 Appendix D: FRC Results Tables ...... 118 9.1 EU27 ...... 119

Tables table 2.1-1 Coal and Lignite production, import and consumption (all coals) ...... 19 table 2.1-2 Proven Reserves of Coal by regions and types ...... 21 table 2.1-3 Resources, Reserves and Production in Selected EU-27 (2004) ...... 22 table 2.1-4 resources & reserves of coal by regions and types...... 23 table 3.1-1 FRC Scenarios (Overview)...... 37 table 3.2-1: International price assumptions for BASE Price scenario...... 38 table 3.2-2: International price assumptions for LOW PRICE scenario ...... 38 table 3.2-3: fuel prices at power station for BASE scenario ...... 39 table 3.2-4: fuel prices at power station for LOW PRICE scenario...... 39 table 3.3-1 RES-E objectives (2010), actual status (2005) and linear forecast (2010) .. 46 table 3.3-2 Share of CHP in electricity generation ...... 49 table 3.4-1 Carbon Emissions of Public Electricity and Heat Production ...... 50 table 4.1-1 classification of pulverised coal-fired power plant technologies (efficiencies for hard coal) ...... 59

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table 4.2-1 Development of investment cost powerplants with CCS technology ...... 68 table 5.3-1 Carbon Emissions in Power Generation [EU 27] ...... 88 table 5.3-2 CO 2 Emissions [EU 27]...... 90 table 6.2-1 FRC program code (simplified)...... 99

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Figures figure 1.2-1 Project Overview ...... 15 figure 2.1-1 Coal Consumption in EU 15 ...... 17 figure 2.1-2 Coal Consumption in selected EU 10...... 18 figure 2.1-3 Coal Production in EU 15 ...... 20 figure 2.1-4 Coal Production in Selected EU 10 and Candidate Countries ...... 24 figure 2.1-5 Coal Imports in EU 15 ...... 25 figure 2.1-6 Net Coal Imports of selected EU-10 and Candidate Countries...... 25 figure 2.1-7 Prices for Imported Energy Sources in Germany [€/tce]...... 27 figure 2.2-1 Electricity Consumption in selected EU 15...... 29 figure 2.2-2 Electricity consumption in selected Central and East European Countries . 30 figure 2.2-3 Physical electricty ex change 2005 ...... 32 figure 2.2-4 Installed Capacity by Fuel ...... 33 figure 2.2-5 Share of Fuels in Power Generation ...... 34 figure 2.2-6 Power Capacity Renewal ...... 35 figure 2.2-7 Capacities to be replaced by time and fuel provided (EU 10) ...... 36 figure 3.2-1 fuel prices at power plant...... 39 figure 3.2-2 fuel prices at power plant...... 40 figure 3.5-1 Carbon Prices and traded volume, first year of ETS...... 53 figure 3.5-2 Carbon prices [€/t] and traded volume ...... 54 figure 4.1-1 Development of NGCC efficiency and cost ...... 57 figure 4.1-2 Development of nuclear power plant efficiency and investment cost...... 58 figure 4.1-3 development of HC pulverised coal efficiency and cost...... 60 figure 4.1-4 development of lignite pulverised coal efficiency and cost...... 60 figure 4.2-1 IGCC with Carbon Capture Flowchart...... 64 figure 4.2-2 PC Power Plant with Post-Combustion Capture ...... 66 figure 4.2-3 PC Power Plant with Oxyfuel Combustion ...... 67 figure 5.1-1 Power generation [EU 27, BASE 5 ]...... 69 figure 5.1-2 Power generation [IT, BASE 5 ]...... 70 figure 5.1-3 Power generation [EU 27, POLICY 15] ...... 71 figure 5.1-4 Power generation [EU 27, POLICY 30] ...... 72 figure 5.1-5 Power generation [EU 27, POLICY 45] ...... 72 figure 5.1-6 Power generation [EU 27, LOWPRICE 15] ...... 73 figure 5.1-7 Power generation [EU 27, LOWPRICE 30] ...... 74 figure 5.2-1 Power Capacities [EU 27, BASE 5 ]...... 75 figure 5.2-2 Power Capacities [EU 27, POLICY 15] ...... 76 figure 5.2-3 Power Capacities [EU 27, POLICY 30] ...... 76 figure 5.3-1 Carbon Emissions [EU 27, BASE 5 ]...... 84 figure 5.3-2 Carbon Emissions [EU 27, Policy 30]...... 85 figure 5.3-3 Carbon Emissions [EU 27, Policy 45]...... 86 figure 5.3-4 Carbon Emissions [EU 27, LowPrice 30] ...... 86 figure 5.3-5 Power generation [EU 27, Low Price 30] ...... 87 figure 5.3-6 CO 2 Emissions [EU 27]...... 89 figure 5.4-1 Power Generation [EU 27, TECH 30]...... 90 figure 5.4-2 Power capacities [EU 27, TECH 45] ...... 91 figure 5.4-3 Power Generation [EU 27, TECH 45]...... 91 figure 5.4-4 Power Generation [DE Germany , TECH 45]...... 92 figure 5.4-5 Power Generation [DE Germany , TECH 45 with nuclear phase-out] ...... 92 figure 5.5-1 Cost of Power Generation [EU 27, BASE 5] ...... 91 figure 5.5-2 Cost of Power Generation [EU 27] ...... 92 figure 5.5-3 Cost of Power Generation [EU 27, TECH 45] ...... 92 figure 6.1-1 Assorted Load Curve...... 94 figure 6.1-2 The principle of maximised earnings...... 95 figure 6.1-3 Structure of FRC Model...... 97

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0 Executive Summary

Focus of the study Lignite and hard coal cover approximately 1/6 of primary energy consumption in the European Union (EU 25). About 2/3 of consumption are covered by domestic production. In the sector of power generation coal is indispensable. Coal delivers an important contribution to a secured and economic power supply within the community. Due to its high carbon intensity coal gets into a defensive position in European climate protection policies but should be in an offensive position due to security of supply and economic reasons. Strong climate policy restrictions connected with Emissions Trading Scheme (ETS) may lead to high CO 2-prices and change the economics of coal use in Europe. Having that in mind, the study aims to examine and to evaluate the current situation as well as the future perspectives of coal in Europe. The focus of the study is on key drivers and determinants of the European market of coal as fuel for power generation. All results are aggregated for the EU 27, EU 15 and EU 10+2. Concerning regional terms, the focus is set on the main coal producing countries (Poland, Germany, United Kingdom, Spain, Greece, Czech Republic, Hungary, Bulgaria and Romania) and the major coal consuming markets (the above mentioned and France, Italy, Netherlands). Coking coal, coke and coal products as raw materials for steel production and other industrial purposes are excluded in this study.

Coal in Europe (1) In Europe there is both a large reserve of hard coal as well as subbituminous and lignite available, with reserves regionally dispersed. Including Russia Europe is keeping more than 30% of the proven reserves worldwide, however only 4.4% in the member states of the EU. Reserves in western and southern Europe (EU 15) have significantly decreased due to a high production level during the last 50 years, while EU 10 and candidate countries, especially Poland still keep significant reserves. (2) Europe (without former Soviet Union) presently accounts for about 315 Mtce coal production ; this is 8% of the world's total annual coal production (4’058 Mtce). Neighbouring countries including Turkey and the states of the former Soviet Union add to approximately the same amount of produced coal (320 Mtce). Germany and Poland are by far the largest coal producers in the EU; together they account for about 2/3 of all coal presently produced in the EU. (3) After an all-time low of 495 Mtce in 1999 coal consumption was taking up again, especially in EU 15 (from 292 to 314 Mtce in 2004), while during the same period keeping approximately a constant level in EU 10 and selected candidate countries (145 Mtce). An-

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other 60 Mtce are consumed by neighbouring countries of the Euro- pean Union, not counting the former states of the Soviet Union, which have been as well decreasing to 230 Mtce in 1998 and growing to 250 Mtce in 2004. (4) Coal consumption is exceeding the European production, with net coal imports growing from 125 Mtce (1994) to 147 Mtce (2004). The most important countries of origin for European hard coal imports are South Africa, Australia, Colombia, and the Former Soviet Union. (5) After a twenty year low in 1999/2000 with CIF prices of around $35 a ton for both Japan and Europe, increased domestic demand in major exporting countries (China, Russia), decreased production (USA) and increased freight charge leading to high coal prices 2004. However, with view on reserves and competitive producer markets as a first conclusion can be drawn, that coal prices are more likely to stay stable or growing moderately compared to other fossil fuels. (6) In power generation , coal is playing a dominant role in the European Union with 25% of installed capacities and almost one third of the power generation. However, investments in new power plants with roughly one third of today's total capacity are necessary throughout Europe in the next 25 years. This could result in a pro- found change in the power generation portfolio, with many options under consideration for new plants including coal, gas and renewables or in some countries also nuclear energy.

Political Framework (7) Energy policies play a significant role for the development of future power generation markets. The member states of the Euro- pean Union are increasingly dependent on oil and natural gas imports. A central statement in the Presidency Conclusions of the Euro- pean Council on the future Energy Policy for Europe (EPE) has expressed a clear comittment to member states' free choice of energy mix and sovereignity over primary energy sources following the three principles: • increasing security of supply, • ensuring the competitiveness of European economies and • promoting environmental sustainability and combating climate change. (8) EU policy framework is recently set by the Energy Policy Action Plan of the European Council in March 2007, in the Commis- sion's Communication "Sustainable power generation from fossil fuels: aiming for near-zero emissions from coal after 2020" in January 2007 and in the Commission's Green Paper on "A European Strategy for secure, competitive and sustainable energy" of March 2006. Be- side the ambitious targets concerning climate protection, renewable energies and energy efficiency, internal markets for electricity and gas have to be completed, monopolists have to unbundle and provide free access to the power and gas grids. Dependent on the progress

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of liberalisation, more competition among incumbents and new en- trants can be expected. (9) Electricity generation from Renewable Energy Sources (RES) other than hydroelectricity continues fast-paced growth among the countries of (especially) Western Europe. In March 2007 the 27 Member States that make up the EU set a firm target to 20% of the primary energy to come from renewable sources by 2020. The governments offer a lot of targeted political support for non-hydropower renewable power sources, most notably wind, in the form of subsidies, guaranteed feed-in tariffs or required quotas. Germany, Spain, and Denmark are the fastest growing wind producers in the world. (10) The Kyoto protocol specifies that the industrialized nations will cut their emissions of the six most important greenhouse gases in 2008-2012 by at least six per cent compared to 1990. The Energy Policy Action Plan of the European Council in March 2007 clearly ex- presses the will to continue the Kyoto policies beyond 2012, aiming at a 20% minimum target within the EU. (11) The EU installed an Emissions Trading Scheme (ETS) , which covers 54% of the EU-25 CO 2 emissions. According to EEA projections, most EU-15 countries are about to fail (with Germany and United Kingdom as exception), while most EU-10 are going to comply their Kyoto targets, which can mainly be attributed to the economic collapse of the East European economies after 1990. (12) The National Allocation Plans (NAPs) of the EU member states allocate all GHG emissions to different sectors. The plans de- fine CO 2 emission caps for the ETS participants. NAPs are based on a set of various rules and criteria, which have been applied very het- erogeneously in the first stage of the ETS (2005-2007). NAPs for the second allocation period are currently under discussion.

FRC Scenarios (13) For modelling the Future Role of Coal (FRC) in Europe in 2030 a specific "FRC" model has been developed and discussed among the accompanying expert group. Based on given final energy demand (gross power generation), prices and policies, the model calculates the investment and operational decisions of market orientated private companies in liberalised markets for 15 separate European regions, which may be aggregated to EU 27, EU 15 and EU 10+2. The FRC model employs marginal cost logic for merit order calcula- tions and ROE (return on equity) logic for investment decisions. (14) The framework of economic growth, population and final energy demand has been adapted to the DG TREN scenario work European Energy and Transport - Trends to 2030 (update 2005) [DG TREN/ NTUA 2006] (15) Following scenarios have been computed: • Base 5 Scenario is based the identical economic framework of EU trends to 2030 and representing comparable high fuel prices at constant 5 €/t carbon price for EUA (European Union Emissions Allowance).

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• Policy 15, 30 & 45 Scenario at the same (high) fuel price path representing different levels of climate protection policies, which might be induced by (more or less) ambitious political targets and their (more or less) strict and consequent implementation. • LowPrice 15, 30 Scenario representing two different levels of climate protection policies at moderate fuel price paths. • Tech 30 Scenario representing an accelerated technological progress with special focus on implementation of carbon capture and storage (CCS) technologies at a level of 30 €/t carbon price. • Tech 45 Scenario representing ambitious strategies for the implementation of carbon capture and storage (CCS) technologies and/or extended nuclear power options at a level of 45 €/t carbon price. (16) Different levels of rational use of energy (RUE) policies and/or aggravated policies on renewable energy sources (RES) have not been regarded within the ambitiuous (but still limited) project framework. In all scenarios final energy demand and contribution of RES in power generation has been kept unchanged.

FRC Results (17) High gas prices and low carbon prices lead to increasing shares of coal in power generation, even at comparable high carbon prices. Moderate gas prices may develop into a significant fuel switch at carbon prices around 30 €/t. (18) At high gas prices power generation based on natural gas (if not operated out in CHP mode) is not competitive for power generation in liberalised electricity markets at carbon price under 30 €/t. Nuclear power plants are likely to become economically feasible at 30 €/t. At very high carbon prices (45 €/t) natural gas is significantly taking up and CCS capacities appear to become economically feasible. (19) At moderate gas prices solid fuels remain competitive at carbon prices of 15€/t. At high carbon prices (30 €/t) both lignite and hard coal power plants significantly lose share against natural gas power plants. Nuclear power comes into play at 30 €/t. (20) A combination of high fuel prices and low carbon prices seems to be unlikely over a longer time period: looking at carbon emissions of the power sector at high gas prices, carbon prices are likely to go over 45 €/t. Moderate gas prices may lead to a significant fuel switch at around 30 €/t. As a consequence a significant fuel switch may turn into higher import dependency and - contradictory against premise - into significant higher gas prices not regarding the political acceptance of a much higher gas import dependency in the European Union which would be foremost a dependency of Russian Gas. (21) In order to tackle the challenge of ambitious climate protection targets and in order to avoid import dependency of price volatile fuels (as oil and gas) there are four possible technological options : RUE, RES, CCS (Carbon Capture & Storage) and nuclear

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power. Under same assumptions as in the baseline scenario of EU trends to 2030 a systematic exploitation of all technological options, including CCS and nuclear power may become necessary. (22) Even without CCS new power plant technologies yield a high primary and CO 2-reduction potential as average efficiencies of existing power plants are far below the potential efficiencies of new modern power plants. This becomes even more important as modern power plant technologies are immediately available and mitigation potential can be realised at short term. (23) After 2020, a large mid-term mitigation potential can be expected by the large scale implementation of CCS technologies which can be combined with modern power plant technologies. Be- cause of the high CO 2 removal rates (85-95%) CO 2 reduction potential is high, while energy efficiency is lower due to efficiency losses and energy input for CO 2 sequestration, transport and storage. (24) CCS power plants become economical feasible at carbon prices close to 30 €/t. The full cost logic implies a break-even point at carbon prices slightly below 30 €/t [TECH 30] . From ROE (return on equity ) perspective however, CCS technologies suffer from high capital intensity. They are competing in a complex economic environment, especially in presence of old conventional coal and gas power plants and new nuclear power plants. In TECH scenarios, technology options as nuclear, lignite CCS and hard coal CCS are appearing by the order of their marginal cost. CCS capacities show a similar economic character as nuclear power plants, needing a stable investment environment of high electricity prices and a carbon price level of at least 30 €/t. (25) CCS implementation requires a strategic and systematic approach by both power sector and state actors. Power sector actors are taking large efforts to implement pilot and demonstration plants at large scale by the middle of the next decade. For broad market implementation at large power plants, however, the CCS technology will not be available before 2020. (26) Compared to the carbon emissions of the power sector in 2005 carbon emissions are decreasing in case of high carbon prices and low gas prices [Low 30] or high carbon and gas prices [Policy 45, Tech 45] . The carbon intensity of power generation compared to 2005 is decreasing in Policy 30 , Policy 45 , Low 15 , Low 30 and both Tech scenarios. A considerable decarbonisation is reached in the TECH 45 scenario, which is including both CCS and nuclear power as technology options. The "mitigation" effect of high carbon prices cannot be observed gradually but is rather occurring in shifts. (27) Cost of power generation significantly increase due to the higher energy demand, due to the higher fuel prices and if technological options as nuclear energy and CCS are employed. The growth rate of the average real cost of unit electricity (without cost for EUAs) may be kept significantly under 1% p.a. (as in Policy 15 and Policy 30) or even under 0,4% p.a. at low price assumptions (as in LowPrice 15 and LowPrice 30). Looking at carbon emissions re-

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duction the technology scenarios [Tech 30, Tech 45] show lower emissions at lower full cost (incl. cost for EUAs), if compared with the same scenarios without CCS introduction [Policy 30, Policy 45]. (28) The main conclusion is: Depending on fuel and carbon prices coal has an excellent longterm perspective and an excellent competitive position in power generation in the European Union. Especially at high fuel price assumptions coal is on the way to push back gas power options. Even at moderate gas prices solid fuels remain competitive at carbon prices of 15€/t. (29) Nevertheless coal has to tackle the challenge of climate protection : for the mid- and longterm use of coal in the power sector the systematic exploitation and implementation of the CCS option is crucial, in order to show pathways for carbon reduced power generation at viable production cost. (30) There are large coal reserves and a high production share of coal in Europe. Coal is an important domestic fuel which significantly contributes to reduce import dependency. Even at longterm perspectives global resources and reserves are abundant and are available in comparatively stable international markets.

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1 Target & Structure

1.1 Target (31) Lignite and hard coal cover approximately 1/6 of primary energy consumption in the European Union (EU 25). About 2/3 of consumption are covered by domestic production. In the sector of power generation coal is indispensable. Coal delivers an important contribution to a secured and economic power supply within the community. (32) Due to its high carbon intensity coal gets in a defensive position in European climate protection policies. In particular the trade with greenhouse gases may lead to a dramatic degradation of the economic position of coal use in Europe. Having that in mind, the actual study aims to examine and to evaluate the actual situation and the future perspectives of coal in Europe. (33) The focus is set on the main coal producing countries (Po- land, Germany, United Kingdom, Spain, Greece, Czech Republic, Hungary, Bulgaria and Romania) and the major coal consuming markets (among the above mentioned and France, Italy, Netherlands). Coking coal production and use will be covered occasionally, but is not the main focus.

1.2 Structure (34) The focus of the study lies on key drivers and determinants of the European market of coal as fuel for power generation, thus providing the basis for the future work on a scenario. As the project overview in figure 2.2-1 shows the study is carried out in two phases: Phase 1 (preliminary survey) is comprising: • the actual and future position of coal in Europe, • climate protection policies and their instruments with a major focus on the European Commissions Emissions Trading Scheme (ETS), • status of renewable energies, • a survey of the relevant energy scenarios of EU, IEA and EIA on the development in Europe. Phase 2 (main study) is comprising: • BASE scenario on the role of coal in Europe until 2030 • LOW energy PRICE scenarios

• POLICY scenarios with higher CO 2 allowance prices (15, 30, 45 €/tCO 2)

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• TECHNOLOGY scenarios at high CO 2 allowance prices (30 & 45 €/tCO 2) and systematic use of technology options as CCS and nuclear power plants.

Kick off Preliminary Survey Workshop Main Study Report 1. 2. 3. 4. 5. Specification Analysis Discussion Scenario Report project description existing statistics results of the role of coal in evaluation timeline existing scenarios preliminary survey Europe until 2030 recommendations workshops on the specifications development of for the main study Europe

Participants Content Specifications Content Content EURACOAL significance of base data prognosis 2030 results of the preliminary survey Prognos AG coal line of climate change NAPE / NACE instruments for argumentation policy restrictions results of the main CO2-Reduction, study Siemens investigative potential of coal REG-Promotion requirements

Results Results Results Results Coordinated Initial evaluation Base assumptions Consistent project goals of coal in Europe for the main study Scenario

ca. 6 Months ca. 12 Months

figure 1.2-1 Project Overview

1.3 Focus (35) The focus of this study lies on key drivers and determinants of the European market of coal as fuel for power generation, thus providing the basis for the future scenario work. Consequently the major concerns are: • Coal as primary energy, concentrating on − resources, reserves and production − import, trade and prices • Electricity as final energy focusing − development of final energy consumption − coal as fuel in power generation • Policy as a key stakeholder for the development of future energy markets, both on European and national level, especially in the fields of: − policy strategies in energy markets,

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− climate protection policies, with a main focus on the emissions trading system, − renewable energy policies. (36) A significant section of this report is covering the current situation in 12 selected and most relevant markets of Europe, • with 7 countries representing the EU 15 (Germany, United Kingdom, Spain, Greece as important coal producers as well as France, Italy and Netherlands (next to the above mentioned) as the main coal consuming countries) • with 3 countries representing the EU 10 (coal producers Po- land, Czech Republic and Hungary) • and 2 countries representing candidate countries for future accession to the EU, both producers of lignite (Bulgaria and Ro- mania)

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2 Coal in Europe: Overview

2.1 Coal Consumption

Conclusion After an all-time low of 495 Mtce in 1999 coal consumption was taking up again, especially in EU 15 (from 292 to 314 Mtce in 2004), while during the same period staying almost constant at 145 Mtce in EU 10 and selected candidate countries. Another 60 Mtce are consumed by neighbouring countries of the European Union, not counting the former states of the Soviet Union, where consumption has been as well decreasing to 230 Mtce in 1998 and growing to 250 Mtce in 2004. Thus, coal remains one of the most important energy sources in Europe.

2.1.1 Primary Energy Consumption: The Role of Coal (37) Coal consumption has been decreasing in Europe over the past decade, both in the old EU 15, the EU 10, candidate (BU, RO, TK) and neighbouring countries (NO, CH, IS). Overall coal consumption showed a 12% decrease from 560 Mtce to an all-time low of 495 Mtce in 1999. This decrease can mainly be attributed to the economic collapse of the East European economies.

400,0

Coal Consumption EU 15 [Mtce] 350,0

300,0

250,0

Ireland 200,0 Sweden Austria Portugal Denmark 150,0 Finland Belgium & Luxembourg Netherlands Greece 100,0 France Italy Spain 50,0 United Kingdom Germany

0,0 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 figure 2.1-1 Coal Consumption in EU 15 [source: BP 2005]

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400,0 Coal Consumption in Selected EU 10 and Candidates [Mtce]

350,0

300,0

250,0

200,0

150,0

Lithuania Hungary 100,0 Slovakia Bulgaria Romania Czech Republic 50,0 Poland

0,0 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 figure 2.1-2 Coal Consumption in selected EU 10 (38) In the new millennium coal consumption was taking up again, especially in EU 15 (from 292 to 314 Mtce), keeping the level in EU 10 and selected candidate countries (145 Mtce). Another 60 Mtce are consumed by neighbouring countries of the European Un- ion, not counting the former states of the Soviet Union, which have been as well decreasing to 230 Mtce in 1998 and growing to 250 Mtce in 2004 (cp. figure 2.1-1). (39) Germany is presently by far the largest coal consumer in the EU, with Poland far the second-largest. Overall, the EU accounts for about 15% of the world's total coal consumption [CSLF 2005] .

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table 2.1-1 Coal and Lignite production, import and consumption (all coals) [BP review 2005]

(40) As can be seen from the overview in table 2.1-1 coal consumption has been declining all over Europe with an average annual growth rate of –1.1% p.a. This development can be mainly attributed to the decline of the economy in accession states after 1990 and the fuel switch in United Kingdom. With a decrease in Denmark, Belgium and Luxemburg at one side, there was a significant increase in Italy on the other side. (41) It has to be taken into account, that in EU 15 coal consumption was increasing with an annual growth rate of 1.5% and was almost stable in EU 10 during the last five years.

2.1.2 Coal Production

Conclusion Europe (without former Soviet Union) presently accounts for about 315 Mtce coal production , this is 12% of the world's total annual coal production (2’550 Mtce). Neighbouring countries including Tur- key and the states of the former Soviet Union add to approximately the same amount of produced coal (320 Mtce). Germany and Poland are by far the largest coal producers in the EU; together they account for about 2/3 of all coal presently produced in the EU. Coal production has a long tradition and importance in many European economies. (42) Europe (without former Soviet Union) presently accounts for about 315 Mtce coal production, this is 12% of the world's total annual coal production (2’550 Mtce). Neighbouring countries including Turkey and the states of the former Soviet Union add to approxi-

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mately the same amount of produced coal (320 Mtce). Germany and Poland are by far the largest coal producers in the EU; together they account for about two-thirds of all coal presently produced in the EU. Of the other member countries, Greece and the Czech Republic are both relatively large coal producers, with the only other significant coal production coming from Spain and the United Kingdom [CSLF 2005] , after closure of the last French coal mine in 2004. (cp. figure 2.1-3) (43) Overall, annual coal production in the EU in 2004 (277 Mtce) was about 73% of what it was in 1994 (377 Mtce), with Greece being the only country that had a larger annual production rate in 2004 than it did in 1994.

400,0

Coal Production in EU 15 [Mtce]

350,0

300,0

250,0

200,0

150,0

100,0 France Spain Greece 50,0 United Kingdom Germany

0,0 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 figure 2.1-3 Coal Production in EU 15

(44) Coal production went down as well in Eastern Europe, yet after a sharp decrease in the late 90s (from 192 to 157 Mtce in 2000), production was stabilising at the level of the year 2000 (cp. figure 2.1-4). The same decrease was experienced in the neighbour states of the former Soviet Union, but since 1999 production was growing again (after an all-time-low of production in 1998 from about 257 Mtce to 305 Mtce in 2004) (45) The production of Bulgaria, Greece, Hungary and Romania is dominated by lignite, while Germany, Poland, Czech Republic and (at a very low level) Spain are producing both lignite and hard coal. United Kingdom is mainly hard coal producer.

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2.1.3 Resources and Reserves

Conclusion In Europe there is both a large reserve of hard coal as well as subbituminous and lignite available, with reserves regionally dispersed. In- cluding Russia Europe is keeping more than 30% of the proven reserves worldwide, however only 4.4% in the member states of the EU. Reserves in western and southern Europe (EU 15) have significantly decreased due to a high production level during the last 50 years, while EU 10 and candidate countries, especially Poland still keep significant reserves. (46) World coal resources and reserves are abundant. Total resources are estimated to an equivalent of 4’773 billion tce [Euracoal 2005]. Proven reserves add to 670 billion tce, according to the last survey of World Energy Council an amount of 907 billion tons in total (table 2.1-2)

Proven Reserves [Mt] Bituminous Sub-Bit. Stat. Res. Brown/Lignite Stat. Res. Total (end of 2003) [Mt] [Mt] [a] [Mt] [a] [Mt] World 476'971 272'326 186 157'967 178 907'264 OECD 170'563 110'352 201 90'688 148 371'603 OECD Europe 17'702 4'718 120 17'041 39 39'461 OECD North America 115'669 103'149 235 35'614 313 254'432 OECD Pacific 37'192 2'485 141 38'033 586 77'710 Transition Economies 94'554 114'208 645 38'872 179 247'634 Russia 49'088 97'472 780 10'450 133 157'010 Asia 153'572 35'527 94 28'280 502 217'379 China 62'200 33'700 64 18'600 - 114'500 East Asia 1'287 1'766 19 4'330 140 7'383 South Asia 90'085 61 262 5'350 211 95'496 India 90'085 0 265 2'360 93 92'445 Latin America 7'701 12'068 324 124 - 19'893 Brazil 0 10'113 1'744 0 - 10'113 Africa 50'162 171 206 3 - 50'336 Middle East 419 0 419 0 - 419 table 2.1-2 Proven Reserves of Coal by regions and types [source: IEA 2004b]

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Definitions: Resources refer to the amount of coal that may be present in a de- posit or coalfield, independent of the economic feasibility. Reserves constitute those resources that are recoverable. Probable (or indicated) reserves are estimated with a lower degree of confidence. Proved (or measured) reserves are not only confidently considered to be recoverable, but can also be recovered economically, under current market conditions [IEA 2004 1].

Hard Coal Lignite Region Resources Reserves Production Resources Reserves Production [Mt] [Mt] [kt/a] [Mt] [Mt] [kt/a] EU 15 Germany 186’000 23’000 29’200 77’600 41’300 181’900 Greece - - - 6’700 3’200 71’900 Spain 4’200 600 12’300 80 50 8’200 United Kingdom 1’000 220 25’100 - - - France *) 99 - - 2 - - EU 10 + BG + RO Poland 113’300 12’113 99'200 58’000 2’423 61'100 Czech Republic *) 4’123 295 13’300 3’873 812 48’800 Hungary 450 198 300 9'000 3’400 11’800 Bulgaria 440 270 3'200 4’031 2’045 23’700 Romania 8’307 810 3’700 2’500 1’456 31’600 table 2.1-3 Resources, Reserves and Production in Selected EU-27 (2004) [source: EURACOAL member, estimates] *) Resources and reserves for France and the Czech Republic in [Mtce]

(47) As outlined in our definition above, the amount of proven reserves is not constant, but dependent on the economic and techno- logic framework 2. For the instant a static reserve (reserve divided by actual production) of 186 years for hard coal and 178 years for brown coal or lignite is available. Not counting the Brazilian subbituminous reserves there is a longest available hard coal reserve in Russia (780 years). (48) In Europe there is both a large reserve of hard coal as well as subbituminous and lignite available, but reserves are regionally dispersed. Including Russia Europe is keeping more than 30% of the proven reserves worldwide, however only 4.4% in the member states of the EU. Reserves in western and southern Europe (EU 15) have significantly decreased due to a high production level during the last

1 IEA Coal Information (2004 Edition) Part I 2 An WEC estimate in 1978 set proved coal reserves at 636 billion tons. The 2003 figure is 43% larger than 25 years before.

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50 years, while EU 10 and candidate countries, especially Poland still keep significant reserves (cp. table 2.1-3).

(49) The BGR numeralises reserves and resources on a lower level than EURACOAL. The definitions and estimates for resources and reserves differ. In table 2.1-4 these differences are illustrated. The different figures can in part be explained by the fact that the BGR only indicates legally approved reserves in those countries in which coal is subsidized. The underlying assumption in these figures is that there will be no further production of coal after the period of assured governmental promotion runs out.

Hard Coal Lignite Region Resources Reserves Production Resources Reserves Production [Mt] [Mt] [kt/a] [Mt] [Mt] [kt/a] Europe 83'930 11'946 183'900 172'350 40'491 539'300 EU 15 - 581 57'400 85'557 9'758 254'600 Germany 8'384 161 24'700 76'396 6'556 178'000 Greece - - - 7'500 3'202 69'100 Spain 2'948 200 12'200 1'051 - 7'500 United Kingdom 7'000 220 20'500 500 - - France - - - 110 - - EU 10 + BG + RO 60'931 10'741 113'220 53'921 9'101 172'500 Poland 50'900 8'354 96'300 40'149 1'878 59'900 Czech Republic 7'155 2'094 13'600 1'892 3'458 48'900 Hungary 1'975 198 300 6'850 595 12'600 Bulgaria - 95 320 2'730 2'698 23'200 Romania 901 - 2'700 2'300 472 27'900 table 2.1-4 resources & reserves of coal by regions and types [source: BGR 2005] Reserves and resources developed in existing legally approved mines.

2.1.4 Coal Imports (50) Coal consumptions are exceeding the European production, with net imports growing from 125 Mtce (1994) to 147 Mtce (2004). Greece is the only coal producing country of EU 15 with a balanced import saldo. Major importers are Germany (44.3 Mtce) and United Kingdom (32.6), followed by Italy (24.4), Spain (20.6), France (17.1) and Netherlands (13.0). (51) Not all imported hard coal is used as thermal coal. France (6.1 Mtce), Italy (5.2), the Netherlands (4.4), Belgium (3.4) and Aus- tria (1.9) are using a significant amount (between 15 and 50%) imported coking coal for steel production. Germany (23.0) and United Kingdom (6.8) use both imported and domestic coking coal.

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Coal Production in EU 10 and selected Candidates [Mtce]

400,0

350,0

300,0

250,0

Hungary Bulgaria 200,0 Romania Czech Republic Poland 150,0

100,0

50,0

0,0 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 figure 2.1-4 Coal Production in Selected EU 10 and Candidate Countries [different sources, own calculation]

(52) The demand of EU 10 and of the acceding states surpasses the domestic production as well, but not in such a significant manner as within EU 15. Poland and Czech Republic are net exporting countries, with 17.3 Mtce (Poland) and 4.4 Mtce (Czech Republic) of ex- ported hard coal in 2004 (cp. figure 2.1-6)

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200,0

Coal Imports EU 15 [Mtce] 150,0

100,0

Ireland Sweden Austria 50,0 Portugal Denmark Finland Belgium & Luxembourg Netherlands France Italy 0,0 Spain 1994 United 1995Kingdom 1996 1997 1998 1999 2000 2001 2002 2003 2004 Germany Greece

-50,0 figure 2.1-5 Coal Imports in EU 15 [different sources, own calculation]

20,0 Coal Imports sel. EU 10 and Candidates [Mtce]

10,0

0,0 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

-10,0

-20,0

-30,0 Czech Republic Poland Lithuania Hungary -40,0 Romania Bulgaria Slovakia

-50,0 figure 2.1-6 Net Coal Imports of selected EU-10 and Candidate Countries [different sources, own calculation] (53) Coking coal is playing a significant role in Slovakia, where most imports are used for steel production, while domestic lignite is used in power plants.

page 25

(54) The most important countries of origin for European hard coal imports (2004) are - with growing importance: • South Africa 56 Mt • Australia 30 Mt • Colombia 21 Mt • Former Soviet Union 21 Mt with decreasing importance: • U.S. 12 Mt and – also with decreasing importance – as an important intra- European trade partner: • Poland 16 Mt

2.1.5 Coal Prices

Conclusion Price predictions cannot be seriously made, because prices are dependent as well on factors as expectation and speculation. However, with view on reserves and competitive producer markets as a first conclusion can be drawn, that coal prices are more likely to stay stable than other fossil fuels. (55) Coal prices are an important key for coal as fuel in power generation. They are comparatively stable and do not suffer from high volatility as prices for natural gas, which is – among others - dependent of the oil price development. Especially the low fuel cost for lignite imply the use of coal capacities as base load capacities. (56) After nearly 20 years of consistent declines, export coal prices nearly doubled from 2003 to 2004. Increased domestic demand in major exporting countries (China, Russia) or decreased production (USA) tightened the market [McKinsey 2005]. China's economic development absorbed coal and steel, among other commodi- ties, turning the nation from an exporter, which pushed Asia-Pacific prices down at the beginning of the century, into a net coal importer. (57) Furthermore temporary supply/demand imbalances occurred. On the demand side, unusually warm weather in Europe drove the need for electricity and at the same time reduced the availability of alternative energy sources (hydro and nuclear) in favor of coal. Several nuclear power plants in Japan were closed for maintenance. (58) High oil and gas prices contributed as well through a shift in demand and higher transportation cost for coal. On the supply side, logistical bottlenecks in ports and railway systems in South Africa and Australia led to capsize vessel rates, which were higher than any experienced on the market over the last 25 years (26 US$/t). (59) Steam coal prices fell to a twenty year low in 1999/2000 with CIF prices of around $35 a ton for both Japan and Europe. However, since then prices have been rising to levels of $60-80 per tone in

page 26

early 2005, with the McCloskey Marker Price North West Europe at $78.70 in December 2004 [World Coal Report 2005]. (60) In the same time oil and gas prices were rising due to − growth of demand − limited spare capacity − limited refining capacities − increasing interest in commodity markets for investments and speculative transactions (61) The price development for imported oil and gas was volatile in the past 30 years. As can be seen in figure 2.1-7 nominal gas and oil prices fluctuated heavily in the past decades. Import steam coal prices followed the prices for imported oil and gas but were not as volatile. Furthermore, the spread between coal prices and prices for other fossil fuels has increased dramatically since 2000. A large spread makes coal more attractive as an energy source for power generation.

300

Import Prices for Selected Power Plant Fuels [€/tce]

250

200

150

100

0 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006

Crude (Import) Gas (Import) Gas (PP) Coal (Import) figure 2.1-7 Prices for Imported Energy Sources in Germany [€/tce] [source: Statistik der Kohlenwirtschaft e.V.]

(62) As a preliminary conclusion, all fossil fuels were short because there was inadequate investment in fuel production in re- sponse to depressed fossil prices over the last decade of the last century. In the new decade expanding economies develop increasing demand for all fossil fuels, not only in Asia, but also in other economic relevant regions (Soviet Union, North America and Europe) at the same time. Now, with worldwide fossil energy supplies as costly as

page 27

they have been in a decade, coal was still more efficient for electricity generation than gas and oil. Variable cost economics implied burning of coal in existing power plants.

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2.2 The Role of Coal in Power Generation

2.2.1 Final Demand of Electricity (63) The consumption of electrical energy is expected to increase at an annual rate of 2.5% worldwide, nearly doubling from 16’100 TWh to 31’700 TWh in 2030. Strong growth is expected in countries of the developing world at an annual rate of 3.5% [IEA coal 2005]

2500

Final Electricity Consumption (Sel. EU 15) [TWh]

2000

1500 EL

1000 ES

UK 500 FR

0 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 figure 2.2-1 Electricity Consumption in selected EU 15 [source: Eurostat 2005]

(64) With a total of 2’612 TWh the European Union presently accounts for about 16% of both the world's annual electricity generation and consumption, while EU 15 accounting for 90% of the European Unions’ electricity (2’371 TWh). Germany and France are the two biggest electricity producers and consumers in the EU, followed by the United Kingdom, Italy, and Spain (cp.). (65) The annual growth rate of the EU 15 is at an average of 1.8% p.a. (between 1990 and 2003) and significantly higher than that of the new accession states, where electricity consumption nearly kept the level of 1990. Especially the candidate countries Bulgaria (- 2.6%) and Romania (-2.2%) show a negative growth rate over that time period. (66) However, from figure 2.2-2 it can be seen that in central and eastern Europe the demand of electricity was increasing again during the last ten years after the breakdown of the Comecon system at the beginning of the 90s. In general during the last years (1999-2003) al-

page 29

most the same growth rates have been reached in EU 10 (1.9%) as in the EU 15 (2.4%).

300,00

Final Electricity Consumption (Sel. CEEC) [TWh]

250,00

200,00

150,00 BG

HU 100,00 RO

50,00 CZ PL

0,00 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 figure 2.2-2 Electricity consumption in selected Central and East European Countries [source: Eurostat 2004] (67) During the last five years (1999-2003) the highest growth rate of electricity consumption can be found in southern Europe with Spain (5.5%); Greece (4.4%), Italy (2.8%), Romania (2.6%) and France (2.2%). That might be strong hint that summer electricity consumption for cooling is getting a more and more important driver for electricity consumption - next to economic growth.

2.2.2 European Power Markets

2.2.2.1 Stability of Power Generation (68) The summer of 2003 was marked by several widespread power failures in some of the largest economies of the Western Euro- pean region. An unusually severe heat wave occurred during the summer months, testing many nations’ electricity infrastructures. Nu- clear power plants were forced to curb operations in Germany and in France when water temperatures exceeded legal limits and the nuclear power plants could not dispose of the water used to cool nuclear core elements. In addition, a lack of wind resulted in weaker perform- ance of installed wind generation in Germany [EIA 2004]. (69) In August 2003, London experienced an electric power outage that affected 400,000 customers during rush hour. However, the U.K. natural gas and power market regulator, often, determined that the failure—and another one that followed a week later—were not caused by insufficient grid investment. Instead, the outage was caused by the wrong type of fuse installed on backup protection

page 30

equipment. Denmark and Sweden, with integrated electricity systems, suffered their worst blackout in 20 years when the 1,135-megawatt nuclear power plant at Oskarshamn in Sweden was shut down, trig- gering an automatic closure at Sweden’s 1,800 megawatt Ringhals nuclear power plant. The shutdown at Oskarshamn was attributed to a fault on the transmission line. Lack of investment in the Scandina- vian power grid has been cited as a key reason for the massive failure [EIA 2004]. (70) The number and severity of the power failures that hit West- ern Europe in 2003 have raised concerns about the liberalization of electricity markets in the region. In the case of the United Kingdom, Sweden, and Denmark, governments are questioning whether the power failures resulted from a lack of investment in the national grids, which is less profitable to companies than is investment in new capacity. In Italy, on the other hand, the government has moved to speed up the process of liberalization in the wake of the widespread power outages, by expediting legislation on an energy reform bill that would make it easier for companies to construct new generation capacity. In the short term, the government passed an emergency de- cree at the end of August 2003 that allowed the Industry Ministry to let power producers ignore temperature limits on the waters they dis- charge [EIA 2004].

2.2.2.2 Liberalization of the Power Market (71) European power network is organised by the Union for the Coordination of Transmission of Electricity" (UCTE), which is respon- sible for the operation and development of the electricity transmission grid from Portugal to Poland and from the Netherlands to Romania and Greece (not comprising Great Britain and Scandinavia). (72) The European power exchange pattern is complex and cannot be read easily because it is highly dependent on the type of demand (base, semi-base, peak) and the actual economic and meteoro- logical framework conditions. If related to the total final electricity consumption the net exchanged electricity is – as a general rule - still below 10% (cp. figure 2.2-3). (73) There are however exceptions to that rule with France with 60 TWh (15% of its domestic electricity consumption) being the major net exporter of the European Union and at the other side, Italy with a net import of 48 TWh (15%) being the major importer, followed by The Netherlands (18 TWh, 16%). (74) Western Europe’s drive to reduce cross-border barriers throughout the regional economy is expected to increase competition in its electricity and natural gas markets. In Eastern Europe, efforts to restructure and liberalize national electricity sectors have been driven by the accession of several countries to the EU. EU membership has compelled many nations of the region to reform electricity markets in order to meet EU standards.

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figure 2.2-3 Physical electricty ex change 2005 [source: UCTE 2006]

2.2.3 Capacities (75) Installed power generation capacity in the European Union has been steadily increasing over the past several decades, and now accounts for about 18% of the world total when the ten new member countries are included. Germany and France have the largest amount of the EU's installed generating capacity, together accounting for about 35% of the current EU total. (76) Most of Germany's installed capacity is fossil fuel-based, while France presently accounts for nearly half of the EU's nuclear power generation capacity and more than 20% of the EU's hydroelectric capacity. (77) As can be seen from the following pictures power capacities in Europe are highly diverse and were dependent on political decisions over the last 30 years. As a reaction to the oil crises in the 1970s and 1980s, national governments decided to promote investments in coal and in nuclear power capacities. Today’s power gen-

page 32

eration mix in Europe reflects the energy policy of these years. The national capacity mix is influenced by aspects as security of supply, domestic availability, diversity, environmental and climate protection, traditional economic structures and technological innovations and state funding.

100% Hydro

90% Geothermal

Wind 80% Conv. Others 1)

70% Gas (>30 MWel) Oil (>30 MWel) 60% Nuclear

Hard Coal (>30 50% MWel) Lignite (>30 MWel) 40%

30%

20%

10% Installed Capacities by Fuel (2003/2004) 0% PO CZ EL GE BG RO UK EU25 ES EU15 HU NL IT FR 1) Plants <30 MWel, Biofuels, Diesel Sources: Eurostat 2005 & Siemens 2005 figure 2.2-4 Installed Capacity by Fuel [source: Eurostat/Siemens/prognos] (78) Non-hydroelectric renewable energy sources of electricity have now started to become a significant contributor to the overall mix of electricity generation in the EU; Germany by far has the largest such installed capacity, with nearly as much as the rest of the EU combined. Spain and Denmark have also greatly increased their renewable energy generating capacity. Most of the renewable energy in the EU is wind energy [CSLF 2005] (79) The contribution of renewable energy sources has increased, with almost unchanged capacities in installed hydroelectric, but with a significant increase in installed wind capacities, summing up to 30 GW in 2004, with half of the capacities being installed in Germany and about 6 GW in Spain. The only other significant non- conventional thermal power generating sources are geothermal plants in Italy, with 666 MW of installed capacity.

(80) Slightly more than half of the EU's total electricity generation is from fossil fuels, with the amount of generation from fossil fuels about 24% greater in 2001 than it was in 1993 [CSLF 2005] . As can be seen from figure 2.2-4 and figure 2.2-5 coal is playing a dominant role in the European Union with 25% of installed capacities and almost one third of the power generation. Only nuclear capacities have a similar contribution in European power generation.

page 33

figure 2.2-5 Share of Fuels in Power Generation [Eurostat]

2.2.4 Outlook on Future Capacities (81) As can be seen from figure 2.2-6 there is a demand for replacement of more than 380 GW old capacities (> than 30 MW) during the next 30 years in the EU 25, with a large emphasis on coal capacities during the next 10 years, followed by a large amount of the nuclear capacities to be replaced between 2015 and 2030. This structure of power plant capacities is in part a result of the energy policies pursued in the 1970s and 1980s. Additional capacities needed to meet future power demand that will occur during the next 3 decades (cp. chapter 8) are not considered in this calculation. This provides both risks and chances for a technological shift in power generation. (82) There are regional differences: in eastern Europe the situation is determined by a lack of investments with a lot of coal capacities already older than 40 years (cp. figure 2.2-7) (83) Some regions, such as Iberia, will have significant excess capacity by 2010, especially through new gas-fired power plants, so that there is temporarily no need for new coal or gas capacities. For other areas, such as the Central countries, a shortage in generation capacity may occur (compare country reports as well as chapter 8). (84) The full cost vs. variable cost economics suggest that last 10 years were dominated by a "burn coal, build gas" trend. The impact of

the CO 2 cost was expected to strengthen this trend. Consequently, planned expansions in generation capacity were mainly natural gas based. With view to the rising gas prices since 2000, there is a trend back to investments in coal capacities.

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Capacity to be replaced in EU25* by time and fuel provided [MW el ]

120'000 Assumptions lifetime: OTHERS NUC: 40 years OIL 100'000 COAL: 40 years GAS LIG: 40 years GAS: 30 years LIG 80'000 OIL: 30 years COAL OTHERS: 30 years NUC

60'000

40'000

20'000

0 before 2011 2011 - 2015 2016 - 2020 2021 - 2025 2026 - 2030 2031 - 2035 *without Latvia and Estonia figure 2.2-6 Power Capacity Renewal 3 (Siemens data base / own evaluation)

(85) The mix of the new generating capacities will depend on a number of factors including: • investment rentability − fuel prices (rsp. cost) − electricity retail prices − taxes and carbon prices − capacity cost • investment security − development of final energy demand − indigenous and international fuel availability − fuel diversity

3 IEA/OECD 2005

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Capacity to be replaced in EU10* by time and fuel provided [MW el ]

20'000 Assumptions lifetime: OTHERS 18'000 NUC: 40 years OIL COAL: 40 years GAS 16'000 LIG: 40 years GAS: 30 years LIG 14'000 OIL: 30 years COAL OTHERS: 30 years 12'000 NUC

10'000

8'000

6'000

4'000

2'000

0 before 2011 2011 - 2015 2016 - 2020 2021 - 2025 2026 - 2030 2031 - 2035 *without Latvia and Estonia figure 2.2-7 Capacities to be replaced by time and fuel provided (EU 10) [Siemens data base / own evaluation] • infrastructural framework − regional infrastructural exposition to (different) fuel markets (fuel terminals and hubs, coast, harbour, river ships, railway terminals) − local infrastructural exposition (local fuel terminal, storage capacities, waste management) − availability and accessibility to grids • political framework − legal framework: regulations, approval procedures − climate protection policies − support schemes for RES and CHP − long term reliability of political systems and political support • technology framework − political support for technologies − availability of know-how and skilled staff (especially in case of application of advanced technologies) • stakeholder acceptability − environmental acceptability − social acceptability

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3 FRC Scenario Framework

3.1 Scenario Overview

Base Policy Low Price Tech Tech 5 15/30/45 15/30 30 45 Final Enery EU-Trends EU-Trends EU-Trends EU-Trends EU-Trends RES/RUE

Energy EU-Trends EU-Trends Energy EU-Trends EU-Trends Prices (high) (high) Report IV (high) (high) (moderate) Climate EU-Trends 15€/t mod. 15€/t mod. Protection 30€/t aggr. 30€/t aggr. 30€/t aggr. 45€/t high 45€/t high Technology economical economical economical accelerated regulatory logic logic logic technology policy progress table 3.1-1 FRC Scenarios (Overview)

(86) For the FRC project different scenarios have been computed. In order to yield a comparable economic, demographic and demand side framework DG-TRENs EU trends to 2030 (ed. 05) [DG TREN/ NTUA 2006] parameters have been applied, as far as they have been made available, to display the future role of coal. For the scenario work differing assumptions have been made to show the impact of major economic and political framework conditions (e. g. price paths, carbon prices, technology paths): • Base 5 Scenario is based on the identical economic framework of EU trends to 2030 and representing comparable high fuel prices at constant 5 €/t carbon price (EUA). • Policy 15, 30 & 45 Scenario at the same (high) fuel price path representing different levels of climate protection policies, which might be induced by (more or less) ambitious political targets and their (more or less) strict and consequent implementation. • LowPrice 15, 30 Scenario representing two different levels of climate protection policies at moderate fuel price paths. • Tech 30 Scenario representing an accelerated technology progress of carbon capture and storage (CCS) technologies at a level of 30 €/t carbon price.

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• Tech 45 Scenario representing ambitious strategies as a regulatory implementation of carbon capture and storage (CCS) technologies and/or extended nuclear power options at a level of 45 €/t.

3.2 Fuel Prices

Summary Fuel prices are modelled according to two different borderline price paths. The BASE price path is based on the EU trends to 2030 (05 edition), the LOW PRICE path is based on the German Energy Re- port IV. For the resulting fuel prices at the power station for both price paths similar transport and delivery conditions have been assumed.

(87) The BASE Price scenario is based on EU trends (ed. 05) [DG TREN/ NTUA 2006] (cp table 3.2-1).

Border Prices 2010 2020 2030 Crude Oil EU trends (ed. 05) [US$ 2005 /boe] 44,60 48,10 57,60 Natural Gas EU trends (ed. 05) [US$ 2005 /boe] 33,90 37,00 44,70 Hard Coal EU trends (ed. 05) [US$ 2005 /boe] 12,50 14,10 14,90

Border Prices 2010 2020 2030 Crude Oil EU trends (ed. 05) [€ 2000 /MWh] 21,61 25,68 30,78 Natural Gas EU trends (ed. 05) [€ 2000 /MWh] 16,42 19,76 23,89 Hard Coal EU trends (ed. 05) [€ 2000 /MWh] 6,06 7,53 7,96 table 3.2-1: International price assumptions for BASE Price scenario [DG TREN/NTUA 2006] (88) As the BASE Price scenario indicates a comparatively high price path, another (lower) price path has been chosen for our PRICE scenario (cp. table 3.2-2). The lower price path is modelled according to the German reference study Energiereport IV (ER IV) [prognos/EWI 2005 ]

Border Prices 2010 2020 2030 Crude Oil ER IV [EWI/prognos] [US$ 2000 /boe] 28,00 32,00 37,00 Crude Oil ER IV [EWI/prognos] [€ 2000 /t] 200,00 235,00 270,00 Natural Gas ER IV [EWI/prognos] [€ 2000 /MWh] 11,10 12,80 14,30 Hard Coal ER IV [EWI/prognos] [€ 2000 /tce] 46,00 48,00 50,00 Crude Oil (fob) Crude Oil (fob) Crude Oil (fob) ER IV [EWI/prognos] [€ 2000 /MWh] 14,84 18,69 21,63 Natural Gas ER IV [EWI/prognos] [€ 2000 /MWh] 11,10 12,80 14,30 Hard Coal ER IV [EWI/prognos] [€ 2000 /MWh] 5,65 5,90 6,14 table 3.2-2: International price assumptions for LOW PRICE scenario [EWIprognos 2005] (89) The comparison of EU trends and ER IV price paths shows that oil and gas prices are assumed to be significantly higher (factor 1.5 to 1.7) in EU trends, while the coal prices are [€ 2000/MWh] are higher by a factor of 1.1 to 1.3.

page 38

(90) Prices at power plants are not published officially by EU trends. We have assumed comparable transportation and delivery cost (cp. table 3.2-3) as for our power plant fuel price scenario for ER IV (cp. table 3.2-4). Both tables and figure 3.2-1 show the prices at the power plant as in our model calculation.

Fuel Prices (Power Station) (EU trends 06) NEU 2010 2020 2030 Fuel Oil (assumption) [€ 2000 /MWh] 39,00 44,08 49,16 Heavy Fuel Oil (assumption) [€ 2000 /MWh] 21,28 24,93 29,05 Gas (assumption) [€ 2000 /MWh] 19,42 22,76 26,89 Hard Coal (assumption) [€ 2000 /MWh] 6,68 8,15 8,59 Lignite (assumption) [€ 2000 /MWh] 3,70 3,90 4,10 Nuclear (assumption) [€ 2000 /MWh] 3,13 3,18 3,30 table 3.2-3: fuel prices at power station for BASE scenario [assumptions based on EU trends 05]

Fuel Prices (Power Station) (ER IV) 2010 2020 2030 Fuel Oil (Low Price) [€ 2000 /MWh] 29,06 32,65 36,27 Heavy Fuel Oil (Low Price) [€ 2000 /MWh] 14,24 15,97 17,30 Gas (Low Price) [€ 2000 /MWh] 13,00 14,58 16,02 Hard Coal (Low Price) [€ 2000 /MWh] 6,19 6,55 6,70 Lignite (Low Price) [€ 2000 /MWh] 3,60 3,60 3,60 Nuclear (Low Price) [€ 2000 /MWh] 3,13 3,18 3,30 table 3.2-4: fuel prices at power station for LOW PRICE scenario [EWIprognos 2005]

60,00

Fuel Oil (assumption) FRC Reference Prices at power plant [€ 2000 / MWh] Heavy Fuel Oil (assumption) 50,00 Gas (assumption)

Hard Coal (assumption)

40,00 Lignite (assumption)

Nuclear (assumption)

Fuel Oil (Low Price) 30,00

Heavy Fuel Oil (Low Price)

Hard Coal (Low Price) 20,00

Gas (Low Price)

Lignite (Low Price) 10,00

Nuclear (Low Price)

0,00 2000 2005 2010 2015 2020 2025 2030 figure 3.2-1 fuel prices at power plant [EU trends prices "□" as assumed, low prices "o" as assumed according to ER IV]

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(91) As can be seen from figure 3.2-2 fuel prices for solid and nuclear fuels are assumed to be less (hard coal, lignite) or even not (nuclear) dependent on the international crude oil price level.

10,00

FRC Reference Prices at power plant Hard Coal (assumption) 9,00 [€ 2000 / MWh]

8,00

Lignite (assumption)

7,00

Nuclear (assumption) 6,00

5,00

Hard Coal (Low Price) 4,00

3,00 Lignite (Low Price)

2,00

Nuclear (Low Price) 1,00

0,00 2000 2005 2010 2015 2020 2025 2030 figure 3.2-2 fuel prices at power plant [EU trends prices "□" as assumed, low prices “o” as assumed according to ER IV]

3.3 Policy (92) Policy is a major, however hardly predictable driver for the power market. As there is no reliable policy forecast, it is helpful to identify the main policy drivers and to assess the range of impacts, which might be initiated by policy action. Policy is applied, if usual market mechanisms are not sufficient or are leading in a political not intended direction. For our study we have identified following relevant policy drivers: • climate protection policy and the emission trading scheme with its (direct) implication for the carbon price, • technology policy with promotion of new technological solutions as the clean coal technologies (e. g. carbon capture and storage), • nuclear energy policy with specific policy restrictions (e.g. nuclear phase out, limited approval) and specific promotion strategies towards the use of nuclear energy, • renewable energy policies and the policy targets settled in the directive on renewable energy sources.

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As the climate protection policy will be subject of chapter 3.4 and the technology will be subject of chapter 4 in this chapter the impacts of nuclear and renewable energy policies are discussed.

3.3.1 General Situation (93) The Environment Council, under the German Presidency, adopted ambitious climate protection goals up to 2020 and an EU negotiation package for a post-2012 climate protection agreement. Until a new agreement is concluded, and without prejudice to its position in international negotiations, the EU will reduce its emissions by at least 20% by 2020 compared with 1990. (94) Furthermore the EU heads of state and government adopted a Climate and Energy Action Plan, which set a binding target of a 20% share of renewables relating to the total energy comsumption and a 20% increase in energy efficiency up to 2020. (95) The member states of the European Union are increasingly dependent on oil and natural gas imports, as was highlighted in the Commission’s Green Paper on Security of Energy Supply (2000). The European Union now imports 50% of its energy needs. Around 2030, this figure is forecast to rise to 70% with an increasing share for fossil fuels. This situation was regarded as making the Union “particularly vulnerable economically, politically and with regard to the environment” [EC 2001] . (96) Because of this situation the Final Report on the Green Pa- per on Energy [EC 2005] stresses the priority of supply security in European energy policies. As a result, European energy policies focus on curbing energy demand, controlling external supplies, diversi- fying energy sources and the establishment of liberalized and competitive energy markets. The EU renewables policy is part of the diversification target. However, coal also plays a major role in the con- siderations of the EU Commission. The report stresses the significance of coal in electricity generation and of coal mining as an option for European supply security. (97) The various EU states have widely different starting positions in terms of resource availability and energy policy stipulations. France and Finland, for example, are heavy backers of nuclear energy. The UK and the Netherlands have gas deposits, although output reduc- tions are foreseeable. In Germany, lignite offers a competitive founda- tion for baseload power generation although hard coal from German deposits is not internationally competitive. In Austria, hydropower is the dominating energy source for generating power, though potentials for expansion are limited. The use of other renewable energy sources is often only feasible if subsidised.

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3.3.2 Nuclear Energy Policy

3.3.2.1 Nuclear Energy in General (98) By the end of 2005 there have been 443 nuclear reactor blocks in 31 states worldwide. Installed capacity was about 370 GW total, the share of power generation at one sixth (16%) [NEA 2007] . (99) The European commission sees nuclear power to play an important role in the European Union's energy mix, provided that, at the same time, issues surrounding safety and security will be ad- dressed appropriately [EComm 07/10] . European Policy explicitly regards the nuclear power technology as a future technology option, as pointed out by the European Council’s conclusion on Energy policy for Europe [ECounc 070215] , leaving each member state to decide whether to use nuclear power. (100) The use of nuclear energy is highly dependent on political support. Without any decisive political commitment no private investor would be able to handle the sensitive infrastructural logistics, approval procedure, risk management and complex fuel cycle and waste management. NOTE This study does not include a detailed assessment of all political, technical, economical, social details on the use of nuclear energy regarding the issues of safety, waste cycle/disposal and proliferation risks. The use of nuclear energy is simplified to the political and economic dimension : Political Dimension: The complex questions of social acceptance, technological handling, waste management cycles and proliferation risks are reduced to the single political dimension, simplified to " yes" or "no", in other words: political active support in favour of or political active refusal of the use of nuclear energy.

(101) In the FRC model the use of nuclear energy has been modelled country wise with a detailed assessment of the nuclear policies. For all scenarios the use of nuclear power has been restricted to the framework as described below (cp. chapter 3.3.2.2). The political viable path include the political restrictions of phase-out (Italy, Ger- many, Belgium, Sweden, Spain, Netherlands) and the political inten- tions for new nuclear sites (France, Finland, United Kingdom, Lithua- nia, Bulgaria, Czech Republic). An additional nuclear power block beyond this (political probable) path is not permitted. (102) Only for the TECH and the POL45 Scenario the following ad- justments have been made: • POL45: the introduction of the new EPR type reactor is allowed (no restriction in any region, e. g. no phase-out in Germany), but not financially supported. Nuclear power plants will be commissioned as far they appear economically competitive. • TECH: the introduction of the new EPR type reactor is promoted politically

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3.3.2.2 Nuclear Energy Country Survey (103) In the European Union, there are 15 member states operating about 150 (commercial) nuclear power blocks: • In France and Lithuania there is a "high" nuclear generation share with more than 70% nuclear power generation, • In 11 member states there is a "medium" share between 20 and 60%, represented by Belgium, Sweden, Slovakia, Bulgaria, Slovenia, United Kingdom, Spain, Finland, Czech Republic, Hungary and Germany. • A low nuclear energy share (lower than 15%) can be found in the Netherlands and Romania. (104) BE: Belgium is operating 7 nuclear power plants (PWR type). In 2003 the phase-out of nuclear energy was decided by stipu- lating that all 7 Belgian nuclear power plants must be shut down no later than 40 years from the date on which they entered operation [NEA 2007]. (105) BG: At short hand, before the accession to the EU (31.12.2006) and in spite of the governments protest Bulgaria was forced to stop operation in two blocks at the site of Kosloduj (Da- nube). New (Russian type) blocks (2’000 MW) are planned at the site of Belene, close to the border of Romania. (106) CZ: In the Czech Republic, there are four units operating at the Dukovany (EDU-Elektrárna Dukovany) nuclear power plant. The units are Russian WWER 440/V213 type PWRs with a total installed power of 1’760 MW(e). The construction of the Temelin nuclear power plant (two units with WWER 1000/V320 type with a total installed power of 2’000 MW(e)) has been completed; the Temelin nuclear power plant is currently the largest power resource in the Czech Republic [NEA 2007]. State Energy Policy (Czech Ministry of Trade and Industry) is considering new nuclear power capacities (1'200 MW) about 2020 [SEP according FRC protocol 061207]. (107) DE: Germany intends to phase out nuclear energy gradually. According to the binding agreement between the government and the electricity producers on phasing out nuclear energy, generation from nuclear power plants will decline from 160 TWh in 2’000 to 152 TWh in 2005 and 133 TWh in 2010. In 2020 nuclear power generation will be at 46 TWh and will eventually cease by 2025, at the latest. The agreement is under discussion. The actual government announced to keep to this agreement, leaving the discussion for the following government (to be expected after 2009). (108) ES: Nuclear power capacity is 7.6 GW. The current Spanish government has uttered the intention to phase out nuclear power. There is no specific plan for the phase-out. Jose Cabrera 1 (Zorita) (142 MW(e), PWR, Spain) was shutdown on 30 April 2006 [IAEA 2007] (109) FI Finland's four nuclear power plant units (Lovisa I+II, Olkiluoto I+II) have a total net capacity of 2’656 MW(e). Both companies have invested a lot to keep the annual outages as short as pos-

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sible. The government made a decision-in-principle on the construction of a new nuclear power plant unit in 2002. The operator TVO chose the plant site Olkiluoto in October 2003. The Finnish government granted TVO a construction license and the construction of the reactor building started in August 2005. After granting the operating licence, the commissioning of the plant is unlikely to take place before 2010. There have been several delays in the project due to quality deficiencies in some heavy components manufacturing processes and building concrete deliveries [NEA 2007] . (110) FR: Along with the decreasing domestic coal production France has replaced most of its coal-fired power plants by nuclear power plants. France possesses 59 nuclear power plants, which form the second largest integrated system of nuclear power plants in the world. Nuclear energy accounted for 78.3% of total electricity production in 2004. France’s annual nuclear power generation has increased by about 40% since the beginning of the 1990s, while annual generation from other sources has not greatly changed during that period [CSFL 2005]. Although the government pursues the aim of promoting renewables, nuclear energy is the crucial energy source for power generation for the future. (111) HU Hungary has only one nuclear power plant in operation with four WWER reactors. The plant runs in base load and sells electricity to Magyar Villamos Müvek (MVM) under a long-term con- tract. The average load factor has remained fairly constant for several years [NEA 2007]. Paks is expected to cease operation in 2020. It seems to be politically intended to replace it by a new (EPR type?) reactor, possibly even before 2020 [FAZ 2007], but so far the social- political acceptance is hardly predictable . (112) IT: Italy phased out nuclear power abruptly in 1987 subsequently to the Czernobyl catastrophe. The four functioning nuclear power plants at that time have been dismantled. (113) NL: The Netherlands operated two nuclear power plants at Borssele and Dodewaard which were mainly used for research purposes. The unit in Dodewaard has been closed. Borssele was to be shut down in 2003 but the government decided to keep it operating in order to comply with its targets to reduce GHG emissions. Op- erating time has been extended to 2033. Even though The Nether- lands disposes of a sufficient amount of generating capacity it might well be affected by the generation capacities of its neighbouring countries. As Belgium and Germany plan to phase out nuclear energy, the amount of imported electricity might decrease in the future. (114) SK In Slovakia there are currently 5 nuclear reactors under operation at the sites of Bohunice and Mochovce, representing a nuclear capacity of 2’064 MW. Bohunice 1 (408 MWel, PWR- WWER) was shutdown on 31 December 2006 [IAEA 2007] as a pre- condition for Slovak entry into the EU in 2004, Bohunice 2 is to be shut by 2008 latest. In January 2006 the government approved a new energy strategy with capacity uprate of 44 MWel gross at Mochovce 1 & 2 in 2007 and a further 18 MWel by 2012, and a 120 MWel gross uprate of Bohunice 3 & 4 by 2010 [IAEA 2007] .

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(115) UK: The nuclear power industry has been privatized. The government’s nuclear policy focuses on the decommissioning of nuclear sites belonging to the public sector. Dungeness A 1&2 (2x 225 MWel, GCR-Magnox) and Sizewell A 1&2 (2x 210 MWel, GCR- Magnox) were shutdown on 31 December 2006 [IAEA 2007]. The decommissioning of Hunterston B and Hinkelby B has been announced by the operator British Energy. If the remaining operation times are confirmed it can be expected that 11 NPP will be decommissioned until 2020 (leaving another 3 NPP in operation after 2020. On the other hand the British government announced, that replacement of these capacities would be welcome, generally leaving the investment decision to the (private) power sector.

3.3.3 Renewable Energy Policy (116) The European Commission regards renewable energy sources as one attractive option towards energy diversification. The importance of renewable energy sources have been stressed in the European commissions memo A Renewable Energy Roadmap: paving the way towards a 20% share of renewables in the EU's energy mix by 2020 [EComm 07/13]. (117) Renewable generation (must-run): For renewable energy sources the maximised earning logics (as modelled in FRC capacity decision) and the marginal cost logics (as modelled in FRC merit order) do not apply. For this reason the renewable energy share is given as external input for the model period (e. g. linear growth from actual share until a projected share in 2030). The renewable capacities slices are evenly dispersed throughout the merit order and thus are present throughout each time of the year. (118) Electricity generation from renewable energy sources other than hydroelectricity continues fast-paced growth among the countries of (especially) Western Europe. The governments in the region offer support for non-hydropower renewable power sources, most notably wind, in the form of subsidies or requirements that utilities pur- chase a certain amount of power from “green” energy sources. Ger- many, Spain and Denmark remain the fastest growing wind producers in the world, and the United Kingdom, Ireland and Portugal all are experiencing a surge in installed wind capacity. (119) The European Commission (DG TREN) launched a directive to establish a framework to increase the share of renewables in electricity generation from 14% to 22% by 2010. The directive obliges member states to set indicative national targets for the contribution of renewable energies, which should be met by 2010. It is probable that the overall target will be missed (the commission expects 19% by 2010), thus leaving the member states to introduce additional measures. (120) The national objectives are listed in table 3.3-1(highlighted in yellow). A linear forecast is simply based on the linear projection from the reference year (1997), the normalised actual survey (2004/2005)

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to the objective year (2010). It has to be kept in mind that the linear projection is just a rough 1 st order estimate. Most member states are experiencing a positive growth dynamic during the last two years - in these cases the linear forecast may indicate too low figures. In few countries a slow down of growth can be expected (Germany, Den- mark) due to the high growth rate during the last ten years - the linear forecast may indicate too high figures. (121) In its memo " EU almost on track in reaching its 2010 renewable electricity target [EComm 07/13]", the commission announced that the renewable energy target of 21% will be missed, readjusting the forecast to 19% by 2010, "although considerable growth has been achieved" throughout the EU, especially by increased use of wind and biomasses. A revision of the member states support schemes and a new legal framework and support scheme for RES is announced [EComm 07/13] .

Reference Normalised Linear RES Linear Target Year Penetration Forecast Objektiv by Miss Achievement 1997 or 2000 2004/2005 95/05/10 2010 Obj. Lin. 2010 % REF % 2005 % 2010 Lin. % 2010 Obj. % 2010 Miss Lin./Obj. Hungary 0.7 4.0 6.1 3.6 -2.5 169% Denmark 8.7 27.3 38.9 29.0 -9.9 134% Germany 4.5 10.8 14.7 12.5 -2.2 118% The Netherlands 3.5 6.5 8.4 9.0 0.6 93% Luxembourg 2.1 4.0 5.2 5.7 0.5 91% Latvia 42.4 43.9 44.8 49.3 4.5 91% Sweden 49.1 52.0 53.8 60.0 6.2 90% Slovenia 29.9 29.4 29.1 33.6 4.5 87% Finland 24.7 25.4 25.8 31.5 5.7 82% Ireland 3.6 8.0 10.8 13.2 2.4 82% Spain 19.9 21.6 22.7 29.4 6.7 77% France 15.0 14.2 13.7 21.0 7.3 65% Italy 16.0 16.0 16.0 25.0 9.0 64% Austria 70.0 57.5 49.7 78.1 28.4 64% Portugal 38.5 28.8 22.7 39.0 16.3 58% United Kingdom 1.7 4.2 5.8 10.0 4.2 58% Poland 1.6 3.2 4.2 7.5 3.3 56% Czech Republic 3.8 4.0 4.1 8.0 3.9 51% Lithuania 3.3 3.3 3.3 7.0 3.7 47% Slovak Republic 17.9 14.9 13.0 31.0 18.0 42% Belgium 1.1 1.9 2.4 6.0 3.6 40% Greece 8.6 7.7 7.1 20.1 13.0 35% Estonia 0.2 0.7 1.0 5.1 4.1 20% Malta 5.0 Cyprus 6.0 EU25 12.9 14.5 15.5 21.0 5.5 74% table 3.3-1 RES-E objectives (2010), actual status (2005) and linear forecast (2010). [source: EComm 2004] (122) However for some regions the take off is somewhat slower than expected and targeted an increasing importance of off-shore windpower can be expected: In 2003, Ireland’s Airtricity began instal-

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lation of the first phase of the 25.2-megawatt Arklow wind farm. The $59 million project, located 6.3 miles off Ireland’s east coast. consists of seven 3.6-megawatt turbines. Airtricity has proposed to eventually expand the site to up to 200 turbines, making it the largest offshore wind project in the world 4.

3.3.3.1 Renewable Energy Country Survey (123) [Survey is sorted by the order in table 3.3-1] (124) EU The European Union set a binding target of a 20% share of renewables relating to the total energy comsumption up to 2020. (125) HU Hungary has made the biggest progress of all EU- 10 states and already exceeds its 2010 target (3.6%) in 2005 (4.0%). (126) DE Germany has made a significant increase with the introduction of its renewable energy feed-in tariffs, which provide guaranteed tariffs for renewables. The share of renewables has been rising continuously, recently breaking the 10% share in electricity generation (60 TWh). (127) DK Denmark is well on track by having systematically exploited its wind energy potential, although at the end of 2001 fun- damental changes have been made to existing energy policies and targets. Most of the favourable promotion schemes for RES have been abolished. The introduction of a green certificate market has been announced but has not been implemented so far. Except for two offshore wind parks, which were already in an advanced planning phase, the strong RES development observed in the 90’s has been slowing down. (128) NL The Netherlands are pursuing a diversified policy in order to promote renewable energies: several measures haven been applied, such as eco-taxes and fixed feed-in-tariffs. (129) SE Sweden : Wind capacity installed in Sweden is relatively low although the wind resource in the south of the country is comparable to Denmark’s. When the new certificate scheme was drawn up by the Government, market parties expressed fear and re- luctance to invest. (130) ES Spain is well promoting electricity generation by renewable energy sources by fixed tariffs. Wind power is on the rise. The government launched a national plan, in order to increase the share of renewables in electricity generation to almost 30% (from an actual level at 25% coming from wind and hydro).

4 Construction was commenced in summer 2003 and finished in autumn. Production started at the beginning of 2004. Located around 10 km off the coast of Arklow, Ireland, the project's seven GE 3.6 MW wind turbines are the world's first commercial application of offshore wind turbines over three megawatts in size.

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(131) FR The French government promotes renewable energies by feed-in-tariffs and sets a major focus on the development of wind energy, thus France making (together with Spain) one of the most attractive market for wind power installations. (132) IT Italy has established a quota system, which will be completed by a more market orientated system of green certificates. However no significant increase has been achieved during 2000-2005 period. (133) UK In United Kingdom , there is a renewable obligation for electricity supply, which was revised in April 2004 and setting the renewable obligation from 10% to 15%, including the possibility of biomass-co-firing. There is a renewable levy, which electricity end consumers are charged with each kWh. The share of renewables is still below the EU 25 average but a significant increase can be expected with the commissioning of large off-shore potential. (134) PL Poland requires that electric utilities maintain a renewable energy portfolio of at least 2.4 percent in 2001 (2.5% in 2002; 2.65% in 2003, etc., 7.5% in 2010 and in the following years) and has established a target of 7.5% of primary energy production from renewable sources by 2010 and 14% by 2020. However, these targets have not yet been enforced, discouraging large scale renewable development. The key resource for achieving the target is likely to be biomass, mainly forestry and agricultural residues and energy crops [EComm 2004] . (135) CZ The significant excess of generated electricity of around 27’000 GWh/year with the full commissioning of the Temelin Nuclear Power Plant is regarded as a major barrier for renewable electricity development for at least another decade in the Czech Re- public. Poor reputation of wind energy is partly caused by premature sales of prototypes to clients. Biomass and hydro are far the most utilised renewables. Geothermal is mainly utilised for balneological and swimming purposes [EComm 2004] (136) GR Renewable energies in Greece are promoted by a feed-in tariff and promotion programs. The share of renewables in electricity is comparable low. (137) PT Portugal has experienced a loss in renewable energy share due to its high hydro power share. The analysis of the Por- tuguese target must take into account the important variability of large hydro power plants. Grid capacity problems hamper a larger uptake of renewable electricity in some Portuguese regions. Complex and slow licensing procedures have resulted in long lead times for new renewable installations. In the recently approved energy policy, the Portuguese Government has set goals for the development of RES, giving special attention to wind power (with an expected capacity of 3’750 MW by 2010) and small hydro (400 MW). For the implementation of the guarantee of origin the grid operator REN is designated as the issuing body [EComm 2004] . (138) AT The linear forecast in table 3.3-1 is misleading due to the volatile high large hydro share. The production of renewable

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energies in Austria is dominated by large hydropower and biomass for heat generation. There is wide variety of policy measures for the support of renewable energies in Austria not only at the federal level but also at the provincial level. The feed-in tariffs introduced in Janu- ary 2003 represent the major modification of the Austrian RES policy. These tariffs included in the Renewable Energy Act are expected to stimulate significant growth especially for wind, biomass electricity and small hydro power. [EComm 2004] .

3.3.4 The Role of CHP (139) CHP generation (base-run): For CHP capacities the maximised earning logics (underlying the FRC capacity decision) and the marginal cost logics (underlying the FRC merit order) do not apply. The CHP capacities slices are assumed to be present in the base load during the heating period. For this reason the CHP share is given as external input for the model period (e. g. a probable development from actual share until a projected share in 2030). The shares are not identic but adapted at the order of size at EU trend to 2030.

Share of CHP in Power Generation (%) 2005 2010 2015 2020 2025 2030 Germany 12 14 16 20 20 20 United Kingdom 6 6 7 9 9 10 Spain 21 21 25 25 25 25 Greece 5 8 8 10 10 10 France 6 8 8 9 9 10 Italy 21 20 19 18 17 18 Netherlands 52 54 54 55 55 55 EU15 Others 15 17 18 20 20 20 Poland 18 19 20 20 20 20 Hungary 26 24 25 21 21 22 Czech Republic 29 28 30 30 30 30 EU10 Others 25 25 25 25 52 25 Bulgaria 16 26 25 25 25 25 Romania 37 40 40 40 40 40 table 3.3-2 Share of CHP in electricity generation [source: DG TREN/NTUA 2006, adaption by Prognos]

3.4 Climate Protection Policy (140) The Environment Council adopted ambitious climate protection goals up to 2020 and an EU negotiation package for a post-2012 climate protection agreement. Until a new agreement is concluded,

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and without prejudice to its position in international negotiations, the EU will reduce its emissions by at least 20% by 2020 compared with 1990.

Public Electricity and Heat Production Carbon Emissions (Mt) 1990 2004 Change EU27* 1465 1366 -7% EU15 950 1011 6% Germany 336 334 -1% United Kingdom 205 171 -16% Spain 64 100 55% Greece 41 54 33% France 48 43 -10% Italy 107 123 14% Netherlands 40 54 35% Austria 11 13 19% Belgium 23 24 3% Denmark 25 23 -8% Finland 16 29 78% Ireland 11 15 36% Luxembourg 1.3 0.4 -70% Portugal 14 19 36% Sweden 8 9 22% EU10* + BG + RO 515 356 -31% Poland 239 172 -28% Hungary 20 19 -6% Czech Republic 54 55 3% Slovenia 6 6 5% Estonia 29 13 -57% Lithuania 12 4 -69% Latvia 9 2 -76% Slovakia 14 9 -40% Bulgaria 38 27 -29% Romania 94 48 -49% *without Malta and Cyprus table 3.4-1 Carbon Emissions of Public Electricity and Heat Production [source UNFCCC 2007]5

(141) Without new policies global energy-related CO 2 emissions are expected to increase very rapidly. In the WEO reference scenario CO 2 emissions increase from 24.5 Gt in 2003 to 37,4 Gt in 2030 [IEA 2005] . In the ETP Baseline scenario the growth in CO 2 emissions

5 The figures show emissions from power and heat production of the public sector as defined by UNFCCC. They compare well with FRC results but do not refer to the same statistical basis. Statstical deviations may occur from small power plants (<30 MW), heat production in cogeneration and power generation in the industrial sector.

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continues through 2050, reaching 58 Gt CO 2, which is 2,4 times higher than 2003. (142) Table 3.4-1 shows the carbon emissions of public electricity and head production in Europe. Carbon emissions have been decreasing in Europe since 1990, caused mainly by the strong reduction in the new memberstates (EU 10, Bulgaria, Romania). By contrast the carbon emissions in the EU15 increased by 6% from 1990 compared to 2004. (143) Due to the increasing climate impact of anthropogenous greenhouse gases, carbon dioxide emissions have been increasingly focused by policy during the last decade. At the 1997 Kyoto confer- ence, the EU as a whole agreed to reduce its greenhouse gas emissions by 8% compared to 1990 levels by the 2008-2012 time frames [CSFL 2005]. (144) Among others the European member states agreed on the implementation of an European Emissions Trading Scheme (ETS) aiming to limit and reduce the emissions of the industrial and the energy sector. For that purpose national emission caps have been de- finded. The European Union is about to start the second commitment period (2008-2012), the first full allocation and trading period. For this purpose national allocation plans (NAPs) have been submitted. So far, the majority of NAPs have not been approved by the European commission. (145) The first commitment period showed that allocation was diverse throughout the member states (MS) of the EU. The allocation rule has different impacts on the carbon cost and hence the decision of an individual participant in the power market: • MARGINAL COST: Carbon costs are introduced as opportunity cost in the marginal cost calculation as additional variable cost, dependent on specific emissions of power production. (100% cost effective). • FULL COST: Carbon costs are introduced as full cost (if the certificates are auctioned or have to be purchased), unless the EUAs are provided for free (grandfathered). This might be limited to a certain share of the needed EUAs, if the EUAs are allocated by benchmark rules. The rest of the needed EUAs have to be purchased by usual market mechanisms (EUA exchange, OTC, auctioning, JI/CDM) at usual market prices. (part cost effective). (146) In FRC model the carbon costs are introduced as a full cost share, representing the auctioning share . Unless not otherwise indicated, this share is chosen as following: • Grandfathering (=0%, full free allocation) for the first allocation period (2005-2007). • Hard coal benchmark for coal fired plants. • Gas benchmark for gas fired plants. • Exception UK : gas benchmark for all plants.

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• Powerplants with CCS technology get the same amount of EUAs as powerplants without CCS in the Tech 30. In the other scenarios CCS powerplants get EUAs amounting to their carbon emissions. • For each technology the auctioning share is linearly increasing up to 100% by 2030. Example : Lignite (hard coal benchmark): − 2008 22% auctioning share, 2009 26% auctioning share, 2010 30% auctioning share, ... etc... 2030: 100% auctioning share. • The share may be chosen regionally individually, as specific allocation rules apply (example: gas benchmark in UK). (147) The implication of the climate protection policies is modelled by the carbon price (compare chapter 3.3.1), with increasing carbon price level representing the increasing pressure of the climate protection policy.

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3.5 Carbon Prices

Summary Since the start of the European Trading Scheme (ETS), carbon prices went up to a level of more than 30 €/t until April 2006 and since then decreased to 1 €/t. After all, EUA markets cannot yet be considered as mature. For the time being an outlook cannot be seriously made, as the NAP 2 is still under discussion. For the FRC model the carbon price level is fully considered in the marginal cost calculation and partly considered in the full cost calculation. (148) After settling into a narrower 20-25 €/t range from the start of the first allocation period until April 2006 (cp. figure 3.5-1), EUA price fell at the end of April from an all-time high of 30,50 €/t to 9€/t within one week. This sharp decrease was initiated by an EC announce- ment, that companies have been emitting 2.5% less than the allocated cap for the 05-07 period [tams 06, eceee 05] (149)

figure 3.5-1 Carbon Prices and traded volume, first year of ETS [EEX spot price Chart 0702]

(150) In the meantime (status: 15 February 07) the EUA price has been further decreasing to 1€/t, much more meeting expert model

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expectations at the beginning of the allocation period (compare FRC report part 1 [prognos 2006, MIT 2005].

figure 3.5-2 Carbon prices [€/t] and traded volume [EUA/day], 03/2006-03/2007 [EEX spot price Chart 0702]

(151) The Futures markets for carbon allowances are - in a comparable manner - ruled by short-term incidents and uncertainties about the future development. Hence the futures market show similar (volatile) behaviour (cp. figure 3.5-2), but on a higher level for the last year of the second allocation period (2012), with EUA price expectation around 20 €/t. The forecast however remains difficult, as the European Commission is still negotiating the submitted NAPs for the second allocation period. (152) The carbon price is introduced as an exogenous parameter. Due to the above mentioned uncertainties and in order to show the impact of allocation the FRC study is assuming several carbon prices, which are kept constant during the whole forecast period. Lower carbon prices are representing a moderate climate protection policy which is likely to bring a moderate allocation, while higher carbon prices are representing an enforced climate protection policy with an aggravated allocation.

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These policies are represented by various carbon price levels: • BASE Scenario at 5 €/t constant • LOW PRICE Scenario at 15 €/t constant • POLICY 15 Scenario at 15 €/t constant • POLICY 30 Scenario at 30 €/t constant • POLICY 45 Scenario at 45 €/t constant • TECH 30 Scenario at 30€/t constant, with accelerated technological progress • TECH 45 Scenario at 45 €/t constant, with regulatory introduction of CCS technologies.

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4 FRC Technology Platform

Summary New power plant technologies yield a high primary and CO 2-reduction potential as average efficiencies of existing power plants are far below the potential efficiencies of new modern power plants. This becomes even more important as modern power plant technologies are immediately available and mitigation potential can be realised at short term . A large mid-term mitigation potential (time horizon: not before 2020) can be expected by the large scale implementation of carbon capture and storage technologies (CCS) which might be combined with modern power plant technologies. Because of the high CO2 removal rates (85-95%) CO2 reduction potential is high, while energy efficiency is lower due to efficiency losses and energy input for CO2 sequestration, transport and storage. For the FRC study an intensive technology assessment has been carried out and discussed with several experts. This assessment aimed above all at the implementation of carbon capture & storage technologies (CCS).

4.1 Power Plant Technologies

(153) New power plant technologies yield a high primary and CO 2- reduction potential as average efficiencies of existing power plants are far below the potential efficiencies of new modern power plants. This becomes even more important as modern power plant technologies are immediately available and mitigation potential can be realised at short term . (154) A large mid-term mitigation potential (time horizon: 2020) can be expected by the large scale implementation of carbon capture and storage technologies (CCS) which might be combined with modern coal and gas power plant technologies. Because of the high CO 2 removal rates (85-95%) CO 2 reduction potential is high, while energy efficiency is lower due to efficiency losses and energy input for CO 2 sequestration, transport and storage.

4.1.1 Natural Gas Combined Cycle (NGCC) (155) Natural gas-fired combined cycle power plants (NGCC) are well developed and commercially available. In this combined cycle process gas is combusted and fed into a gas turbine. The flue gas is fed into a boiler in which steam is heated that drives a steam turbine. (156) Natural gas combined cycle yields a high efficiency by com- bining a conventional steam process with a gas turbine process. Modern NGCC power plants are available at a net efficiency of 58%

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and comparable low prices (400 €/kW). Net efficiencies of 65% can be expected in 2030. Due to its low emissions reduction equipment and low specific investment cost the technology can be employed in comparatively units with small capacities and hence is well suited for the use in CHP units. The units are flexible with a good capability for cycling operation.

600 70.0%

60.0% 56% 58.0% 60.0% 500 65.0% 53.0% 61.5% 62.5% 63.5% 420 420 400 400 400 400 400 400 50.0% 400

40.0% 300 30.0%

200 20.0% Efficiency in(net) % CostCapacity of (€/ kWel) 100 10.0%

0 0.0% 1995 2000 2005 2010 2015 2020 2025 2030

Cost of Capacity (€/ kWel) Net Efficiency figure 4.1-1 Development of NGCC efficiency and cost [prognos, FRC working group 2006]

(157) Fuel cost account for 60 to 85% of total generation cost and have a much higher share than coal power plant technologies. This is why NGCC are much more sensitive to fuel cost. A significant global increase at gas power plants would immediately lead to higher gas prices and could significantly undermine the economics of NGCC [IEA 2006, compare chapter 6.1.3] (158) The variable operation costs are assumed at 0.7 €/MWh and the fix operation cost (maintenance, staff, insurance) are assumed with an annual fee at 20 €/kW.

4.1.2 Nuclear Power Plants (159) From the perspective of direct commercial economics, existing nuclear plants are generally in a sound economic position. Nu- clear power’s cost structure makes it well-suited for baseload power generation, since it has a high fraction of fixed construction cost and a low share of variable operating cost [IEA (2001a)]. It has to be kept in mind that cost structures are highly dependent on the type of nuclear reactor and may also differ considerably among different countries.

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NOTE This study does not include a detailed assessment of all political, social, technical and economical details on the use of nuclear energy. The use of nuclear energy is simplified to its political and economic dimension: Economic Dimension: The question of the cost structure (capital cost, fuel cost, variable and fix operaton cost, internal and external cost for risks) of different nuclear reactor types is reduced to a single typ of nuclear reactor, represented by the EPR, calculated by one internal cost structure, without any regional differences.

2,000 45.0% 1,800 1,800 1,800 1,800 1,800 1,800 1,800 1,800 1,800 37.0% 37.0% 37.3% 37.5% 40.0% 1,600 37.0% 37.0% 35.0% 36.0% 35.0% 1,400 30.0% 1,200 25.0% 1,000 20.0% 800

15.0% Efficiency in(net) % 600

CostCapacity of (€/kWel) Assumption : 10.0% 400 one type of reactor will be realised for a longer time period (EPR) 200 costs for decommissioning are part of fixed operation costs 5.0% (20 €/kW a) 0 0.0% 1995 2000 2005 2010 2015 2020 2025 2030

Cost of Capacity (€/ kWel) Net Efficiency figure 4.1-2 Development of nuclear power plant efficiency and investment cost [prognos, FRC working group 2006] Base year?? The development of net efficiency and investment cost of nuclear power plants are displayed in figure 4.1-2. (160) The variable operation costs are assumed to 2 €/MWh and the fix operation cost (maintenance, staff, insurance) are assumed with an annual fee at 58 €/kW and additional annual cost for decommissioning at 20 €/kW.

4.1.3 Pulverised Coal-Fired Steam Cycle (PC) (161) The pulverized coal-fired steam cycle is the most commonly used technology for coal-fired power plants in the world. About 90% of all coal-fired power plants use this technology. The technology has been developed constantly reaching higher efficiencies and extremely high reliability. (162) In a PC, coal is pulverized and blown with combustion air into the boiler through burner nozzles. Combustion within the boiler takes place at temperatures of 1’300-1’700°C. The heat feeds a

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steam generator powering a steam turbine. Pressure and heat are re- lieved in the turbine. Steam temperatures reach 500-620°C. (163) PCs can be classified into the following categories [Lako 2004] : − Subcritical − Supercritical − Advanced supercritical − Ultra-supercritical (164) This classification is based on the live steam pressure of the live steam temperature within the steam cycle. The higher the temperature and steam in the cycle, the higher the efficiency of the power plant. The classification is shown in table 4.1-1. (165) Ultra-supercritical coal-fired power plants are being developed and only exist as demonstration projects. A biomass ultra- supercritical power plant has been realized in the multi-fuel power plant in Avedore, Denmark [www.power-technology.com] . Due to the high temperatures, alloys have to be developed preventing corrosion. The introduction of advanced ferritic steels has made advanced and ultra-supercritical steam conditions possible in state-of-the-art power plants. If conditions above 700°C and 37MPa are to be reached, nickel-based super alloys will have to be developed. This may increase efficiencies above 50% [Lako 2004] .

Advanced Su- Ultra Super- Category Unit Subcritical Supercritical percritical critical Year <1990 1990 1995-2000 >2000 Live Steam Pressure [MPa] 16.5 ≥22.1 27.5-30 ≥30 Live Steam Temperature [°C] 540 540-560 560-600 ≥600 Reheat Steam Temperature [°C] No reheat 560 580 ≥600 Single Reheat No Yes Yes Yes Double Reheat No No No Yes Generating Efficiency [%] ~38 ~41 ~44 46+ table 4.1-1 classification of pulverised coal-fired power plant technologies (efficiencies for hard coal) [ Source: Lako (2004)] (166) Efficiencies of modern PCs are at about 46% for hard coal and 44% for lignite-fired power plants [Lako 2004] .The average net efficiency of PCs in Germany is at 38% [BEI 2004] . Projected development of cost and net efficiencies including projections through 2030 can be seen from figures figure 4.1-3 and figure 4.1-4

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1,200 60.0% 52.0% 50.5% 51.5% 48.0% 1,000 46.0% 46.5% 47.0% 50.0% 925 900 900 900 860 860 860 880 45.3% 800 40.0%

600 30.0%

400 20.0% Efficiency in (net)% CostCapacity of (€/ kWel)

200 Assumption : gain on production efficiency after 2005 are of the 10.0% same order as cost increases due to technological progress

0 0.0% 1995 2000 2005 2010 2015 2020 2025 2030 Cost of Capacity (€/ kWel) Net Efficiency figure 4.1-3 development of HC pulverised coal efficiency and cost [prognos, FRC working group 2006] (167) The variable operation cost for modern hard coal power plants are assumed at 1.0 €/MWh and the fix operation cost (maintenance, staff, insurance) are assumed with an annual fee at 24 €/kW.

1,200 60.0% 1,075 1,000 1,000 1,000 1,000 975 950 950 975 50.0% 48.5% 49.5% 50.5% 45.5% 43.0% 43.5% 44.0% 800 42.0% 40.0%

600 30.0%

400 20.0% Efficiency in(net) % Cost of Capacity (€/kWel)

200 10.0%

0 0.0% 1995 2000 2005 2010 2015 2020 2025 2030 Cost of Capacity (€/ kWel) Net Efficiency figure 4.1-4 development of lignite pulverised coal efficiency and cost [prognos, FRC working group 2006] (168) The variable operation cost for modern lignite power plants are assumed at 1.2 €/MWh and the fix operation cost (maintenance, staff, insurance) are assumed with an annual fee at 27 €/kW.

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4.1.4 Integrated Coal Gasification Combined Cycle (IGCC) (169) IGCC technology was initially demonstrated in the 1980s. Since then power plants with a capacity of about 4 GW el have been built worldwide. However, less than 1 GW el of the existing IGCCs are exclusively coal-fired [IPCC 2005] . During the 1990s IGCC technology passed through its critical stage of development [IEA CCC] and can now be considered a future technology for large combustion plants. (170) In IGCC power plants coal is gasified and fed into a reactor where it is combined with oxygen and water forming a synthetic gas (syngas) consisting of mainly hydrogen and carbonmonoxide. This syngas is produced at temperatures of 1’700°C. Subsequently this gas is cleaned especially of sulphur contents. (171) IGCC hard coal-fired power plants reach efficiencies of 45- 48% whereas lignite-fired IGCCs have an efficiency of about 42% [Lako 2004; Kirchner/Rits 2006; Ecofys 2004] . Until 2020, efficiencies of up to 52% are expected. (172) Due to the high differences in temperatures necessary for coal gasification and gas clean-up, large heat exchangers are needed. In order to save energy and capital cost, the development of a hot fuel gas clean-up procedure is vital for the further development of this technology.

4.1.5 Fluidised Bed Combustion (FBC) (173) There are two modes of operation of fluidized bed combustion: • Atmospheric fluidized bed combustion (AFBC) • Pressurized fluidized bed combustion (PFBC). (174) Atmospheric fluidized bed combustion is a mature technology that is widespread. Power is generated by a simple steam cycle. The boiler is operated at atmospheric pressure in a circulating or stationary fluidized bed. Temperatures reach 800-900°C. An AFBC power plant can be fed with different kinds of fuel, including low- quality fuels such as coal with high tar or high sulphur concentration [Decon 2003] . AFBC technology is limited to steam turbines at subcritical conditions. (175) The advantage of AFBC power plants in comparison to PC power plants lies in more beneficial environmental effects. Due to the lower combustion temperature, the concentration of NO x is reduced. Furthermore, a sorbent is directly injected into the boiler reducing SO 2 emissions dramatically. (176) There are about 300 units installed worldwide. The technology is well developed and commercially available [Decon 2003] . The technology works well for units up to 300 MW [RAE 2004] .

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(177) Efficiency of AFBC power plants is at about 38-40% and is expected to increase to up to 44% in the coming decades [Decon, 2003; Royal Academy of Engineering, 2004] . (178) Pressurized fluidized bed combustion (PFBC) is a comparatively new operation which has mainly been developed in the 1990s. PFBC power plants operate using a combined cycle. The plants are commercially available. All of the commercially available units use stationary fluidized bed combustion even though circulating fluidized bed combustion would be possible but without a combined cycle. (179) PFBC-powered plants comprise a combustor that is fed with coal, sorbent and hot gas cyclones. The boiler is pressurized at about 15 bar. The pressurized gas generated in the boiler is cleaned up and drives a gas turbine and heats seam in heat transfer tubes. This steam drives a gas turbine. Temperatures should not exceed 900°C in order to prevent vaporizing of alkali metals and ash softening. (180) As AFBC technology, PFBC technology is used for smaller units at a scale of 80 to 350 MW [Decon 2003] . It has the same environmental advantages as AFBC technology. (181) The net efficiency of a commercially available PFBC power plant amounts to about 42%. Further development of the technology might produce efficiencies of up to 47%. However, PFBC technology is still considered to be in the demonstration phase. (182) Fluidized bed combustion technology is a technology used for smaller units. For carbon capture, the size of a power plant is of crucial importance concerning capital cost. Thus, economies of scale can not be realized sufficiently in these small units. Therefore, fluidized bed combustion is not taken into consideration when discussing the possibilities of carbon capture. (183) Moreover, PFBC power plants are not expected to be built on a large scale in the near future as gas turbine materials have advanced in a way that optimal expander inlet temperature exceeds the temperature that can be achieved by a PFBC boiler. This leads to a lack of efficiency compared to other investment alternatives. The efficiencies of FBC plants are relatively low.

4.1.6 Pressurized Pulverized Coal Combustion (PPCC) (184) PPCC units are fueled with hard coal. They drive a combined cycle process. Coal is pulverized and combusted under high pressure (above 16bar) and at high temperature (about 1’600°C). To prevent corrosion and erosion in the gas turbine, the flue gas has to be cleaned, especially of minerals, alkalis and liquid ash particles. There- fore, the flue gas is fed through a column of ceramic balls for liquid slag separation at a temperature of about 1’450°C. Additionally, the flue gas has to pass an alkali remover unit. The cleaned flue gas drives a gas turbine at less than 1’400°C. Afterwards the flue gas is fed into a heat recovery boiler which produces high-pressured steam to drive a gas turbine [Willenborg et al., 2002; Decon, 2003] .

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(185) The PPCC technology is a process which is in an early stage of development. No large units have been built so far. It is expected to generate high efficiencies (above 55%) [Decon, 2003] . However, the technology is not expected to be commercially available before 2020. (186) The main research efforts have been focussed on the flue gas clean-up [Förster w/o y. ]. The technology has not been tested in a large facility. Only pilot projects exist (below 1MW). It is unclear when and if PPCC technology will be available, because the required adaption of commercial gas turbines to the PPCC flue gas is not yet approached. Costs are unclear as well. It is also unclear when and if large units can be realized. Therefore, PPCC is not taken into consideration in this report.

4.1.7 Externally Fired Combined Cycle (EFCC) (187) The EFCC process is another technology which is at an early stage of development. It is a combined cycle process consisting of a hot air turbine and atmospheric firing. Hard coal is the fuel mostly used for this technology. The coal is burned for the purpose of atmospheric firing. The flue gases heat compressed air in a heat exchanger up to the temperature level necessary for the hot air turbine. Then the flue gases are cooled and fed into a heat recovery steam generator. The exhaust air from the hot air turbine serves as combustion air for the process of atmospheric firing. A high-temperature heat exchanger that has to withstand high pressure differences necessary for this technology has not been developed yet. (188) The net efficiency of EFCC power plants is unclear but estimated at 45-47%. (189) As not all parts for this technology exist yet, there are no demonstration units. Commercial availability is not expected before 2020. Capital cost and potential unit sizes are unclear. This technology is therefore not considered in this report.

4.2 Carbon Capture Technologies (190) Carbondioxide can be captured in fossil fuel-fired power plants before or after the combustion of the fossil fuel. In the former case, the term pre-combustion capture applies. The latter case is referred to as post-combustion capture. If carbondioxide is captured after the combustion but the fuel (i.e. coal or gas) is combusted with oxygen instead of air, the capture process is called oxyfuel combustion. (191) Therefore, three carbon capture technologies can be distin- guished: • Pre-combustion capture • Post-combustion capture

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• Oxyfuel combustion. (192) Even though it is possible combine each power plant technology with any carbon capture technology, certain combinations have turned out to be the most cost-effective and are therefore exclusively considered in this report. The possible combinations of technologies are: • IGCC with pre-combustion capture • PC with post-combustion capture • PC with oxyfuel combustion (193) Carbon capture in NGCCs can be applied in the most cost- effective way if post-combustion technology is used.

4.2.1 Pre-Combustion Capture

(194) This technology is applied in IGCC power plants. CO 2 capture can be conducted after the CO-shift is completed. A flowchart of an IGCC power plant with CO 2 capture is illustrated in figure 4.2-1.

figure 4.2-1 IGCC with Carbon Capture Flowchart (Source: IEA, 2005)

(195) CO 2 capture is usually conducted by means of physical solvent scrubbing. Mostly cold ethanol (rectisol process), dimthylether of polyethylene glycol (selexol process), propylene carbonate (fluor process) and sulpholane are used [Davison, Thambimuthu, 2004] . Among these processes, selexol is the most commonly used [cp. IPCC, 2005] .

(196) Physical solvents do not combine strongly with CO 2. The physical solvent is fed into a stripper where CO 2 is separated and caught by reducing the pressure in the stripper. (197) Carbon capture can also be conducted by means of adsorption. Solid materials such as zeolites or activated carbon are used as adsorbers. Three adsorption processes are possible: • Pressure swing adsorption • Temperature swing adsorption • Electric swing adsorption.

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(198) Among these processes pressure swing adsorption is the most adequate process to be applied in pre-combustion capture. The adsorbent is regenerated by reducing pressure (cp. selexol process). (199) As pressure swing adsorption, temperature swing adsorption is a mature industrial process. However, it is associated with higher capital cost and is more energy-intensive. The adsorbent is regenerated by raising temperature in the regenerator. (200) Electrical swing adsorption is not a mature process, yet. the regeneration is performed by passing a low-voltage electric current through the adsorbent.

(201) Finally, CO 2 can be captured by cooling and condensation of gases. This process is referred to as cryogenics. The advantage of this process is that it provides liquid CO 2 which can be easily transported. The cooling, however, is an energy-intensive and costly process. (202) Pre-combustion capture is a well-developed technology which is primarily applied in the chemical industry. Thus, the technology is commercially available. However, no large-scale IGCC power plant with pre-combustion capture technology has been built yet [IPCC 2005] .

4.2.2 Post-Combustion Capture (203) Post-combustion capture technology is usually applied in combination with PC power plants. CO 2 is captured by means of chemical solvent scrubbing from the flue gas. In case of very high carbon prices, this "end-of-pipe" technology may even be applied to existing power plants.

(204) In order to separate CO 2 from the power plant flue gases, an amine solution is used. Monoethanolamine (MEA) is the most commonly used absorbent. After the combustion process, the flue gas is cooled to 40-60°C and fed into an absorber column where it is bub- bled through the solvent. Then the flue gas goes through a water wash section and leaves the absorber. In a regenerator unit the CO2 is stripped from the absorbent at temperatures of 100-120° C. Heat is supplied to the regenerator (reboiler) in order to maintain regeneration conditions. In the stripper (regenerator) steam is produced which serves as a strippping gas. Steam is condensed and fed back to the stripper whereas the CO 2 product gas leaves the stripper. The "lean" solvent is pumped back to the absorber via a lean-rich heat exchanger and a cooler, where it is cooled to 40-65°C [Davison, Tham- bimuthu, 2004] . (205) Another promising approach for post-combustion separation might be the chilled ammonia process, which might reduce the efficiency losses of post-combustion removal. Several pilot plants are in preparation [Beurs 2007, EPRI 2006]

(206) The flowchart in figure 4.2-2 shows how CO 2 capture in a PC power plant is performed.

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(207) Post-combustion capture might be a very energy-intensive process. The energy penalty amounts to 10-12% [Meyer, 2004] . Stud- ies indicate a net efficiency (LHV) drop from 45% to 35% when MEA technology in new PC plants is used [IPCC 2005] .

figure 4.2-2 PC Power Plant with Post-Combustion Capture (Source: IEA, 2005)

(208) The technology is the most cost-effective way to capture CO 2 in NGCC power plants. For these plants net efficiency drops from 55- 58% (LHV) to 47-50% using MEA technology [IPCC 2005] . (209) Even though post-combustion capture can be considered the most mature technology for CO 2 capture, it still has a number of flaws. As large amounts of flue gas with a low CO 2 concentration have to be handled. Therefore, strong solvents have to be used in order to capture the CO 2. Furthermore, the high energy requirement causes a high energy penalty reducing the efficiency of the plant. (210) The technology is commercially available in a small scale. However, CO 2 capture using chemical solvent need more research to make it available in [IPCC 2005] .

4.2.3 Oxyfuel Combustion

(211) If oxyfuel combustion is applied, CO 2 is captured after the combustion of the fuel as in post combustion capture. Nevertheless, the technology is different since the combustion process is conducted with oxygen instead of air. The CO 2 concentration in the flue gas increases dramatically up to 80% instead of 4-14% depending on power plant technology and fuel used [Gupta et al. 2004] . (212) In an air separation unit (ASU), air is separated into oxygen and nitrogen. The oxygen is fed into a boiler with coal where the combustion process takes place. The flue gas consists of 95-98% CO 2. This gas is cleaned of O 2, NO x, SO x and argon leaving CO 2 and H2O. 70-80% of the flue gas is fed back into the boiler to control the combustion temperature. The combustion temperature with pure oxygen would reach up to 3’500°C. For coal boilers it has to be limited to 1’900°C [IPCC 2005] . Therefore, 70-80% of the flue gas is recycled back to the boiler to control the combustion temperature. The remaining steam of the fuel gas is condensed. By condensation CO 2 is separated from H 2O and SO 2. Then it is captured [Jordal et al., 2005].

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Chemical or physical solvent scrubbing is not applied. The flowchart in figure 4.2-3 displays this process.

figure 4.2-3 PC Power Plant with Oxyfuel Combustion (Source: IEA 2005)

(213) The energy penalty of the oxyfuel combustion process is about as high as with post-combustion capture. Efficiency may decrease by 8-10% [Meyer, 2004]. For a PC power plant, efficiency may drop from 44 to 35% and for a NGCC power plant from 58% to 45% [Dillon et al, 2004]. (214) Oxyfuel technologies for carbon capture have not been developed on a commercial scale, yet. There are some pilot plants using oxyfuel combustion. For example, Vattenfall is building a pilot plant at “Schwarze Pumpe”, Germany [Burchhardt, 2005]. Oxyfuel technology is used in metal and glass melting industries today. The separation of oxygen from air is a well developed technology [IPCC 2005] .

4.2.4 Cost Assumptions for CCS Technologies

(215) Capturing and compressing CO 2 requires much energy, significantly raising the operating cost of CCS-equipped power plants. In addition the investment required increases capital cost. The cost of storage and other system cost increase power production cost of by 40-80%. CCS costs are dominated by CO2-capture. Storage and transportation cost are relatively low. Table 4.2-1 shows the investment cost of power plants with CCS technology. Compared to an ap- propriate power plant without CCS the specific investment costs are 50% (Hard, Lignite) to 100% (Gas) higher. (216) To show the impacts of introduction of carbon capture and storage FRC study calculates both a scenario at a carbon price of 30 €/t [TECH 30] and a scenario of a carbon price of 45 €/t [TECH 45] . • the TECH 30 is following the idea of an "accelerated technological progress" : In deviation to other scenarios the cost degression is faster as assumed in table 4.2-1, so that specific investment costs are each 100 €/kW lower from 2020 on. Fur- thermore the cost for carbon transport and storage are reduced to 6€/t compared to 10€/t in the other scenarios (cp. chapter 4.2.5).

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• the TECH 45 is following the idea of an "regulatory introduction" :Cost degression is the same as shown in table 4.2-1. From 2020 on all types of conventional-thermal power need CCS equipment.

Future & Capture Technologies : Costs of Capacities [€/kW ] Time Horizon 2005 2010 2020 2030 Gas NGCC Post 1'200 1'140 1'020 900 Hard Coal IGCC Hard Coal 1'400 1'360 1'280 1'200 IGCC Pre Hard Coal 1'800 1'740 1'620 1'500 PC Post Hard Coal 1'700 1'650 1'550 1'400 PC Oxy Hard Coal 1'800 1'740 1'620 1'500 Lignite IGCC Lignite 1'500 1'460 1'380 1'300 IGCC Pre Lignite 1'900 1'840 1'720 1'600 PC Post Lignite 1'800 1'750 1'650 1'500 PC Oxy Lignite 1'900 1'840 1'720 1'600 table 4.2-1 Development of investment cost powerplants with CCS technology [prognos, FRC working group 2006]

4.2.5 Transport and Storage of CO 2

(217) After capture, the compressed CO 2 must be transported to suitable storage sites. This is done by pipeline, which is generally the cheapest form of transport or by ship when no pipelines are available. Both methods are currently used for transporting CO 2 for other appli- cations. Large-scale pipeline transportation cost range from 1 - 4 €/t CO 2 per 100 km. [IEA 2004] and 1 - 6 €/t CO 2 per 100 km [ECOFYS 2004). For the FRC study average transport cost of 4-6 €/t have been assumed. (218) The carbon dioxide will be injected directly into underground geological formations. The cost of CO 2 storage depends on the site, its location and method of chosen injection type. Oil fields, gas fields, saline formations and saline-filled basalt formations have been sug- gested as storage sites. The assumptions of storage cost differ from 1 to 2 USD/t CO 2 (IEA 2004) and -10 Euro/t CO 2 (en-hanced oil recovery) to 30 Euro/t CO 2 (ECOFYS 2004). For the FRC study average storage cost of 2-4 €/t has been assumed. (219) The FRC Model assumes average cost for transport and storage of 10 €/t CO 2 (exception: Tech 30 scenario with 6 €/t CO 2).

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5 FRC Scenario Results

5.1 FRC Power Generation

Summary High gas prices and low carbon prices lead to significant shares of coal in the power generation, even at comparable high carbon prices. Moderate gas prices may develop into a significant fuel switch at carbon prices around 30 €/t. New nuclear power plants become economically feasible at around 30 €/t. CCS technologies come into play at 45 €/t. (220) FRC Base Scenario is based on comparable assumptions as EU Base [DG TREN/NTUA 06] . Leading fuel prices (regarding oil & gas) are on a comparable high level [BASE] and carbon prices are at a constant level of 5 €/t [BASE 5] . Power generation is forecasted to increase significantly from 3’400 TWh to more than 4’600 TWh (EU 27, cp. figure 5.1-1).

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5.1.1 Power Generation at high fuel prices

Summary At high gas prices power generation based on natural gas (if not operated out in CHP mode) is not competitive for power generation in liberalised electricity markets under a carbon price of 30 €/t. Nuclear power plants are likely to become economically feasible at 30 €/t. At very high carbon prices (45 €/t) natural gas is significantly taking up and CCS capacities appear to become economically feasible. (221) As can be seen from figure 5.1-1, which is representing the results for EU 27, high fuel prices at low carbon prices lead to a significant high contribution of solid fuels, both lignite and hard coal. Contribution of lignite in power generation could be even higher if not capped at the forecasted and probable production output of the Euro- pean lignite mines. The Base 5 scenario is including the nuclear phase-out (where applicable) and is including new nuclear power plants if already known. The share of gas in power generation is only kept because of the gas based CHP power plants. The contribution of gas power plants in combined cycle (NGCC) not operated in CHP is decreasing over the fore cast period. (222) As can be seen from figure 5.1-2, which is representing Italy, the effect of decreasing gas power plants is even more significant in case of countries, where no significant coal or nuclear share is present.

600'000 Import Biomass 500'000 Res. Other Hydro Wind 400'000 Conv. Other Oil (incl. CHP) 300'000 Gas (CCS) Gas CHP Gas 200'000 Hard (CCS) Power Generation [GWh] inGeneration Power Hard (incl. CHP) 100'000 Lignite (CCS) Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.1-2 Power generation [IT, BASE 5 ] [Source: FRC results 2005-2030, Prognos 06]

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(223) It has to be considered that DG TREN/NTUA 06 is modelling comparable high gas prices especially at the end of the forecast period, representing a gas price at almost 24 €2000 /MWh [border price], which is likely to result in gas prices at 27 €2000 /MWh at the power plant. This leads to marginal costs which are not likely to be competitive under liberal market conditions.

(224) Under these fuel price conditions there is no significant effect at moderate higher carbon prices (15 €/t) as shown in figure 5.1-3. (225) At high gas prices natural gas is only gaining competitiveness against hard coal at high carbon prices (30 €/t) as shown in figure 5.2-14. Lignite power plants appear still comparatively untouched by the gas-coal competition. Nuclear power plants are likely to become economically feasible at high fossil fuel price levels and at carbon prices of 30 €/t. (226) At very high carbon prices (45 €/t) and high fuel price conditions natural gas is significantly taking up (figure 5.1-5). As can be seen from the appearance of the light brown generation share after 2027 conventional coal power plants start to shift to CCS technologies. Due to their marginal cost advantages lignite based CCS power plants are the first to be expected to become economically feasible under these framework conditions.

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5.1.2 Power Generation at Moderate Fuel Prices

Summary At moderate gas prices solid fuels remain competitive at carbon prices of 15 €/t. At high carbon prices (30 €/t) both lignite and hard coal power plants significantly lose share against natural gas power plants. Nuclear power comes into play at 30 €/t. (227) Even at moderate fuel prices solid fuels remain competitive at moderate carbon prices (15 €/t). As shown in figure 5.1-6 natural gas is taking up against hard coal, still leaving lignite comparatively untouched. At high carbon prices (30 €/t, figure 5.2-17) both lignite and hard coal power plants significantly lose share against natural gas power plants. This leads on the other hand to a significant production increase from 900 TWh to 2'300 (more than 2.5 times) of gas based power generation. Regarding higher net efficiencies in 2030 this results in doubling the gas fuel use in power generation over the forecast period, and as a consequence definitely leading to higher gas prices (which is of course in contradiction to the initial assumption): leaving other framework conditions unchanged a balancing point with higher gas prices and probably higher carbon prices might be the result.

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5'000'000 Import 4'500'000 Biomass Res. Other 4'000'000 Hydro 3'500'000 Wind Conv. Other 3'000'000 Oil (incl. CHP) 2'500'000 Gas (CCS) Gas CHP 2'000'000 Gas 1'500'000 Hard (CCS) Power inGeneration [GWh] Hard (incl. CHP) 1'000'000 Lignite (CCS) 500'000 Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.1-7 Power generation [EU 27, LowPrice 30] [Source: FRC results 2005-2030, Prognos 07] (228) On the back of gas/coal competition nuclear power comes into play as a third option: as high carbon prices and a comparatively high share of gas power plants lead to a comparatively high price level of the electricity market at the end of the forecast period.

5.2 Power Plant Capacities

Summary At high fuel price levels coal fired power plants are competitive even at high carbon price levels. (229) The effect of high gas prices and low carbon prices can be seen from the development of power capacities. Both lignite and hard coal capacities develop from some 100 GW to more than 300 GW, while gas capacities are still present (especially in CHP or cycling operation), but decrease in generation share. The increase of coal capacities to some extent might be attributed to the nuclear phase-out. New nuclear capacities are not economically feasible (cp. figure 5.2-1)

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1'200'000 Import Biomass 1'000'000 Res. Other Hydro Wind 800'000 Conv. Other Oil (incl. CHP) 600'000 Gas (CCS) Gas CHP Gas Capacities [MW] in 400'000 Hard (CCS) Hard (incl. CHP) 200'000 Lignite (CCS) Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.2-1 Power Capacities [EU 27, BASE 5 ] [Source: FRC results 2005-2030, Prognos 07]

(230) There is no significant effect of moderate higher carbon prices at high gas prices as shown in figure 5.2-1). It has to be considered that DG TREN/NTUA 06 is modelling comparable high gas prices especially at the end of the forecast period, representing a gas price at almost 24 €2000 /MWh [border price], which is likely to result in gas prices at 27 €2000 /MWh at the power plant. This leads to marginal costs which are not likely to be competitive under liberal market conditions. (231) At high gas price levels, natural gas capacities become only feasible at carbon prices around 30 €/t. As can be seen from figure 5.2-3 at 30 €/t high gas fuel prices become effective at the end of the forecast period, resulting in a new reduction of gas capacities.

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1'200'000 Import Biomass 1'000'000 Res. Other Hydro Wind 800'000 Conv. Other Oil (incl. CHP) 600'000 Gas (CCS) Gas CHP Gas Capacities [MW] in 400'000 Hard (CCS) Hard (incl. CHP) 200'000 Lignite (CCS) Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.2-2 Power Capacities [EU 27, POLICY 15] [Source: FRC results 2005-2030, Prognos 07]

1'200'000 Import Biomass 1'000'000 Res. Other Hydro Wind 800'000 Conv. Other Oil (incl. CHP) 600'000 Gas (CCS) Gas CHP Gas Capacities [MW] in 400'000 Hard (CCS) Hard (incl. CHP) 200'000 Lignite (CCS) Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.2-3 Power Capacities [EU 27, POLICY 30] [Source: FRC results 2005-2030, Prognos 07]

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5.3 The introduction of CCS Technology

Summary In order to tackle the challenge of climate protection and to avoid import dependency of price volatile fuels (as oil and gas) a systematic exploitation of all technological options is necessary. This might include all options of rational use of energy, renewable energy sources, nuclear power and CCS technologies.

Under Tech 30 assumptions CCS power plants become economical feasible at carbon prices close to 30 €/t. The full cost logic implies an introduction at slightly lower carbon prices. From a ROE (return on equity) perspective however, CCS technologies are competing in a complex economic environment, especially in presence of old conventional coal and gas power plants and new nuclear power plants. In the TECH scenarios, technology options as nuclear, lignite CCS and hard coal CCS come into play by the order of their marginal cost. CCS capacities show a similar economic character as nuclear power plants and are competing in a complex economic environment. The implementation of CCS requires a strategic and systematic approach, both supported by power sector and state actors.

5.3.1 CCS as Technology Option (232) TECH scenarios have been calculated to show the impact of possible technological alternatives. In order to tackle the challenge of climate protection there are four basic options: • RUE option: the rational use of energy both in power sector and final energy use. • RES option: the accelerated exploitation of renewable energy sources. • CCS option: the accelerated exploitation of Carbon Capture and Storage technologies. • NUCLEAR option: the accelerated exploitation of the nuclear power, which means not only the use of existing nuclear power plants but also leading to new nuclear power plants. (233) With respect to the restricted budget of the FRC study, the possible consequences of accelerated RUE policies concerning the final energy use have not been calculated. Final energy demand of electricity is modelled according to EU trends to 2030 [DG TREN/NTUA 06]. (234) As pointed out in chapter 3.3.3 the use of renewable energy sources is an important option and is supported by the European Un- ion and its member states. The FRC model assumes an increasing contribution of 1'300 TWh/a representing a share of 28% in power generation in 2030. This assumption is the same over all scenarios.

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(235) As pointed out in chapter 5.1, NUCLEAR power plants are likely to become economical feasible at higher carbon prices. Beside the question of the political feasibility the nuclear power requires constant high electricity prices to gain the return for its capital intensive investment. This is the case at carbon prices of more than 30 €/t.

5.3.2 Economic Logic of CCS (236) CCS capacities show a similar economic character as nuclear power plants: high capital intensity requires comparatively high electricity prices to pay off. Once the investment is made, CCS capacities are competitive for marginal cost reasons. Due to their low marginal cost CCS technologies based on lignite can be expected as first to appear by economic logics. As TECH30 shows first CCS power plants are likely to become economically feasible at carbon prices at 30 €/t.

Full costs of power generation, new power plants at 7500 h/a EUA allocation: HC benchmark FRC input parameters TECH30, Germany

70 Nuclear €/MWh 65 Lignite 60

Hard 55

Gas 50

NGCC 45 POST

40 Best CCS Hard

35 Best CCS Lignite 30

25 2005 2010 2015 2020 2025 2030 figure 5.3-1 Full Cost of Power Generation, new power plants at 7'500 € and TECH 30 assumptions (Germany) [Source: FRC results 2005-2030, Prognos 07] (237) The full cost of power generation are shown in figure 5.3-1 based on TECH30 assumptions. As can be seen from the run of the curves the allocation rule of EUAs has a considerable impact: The first NAP (2005-2007) provides free EUAs for existing and new power plants ("grandfathering"). As can be seen by the conventional lignite curve the allocation on a HC benchmark by the start of NAP2 (2008- 2012) leads to a saltus of full cost for lignite. The slope of the curve for conventional coal power plants is mainly caused by this linear increase of auctioning cost rather than by the in-

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crease of fuel cost. The allocation system implies, that certificates for CCS power plants are allocated on the same basis as for conventional power plants, thus providing an incentive for investment in clean coal technologies. (238) Under TECH30 assumptions full cost curves of conventional coal technologies and CCS technologies are subtending at 2018 (lignite) and 2030 (hard coal). There is no intersection for gas based technologies under TECH30 assumptions. As auctioning shares are increasing and reaching a 100% auctioning share in 2030, nuclear power plants come up and are subtending conventional thermal power plants and hard coal based CCS from a full cost perspective, but stay above lignite based CCS.

(239) Whereas full cost economics imply an early competitiveness of CCS technologies, especially for lignite based CCS, the ROE economics (cp. chapter 6.1.2) imply a complex competitive pattern for CCS. As can be seen from figure 5.3-2 the lignite based CCS is introduced by the year of 2025 based on ROE key figures . It has to be kept in mind, that the ROE key figure is computed once at the actual year of introduction of specific power plant. Future sales and future cost are not taken into account as they are dependent of future decisions by market participants (cp. chapter 6.3). (240) From an economical point of view CCS capacities do have three competitors: • At moderate carbon prices CCS capacities compete against existing conventional coal fired plants (if present).

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• At carbon prices of around 30 €/t and above CCS capacities compete against nuclear power plants (if present). • Cost of renewable energy sources such as offshore wind 6 and biomasses may become competitive without additional funding. These findings lead to the conclusion that CCS technologies are competing in a complex environment. The implementation of CCS requires a strategic and systematic approach, both supported by power sector and state actors (cp. chapter 5.3.3).

1'200'000 Import Biomass 1'000'000 Res. Other Hydro Wind 800'000 Conv. Other Oil (incl. CHP) 600'000 Gas (CCS) Gas CHP Gas Capacitiesin [MW] 400'000 Hard (CCS) Hard (incl. CHP) 200'000 Lignite (CCS) Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.3-3 Power capacities [EU 27, TECH 45] [Source: FRC results 2005-2030, Prognos 07]

5.3.3 Strategic Introduction of CCS (241) In order to show the effect of an accelerated technology implementation strategy, FRC study has modelled a TECH 45 scenario, which under otherwise same conditions as Policy 45 excludes the introduction of non-CCS conventional thermal power plants after 2020. (242) As can be seen from figure 5.3-3 and figure 5.3-4 both nuclear, lignite and hard coal based CCS power plants come into play starting 2020. According to their comparable cost structure with slight marginal cost differences the technologies appear in following order:

6 Electricity products by wind power generation and thermal power plants are hardly comparable from a market perspective, as the quality of products is different. Additional cost are needed to refine wind electricity into a tradable band product. From merit order perspective, however, the wind energy is likely to push out old conventional capacities.

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1) Nuclear Power Plants (are going to be built first) 2) Lignite CCS (are going to be built, if lignite is available and as soon as the limit of nuclear infrastructure is reached) 3) Hard Coal CCS (are going to be built, if there is no lignite or no more lignite production capacity available and as soon as the limit of nuclear infrastructure is reached)

(243) The order of appearance might be even more drastic if looking at some selected country results as shown for the case of Ger- many (cp. figure 5.3-5). • Before 2020, hence in the decade before the introduction of CCS power plants, gas expands at the cost of lignite, which is pushed back slowly. At the end of the decade gas suffers from increasing fuel prices and is slowly pushed out by conventional hard coal. • After 2020 the picture changes rapidly in favour of nuclear power. Germany may be considered to have an efficient and functioning nuclear infrastructure, able to manage nuclear fuel and waste cycles up to a (preset) limit of 200 GWh (until 2030). Nuclear power expands quickly until this limit is reached. Con- sequently CCS lignite capacities are following.

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800'000 Import Biomass 700'000 Res. Other

600'000 Hydro Wind 500'000 Conv. Other Oil (incl. CHP) 400'000 Gas (CCS) Gas CHP 300'000 Gas Hard (CCS) Power Generation [GWh] inGeneration Power 200'000 Hard (incl. CHP) Lignite (CCS) 100'000 Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.3-5 Power Generation [DE Germany , TECH 45] [Source: FRC results 2005-2030, Prognos 07]

800'000 Regulation Import 700'000 Biomass Res. Other 600'000 Hydro Wind 500'000 Conv. Other Oil (incl. CHP) 400'000 Gas (CCS) Gas CHP 300'000 Gas Generation[GWh] in Hard (CCS) 200'000 Hard (incl. CHP) Lignite (CCS) 100'000 Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.3-6 Power Generation [DE Germany , TECH 45 with nuclear phase-out] [Source: FRC results 2005-2030, Prognos 07]

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(244) The situation may change drastically if nuclear power phase- out is carried out as agreed, as shown in figure 5.3-5. Lignite CCS appears at 2020 and expands to its (preset) production limits (50 Mtce/year) in 2025, consequently followed by hard coal CCS. How- ever it has to be kept in mind that the drastic increase of lignite production as shown in figure 5.3-6 appears not to be realistic after a decade of decreasing production. (245) Natural gas CCS cannot be observed due to its unfavourable cost structure: the advantage of low capital cost of conventional NGCC is given up in favour of a small advantage of carbon free production at high marginal cost. It may be concluded that there is the least added value of CCS technologies for natural gas power plants.

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5.4 Carbon Emissions

Summary A combination of high fuel prices and low carbon prices seem to be unlikely over a longer time period: at high gas prices carbon prices are likely to go beyond 45 €/t, if the power sector is regarded isolated. Moderate gas prices lead to a significant fuel switch at around 30 €/t CO 2. As a consequence a significant fuel switch leads to higher import dependency and might lead to significant higher gas prices.

The carbon intensity of power generation compared to 2005 is decreasing in Policy 30 , Policy 45 , Low 15 , Low 30 and both Tech scenarios. A considerable decarbonisation is reached in the TECH 45 scenario, which is including both CCS and nuclear power as technology options. The "mitigation" effect of high carbon prices cannot be observed gradually but is rather occurring in shifts.

Until 2020 CO 2 emissions will decrease in all scenarios except Base 5 and Policy 15 when compared with the Kioto baseline year of 1990. From 2020 to 2030, however (cp. table 5.3-2), CO 2 emissions are rising in all scenarios (except Tech 45 ) due to the assumed high growth rate in electricity demand and decreasing market shares of nuclear and gas.

2'000'000

1'800'000

1'600'000 ] 2 1'400'000 Conv. Other Oil (incl. CHP) 1'200'000 Gas (CCS) Gas CHP 1'000'000 Gas Hard (CCS) 800'000 Hard (incl. CHP) Lignite (CCS) 600'000 Lignite (incl. CHP) Carbon Emission Emission Carbon [kt in CO

400'000

200'000

0 2005 2010 2015 2020 2025 2030 figure 5.4-1 Carbon Emissions [EU 27, BASE 5 ] [Source: FRC results 2005-2030, Prognos 07]

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5.4.1 Carbon Emissions at High Gas Prices (246) As can be seen from figure 5.4-1 carbon emissions are significantly increasing at high gas prices and low carbon prices. The carbon emissions by the European Union’s power sector are likely to increase by 50% from 1'250 Mio. t CO 2/a in 2005 to 1'850 Mio. t CO 2/a in 2030. This increase is caused by the use of hard coal. Un- der these preconditions it seems questionable, whether a 5 €/t carbon price path as chosen by DG TREN/NTUA 06 might be stable over a longer time period. (247) As can be seen from figure 5.4-2 and figure 5.4-3 carbon emissions are still increasing at higher carbon prices. The increase at 30 €/t is still at 38% (2030 compared to 2005). Due to a significant fuel shift at 45 €/t carbon price the emissions are (still) slightly increasing to 1'200 Mio. t/a. Two things might be concluded:

2'000'000

1'800'000

400'000

200'000

0 2005 2010 2015 2020 2025 2030 figure 5.4-2 Carbon Emissions [EU 27, Policy 30] [Source: FRC results 2005-2030, Prognos 07]

• (At high gas prices) carbon prices at 45 €/t are not high enough to reach the emissions cap (cp. capter 3.4, if the power sector is regarded isolated). By other words: (at high gas prices) even the 45 €/t don´t give enough inherent incentives for fuel switch. The power sector emissions cap will be missed. • If (at high gas prices) the emissions cap and the emissions target is to be reached by the power sector itself (not regarding flexible mechanisms as JI/CDM) the resulting carbon prices will be higher than 45 €/t.

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1'400'000

1'200'000 ] 2 1'000'000 Conv. Other Oil (incl. CHP) Gas (CCS) 800'000 Gas CHP Gas Hard (CCS) 600'000 Hard (incl. CHP) Lignite (CCS) 400'000 Lignite (incl. CHP) Carbon Emission in [kt CO [kt in Emission Carbon

200'000

0 2005 2010 2015 2020 2025 2030 figure 5.4-3 Carbon Emissions [EU 27, Policy 45] [Source: FRC results 2005-2030, Prognos 07]

5.4.2 Carbon Emissions at Moderate Gas Prices

2'000'000

1'800'000

400'000

200'000

0 2005 2010 2015 2020 2025 2030 figure 5.4-4 Carbon Emissions [EU 27, LowPrice 30] [Source: FRC results 2005-2030, Prognos 07]

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(248) The situation changes at lower gas prices, thus leaving more flexibility for fuel switch: emissions nearly stay constant at lower fuel prices and at 30 €/t carbon prices (cp. figure 5.4-4). (249) As can be seen from figure 5.4-5 the same scenario results in gas based power generation of about 2'100 TWh at the end of the forecast period. The fuel switch is doubling the use of natural gas in power generation and thus resulting in a higher import dependency and very likely to result in higher gas prices.

5'000'000 Import 4'500'000 Biomass Res. Other 4'000'000 Hydro 3'500'000 Wind Conv. Other 3'000'000 Oil (incl. CHP) 2'500'000 Gas (CCS) Gas CHP 2'000'000 Gas 1'500'000 Hard (CCS) Power Generation [GWh] inGeneration Power Hard (incl. CHP) 1'000'000 Lignite (CCS) 500'000 Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.4-5 Power generation [EU 27, LowPrice 30] [Source: FRC results 2005-2030, Prognos 07] (250) As a preliminary conclusion from chapters 5.1 and 5.4 can be drawn that under otherwise similar conditions there is a balancing point with (borderline) gas prices between 15 €2000 /MWh and 25 €2000 /MWh leading to carbon prices of 30 €2000 /t and more than 45 €2000 /t respectively. As low gas and carbon prices encounter a broad fuel switch with a significant demand for natural gas, there is a high probability for both higher gas and carbon prices, if no alternative options are exploited.

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5.4.3 Carbon Emissions in Overview

(251) Compared to the carbon output of 1'275 Mt CO 2/a [carbon emissions by the power sector in 2005] carbon emissions are decreasing in case of high carbon prices and low gas prices [Low 30] or high carbon and gas prices [Policy 45, Tech 45] . All other scenarios lead to higher carbon emissions [cp. table 5.4-1]. (252) The carbon intensity of power generation compared to 2005 is decreasing in Policy 30 , Policy 45 , Low 15 , Low 30 and both Tech scenarios. Carbon intensity is at very low values in the case of high carbon prices [Policy 45: 265 kg/MWh and Tech 45: 167 kg/MWh ] and/or low gas prices [Low 30: 238 kg/MWh ]. In comparison with Pol- icy 30 the Tech 30 leads to a lower carbon intensity. The effect however is not that significant, as CCS is penetrating comparatively slowly.

EU27 Start Base-5 Policy-15 Policy-30 Policy-45 Low-15 Low-30 Tech-30 Tech-45 2005 2030 2030 2030 2030 2030 2030 2030 2030

Capacities GW el 729 991 992 1'003 1'009 999 1'001 1'003 1'017

Generation TWh el 3'444 4'642 4'642 4'641 4'641 4'642 4'641 4'639 4'640 Gen. Growth % p.a. 1.2% 1.2% 1.2% 1.2% 1.2% 1.2% 1.2% 1.2%

Carbon Output Mt CO 2 1'275 1'849 1'829 1'596 1'231 1'698 1'107 1'528 774 Carbon Growth % p.a. 1.5% 1.5% 0.9% -0.1% 1.2% -0.6% 0.7% -2.0%

Carbon Intensity t CO 2/MWh el 0.370 0.398 0.394 0.344 0.265 0.366 0.238 0.329 0.167

Av. Costs of EUA €00 /t 5 15 30 45 15 30 30 45 table 5.4-1 Carbon Emissions in Power Generation [EU 27] [Source: FRC results 2005-2030, Prognos 07]

(253) A considerable decarbonisation is reached in the TECH 45 scenario, which is including both CCS and nuclear power as technology options (cp. chapter 5.3). Carbon intensity is decreasing to 167 kg/MWh el . (254) The "mitigation" effect of high carbon prices cannot be observed gradually but is rather occurring in shifts. For carbon prices between 5 and 20 €/t there is a comparable wide range without any significant reaction and no significant effect on carbon emissions. Es- pecially at comparable high gas prices coal is prevailing in power generation and only declines at carbon prices higher than 20 €/t. This results in comparable constant carbon intensities of 370 kg/MWh.

(255) Compared to the baseline year of 1990 CO 2 emissions will decrease until 2020 in all scenarios except Base 5 and Policy 15 . The largest reduction occurs at low gas prices and high CO 2 prices [Low 30] (cp. figure 5.4-6).

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2'000'000 1990 2005 2020 2020 2020 2020 2020 2020 2020 2020 1'750'000 Biomass Res. Other 1'500'000 Hydro Wind 1'250'000 Conv. Other Oil (incl. CHP) Gas (CCS) 1'000'000 Gas CHP Gas 750'000 Hard (CCS) Hard (incl. CHP) Lignite (CCS)

Carbon Emissions inCarbon Emissions CO2] [kt 500'000 Lignite (incl. CHP) Nuclear 250'000

0 Start Base Policy Policy Policy Low Low Tech Tech 5 15 30 45 15 30 30 45 figure 5.4-6 Carbon Emissions in 2020 [EU 27] [Source: FRC results 2005-2020, Prognos 07; UNFCC 2007]

2.250.000 1990 2005 20302030 2030 2030 2030 2030 2030 2030 2.000.000 Biomass 1.750.000 Res. Other Hydro Wind 1.500.000 Conv. Other Oil (incl. CHP) 1.250.000 Gas (CCS) Gas CHP 1.000.000 Gas Hard (CCS) 750.000 Hard (incl. CHP) Lignite (CCS) Carbon Carbon Emissions in[kt CO2] 500.000 Lignite (incl. CHP) Nuclear 250.000

0 Start Base Policy Policy Policy Low Low Tech Tech 5 15 30 45 15 30 30 45 figure 5.4-7 CO 2 Emissions in 2030 [EU 27] [Source: FRC results 2005-2020, Prognos 07; UNFCC 2007]

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(256) From 2020 to 2030, however (cp. figure 5.4-7, table 5.4-2), CO 2 emissions will rise in all scenarios (except Tech 45 ). The reasons are: • an increasing electricity consumption (9% in 2020 relative to 2030), • electricity generation from nuclear power plants will decrease, • gas will not (significantly) gain market share, or it will even lose market share relative to electricity from coal.

(257) In the Tech 45 scenario, CO 2 emissions will be significantly reduced after 2020 because of CCS introduction and a rise in nuclear power production. In the Tech 30 scenario CCS is starting to display its impact, but these effects are not strong enough to compensate the increase in electricity demand.

Year [Source] EU27 Base-5 Policy-15 Policy-30 Policy-45 Low-15 Low-30 Tech-30 Tech-45

1990 [UNFCC] Mt CO 2 1.465 1.465 1.465 1.465 1.465 1.465 1.465 1.465

2004 [UNFCC] Mt CO 2 1.366 1.366 1.366 1.366 1.366 1.366 1.366 1.366 Change 1990-2004 % -7% -7% -7% -7% -7% -7% -7% -7%

2020 [FRC] Mt CO 2 1.463 1.442 1.308 1.073 1.322 1.004 1.310 1.043 Change 1990-2020 % 0% -2% -11% -27% -10% -31% -11% -29%

2030 [FRC] Mt CO 2 1.849 1.828 1.596 1.231 1.698 1.106 1.528 774 Change 1990-2030 % 26% 25% 9% -16% 16% -25% 4% -47%

7 table 5.4-2 CO 2 Emissions [EU 27, source: FRC results 2005-2030, Prognos 07; UNFCC 2007 ]

7 The UNFCCC figures show emissions from power and heat production of the public sector as defined by UNFCCC. They compare well with FRC results but do not refer to the same statistical basis. Statstical deviations may occur from small power plants (<30 MW), heat production in cogeneration and power generation in the industrial sector.

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5.5 Cost of Power Generation

Summary Total cost of power generation significantly increase due to higher energy demand, higher fuel prices, higher carbon prices and if technological options as nuclear energy and CCS are employed. The growth rate of the average real cost of unit electricity (without cost for EUAs) may be kept significantly under 1% p.a. as in Policy 15 and Policy 30) or even under 0.4% p.a. at low price assumptions (as in LowPrice 15 and LowPrice 30).

The Tech 45 scenario requires an annual growth rate of 1% of electricity cost (without EUAs) to reach ambitious technological investments. Looking at carbon emissions reduction the technology scenarios [Tech 30, Tech 45] shows lower emissions at lower cost (incl. EUAs), if compared to the same scenarios without CCS introduction [Policy 30, Policy 45].

300'000 Biomass Res. Other 250'000 Hydro Wind

200'000 Conv. Other Oil (incl. CHP) Gas (CCS) 150'000 Gas CHP Gas 100'000 Hard (CCS) Hard (incl. CHP)

50'000 Lignite (CCS) Costs of Costs [millioninGenerationPowerof EUR] Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.5-1 Cost of Power Generation [EU 27, BASE 5] [Source: FRC results 2005-2030, Prog- nos 07]

(258) Figure 5.5.-1 shows full cost of power generation for BASE 5 scenario. Cost of power generation increase from 170 bn €2000 /a to 270 bn €2000 /t in 2030 according (figure 5.5-2). This is caused by the increase of power generation by 35 % (1.2% p.a.) and high gas prices as assumed in the Base 5 scenario by NTUA/DG TREN 06 .

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EU27 Start Base-5 Policy-15 Policy-30 Policy-45 Low-15 Low-30 Tech-30 Tech-45 2005 2030 2030 2030 2030 2030 2030 2030 2030

Capacities GW el 729 991 992 1'003 1'009 999 1'001 1'003 1'017

Generation TWh el 3'444 4'642 4'642 4'641 4'641 4'642 4'641 4'639 4'640 Gen. Growth % p.a. 1.2% 1.2% 1.2% 1.2% 1.2% 1.2% 1.2% 1.2%

Carbon Output Mt CO 2 1'275 1'849 1'829 1'596 1'231 1'698 1'107 1'528 774 Carbon Growth % p.a. 1.5% 1.5% 0.9% -0.1% 1.2% -0.6% 0.7% -2.0%

Carbon Intensity t CO2/MWh el 0.370 0.398 0.394 0.344 0.265 0.366 0.238 0.329 0.167

Total Costs bn € 00 168 271 288 315 339 266 284 313 328

Total Costs of EUA bn € 00 0.0 9.2 27.4 47.9 55.4 25.5 33.2 45.8 34.8

Total Costs w/o EUA bn € 00 168 262 261 267 283 241 251 267 293 % p.a. 1.8% 1.8% 1.9% 2.1% 1.5% 1.6% 1.9% 2.3%

Av. Cost €00 /MWh el 48.7 58.4 62.1 67.8 73.0 57.4 61.2 67.5 70.7

Av. Cost of EUA €00 /MWh el 0.0 2.0 5.9 10.3 11.9 5.5 7.2 9.9 7.5

Av. Cost w/o EUA €00 /MWh el 48.7 56.4 56.2 57.5 61.0 51.9 54.1 57.6 63.2 % p.a. 0.6% 0.6% 0.7% 0.9% 0.3% 0.4% 0.7% 1.0%

Av. Costs of EUA €00 /t 5 15 30 45 15 30 30 45 figure 5.5-2 Cost of Power Generation [EU 27] [Source: FRC results 2005-2030, Prognos 07]

350'000 Biomass Res. Other 300'000 Hydro Wind 250'000 Conv. Other Oil (incl. CHP) 200'000 Gas (CCS) Gas CHP 150'000 Gas Hard (CCS) 100'000 Hard (incl. CHP) Lignite (CCS)

Costs of Power Costs Generation of in [million EUR] 50'000 Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 figure 5.5-3 Cost of Power Generation [EU 27, TECH 45] [Source: FRC results 2005-2030, Prog- nos 07]

(259) Total cost of power generation for 4'640 TWh may differ between 280 bn €2000 /a [LowPrice 15] and 353 bn €2000 /a [Tech 45] in 2030. This includes cost for EUAs (internalised cost for carbon emissions, 100% auctioning) between 9.2 bn €/a [Base 5] and 55.4 bn €/a [Policy 45]. This is confirming the expectation, that lowest cost of power generation - of course - can be achieved at low fuel prices and low carbon prices.

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(260) Average full cost of power generation are at 49 €2000 /MWh in 2005 and may differ between 58 €2000 /MWh [LowPrice 15] and 73 €2000 /MWh [Policy 45] in 2030. This is including cost for EUAs between 2 €2000 /MWh [Base 5] and 11.9 €2000 /MWh €/a [Policy 45]. (261) It may be concluded that the growth rate of the average real cost of unit electricity (without cost for EUAs) may be kept significantly under 1% (Policy 45) or even at 0.3%-0.4% at low price assumptions (as in LowPrice 15 and LowPrice 30). The technology scenario requires an annual growth rate of 0.7 % p.a. [Tech 30] or 1.0 % p.a. [Tech 45] of electricity cost (without EUAs) to reach ambitious technological investments. (262) Looking at carbon emissions reduction the technology scenarios [Tech 30, Tech 45] lead to lower emissions at lower cost (including the cost of EUA certificates), if compared to the same scenarios without CCS introduction [Policy 30, Policy 45]. Even if the cost of EUAs are not taken into account the average full cost of power generation are in the same range [Policy 45: 61,0 €/MWh, Tech 45: 63,2 €/MWh].

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6 Appendix A: FRC Model Concept

6.1 FRC Model Logics

6.1.1 Power Plant Parc (263) Underlying the FRC Model is a detailed database for existing power plant for all European Countries. Power plants over 30 MW are characterised by type, installed capacity, year of commissioning and main fuel. For each region, the power plant database is read at the beginning of each model run. Another (not necessarily complete) database is providing data about future (planned) capacities. If there is already evidence about planned power plants (e. g. the projected commissioning of the hard coal steam power plant in the Hamburg-Moorburg in 2012), the data is also made available for the model. At the beginning of each year, power plants which have reached their type specific life span will be decommissioned. In a next step the model compares the required max. net load with the available capacity in the region. If there is not enough capacity available the subroutine “capacity decision” is set into operation.

90000 Max. Net Load (Germany)

80000

70000

60000

50000

40000

Capacities MW in 30000

20000

10000

0 1 1001 2001 3001 4001 5001 6001 7001 8001 Full Load Hours figure 6.1-1 Assorted Load Curve

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6.1.2 Capacity Decision and ROE Concept (264) The capacity decision subroutine (short: CD ) is needed to fill up the existing power plant parc if there is not enough capacity available to meet the net load requirements. Basically the CD follows the logics of maximised ROE (return on equity) , which is represented by the projected sales minus projected average cost (earinngs) divided by the annuity of equity. This figure is not representing a full cash flow calculation, but rather represents a simplified ROE key figure . (265) Projected average annual cost (PAC): for a projected power plant the MO position is calculated. The position gives a projected full load operation time [h/a] . Thus average cost can be calculated by di- viding the annual full cost (capital cost, fix and variable operation cost + fuel cost, cp. pink square in figure 6.1-2) by the annual operation time. (266) Projected average annual sales (PAS): according to its MO position the projected power plant yields sales, which are computed by integrating the marginal cost curve (cp. black line in figure 6.1-2) for each specific hour of the year, when the projected capacity is in operation. (267) The projected average annual earnings (PAE) are computed by the differential of sales and costs: PAE = PAE - PAS and are dive- ded by the annuity of equity to obtain the ROE key figure for each possible type of capacity. The type of power plant which yields the highest ROE key figure will be put into the power plant parc and taken into operation.

90.000 90

80.000 Marginal Cost Cu rve Full Cost Curve 80

70.000 Load Curve 70

Hard Coal Capacity enters MO 60.000 Projected C apacity 60

50.000 50

40.000 40

Capacities MW in 30.000 30

20.000 20 Marginal and and MarginalFull Costs €/MWh in

10.000 10

0 0 1 1001 2001 3001 4001 5001 6001 7001 8001 Full Load Hours figure 6.1-2 The principle of maximised earnings [source: Prognos 2006]

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6.1.3 Merit Order Concept (268) The merit order subroutine (short: MO) is the core routine of the model. It calculates the power generation and its structure for a given region, year and power plant parc. Basically the calculation of MO follows the marginal cost logics: marginal cost are calculated and compared for each type of power plant. A type is defined by a specific power plant type, fuel and year of commissioning. Hence there are easily hundred of different capacity classes with different marginal cost.

6.1.4 Renewables and CHP (269) Renewable generation (must-run): For renewable energy sources the maximised earning logics (underlying the capacity decision) and the marginal cost logics (underlying the merit order) do not apply. For this reason the renewable energy share is given as external input for the model period (e. g. linear growth from actual share until a projected share in 2030). The renewable capacities slices are evenly dispersed throughout the MO and thus are present throughout each time of the year. (270) CHP generation (base-run): For CHP capacities the maximised earning logics (underlying the capacity decision) and the marginal cost logics (underlying the merit order) do not apply. For this reason the CHP share is given as external input for the model period (e. g. linear growth from actual share until a projected share in 2030). The CHP capacities slices are assumed to be present in the base load during the heating period.

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GLOBAL Global Prices Global Reserves Prices Price Ass. Production Cap. Crude Oil Crude Oil Transport/Grid Cap. Natural Gas Natural Gas Coal Coal

EUROPE EU 15 EU 10 Candidates and Neighbours

European Policy Policy Ass. Policy Ass. Policies Renewables Renewables Renewables Global Climate Protection Climate Protection Climate Protection Multilateral National NATIONAL Germany UK ... Poland Czech R. ... Romania Bulgaria

Policy (national) Policy Ass. Policy Ass. Policy Ass. Policy Ass. Policy Ass. Policy Ass. Policy Ass. Policy Ass. Strategy Strategy Strategy Strategy Strategy Strategy Strategy Strategy Strategy Renewables Renewables Renewables Renewables Renewables Renewables Renewables Renewables Renewables Climate Protection Climate Protection Climate Protection Climate Protection Climate Protection Climate Protection Climate Protection Climate Protection Climate Protection

THE FUTURE EUROPE PE Consumption ROAL OF COAL EUROPE 2030 NATIONAL PE Consumption PE Consumption PE Consumption PE Consumption PE Consumption PE Consumption PE Consumption PE Consumption

Technology PP Capacity Capacities Capacities Capacities Capacities Capacities Capacities Capacities Capacities Convent.-Thermal PP Efficiency PP Efficiency ηηη ηηη ηηη ηηη ηηη ηηη ηηη ηηη Clean Coal Capture & Storage Power Generation Power Generation Power Generation Power Generation Power Generation Power Generation Power Generation Power Generation Power Generation

Basic Assumptions Final Energy FE Demand FE Demand FE Demand FE Demand FE Demand FE Demand FE Demand FE Demand Economy Demography Economy Growth Growth Growth Growth Growth Growth Growth Growth consistent with EU Trends 2030 (2005) ! Demography Population Population Population Population Population Population Population Population figure 6.1-3 Structure of FRC Model

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6.2 FRC Conceptual Design (271) Table figure 6.1-3 shows the general structure of the FRC model with global and regional data structure: Basic assumptions as population and economic growth are adapted to the EU trends scenario. The final energy consumption has been also taken from EU trends. This does not necessarily mean that Prognos has In order to make the results of both scenario studies more comparable

(272) table 6.2-1 shows the simplified source code structure of the FRC model. The program is basically structured in two major loops: • loop 1 addresses different model regions, e.g. Germany, UK, Poland…; EU 10, …EU 25, EU 27… • loop 2 addresses subsequent model years, e. g. from 2005 to 2030. The second loop consists of two major subroutines: • the first subroutine “capacity decision” (cp. chapt. ??), which controls the actual power plant parc) • the second subroutine “merit order” (cp. chapt. 6.1.1) The input is structured in • global input data: data are constant and are not changed throughout whole modelling process. • scenario input data: scenario name and relevant data, especially different carbon and fuel price paths. • regional input data, especially regional electricity demand, load curve, power plant data, prices, technology and efficiency data

FRC PROGRAM CODE Start FRC program READ Global Data (Costs, Operation Data) READ Scenario Name(BASE, TECH, POL15, POL 35, etc.) READ Scenario Data(FuelPrice, CarbonPrice, Technology Data)

LOOP 1 CALL for Region (Region =1 to 15) READ RegionalData (Regional Price, Techn. & Efficiency Differences) (Regional Carbon Regime) READ Existing Power Plant Data by Type, Fuel, Year of Operation READ Electricity Demand (Year 2005-2030) CALCULATE Load Curve (Year 2005-2030)

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LOOP 2 CALL for YEAR (Year = 2005 bis 2030) REMOVE old capacities by life time GET already planned capacities (if known) GET BASE RUN capacities (given: CHP) GET MUST RUN capacities (given: RES)

CALCULATE Marginal Cost by Type, Fuel, Year CALL SUBROUTINE Preliminary MERIT ORDER

IF Capacity Gap expected (CAP_MAX < 1.1 x LOAD_MAX): CALL SUBROUTINE Capacity Decision CALCULATE Full Costs by Type, Fuel, Year (according to Merit Order Position) CALCULATE Projected Sales by Type, Fuel, Year (according to Merit Order Marginal Costs = Price) CALCULATE Projected Earnings by Type, Fuel, Year (Sales ./. Full Costs) DECIDE New Capacity after comparision of proj. earnings END SUBROUTINE REPEAT until Capacity Gap is filled up.

CALL SUBROUTINE Merit Order IDENTIFYBaseRun(Combined Heat & Power) DISTRIBUTIONof BaseRun(base load layer)

IDENTIFYMustRun (Renewahle Energy Sources & Import) DISTRIBUTIONof MustRun (equally dispersed layers)

IDENTIFYFree Competing Capacities CALCULATEMarginal Cost by Type, Fuel, Year COMPAREMarginal Cost by Type, Fuel, Year ASSORT Capacities by Marginal Costs CALCULATEOperation Hours by filling up Load Curve CALCULATEPower Generation by Type, Fuel, Year CALCULATECarbon Emissions by Type, Fuel, Year CALCULATEFuel Input by Type, Fuel, Year END SUBROUTINE WRITE results by year and region END CallLOOP next2 year

WRITE results by region END LOOP 1 Call next region

AGGREGATE results by region (EU 27, 25, 15, 10) WRITE results

END FRC Program table 6.2-1 FRC program code (simplified) [source: prognos 2007]

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6.3 Critical Discussion of the FRC Model (273) Modelling requires the reduction of complexity in order to achieve operable and resolvable algorithms. The following simplifying assumptions have been made: (274) Rational behaviour in a rational and ideal market. The model represents a rational and ideal market. All operation and capa- pacity decisions which are rationally based on the given set of economic equations (MO concept, ROE concept) are immediately put into place without considering any market failure or strategic behaviour of individuals in the market. In some cases the immediate reaction to price signals may lead to discontinuous run of the curve of fuel use. In reality however, a sharp increase of power plant fuel use (lignite, nuclear, hard coal, natural / liquis gas and biomasses) requires the upfront investment in production and transport logistics. If fuel supply structures have once been abandoned, it requires a decent time span to take them into operation again, not to mention political decisions and approval procedures that have to be taken before putting up an energy infrastructure. (275) No cash flow forecast. For the computation of the ROE key figure no cash flow forecast of the projected investment has been calculated. The forecast is highly dependent on subsequent decisions. Future decisions are highly dependent on preceding decisions. An it- eration of these possible preceding and subsequent decisions leads to exponential increase of calculation steps. The decisions of the model would become less transparent. Beyond the restricted rational forecast, there is no strategic behaviour of individual market participants included in the FRC model. In reality, the development and operation of an infrastructure as lignite mines, nuclear fuel and waste cycles or CCS technologies requires a longterm strategic behaviour of market participants. This may lead to lonterm decisions which may even accept ROE figures that are lower than the optimal option. (276) Restricted regional input. The model has been computed for 15 model regions, considering the different regional preconditions for power plant investment and operation. For all 15 regions input data (e. g. power plant data) have been assessed and considered with experts. However, not all specific regional preconditions could have been assessed and taken into account. (277) Restricted regional interfaces. The model has been computed for 15 model regions, considering a certain but restricted amount of electricity exchange between regions. The electricity exchange however was not computed as a model result, but was given as an input according to the EU trends to 2030 (05 edition). (278) Annual time resolution. The MO has been computed in an annual time resolution based on an annual load curve. There has been no daily, hourly or minute-by-minute computation of the MO.

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7 Appendix B: Glossary, Definitons, Literature

7.1 Glossary

Base-run For CHP capacities the maximised earning rule does not apply. For this reason the CHP share is given as external input for the model period (e. g. linear growth from actual share until a projected share in 2030). The CHP capacities slices are assumed to be present in the base load during the heat demand period. boe barrel of oil equivalent CHP Combined Heat and Power (cogeneration) Czech Coal Czech coal producing company, Praha, member of FRC expert group. DEBRIV Deutscher Braunkohlen-Industrie-Verein e. V. (German Lignite Produ- cing Industries Associastion), member of FRC expert group. DG diréctorates génerales (general directorates) of the EC e. g. for transport and energy (TREN) or environment. EC European Commission, mostly represented by its DG, diréctorates gé- nerales (general directorates) eon eon Kraftwerke GmbH, Hannover, member of FRC expert group. EU European Union EUA European Union Emissions Allowance EURACOAL European Association of Coal and Lignite, Brussels, member of FRC expert group. EURELECTRIC European Union of the Electric Industry, Brussels ETP Energy Technology Perspective , mostly refered to as a model and a set of recent IEA scenarios discussing the impact of energy technologies [IEA 2006] ETS (European Union´s) Emissions Trading Scheme FRC Future Role of Coal, study and working platform of EURACOAL and several European coal and power producers. GCR Gas cooled reactor, type of nuclear reactor. IEA International Energy Agency, an OECD organisation, located in Paris Magnox (GCR) Magnesium non oxidising alloy, also used for one of the first commercially used nuclear reactor type, referring to the magnox fuel shell. MATRA Matra Erömü Részvénytársaság, Hungarian coal and power producing company, Praha, member of FRC expert group. max. net load The maximum net load is the annual peak load measured in a regional power grid. The FRC model assumes that at least the 1.1 max. net load needs to be represented by installed and available power plant capacities. As installed capacities are not always available for each type of a typical availability is assumed. MO or. M.O Merit Order

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MS Member States (of the EU) NAP National Allocation Plan (within the ETS) OECD International Energy Agency, an OECD organisation, located in Paris PPWB Confederation of the Polish Lignite Industry, member of FRC expert group PWR Type of nuclear reactor (pressurized water reactor) RES Renewable Energy Sources ROE Return on Equity RUE Rational Use of Energy (Energy Efficiency) RWE RWE AG, Essen, member of FRC expert group SIEMENS PG SIEMENS AG Power Generation, Erlangen, associated member of FRC expert group UNFCCC United Nations Framework Convention on Climate Change VDEW Verband der deutschen Elektrizitätswirtschaft, Berlin und Frankfurt VE Vattenfall Europe, member of FRC expert group WEO World Energy Outlook, a set of scenarios, annually published by the IEA. WWER Water-Water Energy Reactor, a Russian type of PWR ZPGWK Polish Hard Coal Employers Association / Kompania Weglowa member of FRC expert group ZSDNP Czech Confederation of the Coal and Oil Producers, Praha member of FRC expert group

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7.2 Geographic and Political Clusters

EU ShortkeyEU Internat. Key Country (Association) Geographic StatusEU EIA Region memberOECD IEA member

EU 25 EU (25 Länder) Europe EU 25 EU 15 EU (15 Länder) Europe EU 15 CandC Candidate Countries Europe CandC NC Neighbouring Countries Europe NC ME EFTA European Free Trade Association Europe EFTA CIS Commonwealth of Indep. States (CIS) (Europe) CIS FSU Former Soviet Union (Europe) FSU EE Eastern Europe EE WE Western Europe WE ME Middle East ME

AL Albany Europe NC EE - AND Andorra Europe AR Armenia Europe FSU (CIS) AT A Austria Europe EU 15 WE OECD IEA AZ Azerbeijan Europe FSU (CIS) BY Belarus Europe FSU (CIS) BE B Belgium Europe EU 15 WE OECD IEA BIH Bosnia Herzegovina Europe NC EE BU BG Bulgary Europe EU 27 EE HR HR Croatia Europe NC EE CY CY Cyprus Europe EU 25 ME CZ Czech Republic Europe EU 25 EE OECD IEA DK DK Denmark Europe EU 15 WE OECD IEA EE ESL Estonia Europe EU 25 FSU (EU) FI SF Finland Europe EU 15 WE OECD IEA FR F France Europe EU 15 WE OECD IEA GE Georgia Europe FSU (CIS) DE D Germany Europe EU 15 WE OECD IEA GBZ Gibraltar Europe EL GR Greece Europe EU 15 WE OECD IEA HU Hungary Europe EU 25 EE OECD IEA IS Iceland Europe EFTA WE OECD IE IRL Ireland Europe EU 15 WE OECD IEA IT I Italy Europe EU 15 WE OECD IEA KZ Kazakhstan Europe FSU (CIS) LV LV Latvia Europe EU 25 FSU (EU) LI LI Liechtenstein Europe LT LT Lithuania Europe EU 25 FSU (EU) LU L Luxembourg Europe EU 15 WE OECD IEA Macedonia (FYR) Europe NC EE MT M Malta Europe EU 25

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EU ShortkeyEU Internat. Key Country (Association) Geographic StatusEU EIA Region memberOECD IEA member MD Moldova Europe FSU (CIS) MC Monaco Europe NL NL Netherlands Europe EU 15 WE OECD IEA NO N Norway Europe EFTA WE OECD IEA PL PL Poland Europe EU 25 EE OECD P Portugal Europe EU 15 WE OECD IEA RO R Romania Europe EU 27 EE RUS Russia Europe FSU (CIS) San Marino Europe Serbia and Montenegro (FYR) Europe NC EE SK Slovakia Europe EU 25 EE OECD SLO Slovenia Europe EU 25 EE ES E Spain Europe EU 15 WE OECD IEA SE S Sweden Europe EU 15 WE OECD IEA CH CH Switzerland Europe EFTA WE OECD IEA TR TR Turkey Europe CandC Middle E. OECD IEA UA Ukraine Europe FSU (CIS) UK UK United Kingdom Europe EU 15 FSU (CIS) OECD IEA UZB Uzbekistan Europe FSU (CIS) V (SCV) Vatican Europe

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7.3 European Union: Groups and Neighbours

EU 10 Cyprus (CY), Czech Republic (CZ), Estonia (EE), Hungary (HU), Malta (MT), Lithuania (LT), Latvia (LV), Poland (PL), Slovakia (SK), Slove- nia (SL) EU 15 Austria (AT), Belgium (BE), Denmark (DK), Finland (FI), France (FR), Germany (DE), Greece (EL), Ireland (IE), Italy (IT), Luxemburg (LU), The Netherlands (NL), Portugal (PT), Spain (ES), Sweden (SE), United Kingdom (UK). EU 25 consists of EU 15 plus EU 10 EU 27 consists of EU 25 plus Bulgaria (BG) and Romania (RO)

7.4 Definitions Coking Coal coal with a quality that allows the production of coke suitable to support a blast furnace [IEA 2004b 8] Hard Coal is reported as the sum of coking coal and steam coal if not indicated otherwise, Other Bituminous coal and Anthracite is a non-agglomerating coal with a gross calorific value greater than 23,865 kJ/kg on an ash-free but moist basis (IEA 2004b). Other Bituminous coal and Anthracite is reported in the category steam coal if not indicated otherwise, Subbituminous coal is a non-agglomerating coal with a gross calorific value greater than 23’865 kJ/kg and 17’435 kJ/kg containing more than 31% volatile matter on a dry mineral-matter-free basis [IEA 2004b]. Subbituminous coal is reported in the category brown coal in IEA literature, except some exceptions where it is reported as steam coal because of its high calorific value. Lignite/Brown coal is a non-agglomerating coal with a gross calorific value greater than 17’435 kJ/kg and greater than 31% volatile matter on a dry mineral-matter- free basis [IEA 2004b]. (Oil shale combusted directly is reported in this category in IEA literature). Lignite is reported in the category brown coal (or vice versa).

8 IEA (2004) Coal Information (2004 Edition), 2005

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7.5 Literature BCG 2003 The Boston Consulting Group: Keeping the Lights On - Navigating Choices in European Power Generation, Boston: BCG BEI 2004 Bremer Energieinstitut (2004): Investitionen im liberalisierten Energiemarkt: Optionen, Marktmechanismen, Rahmenbedingungen, Bremen. Beurs 2007 Alstom And Statoil Sign Chilled Ammonia Project JV In Norway, http://www.beurs.nl/nieuws, Press Release, 22 June 2007. BGR 2005 Bundesamt für Geologie und Rohstoffwesen (2005): Kurzstudie Reserven, Ressourcen und Verfügbarkeit von Energierohstoffen 2005, Hannover. BAH 2004 Booz Allen Hamilton (2004): Coal-Based Integrated Coal Gasification Com- bined Cycle: Market Penetration Recommendations and Strategy, 2004. BMWi 2005 5. Energieforschungsprogramm der Bundesregierung. Berlin: BMWA. BP 2005 BP Statistical Review 2005. Hamburg: 2005. Bundestag 2005 Deutscher Bundestag (2005): Umsetzung des Emissionshandels in Deutsch- land und Europa. In Drucksache 15/5911. Berlin: Deutscher Bundestag. Burchhardt 2005 Burchhardt (2005): The Vattenfall Oxyfuel-Pilot, presentation at Kompetenz- Netzwerk Kraftwerkstechnik NRW, Gelsenkirchen 2005. CIAB 1999 Coal Industry Advisory Board/International Energy Agency: The future role of coal, Paris 1999. CIAB 2004 Coal Industry Advisory Board/International Energy Agency: Reducing Greenhouse Gas Emissions. The Potential of Coal, Paris 2004. CIAB 2005 Coal Industry Advisory Board/International Energy Agency: International Coal Market & Policy Developments in 2004. Paris: CIAB/IEA

COORETEC 2003 COORETEC (2003): CO 2-Reduktions-Technologien, Forschungs- und Ent- wicklungskonzept für emissionsarme fossil befeuerte Kraftwerke. Cooretec. CSLF 2005 Carbon Sequestration Leadership Forum. Washington: CSLF/DOE. Davison 2004 Davison, Thambimuthu: Technologies for Capture of Carbon Dioxide, 2004. Decon 2003 Deutsche Energie-Consult Ingenieurgesellschaft mbH in collaboration with MVV Consultants and Engineers: Study on „Implementing Clean Coal Tech- nologies – Need of Sustained Power Plant Equipment Supply for a Secure Energy Supply” for the European Parliament, 2003.

UBA (2006) Umweltbundeamt,, Verfahren zur CO 2 Abscheidung und Speicherung, Des- sau 2006 DG TREN/NTUA 2003 Mantzos, L. ; Capros, P. ; Kouvaritakis, N. ; Zeka-Paschou, M. (2003) Euro- pean Energy and Transport - Trends to 2030. Luxembourg: EC Office for Of- ficial Publicatins. DG TREN/NTUA 2004 Mantzos, L. ; Capros, P. ; Zeka-Paschou, M. ; Chesshire, J. (2004) Europe- an Energy and Transport Scenarios on Key Drivers. Luxembourg: EC Office for Official Publicatins. DG TREN/NTUA 2006 Mantzos, L. ; Capros, P. et al. (2006) European Energy and Transport - Trends to 2030 (update 2005). DG TREN (available as download onj ).

Dillon 2004 Dillon et al. (2004): Oxy-Combustion Processes for CO 2 Capture from Ad- vanced Supercritical PF and NGCC Power Plant, 2004. DIW/ÖkoI/FH ISI 2005 Ziesing H.-J.; Cames M., et. al. (2005) Implementation of Emissions Trading in th EU: National Allocation Plans of all EU States. Berlin: UBA/DEhSt. EAD 2004 EAD National Electric Company -. (2004) Bulgarian Power Sector Least- Cost Development Plan 2004-2020. Sofia:

ECN 2005 Sijm, J.; Bakker, J. O. S.; Chen, Y.; Harmsen, H. W.; Lise, H. (2005) CO 2 price dynamics: The implications of EU emissions trading for the price of

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electricity. Utrecht: ECN. ECN/PwC 2003 van Dril, T.; Pijnappel, M.; Warmenhoven, H. (2003) Allowance allocation within the Community-wide emissionsallowance trading scheme. Utrecht: ECN/PwC. Ecofys 2004 Ecofys (2004): Global Carbon Dioxide Storage Potential and Costs, Utrecht. ecologic/WI 2004 Langrock, T.; Sterk, T.; Bunse, M. (2004) Linking CDM and JI with EU Emissions Allowance Trading. Berlin: ecologic/WI. EComm 2004a European Commission, DG TREN (2004): EC Directive of 27 October 2004 amending Directive 2003/87/EC establishing a scheme for greenhouse gas emission allowance trading within the Community, in respect of the Kyoto Protocol's project mechanisms (so called Link-ing Directive) Brussels: EC.

EComm 2004b European Commission, DG TREN (2004): European CO 2 Capture and Stor- age Projects, Brussels. 2004. EComm 2004c European Commission, DG TREN (2004): Commission Staff Working Docu- ment, The share of renewable energy in the EU, Country Profiles, Overview of Renewable Energy Sources in the Enlarged European Union, [COM(2004)366 final], Brussels, 26.05.2004 EComm 2005 European Commission COM (2005) 531 final: Communication of the Euro- pean Commission to the European Parliament, the Council, the European Economic and Social Committee and the Committee of the Regions (25 Oc- tober 05) Brussels: EC. EComm 07/10 European Commission, DG TREN (2007): A European approach to nuclear power, safety and security, Brussels, 10.01.2007 EComm 07/13 European Commission, DG TREN (2007): A Renewable Energy Roadmap: paving the way towards a 20% share of renewables in the EU's energy mix by 2020, Brussels, 10.01.2007. ECounc 070215 Council of the European Union (2007): European Council´s conlcusion on Energy policy for Europe, Brussel, 15.02.2007 EIA 2004 International Energy Outlook 2004. Washington: DOE EIA. EIA 2005 International Energy Outlook 2005. Washington: DOE EIA. EPRI 2006 Electric Power Research Institute: CO2 Capture and Storage Test Center: 5 MW Chilled Ammonia Capture Test Pilot, http://www.epriweb.com/public, June 2006. EURACOAL 2005 2nd Coal Dialogue. Brussels: Euracoal. Eurendel 2004 Eurendel Group (IZT, EC BREC, IEFE, Prospektiker, RISOE) (2004) The Eurendel Scenarios - Europe´s Energy System by 2030. Eurendel (Euro- pean Energy Delphi) Eurelectric 2006 Eurelectric (2006) Energy Statistics. Eurelectric. EUROSTAT 2005 Energie: jährliche Statistiken - Data 2003. EUROSTAT. FAZ 2007 Frankfurter Alllgemeine Zeitung: press information, 17.01.2007 Förster w/o y. Förster et al. (no date) Flue Gas Cleanup at Temperatures about 1400°C for a Coal Fired Combined Cycle Power Plant: State and Perspectives in the Pressurized Pulverized Coal Combustion (PPCC) Project.

Gielen 2003 Gielen (2003): The Future Role of CO 2 Capture and Storage. Results of the IEA-ETP Model, Paris 2003. Gielen et. al. 2005 Gielen, Podkanski (2005): The Future Role of CO2 Capture in the Electricity Sector, Paris 2005.

Gupta 2004 Gupta et al. (2004): CO 2 Capture Technologies and Opportunities in Can- ada, “Strawman Document for CO 2 Capture and Storage (CC&S) Technol- ogy Roadmap”, 2004. Harrison/Radov (2002) Harrison, D.; Radov, D. B.: Evaluation of Alternative Initial Allocation Mecha- nisms in GHG Emissions Trading Schemes.

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IAEA 2007 International Atomic Energy Agency: http://www.iaea.or.at/ Power Reactor Information System (2007) IEA (2001a) International Energy Agency /OECD (2001): Nuclear Power Plants in the OECD - Paris: IEA IEA (2001b) International Energy Agency (2001): Energy Policies of IEA Countries - Country Review: Italy. Paris: IEA IEA (2002) International Energy Agency (2002): Energy Policies of IEA Countries - Country Review: France. Paris: IEA IEA (2004a) International Energy Agency (2004): Energy Policies of IEA Countries - 2004 Review. Paris: IEA IEA (2004b) International Energy Agency (2004):Coal Information (2004 Edition) Paris: IEA IEA (2004c) International Energy Agency (2004): World Energy Outlook 2004. Paris: IEA/OECD. IEA (2005a) International Energy Agency (2005): Coal Information (2005 Edition) Paris: IEA IEA (2005b) International Energy Agency (2005):Energy Policies of IEA Countries - Country Review: Spain. Paris: IEA IEA (2005c) International Energy Agency (2005): World Energy Outlook 2005 - Middle East and North Africa Insights. Paris: IEA/OECD. IEA (2006) International Energy Agency (2006): Energy Technology Perspectives - in support of the G8 plan of action. Paris: IEA/OECD. IEA w/o y. International Energy Agency (w/o y.): Emissions Trading and Its Possible Impacts on Investment Decisions in the Power Sector, IEA Information Pa- per, without date. IEA/BGS (2003) International Energy Agency/British Geological Survey (2003): Clean Coal Situation Paper by IEA Greenhouse Gas and the British Geological Survey. IEA Greenhouse Gas / British Geological Survey. IEA CCC 2006 IEA Clean Coal Centre: www.iea-coal.org.uk, 2006.

IEA Greenhouse Gas Ocean Storage of CO 2, 2002. R&D Programme (2002) IER 2004 Swider, D. J.: Background Study - Balancing System of Germany. Stuttgart: IER. IT Power 2004 IT Power (2004) Mariyappan, J. (2004) Background Study - Balancing System of UK: IT Power. IPCC (2005) Intergovernmental Panel on Climate Change: IPCC Special Report on Car- bon Capture and Storage, Cambridge 2005. Johnston, Santillo Carbon Capture and Sequestration: Potential Environmental Impacts. (w/o date)

Jordal et al. (w/o date) Oxyfuel Combustion for Coal-Fired Power Generation with CO 2 Capture – Opportunities and Challenges. Kårstad (w/o date) Geological Storage, Including Cost and Risks, in Saline Aquifers. Kirchner/Rits (2006) Prognos AG: Energieperspektiven für die Schweiz 2035/2050, Szenarien für das Elektrizitätsangebot, Technologie-Assessment: (konventionelle) thermi- sche Kraftwerke, Basel 2006.

Lako (2002) Options for CO 2 Sequestration and Accelerated Fuel Supply. Monograph in the framework of the VLEEM project, 2002. Lako (2004) Coal-fired power technologies. Coal-fired Options on the Brink of Climate Policies, 2004.

LFEE (2003) Laboratory for Energy and the Environment: The Economics of CO 2 Storage, Cambridge 2003. Meyer (2004) IGCC Technologies (Coal Gasification), Presentation at the Congress Inno-

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vative Technologies for Generating Electricity – toward zero emission coal- fired and gas power plants, Berlin 2004. KfW (2005) The KfW Carbon Fund. Frankfurt: KfW. McKinsey (2005) Vahlenkamp, T.; Rittner, F. (2005): European Integrated Energy Perspective and Implications on Thermal Coal. Brussels (Düsseldorf): McKinsey. MMSD (2002) MMSD Mining, Minerals and Sustainble Development: Coal Case Study (A Short Review) MIT (2005) MIT Joint Program on the Science and Policy of Global Change: An Analysis of the European Emissions Trading Scheme: Cambridge MA: MIT NEA 2007 http://www.nea.fr/html/general/profiles/belgium.html Ökoinstitut 2005 Cames, M. (2005) Emissions Trading - Impacts on EU Electricity- Enlargement, DIW & BMWA Workshop, 17-18 February 2005, Berlin. Berlin: prognos 2001 Bohnenschäfer, W.; Taube, S. (2001) Position der Braunkohle in einer nachhaltigen Energiepolitik. prognos 2002 Schlesinger, M.; Scheelhaase, J.; Limbers, J.; Hofer, P. (2002): Die Rolle der Braunkohle in einer wettbewerbsorientierten, nachhaltigen Energiewirtschaft. prognos 2004 Schlesinger, M.; Kirchner, A.; Fahl, U.; Hofer, P.;. (2004) Analyse der Wirk- samkeit von CO 2-Minderungsmaßnahmen im Energiebereich und ihre Wei- terentwicklung. Berlin: Prognos/IER. prognos 2005 Hobohm, J.; Koepp, M.; Peter, F.; Arndt, O.; Steden, P.; (2005) Energie- und regionalwirtschaftliche Bedeutung der Braunkohle in Ostdeutschland. prognos/ewi 2005 Schlesinger, Hofer, P. et. al. (2005) Energiereport IV Basel, Köln: Prog- nos/ewi. prognos 2006 Seefeldt, F.; Sowada, P.; Schlesinger, M. (2006) Future Role of Coal in Europe - Part 1, preliminary report on the actual role of coal in Europe, or- dered and edited by EURACOAL, Brussels. Platts 2005 EU Energy. In Platts (Ed.), EU Energy (Vol. 114/05, pp. 20) London: McGraw-Hill. RAE 2004 Royal Academy of Engineering (2004): The Cost of Generating Electricity, London 2004. Rubin 2004 Rubin et al. (2004): Comparative Assessment of Fossil Fuel Power Plants with CO 2 Capture and Storage, Vancouver 2004. Schuhmacher 2005 Schuhmacher, Sands: Innovative Energy Technologies and Climate Policy in Germany (2005) Berlin. Staiß, F. (2004) Jahrbuch Erneuerbare Energien 2002/03. Radebeul: Bieberstein Fachbuch- verlag. Strömberg (2005) Presentation at the IEA Workshop on Oxyfuel Technology Choice – Bench- marking, Cottbus 2005. tam (2005) TAM Newsletter 28.04.2006: (6) CO 2-Rechte billiger, by Frank Trurnit & Partner Verlag, Ottobrunn Tzimas, Peteves (2003) The Impact of Carbon Sequestration on the Cost of Electricity and Hydrogen in Europe in the Medium Term, Petten 2003. UNFCC 2007 United Nations Framework Convention on Climate Change, National Re- ports, National Inventory Submissions UNICE. (2005) Zusammenfassender Überblick über den Stand Emissionshandel und na- tionale Allokationspläne. Brüssel: VdKI (2005) Jahresbericht 2004, www.verein-kohleimporteure.de, Hamburg WEC (2001) World Energy Council, Survey of Energy Resources, 20 Willenborg et al. (2002) Thermodynamic Properties of Alkali Species in Coal Based Combined Cycle Power Systems.

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8 Appendix C: FRC Figures

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8.1 EU 27 8.1.1 Power Generation

6.000.000 2005 2030 2030 2030 2030 2030 2030 2030 2030 Import 5.000.000 Biomass Res. Other Hydro 4.000.000 Wind Conv. Other Oil (incl. CHP) 3.000.000 Gas (CCS) Gas CHP Gas Hard (CCS) 2.000.000 Hard (incl. CHP)

Power Generation inPower [GWh] Generation Lignite (CCS) Lignite (incl. CHP) 1.000.000 Nuclear

0 Start Base Policy Policy Policy Low Low Tech Tech 5 15 30 45 15 30 30 45 © Prognos 2007 Power Generation [EU 27] [Source: FRC Model, Prognos 07]

5.000.000 Import 4.500.000 Biomass Res. Other 4.000.000 Hydro 3.500.000 Wind Conv. Other 3.000.000 Oil (incl. CHP) 2.500.000 Gas (CCS) Gas CHP 2.000.000 Gas 1.500.000 Hard (CCS) Power Generation in [GWh] Hard (incl. CHP) 1.000.000 Lignite (CCS) 500.000 Lignite (incl. CHP) Nuclear 0 2005 2010 2015 2020 2025 2030 © Prognos 2007

Power Generation [EU 27, Base 5] [Source: FRC Model, Prognos 07]

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Power Generation [EU 27, Policy 15] [Source: FRC Model, Prognos 07]

Power Generation [EU 27, Policy 30] [Source: FRC Model, Prognos 07]

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Power Generation [EU 27, Policy 45] [Source: FRC Model, Prognos 07]

Power Generation [EU 27, LowPrice 15] [Source: FRC Model, Prognos 07]

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Power Generation [EU 27, LowPrice 30] [Source: FRC Model, Prognos 07]

Power Generation [EU 27, Tech 30] [Source: FRC Model, Prognos 07]

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Power Generation [EU 27, Tech 45 [Source: FRC Model, Prognos 07]

8.1.2 Generation Capacities

1.200.000 2005 2030 2030 2030 20302030 2030 2030 2030 Import 1.000.000 Biomass Res. Other Hydro 800.000 Wind Conv. Other Oil (incl. CHP) 600.000 Gas (CCS) Gas CHP Gas Hard (CCS) Capacities Capacities in [MW] 400.000 Hard (incl. CHP) Lignite (CCS) Lignite (incl. CHP) 200.000 Nuclear

0 Start Base Policy Policy Policy Low Low Tech Tech © Prognos 2007 5 15 30 45 15 30 30 45 Generation Capacities [EU 27] [Source: FRC Model, Prognos 07]

page 115

8.1.3 Primary Energy Input

1.400.000 2005 20302030 20302030 2030 2030 2030 2030

1.200.000 Import Biomass Res. Other 1.000.000 Hydro Wind Conv. Other 800.000 Oil (incl. CHP) Gas (CCS) Gas CHP 600.000 Gas Hard (CCS) Hard (incl. CHP) 400.000

Primaryin Energy Input [ktce] Lignite (CCS) Lignite (incl. CHP) 200.000 Nuclear

0 Start Base Policy Policy Policy Low Low Tech Tech © Prognos 2007 5 15 30 45 15 30 30 45 Primary Enery Input [EU 27] [Source: FRC Model, Prognos 07]

8.1.4 CO 2 Emissions

2.250.000 1990 20052030 2030 2030 2030 2030 2030 2030 2030 2.000.000 Biomass 1.750.000 Res. Other Hydro Wind 1.500.000 Conv. Other Oil (incl. CHP) 1.250.000 Gas (CCS) Gas CHP 1.000.000 Gas Hard (CCS) 750.000 Hard (incl. CHP) Lignite (CCS) Carbon Emissions inCarbon Emissions CO2] [kt 500.000 Lignite (incl. CHP) Nuclear 250.000

0 Start Base Policy Policy Policy Low Low Tech Tech © Prognos 2007 5 15 30 45 15 30 30 45 Carbon Emissions [EU 27] [Source: FRC Model, Prognos 07; UNFCC 2007]

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8.1.5 Cost of Power Generation

400.000 2005 2030 20302030 20302030 2030 2030 2030 350.000 Biomass Res. Other 300.000 Hydro Wind 250.000 Conv. Other Oil (incl. CHP) Gas (CCS) 200.000 Gas CHP Gas 150.000 Hard (CCS) Hard (incl. CHP) Lignite (CCS) 100.000 Lignite (incl. CHP) Nuclear

Costs ofinPower [million Generation EUR] 50.000

0 Start Base Policy Policy Policy Low Low Tech Tech © Prognos 2007 5 15 30 45 15 30 30 45 Cost of Power Generation [EU 27] [Source: FRC Model, Prognos 07]

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9 Appendix D: FRC Results Tables

page 118

EU27: BASE-5 9.1 EU27 2005 2010 2015 2020 2025 2030 Generation capacities in MW 728'736 800'788 873'475 905'966 945'903 991'364 Nuclear 139'549 136'363 128'226 106'971 61'337 38'277 Lignite (incl. CHP) 53'500 58'491 56'680 52'093 63'520 69'181 Lignite (CCS) ------Hard (incl. CHP) 119'723 139'717 164'742 192'459 256'010 320'810 Hard (CCS) ------Gas 135'777 152'757 174'923 165'151 127'133 90'267 Gas CHP 34'669 42'235 50'448 58'509 63'924 68'800 Gas (CCS) ------Oil (incl. CHP) 72'741 58'577 41'707 25'205 8'502 6'415 Conv. Other ------Wind 45'930 78'805 104'166 128'955 165'780 184'502 Hydro 107'327 110'973 114'152 116'523 119'246 120'787 Res. Other 2'287 2'995 4'311 6'367 8'918 12'079 Biomass 17'234 19'875 34'118 53'731 71'535 80'246 Import 8'035 7'716 7'400 6'682 6'293 6'112 ------Power Generation in GWh 3'444'413 3'693'975 3'990'655 4'246'322 4'466'653 4'641'543 Nuclear 917'509 901'200 848'878 717'185 416'738 261'771 Lignite (incl. CHP) 375'963 395'913 384'287 377'031 476'779 499'748 Lignite (CCS) ------Hard (incl. CHP) 760'505 818'110 948'145 1'186'829 1'559'848 1'811'226 Hard (CCS) ------Gas 274'496 329'365 330'672 234'108 79'246 18'007 Gas CHP 329'191 385'323 459'636 534'335 583'514 630'418 Gas (CCS) ------Oil (incl. CHP) 62'486 56'626 55'503 50'693 42'609 35'023 Conv. Other ------Wind 65'251 113'706 150'184 181'319 208'340 210'434 Hydro 470'082 486'060 500'031 510'526 522'861 531'959 Res. Other 2'003 2'624 3'776 5'575 7'808 10'658 Biomass 128'323 147'995 254'070 399'940 532'611 600'885 Import 58'606 57'054 55'472 48'779 36'300 31'416 ------Primary Energy Demand in ktce 967'150 998'877 1'042'313 1'076'075 1'077'837 1'091'584 Nuclear 343'281 336'503 314'459 261'781 146'563 88'833 Lignite (incl. CHP) 119'689 121'875 113'478 107'459 128'502 132'301 Lignite (CCS) ------Hard (incl. CHP) 230'729 231'312 252'098 306'958 387'670 442'387 Hard (CCS) ------Gas 61'065 71'158 68'785 47'423 15'864 3'579 Gas CHP 78'327 87'260 99'535 111'376 118'088 124'867 Gas (CCS) ------Oil (incl. CHP) 19'232 17'436 16'774 15'113 12'512 10'268 Conv. Other ------Wind 8'007 13'959 18'442 22'275 25'595 25'852 Hydro 48'598 55'136 61'429 62'718 64'234 65'351 Res. Other 224 315 452 656 939 1'291 Biomass 50'799 56'914 90'047 134'328 173'412 192'994 Import 7'200 7'009 6'815 5'987 4'460 3'859 ------

Carbon Output in kt CO 2 1'274'949 1'310'469 1'354'020 1'463'393 1'702'808 1'848'703 Nuclear ------Lignite (incl. CHP) 385'850 392'858 365'788 346'388 414'217 426'465 Lignite (CCS) ------Hard (incl. CHP) 621'662 623'233 679'238 827'049 1'044'516 1'191'941 Hard (CCS) ------Gas 98'916 115'277 111'422 76'818 25'698 5'798 Gas CHP 126'879 141'349 161'232 180'414 191'286 202'267 Gas (CCS) ------Oil (incl. CHP) 41'642 37'752 36'340 32'724 27'092 22'232 Conv. Other ------Wind ------Hydro ------Res. Other ------Biomass ------Cost Power Generation in Mio EUR 167'671 184'318 213'837 235'349 255'352 270'870 Nuclear 38'970 38'889 38'023 34'558 22'458 13'892 Lignite (incl. CHP) 9'689 10'892 11'153 11'611 15'349 16'438 Lignite (CCS) ------Hard (incl. CHP) 28'199 29'379 37'934 49'598 68'511 83'045 Hard (CCS) ------Gas 23'220 25'440 27'826 22'584 12'893 7'223 Gas CHP 15'844 16'980 21'261 24'799 28'385 32'170 Gas (CCS) ------Oil (incl. CHP) 9'113 8'611 7'985 6'047 4'062 3'607 Conv. Other ------Wind 6'672 11'194 14'501 17'557 22'069 23'762 Hydro 27'594 33'296 39'634 45'080 50'736 55'867 Res. Other 915 1'170 1'606 2'311 3'139 4'054 Biomass 7'455 8'468 13'914 21'203 27'750 30'811 Source: Prognos 2007 page 119

EU27: POLICY-15 2005 2010 2015 2020 2025 2030 Generation capacities in MW 728'736 801'213 873'375 906'666 946'278 991'539 Nuclear 139'549 136'363 128'226 106'971 61'337 38'277 Lignite (incl. CHP) 53'500 57'266 53'080 48'968 63'720 68'431 Lignite (CCS) ------Hard (incl. CHP) 119'723 140'467 166'142 194'184 254'085 319'635 Hard (CCS) ------Gas 135'777 153'657 177'023 167'251 129'233 92'367 Gas CHP 34'669 42'235 50'448 58'509 63'924 68'800 Gas (CCS) ------Oil (incl. CHP) 72'741 58'577 41'707 25'205 8'502 6'415 Conv. Other ------Wind 45'930 78'805 104'166 128'955 165'780 184'502 Hydro 107'327 110'973 114'152 116'523 119'246 120'787 Res. Other 2'287 2'995 4'311 6'367 8'918 12'079 Biomass 17'234 19'875 34'118 53'731 71'535 80'246 Import 8'035 7'716 7'400 6'682 6'293 6'112 ------Power Generation in GWh 3'444'351 3'693'884 3'990'472 4'246'383 4'466'686 4'641'653 Nuclear 917'520 901'265 849'975 723'011 424'379 266'324 Lignite (incl. CHP) 366'643 360'346 347'072 345'690 468'049 493'452 Lignite (CCS) ------Hard (incl. CHP) 769'434 841'686 972'496 1'194'307 1'547'640 1'791'019 Hard (CCS) ------Gas 274'921 340'592 340'566 244'587 79'952 18'904 Gas CHP 329'191 385'523 459'434 534'335 583'514 630'420 Gas (CCS) ------Oil (incl. CHP) 62'389 56'747 55'501 50'693 42'609 35'023 Conv. Other ------Wind 65'108 113'866 151'681 187'522 218'579 228'886 Hydro 470'082 486'060 500'031 510'526 522'861 531'959 Res. Other 2'003 2'624 3'776 5'575 7'808 10'658 Biomass 128'323 147'995 254'070 399'940 532'611 600'885 Import 58'738 57'181 55'869 50'198 38'685 34'124 ------Primary Energy Demand in ktce 966'780 997'587 1'040'370 1'073'959 1'076'180 1'088'871 Nuclear 343'285 336'528 314'867 263'934 149'335 90'369 Lignite (incl. CHP) 116'694 111'122 102'576 98'382 125'432 129'992 Lignite (CCS) ------Hard (incl. CHP) 233'285 238'274 258'422 308'696 384'618 437'668 Hard (CCS) ------Gas 61'161 73'505 70'824 49'557 16'006 3'759 Gas CHP 78'327 87'318 99'481 111'376 118'088 124'868 Gas (CCS) ------Oil (incl. CHP) 19'201 17'472 16'783 15'113 12'512 10'268 Conv. Other ------Wind 7'989 13'980 18'626 23'037 26'853 28'119 Hydro 48'598 55'136 61'429 62'718 64'234 65'351 Res. Other 224 315 452 656 939 1'291 Biomass 50'799 56'914 90'047 134'328 173'412 192'994 Import 7'216 7'025 6'863 6'161 4'752 4'192 ------

Carbon Output in kt CO 2 1'272'264 1'298'527 1'339'133 1'442'273 1'684'921 1'828'836 Nuclear ------Lignite (incl. CHP) 376'188 358'194 330'647 317'128 404'324 419'020 Lignite (CCS) ------Hard (incl. CHP) 628'550 641'992 696'277 831'731 1'036'293 1'179'227 Hard (CCS) ------Gas 99'072 119'067 114'725 80'276 25'927 6'088 Gas CHP 126'879 141'442 161'146 180'414 191'286 202'268 Gas (CCS) ------Oil (incl. CHP) 41'575 37'831 36'339 32'724 27'092 22'232 Conv. Other ------Wind ------Hydro ------Res. Other ------Biomass ------Cost Power Generation in Mio EUR 168'650 186'007 217'507 242'833 267'901 288'450 Nuclear 38'970 38'890 38'040 34'654 22'585 13'967 Lignite (incl. CHP) 9'547 10'933 11'471 12'666 18'399 20'484 Lignite (CCS) ------Hard (incl. CHP) 29'240 30'428 40'182 54'018 75'934 94'006 Hard (CCS) ------Gas 23'304 26'021 28'592 23'550 13'265 7'478 Gas CHP 15'844 16'988 21'521 25'601 29'766 34'193 Gas (CCS) ------Oil (incl. CHP) 9'109 8'619 8'046 6'193 4'257 3'829 Conv. Other ------Wind 6'672 11'194 14'501 17'557 22'069 23'762 Hydro 27'594 33'296 39'634 45'080 50'736 55'867 Res. Other 915 1'170 1'606 2'311 3'139 4'054 Biomass 7'455 8'468 13'914 21'203 27'750 30'811 Source: Prognos 2007 page 120

EU 27: POLICY-30 2005 2010 2015 2020 2025 2030 Generation capacities in MW 728'736 801'988 874'200 908'191 949'878 1'003'289 Nuclear 139'549 136'363 128'226 106'971 61'337 57'477 Lignite (incl. CHP) 53'500 55'841 51'180 42'793 48'045 54'381 Lignite (CCS) ------Hard (incl. CHP) 119'723 104'567 115'767 135'584 193'260 243'735 Hard (CCS) ------Gas 135'777 191'757 230'123 233'551 209'333 174'867 Gas CHP 34'669 42'235 50'448 58'509 63'924 68'800 Gas (CCS) ------Oil (incl. CHP) 72'741 58'577 41'707 25'205 8'502 6'415 Conv. Other ------Wind 45'930 78'805 104'166 128'955 165'780 184'502 Hydro 107'327 110'973 114'152 116'523 119'246 120'787 Res. Other 2'287 2'995 4'311 6'367 8'918 12'079 Biomass 17'234 19'875 34'118 53'731 71'535 80'246 Import 8'035 7'716 7'400 6'682 6'293 6'112 ------Power Generation in GWh 3'443'684 3'693'498 3'992'889 4'247'628 4'466'113 4'640'590 Nuclear 917'550 901'223 850'169 723'169 424'455 433'172 Lignite (incl. CHP) 301'936 260'779 299'828 283'582 347'925 389'767 Lignite (CCS) ------Hard (incl. CHP) 618'130 582'257 723'086 925'530 1'317'847 1'469'158 Hard (CCS) ------Gas 490'568 700'838 636'502 566'674 391'278 223'714 Gas CHP 329'258 386'154 459'439 534'335 583'514 630'424 Gas (CCS) ------Oil (incl. CHP) 62'801 56'565 55'564 50'693 42'609 35'023 Conv. Other ------Wind 64'294 112'147 154'079 196'051 246'810 269'981 Hydro 470'082 486'060 500'031 510'526 522'861 531'959 Res. Other 2'003 2'624 3'776 5'575 7'808 10'658 Biomass 128'323 147'995 254'070 399'940 532'611 600'885 Import 58'742 56'857 56'345 51'552 48'395 45'850 ------Primary Energy Demand in ktce 943'289 968'112 1'022'734 1'054'932 1'053'302 1'085'046 Nuclear 343'296 336'511 314'939 263'994 149'363 145'133 Lignite (incl. CHP) 94'085 77'642 87'657 81'304 93'669 102'681 Lignite (CCS) ------Hard (incl. CHP) 185'998 167'139 194'411 240'423 326'812 359'576 Hard (CCS) ------Gas 107'515 148'815 131'670 114'607 78'009 44'082 Gas CHP 78'342 87'469 99'483 111'376 118'088 124'869 Gas (CCS) ------Oil (incl. CHP) 19'327 17'417 16'802 15'113 12'512 10'268 Conv. Other ------Wind 7'889 13'769 18'921 24'085 30'321 33'167 Hydro 48'598 55'136 61'429 62'718 64'234 65'351 Res. Other 224 315 452 656 939 1'291 Biomass 50'799 56'914 90'047 134'328 173'412 192'994 Import 7'216 6'985 6'922 6'327 5'945 5'633 ------

Carbon Output in kt CO 2 1'147'343 1'121'063 1'217'184 1'308'646 1'527'218 1'595'730 Nuclear ------Lignite (incl. CHP) 303'292 250'273 282'557 262'080 301'935 330'988 Lignite (CCS) ------Hard (incl. CHP) 501'142 450'330 523'811 647'780 880'542 968'819 Hard (CCS) ------Gas 174'159 241'059 213'287 185'648 126'363 71'422 Gas CHP 126'903 141'688 161'148 180'414 191'286 202'270 Gas (CCS) ------Oil (incl. CHP) 41'847 37'712 36'381 32'724 27'092 22'232 Conv. Other ------Wind ------Hydro ------Res. Other ------Biomass ------Cost Power Generation in Mio EUR 172'923 192'288 225'340 255'635 287'614 314'511 Nuclear 38'970 38'890 38'043 34'656 22'586 23'251 Lignite (incl. CHP) 8'652 10'042 11'957 12'998 17'706 21'350 Lignite (CCS) ------Hard (incl. CHP) 23'972 20'925 30'173 44'170 71'152 88'188 Hard (CCS) ------Gas 33'715 42'690 45'446 44'445 36'087 25'838 Gas CHP 15'846 17'007 21'924 26'804 31'839 37'227 Gas (CCS) ------Oil (incl. CHP) 9'132 8'607 8'141 6'411 4'551 4'163 Conv. Other ------Wind 6'672 11'194 14'501 17'557 22'069 23'762 Hydro 27'594 33'296 39'634 45'080 50'736 55'867 Res. Other 915 1'170 1'606 2'311 3'139 4'054 Biomass 7'455 8'468 13'914 21'203 27'750 30'811 Source: Prognos 2007 page 121

EU27: POLICY-45 2005 2010 2015 2020 2025 2030 Generation capacities in MW 728'736 802'888 876'000 909'016 952'053 1'008'790 Nuclear 139'549 136'363 128'226 106'971 61'337 67'077 Lignite (incl. CHP) 53'500 52'991 48'330 39'943 32'370 32'531 Lignite (CCS) - - - - - 1'901 Hard (incl. CHP) 119'723 97'817 98'517 90'659 85'410 94'285 Hard (CCS) ------Gas 135'777 202'257 252'023 282'151 335'033 340'167 Gas CHP 34'669 42'235 50'448 58'509 63'924 68'800 Gas (CCS) ------Oil (incl. CHP) 72'741 58'577 41'707 25'205 8'502 6'415 Conv. Other ------Wind 45'930 78'805 104'166 128'955 165'780 184'502 Hydro 107'327 110'973 114'152 116'523 119'246 120'787 Res. Other 2'287 2'995 4'311 6'367 8'918 12'079 Biomass 17'234 19'875 34'118 53'731 71'535 80'246 Import 8'035 7'716 7'400 6'682 6'293 6'112 ------Power Generation in GWh 3'442'695 3'692'291 3'992'118 4'249'528 4'466'168 4'641'062 Nuclear 917'592 901'203 850'010 723'171 457'337 510'093 Lignite (incl. CHP) 208'606 173'446 174'161 174'783 198'223 231'235 Lignite (CCS) - - - - - 28'306 Hard (incl. CHP) 465'947 374'358 467'797 481'483 667'314 715'815 Hard (CCS) ------Gas 739'063 1'003'906 1'023'958 1'120'457 1'140'051 1'005'623 Gas CHP 330'038 387'072 460'139 534'443 583'690 630'452 Gas (CCS) ------Oil (incl. CHP) 62'921 56'648 55'544 50'693 42'609 35'023 Conv. Other ------Wind 61'470 104'912 148'191 196'664 263'626 292'388 Hydro 470'082 486'060 500'031 510'526 522'861 531'959 Res. Other 2'003 2'624 3'776 5'575 7'808 10'658 Biomass 128'323 147'995 254'070 399'940 532'611 600'885 Import 56'652 54'069 54'439 51'791 50'038 48'626 ------Primary Energy Demand in ktce 919'989 944'808 992'465 1'018'564 1'017'017 1'052'902 Nuclear 343'313 336'504 314'879 263'995 160'180 170'414 Lignite (incl. CHP) 63'559 50'488 49'153 48'840 54'798 62'776 Lignite (CCS) - - - - - 7'518 Hard (incl. CHP) 136'944 105'679 123'182 124'477 169'651 179'697 Hard (CCS) ------Gas 164'149 215'106 212'002 226'520 224'634 195'824 Gas CHP 78'534 87'700 99'641 111'399 118'124 124'874 Gas (CCS) ------Oil (incl. CHP) 19'365 17'443 16'792 15'113 12'512 10'268 Conv. Other ------Wind 7'544 12'881 18'199 24'160 32'387 35'920 Hydro 48'598 55'136 61'429 62'718 64'234 65'351 Res. Other 224 315 452 656 939 1'291 Biomass 50'799 56'914 90'047 134'328 173'412 192'994 Import 6'960 6'642 6'688 6'356 6'147 5'974 ------

Carbon Output in kt CO 2 1'008'910 975'752 1'031'539 1'072'926 1'216'047 1'230'662 Nuclear ------Lignite (incl. CHP) 204'895 162'744 158'442 157'434 176'637 202'356 Lignite (CCS) - - - - - 2'423 Hard (incl. CHP) 368'974 284'736 331'918 335'384 457'098 484'164 Hard (CCS) ------Gas 265'898 348'442 343'414 366'931 363'875 317'207 Gas CHP 127'214 142'061 161'405 180'452 191'344 202'279 Gas (CCS) ------Oil (incl. CHP) 41'929 37'768 36'359 32'724 27'092 22'232 Conv. Other ------Wind ------Hydro ------Res. Other ------Biomass ------Cost Power Generation in Mio EUR 178'485 198'314 235'152 269'643 307'639 338'623 Nuclear 38'971 38'889 38'041 34'656 24'450 27'595 Lignite (incl. CHP) 7'150 8'592 9'660 10'948 12'866 15'908 Lignite (CCS) - - - - - 1'369 Hard (incl. CHP) 19'561 15'136 22'402 27'169 39'885 48'046 Hard (CCS) ------Gas 45'157 55'919 64'812 76'080 87'980 86'453 Gas CHP 15'872 17'039 22'352 28'011 33'918 40'263 Gas (CCS) ------Oil (incl. CHP) 9'138 8'612 8'230 6'629 4'845 4'496 Conv. Other ------Wind 6'672 11'194 14'501 17'557 22'069 23'762 Hydro 27'594 33'296 39'634 45'080 50'736 55'867 Res. Other 915 1'170 1'606 2'311 3'139 4'054 Biomass 7'455 8'468 13'914 21'203 27'750 30'811 Source: Prognos 2007 page 122

EU27: LOWPRICE-15 2005 2010 2015 2020 2025 2030 Generation capacities in MW 728'736 801'988 874'800 907'291 949'603 999'164 Nuclear 139'549 136'363 128'226 106'971 61'337 38'277 Lignite (incl. CHP) 53'500 58'216 53'555 48'018 63'245 66'731 Lignite (CCS) ------Hard (incl. CHP) 119'723 127'392 132'592 141'459 182'285 231'760 Hard (CCS) ------Gas 135'777 166'557 211'523 221'551 204'833 189'567 Gas CHP 34'669 42'235 50'448 58'509 63'924 68'800 Gas (CCS) ------Oil (incl. CHP) 72'741 58'577 41'707 25'205 8'502 6'415 Conv. Other ------Wind 45'930 78'805 104'166 128'955 165'780 184'502 Hydro 107'327 110'973 114'152 116'523 119'246 120'787 Res. Other 2'287 2'995 4'311 6'367 8'918 12'079 Biomass 17'234 19'875 34'118 53'731 71'535 80'246 Import 8'035 7'716 7'400 6'682 6'293 6'112 ------Power Generation in GWh 3'444'394 3'693'359 3'990'322 4'245'913 4'466'745 4'641'771 Nuclear 917'520 901'188 849'999 723'075 424'438 266'390 Lignite (incl. CHP) 366'642 317'935 331'189 327'504 458'763 503'872 Lignite (CCS) ------Hard (incl. CHP) 763'668 524'682 706'999 889'587 1'188'779 1'403'023 Hard (CCS) ------Gas 280'436 705'612 620'785 560'460 428'293 373'460 Gas CHP 329'191 386'284 459'462 534'335 583'514 630'424 Gas (CCS) ------Oil (incl. CHP) 62'694 56'541 55'609 50'693 42'609 35'023 Conv. Other ------Wind 65'099 109'496 152'630 192'378 231'713 245'509 Hydro 470'082 486'060 500'031 510'526 522'861 531'959 Res. Other 2'003 2'624 3'776 5'575 7'808 10'658 Biomass 128'323 147'995 254'070 399'940 532'611 600'885 Import 58'738 54'942 55'771 51'839 45'356 40'569 ------Primary Energy Demand in ktce 966'519 965'827 1'021'842 1'056'689 1'056'595 1'070'191 Nuclear 343'285 336'498 314'875 263'959 149'357 90'391 Lignite (incl. CHP) 116'693 95'881 97'155 93'242 122'682 132'508 Lignite (CCS) ------Hard (incl. CHP) 231'749 144'952 187'665 232'179 296'520 344'730 Hard (CCS) ------Gas 62'344 151'022 128'321 113'122 84'814 72'643 Gas CHP 78'327 87'506 99'488 111'376 118'088 124'868 Gas (CCS) ------Oil (incl. CHP) 19'295 17'410 16'816 15'113 12'512 10'268 Conv. Other ------Wind 7'988 13'443 18'743 23'634 28'466 30'161 Hydro 48'598 55'136 61'429 62'718 64'234 65'351 Res. Other 224 315 452 656 939 1'291 Biomass 50'799 56'914 90'047 134'328 173'412 192'994 Import 7'216 6'750 6'852 6'363 5'572 4'984 ------

Carbon Output in kt CO 2 1'270'244 1'123'696 1'224'236 1'322'509 1'550'150 1'698'126 Nuclear ------Lignite (incl. CHP) 376'187 309'067 313'172 300'561 395'459 427'133 Lignite (CCS) ------Hard (incl. CHP) 624'411 390'549 505'634 625'569 798'926 928'821 Hard (CCS) ------Gas 100'988 244'635 207'861 183'241 137'386 117'671 Gas CHP 126'879 141'747 161'156 180'414 191'286 202'269 Gas (CCS) ------Oil (incl. CHP) 41'779 37'698 36'411 32'724 27'092 22'232 Conv. Other ------Wind ------Hydro ------Res. Other ------Biomass ------Cost Power Generation in Mio EUR 166'880 177'072 202'363 225'449 248'435 266'304 Nuclear 38'970 38'889 38'041 34'655 22'586 13'968 Lignite (incl. CHP) 9'528 10'234 11'076 11'945 17'635 20'065 Lignite (CCS) ------Hard (incl. CHP) 28'994 20'879 27'887 36'041 52'189 65'394 Hard (CCS) ------Gas 22'835 32'869 33'704 33'430 28'661 26'340 Gas CHP 15'065 12'671 15'487 18'593 21'029 23'800 Gas (CCS) ------Oil (incl. CHP) 8'853 7'403 6'514 4'633 2'642 2'245 Conv. Other ------Wind 6'672 11'194 14'501 17'557 22'069 23'762 Hydro 27'594 33'296 39'634 45'080 50'736 55'867 Res. Other 915 1'170 1'606 2'311 3'139 4'054 Biomass 7'455 8'468 13'914 21'203 27'750 30'811 Source: Prognos 2007 page 123

EU27: LOWPRICE-30 2005 2010 2015 2020 2025 2030 Generation capacities in MW 728'736 803'738 877'300 911'157 951'647 1'001'261 Nuclear 139'549 136'363 128'226 106'971 61'337 46'277 Lignite (incl. CHP) 53'500 54'891 50'230 41'843 34'270 29'681 Lignite (CCS) ------Hard (incl. CHP) 119'723 98'567 98'517 88'501 69'004 64'907 Hard (CCS) ------Gas 135'777 200'457 251'423 284'551 349'133 387'567 Gas CHP 34'669 42'235 50'448 58'509 63'924 68'800 Gas (CCS) ------Oil (incl. CHP) 72'741 58'577 41'707 25'205 8'502 6'415 Conv. Other ------Wind 45'930 78'805 104'166 128'955 165'780 184'502 Hydro 107'327 110'973 114'152 116'523 119'246 120'787 Res. Other 2'287 2'995 4'311 6'367 8'918 12'079 Biomass 17'234 19'875 34'118 53'731 71'535 80'246 Import 8'035 7'716 7'400 6'682 6'293 6'112 ------Power Generation in GWh 3'443'351 3'692'327 3'990'876 4'247'622 4'466'378 4'641'187 Nuclear 917'570 901'319 849'951 722'707 424'443 355'826 Lignite (incl. CHP) 275'368 194'810 149'257 130'205 102'528 120'120 Lignite (CCS) ------Hard (incl. CHP) 559'334 277'373 338'637 341'970 321'468 378'602 Hard (CCS) ------Gas 576'407 1'088'741 1'201'243 1'331'535 1'640'438 1'651'689 Gas CHP 329'414 387'105 460'808 534'714 583'898 630'502 Gas (CCS) ------Oil (incl. CHP) 62'870 58'080 55'544 51'353 42'608 35'023 Conv. Other ------Wind 63'779 98'063 128'660 172'190 241'762 278'869 Hydro 470'082 486'060 500'031 510'526 522'861 531'959 Res. Other 2'003 2'624 3'776 5'575 7'808 10'658 Biomass 128'323 147'995 254'070 399'940 532'611 600'885 Import 58'200 50'159 48'898 46'907 45'954 47'055 ------Primary Energy Demand in ktce 934'340 942'429 985'229 1'009'314 987'545 1'003'954 Nuclear 343'304 336'548 314'857 263'819 149'359 119'724 Lignite (incl. CHP) 85'332 56'719 41'985 36'124 27'910 32'382 Lignite (CCS) ------Hard (incl. CHP) 166'735 77'099 88'105 87'390 81'340 95'292 Hard (CCS) ------Gas 126'644 235'908 249'954 270'592 324'326 321'727 Gas CHP 78'379 87'706 99'801 111'463 118'169 124'884 Gas (CCS) ------Oil (incl. CHP) 19'348 17'883 16'792 15'314 12'512 10'268 Conv. Other ------Wind 7'826 12'040 15'801 21'154 29'701 34'259 Hydro 48'598 55'136 61'429 62'718 64'234 65'351 Res. Other 224 315 452 656 939 1'291 Biomass 50'799 56'914 90'047 134'328 173'412 192'994 Import 7'150 6'162 6'007 5'757 5'645 5'781 ------

Carbon Output in kt CO 2 1'098'321 953'501 975'632 1'003'935 1'053'007 1'106'846 Nuclear ------Lignite (incl. CHP) 275'077 182'840 135'336 116'443 89'965 104'403 Lignite (CCS) ------Hard (incl. CHP) 449'241 207'731 237'384 235'459 219'170 256'762 Hard (CCS) ------Gas 205'145 382'138 404'891 438'320 525'363 521'153 Gas CHP 126'963 142'071 161'663 180'555 191'417 202'295 Gas (CCS) ------Oil (incl. CHP) 41'894 38'720 36'359 33'158 27'092 22'232 Conv. Other ------Wind ------Hydro ------Res. Other ------Biomass ------Cost Power Generation in Mio EUR 171'822 180'495 210'062 237'097 262'476 284'107 Nuclear 38'971 38'891 38'040 34'649 22'586 18'966 Lignite (incl. CHP) 8'188 8'620 8'479 8'573 7'682 8'264 Lignite (CCS) ------Hard (incl. CHP) 21'958 12'971 17'189 19'043 18'559 21'795 Hard (CCS) ------Gas 36'135 45'731 54'177 63'989 83'909 91'172 Gas CHP 15'072 12'687 15'921 19'806 23'112 26'836 Gas (CCS) ------Oil (incl. CHP) 8'863 7'467 6'602 4'886 2'935 2'579 Conv. Other ------Wind 6'672 11'194 14'501 17'557 22'069 23'762 Hydro 27'594 33'296 39'634 45'080 50'736 55'867 Res. Other 915 1'170 1'606 2'311 3'139 4'054 Biomass 7'455 8'468 13'914 21'203 27'750 30'811 Source: Prognos 2007 page 124

EU27: TECH-30 2005 2010 2015 2020 2025 2030 Generation capacities in MW 728'736 801'988 874'200 907'966 950'653 1'002'618 Nuclear 139'549 136'363 128'226 106'971 61'337 55'877 Lignite (incl. CHP) 53'500 55'841 51'180 42'793 48'045 46'306 Lignite (CCS) - - - - - 14'229 Hard (incl. CHP) 119'723 104'567 115'767 135'359 193'135 237'910 Hard (CCS) ------Gas 135'777 191'757 230'123 233'551 210'233 175'467 Gas CHP 34'669 42'235 50'448 58'509 63'924 68'800 Gas (CCS) ------Oil (incl. CHP) 72'741 58'577 41'707 25'205 8'502 6'415 Conv. Other ------Wind 45'930 78'805 104'166 128'955 165'780 184'502 Hydro 107'327 110'973 114'152 116'523 119'246 120'787 Res. Other 2'287 2'995 4'311 6'367 8'918 12'079 Biomass 17'234 19'875 34'118 53'731 71'535 80'246 Import 8'035 7'716 7'400 6'682 6'293 6'112 ------Power Generation in GWh 3'443'684 3'693'498 3'992'890 4'247'656 4'466'001 4'638'716 Nuclear 917'550 901'223 850'169 723'235 424'468 425'069 Lignite (incl. CHP) 301'936 260'779 299'822 284'975 343'647 327'927 Lignite (CCS) - - - - 7'076 115'577 Hard (incl. CHP) 618'130 582'257 723'143 922'895 1'323'923 1'424'744 Hard (CCS) ------Gas 490'568 700'838 636'437 569'408 386'445 223'121 Gas CHP 329'258 386'154 459'440 534'335 583'515 630'424 Gas (CCS) ------Oil (incl. CHP) 62'801 56'565 55'564 50'693 42'609 35'023 Conv. Other ------Wind 64'294 112'147 154'141 194'389 243'402 267'354 Hydro 470'082 486'060 500'031 510'526 522'861 531'959 Res. Other 2'003 2'624 3'776 5'575 7'808 10'658 Biomass 128'323 147'995 254'070 399'940 532'611 600'885 Import 58'742 56'857 56'296 51'683 47'636 45'977 ------Primary Energy Demand in ktce 943'289 968'112 1'022'736 1'055'181 1'054'504 1'086'836 Nuclear 343'296 336'511 314'939 264'019 149'368 141'539 Lignite (incl. CHP) 94'085 77'642 87'655 81'714 92'739 87'398 Lignite (CCS) - - - - 1'973 31'491 Hard (incl. CHP) 185'998 167'139 194'428 239'883 328'466 349'067 Hard (CCS) ------Gas 107'515 148'815 131'656 115'150 77'020 44'074 Gas CHP 78'342 87'469 99'483 111'376 118'088 124'868 Gas (CCS) ------Oil (incl. CHP) 19'327 17'417 16'802 15'113 12'512 10'268 Conv. Other ------Wind 7'889 13'769 18'929 23'881 29'902 32'844 Hydro 48'598 55'136 61'429 62'718 64'234 65'351 Res. Other 224 315 452 656 939 1'291 Biomass 50'799 56'914 90'047 134'328 173'412 192'994 Import 7'216 6'985 6'916 6'343 5'852 5'648 ------

Carbon Output in kt CO 2 1'147'343 1'121'063 1'217'200 1'309'390 1'527'713 1'528'274 Nuclear ------Lignite (incl. CHP) 303'292 250'273 282'552 263'399 298'939 281'722 Lignite (CCS) - - - - 636 10'151 Hard (incl. CHP) 501'142 450'330 523'855 646'327 884'998 940'505 Hard (CCS) ------Gas 174'159 241'059 213'264 186'526 124'761 71'394 Gas CHP 126'903 141'688 161'148 180'414 191'286 202'269 Gas (CCS) ------Oil (incl. CHP) 41'847 37'712 36'381 32'724 27'092 22'232 Conv. Other ------Wind ------Hydro ------Res. Other ------Biomass ------Cost Power Generation in Mio EUR 172'923 192'288 225'339 255'622 287'652 313'218 Nuclear 38'970 38'890 38'043 34'657 22'586 22'757 Lignite (incl. CHP) 8'652 10'042 11'957 13'034 17'458 18'140 Lignite (CCS) - - - - 322 4'758 Hard (incl. CHP) 23'972 20'925 30'174 43'969 71'323 85'837 Hard (CCS) ------Gas 33'715 42'690 45'443 44'596 35'879 25'843 Gas CHP 15'846 17'007 21'924 26'804 31'839 37'227 Gas (CCS) ------Oil (incl. CHP) 9'132 8'607 8'141 6'411 4'551 4'163 Conv. Other ------Wind 6'672 11'194 14'501 17'557 22'069 23'762 Hydro 27'594 33'296 39'634 45'080 50'736 55'867 Res. Other 915 1'170 1'606 2'311 3'139 4'054 Biomass 7'455 8'468 13'914 21'203 27'750 30'811 Source: Prognos 2007 page 125

EU27: TECH-45 2005 2010 2015 2020 2025 2030 Generation capacities in MW 728'736 802'888 876'000 905'493 961'208 1'016'898 Nuclear 139'549 136'363 128'226 106'972 145'337 165'477 Lignite (incl. CHP) 53'500 52'991 48'330 39'943 32'370 27'781 Lignite (CCS) - - - - 6'676 24'754 Hard (incl. CHP) 119'723 97'817 98'517 90'251 70'752 65'152 Hard (CCS) - - - - 26'551 56'153 Gas 135'777 202'257 252'023 279'036 241'018 204'152 Gas CHP 34'669 42'235 50'448 58'509 63'924 68'800 Gas (CCS) - - - - 600 600 Oil (incl. CHP) 72'741 58'577 41'707 25'205 8'502 6'415 Conv. Other ------Wind 45'930 78'805 104'166 128'955 165'780 184'502 Hydro 107'327 110'973 114'152 116'523 119'246 120'787 Res. Other 2'287 2'995 4'311 6'367 8'918 12'079 Biomass 17'234 19'875 34'118 53'731 71'535 80'246 Import 8'035 7'716 7'400 6'682 6'293 6'112 ------Power Generation in GWh 3'442'695 3'692'290 3'992'116 4'249'059 4'465'982 4'640'493 Nuclear 917'592 901'203 850'012 779'446 1'078'862 1'104'430 Lignite (incl. CHP) 208'597 173'368 174'055 174'290 169'656 151'589 Lignite (CCS) - - - 11'170 65'273 193'621 Hard (incl. CHP) 465'926 374'230 467'684 477'439 469'434 425'347 Hard (CCS) - - - 33'882 245'177 442'766 Gas 739'042 1'003'681 1'023'328 1'022'151 458'070 231'283 Gas CHP 330'038 387'071 460'139 534'439 583'688 630'436 Gas (CCS) - - - - 1'343 239 Oil (incl. CHP) 62'921 56'648 55'544 51'179 42'609 35'023 Conv. Other ------Wind 61'500 105'194 148'793 196'912 240'418 238'545 Hydro 470'082 486'060 500'031 510'526 522'861 531'959 Res. Other 2'003 2'624 3'776 5'575 7'808 10'658 Biomass 128'323 147'995 254'070 399'940 532'611 600'885 Import 56'670 54'216 54'685 52'110 48'171 43'714 ------Primary Energy Demand in ktce 919'980 944'746 992'373 1'029'631 1'114'079 1'163'413 Nuclear 343'313 336'504 314'879 282'481 364'085 366'301 Lignite (incl. CHP) 63'556 50'465 49'122 48'722 46'881 41'466 Lignite (CCS) - - - 3'236 18'489 52'974 Hard (incl. CHP) 136'938 105'641 123'150 123'516 120'791 108'467 Hard (CCS) - - - 9'518 67'092 118'588 Gas 164'144 215'054 211'869 207'209 91'757 46'111 Gas CHP 78'534 87'699 99'641 111'398 118'124 124'871 Gas (CCS) - - - - 311 55 Oil (incl. CHP) 19'365 17'443 16'792 15'262 12'512 10'268 Conv. Other ------Wind 7'548 12'916 18'273 24'191 29'535 29'305 Hydro 48'598 55'136 61'429 62'718 64'234 65'351 Res. Other 224 315 452 656 939 1'291 Biomass 50'799 56'914 90'047 134'328 173'412 192'994 Import 6'962 6'660 6'718 6'395 5'918 5'370 ------

Carbon Output in kt CO 2 1'008'875 975'489 1'031'136 1'042'601 867'727 774'135 Nuclear ------Lignite (incl. CHP) 204'885 162'671 158'343 157'053 151'117 133'662 Lignite (CCS) - - - 1'043 5'960 17'076 Hard (incl. CHP) 368'957 284'632 331'831 332'794 325'453 292'246 Hard (CCS) - - - 2'565 18'077 31'952 Gas 265'890 348'357 343'198 335'649 148'634 74'694 Gas CHP 127'214 142'061 161'405 180'450 191'344 202'274 Gas (CCS) - - - - 50 - Oil (incl. CHP) 41'929 37'768 36'359 33'047 27'092 22'232 Conv. Other ------Wind ------Hydro ------Res. Other ------Biomass ------Cost Power Generation in Mio EUR 178'483 198'240 234'953 269'347 304'030 328'008 Nuclear 38'971 38'889 38'041 37'829 60'869 63'533 Lignite (incl. CHP) 7'150 8'531 9'545 10'754 11'225 10'895 Lignite (CCS) - - - 510 3'137 9'739 Hard (incl. CHP) 19'560 15'133 22'381 26'952 28'903 29'414 Hard (CCS) - - - 1'935 14'412 26'089 Gas 45'156 55'910 64'773 70'584 42'910 29'027 Gas CHP 15'872 17'039 22'336 27'967 33'843 40'142 Gas (CCS) - - - - 140 89 Oil (incl. CHP) 9'138 8'612 8'223 6'648 4'835 4'497 Conv. Other ------Wind 6'672 11'194 14'501 17'557 22'069 23'763 Hydro 27'594 33'296 39'634 45'091 50'769 55'919 Res. Other 915 1'170 1'606 2'311 3'139 4'054 Biomass 7'455 8'468 13'914 21'209 27'780 30'847 Source: Prognos 2007 page 126