64543 ENERGY AND MINING SECTOR BOARD DISCUSSION PAPER PAPER NO.25 JUNE 2011 Carbon Capture and Storage in Developing Countries: a Perspective on Barriers to Deployment Natalia Kulichenko Eleanor Ereira THE WORLD BANK The Energy and GROUP Mining Sector Board ENERGY AND MINING SECTOR BOARD DISCUSSION PAPER PAPER NO. 25 JUNE 2011 Carbon Capture and Storage in Developing Countries: a Perspective on Barriers to Deployment Natalia Kulichenko Eleanor Ereira The World Bank, Washington, DC THE WORLD BANK GROUP The Energy and Mining Sector Board Copyright © 2011 The International Bank for Reconstruction and Development/The World Bank. All rights reserved ©2011 The International Bank for Reconstruction and Development / The World Bank 1818 H Street NW Washington DC 20433 Telephone: (202) 473-1000 Internet: www.worldbank.org E-mail: feedback@worldbank.org All rights reserved This volume is a product of the staff of the International Bank for Reconstruction and Development / The World Bank. 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CONTENTS ACRONYMS AND ABBREVIATIONS ...............................................................................................................vii UNITS OF MEASURE .......................................................................................................................................vii FOREWORD .................................................................................................................................................... viii ACKNOWLEDGMENTS..................................................................................................................................... x EXECUTIVE SUMMARY ...................................................................................................................................xii 1. INTRODUCTION ......................................................................................................................................... 1 2. TECHNOLOGY OVERVIEW AND STATUS OF CCS DEVELOPMENT ........................................................... 3 CCS Technology ���������������������������������������������������������������������������������������������������������������������������������������� 3 Capture ................................................................................................................................................ 3 Transport............................................................................................................................................... 4 Injection ................................................................................................................................................ 4 Monitoring ............................................................................................................................................ 5 Current Status of Technology .................................................................................................................. 5 Economics ������������������������������������������������������������������������������������������������������������������������������������������������� 6 iii Enhanced Oil Recovery .......................................................................................................................... 7 3. TECHNO-ECONOMIC ASSESSMENT OF CARBON CAPTURE AND STORAGE DEPLOYMENT IN THE POWER SECTOR IN THE SOUTHERN AFRICAN AND BALKAN REGIONS .................................. 9 Overview of Results ...................................................................................................................................... 9 Methodology .............................................................................................................................................. 12 Southern African Region ............................................................................................................................. 13 Scenarios Modeled .............................................................................................................................. 13 Modeling Results for Southern Africa .................................................................................................... 14 Conclusions for the Southern African Region ......................................................................................... 18 The Balkan Region...................................................................................................................................... 18 Scenarios Modeled .............................................................................................................................. 19 Modeling Results for the Balkan Region ................................................................................................ 19 Conclusions for the Balkan Region ....................................................................................................... 22 4. ADDRESSING THE LEGAL AND REGULATORY BARRIERS IN DEVELOPING COUNTRIES .................... 25 Key International and Multilateral Legal Instruments Relevant to CCS Projects........................................... 25 UNFCCC and the Kyoto Protocol.......................................................................................................... 25 United Nations Convention on the Law of the Sea, 1982 ...................................................................... 27 Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter 1972 (London Convention).......................................................................................... 27 Basel Convention on the Control of Trans-Boundary Movements of Hazardous Wastes and Their Disposal, 1989 (Basel Convention) ................................................................................... 27 Review of Regional and National Legal Regimes Applicable to CCS Activities in the Southern African Region ................................................................................................................... 27 Regional Framework ............................................................................................................................ 28 National Frameworks........................................................................................................................... 28 Review of Regional and National Legal Regimes Applicable to CCS Activities in the Balkan Region ........... 33 Regional Framework—European Union CCS Directive........................................................................... 34 National Frameworks........................................................................................................................... 34 5. THE ROLE OF CLIMATE FINANCE SOURCES IN ACCELERATING CARBON CAPTURE AND STORAGE DEMONSTRATION AND DEPLOYMENT IN DEVELOPING COUNTRIES................................ 43 Mapping Climate Finance to a Deployment Pathway ................................................................................. 43 Current Technology Status and Future Outlook for CCS in Developing Countries: A Reading of the IEA ETP Blue Map Scenario ........................................................................................................ 45 The Funding Needs to Deploy CCS in Developing Countries and Current Level of Support ..................... 46 Combining Climate Finance Instruments for Near-Term Support up to 2020........................................... 47 Longer-term support for CCS demonstration through climate finance (beyond 2020).............................. 49 Challenges for CCS Projects in Developing Countries to Access Carbon Finance ....................................... 49 Key Policy Issues Defining CCS Attractiveness for Climate Finance.......................................................... 49 Other Policy and Methodology Factors Affecting the Level of Support for CCS from Climate Finance ....... 52 Potential In-Country Limitations for CCS Deployment in Developing Countries ....................................... 53 6. PROJECT FINANCE FOR POWER PLANTS WITH CARBON CAPTURE AND STORAGE IN DEVELOPING COUNTRIES ................................................................................................. 55 Key Findings ............................................................................................................................................... 55 Methodology .............................................................................................................................................. 55 Description of the Model ............................................................................................................................ 59 Assumptions ............................................................................................................................................... 59 Financing Assumptions ........................................................................................................................ 59 Technology Assumptions ...................................................................................................................... 59 Scenarios ............................................................................................................................................ 61 Results ���������������������������������������������������������������������������������������������������������������������������������������������������� 61 Impact of Coal Price ............................................................................................................................ 62 Impact of CO2 Price............................................................................................................................. 63 Impact of Enhanced Hydrocarbon Recovery .......................................................................................... 63 Impact of Different Financial Structures ................................................................................................. 63 iv Impact of Concessional Finance ........................................................................................................... 64 Required Level of Concessional Finance for Break-Even LCOE ............................................................... 64 APPENDIX A: INTERNATIONAL ORGANIZATIONS INVOLVED IN CCS WORK ....................................... 68 APPENDIX B: TECHNO-ECONOMIC ASSESSMENT OF CCS DEPLOYMENT IN THE POWER SECTOR IN SOUTHERN AFRICA AND THE BALKANS ..................................... 69 The Model .................................................................................................................................................. 69 Modeling CCS Technology ................................................................................................................... 69 Storage Options .................................................................................................................................. 69 Assumptions in the Model for Southern Africa ............................................................................................ 69 Scenario Assumptions .......................................................................................................................... 74 Assumptions in the Model for the Balkan Region........................................................................................ 74 Scenario Assumptions .......................................................................................................................... 78 APPENDIX C: ASSESSMENT OF LEGAL AND REGULATORY FRAMEWORKS APPLICABLE TO POTENTIAL CCS DEPLOYMENT IN SOUTHERN AFRICA AND THE BALKANS .............. 81 Key Findings and Recommendations .......................................................................................................... 82 Key Findings and Recommendations at the Domestic Level—Southern African Region ............................... 82 Key Findings and Recommendations at the Domestic Level—the Balkan Region ........................................ 86 APPENDIX D: THE ROLE OF CLIMATE FINANCE SOURCES IN ACCELERATING CARBON CAPTURE AND STORAGE DEMONSTRATION AND DEPLOYMENT IN DEVELOPING COUNTRIES ............................................................................................... 93 APPENDIX E: PROJECT FINANCE STRUCTURES AND THEIR IMPACTS ON THE LEVELIZED COST OF ELECTRICITY FOR POWER PLANTS WITH CCS ............................ 99 Technology Assumptions ............................................................................................................................. 99 Additional Results ..................................................................................................................................... 102 BIBLIOGRAPHY ........................................................................................................................................... 103 BOXES Box 4�1: Key Findings and Recommendations ................................................................................................... 26 Box 5�1: Summary of Findings and Conclusions ................................................................................................ 44 Box 6�1: LCOE Structure ................................................................................................................................. 58 Box D�1: Metrics Used to Describe CCS Deployment in This Report .................................................................... 95 FIGURES Figure 2�1: Diagram of a Power Plant with CCS with Offshore Storage and Enhanced Oil Recovery .................... 3 Figure 2�2: Comparison of Studies of LCOE Increase and Net Efficiency Decrease for Post-Combustion Power Plants with CCS.................................................................................... 7 Figure 3�1: Electricity Generation for Southern African Region—Reference Scenario.......................................... 14 Figure 3�2: Electricity Generation for Southern African Region—Baseline Scenario ............................................ 14 Figure 3�3: Electricity Generation Portfolio for Southern African Region—US$100/Ton CO2 Price Scenario......... 15 Figure 3�4: Cumulative CO2 Storage for Southern African Region—US$100/Ton CO2 Scenario ........................ 16 Figure 3�5: Summary of Results for Southern African Region, 2030 ................................................................. 17 Figure 3�6: Comparison of Average Generation Costs across Scenarios for the Southern African Region............ 17 Figure 3�7: Comparison of Annual CO2 Emissions across Scenarios for the Southern African Region ................. 18 Figure 3�8: Electricity Generation for the Balkan Region—Reference Scenario .................................................. 19 Figure 3�9: CO2 Emissions for the Balkan Region—Reference Scenario............................................................ 19 Figure 3�10: Share of CCS in Coal-Based Power Generation in the Balkan Region—Reference Scenario with EOR/ECBM benefits ............................................................................................................. 20 Figure 3�11: Share of CCS-Based Generation in the Balkan Region—US$100/Ton CO2 Price Scenario ............... 21 Figure 3�12: CO2 Stored in the Balkan Region—US$100/Ton CO2 Price Scenario ............................................. 21 Figure 3�13: CO2 Emissions for the Balkan Region—US$100/Ton CO2 Price Scenario ....................................... 21 Figure 3�14: Comparison of Average Generation Costs across Scenarios for the Balkan Region .......................... 23 Figure 3�15: Comparison of Total CO2 Emissions across Scenarios for the Balkan Region ................................... 23 v Figure 5�1: Marginal Abatement Cost Curves for CCS in 2020 by Sector and Region ....................................... 45 Figure 5�2: Marginal Abatement Cost Curves for CCS in 2030 by Sector and Region ....................................... 45 Figure 6�1: LCOE for Reference Plants without CCS and Plants with CCS for the Five Technologies Examined .... 61 Figure 6�2: LCOE for Full Capture Coal Plants with CCS with Different Coal Prices .......................................... 62 Figure 6�3: Percentage Increase in LCOE from Reference Plant to Corresponding Plant with Full Capture CCS for Different Coal Prices ................................................................................... 62 Figure 6�4: Percentage Increase in LCOE from Reference Plant to Plant with CCS for Different CO2 Prices ......... 63 Figure 6�5: Percentage Increase in LCOE for a Reference Plant without CCS to a Plant with CCS and Enhanced Hydrocarbon Recovery ................................................................................................. 63 Figure 6�6: LCOE Variations with Different Financial Structures ........................................................................ 64 Figure 6�7: LCOE with Different Levels of Concessional Financing for IGCC plant ............................................ 64 Figure 6�8: Concessional Financing Required to Set LCOE for Plant with Full Capture Equal to Reference Plant, for Financing Structure Case 1 ............................................................................ 65 Figure E�1: Percentage Change in LCOE from Reference Plant without CCS to Plant with CCS with Enhanced Hydrocarbon Recovery and CO2 Price ........................................................................ 102 TABLES Table 2�1: Active Large-Scale Integrated CCS Projects ........................................................................................ 6 Table 3�1: Summary of Findings ...................................................................................................................... 10 Table 3�2: Summary of Installed Capacity in 2030 for the Southern African Region ............................................. 16 Table 3�3: Summary of Installed Capacity in 2030 for the Balkan Region ........................................................... 22 Table 6�1: Summary of Findings and Conclusions ............................................................................................. 56 Table 6�2: Terms of Financing Instruments and Resulting Blended Debt Interest Rates........................................... 60 Table 6�3: Blended Debt Interest Rate for Different Levels of Concessional Financing ........................................... 64 Table B�1: References Used to Develop CO2 Storage Estimates in the Model ...................................................... 70 Table B�2: Fuel Price Assumptions for Southern African Region .......................................................................... 71 Table B�3: Generic Energy Technology Options Available in the Region and Associated Model Input Parameters for the Southern African Region .............................................................................. 71 Table B�4: South Africa DOE 2011 IRP “Revised Balance� Expansion Plan ......................................................... 72 Table B�5: CO2 Storage Options, Volumes, and Costs for Southern Africa.......................................................... 73 Table B�6: CO2 Transport Options for the Southern African Region .................................................................... 73 Table B�7: Comparison of Results across Scenarios for Southern African Region.................................................. 74 Table B�8: Fuel Prices Used in Simulation for the Balkan Region ........................................................................ 75 Table B�9: Generic Energy Technology Options Available in the Region and Associated Model Input Parameters for the Balkan Region ............................................................................................ 76 Table B�10: CO2 Storage Options, Volumes, and Costs for Balkan Region ................................................................78 Table B�11: Descriptions of CO2 Price Scenarios in the Balkan Region ......................................................................79 Table B�12: Comparison of Results across Scenarios for the Balkan Region ...............................................................80 Table C�1: Summary of Legal Obligations of the Reviewed Countries under Relevant International Conventions..... 81 Table C�2: Summary of the EU CCS Directive ................................................................................................... 81 Table C�3: Key Findings for Botswana, Mozambique, and South Africa ............................................................... 82 Table C�4: Key Findings for Bosnia and Herzegovina, Kosovo, and Serbia .......................................................... 86 Table D�1: Summary of Near-Term Demonstration Challenges for CCS ............................................................... 93 Table D�2: Status of CCS in Developing Countries:Policy Initiatives, Project Implementation, and Other Enabling Activities, Select Examples ................................................................................. 94 Table D�3: Main Components for Good Practice for CCS Project Design and Operation ..................................... 96 Table D�4: Focus Areas for CCS Capacity Building Efforts in Developing Countries ............................................. 98 Table E�1: Financial Assumptions Used in LCOE Model .................................................................................... 99 Table E�2: Cost and Technical Assumptions for PC Technologies in Model .......................................................... 99 Table E�3: Cost and Technical Assumptions for IGCC Technologies in Model ................................................... 100 Table E�4: Cost and Technical Assumptions for Oxy-fuel Technologies in Model ................................................ 100 Table E�5: Explanation of Varied Parameters and Justifications ......................................................................... 101 Table E�6: Oil and Methane Recovery Rates Assumed for EOR/ECBM .............................................................. 101 Table E�7: Assumed Revenue Streams for EOR and ECBM Recovery................................................................. 102 vi ACRONYMS AND ABBREVIATIONS NZEC Near-Zero Emissions Coal O&M Operations and maintenance ADB Asian Development Bank OECD Organization for Economic Co-operation APA Atmospheric Pollution (Prevention) Act and Development (Botswana) Oxy Oxy-fuel BECCS Bio-energy combined with carbon capture PC Pulverized coal and storage R&D Research and development CCGT Combined cycle gas turbine REQSEE Regulations on Environmental Quality CCS Carbon capture and storage Standards and Effluent Emissions CDM Clean Development Mechanism (Mozambique) CO2 Carbon dioxide RWM Regulation on Waste Management COACH Co-operation Action within CCS China-EU (Mozambique) COP Conference of Parties SADC Southern African Development Community CSLF Carbon Sequestration Leadership Forum SANS South African National Standards DOE Department of Energy SAPP Southern African Power Pool EBRD European Bank for Reconstruction and SBSTA Subsidiary Body for Scientific and Development Technological Advice ECBM Enhanced coal-bed methane SEA Strategic Environmental Impact Assessment vii EEZ Exclusive economic zone TIMES The Integrated MARKAL/EFOM System EIA Environmental impact assessment UNCLOS United Nations Convention on the Law of EIHP Energy Institute Hrvoje Požar (Croatia) the Sea EOR Enhanced oil recovery UNFCCC United Nations Framework Convention on ERC Energy Research Centre (South Africa) Climate Change ETP Energy Technology Perspectives VITO Flemish Institute for Technological ETS Emission trading scheme Research (Belgium) EU European Union UK United Kingdom GHG Greenhouse gases WB World Bank HW Hazardous waste WB CCS TF World Bank Carbon Capture and Storage IEA International Energy Agency Trust Fund IEAGHG IEA Greenhouse Gas R&D Programme WBG World Bank Group IGCC Integrated gasification combined cycle WRI World Resources Institute IPCC Intergovernmental Panel on Climate ZEP EU Zero Emissions Platform Change IRP Integrated Resource Plan UNITS OF MEASURE LCOE Levelized cost of electricity LNG Liquefied natural gas bbl Barrel MARKAL MARKet ALlocation model GJ Gigajoule MDB Multilateral development bank kW Kilowatt MESSAGE Model for Energy Supply Strategy kWh Kilowatt hour Alternatives and Their General m3 Cubic meter Environmental Impact mcf Million cubic feet MICOA Ministry for Coordination for mill/kWh Tenth of a U.S. cent per kWh Environmental Action (Mozambique) MMBtu Million British thermal units MMA Mines and Minerals Act (Botswana) Mt Megatons MOP Meeting of the parties MtCO2-e Megatons of CO2 equivalent MRV Measuring, reporting, and verification MWh Megawatt-hour NEMA National Environmental Management Act Ppm Parts per million (South Africa) t Metric Ton NETL National Energy Technology Laboratory tCO2 Metric Ton CO2 NWA National Water Act (South Africa) FOREWORD Many scientists and analysts identify carbon capture and storage (CCS) technologies as potentially capable of making a significant contribution to meeting global greenhouse gas (GHG) mitigation objectives. CCS technology could provide a technological bridge for achieving near to midterm GHG emission reduction goals. Integrated CCS technology is still under development and has noteworthy challenges, which would be possible to overcome through the implementation of large-scale demonstration projects. Several governments, noticeably among industrialized countries, are currently undertaking efforts aimed at advancing the deployment of CCS technologies in the industrial and power generation sectors. However, before the technology can be deployed in industries viii in developing countries and countries in transition, substantial efforts should be carried out to exchange knowledge to understand all aspects of CCS to reduce investor risk, and help design policies to mitigate economic impacts, including increases in electricity prices and financing mechanisms to facilitate investment in the technology use. The World Bank Group (WBG) has been engaged in providing assistance to its partner countries on carbon capture capacity building since the establishment of the World Bank Multi-Donor CCS Trust Fund (WB CCS TF) in December 2009. The Government of Norway and the Global Carbon Capture and Storage Institute are the two donors of the WB CCS TF at present. The objectives of the WB CCS TF are to support strengthening capacity and knowledge sharing, to create opportunities for WBG partner countries to explore CCS potential, and to facilitate the inclusion of CCS options into low-carbon growth strategies and policies developed by national institutions. In order to assist our partner countries better, there is a need to start analyzing various numerous challenges facing CCS within the economic and legal context of developing countries and countries in transition. This report is the first effort of the WBG to contribute to a deeper understanding of (a) the integration of power generation and CCS technologies, as well as their costs; (b) regulatory barriers to the deployment of CCS; and (c) global financing requirements for CCS and applicable project finance structures involving instruments of multilateral development institutions. We expect that this report will provide insights for policy makers, stakeholders, private financiers, and donors in meeting the challenges of the deployment of climate change mitigation technologies and CCS in particular. Lucio Monari Sector Manager, Sustainable Energy Department ix ACKNOWLEDGMENTS The broad scope of this report drew extensively on the expertise of many individuals with project and analytical experience in the field of carbon capture and storage (CCS). Natalia Kulichenko (Task Team Leader) and Eleanor Ereira led the preparation of this report under the guidance of Lucio Monari, Sector Manager of the Sustainable Energy Unit, World Bank (WB). Charles Di Leva, Sachiko Morita, and Yuan Tao (WB International and Environmental Law Unit, Legal Department) reviewed related legal documents and prepared Chapter 4. Alexandrina Platonova-Oquab (Carbon Finance Unit, WB Environmental Department) and Philippe Ambrosi (WB Environment Department) led the preparation of Chapter 5 on the applicability of climate finance for CCS projects. Concepcion Aisa Otin, Fatima x Revuelta, and Ricardo Antonio Tejada (WB Treasury Department) provided support for model development in Chapter 6 on project finance for CCS. This report also benefited from advice, suggestions, and corrections on the numerous technical, financial, economic, and regulatory issues involved in the development and deployment of CCS. The authors would like to express their gratitude to the following colleagues inside and outside the World Bank Group: Alex Huurdeman (WB Sustainable Energy Department), Supriya Kulkarni (WB consultant), and Stratos Tavoulareas (WB consultant); Jeffrey James at Tenaska Energy; Jon Kelafant at Advanced Resources International; Steve Melzer at Melzer Consulting, Andy Paterson at CCS Alliance, Pamela Tomski at EnTech Strategies LLC, Gøril Tjetland at Bellona Foundation; and Scott Smouse and John Wimer at the National Energy Technology Laboratory, U.S. Department of Energy. Several sections are based on the work of external consultants. Jan Duerinck, Helga Ferket and Arnoud Lust of the Flemish Institute for Technological Research (VITO, Belgium) in cooperation with Mario Tot and Damir Pešut of the Energy Institute Hrvoje Požar, EIHP (Croatia), and Alison Hughes, Catherine Fedorski, Bruno Merven, and Ajay Trikam of the Energy Research Centre (ERC), University of Cape Town (South Africa), contributed to the preparation of Chapter 3. Yvonne Chilume of Chilume and Company (Botswana), Andrew Gilder of IMBEWU (South Africa), Samuel Levy and Antonio Bungallah of Sal and Caldeira Advogados (Mozambique), and Gretta Goldenman and Caroline Nixon of Milieu Ltd (Belgium) provided inputs for the preparation of Chapter 4. Paul Zakkour and Greg Cook of Carbon Counts (UK), and Anthea Carter, Charlotte Streck, and Thiago Chagas of Climate Focus (UK) supported the preparation of Chapter 5. The financial support by the World Bank Carbon Capture and Storage Capacity Building Trust Fund (WB CCS TF) is gratefully acknowledged. The WB CCS TF is a multi-donor trust fund supported by the Government of Norway and the Global CCS Institute, with the objective of providing CCS capacity building support to developing countries. xi EXECUTIVE SUMMARY Carbon capture and storage (CCS) could have significant impact as a carbon mitigation technology in greenhouse gas– (GHG-) emitting industries. Given the nascence of CCS technology, with only eight large-scale integrated projects in the world (Global CCS Institute 2010), significant challenges still must be overcome for large-scale deployment, such as addressing technical issues of integration and scale-up, legal and regulatory requirements to reduce investor risk, policies to create market drivers and mitigate economic impacts, including increases in electricity prices, and financing mechanisms to facilitate investment in the technology. This report does not provide prescriptive solutions to overcome these barriers, since action must be taken on a xii country-by-country basis, taking account of different circumstances and national policies. Individual governments should decide their priorities on climate change mitigation and adopt appropriate measures accordingly. The analyses presented in this report may take on added relevance, depending on the future direction of international climate negotiations and domestic legal and policy measures, and how they serve to encourage carbon sequestration. Both international and domestic actions can further incentivize the deployment of CCS and its inclusion in project development. Incentives to promote CCS include adopting climate change policies that could provide revenues for CCS projects, but it is likely that a combination of domestic and international mechanisms will be required, alongside carbon revenues, to kick-start CCS project development and reduce investor risk in developing countries in particular. This report assesses some of the most important barriers facing CCS deployment within the context of developing and transition economies. The selection of the case studies is based on several criteria, including the level of reliance on fossil fuels for power generation and the level of interconnection of electricity networks. The case studies selected for this analysis are the Balkans and Southern African regions. Many countries within the Balkan region are considered transition economies, a status recognized as different from middle-income and low-income developing countries. However, for the purposes of this report, countries within both regions are referred to as developing countries. Against this background of numerous challenges facing This comparison provides an initial cost estimate of that CCS, and assuming there is an ambition to reduce policy to society. For example, imposing a CCS target GHG emissions, this report (a) assesses the economic on power plants through the construction of three 500 and environmental (GHG) impacts of potential CCS MW coal plants with CCS in the Balkans generates deployment in the power sector in the Balkan and cumulative savings of 37 Mton of CO2 by 2030, and Southern African regions using a techno-economic increases total system costs by 1.5 percent compared to model; (b) analyzes legal and regulatory frameworks the Reference Scenario. that could be applicable to potential CCS deployment in these regions; (c) assesses the role of climate finance The modeled storage capacities are based on available to support prospective investment needs for CCS data for each region, and constraints are incorporated projects in developing countries; and (d) examines into the model to reflect these capacities. The costs potential structures for financing power plants equipped of CCS deployment in the model take account of the with CCS and the impacts of CCS on the electricity proximity to the storage site, and the uncertainty over rates through a levelized cost of electricity (LCOE) storage capacity estimates for any given reservoir, such model. that where there is greater uncertainty over storage capacity, storage costs are modeled as higher. Potential CCS Deployment in the Power Sector in Southern Africa and Balkans Under the South African Department of Energy’s xiii Integrated Resource Plan (IRP), which includes a limit The report presents the results of a techno-economic on CO2 emissions of 275 Mton CO2/year, CCS modeling exercise to investigate the impacts of a in combined cycle gas turbines (CCGTs) could be number of policies on CCS deployment in the power economically competitive, making up 2 percent of the sector in the Balkan and Southern African regions.1 The share in electricity generation by 2030. analysis examines the effects of such policies on energy technology portfolios in the two regions, including Combining CCS with enhanced hydrocarbon recovery, the level of CCS deployment, the average generation such as enhanced oil recovery (EOR), and assuming costs, the CO2 emission reductions, and the costs of associated revenues of US$40/ton CO2 from injections the policy. Policies considered in the analysis include in oil fields, could make CCS technology in the the introduction of a carbon price (introduced into power sector economically competitive in Albania and the model incrementally at the following three levels: Croatia, as well as in South Africa, without additional US$25/ton CO2, US$50/ton CO2, and US$100/ton policies. CO2) the availability of enhanced hydrocarbon recovery, and technology specific deployment targets. However, In the Southern African region, a carbon price it should be noted that other measures that are not of US$50/ton CO2 could make capturing and included in the model, but discussed in other sections transporting CO2 for storage from South Africa of the report, could promote the development of CCS, to depleted oil and gas fields in Mozambique such as government supporting policies, as seen in the economically feasible. At a CO2 price of US$100/ United States, United Kingdom, European Union and ton, storage in Botswana and Namibia could also Australia. be utilized. In the Balkans, CCS would not be economically competitive at CO2 prices of US$25/ton. For any policy, such as the imposition of CCS However, if nuclear power, as an energy technology deployment targets or a carbon price, the resulting option is excluded from the modeling scenario, and total power system cost is compared to that under the with a CO2 price of US$50/ton, constructing coal Reference Scenario (where no policy is applied and plants with CCS in Kosovo could be economical, since capacity additions are made purely on the least-cost this area has the lowest costs for coal production within basis, where these costs are based on local data on the region. At carbon prices of US$100/ton CO2, both energy technologies in Southern Africa or the Balkans). building new plants and retrofitting existing plants with 1 For the purposes of this study, the Balkan region refers to the following countries, also often classified as South Eastern Europe (SEE): the Federation of Bosnia and Herzegovina, and the Republics of Albania, Croatia, Kosovo, Macedonia, Montenegro, and Serbia. Also for the purposes of this study, the Southern African region includes the Republics of Botswana, Mozambique, Namibia, and South Africa. CCS could be economically justified across the Balkan Assessment of Legal and Regulatory region, making up 70 percent of the electricity portfolio Frameworks Applicable to Potential CCS by 2030. Deployment in Southern Africa and the Balkans While carbon prices of US$100/ton can result in a significant increase in CCS deployment in the Balkans, The report presents the results of an assessment of the such a result would not be observed in the Southern existing legal frameworks and their potential applicability African region. At a CO2 price of US$100/ton, the to CCS technology in the Southern African and Balkan share of electricity generation from CCS equipped region with the objective of identifying challenges to power plants could reach 15 percent by 2030 in the development of cross-boundary and national CCS Southern Africa, compared to 70 percent in the projects. The assessment involves an examination of the Balkans. This is because coal plants in the Southern existing multilateral, bilateral, and national regulatory Africa region employ dry-cooling technology, and, and legal frameworks, and suggests ways to bridge gaps therefore, have lower efficiencies. The addition of in the regulations that should be addressed, should CCS CCS equipment results in an energy penalty since the technology be adopted in these regions. capture unit requires incremental power supply. Thus, based on the modeled results, carbon prices higher None of the three countries examined in the Southern xiv than US$100/ton CO2 would be necessary to show that African region has adopted a CCS-specific legal CCS plants are competitive against non CCS plants instrument. However, all three countries appear to have in Southern Africa at the same scale as it could be the basic elements that touch on certain aspects of the projected in the Balkan region. relevant legal issues. The three countries examined in the Balkan region are candidate countries to European Union In both Southern Africa and the Balkans, the higher membership and, as such, at some point in the future will the CO2 price, the higher the average generation need to take steps to harmonize with Directive 2009/31/ costs. This is because imposing a CO2 price in the EC (The CCS Directive). At this stage, none of the three model requires emitting power plants to buy permits countries has transposed the directive into national laws. at that price for every ton of CO2 released into the atmosphere. Average generation costs increase because There are grounds to recommend a platform for of the additional costs of buying these permits, or from countries in the Southern African and the Balkan switching away from cheaper electricity sources, such regions to discuss and agree on multilateral and as coal, to more expensive technologies with lower regional treaties for important CCS-related issues, such emissions. In both regions, imposing a CO2 price also as compliance, enforcement, and dispute resolution results in higher total system costs. For example, for mechanisms, in case these countries decide to move carbon prices of US$25/ton CO2 and US$100/ton towards using CCS technology in the future. CO2 in Southern Africa, the total system costs become between 11 and 28 percent greater than under the Multilateral and regional agreements on potential cross- Reference Scenario, respectively. With the same carbon boundary movement of CO2 for disposal, addressing prices, in the Balkans, the total system cost increase the propriety rights over various segments of cross- ranges from 30 to 66 percent greater than under the boundary transportation, are needed so that operations Reference Scenario. can be conducted based on an agreement among the countries concerned. Although both the total system costs and average generation costs increase as carbon prices increase, as At the point where CCS is poised to reach an explained above, the level of CO2 emissions decreases. operational level, several issues should be taken In Southern Africa, carbon prices of US$25 ton and into consideration and addressed by regional and US$50/ton CO2 result in CO2 emission levels that are international regulatory frameworks for CCS activities, largely lower than under the Reference Scenario. Carbon including enforcing robust criteria for selection of CO2 prices of US$100/ton reduce emissions even more storage sites, stringent monitoring plans, frameworks for noticeably. The same is seen in the Balkan region, where risk and safety assessments, assumption and allocation a carbon price of US$100/ton results in significantly of liability, and a means of redress for those affected by lower emissions than the other prices modeled. release of stored CO2, among others. The Role of Climate Finance Sources to The way, in which the following issues, among others, Accelerate Carbon Capture and Storage are addressed, will have lasting repercussions on the Deployment in Developing Countries attractiveness of potential carbon assets generated by CCS projects: The report presents the results of an assessment on the options for using climate finance to accelerate 1. Managing permanence and liability. demonstration and deployment of CCS in developing 2. Establishing good CCS project design and countries over the next 20 years, which takes into operational standards (including measurement, account future uncertainties in the international policy monitoring, reporting, and verification (MRV) frameworks for climate finance. The assessment involves procedures). comparing potential sources of climate finance to 3. Establishing national regulatory regimes for CCS financing needs for CCS deployment in developing projects in developing countries. countries, according to a particular deployment pathway developed by the International Energy Agency (IEA). The Addressing the regulatory requirements for CCS in comparison considers how such funding sources could developing countries should include consideration of meet these investment needs, as well as certain policy funding sources to meet these regulations, for example, elements that could affect access to climate finance. through accessing public sources of climate finance or leveraging private finance through carbon markets. xv CCS is essentially a high-cost abatement option, and The latter could cover methodological aspects (such therefore widespread CCS deployment in developing as baseline approaches and MRV procedures) and countries would only occur in line with ambitious other possible restrictions that may be imposed when GHG emission reduction targets. There is a great deal linking regional emission trading schemes (ETSs) of uncertainty about the future structure and specific to international offsets. This will be vital to ensure features of climate finance instruments and channels. It is fungibility of any CCS-generated carbon assets. likely, however, that in a highly ambitious GHG Emission Mitigation Scenario, market-based climate finance Timing is important, and fast-tracking of low-cost instruments, as part of a mix of funding sources, will opportunities in demonstration projects could create have to play an important role as a base for cost efficient prospects for targeted technical, regulatory, and solutions to attracting finance at the international level. institutional capacity building in developing countries. Establishing certainty in supporting climate finance Based on the metrics developed in this analysis and policy frameworks for CCS would be crucial in creating the data from the IEA ETP Blue Map Scenario, the an economically attractive and low-risk environment for total incremental costs of CCS in developing countries project investors. (covering both capital and operating aspects of CCS deployment and financing costs) could amount to Finance Structures and Their Impacts on US$220 billion between 2010 and 2030. By 2020, this Levelized Cost of Electricity for Power Plants will be equivalent to an estimated of around US$4–5 with CCS billion per year, increasing tenfold to almost US$40 billion per year in 2030. The significant increase in the The report presents the results of a model developed estimated annual requirement between 2020 and 2030 to investigate ways of structuring financing for power reflects progressive growth in the amount of projects as generation facilities equipped with CCS in the well as their scale. developing world, using instruments available from multilateral development banks and commercial CCS projects are highly heterogeneous, with financiers, as well as concessional funding sources. The considerable variations in marginal abatement costs, objective is to assess whether a combination of such reflecting differences in energy requirements and unitary instruments could result in reductions in the overall costs of technology, capital and operating costs, and cost of financing. The model calculates the resulting project scale factors. A range of support mechanisms, levelized cost of electricity (LCOE), and includes both market and nonmarket approaches working in numerous variable parameters, such as coal prices, tandem, may, therefore, be required to support different CO2 prices, and potential revenues from selling oil and types of CCS projects throughout their lifetime. gas obtained through enhanced hydrocarbon recovery. Of the generation technologies examined, integrated greater the portion of concessional financing, the lower gasification combined cycle (IGCC) plants equipped the LCOE for plants with CCS. with CCS demonstrate the least increase in LCOE compared to a reference plant of the same technology There are a few cases where concessional financing of without CCS. Oxyfuel plants with capture experience less than 50 percent of the entire financing package greater cost increases, and pulverized coal (PC) can reduce the LCOE for a coal plant with CCS – plants with capture experience the greatest increase. down to the point where it is equal to the LCOE of a At coal prices of 3$/MMBtu and assuming financing reference plant without CCS (the latter is assumed to of 50 percent from multilateral development banks have no concessional funding). The total dollar amount (MDBs) and 50 percent from commercial sources, the of concessional financing for a single plant with CCS, percentage increases in LCOE are 34 percent, 46 ranges from US$53 million to US$1,338 million for percent, and 60 percent, respectively. these few cases. In these specific cases, for plants, capturing 90 percent of the plant’s total CO2 emissions, Extra revenue streams from carbon prices reduce the the oxy-fuel technology requires the least amount LCOE of plants with CCS. The percentage change in of concessional financing, followed by the IGCC the LCOE from a reference plant without CCS to a technology, and then the PC technology. . plant with CCS, ranges between 25 percent and 51 xvi percent at US$15/ton CO2, and between 4 percent Conclusions and 29 percent at US$50/ton CO2, depending on the plant technology type. This is a considerably greater A common theme found throughout the analyses is impact than that is seen from revenues from EOR or that there could be potential for CCS deployment enhanced coal-bed methane (ECBM) recovery, both of in the regions under consideration. Lower-cost which, based on the assumptions used for this analysis, opportunities—for example, in sectors practiced in reduce the LCOE of a plant with CCS by only 1–2 handling CO2, such as gas processing, or where extra percent. revenues could be made available from enhanced hydrocarbon recovery—could provide platforms for the Three financing structures are modeled, based on first CCS projects in developing countries. However, combinations of different financing instruments with broader CCS deployment is contingent upon a average debt interest rates ranging from 5.91 percent number of factors, including an availability of a mix to 6.59 percent. This small range in rates results in of sources of finance from public funds and carbon very little variations in the LCOE across the financing market mechanisms, as well as concessional financing structures. sources. In parallel, financing should be supported by legal and regulatory frameworks not only to define Including concessional funding for plants with CCS at mechanisms for access to concessional and climate cheaper terms than the original MDB loans, modeled finance, but also to reduce investor risk and create in the financing packages, reduces the debt rate more market drivers to leverage all available sources of considerably, thus lowering the resulting LCOE. The domestic and international support. 1. INTRODUCTION Leadership Forum (CSLF) have already established themselves as leaders in the field of CCS technical, Many countries are dependent on fossil fuels for energy regulatory, and economic knowledge. During generation, and fossil fuels remain a vast energy discussions with these organizations and representatives resource, widely distributed around the world. Coal in of donor governments, it has been acknowledged that particular is abundant in regions that have large existing the WBG could play a facilitating and catalytic role or projected energy demand and limited alternative for CCS promotion and deployment in developing energy options. With an average of two coal-fired countries, building upon its vast knowledge of and power stations being built in the developing world every experience in infrastructure and energy sector policy week, reduction in local pollution and emissions of and project development, as well as its close working greenhouse gases (GHGs) from the combustion and relationships with the major CCS initiatives and processing of fossil fuels will remain one of the world’s organizations. biggest challenges in the years ahead. Because of the relatively new status of CCS technology, At the 2009 Conference of the Parties to the United substantial capacity building gaps exist that need Nations Framework Convention on Climate Change be addressed in WBG partner countries to enable (UNFCCC), a number of countries agreed that action government decision makers and private sector should be taken to limit the increase in average stakeholders to embark on the development and 1 global temperatures to 2°C (UNFCCC 2009a). implementation of CCS related policies and projects. In many studies (for example, van der Zwaan and To help address these capacity building needs, the Gerlagh 2008; IPCC 2007; Stern 2006; Lecocq and Multi-Donor World Bank CCS Capacity Building Trust Chomitz 2001; Narita 2008), in determining pathways Fund (WB CCS TF) was established, and became to achieve this goal by limiting carbon dioxide operational in December 2009. The initiation of the (CO2) concentrations in the atmosphere to 450 ppm, WB CCS TF was enabled with contributions from two the application of carbon capture and storage (CCS) donors—the government of Norway and the Global in a number of industrial sectors plays an important CCS Institute—with the total capitalization at about role—either as an interim solution until other options US$11 million. Relying on this fund, as well as internal become economically and technologically viable or as WBG resources and other donor support, the World a long-term solution. Bank started providing assistance to its developing partner countries for CCS knowledge sharing and One of the decisions of the UN Climate Change capacity building to facilitate future deployment of Conference (COP16) in Cancun (UNFCCC 2010e) CCS. This report is commissioned as one of the in December 2010 calls for new rules governing programs supported by the WB CCS TF . the inclusion of CCS into the Clean Development Mechanism (CDM), including the measurement of the It is widely acknowledged that there are a number of carbon savings from CCS projects. This decision is to barriers that need to be overcome in order to achieve be finalized by the next UNFCCC climate summit in large scale CCS deployment in both developed and Durban in December 2011. On its own, the decision developing countries. Such barriers include the following: on eligibility of CCS technology within the CDM framework would not make CCS projects financially • Technical barriers: Full integration of the CCS viable. However, from the perspective of a developing technology elements at scale is yet to be achieved. country, this decision could help kick-start CCS projects in countries that have no climate policy incentives targeted specifically towards CCS. To continue to extract and combust the world’s rich endowment of oil, coal, peat, and natural gas at During the last few years, a number of organizations current or increasing rates, and so release more of and initiatives have been making continuous the stored carbon into the atmosphere is no longer environmentally sustainable, unless carbon dioxide concentrated efforts to promote CCS deployment in capture and storage (CCS) technologies currently both developed and developing countries (Appendix being developed can be widely deployed� A). Some organizations, such as the Australia-based Global CCS Institute, and Carbon Sequestration (IPCC 2007) • Economic barriers: Sectoral economic issues could For the purposes of this report, the above analyses arise from potential increases in the cost of electricity are carried out for case study regions, since potential production if CCS were to be employed in the power deployment of CCS could have both regional and sector. country-level impacts. The focus is on two regions, which • Legal and regulatory barriers: Adequate legal are selected based on (a) their level of reliance on fossil frameworks are necessary to provide investors with fuels for power generation, (c) regional energy and the security for CCS deployment. electricity network interdependency, and (c) their potential • Financial barriers: As a new and expensive to establish CCS regional networks linking CO2-emitting technology, financing mechanisms are needed to sources and sequestration sites across different countries help make CCS projects economically viable and within the region. Based on these criteria, the selected financially attractive for investment by the private case study regions are Southern Africa and the Balkans. sector. It should be noted that many countries within the Balkan The objectives of this study are to inform Bank staff and region are considered transition economies, and it is partner country policy makers about the following: recognized that this status is different and distinct from the status of mid-income and low-income developing • Technical, environmental (GHG emissions), countries. However, for the purposes of this report, the 2 regulatory, and socioeconomic issues related to states within both regions are referred to as developing potential CCS deployment in regional energy countries. infrastructure. • Existing and prospective financing mechanisms An assessment of the financial barriers is conducted on that that might encourage deployment of CCS in a project level, as well as through examining financing developing countries, where appropriate. needs on a global scale. These issues are not directly related to the case study regions, since the objective These objectives are achieved through addressing is to explore general frameworks for financing CCS issues associated with three of the barriers described projects that can be applicable in all developing above. Technical barriers related to CCS deployment countries, rather than in specific regions. are not examined in this report, since CCS is a relatively new technology, and the WBG—as well as This report only considers CO2 storage in geological other MDBs—do not have specific project expertise or formations, and does not cover many aspects related to experience in the field. utilization of CO2 that are referred to as CCUS (carbon capture utilization and storage). CCUS is a new and The economic barriers are addressed through an promising aspect of the CCS cycle that requires further examination of some of the impacts of potential CCS analysis on its technological prospects, scale, and deployment in power sectors, including changes in associated costs. There are several ongoing projects electricity prices and GHG emission levels. The legal in this area today, but such applications are at the and regulatory barriers are assessed through a review early stages of development. Enhanced hydrocarbon of existing national and international regulations recovery, is an example of CCUS that is well established potentially applicable to CCS to define gaps and and is therefore included in the analyses in this report. suggested approaches to address them. Other options for CCUS should be investigated in a separate study. 2. TECHNOLOGY OVERVIEW AND STATUS OF overview. More detailed descriptions of all elements of CCS DEVELOPMENT CCS technology applied in different industries can be found in the literature, including in MIT 2007, Metz This chapter provides an overview of CCS technology, and others 2005, and the U.S. Department of Energy’s its application, the current status of its deployment and National Energy Technology Laboratory (NETL) website its cost. (NETL 2011). CCS Technology Figure 2.1 shows how a power plant could be combined with CCS to store CO2 underground in Carbon capture and storage or CCS (also referred to as different types of geological formations. carbon capture and sequestration) is a GHG emissions– reducing option that involves an integrated process Capture of capture, transportation, and long-term storage of CO2 in subterranean geological structures (Global CO2 capture can take place in many applications, CCS Institute 2011). CCS technology, when applied to including industrial processes, such as steel or cement industrial processes or power plants, can reduce CO2 production, natural gas processing, and fossil-fuel and emissions considerably (highest target capture rates, biomass combustion in power generation. CO2 can be taking account of both technological and economic captured in various ways, depending on the particular 3 considerations, referred to as “full capture� systems, application, and must be compressed in order to be are frequently given as approximately 85 or 90 percent) transported. CO2 is compressed to the extent that it and is therefore a potential GHG emissions mitigation becomes a liquid to reduce its volume, making it easier technology. The four components that make up the and therefore cheaper to handle. For processes such as full CCS technology chain are CO2 capture, transport, steel or cement production, CO2 can be captured and injection, and monitoring. The information below removed from the flue gas by using chemical solvents. provides a very general, non-engineering technology A similar process is used in natural gas processing Figure 2.1: Diagram of a Power Plant with CCS with Offshore Storage and Enhanced Oil Recovery Source: Carbon Trust 2011� facilities, in which the removal of CO2 is a standard Pre-Combustion Method operational procedure required for meeting transmission pipeline standards. In power generation installations, In the case of CO2 pre-combustion capture, the fuel the capture and removal of CO2 can be achieved is gasified, applying high temperatures, steam, and through the following methods. pressure to produce carbon monoxide and hydrogen. The carbon monoxide is reacted with steam in a shift Post-Combustion Method reactor to produce CO2 and more hydrogen. The hydrogen is then used in a gas turbine to generate In the post-combustion capture chemical method, power, while the waste heat from the combustion solvents such as aqueous amines or chilled process is used to generate electricity in a steam ammonia are used to absorb the CO2 from the flue turbine. The CO2-rich stream is derived after the gas resulting from the combustion process. After gasification process is purified, typically using a the absorption, the CO2-rich solvent is heated to physical solvent-based process, and then compressed release the CO2, which then can be separated and and transported for storage. Plants that could adopt compressed for transport and storage, while the this technology are integrated gasification combined solvent is regenerated and applied again to the flue cycle (IGCC) power plants. IGCC plants with CO2 gas to repeat the process. capture have an advantage over pulverized coal 4 or fluidized bed combustion plants with capture, CO2 Capture and Removal in Air-Oxygen associated with a more concentrated CO2 stream that Combustion facilitates the capture process and reduces equipment and solvent costs. However, gasifiers are more costly This process involves CO2 capture and removal from and IGCC plants are less technologically mature than the flue gas after the fuel combustion process is pulverized coal or fluidized bed combustion boilers completed. The combustion takes place in a mix of (Bellona Foundation 2011a). air and oxygen, and is typically used in conventional pulverized coal and fluidized bed power generation Transport facilities. CO2 capture is applied at the end of the combustion process. Coal-fired power plants that CO2 can be transported by pipeline or in containers are constructed without a CO2 capture unit can be by truck or by ship. There are already 3,400 miles of retrofitted with the installation of a CO2 capture and dedicated CO2 transport pipelines in the United States compression plant. used for the purposes of delivering CO2 for enhanced oil recovery (EOR), which is explained in greater detail CO2 Capture and Removal in Oxyfuel Combustion below. There is also experience in transporting CO2 in small volumes in containers by truck and in vessels by By combusting the fuel in oxygen rather than a mix ship for the purpose of cooling and food production of air and oxygen, a higher concentration of CO2 in (Bellona Foundation 2011b). the flue gas can be achieved. The process of CO2 removal from a concentrated stream is more efficient Injection and effective than in the case when CO2 is diluted in a large volume of various gases composing the flue CO2 can be injected into different types of geological stream. On the other hand, the oxygen is derived formations, such as saline aquifers, depleted (or near from air, requiring the addition of an air separation depleted) oil and gas reservoirs, and deep unmineable unit to the plant, which translates into additional coal seams, among others. capital investment. Under certain technical conditions, pulverized coal power generation facilities can Saline aquifers: Estimates suggest that saline aquifers be converted into Oxyfuel combustion plants and make up the largest potential storage volume for CO2 retrofitted with CCS, in order to benefit from the high storage among all available geological sequestration CO2 concentration in the flue gas, as compared to options. Potential saline aquifers for storage have the lower CO2 concentration in air-oxygen combustion porous rock and are overlain by cap rock to ensure plants (Doctor and Hanson 2010; Châtel-Pélage and there is no leakage of CO2 into the surrounding others 2003). environment (Global CCS Institute 2011). Under these conditions CO2 can be injected in a supercritical more than 70 years ago (Herzog 2009). Transport, state.2 injection, and monitoring of CO2 have also been in use for EOR in the oil exploration industry since the Depleted oil and gas fields: Injecting CO2 into 1950s. For CCS in power generation, however, the depleted oil and gas fields has the advantage of the required capture equipment would need significant tested integrity of the reservoir, which is likely to be high, scale-up compared to process units that have been since oil or gas was previously naturally stored there. realized so far. However, a downside of this is that since oil or gas has been removed, an additional number of wells are Despite the fact that these processes are technically likely to have been drilled into the geological structure. established individually, there are very few integrated This could lead to leakages and seepages that would CCS systems connecting all the parts of the CCS need to be sealed, tested, and monitored. Enhanced chain. However, industry and government cooperation hydrocarbon recovery, such as EOR is possible when has led to significant developments in the field of CCS CO2 is injected into near-depleted fields, since the in the last few years, resulting in several operating CCS increased pressure in the reservoir forces more of the projects, and plans for more pilot, demonstration, and hydrocarbon out to the surface. This in turn presents commercial plants to be constructed within the next an opportunity to obtain additional revenues for a CCS decade. project from selling extra oil or gas obtained as a result 5 of CO2 injection. The Australia-based Global CCS Institute recently released a report on the status of global CCS project Deep unmineable coal seams: There are coal development and deployment and, according to deposits that are uneconomical to mine because of their the study, eight large-scale integrated CCS projects depth. CO2 can be injected into such formations and are in operation today (Global CCS Institute 2010). stored there if left undisturbed. A potential extra upside The Global CCS Institute study defines large-scale to this storage process is the process called enhanced integrated projects as those where at least 80 percent coalbed methane (ECBM) recovery, resulting in recovery of 1 Mt/year of CO2 is captured and stored from a of methane gas, which is pushed out of the coal seam power plant, or that at least 80 percent of 0.5 Mt/ during the CO2 injection. The obtained methane could year of CO2 is captured and stored from a non be sold for profit. power generation source, such as industrial facilities. Table 2.1 lists the CCS programs considered large- Monitoring scale integrated projects. Many tools and methods are available for monitoring Of these eight projects, none are operational in the CO2 migration once injected to ensure that it stays power sector. However, among the 234 active or permanently in the ground. Examples of such methods planned CCS projects of various scale across all include time-lapse 3D seismic monitoring, passive sectors identified in the 2010 study, 77 are defined seismic monitoring, and cross-well seismic imaging as large-scale integrated projects, and 42 of these (Herzog 2011). are in the power sector, demonstrating a shift towards developing CCS capacity for electricity generation. Current Status of Technology The study also found that cumulatively, governments have stated investment commitments of up to US$40 All four of the above components making up the billion for CCS demonstration projects. Eight-seven CCS chain are established as individual technologies percent of the funding is dedicated to 22 industrial and processes in multiple sectors and practices. CO2 and power generation projects in particular, and an capture has been in use in natural gas processing additional US$2.4 billion is committed to research and and oil refining since the 1930s. The process of using development (R&D) (Global CCS Institute 2010). amine-based solvents to remove gases such as CO2 and H2S from natural gas streams was also developed 2 A substance is in a supercritical state when it is at a temperature and pressure above the critical temperature and pressure of the substance concerned. The critical point represents the highest temperature and pressure at which the substance can exist as a vapor and liquid in equilibrium (Metz and others 2005). Table 2.1: Active Large-Scale Integrated CCS Projects Project name Location Industry Storage Sleipner CO2 injection Norway Gas processing Deep saline formation Snøvit CO2 injection Norway Gas processing Deep saline formation In Salah CO2 injection Algeria Gas processing Deep saline formation Weyburn-Midale CO2 Monitoring and USA/Canada Synfuels production EOR Storage (pre-combustion capture) Rangley Weber Sand unit CO2 Injection USA Gas processing EOR Salt Creek USA Gas processing EOR Enid Fertilizer USA Fertilizer production EOR (pre-combustion capture) Sharon Ridge USA Gas processing EOR Source: Status of CCS, Global CCS Institute, 2010� 6 Economics verify these estimates. Therefore, there is significant uncertainty as to what the true costs of commercial- Leaving aside policy incentives, combining CCS scale projects will be. with any industrial or power generation process will invariably be more expensive than the original process. The International Energy Agency (IEA) recently published In the case of CCS applied at a coal-fueled power a report reviewing engineering studies from the last generation plant, not only do capital and operation five years that give cost estimates of CO2 capture from and maintenance (O&M) costs become expensive power generation, including CO2 conditioning and because of the extra equipment required, but the compression (Finkenrath 2010). The report states that output of the plant will be reduced, since a portion of the presented numbers are “estimates for generic, early the produced energy will be used in the CO2 capture commercial plants based on feasibility studies, which and compression units. This plays a significant role in have an accuracy of ±30 percent.� This demonstrates contributing to overall higher costs for power generation the scale of uncertainty and the difficulty of comparing units with CCS compared to those without. The cost cost numbers across different studies. Figure 2.2 shows of equipping power plants with CCS capture and how estimates of the increase in the levelized cost compression units is considered an incremental cost of electricity (LCOE) and decrease in efficiency for increase, as opposed to gas processing facilities, for pulverized coal plants over 300 MW net power output example, where the cost of a CO2 capture unit is a with CCS vary across the studies. It should be noted standard part of the plant capital expenditure. that the technical efficiency of a coal plant remains the same if a capture unit is included compared to a For a power plant with an integrated CCS system, coal plant without a capture unit. However, the capture the majority of the costs for CCS are the result of unit requires energy to operate, referred to as parasitic the capture component (including compression of load, and so the electricity sent out by the plant and the CO2) comprising of approximately 70 percent. Costs resulting capacity factor are reduced. There is therefore for CO2 transport (assuming a 200 km pipeline) and an energy penalty for a coal plant with CCS, often storage components are approximately 15 percent referred to as a net efficiency decrease. each, depending, of course, on the specifics of the project (IEA ETSAP 2010). Although the study calibrated the data by ensuring that the costing scope was aligned across compared A multitude of studies give cost estimates for CCS studies, and converted the costs to 2010 U.S. dollars, projects. Since there are few existing integrated the figures are not for a standardized reference plant, CCS projects in operation today, it is very difficult to but rather for plants ranging in capacity from 399 MW to 676 MW. This limits the accuracy in comparing costs Institute recently published a report that estimated across studies. that the increase in capital costs for a PC plant with CCS is approximately 80 percent, while the relative The IEA paper finds that on average, in Organization decrease in efficiency, as defined above, is 30 for Economic Co-operation and Development (OECD) percent (Global CCS Institute 2009). The report also countries, the relative increase in LCOE for a coal-fired estimates that the increase in LCOE compared to a power plant with post-combustion CO2 capture is 63 supercritical and ultra-supercritical reference plant percent, compared to a plant without CCS. The net without CCS is 61–67 percent. Although the numbers decrease in power available to the grid because of the in the IEA review and the Global CCS Institute study parasitic load of the capture unit for pulverized coal are comparable, there is still a range observed, which plant, with PC across subcritical, supercritical, and ultra- is more substantial for some parameters than others. supercritical technologies, is 25 percent. The report finds The absolute costs of CCS systems are clearly highly that in OECD countries, overnight costs for coal-fired uncertain, and more accurate predictions of these power plants with CCS of any technology is on average costs will not be possible until integrated systems are approximately US$3,800/kW, which is 74 percent built at scale, and the industry can learn from these higher than for reference plants without CCS. processes. These numbers should not be regarded as Enhanced Oil Recovery 7 necessarily accurate just because they average across different studies. The review of the cost estimates CCS projects have the objective of reducing CO2 rather provides an insight into the different ways emissions, and combining such projects with processes cost approximations can be developed, and the that recovery hydrocarbons, such as EOR, could affect assumptions for each should be taken into account to the economics through selling the extra oil recovered, fully understand the cost numbers. The Global CCS making CCS more attractive to project developers. Figure 2.2: Comparison of Studies of LCOE Increase and Net Efficiency Decrease for Post- Combustion Power Plants with CCS Relative increase in LCOE (%) Relative decrease in net efficiency (%) 100% 50% 80% 40% 60% 30% 40% 20% 20% 10% 0% 0% CMU MIT GHG IA GHG IA EPRI EPRI EPRI MIT NETL NETL GCCSI GCCSI GHG IA NZEC CMU MIT GHG IA GHG IA EPRI EPRI EPRI MIT NETL NETL GCCSI GCCSI GHG IA NZEC 2005 2007 2009 2005 2007 2009 Source: IEA 2011a� Note: The studies examined are the following: CMU: Carnegie Mellon University (Rubin 2007; Chen and Rubin 2009; Versteeg and Rubin 2010)� NZEC: China-UK Near Zero Emissions Coal Initiative (NZEC 2009)� CCP: CO2 Capture Project (Melien 2009)� EPRI: Electric Power Research Institute (EPRI 2009)� GCCSI: Global CCS Institute (Global CCS Institute 2009)� GHG IA: Greenhouse Gas Implementing Agreement (Davison 2007; GHG IA 2009)� NTEL: National Energy Technology Laboratory (NETL 2008a; NETL 2010a–f)� MIT: Massachusetts Institute of Technology (MIT 2007; Hamilton and Parsons 2009)� EOR processes only provide additional revenues of actions. If the primary objective of the project is to for CCS projects as long as the costs of capturing, recover oil, then once the process is uneconomical, compressing, and re-injecting CO2 are lower than absent some other driver to sequester CO2, the project the revenues that can be generated from selling is ended. Where other economic or regulatory drivers the additional oil recovered.3 This depends on the exist to encourage CCS projects, the CO2 would still be geological characteristics of the site that determine how injected into the depleted field even though no more oil much oil can ultimately be recovered, as well as the is produced, or else alternative sinks would need to be price at which oil can be sold. Since CO2 is recycled identified and developed. Building a connected network for EOR processes, the proportion of injected CO2 of pipelines to oil fields where EOR can be adopted, that comes directly from the CO2 source, as opposed such that CO2 could be continually stored, would to recycled CO2, will decrease over time. The result reconcile these two incentives. is that an individual site for EOR will be able to store less and less newly captured CO2. If the CO2 supply In many cases, EOR has provided economic benefits from the source, such as a power plant or natural gas and additional incentives for CCS projects. An example processing facility, remains constant over time, either is the Tenaska Trailblazer project, where its inclusion an alternative storage site would need to be identified in the scope is expected to add more than 10 million or the CO2 would be vented into the atmosphere. barrels of oil production annually to the West Texas 8 This is where different interests result in a divergence economy (Tenaska 2011). 3 It should be noted that CO2 from CO2 capture systems could be sold to a market and purchased by EOR project developers, rather than integrating the capture and storage elements into one project. However the economic argument still holds that the revenues are only possible if the price at which CO2 is sold is greater than the cost of capturing it. This depends on the profitability of EOR, which in turn depends on oil prices, and the geology of particular storage sites where EOR could be implemented. 3. TECHNO-ECONOMIC ASSESSMENT 9. Availability of revenues for CCS projects from CO2 OF CARBON CAPTURE AND STORAGE prices. DEPLOYMENT IN THE POWER SECTOR IN 10. CCS deployment targets.5 THE SOUTHERN AFRICAN AND BALKAN REGIONS It should be noted that further policies that would affect CCS deployment are not included in the modeling Developing policy recommendations to address the analysis, such as public funding and direct investment. barriers to CCS deployment requires an understanding These are discussed in detail in Chapters 5 and 6 on of the impacts of the potential policy options. The financing CCS. objective of this chapter is to describe the findings of the techno-economic modeling analysis to investigate Overview of Results the impacts of different climate policies on CCS deployment in the power sector in the Balkan and The techno-economic study finds that under some of the Southern African regions.4 Core assumptions and scenarios, CCS could be an economically competitive the main results are presented here. All supporting option, whereas in others it is not. The results are background information and other results can be summarized in Table 3.1. The percentage difference in found in the full report. All graphs and tables are the total system cost is a way of measuring the cost of from the report, on which this chapter is based. The the policy. The Reference Scenario can be thought of as 9 study involved developing a model to examine the a no-policy scenario, and therefore any increases in the impacts of policies on the following criteria over time system, cost once a policy is applied, represent the costs up to 2030 (2030 is selected as an appropriate end related to the implementation of the policy. It should to the time horizon, since it is long enough to allow be noted that only the costs of policies, and not their for capacity building and for CCS projects to be built associated benefits, are taken account of here. CO2 and operated at scale, but short enough to account emission reductions for each scenario are investigated; for timeframes often under consideration by policy they can be viewed as a benefit to weigh against costs, makers): but they are not quantified here, as would be the case in a cost-benefit analysis. 1. Development of the energy technology mix, especially noting the level of CCS deployment. In both regions, the results show that certain CO2 prices 2. Average generation costs. can result in the deployment of power plants with CCS 3. CO2 emissions. and, in some cases, the higher the price, the greater 4. Total discounted system cost, which is the the level of deployment. However, while a very high discounted cost of the entire energy sector, price (US$100/ton) in the Balkans results in a significant including investment costs, operation costs, and increase in CCS deployment, such an increase in CCS any additional penalty costs associated with the penetration is not observed in Southern Africa for particular policy. similarly high prices. This is because coal plants in the 5. These four criteria are found under variations of the Southern African regions are air-cooled, resulting in following policy scenarios in the regions: lower efficiencies. The application of CCS technology 6. Least-Cost Expansion Planning or Reference leads to additional losses in power output, and thus Scenario. capacity factors, to the point where the total efficiency 7. Forced capacity additions as prescribed by penalty becomes prohibitively costly, and reaches a level government policies and energy plans in the where CCS technology is less economically competitive regions (Baseline Scenario). than the wet-cooled plants in the Balkan region. 8. Availability of revenues for CCS projects from enhanced hydrocarbon recovery. The modeling results show that in the Balkan region, with revenues achieved through enhanced hydrocarbon 4 This chapter is based on the report, “Techno-Economic Assessment of Carbon Capture and Storage Deployment in Power Stations in the Southern African and Balkan , Regions,� by VITO, EIHP and ERC (Tot and others 2011) under a contract with the World Bank. 5 The techno-economic study includes further scenarios, including CO2 emission limits and energy efficiency policies. A selection of scenarios sufficient to demonstrate the trends in the results relating to CCS deployment, CO2 emissions and electricity prices are presented here. The results of all the scenarios modeled are available in the full report (Tot and others 2011). 10 Table 3.1: Summary of Findings Average Total system costs Percent of CCS Cumulative CO2 generation (percent increase in generation emission savings by costs in 2030 from reference portfolio in 2030 compared to Region Scenario (US$/MWh) scenario) 2030 reference (Mton) Qualitative description Southern Reference 53 NA 0 NA Coal power makes up major share of Africa electricity portfolio� Baseline (Integrated 68 4 2 701 Small amount of CCGT with CCS is Resource Plan) deployed late in planning horizon� Baseline (Integrated 68 4 2 704 Same as above, with addition of one coal Resource Plan) with plant in South Africa retrofitted with CCS� EOR/ECBM revenue benefits US$25/ton CO2 77 11 10 628 CCS applied in both newly built plants and price* retrofits in South Africa� CO2 is stored in South African and Mozambique depleted oil fields� US$50/ton CO2 93 20 12 758 Same as above, but plants with CCS make price* up further 2% of portfolio� US$100/ton CO2 114 28 16 1,496 CCGT with CCS makes up 4% of the price* 16% share in CCS� CO2 is stored in South Africa, Botswana, Namibia, and Mozambique� (continued on next page) Table 3.1: Summary of Findings (continued) Average Total system costs Percent of CCS Cumulative CO2 generation (percent increase in generation emission savings by costs in 2030 from reference portfolio in 2030 compared to Region Scenario (US$/MWh) scenario) 2030 reference (Mton) Qualitative description Balkans Reference 50 NA 0 NA Coal power makes up major share of electricity portfolio� Reference with 54 0 13 15 Newly built coal plants use EOR in Croatia EOR/ECBM revenue and Albania� Total system costs are about benefits the same as in the Reference Scenario even though capacity investments are higher, since oil revenues offset additional investment costs� US$25/ton CO2 60 30 0 173 No CCS deployed, since nuclear power is price * more competitive� US$25/ton CO2 62 30 0 154 No CCS deployed, since conventional coal price, nuclear and gas are more competitive� power unavailable* US$50/ton CO2 73 57 10 305 Coal plants with CCS are constructed in price, nuclear Kosovo, since coal is cheapest there� power unavailable* US$100/ton CO2 78 66 70 838 Newly built coal plants and retrofits with price, nuclear CCS are deployed region-wide, with only power unavailable* coal plants with CCS and non–CO2-emitting energy technologies operating by 2030� CCS Deployment 53 1�5 7 37 Three coal plants with CCS are forced to Target be constructed� NA – Not Applicable� *It should be recognized that although the carbon prices modeled here seem high in absolute terms compared to current prices seen in operating carbon markets today, it is assumed that they are indicative of circumstances where there are national or international policies with ambitious climate change mitigation targets, and that over time the costs of CCS will reduce because of technological learning� Further, it should be noted that a carbon price is not necessarily the entry point for CCS deployment, but that this should be accompanied by other financing mechanisms, as discussed in Chapters 5 and 6� 11 recovery, the application of CCS could become and should be understood to be contingent on the economically competitive in Croatia and Albania assumptions adopted. without any further policies needed. The model assumes US$40/ton revenues from EOR and US$4.8/ton from Methodology ECBM (not including costs associated with CCS). The assumption that revenues of US$40/ton injected can be Modeling exercises that enhance the understanding of achieved through EOR is based on as assumed oil price the impacts of energy policies on the electricity sector of US$70/bbl and a recovery rate of 8 percent extra are important for informing policy decisions that can oil in place. The assumptions on revenues for ECBM shape the future electricity generation mix. The purpose are based on recovery rate ratios of methane to CO2 of the study is to investigate the impact of energy injected of between one-half and one-third, and the policies in Southern Africa and the Balkans, to test understanding that CO2 would compete with nitrogen how they affect CCS deployment, CO2 emissions, total for methane recovery.6 system cost, and average generation costs. Among the countries in the region, the most competitive For the purposes of the study, techno-economic CCS options are coal-based CCS units in the Kosovo optimization models are appropriate tools to investigate area because of low coal costs and favorable extraction the impacts of policies on the power sector, since 12 conditions. they can be used to examine how well particular technologies compete against other energy technologies In Southern Africa, if benefits from EOR are included that are available, allowing the cheapest option to in the model, some plants are retrofitted with CCS. be built to meet capacity addition requirements. Modeling of the Integrated Resource Plan (IRP), the Several models have been considered for this study, South African government’s generation expansion plan, and ultimately the Model for Energy Supply Strategy shows that even without EOR/ECBM revenues, CCS Alternatives and Their General Environmental Impact combined with gas power plants could be economically (MESSAGE) was selected for reasons associated with competitive in this scenario. Among the countries in the data availability and model transferability.7 region, South Africa has the cheapest storage options, which are utilized once CCS units are built, although if The model determines the electricity portfolio, solving in additional incentives for CCS deployment are applied, one-year time steps out to 2030 by adding generation CO2 is also transported to other countries for storage. capacity and dispatching existing plants in order to With moderate CO2 prices imposed, CO2 can be meet an electricity demand profile that is provided as transported from South Africa to Mozambique, and as an exogenous initial input. The model solves, giving the the price rises considerably, storage in Botswana and resulting electricity portfolio found, by minimizing the Namibia can also be utilized. total discounted system costs over the period examined, based on calculations on the LCOE of different energy As explained in Chapter 2, it should be recognized that technology options. The total system cost is the total cost estimates associated with CCS are highly uncertain, cost for the supply of electricity to end users, including as are estimates on storage capacity. Therefore, investment, fuel, and operating costs, as well as penalty although the costs and storage capacities in the model costs as prescribed by the policy that is modeled in a have been informed by rigorous research and expert given scenario. For a detailed description of the model, consultation, the results should still be read with caution see the section, The Model, in Appendix B. 6 The CH4:CO2 ratio is between ½ and 1/3. Reeves and Oudinot estimate the cost for purification as 0.25 € /GJ. Taking the lower ratio, a gas price of US$4/GJ CH4 and appropriate unit converting and accounting for purification costs, a maximum CO2 credit of US$62/ton CO2 is obtained. This figure leaves zero profit for the private company and should be considered as an upper limit unless a higher gas price is considered. However, a private investor will consider also the alternatives for ECBM, such as N2. Reeves and Oudinot (2005) estimate the price of N2 at US$11/ton. Given the recovery ratio of N2/CH4 is estimated at 1.3/1, then the alternative “feedstock “cost is only US$14.3/ton CH4. So a private company will be prepared to pay US$14.3 for 3 tons CO2 (CH4:CO2 ratio) or US$4.8/ton CO2, which is assumed in this report. This figure can be considered as a conservative estimate. 7 MARket ALlocation (MARKAL), The Integrated MARKAL/EFOM System (TIMES), and MESSAGE (Model for Energy Supply Strategy Alternatives and their General Environmental impact) are all techno-economic optimization models that are suitable for this analysis, and were all considered for the study. TIMES and MARKAL use a more user friendly data processing system than MESSAGE, however International Atomic Energy Agency (IAEA) member countries can apply for the training in use of MESSAGE software at no cost, and MESSAGE software if free of charge and so free transfer of the model to partner countries is possible. Further, there are existing MESSAGE models of the electricity sectors in the countries considered in the two case study regions. For these reasons, MESSAGE was selected as the model to be used for this study. In order to model regional power networks effectively, bearing fields and storage opportunities. Although a significant amount of data is needed to simulate the belonging to different basins, a semi-continuous rim of system and to investigate how it develops over time. hydrocarbon fields surrounds the coasts of Namibia, Before carrying out the modeling analysis, an inventory South Africa, and Mozambique. Depending on the size of potential capacity additions and their associated of the rifted blocks and substructures, small or larger oil CO2 emissions and costs was prepared for each of and gas fields have been formed. the countries in the case study regions, and entered as inputs in the model. Similarly, potential storage Excellent-quality coal deposits are found in the Southern sites and their associated costs were researched and African region. Because of its shallow depth, coal has included in the model. Data on storage estimates were been mined mainly in the South Africa Karoo Basin. based on previous studies documenting geological Where the coal occurs at greater depths, coal-bed reservoir characterization in the selected regions. For methane extraction becomes an option. This is the case, South Africa, the Atlas on Geological Storage of Carbon for instance, in the Great Kalahari Basin, which spreads Dioxide in South Africa by the Council for Geoscience out largely over Botswana and minor parts of Namibia, and its associated technical report (Viljoen and others South Africa and Zimbabwe. 2010) was used, augmented by additional papers and reports for the other countries in the region. For The underlying assumptions for the model scenarios and the Balkan region, the EU GeoCapacity project (EU parameters, including fuel costs, electricity technologies, 13 GeoCapacity 2006) served as the main source of data. and their associated costs and storage options are For a complete list of the references, see Table B.1 in given in the section, Assumptions in Model of Southern Appendix B. Based on this research, storage options Africa, in Appendix B, Tables B.2–B.6. and their estimated costs were developed. For details on the method of cost estimation and the storage options Scenarios Modeled used in the model, see the section, Storage Options, in Appendix B. Tables B.5, B.6, and B.10 in Appendix B In the Southern Africa region, the following scenarios give the underlying assumptions on storage options in are modeled, with the study horizon running from 2010 both regions used as inputs in the model. to 2030. Southern African Region • Reference Scenario: This is the least-cost option, with the only constraint being that plants that have a The following countries of the Southern African region commitment to be built in the base year are forced are included in the modeling exercise: the Republics to be built. Without any other policies, the remaining of Botswana, Mozambique, Namibia, and South capacity additions are selected purely on a least-cost Africa. This selection of countries is determined by the basis. availability of both storage capacity data and plant-level • Baseline Scenario: This scenario portrays the cost information. situation where capacity additions are built out according to the current plans and policies in place. The main medium-term generation expansion options in Here, the Baseline Scenario represents the Integrated the region are coal based thermal power plants, gas and Resource Plan 2010, which applies to South Africa, oil thermal power plants, and large-scale hydropower and includes a CO2 limit in South Africa. This is installations (South Africa DOE 2011). In the longer modeled both with and without EOR and ECBM term, nuclear could also be an option in South Africa, options providing extra revenues. and a small portion of renewable (wind and solar) • CO2 Price Scenarios (also with a CO2 constraint additions are in consideration in all four countries. for South Africa). CO2 prices of US$25/ton CO2 US $50/ton CO2 and US$100/ton CO2 are individually The main CO2 reservoir opportunities in Southern modeled, with EOR and ECBM benefits included. Africa relate to either the petroleum or coal basins. Modeling carbon prices has a similar effect as The oil and gas prospects are located onshore close a CO2 tax in the model, promoting non-GHG- to the coast and offshore. Rifted blocks from several emitting technologies and penalizing those that emit ages contain reservoir, source, and sealing rocks in CO2. The US$25/ton CO2 price modeled is close geometrical trap situations that provide hydrocarbon- to the figure of approximately ZAR 200/ton CO2 that has recently been discussed in South Africa as Table B.4 in Appendix B shows planned investments in a potential CO2 tax (National Treasury, South Africa new generation capacity according to the South Africa 2010). DOE IRP “Revised Balanced� expansion plan. The scenario also imposes a limit on CO2 emissions for Modeling Results for Southern Africa South Africa at the level of 275 Mton/year, as specified in the IRP 2010. Figure 3.2 shows the technology For the scenarios modeled, the breakdown in electricity breakdown in electricity generation in the region for portfolio is shown. For all the scenarios, the CO2 the baseline case, reflecting the IRP “Revised balance� emissions in the region are almost entirely from South expansion plan. Africa, with a very small contribution from Botswana, while GHG emissions in Mozambique and Namibia are The technology breakdown is similar to the Reference negligible. Scenario in the sense that the existing capacity of coal plants without CCS still makes up the majority of the Reference Scenario electricity generation portfolio. However, compared to the Reference Scenario, less electricity would be Figure 3.1 shows the electricity generation over time generated by coal (new or existing) by 2030. This across the Southern African region broken down by drop in the coal share is largely taken up by nuclear 14 technology for the Reference Scenario. The figure shows power and solar power in South Africa. In addition, that electricity generation fueled by coal dominates the combined cycle gas turbines (CCGTs) with CCS enters energy mix over the entire region for the study horizon. the electricity mix from 2027, implying that there is a At the beginning of the period, this contribution is from role for CCS with gas power in meeting the stringent existing coal plants, which are later displaced by new CO2 limit that South Africa intends to impose. It is coal plants (which do not have CCS) as the existing worthwhile pointing out the baseline case modeling ones are retired. the IRP has a 4 percent greater total system cost than the Reference Scenario. The IRP targets are developed In the Reference Scenario, CCS is not deployed as part by modeling the Long Term Mitigation Strategies, but of the generation mix technologies because it is not have also been informed by political influences and economically competitive in the marketplace. stakeholder engagement. It is therefore unsurprising that the resulting policies should lead a slightly Baseline Scenario suboptimal energy technology mix in terms of pure economic cost. In this scenario, gas power plants with This scenario models the South Africa Department CCS make up approximately a 2 percent share of of Energy’s (DOE’s) IRP policies, forcing certain electricity generation. technologies to be constructed at given levels. Figure 3.1: Electricity Generation for Figure 3.2: Electricity Generation for Southern African Region—Reference Scenario Southern African Region—Baseline Scenario 500 500 Electricity Supply (TWh) Electricity Supply (TWh) 400 400 300 300 200 200 100 100 0 0 2010 2015 2020 2025 2030 2010 2015 2020 2025 2030 Net Imports Wind Hydro Net Imports Wind Hydro Nuclear CCGT CCS CCGT CCS CCGT Coal New CCGT OCGT Coal CCS Coal New The result of applying a US$25/ton of CO2 price is that Figure 3.3: Electricity Generation Portfolio for Southern African Region—US$100/Ton CO2 the share in electricity generation from coal power plants Price Scenario without CCS drops from 86 percent to 61 percent in 2030, while shares of nuclear power and renewables 500 in the electricity mix increase. Electricity generated Electricity Supply (TWh) 400 from coal plants with CCS has a share of 10 percent by 2030, from both new build plants and retrofits, 300 with CO2 stored in depleted South African oil fields 200 and depleted Mozambican oil fields (transported from South Africa). In the US$50/ton CO2 price scenario, 100 the electricity generation mix is similar to the US$25/ton scenario, but with a slightly greater role for coal power 0 2010 2015 2020 2025 2030 generation with CCS, with a share of 12 percent in the electricity generation portfolio by 2030. The amount of Net Imports Wind Solar Hydro Nuclear CCGT CCS CCGT OCGT Coal CCS Coal New CO2 stored is also similar, with the same two storage sites being utilized, and approximately 20 Mt more CO2 cumulatively stored by 2030. Figure 3.3 shows the technology breakdown in the US$100/ton CO2 scenario. 15 Baseline Scenario with EOR/ECBM Benefits With a CO2 price of US$100/ton, the share of This scenario includes the South Africa DOE 2011 IRP electricity generation from coal without CCS drops with the same CO2 limit of 275Mton for South Africa from 86 percent to 29 percent in 2030, compared to as an input into the model, but it also includes the the Reference Case, and the share of nuclear power potential to gain revenues from EOR/ECBM recovery. generation rises from 5 percent to 28 percent in the The only difference in this scenario compared to the same year. Electricity generation fueled by coal with baseline without EOR/ECBM is that a small portion of CCS has a share of 15 percent, all from new build the electricity generation mix is from one plant retrofitted plants, since retrofits are more expensive than new with CCS in South Africa. Approximately 1 Mton CO2/ builds, while CCGT with CCS makes up 4 percent by year is transported from this capture facility to depleted 2030.8 Renewables also increase their share to 18 oil and gas fields in Mozambique towards the end of percent by 2030. Figure 3.4 shows the cumulative CO2 the study horizon. Again, CCS technologies contribute stored by storage location. approximately 2 percent of electricity generation across the region. Three extra storage sites are utilized in this scenario compared to the scenarios with US$25/ton and US$50/ CO2 Price Scenarios ton CO2 prices, namely, in Botswana, Namibia, and South Africa. Three price levels are modeled to investigate their impact on CCS deployment—US$25/ton CO2, In summary, by 2030, a carbon price of US$25/ton US$50/ton CO2, and US$100/ton of CO2. All CO2 results in a 10 percent share of power plants with scenarios assume least-cost capacity additions without CCS in the electricity generation portfolio. With US$50/ the baseline (IRP) build constraints, other than the ton CO2, a 12 percent share is achieved, and with committed build plans, and so other than the imposed US$100/ton CO2, a 15 percent share is reached. prices are the same as the Reference Scenario. Including a carbon price in the model forces emitting Summary of Results units to buy permits for each ton of CO2 emitted equal to the carbon price, making CO2-emitting technologies Table 3.2 shows the installed capacities by technology more expensive. across the region for all the scenarios, and Figure 3.5 8 The CCS retrofits option in the model includes retrofitting existing or future plants (mainly those to be constructed by 2020) with CCS. Retrofits are more expensive when considering the initial cost of the original plant, as well as incremental cost of adding the capture component, compared to the new build CCS option. An increase in investment costs of 40 percent is assumed. Figure 3.4: Cumulative CO2 Storage for Southern African Region—US$100/Ton CO2 Scenario 300 Cumulative Stored CO2 (Mton) 250 200 150 100 50 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Namibia depleted oil fields South Africa export to Mozambique Depleted Oil fields South Africa export to Botswana coal fields South Africa Saline Aquifer (East) South Africa Saline Aquifer (South) South Africa depleted oil field 16 gives a snapshot of the technology mix and the amount among scenarios differs is because of the different levels of CO2 stored in 2030. Table B.7 in Appendix B of renewable penetration. Renewable technologies have summarizes all the results across the scenarios. It should lower capacity factors, and therefore when renewables be noted that the reason the total installed capacity Table 3.2: Summary of Installed Capacity in 2030 for the Southern African Region (MW) Scenarios Baseline with US$25/ton US$50/ton US$100/ton EOR/ECBM with EOR/ with EOR/ with EOR/ Energy source Reference Baseline benefits ECBM benefits ECBM benefits ECBM benefits Coal (existing) 29,080 27,712 27,718 27,617 27,617 27,237 Coal (new) 21,895 15,972 15,972 9,774 9,222 9,207 Coal with CCS 0 0 0 5,936 7,294 6,840 Oil 6,812 6,657 6,657 5,152 3,828 3,767 Gas 8,486 2,543 2,543 9,092 8,294 1,229 Gas with CCS 0 2,370 2,370 0 0 2,583 Nuclear 1,800 11,400 11,400 4,922 5,202 16,200 Hydro 6,335 3,431 3,431 6,335 6,335 6,335 Pumped storage 4,232 4,232 4,232 4,232 4,232 2,732 Biomass 130 130 130 130 130 1,500 Solar 724 9,442 9,442 4,438 5,557 16,337 Wind 800 8,400 8,400 8,800 10,524 12,067 TOTAL 80,294 92,289 92,295 86,428 88,235 106,034 Percentage of 0 2 2 10 12 16 CCS in electricity generation Figure 3.5: Summary of Results for Southern African Region, 2030 100% 300 Share of Total Electricity Generation 90% Cumulative Stored CO2 (Mton) 250 80% 70% 200 60% 50% 150 40% 100 30% 20% 50 10% 0% 0 2010 2030 – Reference 2030 – Baseline 2030 – Baseline EOR 2030 – CO2 price $25/ton 2030 – CO2 price $50/ton 2030 – CO2 price $100/ton 17 Gas CCS Coal CCS Other RE Hydro/PS Nuclear Gas Oil Coal Stored CO2 (Mton) make up a larger share of the electricity portfolio, Figure 3.6: Comparison of Average greater overall installed capacities are required. Generation Costs across Scenarios for the Southern African Region Figure 3.6 compares the average generation costs across the different scenarios (these costs do not 140 Average Generation Costs ($/MWh) include any additional costs incurred from purchasing 120 CO2 permits at the modeled CO2 price for any given scenario). The reference case is the cheapest, 100 unsurprisingly, since this is the least-cost option by 80 default. The average generation cost in the Revised Baseline (IRP) Scenario without EOR/ECBM benefits is 60 the same as the cost with EOR/ECBM benefits, since 40 there is little change in the electricity portfolio. Of the policy scenarios, the Baseline Scenario has the lowest 20 average generation costs. The higher the CO2 price, the 0 higher the average generation cost, with significantly 2010 2015 2020 2025 2030 increased costs seen in the US$100/Ton CO2 Price Scenario. This is because imposing a CO2 price in the Reference CO2 price, Baseline with model requires emitting units to buy permits at that price $25/ton EOR for every ton of CO2 released into the atmosphere. CO2 price, CO2 price, Baseline Average generation costs increase as greater CO2 $50/ton $100/ton EOR prices are imposed because of the additional costs of buying these permits, or from the electricity sector switching from cheaper electricity sources, such as coal, to more expensive technologies with lower emissions. reaches 10 percent by 2030. This increases to 12 Figure 3.7: Comparison of Annual CO2 Emissions across Scenarios for the Southern percent with a price of US$50/ton CO2, and 15 percent African Region with US$100/ton CO2. In this last case, it is economical to store CO2 in sites in South Africa, Botswana coalfields, 400 and Mozambican and Namibian depleted oil fields. 350 The Balkan Region CO2 Emissions (Mton) 300 250 For the purposes of this study, the Balkan region refers 200 to the Southeastern Europe area covering the Republics 150 of Albania, Croatia, Macedonia, Montenegro, Kosovo, Serbia, and the Federation of Bosnia and Herzegovina. 100 50 The main generation expansion options in the region 0 are coal-based thermal power plants and large- scale hydropower plants. Greater use of natural gas 2010 2015 2020 2025 2030 in electricity generation is limited by the lack of gas 18 Reference CO2 price, Baseline with transport and distribution networks. Only Croatia and $25/ton EOR northern Serbia currently have suitable gas supply CO2 price, CO2 price, Baseline routes. However, it is reasonable to expect that by $50/ton $100/ton EOR 2020, gas networks will be well developed throughout the region, since all countries are likely to consider gasification as a technology option (subject to the development of large-scale gas pipelines from Russia In contrast to Figure 3.6, Figure 3.7, showing the CO2 and the Caspian area). The largest coal reserves are emissions levels for each scenario, demonstrates an available in Kosovo, followed by Serbia and Bosnia and opposite pattern of the generation cost results. The Herzegovina. Reference Scenario has lowest average generation costs, but emits the most CO2, and the most costly US$100/ The geology of the selected Balkan region is Ton CO2 Price Scenario results in the lowest emissions dominated by the Carpathian and Alpine orogenies in levels. The graph shows that the US$100/Ton CO2 Price a mountain chain surrounding the Pannonian Basin. Scenario gives significantly lower CO2 emissions than all The Pannonian Basin groups several sub-basins and the other policy scenarios, which are comparable. hosts oil and gas fields. It could contain also various non-hydrocarbon–prone storage structures. In general, Conclusions for the Southern African Region the potential storage volume in the Pannonian Basin structures is relatively small (on the order of one to In the Reference Scenario without any additional policies, a few Mton CO2-storage capacity) (Dolton 2006). CCS technologies are not competitive. In the case where The Albanian petroleum structures, which formed current energy policies (in this case the South African in a geologically different setting, are larger, with Integrated Resource Plan) are modeled, including the several fields showing storage capacities above 10 CO2 limit of 275 Mton of CO2 per year, the model finds Mton CO2. The oil and gas fields in the Albanides are there could be a small penetration of CCS in gas-fired generally larger than the Pannonian field, which makes plants towards the end of the planning horizon, with no the Albanian depleted fields more suitable for CO2 CCS in coal-fired plants being constructed. If revenues storage. from EOR/ECBM are included in the model, CCS retrofits could be installed on South African coal plants, The general model assumptions for the Balkan region, and CO2 exported to Mozambique depleted oil and gas including fuel prices, energy technology expansion fields towards the end of the 2020s. options and their associated costs, and CO2 storage options and costs, are given in the section, Assumptions With a price of US$25/ton CO2, the share of coal in The Model for the Balkan Region, in Appendix B in power plants with CCS in the model of the power sector Tables B.8–B.10. Scenarios Modeled Figure 3.8: Electricity Generation for the Balkan Region—Reference Scenario In the Balkan region, the following scenarios are modeled from 2015 to 2030 (2015 is selected as the 160 base year, since it is unlikely that investments will be made in the region between 2010 and 2015): 120 • Reference Scenario: This is the least-cost option, with the only constraint being that plants that have a TWh commitment to be built in the base year are forced 80 to be built. Without any other policies, the remaining capacity additions are selected purely on a least-cost basis. This is modeled both with and without EOR 40 and ECBM options providing extra revenues • Baseline Scenario: This scenario portrays the situation where capacity additions are built out 0 according to the current plans and policies in place. 2015 2020 2025 2030 Years • CO2 Price Scenarios: CO2 prices of US$25/ton,9 19 US$50/ton, and US$100/ton CO2 are individually Oil Gas Nuclear Coal modeled. Wind Hydro Demand • CCS Deployment Target Scenario: This scenario involves forced building of a particular amount of capacity of fossil power with CCS. US$32.4 billion, while the total system discounted Modeling Results for the Balkan Region cost is US$32.1 billion. Figure 3.9 shows the CO2 emissions for each country for the Reference Scenario. Reference Scenario The Reference Scenario assumes the least-cost electricity generation development plan, that is, free construction Figure 3.9: CO2 Emissions for the Balkan of the most economic capacity expansion options. Region—Reference Scenario Figure 3.8 shows the electricity generation expansion 100 under the Reference Scenario. Regional electricity generation in the Reference 80 Scenario is dominated by power plants fueled by domestic and imported coal. The share of the coal- 60 Mton CO2 based generation in the total electricity production increases from 49 percent in 2015 to 72 percent in 2030, almost tripling in absolute terms. Hydropower 40 is constant throughout the period, and electricity generation from wind is negligible. The red line in 20 Figure 3.8 indicates the total demand (including transmission and distribution losses) in the region, and surpluses of production in the region (above 0 2015 2020 2025 2030 the red line), can be exported from 2018. By 2030 Years approximately 16 GW of new generation capacity Macedonia Albania Kosovo Montenegro is added, predominantly from coal power plants. Bosnia and Herzegovina Serbia Croatia Total investment in new power units amounts to 9 US$25/ton is close to the value of carbon permits under the EU ETS. The increasing share of coal in the generation portfolio additional policies. Figure 3.10 shows the breakdown drives annual CO2 emissions up from 52 Mton in 2015 in the electricity portfolio by non–CO2-emitting sources, to 93 Mton in 2030 across the region, which is an new build coal plants with CCS, and all other electricity increase of 78 percent. Cumulative CO2 emissions over generating technologies. The share of new build coal the period from across the region reaches 1,355 Mton power plants with CCS in the overall electricity portfolio by 2030, which is comparable to the estimated total reaches 13 percent in 2030. underground storage volume in the region, albeit that the potential volume in many jurisdictions is still to be Total investment costs in new units in this scenario confirmed. The country with the most CO2 emissions is are US$41billion, which is US$8.6 billion above the Serbia, which emits on average 41.1 percent, followed Reference Scenario. However, this substantial increase by Bosnia and Herzegovina (23 percent) and Kosovo in investments is offset by the revenues from crude oil (14 percent). markets, and therefore the total discounted system costs work out to be about the same as the system The results of the modeling of the Reference Scenario costs in the previous Reference Scenario without EOR demonstrate that CCS would not be deployed at all benefits. Cumulative CO2 emissions savings amount over the period examined, since it is not economically to 15.2 Mton, while the total CO2 stored amounts to competitive. approximately 100 Mton by the end of the investigated 20 time period. Therefore, if EOR opportunities are Reference Scenario, with EOR/ECBM Benefits available, coal power plants with CCS could be competitive. This scenario assumes that CO2 could be stored in near- depleted oil fields where EOR could produce a benefit CO2 Price Scenarios of US$40/ton of CO2 stored, which is modeled as a possibility in Albania and Croatia from 2020 onwards as Several CO2 price scenarios are modeled in the Balkan the data suggest that these are the only two countries in region. A carbon price of US$25/ton CO2 is not a high the region where EOR could be a possibility. enough price to make fossil fuels with CCS competitive. If nuclear power is a technology option in the model, The results show that in this case, electricity from coal it competes with conventional coal plants and makes plants with CCS could be competitive even without any up some of the share of the electricity mix. If nuclear power is not included in the model, with a US$25/ton price, coal plants with CCS are still not competitive, and natural gas and conventional coal power make up the Figure 3.10: Share of CCS in Coal-Based Power Generation in the Balkan Region— lion’s share of capacity additions. With a carbon price Reference Scenario with EOR/ECBM benefits of US$50/ton CO2, however, and with if nuclear power is not an option in the model, CCS technology becomes 160 economically competitive in the Kosovo area after 2020 because of cheap domestic coal development opportunities there. Coal plants with CCS also become 120 competitive in Albania towards the end of the period. All the CCS units constricted in this case are new builds, not retrofits. TWh 80 With a carbon price of US$100/ton and with nuclear power unavailable, coal plants with CCS become 40 much more competitive and are deployed across the region, while CCS retrofits also become competitive. Figure 3.11 shows the electricity technology mix split 0 into non–CO2-emitting technologies, fossil plants 2015 2020 2025 2030 with CCS, fossil plants retrofitted with CCS, and Years other technologies (CCS is applied in both coal and Other RETROFIT CCS Non CO2 gas plants, although in gas plants only as retrofits). The figure shows that by 2030, the entire electricity There is a substantial drop in CO2 emissions after 2020 generating portfolio is made up of non–CO2-emitting when coal plants with CCS are available to come online energy technologies and coal plants with CCS—both if economically competitive (power plants with CCS are new builds and retrofits, making up a 70 percent share constrained in the model not to be built before 2020, to of the total portfolio. Figure 3.12 shows the amount of take account of the time for required capacity building CO2 stored over the horizon broken down by country. before CCS units can be built at scale). Cumulative savings in CO2 emissions are 837.1 Mton, and at the end of the period 650 Mton of CO2 have been stored underground. The average generation costs increase Figure 3.11: Share of CCS-Based Generation at the same time as the CO2 emissions drop, but then in the Balkan Region—US$100/Ton CO2 Price stabilize between US$75 and US$80/MWh from 2023 Scenario onwards, while the CO2 emissions also stabilize after 160 2020 once CCS technology is available. Figure 3.13 shows how the CO2 emissions are reduced dramatically as coal power is phased out. 120 CCS Deployment Target Scenario 21 The CCS Deployment Target Scenario represents TWh 80 targeted development of several CCS projects. The optimal solution from the Reference Scenario is modified to include the forced construction of coal plants with 40 CCS starting in 2025, to replace the construction of conventional coal units selected in the Reference Scenario. This means that instead of allowing the model 0 2015 2020 2025 2030 to select the least-cost capacity additions, the model Years is forced to select certain coal plants to be built with Other RETROFIT CCS Non CO2 CCS. No other policies or constraints are modeled. In total, three 500 MW coal plants equipped with CCS are forced by the model to be constructed in Bosnia and Figure 3.12: CO2 Stored in the Balkan Region—US$100/Ton CO2 Price Scenario Figure 3.13: CO2 Emissions for the Balkan 700 Region—US$100/Ton CO2 Price Scenario 600 80 500 60 Mton CO2 400 Mton CO2 300 40 200 20 100 0 0 2015 2020 2025 2030 2015 2020 2025 2030 Years Years Macedonia Albania Kosovo Montenegro Macedonia Albania Kosovo Montenegro Bosnia and Herzegovina Serbia Croatia Bosnia and Herzegovina Serbia Croatia Herzegovina, Kosovo, and Serbia, since these are the shows the average generation costs across the countries with the most available local coal resources. scenarios. As was seen for the Southern African region, the Reference Scenario is cheapest, where the CCS Cumulative carbon savings amount to 37 Mton of Deployment Target Scenario is closest to the Reference CO2 over the entire modeling period, which is 2.7 Scenario in terms of generation costs, while the US$100/ percent less compared to the Reference Scenario. The ton CO2 Price Scenario results in the highest average total discounted system costs are only 1.5 percent generation costs. Conversely, the US$100/ton CO2 price greater than the Reference Scenario, demonstrating has the lowest CO2 emissions, while the Reference Case that this policy is overall not much more costly than has the highest, as shown in Figure 3.15. the Reference Scenario, but does result in lower CO2 emissions. In total, 42.7 Mton of CO2 would be stored Conclusions for the Balkan Region underground by these three countries by 2030. This scenario results in a 7 percent share of CCS units in Similarly to the Southern African region, under the the total electricity production by 2030. There are no Reference Scenario, CCS options are not competitive, retrofits in this case, since no policies are applied other since they are more expensive than all other than to force construction of three coal plants with CCS. alternatives. However, if revenues from EOR are available, CCS could be competitive without any further 22 Summary of Results policies to promote it. Table 3.3 gives installed capacity by fuel type across Under the US$50/Ton CO2 Price Scenario, coal plants the region for the scenarios examined, and Figure 3.14 with CCS could become competitive, assuming that Table 3.3: Summary of Installed Capacity in 2030 for the Balkan Region (MW) Scenarios CO2 tax CO2 tax CO2 tax CO2 tax US$25/ton US$25/ton US$50/ton US$100/ton Energy Reference (nuclear (nuclear (nuclear (nuclear CCS source Reference +EOR available) unavailable) unavailable) unavailable) target Coal without 14,920 11,406 11,512 13,551 10,310 0 13,447 CCS Coal with CCS 0 6,000 0 0 2,120 7,520 1,500 (new builds) Coal with CCS 0 0 0 0 0 6,098 0 (Retrofits) Gas without 1,190 1,190 1,190 1,617 2,517 258 1,190 CCS Gas with CCS 0 0 0 0 818 0 0 (new builds) Gas with CCS 0 0 0 0 0 1,227 0 (retrofits) Nuclear 427 427 2,619 0 0 0 427 Hydro 10,256 9,932 10,537 11,237 14,309 14,153 10,256 Wind 320 320 320 320 465 1,215 320 TOTAL 27,113 29,275 26,178 26,725 30,539 30,471 27,140 Percentage 0 13 0 0 10 70 7 of CCS in electricity generation Figure 3.14: Comparison of Average Figure 3.15: Comparison of Total CO2 Generation Costs across Scenarios for the Emissions across Scenarios for the Balkan Balkan Region Region 80 120 70 100 80 USD/MWh Mton CO2 60 60 50 40 40 20 30 0 2015 2020 2025 2030 2015 2020 2025 2030 Years Years CCS Deployment CO2 price, 100USD/ton, CCS Deployment CO2 price, 100USD/ton, Target Scenario NO NUCLEAR Target Scenario NO NUCLEAR CO2 price, 50USD/ton, CO2 price, 25USD/ton, CO2 price, 50USD/ton, CO2 price, 25USD/ton, 23 NO NUCLEAR NO NUCLEAR NO NUCLEAR NO NUCLEAR CO2 price, 25USD/ton Ref + EOR/ECBM CO2 price, 25USD/ton Ref + EOR/ECBM Reference Reference nuclear power is unavailable. According to the model In the CCS Deployment Target Scenario, three 500 MW results, coal-fueled power plants with CCS are most CCS coal units would be added to the generation competitive in the Kosovo area because of low coal capacity in 2025. This strategy would lead to a 7 prices and favorable extraction conditions. With a percent share of CCS equipped power plants in the CO2 price of US$100/ton CO2, regionwide adoption total electricity production mix by the end of 2030, of CCS is possible, including retrofits and new builds, while average generation costs would only increase by and by the end of 2030, practically all plants could be 6 percent. equipped with CCS. 4. ADDRESSING THE LEGAL AND 8. Regulatory compliance and enforcement schemes. REGULATORY BARRIERS IN DEVELOPING 9. Environmental impact (including cumulative impact) COUNTRIES assessment process, risk assessment, and public consultation. Addressing barriers to CCS deployment in any country involves creation of a regulatory base, among other This chapter of the report is based on a summary of things, to help reduce potential legal risks related to the two analyses of existing regulatory frameworks in the implementation of CCS projects to be borne by both Southern African and Balkan regions. The first section public and private sectors. The objective of this chapter provides a review of the relevant legal instruments at the is to identify potential challenges to the development international and multilateral level that seeks to indicate of cross-boundary and national CCS projects, and to and identify the relevance of each instrument for CCS suggest approaches to remove them. This chapter is and, where possible, the potential implications of the based on in-depth reports summarizing the findings instruments for CCS projects in the Southern African for both the Southern Africa and Balkan regions as region and Balkan region. The following two sections case studies.10 The analysis is developed based the contain analyses of relevant national legislative and examination of the existing multilateral, bilateral, institutional frameworks in Botswana, Mozambique, and and national regulatory and legal frameworks in the South Africa, and Bosnia and Herzegovina, Kosovo, Southern African and Balkan regions, and focuses on and Serbia, respectively, organized by the key issues 25 the following key issues: listed above. 1. Classification of CO2 and its legal definition, A summary of key findings on the issues analyzed, along including proprietary rights of stored CO2. with recommendations for the adoption of national and 2. Jurisdiction over the control and management regional regulatory frameworks that may be applicable of domestic and cross-boundary pipelines and to CCS activities,12 are provided in Box 4.1. reservoirs (including monitoring, reporting, and verification requirements). Key International and Multilateral Legal 3. Proprietary rights to cross-boundary CO2 capture Instruments Relevant to CCS Projects and storage sites and facilities. 4. Regulatory and/or licensing (permitting) schemes At this stage, there is no international instrument that related to the operation and management of is dedicated to CCS-related issues. However, certain storage and transportation facilities. sectoral agreements and conventions have or may have 5. Long-term management and liability issues arising implications for CCS activities in the Southern African out of accidents or leaks in domestic and cross- and Balkan regions. In this context, the most relevant boundary CCS projects. conventions or agreements relate mainly to climate 6. Financial assurance for long-term stewardship, change and maritime law, and in particular, conventions including how long-term responsibility for a storage concerning the protection of the marine environment. site is transferred to the relevant authority, and how CCS regulatory frameworks may reduce the UNFCCC and the Kyoto Protocol financial exposure of the relevant authority by requiring the operator to contribute to the costs Recent developments under the 1992 United Nations associated with long-term stewardship of the site.11 Framework Convention on Climate Change (UNFCCC) 7. Third-party access rights to transportation networks, and the 1997 Kyoto Protocol may have important transit rights, and land rights with regard to pipeline implications for CCS. At the 16th Conference of Parties routes. (COP) in Cancun, Mexico, in December 2010, Decision 10 The country-specific reviews were conducted by independent consultants: Chilume and Company (Botswana); Sal and Caldeira Advogados, LDA (Mozambique); and IMBEWU Sustainability Legal Specialists (Pty) Ltd (South Africa) for the Southern African region; and by Milieu Ltd. for the Balkan region. The reports can be accessed at http://go.worldbank.org/MJIX0TRAB0. 11 This issue was examined only for the Balkan region. 12 The recommendations are based on a high level analysis of relevant international and multilateral treaties and laws in the six countries, and it must be noted that laws in this field are continually evolving at the national, regional and international levels. Therefore, the analyses of laws and the recommendations should be considered accurate as at the date of this report, and the proponents of CCS interventions are advised to revisit the assumptions and conclusions included herein at the time of the interventions. Box 4.1: Key Findings and Recommendations At the international level: 1� There are grounds to recommend a platform for countries in the Southern African and Balkan regions to discuss and agree on multilateral and regional treaties for important CCS-related issues, such as compliance, enforcement, and dispute-resolution mechanisms, in case these countries decide to consider such issues� 2� Multilateral and regional agreements on potential cross-boundary movement of CO2 for disposal would be needed so that operations can be conducted based on an agreement among the countries concerned� 3� In terms of property rights, there might be a need for a specific multilateral agreement to address the propriety rights over various segments of cross-boundary transportation� Each agreement and treaty could provide sufficient compliance, enforcement, and dispute-resolution mechanisms� 4� At the point where CCS is poised to reach an operational level, the following issues should, at a minimum, be taken into consideration and addressed by a regional and international regulatory framework for CCS activities (UNFCCC 2010e): i� The selection of a CO2 storage site in geological formations should be based on robust criteria in order to seek to ensure the long-term permanence of the storage and the long-term integrity of the storage site� ii� Stringent monitoring plans should be in place in order to reduce the risk to the environmental integrity 26 of CCS in geological formations� iii� A framework should provide for a thorough risk and safety assessment, as well as a comprehensive socio-environmental impacts assessment, prior to the deployment of CCS in geological formations� iv� A framework should adequately and clearly address the following issues related to liability: a� A means of redress for communities, private sector entities, and individuals affected by the release of stored CO2 from CCS project activities� b� Provisions to allocate liability among entities that share the same reservoir, including if disagreements arise� c� Possible transfer of liability� d� Long-term liability needs to be specifically addressed, including (a) CO2migration to areas where it was not originally injected, which may result in public health, environmental, or ecosystem damage; (b) transnational liability, to be determined specifically by means of intergovernmental agreement among the countries concerned; and (c) applicable corrective measures in case of leakage� At the domestic level: While none of the three countries in the Southern African region has adopted a CCS-specific legal instrument, all three countries appear to have the basic elements that touch on certain aspects of the issues discussed� None of the three countries examined in the Balkan region are members of the European Union yet, but as candidate countries, all are committed to EU membership and will at some point in the future need to take steps to harmonize with Directive 2009/31/EC (The CCS Directive)� At this stage, none of the three countries has transposed Directive 2009/31/EC into national law� The tables in the appendixes summarize the key findings for each of the six countries analyzed and set forth recommendations that may be adopted at the domestic level necessary for an effective regional framework on CCS� .6, 7/CMP “Carbon Dioxide Capture and Storage (UNFCCC 2010e). Furthermore, the COP/MOP asked in Geological Formations as Clean Development the Subsidiary Body for Scientific and Technological Mechanism Project Activities� was adopted. The Advice (SBSTA), at its 35th session, to elaborate Conference of Parties/Meeting of Parties (COP/MOP) modalities and procedures for the inclusion of CCS in decided that “carbon dioxide capture and storage in geological formations as project activities under the geological formations is eligible as project activities Clean Development Mechanism (CDM) (UNFCCC under the clean development mechanism,� provided 2010e). This Decision will have critical implications for .5, that the issues identified in decision 2/CMP para. 29, CCS projects, not only regarding their potential inclusion are addressed and resolved in a satisfactory manner in the CDM, but also regarding their specific conditions. United Nations Convention on the Law of the Sea, CO2 capture processes in geological formations under 1982 the seabed. Specifically, it provides that “carbon dioxide streams from carbon dioxide capture processes for The United Nations Convention on the Law of the sequestration� can be stored if they meet three criteria: Sea (UNCLOS) sets the limit of various zones, such as (a) disposal is into a sub-seabed geological formation; internal waters, territorial waters, archipelagic waters, (b) the CO2 stream is of high purity containing only contiguous zones, exclusive economic zones (EEZs), and incidental amounts of associated substances; and the continental shelf. In essence, coastal states have (c) no wastes or other matter are added for the purpose jurisdiction over their territorial sea, EEZ, and continental of disposing of those wastes or other matter (London shelf, and may therefore prescribe regulations within Protocol 1996). This Protocol was welcomed as an these areas (UNCLOS, article 21).13 It has been argued important step towards addressing the legal uncertainty that a country has sovereign rights to use underground surrounding CCS and is regarded by some scholars as aquifers and reservoirs on the continental shelf and the first international law explicitly addressing carbon in the EEZ for injection of CO2 for both depositing sequestration in international waters and a step towards purposes and enhanced oil recovery (Solomon and creating a positive international legal framework for others 2007, p. 6). However, for oil and gas reservoirs, CCS activities (WRI 2006). including aquifers in the continental shelf that are shared with neighboring countries, it has been argued that a Basel Convention on the Control of Trans- 27 country cannot unilaterally decide to use such reservoirs Boundary Movements of Hazardous Wastes and and aquifers for CO2 injection without an agreement Their Disposal, 1989 (Basel Convention) among the parties, and such an approach might also apply to inland reservoirs (Solomon and others 2007, p. The Basel Convention imposes strict requirements on 6). UNCLOS, however, is silent on the rights of coastal trans-boundary movements of hazardous waste, such as states in relation to disposal of CO2 via pipeline into the prior written notice by the state of export to the competent EEZ or continental shelf. With regards to the high seas, authorities of the state of import and transit, consent, CO2 disposal is a freedom that may be exercised by all and tracking of waste movements. The Basel Convention states provided that they have due regard to the interests places outright bans on the export of hazardous wastes of other states and the requirements of international to certain countries. Cross-boundary movements are law (de Coninck and others 2006). Furthermore, in permissible if the state of export does not have the order to protect the marine environment from pollution, capability to manage or dispose of the hazardous waste UNCLOS requires states “not to transfer, directly or in an environmentally sound manner. A cross-boundary indirectly, damage or hazards from one area to another� movement of CO2 might trigger the application of the (UNCLOS 1982, Art. 195). At present, there is no Basel Convention, although this is not yet certain, since conclusive opinion as to whether CO2 is considered a CCS has not been considered in the context of this hazardous substance under UNCLOS. If CO2 is defined Convention. When it is considered, the key issue will be in this way, it may prevent states from transporting CO2 on the classification of CO2 and whether it should be from the capture site to an offshore storage site. considered a hazardous waste under the Convention. Convention on the Prevention of Marine Pollution A summary of the legal obligations of the reviewed by Dumping of Wastes and Other Matter 1972 countries under the above international treaties is (London Convention) provided in Table C.1 in Appendix C. The London Convention was one of the first international Review of Regional and National Legal conventions to protect the marine environment from Regimes Applicable to CCS Activities in the human activities and has been in force since 1975. Southern African Region In 2006, the Contracting Parties to the 1996 Protocol of the London Convention adopted amendments that This section is based on the 2011 World Bank report allow and regulate the storage of CO2 streams from examining the relevant legal frameworks applicable 13 See, for example, UNCLOS 1982, Article 21, describing the rights of coastal states to adopt certain types of laws and regulations. to CCS in the Southern African region (World Bank purposes of CCS. The analyses of relevant legislation in 2011c). the three countries suggest that CO2 could potentially be classified in the existing laws as a noxious or Regional Framework offensive gas, certain types of “waste,� or a dangerous good for the purposes of transport. Botswana, Mozambique, and South Africa are members of the Southern African Power Pool (SAPP)14 and the In Botswana, for example, under the Atmospheric Southern African Development Community (SADC).15 Pollution (Prevention) Act (APA) (APA, Chapter 65:03), Mozambique and South Africa also participate in the CO2 is not expressly included under the list of “noxious Regional Electricity Regulators Association of Southern or offensive gases.�16 However, such gases include Africa, which was established by SADC as a formal “any other gas, fumes or particular matter prescribed as association of electricity regulators in July 2002 in noxious or offensive gas for the purposes of the Act.� terms of the SADC Protocol on Energy (1996), the The list of gases included as “noxious or offensive� SADC Energy Cooperation Policy and Strategy (1996), under the Act are mostly produced as a by-product of the SADC Energy Sector Action Plan (1997), and the industrial processes. Therefore, it is possible that CO2 SADC Energy Activity Plan (2000) in pursuit of the in the context of CCS purposes may be prescribed broader initiative of the New Partnership for Africa’s as a “noxious or offensive� gas. Under the Waste 28 Development and the African Energy Commission Management Act (WMA), CO2 may be characterized (AFREC). The Regional Electricity Regulators Association as a “waste,� which is defined as “undesirable or of Southern Africa aims to facilitate the harmonization superfluous by-products, any residue or remainder of of regulatory policies, legislation, standards, and any process or activity or any gaseous, liquid or solid practices, and serves as a platform for effective matter� (see WMA). cooperation among energy regulators within the SADC region. In Mozambique, the Regulation on Waste Management (RWM), the primary law governing National Frameworks wastes, defines “Hazardous Waste� (HW) as containing risk characteristics because of its While none of the three countries has conducted a flammable, explosive, corrosive, toxic, infectious or comprehensive review of existing regulatory frameworks radioactive nature, or because of the presence of any for relevance to CCS, these countries all have relevant other characteristic that poses danger to life or health legislation that may be applicable to some aspects of of humans and other living beings and to the quality CCS activities. This section of the report highlights the of the environment (RWM 2006).17 Characteristics most relevant legal instruments that may be potentially of HWs are duly identified in Annex III to the RWM, applicable to CCS activities. which include “substances consisting of compressed gases, liquefied or under pressure.� These substances The Classification of CO2 and Its Legal Definition, are gases that are hazardous by virtue of being Including the Proprietary Rights of Stored CO2 compressed or liquefied, dissolved under pressure, or refrigerated (ELI, Annex III, Item 2.H2). Based on (a) Legal Definition of CO2 the definition of HWs cited above, and because CO2 is known to affect the quality of the environment; and There is no CCS-specific legislation in Botswana, (b) the fact that CCS involves carbon compression Mozambique, or South Africa that defines “CO2� for the and liquefaction, which could make it potentially 14 SAPP has not developed any specific guidelines or agreements related to CCS. However, the SAPP has developed documentation for a number of environmental issues, which may be relevant for CCS, such as Environmental and Social Impact Assessment Guidelines For Transmission infrastructure for the SAPP Region, Guidelines for Environmental Impact Assessment (EIA) for Thermal Power Plants, SAPP Guidelines on the Management of Oil Spills, and Guidelines for Environmental and Social Impact Assessments for Hydro Projects in SAPP Region. 15 SADC has no protocol or agreement dealing specifically with CCS, although some of its protocols could potentially be relevant, to some extent, for CCS activities. These include, for example, Protocol on Shared Watercourse Systems in the SADC, 1997, Protocol on Mining in the SADC, 1999, Protocol on Energy in the SADC region, 1999, and Revised Protocol on Shared Watercourses in the SADC, 2002. 16 The “noxious or offensive gases� are defined as “any of the following groups of compounds when in the form of gas, namely hydrocarbons;…and any other gas, fumes or particular matter prescribed as noxious or offensive gas for the purposes of the Act; and includes dust from asbestos treatment or mining� (emphasis added). 17 Further, the Environmental Law defines “hazardous waste� as substances or objects that are disposed or are intended to be disposed, or are required, by law, to be disposed and which contain risk features given it flammable, explosive, corrosive, toxic, infectious or radioactive nature, or present any other feature that endangers mankind’s or other living beings’ life or health, or environmental quality (ELI). dangerous, CO2 may be treated as a hazardous waste Jurisdiction over the Control and Management under the RWM. of Domestic and Cross-Boundary Pipelines and Reservoirs, Including Monitoring, Reporting, and In South Africa, in the absence of a carbon market, Verification Requirements CO2 may fall under the definition of a “waste.� The National Environmental Management: Waste In Botswana, the Water Act may be relevant to the Management Act 59 of 2008 (NEM: WA) defines cross-boundary CCS pipelines. Under this Act, the “waste� as “any substance� “that is surplus, unwanted, Water Apportionment Board has the power to create rejected, discarded, abandoned or disposed of;� servitudes to build pipelines to transport water from “which the generator has no further use of for the the dams. The Board may negotiate compensation purposes of production;� and “that must be treated with those where land is acquired compulsorily to or disposed of.� Furthermore, the South African build pipelines. The same occurs in tribal areas, National Standards (SANS) 10228 (2006) deals with but through the Water Authorities, which are local the identification and classification of dangerous authorities. Similar arrangement may be adopted for substances and goods for transport, and it classifies CCS pipelines. CO2 as a “Class 2 dangerous good� (Division 2.2 of Class 2), which is a gas that is nonflammable and In Mozambique, Decree N. 24/2004 (Petroleum nontoxic, as well as also either an asphyxiant or an Operations Regulations) may be relevant for CCS 29 oxidizing gas. operation. The Decree includes provisions on oil and gas pipeline systems and establishes rules, among Proprietary Rights over Stored CO2 others, on pipeline operator approval, insurance, design and construction, risk analysis, environmental The concept of propriety rights or “ownership� of protection, site and route selection, and safety stored CO2 (CO2 that has been injected into the (Petroleum Operations Regulations 2004). Similar subsurface for the purposes of long-term sequestration) provisions may be adopted for CCS pipelines. The has not been specifically provided for in the legislation RWM may also be relevant, if as discussed above, in any of the three countries. However, relevant CO2 is considered a “waste� or “hazardous waste� in legislation includes the regime applicable to the Mozambique. The legislation currently focuses on the subsurface rights in the minerals and petroleum transportation of waste by mobile equipment (that is, context. For example, in South Africa, the Mineral and vehicles) only, and not by pipelines. Petroleum Resources Development Act 28 of 2002 (MPRDA) regulates rights with regards to minerals In South Africa, the relevant legislation is the law and petroleum and the mining and production applicable to the transportation of specific types (winning) thereof from the Earth. However, in its current of substances and “wastes� in pipelines if CO2 formulation, these mining laws are unlikely to be is classified as a waste. These include the Gas applicable to CO2 captured from power generation Act 48 of 2001 and the National Environmental or other processes for the purposes of long-term Management Act. Typically, some form of approval or storage, among other things, for the reasons that authorization is required prior to the construction of (a) such substance is not a “mineral� in terms of the such pipelines, and relevant administrative authority laws’ definition thereof;18 and (b) the injection of such would impose monitoring and reporting requirements substance into the subsurface does not constitute the and mechanisms to facilitate verification of legal “winning of a mineral.�19 Similar provisions are also compliance. Furthermore, the National Environmental in mining laws of Botswana (Mines and Minerals Act) Management: Integrated Coastal Management Act and Mozambique (Mines and Minerals Act 2002; (NEM: ICMA 2008) extends the general duty of care Regulation on the Mining Law 2002), and are not to “the operator of a pipeline that ends in the coastal likely to be applicable in their current form, for the zone�. same reasons. 18 The definition of “minerals� in the MPRDA is: “any substance, whether in solid, liquid or gaseous form, occurring naturally in or on the earth or in or under water and which was formed by or subjected to a geological process, and includes sand, stone, rock, gravel, clay, soil and any mineral occurring in residue stockpiles or in residue deposits….� 19 This applies unless there is enhanced oil recovery or enhanced coalbed methane recovery. Proprietary Rights to Cross-Boundary CCS Sites and Regulatory and Licensing (Permitting) Schemes Facilities Related to the Operation and Management of Storage and Transportation Facilities In Botswana, for the acquisition of a CCS site, the relevant legislation, the State Land Act and Tribal Land This section divides the discussion by the types of Act, relates to land acquisition. Generally, if a project licensing and permitting requirements to protect the is deemed to be of benefit to Botswana, land can be environment that are most relevant for CCS. allocated to the project holders by the responsible minister. The land so allocated remains state land License Requirements Related to Waste and and the user shall be granted a lease for a defined Hazardous Waste Management period (a period of either 50 years or 99 years). Such allocation often requires a prior fulfillment of In Botswana, under WMA, trans-boundary movement environmental impact assessment (EIA) requirements for of waste refers to the import and export of waste into necessary licenses. or from Botswana or the transit of waste in Botswana. If CO2 is classified as a “waste� under this Act, a In Mozambique, the Civil Code provides that in the waste carrier license may be required for any such case of construction of immovable goods (hereinafter movements of “waste� (CO2) in Botswana or for 30 “works�),20 the property right belongs to the owner trans-boundary movements thereof. In Mozambique, of the works provided that it holds land use rights. under the RWM, CO2 is likely be characterized as an The property rights over immovable goods covers HW (RWM 2006). The RWM provides that the entities the airspace corresponding to the surface, as well engaged in the disposal, recovery, or recycling of as the subsurface, including the content in the said waste must prove, by risk assessment conducted during immovable goods, except if otherwise provided by the development of waste management plan, the law (Civil Code 1967). Therefore, it appears that the environmental feasibility of the operation of treatment, property rights over CO2 storage sites and facilities disposal, or recovery, as the case may be. The facilities would belong to the owner of works. Because the referred to above are subject to environmental property right would also cover the content in the licensing under the Decree N. 45/2004 (see REIAP). storage sites or facilities, the property right over In South Africa, under NEM: WA, it is likely that CO2 CO2 itself would likely belong to the owner of such will be classified as “waste.� The Act provides that the infrastructures, unless otherwise is stipulated by law or holder21 of waste must, within all reasonable measures, contract. avoid the generation of waste and, where it cannot be avoided, minimize the toxicity and amount of waste In South Africa, property rights to potential CCS sites generated. The person transporting the waste must and facilities are not clearly defined. However, under also take all reasonable measures to ensure that no NEM: ICMA (2008), if a CCS project is located in a spillage or littering of waste occurs while transporting coastal area, it can be stipulated that the site is held in such waste.22 trust by the state on behalf of the citizens. Furthermore, under the common law principle of cuius est solum, Licensing Requirements Related to Water Pollution that is, whoever owns the soil, “it is their[s] up to the heavens and down to hell,� it appears that the owner of In Botswana, the Water Act provides that “no person the soil should also own the subsoil and the elements shall divert, dam, store, abstract, use, or discharge comprising the subsoil. This principle has been applied any effluent into public water or for any such purpose by the South African courts to grant subsurface right construct any works, except in accordance with a to the land owner (London and SA Exploration Co v water right granted under this Act� (Water Act, Laws of Rouliot 1891). Botswana, Article 9). Such a right may be granted by the Water Apportionment Board, which would specify 20 Pipelines would be classified as immovable goods. 21 In terms of section 1 of NEM: WA. a “holder of waste� means any person who imports, generates, stores, accumulates, transports, processes, treats, or exports waste or disposes of waste. 22 In July 2009, the Minister published a list of waste management activities (GN 718), under which any person who wishes to commence, undertake or conduct a waste management activity must apply for and be issued with an appropriate waste management license. the quantity, period, and the purpose for which such ecosystems, damage material goods, and threaten a water right is granted (Water Act, Laws of Botswana, or impair the recreational value or other legitimate Articles 9 and 15). Any holder of a water right who uses of environmental elements� (REQSEE, Article contravenes or who fails to comply with any condition 1, para. 17). Annex II of the REQSEE establishes implied in a water right shall be liable to the penalties the standards to be observed by industrial facilities, prescribed in the Act (Water Act, Laws of Botswana, including thermal power plants, with regard to emission Articles 9 and 17). of air pollutants (REQSEE, Article 8). A similar license would be required for emission of air pollutants. In In Mozambique, Regulations on Environmental South Africa, the relevant legislation is the National Quality Standards and Effluent Emissions (REQSEE) Environmental Management: Air Quality Act 39 of require emission or discharge sites to be approved 2004 (NEM: AQA). NEM: AQA provides that the for environmental licensing. Annex III of the REQSEE minister must publish a “list of activities� that result in establishes the parameters and limits for discharge of atmospheric emissions and that may have a significant liquid effluents by industries, including thermal power detrimental effect on the environment, including health, plants, although they do not refer to CO2. Furthermore, social conditions, economic conditions, ecological Law N. 16/91 (The Water Law, or WL) requires conditions, or cultural heritage. Subject to the all activities that are likely to cause contamination transitional provisions contained in Section 61 of the and degradation of the public water domain, in Act, a provisional atmospheric emission license (AEL) is 31 particular the discharge of wastewater, other wastes or required to undertake the published “listed activities,� substances into the water, to be licensed by regional some of which may be relevant for CO2-generating water administrations. Such activities shall be subject activities (“List of Activities Which Have or May Have to standards on effluent quality (Water act, Laws of a Significant Detrimental Effect on the Environment, Botswana, Articles 9 and 54). Including Health, Social Conditions, Economic Conditions, Ecological Conditions or Cultural In South Africa, the National Water Act 36 of 1998 Heritage�, 2010). (NWA) states that the national Government is the “public trustee� of all of the nation’s water resources Long-Term Management and Liability Issues Arising and therefore has the power to regulate the use, from Incidents or Leaks in Domestic and Cross- flow, and control of all water resources. Accordingly, Boundary CCS Projects authorization is required for water uses (NWA 1998). If it is determined that a license is required for a use, In Botswana, the Environmental Impact Assessment a person must apply for a license, and may also be Act (EIA Act) provides that the person responsible for required to undertake an environmental or other the negative environmental impact shall rehabilitate assessment, which may be subject to independent the affected environment to its normal function. review. Furthermore, under the Mines and Minerals Act (MMA), the holder of a license is obliged to conduct the Licensing Requirements Related to Air Pollution operations in accordance with good mining industry practice and to preserve the natural environment, In Botswana, APA prohibits a person from carrying minimize and control waste, prevent loss of biological out an industrial process23 on any premises that resources, and treat pollution or contamination of the may involve the emission into the atmosphere of an environment (see MMA). An EIA is required as part “objectionable matter� without a registration certificate. of the Project Feasibility Study Report, and a holder If CO2 falls in the definition of an “objectionable of a license shall rehabilitate or reclaim the mining matter,� as discussed above, such a registration area from time to time. Where government carries out certificate may be required. In Mozambique, the restoration on behalf of the holder, he or she shall REQSEE defines air pollutants as “substances or reimburse the government for any costs incurred. energy that exert harmful action likely to endanger Noncompliance with the provisions of MMA is a human health, cause harm to living resources and criminal offense with penalties. 23 Industrial process is defined as “a process prescribed by the Minister which is involved in trade, occupation or manufacture devoted to production by physical, mechanical, electrical, chemical or thermal means, including…operations to generate power and ancillary operations.� In Mozambique, Environmental Law requires persons Third-Party Access Rights to Transportation conducting certain activities to meet their liability Networks, Transit Rights, and Land Rights for obligations, which must be covered by appropriate Pipeline Routes insurance policies against any damages caused. These obligations include the duty to indemnify the In Mozambique, with regard to third-party access injured parties, regardless of fault, for damages to to pipelines, Law No. 03/2001 (Petroleum Law) the environment or for causing temporary or definitive provides for the conclusion of contracts for purposes interruption of economic activities. It also provides for of establishing and operating oil or gas pipelines proactive action by the state, if so required, by means (Petroleum Law, Article 17, clause (b)). It also provides of adoption of necessary measures to prevent, mitigate, for access to such pipelines by third parties by requiring or eliminate any serious damage to the environment the holders of pipeline rights to transport, without (ELI, Article 20). However, there is no provision for discrimination and in commercially acceptable terms, transnational liability, which raises uncertainty as to oil belonging to third parties, provided that the pipeline who is liable in the event of damage resulting from the system has sufficient capacity and that there are no trans-boundary movement of hazardous wastes and unsolvable technical problems that may hinder the other wastes and their disposal, including illegal traffic satisfaction of third parties’ demands (Petroleum Law, in those wastes. Article 18, para. 1). In case the capacity of the pipeline 32 system is not sufficient, the respective holder of rights is In South Africa, the National Environmental required to increase the capacity, provided that it does Management Act (NEMA) imposes a duty of care on not cause an adverse effect on the technical integrity or every person who causes, has caused, or may cause safe operation of the system, and that the third parties significant pollution or environmental degradation to have secured funds to meet the costs of the increased take reasonable measures to prevent such pollution capacity (Petroleum Law, Article 18, para. 2). from occurring, continuing, or recurring. The Act also requires that, insofar as harm to the environment is In South Africa, although the Gas Act and regulations authorized by law or cannot reasonably be avoided thereunder are not applicable to CO2 transported by or stopped, measures should be taken to minimize pipeline, this Act and regulations make provision for and rectify such pollution or degradation of the third-party access to hydrocarbon pipelines, and these environment.24 This broad form of potential liability provisions may serve as an indicator of the future may be applicable to South African CCS projects. With architecture for regulating pipelines in the CCS context respect to “waste� under NEM: WA, it is important in South Africa.26 Concerning transmission pipelines and to recognize that the contaminated land provisions storage facilities, the Regulations state that the allocation under the Act have retrospective effect,25 and that mechanism to ensure third-party access to uncommitted they apply to contamination that originated on land capacity27 must comply with the following principles: other than the land that becomes contaminated, and (a) use it or lose it, taking into account diurnal and to contamination that arises or is likely to arise at a seasonal load profiles; (b) nondiscrimination; (c) defined different time from the actual activity that caused the time periods; and (d) technical feasibility. contamination, or arises through an act or activity of a person that results in a change to pre-existing In Botswana, while there are no specific laws identified contamination. The landowner must take necessary that regulate third-party access rights, it is likely that a steps set out in order to remediate the contaminated contract law, similar to that in Mozambique and South land. These contaminated land provisions may apply Africa, would generally govern such third-party access to CO2 leaks. rights. 24 The persons on whom the NEMA imposes an obligation to take “reasonable measures� include an owner of land or premises, a person in control of land or premises, or a person who has the right to use the land or premises on which or in which any activity or process is or was performed or undertaken or any other situation exists, which causes, has caused or is likely to cause significant pollution or degradation of the environment. 25 NEM: WA section 35 provides that Part 5 of NEM: WA applies to the contamination of land even if the contamination occurred before the commencement of the Act. 26 According to the Gas Act, a licensee may “lay and construct pipes for the distribution of gas under or over any such street, and may from time to time repair, alter or remove any pipes so laid or constructed within its licensed area of supply.� Moreover, the Piped Gas Regulations (GN 321 of 20 April 2007) make provision for third party access to transmission pipelines and to storage facilities. 27 “Uncommitted capacity� means such capacity determined by the gas regulator in a transmission, storage, or distribution facility, since is not required to meet contractual obligations. Regulatory Compliance and Enforcement Scheme provisions are included in NEM: ICMA (2008, Section 59), NEM: AQA (2004), NWA (1998, Section 53), and In Botswana, an authorized officer is provided with NEM: WA (NEM: WA, Sections 67 and 68). inspection powers to ascertain compliance of holders with requirements of various licenses, including under Environmental Impact (Including Cumulative Impact) MMA, APA, and the Public Health Act. Furthermore, Assessment Processes, Risk Assessment, and Public the EIA Act provides for inspectors to have access to Consultation a site in order to evaluate compliance with the Act and the residual environmental impact of the existing In Botswana, the EIA Act applies to activities activity, the effectiveness of mitigation measures, “likely� to cause significant adverse effects on the and functioning of monitoring mechanisms. The Act environment. Before a license is issued for an activity also provides for powers of entry to the site. Under prescribed under the EIA Act, the licensing authority the EIA Act, a competent authority may revoke or shall ensure that an “authorization� is granted. A modify authorization to implement an activity where preliminary EIA is required as a first step to obtaining there has been an unanticipated irreversible adverse such a license. Public participation is required by environmental impact or a developer fails to comply way of publication through media and meetings with with any term or conditions subject to which the affected communities. Information provided by the developer’s authorization was issued. Similarly, WMA applicant may be subject to public review. Public 33 permits the state to order the immediate closure of any comments must be taken into consideration in the existing waste management facility on the grounds of decision making. risk of pollution to the environment and harm to animal or plant life. In Mozambique, a similar EIA law is in place. EIA requires an environmental license for any activity that In Mozambique, institutions including the may cause significant environmental impact. As a part Ministry for Coordination for Environmental Action of an environmental assessment, an activity proponent (MICOA) are generally responsible for the regular must conduct public consultations with all stakeholders inspection and oversight of monitoring actions and directly or indirectly affected by the activity in question. environmental management of the activity subject Upon successful completion of environmental to an environmental license. These institutions are assessments and approval thereof by MICOA, it grants vested with punitive powers in case of breach of the the concerned person or entity an environmental license regulations, under which fines can be imposed on for the activity it intends to carry out. , offenders (REIAP Articles 24 and 26). For instance, MICOA is responsible for enforcing REQSEE, and it In South Africa, NEMA is the primary statute is vested with powers to conduct tests, audits, and regulating the “listed activities,� which are the activities technical-scientific assessments in order to determine that require environmental authorization prior to the quality of the environment and compliance with their being undertaken (CO2 sequestration is not a the law. “listed activity�). Section 24 of NEMA requires that an applicant for an environmental authorization consider, In South Africa, NEMA provides for the appointment investigate, assess, and report the consequences for of the Environmental Management Inspectors (EMIs) or impacts on the environment of the listed activity to and their powers, including powers relating to the the relevant competent authority. One requirement that seizure of items, routine inspections, the power to is particularly important is the requirement of public issue compliance notices, and the forfeiture of items. participation. EMIs may issue compliance notices where there is reason to believe that a person has failed to comply Review of Regional and National Legal with a provision of the law the inspector is responsible Regimes Applicable to CCS Activities in the for upholding, or has failed to comply with a term Balkan Region or condition of a permit, authorization, or instruction issued (NEMA, Section 31L). A person who fails to This section is based on the 2011 World Bank report comply with a compliance notice commits an offense examining the relevant legal frameworks applicable to and may be liable for a fine or imprisonment. Similar CCS in the Balkan region (World Bank 2011b). Regional Framework—European Union CCS Classification of CO2 and Its Legal Definition, Directive Including Proprietary Rights of Stored CO2 In April 2009, the European Union adopted Directive Legal Definition of CO2 2009/31/EC on the geological storage of CO2 with the aim of establishing a legal framework for In Bosnia and Herzegovina, CO2 has not been the environmentally safe geological storage of CO2 defined or regulated by legislation. Traditionally, CO2 (Directive 2009/31/EC 2009). The objective of this has not been considered a pollutant, nor is it listed Directive is to provide conditions for permanent among the pollutants in any of the legislation in Bosnia containment of CO2 to prevent and, where this is not and Herzegovina. possible, eliminate the negative effects and any risk to the environment and human health. It covers all CO2 In Serbia, there is no legal definition of CO2 in storage in geological formations within the EU common national environmental legislation, though several space, and lays down requirements covering the entire existing laws may offer some guidance. For example, lifetime of a storage site. Existing legal frameworks in CO2 may fit into the definition of a pollutant, or waste, member countries are used to regulate the capture or a dangerous substance, under various sections of the and transport components of CCS. It requires Member Law on Environmental Protection (Official Journal of the 34 States to regulate this new area by, for example, the Republic of Serbia, No. 135/04, 36/09, 36/09-other issuance of exploration permits, storage permits, and by law, and 72/09-other law, Article 3). Under the Law on ensuring that monitoring and inspections are carried out Air Quality, CO2 is classified as a GHG. The Law on and that the storage site operator sets aside a financial Waste Management may define CO2 as a type of waste guarantee. The CCS Directive also amends other or hazardous waste, although the current list of waste legal instruments in order to remove legal barriers to categories does not include CO2. the deployment of CCS technology (as summarized in Table C.2 in Appendix C). In Kosovo, no legal definition of CO2 can be found in presently applicable legislation. For instance, the In addition to Directive 2009/31/EC, on March Law on Air Protection from Pollution (APP) does not 31, 2011 the European Commission published four include CO2 in the list of basic environmental indicators guidance documents aimed at assisting stakeholders of air quality that indicate the concentration of solid, with implementation of the Directive so as to liquid, and gaseous substances in the air. Nor does promote a coherent implementation of the CCS APP provide any definition or classification of CO2. Directive throughout the European Union (European From all pertinent laws, it appears that CO2 in Kosovo Commission, Climate Action 2011b). EU member would be more likely defined as a pollutant because states are obliged to transpose Directive 2009/31/EC (a) CO2 does not appear on the list of substances by June 25, 2011. It is worth noting that the guidance belonging to the category of waste in the Waste Law; documents are not binding on states (unlike the and (b) in Annex II of the Law on Environmental Impact Directive itself), but in practice will be highly persuasive Assessment, “installations for the capture of CO2 for EU Member States. Bosnia and Herzegovina, streams for the purposes of geological storage� are Kosovo, and Serbia are not yet members of the listed under the “Energy Industry� section rather than European Union, but as candidate countries, each under “Waste,� which is another section of the annex. committed to EU membership, they will, at some point in the future, need to take steps to harmonize with Proprietary Rights over Stored CO2 Directive 2009/31/EC. At this stage, none of the three countries has transposed Directive 2009/31/EC into In Bosnia and Herzegovina, there is currently no national law. legislation setting out the proprietary rights of stored CO2. The existing legal frameworks of the energy sector, National Frameworks geological exploration and mining, and environmental protection may be a basis for introduction of a legal This section highlights the most relevant national legal regime of CCS in the country. The legislation on instruments that may be potentially applicable to CCS production, transportation, distribution, and storage activities in the Balkan region. of gas is perhaps the most likely to correspond to the requirements of CCS. The legislation on geological had the right to use), operated, or otherwise possessed exploration and mining is also pertinent, since the focus energy facilities sited on property, over which the energy of Directive 2009/31/EC is geological storage of CO2. enterprise had not formally acquired or been granted The legislation of Serbia provides that all activities in a servitude, right of use, or property ownership right, the gas sector, including storage of the gas, are public were granted all necessary servitudes, rights of use, interest activities. A consequence of an activity being and/or other property rights in or to the concerned “public interest� is that ownership of the installation property by the operation of the Law on Energy.28 The and facilities is considered “public� property or, more second aspect concerns the new developments, such precisely, under the ownership of Serbia. A similar as the construction of new, or expansion of existing, situation exists in Bosnia and Herzegovina with the generation, transmission, or distribution facilities that Decree on Organization and Regulation of the Gas require the acquisition of servitudes, rights of use, or Sector (Law of Environmental Protection of Federation of other property rights. This aspect would be most likely Bosnia and Herzegovina, Official Gazette of Federation to apply to proprietary rights over stored CO2. If the of Bosnia and Herzegovina, 40/02). Based on the property concerned is privately owned, the law provides provisions of the above-mentioned legislation, the that the concerned energy enterprise shall give notice Political Entities would be the owners of facilities within to the private land owner and agree with the owner the gas sector on their territories. on servitude, based on the fair market value of the land. Any servitude or other property rights agreed by 35 In Serbia, with respect to the proprietary rights over the parties have to be registered with the competent stored CO2, the provisions of the Act on Bases of Municipal Cadastral Office (Law on Energy, Article Property Relations, Act on Conveyance of Immovable 25(1)). The Energy Regulatory Office can also determine Title, the Contracts and Torts Act, and the Concession that the new or expanded facilities are needed to meet Act could apply. The main question that arises in the concerned energy enterprise’s license obligations, regard to CO2 is whether it could represent a “thing and such determination is deemed to meet the (matter)� that can be possessed, used, and disposed requirements of the Law on Expropriation of Immovable of, and which can be subject of property rights. Property. The Energy Regulatory Office forwards that Although there are no specific legal provisions to this determination to the Government with its request for effect, it is accepted in case law in Serbia that any initiation of the proceedings for expropriation of the “substance� (gas and natural sources of energy, such as private land and the transfer of that land to the energy wind, electricity, and heat) that is subjected to human enterprise to determine the compensation in accordance intervention (such as capturing a gas) represents a with the relevant provisions of the Law on Expropriation matter, over which a person may have property rights. of Immovable Property (Law on Energy, Article 15(4)). The same analogy could be applied to captured and stored CO2. As regards the ownership of stored CO2, Jurisdiction over the Control and Management the rule superficies solo cedit in principle applies—an of Domestic and Cross-Boundary Pipelines and improvement that stands on the surface of the ground, Reservoirs, Including Monitoring, Reporting, and such as a structure, trees, or plants, and anything Verification Requirements underground belongs to the owner of the land. If it concerns state land, the conveyance of title to natural In Bosnia and Herzegovina, the national legislation or legal persons is possible, but it may only be done by does not yet explicitly regulate transportation of CO2 public sale or by public procurement. in pipelines, whether domestic or cross-boundary, but interpreting provisions of the Serbian Law on Gas and In Kosovo, since CCS is essentially not regulated by the the Federation of Bosnia and Herzegovina Decree on existing legal framework, it is difficult to unequivocally the gas sector, there is a legal basis for transportation of set out the proprietary rights of stored CO2. However, gases that are technically acceptable for transportation one could apply the proprietary rights of the Law on by gas pipelines. In the case of CCS development, Energy, which provides for two principal mechanisms. transportation of CO2 may be regulated on bilateral First, those energy enterprises that owned, used (or basis, following legal principles of mutual interest, 28 The Law was published in the Official Gazette on November 15, 2010, and as prescribed in the Law, it entered into force 15 days after its publication in the Official Gazette. The effective date of this particular law was also confirmed with the Office of the Official Gazette. cooperation, and the need to ensure that no harm and inter-ministerial agreements, between Regulatory is caused to other countries. The above-mentioned Commissions. On the operational level, cooperation is acts (a) set out the procedure by which an operator organized among operators. Inter-entity flows of CO2 can extend a network of pipelines and measures for are also likely to be regulated on the basis of such implementation of the legislation, including inspection cooperation. and enforcement; and (b) specify conditions that the operator must meet to obtain a permit for performing In Serbia, the Agreement on Succession Issues signed activities in gas sector. It is therefore considered that in 2001 regulates the division of existing movable and the gas legislation in Bosnia and Herzegovina provides immovable property, which also includes cross-border a solid structure, which could be followed for the sites and facilities. The use of cross-border sites is an introduction of CO2 pipelines in the country. issue to be regulated by separate agreements. Movable and immovable state property of the federation shall In Serbia, the transportation of CO2 is not regulated by pass to the successor states in accordance with the any specific law. However, the provisions of the Act on provisions of the Agreement. Immovable and movable Pipeline Transport of Gaseous and Liquid Hydrocarbon tangible state property, which was located within the and Distribution of Gaseous Hydrocarbons could apply. territory of the Socialist Federal Republic of Yugoslavia The act regulates different types of pipelines, namely oil, (former Yugoslavia) shall pass to the successor state on 36 gas, and product pipelines and also pipeline transport whose territory that property is situated on the date on conditions. The act distinguishes interstate systems for which it proclaimed independence. A Joint Committee oil and natural gas transport or their products when it on Succession to Movable and Immovable Property concerns the cross-boundary movement between other shall be established by the successor states, which shall states or transit through Serbia. ensure the proper implementation of the provisions of the Agreement. However, in relation to cross-border facilities In Kosovo, the law does not currently regulate the or sites that do not currently exist, but may be built in the transportation of CO2, although it addresses aspects future, these shall be regulated by a separate agreement. that relate to the transportation of CO2 for purposes of conducting an environmental impact assessment, Kosovo is not a party to any succession agreement required for granting an environmental consent by of the former Yugoslavia. It seems unlikely that there the Ministry of Environment and Spatial Planning would be any scope for agreement between Kosovo to relevant public or private projects. National law, and its neighboring countries on a cross-boundary CO2 however, regulates the transportation of gas, oil, and capture and storage site and facilities. energy through the respective Laws on Natural Gas, Energy, and Trade of Petroleum and Petroleum Products. Regulatory and Licensing (Permitting) Scheme No other general environmental law appears to be Related to the Operation and Management of applicable to CO2 transportation. Storage and Transportation Facilities Proprietary Rights to Cross-Boundary CO2 Capture In Bosnia and Herzegovina, there is no specific and Storage Sites and Facilities licensing system in place yet for CCS projects. However, the existing permitting system from the gas sector might Currently, there are no CCS sites and facilities in be applicable. For example, Article 6 of the Federation Bosnia and Herzegovina. The Political Entities’ laws of Bosnia and Herzegovina Decree on the Organization only regulate the gas sectors within their own territories. and Regulation of Gas Economy stipulates conditions Thus, the laws of Bosnia and Herzegovina cannot create that the system operator has to meet. The Serbian Law rights and obligations for persons and legal subjects on Gas regulates action in case that operator does in Serbia, and similarly, the laws of Serbia cannot not fulfill the conditions of its permit. The Regulatory create rights and obligations for persons in Bosnia and Commission may revoke the permit on a temporary Herzegovina. Gas sector installations in Bosnia and basis and can set the operator a deadline by which Herzegovina are public property and owned by these time he must have achieved full compliance with entities. Installations within the territory of Serbia are the requirements. The Serbian Law on Gas gives the owned by state. Inter-entity flow of gas is regulated on Inspector the option to initiate a procedure to revoke the bilateral cooperation, and through inter-government permit where he finds noncompliance with the permit. In Serbia, the lack of more precise information on defined as those that may cause significant risk for CCS projects leaves uncertainty as to the permits that people, health, property, and/or the environment. would be required. The existing licensing laws are An entity that performs dangerous activities bears divided into two categories: (a) permits according to responsibility for damages caused by that activity. the Mining Act, Geological Explorations Act and Energy Although CCS projects are not expressly included in the Act; and (b) permits issued under the Spatial Planning laws as dangerous activities, it is possible that plants and Construction Act, and environmental and other containing equipment to capture CO2, the pipelines legislation. This classification comes from the idea that used to transport concentrated CO2, and also the plant the use of CCS technology will include both permits used to inject CO2 could be considered locations that required for certain hazardous activities and their are dangerous to the environment. effects on the environment and human heath, as well as permits required for geological explorations, mining In Serbia, the responsibility for pollution to the date sites, and energy facilities. of privatization at state enterprises shall be borne by the state, not the new owner (NEPP 2010). According In Kosovo, no legal framework specifically directed at to the Law on Environmental Protection, any legal or CCS is currently in place, but the current energy and natural person that causes environmental pollution by natural gas legal framework may apply in the future illegal or improper activities shall be liable, including to CCS projects. The Energy Regulatory Office has the the cases when the polluter goes into liquidation 37 authority to issue, amend, suspend, transfer, or terminate or bankruptcy (Official Journal of the Republic of licenses to energy enterprises (Law on Energy Regulator, Serbia, No. 135/04, 36/2009, 72/2009). When the Article 14 (2.2)). The office also issues authorizations for ownership of a company changes an environmental the construction of new energy generation capacities, assessment, liability for environmental pollution must new facilities for the transmission and distribution of be determined, and settlement of debts of the previous gas, and direct electricity lines and direct pipelines for owner on account of pollution and/or environmental the transition of natural gas (Law on Energy Regulator, damage must be agreed. At the same time, any legal Article 14(2.7)). It follows from this analysis that, for and natural person who enabled or allowed pollution future CCS projects, the interested enterprises would of environment through illegal or incorrect action shall most likely have to apply for an operating license from also be responsible. If several polluters are responsible the Energy Regulatory Office or any other similarly for the environmental damage, and if it is not possible designated independent body. It remains to be seen to determine the share of certain polluters, the costs whether the Kosovo legislator also allocates any role to shall be borne jointly and individually. the Government, as in the Law on Natural Gas. In Kosovo, the Law on Environmental Protection Long-Term Management and Liability Issues Arising specifies a number of liability-related aspects, which from Accidents or Leaks in Domestic and Cross- could be applied to an accident or leak from a CCS Boundary CCS Projects project. The Law on Environmental Protection (Law on Environmental Protection, Article 81(1), (2) of Kosovo) Bosnia and Herzegovina signed the Protocol on Civil addresses liabilities of all natural and legal entities that Liability and Compensation for Damage Caused by are obliged to ensure environmental protection while the Transboundary Effects of Industrial Accidents on performing their activities. The Law on Environmental Transboundary Waters to the Water Convention during Protection also provides that the polluter—a legal or the Kiev Conference 2003, but has not ratified the natural person—is responsible for the damage caused Protocol. Also, the Political Entities have not introduced and for the evaluation and elimination of the damage any legislation on environmental liability and have resulting either from legal or illegal or inadequate not started to harmonize with Directive 2004/35/EC. action (Law on Environmental Protection, Articles In situations where damage is caused, the laws on 66(1) and 66(2)). It is important to note that the Law obligations and general rules on damages shall be on Environmental Protection has been approximated to applied, such as stipulated in Article 103 of Serbian Directive 2004/35/EC on environmental liability with Law on Environmental Protection and Article 103 regard to prevention and remedying of environmental of Federation of Bosnia and Herzegovina Law on damage to the extent that it complies with the basic Environmental Protection. Dangerous activities are principles of the Directive. The Law establishes a legal framework for environmental liability based on the (Official Journal of the Republic of Serbia 2004, no. “polluter pays� principle. The Waste Law (The Waste 72/09). Law of Kosovo (02/L-30)) also sets forth responsibilities and obligations for waste management. However, it In Kosovo, the EU Directive 2009/31/EC of April should be noted that these would only be applicable 2009 has not yet been approximated in the domestic in the CCS context if captured CO2 was considered legislation. Neither is it possible to observe the presence waste. of any provision that in any way reflects the content of the Directive’s relevant Article 18 on transfer of Financial Assurance for Long-Term Stewardship responsibility and Article 20 on financial contribution. and Reduction of Financial Exposure through CCS There is no other relevant legislation in Kosovo. Regulatory Frameworks Third Party Access Rights to Transportation Since CCS is not specifically regulated by legislation Networks, Transit Rights, and Land Rights with in Bosnia and Herzegovina, the discussion can Regard to Pipeline Routes only focus on some guarantee scenarios from existing legislation that potentially could be taken into account There is no CCS legislation at present in Bosnia when drafting legislation on financial assurance for and Herzegovina on third party access rights to 38 long-term stewardship of a CCS site. The existing laws transportation networks. The gas sector legislation vis- are practically the same in both Political Entities. Both à-vis third party access rights may be relevant. The Entities’ laws on environmental protection contain a Federation of Bosnia and Herzegovina Decree on provision that provides that the legal entity that carries Organization and Regulation of Gas Economy and out activities that are dangerous to the environment Serbian Law on Gas define obligations of operator. is responsible for the damage caused by that activity. With regard to the transportation network, the operator Both laws on environmental protection require that is responsible under both The Federation of Bosnia and the legal entity managing the dangerous activity Herzegovina Decree and the Serbian Law for providing provides sufficient financial security to cover any access and use of the transportation network to third damage that potentially might occur to third parties parties under transparent nondiscrimination rules with and compensation through insurance or by some other full protection of the user’s interest and provision of all means. However, it is unclear whether this general information needed for efficient access to transportation provision regarding liability also applies to closed network users. facilities. The Entities’ laws on waste management requires that sites holding hazardous waste provide a In Serbia, the Act on Pipeline Transport of Gaseous financial or other guarantee to compensate against and Liquid Hydrocarbon and Distribution of Gaseous the costs related to risks, or costs related to minimizing Hydrocarbons prescribes the conditions for safe and damage and against costs produced by activities after uninterrupted pipeline transport of gaseous hydrocarbon closure of such facility. The financial guarantee shall and liquid hydrocarbons and distribution of gaseous be proportional to the size of the site, quantity of waste hydrocarbons, industrial design, building, installation, disposed, and expected risks. The financial guarantee and use of pipelines and internal gaseous installation. has to be in place for maintenance of the facility after The Energy Act provides for third-party access, which closure for at least 30 years. may give an indication of the possible rules to be applied for CCS transport. The operator in the energy In Serbia, under the Environment Protection Act entity in charge of transmission, transportation or (Official Journal of the Republic of Serbia 2004), an distribution systems shall allow access of third parties Environmental Protection Fund has been established to the system based on the principles of transparency to provide financial resources for the improvement and nondiscrimination, in conformity with technical and protection of the environment in Serbia (Official possibilities and depending on the load level of the Journal of the Republic of Serbia 2004). According to transmission, transportation. or distribution systems. A the Amendment to the Environmental Protection Act system operator may refuse access to the system when (2009) and the Law on Environment Protection Fund, technical possibilities do not so allow because of a lack expanding the list of activities to be financed by the fund of capacities, faulty operation, or system overload, for is envisaged, which could potentially cover CCS projects example, as a result of threatened system functioning safety or the objection of an energy producer in Serbia by citizens, enterprises, and other organizations, in on a lack of reciprocity. matters concerning their business, and to inform them about the results of the inspection,29 and proceed with In Kosovo, in the absence of the CCS legislature, it is competent authorities in case a criminal act, commercial relevant to look at similar applicable legislation that offense, offense, or breach of working duty has been contains third-party access rights. For example, in the committed (Article 30). Inspections in the relevant Law on Natural Gas, the transmission and distribution fields are also regulated by sectoral laws, such as the system operators should allow natural gas undertakings Law on Environmental Protection, Law on Integrated and eligible customers, including supply undertakings, Pollution Prevention and Control (IPPC), Law on Strategic to have nondiscriminatory access to transmission and Environmental Impact Assessment (SEA), Law on EIA, distribution systems, in compliance with rules and Law on Waste Management, Law on Chemicals, Law transparent tariffs approved by the Energy Regulatory on Air Protection, Law on Mining, Energy Law, Law Office (Law on Natural Gas, Article 17(1)). on Geological Explorations, and Law on Pipeline Transportation of Gaseous and Liquid Hydrocarbons and Regulatory Compliance and Enforcement Schemes Distribution of Gaseous Hydrocarbons. In Bosnia and Herzegovina, both Political Entities Competence for law enforcement in the field of have adopted a Law on Inspections. The system environmental protection is divided between: 39 consists of an entity-level Directorate for Inspections republic inspections, provincial inspections, and local (Inspectorate) and inspections established at a local inspections. The Instruction on Environmental Inspection (cantonal or municipal) level. The Laws on Inspections Reporting (No. 353-03-2197/2006-01) entered into specify certain areas for inspection, including “Technical force in 2007 and attempted to unify inspection work inspection,� “Urbanism-construction and ecology on all levels in Serbia. inspection,� and “Sanitary inspection.� “Technical inspections� seem to be the most relevant in the context In Kosovo, an institutional scheme that could apply to of CCS projects. After performing an inspection, the future CCS activities is the one prescribed in the Law on Inspector will prepare a report on these findings. Environmental Protection. The Ministry of Environment and Spatial Planning could potentially be the authority Enforcement measures and actions with regard to responsible for implementing and enforcing laws environmental protection are set on several levels. The related to CCS, adopting any sublegal act and carrying Entities’ Laws on Offenses establish a system of offenses out administrative supervision (Law on Environmental and sanctions and authorized bodies that may impose Protection, Articles 50, 80, and 81(1)). Inspective activities sanctions. The criminal laws provide for crimes relating would, in this case, be carried out by the Environmental to “destruction of facilities of public use� and “crimes Protection Inspectorate (Law on Environmental Protection, against environment.� CCS installations can potentially Article 81(1)). Inspections in municipalities are carried be considered public interest facilities or facilities of out by municipality environmental inspectors (Law on public use, making the crime relating to “destruction Environmental Protection, Article 81(2)), who may also of facilities of public use� potentially applicable. be tasked with other duties by the Ministry of Environment Additionally, the legislation on environmental protection and Spatial Planning. and on air protection sets out several crimes and offenses related to air protection. Environmental Impact (Including Cumulative Impact) Assessment Process, Risk Assessment, and Public In Serbia, the responsibilities related to inspections and Consultation enforcement are determined by several legal acts. The Law on State Administration contains special provisions Environmental Impact Assessment related to inspection control performed by ministries through their inspectors and other authorized persons. In Bosnia and Herzegovina, with regard to The inspector is obliged to undertake inspection if asked transposition and implementation of Directive 29 The inspected parties are obliged to allow the inspector to perform his duties without any obstacle, to allow him to inspect documents and objects and to help him in other way if asked (Art. 29). 85/337/EC (the EIA Directive), both Bosnia and applicable both to the capture and transport of CO2 Herzegovina Political Entities have achieved good streams for the purposes of geological storage and results. The Serbian General Administration Procedure also to storage sites. on General Administration Procedure (Official Journal of the Republic of Serbia 13/02) sets basic Public Participation in Environmental Matters rules of administrative procedure. The Serbian Law of Environmental Protection (LEP) sets rules for two In Bosnia and Herzegovina, public participation administrative procedures: EIA and ecological permits. is one of the principles of environmental protection EIA is the procedure for obtaining an administrative under the law of both Political Entities that acceded decision on the acceptability of environmental impact to the Aarhus Convention in 2008, and that are in the process of project development. In a wider currently preparing their First National Reports on context, the decision on EIA is a precondition for implementation of the Aarhus Convention. The obtaining a construction permit. The EIA procedure legal basis for free access to information and public itself has two main parts. First, the screening process, involvement is also set by the Law on Free Access which results in a decision on whether or not EIA to Information (Official Gazette of the Federation of is mandatory and the extent of the EIA procedure. Bosnia and Herzegovina 32/01) and Law on Free Second, is the actual decision on EIA. The Serbian Access to Information (Official Journal of the Republic 40 LEP prescribes rules on procedure, involvement of of Serbia, no. 20/01). The existing legal instruments interested parties, and the public in the procedure. are clear in that (a) the publishing of information The Federation of Bosnia and Herzegovina LEP also is mandatory, (b) there must be public participation has detailed provisions on EIA. possibilities open to all interested parties and to the general public, and (c) the public and interested parties In Serbia, EIA has been carried out since the early are able to provide written comments and to participate 1990s. The basic legal act which currently regulates in public scrutiny. EIA in Serbia is the Law on Environmental Impact Assessment (Official Journal of the Republic of Serbia, Serbia is also a member of the Aarhus Convention No. 135/2004, 72/2009). The Law on EIA targets (Official Journal of the Republic of Serbia, no. planned and implemented projects, changes in 38/09), and public participation and while access technology, reconstruction, the extension of capacity, the to information is regulated at the national level. The termination of operations, and the removal of projects 2004 Law on Environmental Protection (EPL) contains that may have significant impact on the environment. a number of provisions of systemic character relevant In addition, the Law on SEA introduced strategic for access to environmental information and public assessment of effects on the environment into the legal participation (Articles 78–83). According to the system of Serbia (Official Journal of the Republic of relevant laws, the public should be informed at all Serbia, No. 135/2004, 88/2010). stages of the process and has the right to voice its opinion at each of these stages. The authorities must, Kosovo’s Law on Environmental Impact Assessment if requested to do so, at all stages, provide complete has undergone the screening of its compliance with documentation related to an EIA procedure. The 2004 Directive 85/337/EC and is made in line with its Law on Strategic Environmental Assessment provides content, making IEA explicitly address CCS, though that the public has the right to be informed about it still does not cover it in its entirety. For example, programs in preparation and their impact on the it does not provide any guidance with regard to environment. injection and storage, but rather speaks of this aspect in terms of a broader environmental dimension, of In Kosovo, an environmental consent is required by assessing all projects, public and private, that could the Law on Environmental Impact Assessment (Law significantly impact the environment to acquire the on Protection from Non-Ionized, Ionized Radiation required consent to operate from the competent and Nuclear Security of Kosovo (03/L-104) for every governmental body. Article 31 of Directive 2009/31/ public or private project, which is likely to have EC on the assessment of the effects of certain projects significant effects on the environment by virtue, among on the environment is also included in the Law on other things, of its nature, size, or location (Law Environmental Impact Assessment, meaning that it is of Environmental Impact Assessment, Article 7(1)). Environmental consents are issued by the Ministry made subject to public debate, and that the results of of Environment. The Law on Environmental Impact these consultations must be taken into consideration Assessment requires that the main conclusions and in reaching the decision on the environmental consent recommendations included in the EIA Report and (Law of Environmental Impact Assessment, Articles 20 the proposed decision for environmental consent are and 22). 41 5. THE ROLE OF CLIMATE FINANCE SOURCES The main findings of the study are summarized in IN ACCELERATING CARBON CAPTURE Box 5.1. AND STORAGE DEMONSTRATION AND Mapping Climate Finance to a Deployment DEPLOYMENT IN DEVELOPING COUNTRIES Pathway This chapter examines the range of policy, legal, Detailed national strategies, deployment scenarios, and regulatory, as well as methodological factors and roadmaps for CCS have not yet been widely that will define access to climate finance for CCS.30 compiled at either a national or regional level for Understanding the above-mentioned factors, associated developing countries. The most comprehensive, detailed, challenges, and possible options is essential in and consistent analysis of CCS demonstration and supporting efforts to maximize the use of climate finance deployment for both developed and developing countries by CCS at a time when the design of a future climate to date, was prepared under the IEA ETP Blue Map finance architecture is under negotiation. With a focus on Scenario (IEA 2010c) and described further in the IEA eligibility of CCS in climate finance, the analysis in this CCS Roadmap (IEA 2009). This is the scenario used chapter complements other studies that assess how policy as the basis for the analysis presented in this chapter. and financing instruments, along with their combination The IEA ETP Blue Map Scenario is a normative scenario and sequencing, can address the technical, financial and that charts a cost-effective pathway consistent with 43 economic near-term demonstration challenges for CCS.31 bringing down global emissions from the energy sector The analysis is presented in two sections: to 50 percent of their 2005 levels in 2050. This is arguably a collective effort much more ambitious than 1. An analysis mapping a deployment pathway for current mitigation pledges. However, with CCS being CCS in developing countries with associated essentially a high-cost abatement option, it is likely financing needs to climate finance instruments, that widespread CCS deployment globally, let alone in order to gain a better understanding of in developing countries, would only occur in line with their potential in supporting CCS. Two broad ambitious emission reduction targets. In addition, while categories of instruments are considered: market one must acknowledge today the large uncertainties or performance-based instruments and nonmarket, about the future structure and specific features of climate or so-called “public� instruments. The latter could finance instruments and channels, it is likely, however, be critical for addressing upfront investment needs that market-based climate finance instruments will, in the through grant and concessional loans or risk- longer term, play an important role as part of the mix of mitigation instruments, as well as providing other finance sources in providing cost-efficient solutions in a forms of support, such as enabling activities through highly ambitious GHG Emission Mitigation Scenario. dedicated funds. The market-based instruments, in turn, could provide additional revenues to cover The analysis presented in this chapter is carried out in part or in full, O&M costs. However, in general, by developing a set of metrics applied to the data on market-based instruments have limited capacity to CCS deployment in developing countries under the address challenges facing CCS technology build-out IEA ETP Blue Map Scenario. These metrics include at the demonstration stage. captured emissions, avoided emissions, number 2. A discussion of the policy, legal, and regulatory, of CCS projects required, additional investments, as well as methodological, issues that must be additional costs, and the cost of abatement. These satisfactorily resolved, at the international and metrics are explained in detail in Box D.1 in Appendix national level, for CCS to gain full access to D. Using the metrics, estimates of the potential climate finance. In general, these issues center contributions from different climate finance sources around ensuring the environmental integrity of to meet the costs of CCS deployment in developing avoided emissions achieved through CCS. countries are developed, according to the deployment 30 This chapter summarizes the main findings of a background report commissioned by the World Bank under a contract with a consortium comprised of Carbon Counts Company Ltd and Climate Focus. The report is titled Assessment of Climate Finance Sources to Accelerate Carbon Capture and Storage Deployment in Developing Countries (Zakkour and others 2011) 31 Such studies include the recent report by the IEA (IEA 2011b), looking into a panoply of instruments to incentivize the deployment of CCS in power generation and industry globally (including the appropriate form of incentives over time, as technology matures). Box 5.1: Summary of Findings and Conclusions Analysis of funding sources to achieve deployment trajectory of IEA Blue Map Scenario 1� CCS remains a technology at the demonstration stage, characterized by high capital-intensiveness, and requires further alignment with developing countries energy priorities and policies� These policies will have a significant impact on the role of CCS in national climate change strategies as compared to other technologies and options� The policies would also define the type of funding instruments that the host countries would be willing to use for supporting CCS in the context of limited availability of climate finance� CCS is essentially a high-cost abatement option, and therefore widespread CCS deployment in developing countries would only occur in line with ambitious GHG emission reduction targets� There is a great deal of uncertainty today about the future structure and specific features of climate finance instruments and channels� It is likely, however, that in a highly ambitious GHG Emission Mitigation Scenario, market-based climate finance instruments, as part of a mix of funding sources, will have to play an important role as a basis for cost-efficient solutions to attracting finance at the international level� 2� There are significant funding needs to deploy CCS in developing countries at the pace described by the IEA Blue Map Scenario� All in, based on the metrics developed in this analysis and the IEA data for the global deployment scenario, the total additional costs of CCS in developing countries could amount to US$15–20 billion between 2010 and 2020, and may total US$220 billion between 2010 and 2030� By 2020, this is equivalent to an estimated annual requirement of around US$4–5 billion per year, increasing tenfold to 44 almost US$40 billion per year in 2030� 3� CCS projects are highly heterogeneous, with considerable variations in marginal abatement costs, reflecting differences in energy requirements and unitary costs of technology, capital, and operating costs, and project scale factors� A range of support mechanisms, both market and nonmarket approaches working in tandem, may therefore be required to support different types of CCS projects throughout their lifetime� 4� In some cases, project-based mechanisms such as the CDM, in particular if blended with other sources and forms of public assistance, could work well to support lower-cost, early opportunities, such as natural gas processing (subject to the timely resolution of regulatory, policy, and methodology issues)� Further, mechanisms such as NAMAs could provide the framework for combining options for CCS support, bringing together domestic financing and policy support with international support from carbon markets� The Technology Mechanism and related institutions could also provide valuable R&D knowledge and facilitate capacity building assistance activities in order to support project implementation� Policy, legal, and regulatory factors affecting access to climate finance for CCS 5� As for CCS projects in developed, as well as developing, countries, a number of legal, regulatory, and policy issues remain to be addressed at international and national levels to ensure environmental integrity of the emission reductions achieved through CCS� These include, among others, the following: i� Managing permanence and liability� ii� Establishing good CCS project design and operational standards (including measurement, monitoring, MRV procedures)� iii� Establishing national regulatory regimes for CCS projects in developing countries� 6� The ways in which these issues are addressed will have lasting repercussions on the attractiveness of potential carbon assets generated by CCS projects, and also on the scope and complexity of future regulatory requirements for CCS in developing countries� The latter issue could possibly become one of the main limiting factors for the ability of developing countries to host CCS projects during the period 2010–2030� 7� Addressing the regulatory requirements for CCS in developing countries should encompass all potential requirements that may be set in relation to accessing public sources of climate finance, as well as to leveraging private finance through carbon markets� The latter could cover methodological aspects (such as baseline approaches and MRV procedures) and other possible restrictions that may be imposed when linking regional ETSs to international offsets� This will be vital to ensure fungibility of any CCS-generated carbon assets� 8� Fast-tracking of demonstration projects in low-cost opportunities, in sectors with established laws and practices that could be applicable to CCS, could allow targeted technical, regulatory, and institutional capacity building in developing countries� However, there is significant lead time in developing operational CCS projects and designing cost-effective optimization of CO2 pipeline networks and storage hubs� These long lead times, combined with the uncertainty concerning the shape of future policy frameworks and the resulting ambiguity surrounding the associated amounts, schedules, mechanisms, and modalities of climate finance, could result in delays in project implementation, and the loss of opportunities for key capacity building benefits that could be earned during a phase of technology demonstration� Figure 5.1: Marginal Abatement Cost Curves for CCS in 2020 by Sector and Region 150 Abatement cost $/tCO2 avoided 125 100 75 50 25 0 0 20 40 60 80 100 120 Abatement potential MtCO2 per year Gas processing Chemicals Coal power Iron & Steel Gas power Cement 45 Figure 5.2: Marginal Abatement Cost Curves for CCS in 2030 by Sector and Region 100 Abatement cost $/tCO2 avoided 80 60 40 20 0 0 100 200 300 400 500 600 700 800 900 Abatement potential MtCO2 per year Gas processing Chemicals Gas power Biomass power Iron & Steel Pulp and paper Coal power Cement Source: Carbon Counts based on IEA Technology Roadmap for CCS (2009)� trajectory in the IEA Scenario. The estimates are Current Technology Status and Future Outlook for investigated for assumptions for both carbon prices CCS in Developing Countries: A Reading of the IEA of US$15/ton CO2 and US$50/ton CO2. As well ETP Blue Map Scenario as its focus on developing countries, an additional novel component of the analysis presented is the Under the Blue Map Scenario, a strong outlook for compilation of CCS-specific marginal abatement cost CCS deployment in developing countries is suggested, curves based on the metric for the cost of abatement with a significant ramp-up beyond 2020, following in developing countries, as shown in the Figures 5.1 a decade-long demonstration phase. Between 2020 and 5.2.32 and 2030, emission reductions in developing countries 32 For the purposes of the analysis used in this report, those countries defined as “developing� have been interpreted to include all non–Annex I Parties to the Kyoto Protocol, as well as the Former Soviet Union (FSU) countries excluding Russia, Ukraine, and Belarus. The regional category indicated as “other� includes the FSU and non-EU East European and Balkan countries. achieved through CCS are anticipated to increase and reaching 50 large-scale projects that should be around eightfold, rising from 114 Mton CO2e avoided in operation by that time. from 50 projects in 2020 to 850 Mton CO2e avoided from 450 projects in 2030. This is a considerable 2020–2030 expansion from today’s situation where the In Salah Gas CCS project in Algeria is the only large-scale • Beyond 2020, the scenario indicates the deployment CCS project operational in a developing country. of CCS across a much wider range of sectors However, a number of other CCS projects are at and project types compared to the previous various stages of deployment in the developing world, decade’s focus on lower-cost “early opportunity� including several CCS initiatives linked to enhanced projects and technology demonstrations in higher- oil recovery, led by Masdar Carbon and supported cost opportunities with pure CO2 streams. In by the Abu Dhabi National Oil Company (ADNOC), the 2020–30 period, for example, the growing and two pilot-scale projects capturing CO2 from coal- role of bio-energy to meet mitigation efforts in fired power facilities in China. There has also been a the transportation sector could make bio-energy considerable increase in activity in other developing combined with carbon capture and storage (BECCS) countries relating to CO2-EOR (for example, in the an essential technology to reduce the life-cycle Middle East and Latin America), driven largely by emissions of bio-fuels. 46 efforts to increase national hydrocarbon production, • According to the scenario, China and India led by both state energy companies and international represent a more dominant and growing role in oil majors (see Table D.2 in Appendix D for a brief deployment after 2020, driven largely by the capture overview of the status of CCS in developing countries). potential in fossil fuel–fired power generation and heavy industry. China alone is envisaged to The following points summarize the trajectory of account for almost one-third of CCS deployment in CCS deployment, as described in the IEA ETP Blue developing countries by 2030 (by share of avoided Map Scenario, and the resulting implications on the emissions), largely driven by the ramping-up of CCS deployment across sectors and regions: projects in the coal-fired power sector and a steady number of projects around iron and steel sources. 2010–2020 In the near term, however, other emerging countries in Asia are expected to account for a significant • In the next 10–15 years, CO2 capture from power share of deployment, predominantly because of the generation will represent only a minor share of CCS presence of high-CO2 natural gas fields across the projects, with units capturing CO2 from industrial region. (iron and steel, cement, and chemicals) and upstream • The trajectory includes around 40 projects (natural gas processing) sources contributing a larger constructed every year from 2020 to 2030. share of the total number of CCS projects. • Projects in natural gas processing facilities are The Funding Needs to Deploy CCS in Developing among those that represent early CCS opportunities Countries and Current Level of Support because of their likely low capture costs, with the capture step integrated within the gas processing Significant funding is needed to deploy CCS in from high-CO2 concentration streams in natural developing countries at the pace described by the IEA gas fields. These projects will also likely have low trajectory. All in, based on the metrics developed in this transport and storage costs, since storage is located analysis and the IEA data for the deployment scenario, either in situ or in close proximity with the project the total additional costs of CCS in developing (like the In Salah project). Such opportunities can countries could amount to US$15–20 billion between be found across a range of regions (most notably in 2010 and 2020, and may total US$220 billion Asia) where there are significant recoverable reserves between 2010 and 2030. By 2020, this is equivalent of high-CO2 natural gas with associated storage to an estimated annual requirement of around US$4–5 capacity. An example is the giant Natuna D-Alpha billion per year, increasing tenfold to almost US$40 gas field located offshore in Indonesia. billion per year in 2030. These costs correspond to the • The trajectory sees on average 5 new operational annualized expenditures for building, operating, and projects built every year in the period up to 2020, maintaining exclusively the CCS component of a CCS facility, thereby reflecting additional, or incremental, across regions and sectors, from as little US$7–8/ costs for operators relative to an equivalent facility ton CO2 for some early opportunities (upstream gas without CCS. They include capital repayment of upfront processing and chemicals) to more than US$120/ investment,33 operating costs, and costs associated with ton CO2 in more complex applications (power and CO2 transport and storage.34 industrial sectors)—as shown in Figure 5.1 on the MAC curve for 2020. A range of support mechanisms, both In contrast to these needs, only limited support is market and nonmarket approaches working in tandem, currently available through the existing mechanisms of may therefore be required to support different types of climate finance.35 Presently, the Financial Mechanism CCS projects throughout their lifetime. of the UNFCCC (managed by the Global Environment Facility, GEF), the CDM, and multi- and bilateral For instance, carbon market revenues and nonmarket– concessional loans, grants, and guarantees are the based support can complement each other to cover main channels of climate finance for mitigation, the funding requirement of capital-intensive and delivering potentially on the order of US$8 billion of complex CCS applications (such as power and finance per year to developing countries, depending industrial CCS applications, albeit that according to on interpretations around the scope of climate finance the deployment scenario, projects in these sectors will (World Bank, 2010d). GEF support for CCS has been be in the minority in this period, with the majority in historically limited, although the GEF has recently lower-cost opportunities, such as gas processing). In 47 approved a US$3 million grant for a CCS project at these capital-intensive sectors, the technology costs a bio-ethanol refinery in Brazil. CCS technology is are greater because of the need to install capture currently only eligible under the CDM subject to the equipment associated with higher technological risk resolution of a range of technical, legal, policy, and (since the capture technology is less mature), making it financial conditions that are under discussion at the more difficult to raise the necessary investment capital time of the report preparation. from equity and debt. Operators are typically less well capitalized, have limited experience in subsurface Combining Climate Finance Instruments for issues, and tend to be more risk-averse. Public Near-Term Support up to 2020 finance will be critical to leverage equity and debt, and the carbon market will be essential in providing Mobilizing financial support for CCS in the next 10 the revenues to cover ongoing costs associated with years will be critical if successful demonstration of the operation of CCS plants. Early experience in these technology across different world regions and sectors sectors will also be critical to driving down costs—both is to be achieved. This will help acquire the necessary the technology (capital) costs, through better technology technical and institutional experience and achieve the integration, and financing (debt) costs, through greater anticipated cost reductions required to move into a experience and demonstrated performance. second phase of wider deployment beyond 2020. CCS projects are highly heterogeneous, with considerable The most effective support from climate finance to date variations in marginal abatement costs, reflecting is likely to take the form of up-front access to capital, differences in energy requirements and unitary costs of whether from grants or concessional loans, which can technology, capital and operating costs, and project- overcome the considerable CCS investment risks faced scale factors.36 The costs for CCS vary significantly by project developers and commercial lenders. Further, 33 Upfront investment for capture plants and associated transport and storage infrastructure could be as high as US$300 billion through 2030, of which around 8 percent (US$23 billion) would be needed over 2010–20. The transport and storage component could easily require half of this, depending on the degree of pipeline infrastructure optimization, as development of regional CCS networks and hubs using large diameter common carriage pipelines could reduce costs. 34 In addition to the upfront investment for capture plants and associated transport and storage infrastructure, the costs of deploying CCS include operational costs, such as maintenance and materials (such as amine solvents to capture CO2), the energy penalty associated with capture and compression, and the costs associated with transport and storage (such as additional compression requirements). These elements may represent a significant share, up to one-third, of annualized CCS costs with the remainder consisting of financing costs. 35 CCS demonstration is focused so far in developed countries. In a recent report from the Carbon Sequestration Leadership Forum (CSLF) and the IEA, it was highlighted that between US$26.6 and US$36.1 billion of funding to support 19–43 large-scale CCS demonstration projects has been allocated across OECD regions (IEA/CSLF 2010). 36 Abatement costs for CCS projects are expressed in U.S. dollars per ton CO2 avoided and calculated as the ratio between additional costs and avoided emissions. Additional costs correspond to the annualized expenditures of building and operating the CCS component in a project. They include capital repayment and operation (fuel and maintenance, transport and storage). Avoided emissions are defined as the level of emissions abatement achieved by CCS-equipped facilities relative to the emissions of an equivalent facility (that is, with the same output) without CCS. It reflects the “energy penalty� associated with CCS equipment. The different cost tranches presented within each sector reflect regional cost differences and/or the varying economics of different project and technology options within sectors and subsectors. For detailed explanations of the metrics used, see Box D.1 in Appendix D. depending on the prevailing carbon price, these upfront analysis suggests that market mechanisms could work needs could be met through a dedicated public fund well to support lower-cost, early opportunities, such as with capitalization of approximately US$4–20 billion (for in natural gas processing (subject to the timely resolution carbon prices of US$50/ton CO2 and US$15/ton CO2, of regulatory, policy, and methodology issues, discussed respectively). below). For example, project-based approaches such as the CDM, in particular when blended with other Nationally Appropriate Mitigation Actions (NAMAs), sources and forms of dedicated public assistance, recently formalized at COP 16, could provide a may be applicable to lower-cost, single-operator CCS framework for combining options for CCS support, projects, such as those associated with isolated high- bringing together domestic financing and policy support CO2 concentration natural gas field developments. In (including such measures as mandating capture or this sector, the technology is more mature, with several capture-ready design at new-build facilities, indirect hundred CO2 removal facilities in operation around the support through carbon taxes and levies, or the use world as of today. Further, operators in this sector are of feed-in tariffs for CCS in the power sector) with typically well capitalized, they have in-house expertise international support through climate finance. suitable for project development, for example on regulatory aspects relating to subsurface issues and, in The proposed Technology Mechanism, for example, the case of international oil companies, they have direct 48 could also play a role in supporting other aspects drivers for accessing carbon assets. of deployment for pre-commercial technologies, by offering loan guarantees to buy down project financing These early opportunity projects in the natural costs or developing a system of carbon price floors gas industry can help demonstrate successful or credit revenue guarantees. Other types of softer CCS implementation in developing countries and support could include activities, such as supporting the allow experience to be gained with, in particular, optimization of regional CCS deployment by providing methodological and accounting approaches and additional up-front support for pipeline oversizing (for technical subsurface issues, which tend to be the example, lending the incremental capital requirements), most challenging and are generic for all types of CCS and undertaking financial analysis for potential project applications. Further, these types of projects can support clustering. the early stage development of expanded infrastructure by establishing qualified storage sites that may be Other alternative forms of climate finance to foster CCS suitable for storing CO2 captured from other sources in development have been suggested in the literature, such the future. as fund-based financing structures—that is, creation of an international public fund solely dedicated to CCS37 However, there are challenges for these projects in or a CCS window within a larger fund that may also gaining access to climate finance, since the oil and gas finance other pre-commercial low-carbon technologies sector has historically struggled to access mechanisms in developing countries (Almendra and others, 2011). such as the CDM, for a range of reasons, including Another option is possible bilateral partnerships between in-house and external political factors.38 Further, any developed and developing countries that might be realistic expectations of the level of support for CCS accounted as fast track financing under the UNFCCC projects through market-based instruments would need and bilateral crediting systems that might include CCS to account for some intrinsic limitations of performance- (Hagemann and others 2011). based crediting, including limited capacity both in leveraging projects with high upfront investment needs, The relative contribution of market and nonmarket and to support demonstration stage technologies, mechanisms is highly dependent on project types. The because of the institutional and political uncertainty 37 Such dedicated CCS fund might help to address the issue of limited ability of CCS to compete with other commercially deployed mitigation technologies (Almendra and others 2011). 38 Within the current portfolio of CDM projects, the sector has only around 35 projects supporting around 66 MtCO2 of annual emission reduction. This restricted access to the CDM, among other economic and political factors, results from the perception of potential perverse incentives for CDM projects in the extractive industries (additionality of reductions) and to the complexity and limited flexibility of current methodological approaches to estimate and monitor achieved emission reductions. These aspects created significant uncertainty around the prospect of generating carbon revenues from CDM projects in oil and gas sector, which in turn reduced the appetite of investors for GHG mitigation opportunities in this sector. over the acceptability of the CCS-generated emission improved technology integration, and cost reduction. reductions. If these challenges are to pervade into the The fast-tracking of demonstration projects in low-cost next decade—which is possible, given the potential opportunities also allows targeted technical, regulatory, perverse outcomes that some Parties and Observers and institutional capacity building in developing have associated with CCS under carbon finance39— countries. Yet, given the lead time in developing there is a strong possibility that the contribution of these operational CCS projects and constructing cost- funding sources to the vital near-term demonstration effective, optimized CO2 pipeline networks and storage efforts for CCS in developed countries could be, at best, hubs, it is essential to rapidly provide sufficient certainty deferred and at worst, missed altogether. concerning the shape of future policy frameworks and the associated amount, schedule, mechanisms, Longer-term support for CCS demonstration and modalities of climate finance, in order to avoid through climate finance (beyond 2020) deferring or missing the important benefits obtained during a period of technology demonstration. Although the abatement costs within each sector are expected to have fallen by 2030 through technology Challenges for CCS Projects in Developing demonstration, fewer low-cost “early opportunity� Countries to Access Carbon Finance projects would be available, resulting in a sectoral shift in deployment towards larger-emitting, but more Climate finance may become available in a variety 49 challenging sectors, such as coal- and gas-fired power of forms and should be combined in an effective generation facilities, iron and steel plants, and cement way for supporting demonstration and deployment kilns. Consequently, per-ton CO2 deployment costs are of CCS technologies in developing countries over overall expected to rise on average over this period, as the period up to 2030. The capacity of CCS to be shown in the MAC curve in Figure 5.2. The shift in the eligible for these various forms of climate finance will scale of deployment will require a corresponding step- rest on policy makers and investors being assured change in the finance and investment needs. that the technology can deliver emission reductions permanently, at an affordable cost, and with a low risk Because CCS will be only one of several low-carbon of failure for both capture and storage. Critical to this technology options calling for significant climate finance will be the development of high-quality CCS projects over the coming decades, the level of ambition will in which the risks of technology failure have been need to rise from what is currently envisaged to meet minimized to a sufficiently low level that is comfortable the required mitigation investment needs of the future, for investors. in order to cover the average annual finance needs of US$11 billion per year over the period 2021 to 25 and However, in practice, a range of qualitative factors will US$30 billion per year from 2025 to 2030. New forms likely have a major impact on the perspectives of CCS of climate finance involving cooperative combinations projects to access climate finance and achieve the of domestic and international support will likely be projected level of financing needs for CCS in developing necessary to deliver these levels of investment. countries. These factors are assessed in the section below. Timing is a critical factor in scenarios of CCS Key Policy Issues Defining CCS Attractiveness for deployment and financing. Although the near-term Climate Finance financing needs associated with CCS demonstration are modest compared to the levels of climate finance Many legal, regulatory, and policy issues remain to potentially available, the success of this phase over be resolved at the international level, including, for the next decade or so will be critical to realizing example, approaches to managing permanence, the longer-term vision for CCS and climate change project boundaries, MRV, and safety and environmental mitigation. Important lessons and experience gained impacts. At the present time, these issues are being over this period include technology demonstration, discussed by Parties to the Kyoto Protocol in the context 39 Such as an increase in production and consumption of fossil fuel, diverting investment away from other low-emission technologies, creating new emissions through combustion of fossil fuels obtained through EOR, enhancing CO2 generation to maximize carbon asset potential, and constraining bio-energy with CCS (BECCS). See Zakkour and others 2011, Section 5.1.7. of modalities and procedures for CCS inclusion within Both approaches have advantages and disadvantages, the CDM. The topics under consideration within although the former approach (buyer liability) has the context of the CDM will, however, be critical for significantly eroded demand for carbon assets from the design of MRV approaches by setting important afforestation and reforestation projects under the precedents for future mechanisms for climate finance CDM. Emerging preferences among developed country that might support CCS. Three of the key issues to be Parties—as expressed in views on the inclusion of CCS resolved include the following: in the CDM—is to opt for the seller liability approach, although this may not receive widespread support from • How to account for the permanence (or non- developing country Parties. permanence) of emissions avoided through CCS, if a carbon reversal were to occur as a result of CO2 Secondly, and in particular for a seller liability leaking from a storage site. approach, there is also a need to consider the use of • Whether and what form of mechanism might be a financial assurance mechanism to ensure the longer- employed to provide financial assurance over long- term availability of funds for the host country to cover term stewardship and the risk of carbon reversal. any costs associated with the long-term stewardship of • The extent to which governments will have storage sites (for example, monitoring and remediation to implement domestic regulatory regimes to in the event of carbon reversal). This could involve 50 cover various aspects relating to CCS project either some form of a global pooled trust fund, or development, management, and long-term private or bilateral instruments agreed between a stewardship (for example, project design and developer and the host country. The precise shape and operational standards, including MRV aspects). form of each option has yet to be fully explored and This will be strongly influenced by the requirements evaluated, although there is general consensus among developed at the international level in relation to Parties considering CCS in the CDM that some form climate finance for CCS. of insurance might be needed to cover compensation because of seepage, as reflected in recent Decisions on There exists a broad range of literature sources, the matter at the UNFCCC level. describing options for tackling many of the issues raised.40 Further, in the case of regulatory developments in developing countries, the precise scope and extent of Managing Permanence and Long-Term Liability for requirements is partly contingent on the approach taken Seepage to manage permanence and long-term liability, with a seller liability model probably posing more onerous In the case of permanence, which has been defined requirements in relation, for example, to the need to set as “a quantitative term to characterize whether the down a structured approach to liability transfer for any removed carbon dioxide stays out of the atmosphere related financial assurance mechanism. for a long time� (Sharma 2006), the leakage of CO2 from the storage site into the surrounding environment Main Components of a High-Quality CCS Project would compromise the political and technical objectives Design and Operational Practice of the technology and erode the environmental integrity of any emissions trading scheme, into which carbon Subject to the range of issues outlined previously being assets from leaking CCS projects have been sold. It resolved, several other key components will be needed is presently unclear whether permanence issues will within a CCS project development plan in order to attract be managed through a buyer liability approach (for climate finance and generate fungible carbon assets. example, the use of temporary carbon assets) or seller The establishment of rules, steps, and criteria for project liability approach (for example, host country takes on design and operation is an important part of future long-term permanence risk), which would either couple accounting rules for any climate finance mechanism or decouple liability from the carbon assets generated. supporting CCS projects in developing countries.41 The 40 This includes submissions from Parties and Observers to the UNFCCC spanning several years up to and including the most recent round in March 2011 (available at UNFCCC 2011a); the UNFCCC Synthesis Reports of previous submissions (UNFCCC (2008a) and UNFCCC (2008b)), reports from the IEAGHG in both 2007 and 2008 (IEAGHG 2007; 2008) and a recent set of recommendations for addressing the key issues for CCS in the CDM published at the end of 2010 by the World Resources Institute (WRI) (WRI 2010a). effective project design and operation would need to transparent MRV approaches are essential to ensure the cover robust selection and characterization procedures environmental integrity of international offsets. At the for geological storage sites, the carrying out of risk same time, the MRV approaches should be practicable assessments that can effectively assess the likelihood and enforced at acceptable costs for project operators. of achieving long-term or permanent storage, methods For instance, taking into account the heterogeneity of that can establish appropriate modes of operation for subsurface conditions of CCS geological storage sites, storage sites, and the defining of project boundaries it would be more practicable to develop a generalized and the MRV requirements for CCS projects within those series of steps and procedures that would need to boundaries, as well as closure and stewardship of the site be tailored on a project-by-project basis (based on post-closure. the appropriate techniques, locations, and frequency of application) rather than establish the prescriptive Projects would also need to conform to relevant approaches. It is also important to ensure that there is domestic and international laws that could apply to sufficient competence within the auditing entities at the CCS, such as requirements for EIAs, social impact national and international level, so as to enable efficient assessments, and requirements under, for example, the third-party verification of the CCS projects and reported London Convention and Protocol thereto, as discussed CO2 emission reductions. It is also critical to maintain a in Chapter 4 on legal and regulatory frameworks degree of flexibility on any overarching rules to ensure potentially applicable to CCS. their improvement and evolution along with the lessons learned from the demonstration of CCS activities in Addressing these regulatory aspects of CCS projects is developing countries. necessary to minimize exposure to risks related to CCS operations, including the risk of seepage.42 A range of Table D.3 in Appendix D provides an overview of the good-practice examples exists for all these aspects of main components for good practice for CCS project project design.43 Bringing together this knowledge and design and operation. experience into a comprehensive yet workable framework for CCS project development will likely be critical for Role of International and National Regulation in unlocking climate finance support for high-quality CCS Establishing Rules and Standards for CCS Projects projects in developing countries in coming years. Concerning CCS project design standards, it is The MRV approaches to be implemented in CCS presently unclear whether centralized approaches projects represent an important part of the rules (involving the setting of detailed rules and procedures for accounting for CO2 stored in CCS projects. at the UNFCCC level, for example, site selection) or The monitoring plan should cover the entire set of decentralized approaches (involving, for example, components included in the project boundaries. imposition of a range of eligibility criteria that countries Monitoring should also continue for a period after a wishing to obtain climate finance for CCS would need storage site has been closed (post-closure monitoring to implement in national legislation) will be taken. Some can also provide a useful basis for liability transfer from developed country Parties and experts have suggested operator to state, if appropriate). that the presence of national CCS legislation should be a prerequisite for hosting CCS projects under the CDM, The experience gained so far by CDM/JI (Joint a view that partly relates to their support for the seller Implementation) projects, as well as by the Green liability preference to managing permanence. However, Investment Schemes (GIS),44 suggests that robust and the view also seems to prejudge the extent of rules 41 An example of a potential high-level approach is contained in Annex I and Annex II of the EU’s CCS Directive (Directive 2009/31/EC). Annex I sets out steps for site selection and risk assessment. Annex II sets out guidance on monitoring plan design, including procedures for updating the monitoring plans during the operational phase of a CO2 storage site. 42 The above-ground components of CCS projects present similar risk as those presented by other large infrastructure projects, including oil and gas field developments, power plants, gas distribution networks and other large industrial facilities. Management of occupational health and safety, civil protection, and environmental impacts related to these components should be covered under existing controls applicable in the host country. Subsurface storage, including seepage, also presents health, safety, and environmental risks. 43 This includes the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006), various emerging legal frameworks in OECD countries, a proposal for a new methodology for CCS within the CDM for the In Salah project in Algeria, and publications from industry sources and reputable international organizations. 44 Green Investment Scheme (GIS): A GIS is a voluntary mechanism through which proceeds from AAU transactions will contribute to contractually agreed environment- and climate-friendly projects and programs both by 2012 and beyond. that could emerge under international climate change term certified emission reductions (tCERs, lCERs) are frameworks for CCS. Today, uncertainty in these respects prohibited in several developed country ETSs today. has ramifications for the design of domestic CCS Conversely, a seller liability approach could result in legislation in terms of its scope and extent, for example, the introduction of differential approaches to regulatory in terms of the level of detail on site selection that might aspects of CCS projects, such as approaches to need to be implemented in national legislation. Delays managing liability across developing countries. This in decisions at the international level on this matter might lead to a situation in which some jurisdictions affect the capacity of developing countries to implement would impose their own standards for accepting appropriate national legislation and standards for CCS. CCS-derived carbon assets, or could result in a total prohibition on such use of assets by some emissions Other Policy and Methodology Factors Affecting trading scheme operators. A further outstanding issue to the Level of Support for CCS from Climate Finance be resolved is whether value-added applications, such as EOR, will be eligible for climate finance. The level of benefit from climate finance will also depend on the approaches to be used to define and The key questions for fungible treatment of CCS-derived account for GHG emission reductions eligible for trading offsets, and the potential use of restrictions in Annex and crediting through the market-based mechanisms I carbon markets, mirror similar ongoing discussions 52 in their current and future forms. The following two concerning CCS inclusion within the CDM and its main limitations would alter the level of support and the treatment within the UNFCCC policy framework. As a financing profile of CCS projects presented previously: consequence, the important remaining challenges relate (a) restricted fungibility of CCS assets (that is, their ability to the development of robust and enforceable rules and to be mutually recognized and tradable across different guidelines to fast-track support for CCS through market- developed countries’ ETSs), including the issues related based mechanisms of climate finance. to potential linking of ETSs that might affect the eligibility of CCS assets for trading; and (b) the approaches Impact of Baseline Methodology Selection selected for defining the baseline level of CO2 emissions that may also have tangible impacts on the net amount Although the precise impact of the baseline of CCS assets eligible for crediting. methodology selection has not been analyzed in detail, the baseline selection could potentially reduce the Possible Restrictions on the Fungibility of CCS- level of offsets supplied by CCS in the order of 40–60 Generated Assets percent of the estimates outlined in the previous section. The data used in this analysis is based on the “avoided Various restrictions may apply to the CCS-related CO2� emissions calculated on the basis of the emissions assets generated in developing countries under associated with the same underlying process with the current and future ETSs. These restrictions may relate same output, but absent CCS. In practice, baselines to the perception of the environmental integrity and may be calculated at a regional or sector level (for acceptance of CCS-generated assets within the example, a grid emission factor in the power sector) established regulatory and institutional framework or according to the best available technology in the (based on the evaluation of the robustness of project sector. This allows an assessment to be made in a design and operation standards, MRV approaches, conservative manner of an alternative option that would treatment of permanence and long-term liability, be implemented in the absence of the CDM project, but treatment of CCS projects involving EOR, and so forth). providing similar service. Approaches to managing permanence and long- Other approaches could also be considered for CCS term liability could also have ramifications for the projects. In particular, drawing parallels with the existing fungibility of CCS derived carbon assets. For example, methodologies for waste recovery (and utilization) or if temporary credits are issued under a buyer liability associated gas flaring reduction activities in the oil and approach model, this would likely significantly erode gas sector. demand for such credits in the carbon market, as has been seen for afforestation and reforestation projects Further, under the potential sectoral trading, if the under the current CDM, and temporary and long- baselines are defined at the sectoral level without allocation to individual entities, the incentive provided • Lack of host government policies and private by the carbon price signal may be less direct or sector strategies that may be geared towards the insufficient to alleviate the high risks of CCS projects. demonstration and deployment of CCS, including In fact, in this case offsets may be only awarded based those that represent early opportunities. on the performance of the whole sector achieving a set reduction target, which would in all likelihood deter Domestic Legal and Regulatory Requirements any investment in step-change reduction technologies, such as CCS. Under potential NAMA crediting, if It is currently uncertain what in-country legal different layers of climate finance are envisaged, only requirements would be needed in order for developing a limited portion of emission reductions achieved by countries to host CCS projects, which could attract CCS activities might be eligible for carbon finance climate finance and generate internationally acceptable (for example, a portion of the costs met through CCS-derived carbon assets.45 Greater clarity is necessary implementation of domestic polices and measures, in a number of areas including the following:46 a portion of finance provided by concessional loans, and a remaining portion of costs provided through the • The level of technical detail that might be factored sale of carbon assets). In either case, the financing into international modalities and procedures for profile presented previously would be altered, CCS (for example, within the CDM) with respect to meaning a change in emphasis away from carbon the CO2 storage site selection and operation, and 53 asset generation towards the use of other types of the degree to which a prescriptive approach will mechanisms to raise finance. In this context, NAMAs be taken in the main components of CCS project with a potentially layered approach to climate finance design and operational rules and standards. offer a possible effective mechanism to channel • A set of technical aspects that might need to be finance to CCS. elaborated in secondary implementing tools, such as approved methodologies and project financing Potential In-Country Limitations for CCS guidelines, as well as the level of complexity and Deployment in Developing Countries flexibility of these tools. • Approaches to managing permanence and long- Notwithstanding the range of options for managing term liability at the national, bilateral, or multilateral the environmental integrity of CCS and its acceptability level (for example, under UNFCCC mechanisms). under the climate finance, potential limitations could also arise in host country requirements and capacities. The way and extent to which these aspects, as well This section discusses some of the main in-country as other legal and regulatory requirements, will be limitations for CCS deployment and suggests a set of handled at the international level, will determine the capacity building activities that would help to alleviate scope and extent of issues to be covered in national them. In-country factors, potentially affecting CCS laws and regulations. The level of detailed guidance deployment, may include the following: on the design of modalities and procedures issued by .6 the Parties in Decision 7/CMP suggests that, at least • Potential lack of awareness about CCS technologies, within the CDM framework, a significant amount of including their costs, prospective applications, legal detail will be included within guidelines at the UNFCCC aspects, and technical factors. level. At the same time, the presence of national laws • Lack of legal and regulatory regimes that are able to and regulations for CO2 storage sites (and potentially accommodate CCS projects, in particular, the CO2 other aspects) is viewed by some developed countries storage component. as a precondition for developing countries to host CCS • Lack of suitable institutions and regulatory capacities projects. to provide oversight for project design, development, operation, closure, and longer-term aspects of site Even though significant uncertainty remains on stewardship. regulatory needs, legislation pertaining specifically to 45 It is important to be mindful in this context that it is possible for developing countries to develop CCS projects within their own jurisdictions today, irrespective of activities at the international level. The issues described here relate only to those actions that might be necessary in order for countries to host projects that would be eligible to receive climate finance. 46 The full list of regulatory issues to be addressed when creating a sound regulatory framework for CCS is suggested in IEA 2010b. CO2 storage, for example, could be developed within of research centers and programs supported by multi- existing legal frameworks, such as oil and gas field and bilateral institutions. Other important activities for development regulations. This will particularly be the regulatory aspects include the IEA’s International CCS case where CO2 injection operations take place within Regulatory Network, where several developing country an existing oil or gas field lease, where laws are already participants have been invited to attend in recent years, define the modalities for subsurface access and use, including participants from Botswana, Malaysia, Mexico, regulations exist defining the operational practices South Africa, and Vietnam in 2011, as well as China, for the field (for example, within a field development India, and Brazil in 2010.48 The World Bank CCS plan), and a competent regulator is in place to oversee Capacity Building Trust Fund is also planning a range of activities.47 Flexible approaches to regulation that capacity-building activities in Asia (for example, China, recognizes the distinction in different project types India, and Indonesia), the Middle East (for example, and allows for “fast-tracking� within well-established Egypt and Jordan), North Africa and the Maghreb (for hydrocarbon laws could be an attractive solution to example, Algeria, Morocco, and Tunisia), the Balkans facilitate early development and demonstration of (for example, Kosovo), and Southern Africa (for example, CO2 storage activities in developing countries. This is Botswana and South Africa). Table D.2 in Appendix D a particularly relevant issue with respect to the CCS provides a summary of CCS activities in developing demonstration and deployment pathway outlined countries. 54 previously, and the focus on gas processing projects in the near term. Further initiatives would need to build upon the ongoing effort and ensure the avoidance of duplication of efforts Capacity-Building Needs in covering a broad range of institutional, technical, and management capacity building needs in developing Capacity building and knowledge exchange will play countries. In addition to broader awareness-raising an important role in ensuring CCS demonstration and activities, suggested capacity building components that deployment in developing countries. The number of would target the development of regulatory frameworks, ongoing and planned initiatives and activities in this institutional capacities, and appropriate approaches area is growing, including regional workshops and other defining the attractiveness of CCS for climate finance in-country supported activities, such as the establishment are summarized in Table D.4 in Appendix D. 47 This is the case now with the In Salah project in Algeria, which is overseen within the scope of the Joint Venture partners’ gas-producing lease. 48 More information available at http://www.iea.org/ccs/legal/network.asp. 6. PROJECT FINANCE FOR POWER PLANTS CCS projects with known specifications (World Bank WITH CARBON CAPTURE AND STORAGE IN 2011d). DEVELOPING COUNTRIES Key Findings Chapter 5 of this report discusses the climate financing needs required for CCS to be deployed at on the They key findings of the analysis are presented in trajectory described in the IEA Blue Map Scenario, and Table 6.1. Unless otherwise stated, the numeric results specific market and nonmarket mechanisms that could described in Table 6.1 are for medium coal prices be used to achieve these trajectories. As a next step, this (US$3/MMBtu), wet-cooled generation technologies, chapter narrows the focus of financing to the project full capture CCS (90 percent of plant emissions) without level, summarizing the results of a study to investigate extra revenues from enhanced hydrocarbon recovery, (a) how certain parameters affecting project cash flows and they assume 50 percent financing from MDBs can impact the LCOE, (b) possible ways to structure and 50 percent from commercial loans. Reference financing for power generation facilities equipped plants never include concessional sources as part with CCS in the developing world using instruments of their financing. Of the many scenarios examined, available from both multilateral development banks and only a subset are presented in this report, since the commercial financiers, and (c) whether a combination implications drawn from these results are consistent of such instruments could result in reductions in the across variations in parameters and financing scenarios, 55 overall cost of financing and consequently requiring and demonstrate the main trends observed. See Box 6.1 smaller incremental increases in electricity rates. for an explanation of the LCOE. The study examines these parameters through Methodology investigating the percentage increase in the LCOE of a coal plant with CCS with respect to a corresponding The study method involves adapting a model of LCOE plant of the same combustion technology without CCS (Du and Parsons 2009) for coal plants with and without (the reference plant). By this construction, the definition CCS technology. For the purposes of investigating the of financial viability for this study is a power plant effects in variations of financial instruments, reference with CCS having an LCOE equal to that of a plant 500 MW coal power plants, of different power of the same technology without CCS. To understand generation technologies and cooling methods, are the implications of the results in reality, consideration built into the model. For each reference plant, a coal should be given to whether the bar for financial viability plant of the same generation technology and cooling should be set higher, perhaps on a par with other low method, but with capture technology appropriate GHG–emitting technologies. The reason for this is that to the plant type, is also included in the model. The if there is ambition to reduce emissions, these low- plants with CCS are modeled as new builds, rather carbon technologies should be competing with each than plants retrofitted with CCS. Transport and storage other, rather than with the current source of power costs are also included. The model includes varying generation. parameters to allow for the examination across the CO2 capture technologies. These variable parameters As mentioned earlier in the report, cost estimates for are CO2 capture rates, coal prices, and potential CCS technology are highly uncertain. This should be revenue streams from EOR/ECBM recovery or carbon borne in mind while reviewing the results, rather than prices. For each combination of the varied parameters interpreting the absolute values as the key findings of described above, different financing structures are tested the analysis. Further, given that this analysis has been as scenarios, including a combination of instruments performed for generic coal plants as “reference plants� employed by MDBs and commercial lenders, as well as and not for a specific region or project, the findings concessional finance, to assess their impact on lowering should be viewed as illustrative of general relationships the LCOE for the coal plants equipped with CCS between parameters and the financial viability of technology. For each scenario and capture technology, potential power projects with CCS. The model used the analysis examines the percentage change in the for the analysis is available and can be edited as the LCOE from the reference plant (the plant without CCS) user wishes to model the financial viability of particular to the corresponding plant with CCS. Table 6.1: Summary of Findings and Conclusions Result Implications of results Variations in cooling method The differences in percentage changes Percentage change in LCOE from reference plant to plant with CCS: in LCOE from the reference plant to the plant with CCS are smaller across wet- or Coal Plant technology Percentage increase in LCOE dry-cooled technologies than all the other IGCC dry-cooled 34 variations examined� In other words, whether a technology is wet- or dry-cooled has IGCC wet-cooled 32 less impact on the LCOE than the other parameters examined� PC dry-cooled 60 PC wet-cooled 60 Variations in capture technology IGCC technology has the smallest percentage Percentage change in LCOE from reference plant to plant with CCS: change in LCOE from the reference plant to the plant with CCS, followed by Oxyfuel, then Technology Full capture Partial capture PC� PC 60 19 56 Oxy-fuel 46 16 IGCC 34 11 Variations in coal price Increasing coal prices affect the percentage Percentage change in LCOE from reference plant to plant with CCS: change in LCOE from the reference plant to the plant with CCS� As the coal price Coal price (US$/MMBtu) PC Oxy-fuel IGCC increases, the percentage change in LCOE 1 69 53 31 trends towards the percentage change in the heat rate of the reference plant to the heat 3 60 46 34 rate of the capture plant� This is because the effect of the coal price on the LCOE is 5 56 34 35 dependent on the plant’s efficiency, and as coal prices get higher, this effect dominates Percentage change in heat rate from reference plant to plant with CCS: the other costs� For each capture technology, the percentage change in LCOE therefore PC Oxy-fuel IGCC trends towards different values, since the percentage change in heat rates are also 44 34 38 different� Variations in Co2 price The extra income from higher CO2 prices Percentage change in LCOE from reference plant to plant with CCS: lowers the LCOE of plants with CCS� The trend in decrease in LCOE when there is a PC Oxy-fuel IGCC carbon price is uniform across technologies� US$0/ton 60 46 34 Going from US$0/ton CO2 to US$50/ton CO2, the percentage change in LCOE from US$15/ton 51 37 25 the reference plant to the plant with CCS decreases by approximately 30% across plant US$50/ton 29 15 4 technologies� Variations in EOR/ECBM The impact of additional EOR and ECBM Percentage change in LCOE from reference plant to plant with CCS: revenue streams on LCOE depends heavily on the specifics of the storage site� For the PC Oxy-fuel IGCC assumptions used in this study, both options None 60 46 34 reduce the LCOE for the plant with CCS, but only by approximately 2% across all plant EOR 58 44 32 technologies� ECBM 58 45 32 (continued on next page) Table 6.1: Summary of Findings and Conclusions (continued) Result Implications of results Variations in finance structure The blended debt interest rates for the three Percentage change in LCOE from reference plant to plant with CCS: financing structures examined are 6�59%, 5�91%, and 5�98%� Since all financing sources Financing Blended debt Oxy- are market based with similar financial costs, structure interest rate* PC fuel IGCC the results show that the small difference in MDB loan + 6�59 60�2 46�3 33�7 debt interest rate has virtually no effect on commercial loan the resulting LCOE of a coal plant with CCS, and therefore has no effect on the percentage MDB loan + 5�91 59�8 45�9 33�8 change in LCOE from the reference plant to commercial loan the coal plant with CCS� with guarantee Multiple 5�98 59�8 45�9 33�8 *Rates based on the US$ LIBOR curve as of MDB loans + May 12, 2011� All rates are subject to change commercial loan because of market conditions� + guarantee Variations in concessional financing If concessional financing of 30% and 50% Percentage change in LCOE from reference plant without concessional of total project finance are provided to a 57 funding to a plant with CCS with concessional funding: coal plant with CCS, the LCOE is reduced� The greater the portion of concessional Level of concessional finance, the lower the LCOE for a plant with financing (Percent) PC Oxy-fuel IGCC CCS (concessional finance is not applied to the reference plants without CCS)� At the 0 60 46 34 maximum level of concessional financing 30 54 41 30 used (50% of all debt financing needs of the project), the LCOE increases from 29% to 51% 50 51 37 29 from that of the reference plant depending on the technology used� Cases where less than 50% concessional financing (CF) is There are cases where concessional financing required for LCOE of plant with CCS to be equal to that of of less than 50% could reduce the LCOE of a reference plant without CCS (and without concessional the coal plant with CCS to the point where it financing) is equal to that of a reference plant�* US$ In all cases where this is possible, the plant Percent CF amount with CCS receives additional revenues in the Technology Extra revenues required (millions) form of carbon credits at a price of US$50 per ton and, in most cases, additional revenues Oxy-fuel EOR, US$50/ton CO2 2 26 from enhanced hydrocarbon recovery are also Oxy-fuel ECBM, US$50/ton CO2 4 49 available (EOR/ECBM)� These cases emerge as requiring less than 50% concessional Oxy-fuel US$50/ton CO2 12 142 financing in order to reduce the LCOE of the plant with CCS equal to the reference plant IGCC EOR, US$50/ton CO2 17 145 as these additional revenue streams improve IGCC ECBM, US$50/ton CO2 20 155 the profitability of the project� IGCC US$50/ton CO2 46 337 In these cases, for a plant with 90% CO2 capture, Oxy-fuel requires the least amount PC EOR, US$50/ton CO2 48 662 of concessional funds, followed by IGCC, and then PC� *It should be noted that in this analysis, the LCOE of the plant with CCS and concessional financing is compared to that of a reference plant with no concessional financing� capture (described as partial capture) and 90 percent Box 6�1: LCOE Structure CO2 capture (described as full capture). LCOE generally represents the cost of generating electricity for a particular plant or system� The For each technology, the LCOE is investigated for concept is basically an economic assessment of various circumstances, by varying the following all the accumulated costs of the plant over its parameters within a set range: lifecycle relative to the total energy produced over its lifecycle� More specifically, LCOE is a financial annuity for the capital amortization • Coal prices. expenses, including fixed capital costs (for example, • Availability of revenues from enhanced hydrocarbon equipment, real estate purchases, and leases) and recovery (EOR/ECBM). variable O&M expenses (and for thermal plants, fuel • Carbon prices. expenses), taking into account the depreciation and interest rate over the plant’s lifecycle, divided by the annual output of the plant adjusted by the discount These parameters are varied both individually as a rate: sensitivity test on the LCOE, but also in combination. For all combinations tested, three financing structures ∑ N I + Mt are applied to see how they affect the LCOE. As a t−1 t next step, these financing structures are then adapted (1+ r ) t 58 to include concessional financing to assess the impact LCOE = Et on the LCOE of the coal plant with CCS. Levels of 30 ∑ N I percent, and also 50 percent, of project costs financed (1+ r ) t−1 t t by concessional funds, are examined. These levels are chosen to reflect a maximum cap of concessional where r = discount rate | N = the lifecycle of the financing on a project, which is suitable at 50 percent, plant | t = year | = Investment costs in year t | = and a lower level, as a medium point between 0 O&M costs in year t | = Electricity generation in percent and 50 percent. year t If the discount rate is assumed to be equal to the For all the scenarios examined (the three different Weighted Average Cost of Capital (WACC), as it is financing structures, with and without concessional in the model used in this analysis, LCOEs reflect financing) and all the combinations of varying the price that would have to be paid to investors to cover all expenses incurred (such as capital and parameters (coal prices, EOR/ECBM, and CO2 prices), O&M) and hence the minimum cost recovery rate at the percentage change from the LCOE of the reference which output would have to be sold to break even� plant to the plant with CCS is calculated. In the cases where concessional financing is applied, it is assumed Source: A�T� Kearney 2010� that the reference plant does not receive concessional financing, and so the percentage change in LCOE here refers to the percentage change in LCOE from the reference plant under the original financing structure to The LCOE model includes reference coal plants of the the LCOE of the coal plant with CCS under the adapted following technologies: financing structure, which now includes concessional financing. • Pulverized coal (PC) wet- and dry-cooled • Oxy-fuel (Oxy) wet-cooled49 The results are reviewed to test whether the LCOE of a • IGCC wet- and dry-cooled plant with CCS with concessional financing is actually lower than the corresponding reference plant. For the For each of the technologies above, coal plants of the combinations of scenarios and parameters where this is same generation technology and cooling method, but the case, the amount of concessional financing of the with CCS, are also built into the model. The coal plants coal plant with CCS necessary to make the LCOE equal with CCS in the model allow for both 25 percent CO2 to the reference plant, is found. 49 Oxy-combustion with dry-cooled technology has been not been included in the analysis since studies combining this particular plant technology and cooling method have not been widely carried out to date and cost data is not available. Description of the Model to provide the 50 percent required to match the commercial loan. The model determines the LCOE by calculating the cash • Case 2 includes the impact of a Guarantee that flows in every project year and discounting these to the reduces the cost of private financing sources. This base year using the weighted average cost of capital results in a larger share of financing from private (WACC). The WACC is a way of estimating the project’s sources (71 percent) at lower costs, while the rest discount rate and is defined as follows: comes from MDBs at similar terms. • Case 3 combines four loan types—traditional MDB WACC = (Equity return rate x [1- Debt fraction]) financing (MDB1, 25 percent), plus additional + (After tax Average Debt rate MDB financing available at EBRD terms (MDB2, 25 x Debt fraction) percent) and private debt reduced in cost because of the guarantee from MDB1 (25 percent), and Equity financing is capped at 35 percent of total required commercial sources with no guarantees (25 percent). financing for each technology, and the expected rate of return on equity is 20 percent in all cases. The above cases are investigated to find the resulting LCOE. The first step is to apply 0 percent of With respect to the debt rate used in this study, concessional financing to all three cases—Cases 1, different combinations of the following funding 2, and 3. In the next steps, two levels of concessional 59 sources are used: (a) two types of MDB loans, financing are applied in turn—30 percent, and then (b) commercial loans, (c) cheaper commercial loans 50 percent of project financing needs—to reduce the as a result of an applied guarantee,50 and commercial debt portion in the financing package. (d) concessional loans with cheaper terms compared For all cases, the percentage increase from the LCOE to MDB loans (terms similar to Clean Technology from the reference plant (without CCS, and assuming Fund (CTF) loans). The model calculates the Internal no concessional financing) to the LCOE of the coal Rate of Return (IRR) for each funding source based plant with CCS is calculated. If the LCOE for the coal on the financial terms of each source (see Table 6.2 plant with CCS is found to be lower than the LCOE below for a summary of financial terms used). By for the reference plant (that is, the percentage change combining these funding sources, a weighted average is negative), the amount of concessional financing is debt rate can be calculated, which in turn determines reduced to the minimum necessary to equalize the the WACC. The resulting WACCs are applied to the LCOE of both plants. The dollar amount associated with model to test the impact on the LCOE from different this minimum concessional financing is also determined. financing structures with corresponding variations in financing terms. The remaining financial assumptions are given in Table E.1 in Appendix E. Assumptions Technology Assumptions Financing Assumptions The model is developed to include five generic coal The financial terms of the different funding sources are technologies as reference plants without CCS—PC, both given in Table 6.2. wet- and dry-cooled, IGCC both wet- and dry-cooled, and Oxy-fuel wet-cooled (only the wet-cool option is Table 6.2 also shows the three basic financial structures examined, since there is no experience in application that are defined and used to generate results: of dry-cooling Oxy-fuel projects as of today and cost data is not readily available). The wet- and dry-cooling • Case 1 assumes that 50 percent of the required options are assessed because in certain regions, such financing is at market terms (commercial), and the as Southern Africa, dry-cooled technologies are a rest is financed by multilateral sources. This scenario preferred option because of regional water scarcity. assumes that several MDBs are pulled together Tables E.2, E.3, and E.4 in Appendix E give the specific 50 The guarantee used in this study assumes the characteristics of the Partial Credit Guarantee (PCG) instrument of the World Bank. The PCG covers debt service defaults on a portion of a loan or a bond, allowing public sector projects to access financing with extended maturities and/or lower spreads. Table 6.2: Terms of Financing Instruments and Resulting Blended Debt Interest Rates Financial structures (as % of total debt Terms of financial instruments financing) Grace Spread over Front- Funding Maturity period U.S. LIBOR end fee source Description (years) (years) (%) (%) Case 1 Case 2 Case 3 Loan 1: MDB 1 Similar in terms to 30 5 0�48 0�25 50 29 25 IBRD loan Loan 2: MDB 2 Similar in terms to 15 3 1�50 0�00 0 0 25 EBRD loan Loan 3: Terms based on 20 10 Fixed Rate of 0�00 0 0 0 Concessional Clean Technology 0�75 Funding Fund (CTF) Commercial Based on current 15 4 4�00 0�50 50 0 25 Loan 1 spread over LIBOR of JP Morgan’s 60 Emerging Market Bond Index Global (EMBIG), plus an adjustment of 1% to account for project specific risk Commercial Similar to 15 4 2�00 0�75 0 71 25 Loan 2 (With Commercial Loan Guarantee) 1, but it has a lower spread as a consequence of the use of a guarantee Resulting blended debt rate 6�59% 5�91% 5�98% technical and cost assumptions for each of the five technologies, since different sources are used for the examined technologies. base case of a coal plant without CCS, although these costs are compared with other estimates through an The technical specifications and cost are not based extensive literature review and expert consultations, and on any particular plant. However, for the purposes of confirmed to be within the ranges of cost data reported. this report, it is important to keep cost and technical parameters close to respective estimates in developing For each of the reference plants for the five countries. Therefore, the assumptions for the reference technologies, coal plants of the same technology with coal plants without CCS are aggregated across CCS are built into the model. The assumptions for these projects and studies performed in and for developing technologies are developed by scaling the reference countries. The pulverized coal case plant and Oxy- plant data appropriately to reflect the changes in cost fuel plant (which is assumed to be the same in the no and efficiency if a CCS component is included, and CO2 capture case, since there would be no reason to again cross-checked through an extensive literature build an Oxy-fuel plant without an application such as review and expert consultation. The scaling factors are CCS) are based on estimates of a coal plant in South taken from a Global Institute of CCS Report (Global Africa (World Bank 2010b) and data for an IGCC plant CCS Institute and others 2009), and further informed developed by NETL study for India (NETL and others by expert consultation with NETL. Since the scaling 2007). It is important to recognize that caution should factors for all technologies are taken from a uniform be taken when comparing the absolute costs across source, the change in LCOE for a coal plant with CCS compared to the LCOE for a reference plant Figure 6.1: LCOE for Reference Plants without CCS, is a robust parameter to examine across without CCS and Plants with CCS for the Five technologies. Therefore, this parameter is examined for Technologies Examined all variations of cases and scenarios in this study. 16 Assumptions on the oil and methane recovery schedules, 14 and associated revenues for EOR and ECBM, respectively, 12 LCOE $/MWh are given in Table E.6 and E.7 in Appendix E. 10 8 Scenarios 6 4 Several scenarios are developed by changing the 2 following variables in the model: 0 PC wet PC dry Oxy IGCC wet IGCC dry • Coal prices: Defined as low (US$1/MMBtu), medium Technology type (US$3/MMBtu), or high (US$5/MMBtu). No CCS Partial capture (25%) Full capture (90%) • These low and high values are selected since US$1/MMBtu is of the order of the price of 61 domestic coal in South Africa, while US$5/ MMBtu is the value is the internationally traded price of coal as of March 2011.51 hydrocarbon recovery, and Case 1 financial structure • CO2 prices: Set at US$0, US$15, or US$50/ton. is assumed (50 percent MDB and 50 percent • US$15/ton is selected as a price close to the commercial finance with a blended debt interest rate carbon prices under the EU ETS and US$50/ton of 6.59 percent). Figure 6.1 shows the LCOE for all to test the impacts of much higher values, as well five technologies examined without CCS, with partial as to allow for consistency between the chapter capture CCS and full capture CCS. on climate finance of CCS and this chapter on project finance. The results show that, as expected, the LCOE is • Availability of extra revenues from EOR or ECBM lowest for a reference plant without CCS, higher with recovery. partial capture CO2 capture, and highest with full CO2 capture. For the PC and IGCC technologies, The assumptions behind each of the variables are given the dry-cooled cases have slightly higher LCOEs in Table E.5 in Appendix E. than the wet-cooled case, because of the efficiency penalty experienced in dry-cooled installations. PC Results has the highest LCOE, while the LCOE for an Oxy- fuel reference plant is in the middle, and IGCC has Given the large number of variables in this study—5 the lowest LCOE. Further, as expected, the percentage plant technologies, 3 coal prices, 3 CO2 prices, 3 increase in LCOE is less for a coal plant with partial financing structures, and 2 levels of concessional capture than full capture, since the cost of capturing finance, the resulting number of scenarios is only 25 percent of the total plant emissions is less. considerably large (1,620 scenarios are developed). Out of the total 1,620 scenarios, a selected number of In order to examine the effects of the other parameters scenarios are presented in this report, to illustrate major in this study, the cooling method should be held results and conclusions of this financial modeling study. constant, so that observed results can be understood to be the results of varying the other parameters (in the Unless stated otherwise, for all the results shown, the same way one coal price is chosen for all of the results coal price is medium (US$3/MMBtu), CCS refers presented, other than the scenario where variations to full capture (90 percent), there is no enhanced in coal prices are presented). For this reason, for the 51 For the low coal price assumed, a World Bank project appraisal document was used as a reference giving prices of domestic coal in South Africa (World Bank 2010b). For the high coal price assumed, a World Bank commodity Markets Review giving information on prices of internationally traded coal was used (World Bank 2011a). remaining results presented here, only wet-cooled prices looks similar for all technologies, but, as it is technologies are included. shown in Figure 6.3, the percentage increases in the LCOE for plants with CCS varies among the different It should be noted that, although the absolute value of technologies. the LCOE for IGCC for a reference plant without CCS is greater than the LCOE for the corresponding PC plant Figure 6.3 shows that overall, the percentage increase with CCS, the case is the opposite when CCS is included. in LCOE from a reference plant without CCS to a plant Again, caution should be used to compare across the with CCS, is greatest for PC plants, medium for Oxy-fuel technologies, since the data are taken from different plants, and the smallest for IGCC plants. The results also sources. For this reason, the remainder of the chapter show that as the coal price gets higher, the percentage focuses on the percentage increase in LCOE since the change in the LCOE decreases for the PC and Oxy values used to scale the inputs were taken from a single plants with full CO2 capture, while for the IGCC source, allowing for comparison across the technologies. technology, it increases. The reason for this is that the fuel cost contribution to the LCOE is proportional to the It should be recognized that this study compares the heat rate of the plant, and as coal prices rise, this effect LCOE of plants with CCS to reference plants of the dominates the other costs. Therefore, as the coal price same technology without CCS, but that generalizing the increases and dominates, the percentage change in the 62 study to compare coal plants across technologies (for LCOE of the reference plant without capture, to the CCS example, comparing the cost difference from pulverized plant, tends towards the percentage change in the heat coal without CCS to IGCC with CCS) would yield rate of the reference plant without capture to the heat different results. For regions where all three of the plant rate of the capture plant. For example, the heat rate for technologies are technologically feasible, comparing the reference PC coal plant is 8,652 BTU/kWh and for changes in LCOE in this way would be a worthwhile a capture plant it is 12,459 BTU/kWh. As the coal price exercise to examine the cheapest coal plant technology increases, the percentage change in LCOE from the with CCS to employ. reference plant without CCS to the plant with CCS will tend to the ratio in the heat rates, that is, 12,459/8,652 Impact of Coal Price which is 1.44—an increase of 44 percent. Therefore, the higher the coal price, the percentage change in Figure 6.2 shows the LCOE for varying coal prices for LCOE for PC plants will decrease towards 44 percent. plants with CCS with three technologies and a wet- Conversely, the percentage change in heat rate for IGCC cooling application in the case of full CO2 capture. plants is 12,135/8,989=1.35, and so the percentage The higher the coal price, unsurprisingly, the higher change in LCOE for IGCC plants will increase up to 35 the LCOE is for all three generation technologies. percent as the coal price increases. The pattern in LCOE associated with various coal Figure 6.3: Percentage Increase in LCOE from Figure 6.2: LCOE for Full Capture Coal Plants Reference Plant to Corresponding Plant with with CCS with Different Coal Prices Full Capture CCS for Different Coal Prices 20 80% 18 70% 16 60% 14 LCOE $/MWh 12 50% 10 40% 8 30% 6 20% 4 2 10% 0 0% PC Oxy IGCC PC Oxy IGCC Low Medium High Low Medium High Figure 6.4: Percentage Increase in LCOE Figure 6.5: Percentage Increase in LCOE for from Reference Plant to Plant with CCS for a Reference Plant without CCS to a Plant with Different CO2 Prices CCS and Enhanced Hydrocarbon Recovery 70% 70% 60% 60% 50% 50% LCOE $/MWh 40% 40% 30% 30% 20% 20% 10% 10% 0% 0% PC Oxy IGCC PC Oxy IGCC 0$/ton 15$/ton 50$/ton None EOR ECBM 63 Impact of CO2 Price therefore have little effect on the LCOE. For all cases, the percentage increase in LCOE from the reference Figure 6.4 shows how the increase in the LCOE from plant to the plant with CCS is approximately only 2 the reference plant to a plant with CCS varies by percent less if EOR or ECBM revenues are modeled, generation technology and carbon price. The scenarios compared to when they are not included.52 assume that the project receives additional revenues equal to the tons of CO2 stored multiplied by a given Figure E.1 in Appendix E shows the percentage change carbon price. in the LCOE level if both a CO2 price and revenues from EOR/ECBM are available. Figure 6.4 shows that the higher the carbon price, the lower the LCOE, as the project revenue streams Impact of Different Financial Structures increase as a result of the greater value of the stored carbon. The smallest percentage increase is seen for Figure 6.6 shows how the LCOE varies for the IGCC for all the CO2 prices, and the greatest increase different technologies under the three different is for PC, although the LCOE for all technologies with financing structures assumed in Cases 1, 2, and 3 (see CCS are reduced by approximately 30 percent from the Table 6.2). case where there is no carbon price to the case with a carbon price of US$50/ton. The results show that the LCOE for reference plants without CCS and corresponding plants with CCS for Impact of Enhanced Hydrocarbon Recovery the various examined technologies is very similar for all financing structures. Table 6.2 shows that the blended Figure 6.5 shows how the LCOE increases for a plant debt interest rates for the three cases range from 5.91 with CCS if EOR or ECBM is incorporated into the percent to 6.59 percent. This small change in the debt project financial model as additional revenue. The interest rate does not affect to a noticeable extent the results show that, although the revenues from EOR or absolute values of the LCOE. The difference in LCOE ECBM recovery do lower the LCOE, the overall effect across cases is less than 1 percent for all technologies. is not noticeable big. The revenues from ECBM and This demonstrates that the LCOE is hardly sensitive to EOR are very similar, and not large when compared to the small changes in the financing structure, unless revenue generated purely from selling electricity, and substantial cost reductions can be achieved, such as 52 It should be noted that the technical parameters used to estimate revenues from EOR/ECBM depend heavily on the circumstances and geology of the particular project. Since this is a generic project, only one set of assumptions was made based on literature review and expert consultation, which given in Tables E.6 and E.7 in Appendix E. If a given specific project has more favorable parameters, higher revenue streams and a more significant difference in LCOE would be observed. including concessional financing, as discussed below. Table 6.3: Blended Debt Interest Rate for Other variables investigated in this study, such as Different Levels of Concessional Financing CO2 prices or realization of revenues from enhanced hydrocarbon recovery, have a greater impact on No 30% 50% concessional concessional concessional reducing the LCOE of plants with CCS technologies financing financing financing than selecting the cheapest of the three financing structures modeled. 6�59% 4�36% 2�86% Impact of Concessional Finance two. This is because Case 1 has the largest commercial Contributions of concessional finance of 30 percent financing portion, which is proportionately replaced and then 50 percent are applied in individual scenarios by concessional financing, which is on much cheaper to see how this affects the LCOE level. Figure 6.7 terms. shows the results for the IGCC wet-cooled technology for finance structure Case 1. Of the three Cases, Case The results show that as the portion of concessional 1 is presented here as concessional financing has the finance increases, the LCOE decreases as expected, greatest impact for this case compared with the other since this lowers the blended debt interest rate 64 considerably, as shown in Table 6.3. Figure 6.6: LCOE Variations with Different Required Level of Concessional Finance for Break- Financial Structures Even LCOE 16 For several cases, concessional financing contributions 14 of less than 30 or 50 percent result in LCOEs of coal 12 LCOE $/MWh plants with CCS that are lower than the LCOE of the 10 8 corresponding reference plant. In these cases, the 6 amount of concessional financing is reduced to the 4 minimum necessary to equalize the LCOE of the plant 2 with CCS to that of the reference plant. This allows the 0 required amount of concessional financing to set the no CCS CCS no CCS CCS no CCS CCS LCOEs equal to be found. The seven bars in Figure 6.8 PC Oxy IGCC represent the cases for wet-cooled technologies where Case 1 Case 2 Case 3 it is found that the LCOE of the plant with CCS can be reduced to a point where it is equal to the reference plant, if it is partially financed with concessional funding sources that make up less than 50 percent of Figure 6.7: LCOE with Different Levels of total project costs. Figure 6.8 shows the amount of Concessional Financing for IGCC plant concessional funding required, both as a percentage of total debt financing requirements and the corresponding 14 U.S. dollar amount, to set the LCOE of the plant with 12 CCS equal to that of the reference plant. 10 The results show that, depending on the circumstances, $/MWh 8 concessional funds between US$26 million and $662 6 million could set the LCOE of a coal plant with CCS 4 equal to a reference coal plant without CCS. 2 It should be noted that all the cases show extra revenue 0 No CF No CF 30% CF 50% CF streams, all with carbon prices of US$50/ton CO2 and Full capture Partial capture No CCS most with enhanced hydrocarbon recovery as well. This is because modeling revenues from EOR/ECBM and Figure 6.8: Concessional Financing Required to Set LCOE for Plant with Full Capture Equal to Reference Plant, for Financing Structure Case 1 (Percentage of total debt financing requirements and millions of US$) 50 662 700 Percent of concessional finance required Concesional funding (US$ millsions) 45 600 40 35 500 30 400 337 25 300 20 15 155 200 142 145 10 49 100 5 26 0 0 Oxy, EOR, Oxy, ECBM, Oxy, IGCC, EOR, IGCC, ECBM, IGCC, PC, EOR, 50$/ton 50$/ton 50$/ton 50$/ton 50$/ton 50$/ton 50$/ton 65 Note: Concessional financing portion is capped at 50 percent of total debt financing requirements� carbon prices already reduces the LCOE substantially, plants require the most. This is because another factor is and so a lesser amount of concessional financing is affecting the results: the percentage increases in LCOE required to set the LCOE equal to that of the reference from the reference plant to the plant with CCS for IGCC plant. Hence, these cases emerge as the scenarios plants and Oxy-fuel plants is less than for PC plants. where it is possible to set the LCOEs equal with less than 50 percent of total debt finance requirements from As shown in Figure 6.1, the percentage difference in concessional sources. The results also show that Oxy the LCOE for a reference plant to the plant with CCS is and IGCC require the least amount of concessional smallest for IGCC, followed by Oxy-fuel and then PC. finance, followed by only one case of PC that is relevant. Given that the percentage change in LCOE is smallest for IGCC, less concessional financing is needed overall Concessional financing lowers the debt rate, to reach equality between the LCOE for reference subsequently reducing the overall cost of the project plants and the plant with CCS. There are, therefore, (that is, the WACC). Therefore, a plant technology two competing elements affecting which technologies with CCS that has a significant incremental increase in require the least amount of concessional financing capital costs compared to a plant without CCS, will be to set the LCOE of a plant with CCS equal to that of impacted by concessional financing more than a plant the reference plant: (a) a high capital cost increase without smaller capital costs increases when CCS is from a reference plant to a plant with CCS, since included. This impact can be observed for a PC plant concessional financing reduces the LCOE further than with CCS, which requires 81 percent more additional for plant technologies with low capital cost increases, capital compared to the reference plant. On the other which would suggest that the PC plant requires the hand, a reference Oxy-fuel plant with CCS has an least concessional financing, followed by Oxy-fuel incremental capital cost of 70 percent, and IGCC and then IGCC; and (b) the smaller the percentage is only 30 more with respect to its reference plant. increase in LCOE from the reference plant to the plant Therefore, concessional financing should affect the with CCS, the less concessional financing is required to percentage change in LCOE for the PC plant the most, set the two equal. IGCC technology sees the smallest followed by an Oxy-fuel plant, followed by an IGCC percentage increase in LCOE, followed by Oxy-fuel, plant, since the increase in capital costs is the greatest. and then PC. For both of these competing elements, Figure 6.8, however, shows that Oxy-fuel plants require Oxy-fuel is the technology in the middle of the extremes the least amount of concessional funding, while PC felt by IGCC and PC. The resulting observation is that Oxy-fuel, as the financing between 2 percent and 31 percent would technology in the middle of these competing aspects, be sufficient to set the LCOE equal between the requires the least amount of concessional financing. options “without� and “with� CCS. Such scenarios are Since the results in Figure 6.8 show that the IGCC observed for Oxy-fuel and IGCC technologies, and cases require less concessional financing than the PC there are no instances in the Case 3 financial structure. case, the smaller percentage increase in LCOE from the As mentioned above, the reason for this is that Case 1, reference plant to the plant with CCS for IGCC of the which is 50 percent MDB and 50 percent commercial three technologies outweighs the effect of concessional funding, has the largest amount of commercial financing reducing the LCOE in high incremental capital finance, which is reduced when concessional finance cost technologies, such as PC. displaces it. Therefore, every percent of concessional finance added in Case 1 makes more of an impact The results also show that there are four scenarios than in the other two cases. in the Case 2 financial structure where concessional 66 APPENDIX APPENDIX A: INTERNATIONAL ORGANIZATIONS INVOLVED IN CCS WORK Organization CCS related work Global Carbon Capture and Storage The Global CCS Institute is based in Australia and is positioning itself as the Institute global broker of information relevant to CCS, and supporting knowledge sharing as a tool to facilitate technology diffusion, drive cost reduction, accelerate innovation, and improve public awareness� Carbon Sequestration Leadership CSLF is a ministry-level international climate change initiative whose mission Forum (CSLF) is to further promote the development and deployment of CCS technologies via shared efforts that address key technical, economic, and environmental obstacles� IEA Greenhouse Gas R&D Programme IEAGHG studies and evaluates technologies that can reduce GHG emissions (IEAGHG) from fossil fuels� It aims to evaluate CCS technologies, facilitate the implementation of CCS options, disseminate the data and results from the evaluation studies, and help facilitate international collaborative R&D and demonstration activities� 68 International Energy Agency (IEA) CCS The IEA, in association with the IEAGHG, University College London’s Carbon Regulators Network Capture Legal Programme, and the CSLF, has created the CCS Regulators Network to provide policy makers with opportunities to interact with peers in an objective, neutral forum to aid in the drafting of CCS policies� World Bank Group CCS Trust Fund The World Bank Group CCS Trust Fund was established in 2009, and is currently capitalized at US$11 million, supported by the Global CCS Institute and the Government of Norway� The Trust Fund supports capacity Building activities in several developing countries, and the production of this report� Asian Development Bank (ADB) In July 2009, the ADB announced the establishment of the CCS Trust Fund, capitalized at AUS$21�5 million from a contribution of the Global CCS Institute� The Trust Fund will provide grant financing for CCS components in investment projects (including inject well engineering and capture equipment), along with technical assistance, policy support, and other capacity building activities in the ADB’s developing member countries� The Zero Emissions Platform (ZEP) ZEP is a broad coalition of stakeholders with the main goal of making CCS technology commercially viable by 2020 via a European Union–backed demonstration program, and to accelerate R&D into next-generation CCS technology and its wide deployment post-2020� World Resources Institute (WRI) WRI’s CCS project works with policymakers and the private sector to develop solutions to the policy, regulatory, investment, environmental, and social challenges associated with CCS demonstration and deployment� Clinton Climate Initiative—Clinton The goal of the Clinton Climate Initiative is to create projects that enable Foundation governments to anticipate and resolve CCS related critical issues, and allow government partners to be “capture ready,� that is, to implement commercial CCS program swiftly and effectively when the market is ready� Co-operation Action within CCS China- COACH aims at establishing broad cooperation between China and the EU (COACH) European Union in the field of CCS by exploring coal gasification for appropriate poly-generation schemes with CCS, identifying CO2 geological storage in China, and exploring regulatory and public issues related to CCS� Asia Pacific Economic Cooperation The EGCFE is one of five Expert Groups that were established by, and report (APEC) Expert Group on Clean Fossil directly to, the Energy Working Group (EWG)� The EWG is one of 10 such Energy groups that implement the Action Agenda of the Asia Pacific Economic Cooperation (APEC)� The EGCFE’s mission is to encourage the use of clean fuels and energy technologies that will both contribute to sound economic performance and achieve high environmental standards� APPENDIX B: TECHNO-ECONOMIC Modeling CCS Technology ASSESSMENT OF CCS DEPLOYMENT IN THE POWER SECTOR IN SOUTHERN AFRICA AND CCS is included in the model as a generic capture THE BALKANS technology, both for coal and gas plants, rather than specifying post-combustion or pre-combustion capture. The Model This is because the differences in costs between different capture technologies are minimal in comparison to the Using a techno-economic optimization model is a differences in cost between alternative energy options. suitable method for exploring the effects of policies Both new builds and retrofits, which are considered as on CCS deployment. Such models have been used to having 40 percent greater in investment costs than new model the power sector for decades, since it is possible build CCS plants, are included in the model. to examine how well particular technologies compete against other energy technologies that are available, Storage Options allowing the cheapest alternative to be selected. For all costs occurring at later points in time, the present value Potential storage sites for each of the regions were is calculated by discounting them to the base year of researched to give an inventory of potential CO2 the case study, and it is this sum of the discounted reservoirs. Table B.1 shows the references used for this costs that is used to find the optimal solution. Unless research. 69 forced by the model user, the methodology does not require any arbitrary fixing of a trajectory for a Certain assumptions were necessary to estimate the power plant with CCS or any other energy technology, costs of developing each storage site, since for many and selects among potential new installations and of them their full capacity is not defined with certainty. dispatching of new and existing installations as defined Since the injectivity of a well is a parameter that is by the model user, to find the economically optimal lacking in most of the identified storage options—and electricity portfolio. this parameter determines the amount of wells needed for a storage project of a certain size—the total drilling The choice of the discount factor is an important issue, costs per site can be calculated as an order of cost since it determines the balancing between capital whereby the number of wells is defined based on an costs (predominantly investment) and operating cost assumed injectivity. The relative storage cost expressed (predominantly fuel). Since the operational lifetime as US$/ton CO2 is influenced mainly by the size of the extends over a long period, discounting has more storage project (total volume stored). effect on the variable costs, and the higher the discount rate, the less weight is given to the variable cost as Since the size of individual structures is also an the model solves to determine the costs of each of the unknown, an estimate was included in the inventory energy technology options. The choice of discount rate using a realistic size distribution of storage sites based is a subjective decision that takes into account opinions on a statistical analysis of existing data. Subsequently, on intergenerational equity and financial valuation, and generic cost curves for each of the storage options with is beyond the scope of this report. For the purposes of a price per ton as a function of the volume that can this study, a discount rate of 8 percent—as a midway be stored were calculated for each of the storage types between a social discount rate and rate more akin to involving specific costs and conditions. By combining private sector investments—is used. The same scenarios these cost curves with the (expected) size of a project could be tested with a different discount rate and (that is, the position on the cost curve), a reasonable compared if so desired. cost per ton was deduced for each of the storage options. A set of individual countries is modeled for each region as separate systems, and connections between Assumptions in the Model for Southern Africa regions are set at a multiregional level to allow for trade between counties, which allows for a regional The following tables detail the assumptions used in the analysis. model to represent the Southern African region. Table B.1: References Used to Develop CO2 Storage Estimates in the Model References for research on potential storage sites References for research on potential storage sites in Southern African region in the Balkan region • Atlas on Geological Storage of Carbon Dioxide in South • Andricevic, R�, H� Gotovac, M� Loncar, and V� Srzic, Africa, Council of Geoscience, 2010, 51p + appendix� “Risk Assessment from Oil Waste Disposal in Deep • Clough, L� D�, 2008� “Energy Profile of Southern Wells�� Risk Conference, Cephalonia, Greece, May 5–7, Africa�� In Encyclopedia of Earth, C� J� Cleveland (ed�), 2008� National Council for Science and the Environment� • Cokorilo, V�, N� Lilic, J� Purga, V� Milisavljevic, “Oil Shale • De Koninck, H�, T� Mikunda, B� Cuamba, R� Schultz, Potential in Serbia,� Oil Shale 26(4), pp 451–62, 2009� and P Zhou, 2010� CCS in Southern Africa—An � • Dimitrovic, D�, “Current Status of CO2 Injection Projects Assessment of the Rationale, Possibilities and Capacity in Croatia�� In CO2GeoNet, CO2NET EAST Regional Needs to Enable CO2 Capture and Storage in Botswana, Workshop for CEE and EE Countries—CCS Response to Mozambique and Namibia. ECN Report ECN-E—10- Climate Changes� Zagreb, February 2007� 065� • Dubljevic, V�, “Oil and Gas in Montenegro�� • Engelbrecht, A�, A� Golding, S� Hietkamp, and B� Government of Montenegro, Ministry for Economic Scholes, 2004� “The Potential for Sequestration of Development, 2008� http://www�minekon�gov�me/en/ Carbon Dioxide in South Africa�� CSIR Report 86DD/ library/document HT339, 54pp� • “Energy Strategy and Policy of Kosovo,� white paper� EU • Gale, J� J�, 2004� “Using Coal Seams for CO2 Pillar, PISG-Energy Office: Lignite Mining Development Sequestration�� Geologica Belgica 7, 99–103� Strategy� 70 • Ercegovac, M�, D� Zivotic, and A� Kostic, “Genetic- • Jeffrey, L� S�, 2005� “Characterization of the Coal Resources of South Africa�� Journal of the South African Industrial Classification of Brown Coals in Serbia�� Int. Institute of Mining and Metallurgy, February 2005, J. of Coal Geol. 68, 2006� 95–102� • “EU GeoCapacity� Assessing European Capacity for • Mabote, A�, 2010� “Overview of the Upstream Geological Storage of Carbon Dioxide�� FP6 report, Petroleum Sector of Mozambique,� UK—Mozambique D16� WP2 Report Storage Capacity, 2006� Investment Forum 2010� London, Dec 2, 2010� • Hatziyannis, G�, “Review of CO2 Storage Capacity of • Mbede, E� I�, 1991� “The Sedimentary Basins of Greece, Albania and FYROM�� EU GeoCapacity final Tanzania—Reviewed�� Journal of African Earth Sciences conference, Copenhagen, 2009� (and the Middle East) 13, 291–97� • Hatziyannis, G�, G� Falus, G� Georgiev, and C� Sava, • Nkala, 2008� “Energy Firm Probes Coalbed Methane “Assessing Capacity for Geological Storage of Carbon Prospects in Botswana, Zimbabwe�� Engineering News Dioxide in Central—East Group of Countries (EU Magazine 24/08/2008, Exploration and Development GeoCapacity project)�� Energy Procedia, 2009� section� http://www�engineeringnews�co�za/article/ • Komatina-Petrovic, S�, “Geology of Serbia and energy-firm-probes-coalbed-methane-prospects-in- Potential Localities for Geological Storage of CO2�� botswana-zimbabwe-2008-10-24 In CO2GeoNet, CO2NET EAST Regional Workshop • Petroleum Agency SA, 2008� “Petroleum Exploration— for CEE and EE Countries—CCS Response to Climate Information and Opportunities 2008�� Brochure� Changes� Zagreb, February 2007� • Schalwyck, H� J�-M�, 2005� “Assessment Controls on • Kucharic, L�, “CO2 Storage Opportunities in the Reservoir Performance and the Effects of Granulation Selected New Member States and Candidate States Seam Mechanics in the Bredasdorp Basin, South of EU (on the basis of CASTOR, WP1�2 results)�� In Africa�� Master’s thesis, University of the Western CO2GeoNet, CO2NET EAST Regional Workshop for Cape, Dept� of Earth Sciences, 161pp� CEE and EE Countries—CCS Response to Climate • Swart, 2010� “Geological Sequestration of CO2 Changes� Zagreb, February 2007� in Namibia�� Workshop Presentation CCS-Africa, • Marko D�, and A� Moci, “Oil Production History in Windhoek 15/04/2010� Albania Oil Fields and Their Perspective,� Technological • Van der Spuy, D�, 2010� “Natural Gas—An Update on institute for Oil and Gas, 6th UNITAR Conference on South Africa’s Potential�� SANEA, Cape Town 21 July Heavy Crude and Tar Sands, 1995� 2010� Presentation with notes� • Workshop for New Energy Policies in Southeast • Viljoen, J� H� A�, F D� J� Stapelberg, and M� Cloete, � Europe—The Foundation for Market Reform� Coalmines 2010� “Technical Report on the Geological Storage in Serbia and Montenegro� of Carbon Dioxide in South Africa�� Council for Geoscience, 237pp� Table B.2: Fuel Price Assumptions for Southern African Region Fuel US$/GJ Price Diesel—imported 27�0 Natural gas—domestic 8�8 Natural gas—imported 10�8 Coal—domestic 2�0 Nuclear fuel 0�8 Table B.3: Generic Energy Technology Options Available in the Region and Associated Model Input Parameters for the Southern African Region Variable Available/ Capital cost1 Fixed O&M O&M Efficiency capacity 71 Plant description Fuel type (US$/kW) (US$/kW) (US$/MWh) (%) factor (%) OCGT liquid fuels Diesel 547 9�5 0�0 30 89 Combined cycle gas Gas/LNG 842 20�0 0�0 48 90 Supercritical coal Coal 2,746 61�5 6�0 37 2 85 PWR nuclear3 Nuclear fuel 6,412 0�0 12�9 33 85 Biomass4 Renewable 4,496 131�4 4�2 25 85 Bulk wind 5 Renewable 2,000 35�9 0�0 NA 29 Solar thermal central Renewable 5,207 81�5 0�0 NA 41 receiver Solar PV (bulk) Renewable 3,896 67�8 0�0 NA 20 CCGT with CCS Gas 1,314 25�4 0�0 39 89 Supercritical coal with Coal 4,046 71�8 6�6 306 85 CCS NA� Not applicable� 1 PV costs are based on South Africa DOE (2011), and costs are expressed in 2010 U�S� dollars using ZAR 7�4 to the dollar, and including interest during construction at 8 percent� 2 All coal plants are assumed to be air-cooled, which explains the lower efficiency� 3 The option is only available in South Africa� The costs have incorporated the 40 percent increase that was implemented at the late stage of the 2011 IRP process� 4 Option only available in South Africa and Mozambique� 5 Option only available in South Africa and Namibia� 6 All coal plants are assumed to be air-cooled, which explains the lower efficiency� Table B.4: South Africa DOE 2011 IRP “Revised Balance� Expansion Plan New build options(MW) Coal (PF, FBC, Import Solar Nuclear Imports) Gas CCGT OCGT Hydro Wind PV Solar CSP Fleet 2010 0 0 0 0 0 0 0 0 2011 0 0 0 0 0 0 0 0 2012 0 0 0 0 0 300 0 0 2013 0 0 0 0 0 300 0 0 2014 500 0 0 0 400 300 0 0 2015 500 0 0 0 400 300 0 0 2016 0 0 0 0 400 300 100 0 2017 0 0 0 0 400 300 100 0 2018 0 0 0 0 400 300 100 0 72 2019 250 0 0 0 400 300 100 0 2020 250 237 0 0 400 300 100 0 2021 250 237 0 0 400 300 100 0 2022 250 237 805 1 143 400 300 100 0 2023 250 0 805 1 183 400 300 100 1,600 2024 250 0 0 283 800 300 100 1,600 2025 250 0 805 0 1,600 1,000 100 1,600 2026 1,000 0 0 0 400 500 0 1,600 2027 250 0 0 0 1,600 500 0 0 2028 1,000 474 690 0 0 500 0 1,600 2029 250 237 805 0 0 1,000 0 1,600 2030 1,000 948 0 0 0 1,000 0 0 Table B.5: CO2 Storage Options, Volumes, and Costs for Southern Africa Storage cost Storage cost Capacity (USD/ton) (USD/ton) with Start Country Site name Location (Gton) No EOR/ECBM EOR/ECBM1 year South Africa Zululand Mesozoic On-shore East 0�46 15�00 15�00 2025 Basin Coast Mesozoic Algoa and On-shore 0�4 11�25 11�25 2025 Gamtoos Basin South Coast Mesozoic Outeniqua Off-shore 48 11�25 11�25 2025 Basin South Coast Mesozoic Durban Off-shore East 42 11�25 11�25 2025 Basin Coast Depleted oil and gas Off-shore 0�077 9�38 –30�63 2020 fields South Coast Botswana Coal fields South 3�78 6�45 6�45 2020 Mozambique Coal fields Inland South 6 10�20 10�20 2025 73 Depleted gas fields Off-shore 0�1 11�25 –28�75 2029 South Depleted oil and gas Off-shore 0�129 13�13 –26�88 2029 fields South 1 Assuming US$40/ton benefit for EOR and US$4�8/ton benefit for ECBM� Table B.6: CO2 Transport Options for the Southern African Region Transport Transport Approx. distance Unit transport cost Transport cost Country source sink (km) (USD/tonCO2/100km) (USD/tonCO2) South Africa Coal plant in East coast 800 1�00 8�00 coal fields Coal plant in South coast 1,400 1�00 14�00 coal fields Coal plant in Botswana coal 100 1�00 1�00 coal fields fields East coast East coast 100 1�00 1�00 South coast South coast 100 1�00 1�00 Botswana Coal plant in Coal fields 100 1�00 1�00 coal fields Mozambique Coal plant in Coal fields 100 1�00 1�00 coal fields Coal plant in Gas fields 400 1�00 4�00 coal fields Gas plant in Gas fields 100 1�00 1�00 gas fields Namibia Coal plant in Gas fields 600 1�00 6�00 coal fields Scenario Assumptions • Electricity from intermittent renewable can take up to a maximum of 30 percent of total electricity A number of general assumptions apply to all scenarios generated. for modeling the Southern African region. The main • Fuel prices are given in Table B.2, and are assumed general assumptions are as follows: to be constant over the modeling horizon. • Generic energy technology options available in the • The period modeled runs from 2010 to 2030. region and their associated model input parameters • All costs are in constant 2010 U.S. dollars. are given in Table B.3. • The overall real discount rate is 8 percent. • The identified storage options and their associated • Coal is available in all regions. costs are given in Table B.5. • Gas is available as needed. • The nuclear option is only available in South Africa. Assumptions in the Model for the Balkan • The wind option is only available in South Africa and Region Namibia. • The biomass option is only available in South Africa The following tables detail the assumptions used in the and Mozambique. model to represent the Balkan region. • Electricity imports by individual countries are 74 constrained to 15 percent by 2020. Table B.7: Comparison of Results across Scenarios for Southern African Region Scenarios US$25/ US$50/ US$100/ Baseline ton with ton with ton with with EOR/ EOR/ EOR/ EOR/ Unit of ECBM ECBM ECBM ECBM Indicator measure Reference Baseline benefits benefits benefits benefits Total system cost Billion US$ 294 305 305 325 353 375 Percentage % NA 4 4 11 20 28 difference from Reference Scenario Average US$/MWh 53 68 68 77 93 114 generation costs in 2030 CCS share in total % 0 2 2 10 12 16 generation in 2030 Cumulative CO2 Mton 6,418 5,717 5,714 5,790 5,660 4,922 emissions by 2030 Total CO2 stored Mton 0 19 23 162 177 283 by 2030 Total new GW 45 57 57 51 53 70 installations by 2030 Total installed GW 80 92 92 86 88 106 capacity by 2030 Total Investment Billion US$ 87 177 177 134 147 261 in new plants— without CCS retrofit NA – Not Applicable Table B.8: Fuel Prices Used in Simulation for the Balkan Region Fuel Unit of measure Price US$/GJ price*** Fuel oil US$/ton 438 10�6 Natural gas US cents/m 3 34�6 9�9 Coal—imported US$/ton 60�0 2�4 Coal—domestic* US$/ton 21�6 2�5 Nuclear fuel** US$/MWh 10�5 1�0 *Average price for most of the local coals� Only Kosovo has price at US$1�4/GJ� **Expressed per unit of produced electricity� ***All prices per unit of input fuel� 75 76 Table B.9: Generic Energy Technology Options Available in the Region and Associated Model Input Parameters for the Balkan Region Capacity Efficiency Availability Investment cost Variable cost Fixed cost Earliest Max. installed Plant Fuel (MW) ratio ratio (US$/kW) (US$/MWh) (US$/kW/yr) available (year) (MW) Coal with CCS Coal 500 0�38 0�85 3,211 4�6 48�2 2020 NA CCS CCGT Gas 300 0�47 0�85 1,611 2�8 27�7 2020 NA Coal Coal 500 0�45 0�85 2,094 4�2 41�9 2016 NA CCGT Gas 300 0�55 0�85 1,033 2�2 21�8 2015 NA OCGT Gas 100 0�37 0�90 531 2�8 30�2 2015 NA Nuclear Nuclear 1,000 0�33 0�92 4,189 7�0 27�9 2025 NA Albania SHPP Hydro — — 0�35 2,443 — 14�0 2015 100 Hydro Hydro — — 0�424 2,737 — 14�0 2015 1,000 Wind Wind — — 0�254 2,094 — — 2015 1,300 Bosnia and Herzegovina Ugljevik 2 Coal 400 0�42 0�85 2,094 3�2 27�9 2018 NA Gacko 2 Coal 2x300 0�4 0�85 1,885 3�2 27�9 2018 NA Stanari Coal 300 0�38 0�85 2,094 3�2 27�9 2015 NA Bugojno Coal 2x300 0�42 0�85 2,234 3�2 27�9 2018 NA Kongora Coal 2x250 0�38 0�85 2,304 3�2 27�9 2019 NA Tuzla Coal 3x400 0�45 0�85 2,094 3�2 27�9 2018 NA Kakanj Coal 400 0�45 0�85 2,094 3�2 27�9 2018 NA CCGT Gas 150 0�50 0�85 1,257 4�0 20�9 2018 450 SHPP Hydro — — 0�387 2,415 — 14�0 2015 280 Wind Wind — — 0�25 2,094 — 2013 1,200 Croatia HPP Hydro 2,500 — 0�48 3,491 — 14�0 2015 300 Wind Wind 1,500 — 0�25 2,094 — — before 2015 1,200 (continued on next page) Table B.9: Generic Energy Technology Options Available in the Region and Associated Model Input Parameters for the Balkan Region Table B.9: (continued) Generic Energy Technology Options Available in the Region and Associated Model Input Parameters for the Balkan Region Capacity Efficiency Availability Investment cost Variable cost Fixed cost Earliest Max. installed Plant Fuel (MW) ratio ratio (US$/kW) (US$/MWh) (US$/kW/yr) available (year) (MW) Kosovo Zhur Hydro 292 — 0�157 1,107 — 14�0 2016 NA Coal Coal 500 0�46 0�85 2,094 4�8 27�9 2015 2000 Macedonia Coal Coal 300 0�40 0�85 1,536 6�6 27�9 2018 NA PSP Cebren Hydro 333 — 0�288 1,419 — 14�0 2017 NA HPP Hydro — — 0�373 2,737 — 14�0 2015 600 Wind Wind — — 0�25 2,094 — — 2015 600 Montenegro Komarnica Hydro 160 — 0�17 1,170 — 41�9 2018 NA Moraca Hydro 238 — 0�33 2,928 — 14�0 2016 NA Wind Wind 120 — 0�25 2,094 — — 2015 NA Pljevlja Coal 210 0�38 0�85 1,724 6�6 50�3 2015 NA Berane Coal 100 0�36 0�85 2,482 6�6 67�0 2016 NA Serbia Kolubara B coal 2x350 0�37 0�85 1,096 3�2 55�8 2015 NA TENT B3 coal 700 0�42 0�85 1,731 3�2 55�8 2016 NA SHPP hydro — — 0�30 2,792 — 14�0 2015 500 Wind wind — — 0�25 2,094 — — 2015 1,300 NA – Not Applicable 77 Table B.10: CO2 Storage Options, Volumes, and Costs for Balkan Region Storage type Storage volume Jurisdiction Category Oil or gas field Saline aquifer Salt dome total Albania Storage volume (Mton CO2) 111 No data 20 131 Storage cost (US$/ton CO2) 7�5 NA 10 Transport cost (US$/ton CO2) 4�0 Bosnia and Storage volume (Mton CO2) No data 197 No data 197 Herzegovina Storage cost (US$/ton CO2) n�a� 7�5 NA Transport cost (US$/ton CO2) 2�5 Croatia Storage volume (Mton CO2) 148�5 351 No data 499�5 Storage cost (US$/ton CO2) 7�5 7�5 NA Transport cost (US$/ton CO2) 4�8 78 Kosovo Storage volume (Mton CO2) No data No data No data 0 Storage cost (US$/ton CO2) 10�0 Transport cost (US$/ton CO2) 4�8 Macedonia Storage volume (Mton CO2) No data 390 No data 390 Storage cost (US$/ton CO2) n�a� 7�5 NA Transport cost (US$/ton CO2) 3�0 Montenegro Storage volume (Mton CO2) No data No data No data 0 Storage cost (US$/ton CO2) 10 Transport cost (US$/ton CO2) 7�6 Serbia Storage volume (Mton CO2) No data No data No data 0 Storage cost (US$/ton CO2) 10�0 Transport cost (US$/ton CO2) 5�0 Region-wide Storage volume (Mton CO2) 259�5 938 20 1,217�5 NA – Not applicable Scenario Assumptions • Nuclear power: Several jurisdictions are considering development of nuclear power plants although it is A number of general assumptions apply to all scenarios not certain whether these will be built out or not. for modeling the Balkan region. The main general Nuclear power is therefore modeled as a technology assumptions for the Balkan region are as follows: option in some scenarios after 2025 (the assumption is based on the idea that at least 15 years is needed • The planning horizon covers the period from 2015 to move towards an environment where nuclear until 2030 (it is assumed that no new builds would power plants can be constructed). Nuclear power, take place before 2015, and so a base year in when available, could be constructed in Albania, 2015 rather than 2010 is thought sufficient). Croatia, and Macedonia. Specific investment • All costs are presented in U.S. dollars. costs in nuclear are assumed to be US$4,190/kW • A uniform discount rate of 8 percent is used across (3,000/kW). Scenarios without the nuclear option the region. are also developed, to reflect the uncertainty over Simulations are based on a purely competitive future nuclear power plant construction. market, meaning that local plants can compete • Availability of natural gas: Natural gas for electricity for supply with surrounding systems (price on generation is available in Croatia, Macedonia, surrounding markets is fixed in advance and sales and Serbia from the base year, while in other to external market permitted in line with available jurisdictions, gas is assumed to become available interconnection capacities). after 2020. • For countries with an undeveloped coal mining CO2 Price Scenarios for the Balkan Region industry (because of low-quality coal locations or low reserves), the import of coal is assumed (that is, for Croatia and Albania, which have direct access to the sea). Table B.11: Descriptions of CO2 Price • Interconnection transmission capacities between Scenarios in the Balkan Region regions are modeled, taking into account net CO2 price scenario Profile of CO2 price Scenario transfer capacity (NTC). NTC values were estimated US$25/ton CO2 Gradual increase from zero in based on Entso-e historical data (Entso-e 2011). 2015 to US$25/ton CO2 in 2020 • A gradual decrease of imports outside of the region and constant beyond is assumed, meaning that the region gradually US$25/ton CO2 Same as above 79 becomes independent in terms of electricity supply without nuclear (a transition period of 10 years starting from 2015 is US$50/ton CO2 Gradual increase from zero in assumed in order to reach practically zero electricity without nuclear 2015 to US$50/ton CO2 in 2020 imports). Trade between jurisdictions in the region is and constant beyond limited only by the capacity of interconnectors. US$100/ton CO2 Gradual increase from zero in • External market electricity price is fixed at US$84/ without nuclear 2015 to US$100/ton CO2 in MWh (that is, €60/MWh) for all scenarios. 2025 and constant beyond Table B.12: Comparison of Results across Scenarios for the Balkan Region Scenarios CO2 Price Scenarios US$100/ US$25/ US$25/ton US$50/ton ton CCS ton with without without without deployment Reference nuclear nuclear nuclear nuclear target Indicator Unit Reference with EOR available available available available scenario Total system Billion 32 32 42 42 51 53 33 cost US$ Percentage % NA 0 30 30 57 66 1�5 difference from Reference Scenario Average US$/ 50 54 60 62 73 78 53 80 generation MWh cost in 2030 CCS share % 0 13 0 0 10 70 7 in total generation in 2030 Cumulative Mton 1,355 1,340 1,182 1,201 1,050 517 1,318 CO2 emissions by 2030 Total CO2 Mton 0 97 0 0 63 652 43 stored by 2030 Total new GW 16 18 15 16 20 19 16 installations by 2030 Total installed GW 27 29 26 27 31 31 27 capacity by 2030 Total Billion 32 41 27 28 28 39 34 investment in US$ new plants— without CCS retrofit NA – Not Applicable APPENDIX C: ASSESSMENT OF LEGAL AND REGULATORY FRAMEWORKS APPLICABLE TO POTENTIAL CCS DEPLOYMENT IN SOUTHERN AFRICA AND THE BALKANS The tables below summarize the findings of the assessment of legal and regulatory frameworks in Southern Africa and the Balkans. Table C.1: Summary of Legal Obligations of the Reviewed Countries under Relevant International Conventions Status of ratification/accession International South Bosnia and conventions Botswana Mozambique Africa Herzegovina Kosovo Serbia UNFCCC Non–Annex I Non–Annex I Non–Annex I Non–Annex I Not a party Non–Annex I 81 Kyoto Protocol Party Party Party Non–Annex B Not a party Non–Annex B Party Party UNCLOS Not a party Party Party Party Not a party Party London Convention Not a party Not a party Party Not a party Not a party Party London Protocol Not a party Not a party Party Not a party Not a party Not a party Basel Convention Party Party Party Party Not a party Party Table C.2: Summary of the EU CCS Directive EU CCS Directive Directive 85/337/EEC on environmental Amends the EIA Directive to include CCS transport pipelines, storage sites, impact assessment (EIA) and capture installations� Directive 2001/80/EC on large combustion • Amends the LCP Directive by requiring Member States to assess plants (LCP) whether suitable storage sites are available and transport facilities are technically and economically feasible, and whether it is technically and economically feasible to retrofit for CO2 capture� • Introduces the requirements of “carbon capture readiness� (CCR) in relation to new-build electricity generating power stations with related capacity of 300 MW or more� Directive 2008/1/EC concerning integrated Amends the IPPC Directive to include within its scope the capture of CO2 pollution prevention and control (IPPC) by CCS installations� Directive 2000/60/EC establishing a Amended to allow Member States to authorize the injection of CO2 framework for the Community action in the streams into geological formations for storage purposes� field of water (Water Framework Directive) Directive 2006/12/EC on waste (Waste Amends Directive 2006/12/EC so that CO2 captured and transported for the Framework Directive) purposes of CCS is excluded for the scope of the Waste Framework Directive� Regulation 1013/2006 on shipments of Amended to exclude from its scope shipments of CO2 for the purposes of waste CCS� Directive 2004/35/EC on environmental Amends Directive 2004/35/EC extending it to cover CCS storage� liability Key Findings and Recommendations and the proponents of CCS interventions are advised to revisit the assumptions and conclusions included herein This section provides a summary of key findings on at the time of the interventions. the eight issues analyzed in six countries (Botswana, Mozambique, and South Africa for the Southern African Key Findings and Recommendations at the region and Bosnia and Herzegovina, Kosovo, and Domestic Level—Southern African Region Serbia for the Balkan region),53 and recommendations for the adoption of national and regional regulatory While none of the three countries in the Southern frameworks that may be applicable to CCS activities. African region has adopted a CCS-specific legal The recommendations are based on a high-level instrument, all three countries appear to have the analysis of relevant international and multilateral treaties basic elements that touch on certain aspects of and laws in the six countries. It must be noted that laws the eight issues. Table C.3 summarizes the key in this field are continually evolving at the national, findings for each of the three countries and sets regional, and international levels. Therefore, the forth recommendations that may be adopted at the analyses of laws and the recommendations should be domestic level necessary for an effective regional considered accurate as of the time of writing this report, framework on CCS. 82 Table C.3: Key Findings for Botswana, Mozambique, and South Africa Key findings 8 key issues Botswana Mozambique South Africa Recommendations Classification May be prescribed as: Possibly regarded as Potentially classified as The applicable legal of CO2 “noxious or offensive “hazardous waste� a “waste� (NEM: WA) instrument should gas� (Atmospheric (RWM 2006)� Class 2 dangerous specifically define CO2 Pollution Prevention good (division 2�2), in the context of CCS Act), which is a gas that activities� “waste,� or “hazardous is nonflammable waste� (Waste and nontoxic, and is Management Act)� either an asphyxiant or oxidizing (SANS 10228)� Jurisdiction The governing laws on Petroleum Operations The Gas Act regulates Clearly specify the over the the jurisdiction of the Regulations include gas transmission, jurisdiction, role, pipelines and pipeline and reservoirs provisions on oil and storage, distribution, and responsibilities reservoirs may be dependent gas pipeline systems liquefaction, and of relevant players on the location of the and establishes rules regasification facilities for the authorization pipeline, wherein it generally governing for specified gases� and operation of CCS may be governed by the operation of such General duty of care pipelines and reservoirs� different land acts� For pipeline systems� (NEMA) and NEM: a pipeline, a servitude ICMA extends this duty (real rights) may need MICOA has jurisdiction of care to the coastal to be created over over the control and environment� the area in which the management of The National Heritage pipeline is built and the domestic transportation Resources Act stipulates powers to grant such and storage sites that any person who real rights are vested in of waste� However, intends to undertake different entities (State the legislation is not a development Land Act, Water Act)� clear as to the use of categorized as “the pipelines as a means construction of a … of transporting waste pipeline� must notify (RWM 2006)� the responsible heritage resources authority� (continued on next page) 53 The analysis for the Balkan region also examined the issue of financial assurance for long-term stewardship. Table C.3: Key Findings for Botswana, Mozambique, and South Africa (continued) Key findings 8 key issues Botswana Mozambique South Africa Recommendations Proprietary Generally, if a project Property rights over Coastal public property The proprietary rights to rights to CO2 is deemed to be of CCS storage sites vests in the citizens of the land on which the CCS sites and benefit to Botswana, and facilities would the republic, held in facilities are sited and facilities land is allocated to the belong to the owners trust by the state on built must be clearly project holders by the of works� Because behalf of the citizens defined in the relevant responsible minister� the property right (NEM: ICMA)� legal instrument� The land so allocated would also cover the The owner of the remains state land content in the storage soil is also owner of and the user shall be sites or facilities, the the subsoil and the granted a lease for a property right over CO2 elements comprising defined period� itself would belong the subsoil (common to the owner of the law)� pipeline as well, unless otherwise stipulated by law or contract� Regulatory WMA regulates the RWM regulates NEM: WA regulates CCS-specific standards 83 schemes trans-boundary hazardous waste and wastes and places a should be developed, related to movement of waste, waste, as well as its general duty of care on and existing laws may management as well as duty of care disposal, recovery, persons transporting be adapted to apply of storage relating to a person recycling, and transport, waste� GN 718 lists specifically to CCS and who produces, carries, and requires relevant waste management activities to prevent transportation treats, keeps, or licenses for conducting activities that require potential environmental facilities disposes of controlled such activities� a waste management pollution and waste� REQSEE prohibits the license� degradation� The Water Act requires storage of harmful NWA lists the water water right to divert, substances in the soil; uses for which dam, store, abstract, requires emission authorization is use, or discharge any or discharge sites required� effluent into public to be approved for NEM: AQA provides water from such source� environmental licensing for the establishment The Waterworks Act to prevent water of ambient air quality specifies that it is an pollution, and regulates standards� AEL is offense for any person air pollutants� required to carry on that pollutes or causes Regulation on “listed activities�� pollution to water, or Prevention of Pollution In the event that the allows foul liquid, gas, and Protection of CO2 is stored within the or other noxious matter Marine and Coastal coastal public property, to enter into the water� Environment (RPPPMCE) a coastal lease will be APA aims to prevent air establishes the required (NEM: ICMA)� pollution� legal regime for the The Occupational The Petroleum prevention and control Health and Safety Act (Exploration and of marine pollution� No� 85 of 1993(OHSA) Production) Act requires Regulation on Technical imposes health and licenses for specific Safety and Health at safety obligations� activities� Geological-Mining MPRDA governs mining Activities (RTSHGMA) activities� contains provisions related to the protection of workers against exposure to CO2� Mining Law (ML) and Regulation on Mining Law (RML) regulates mining activities and licenses� (continued on next page) Table C.3: Key Findings for Botswana, Mozambique, and South Africa (continued) Key findings 8 key issues Botswana Mozambique South Africa Recommendations Long-term The EIA Act requires ELI provides for general NEMA imposes a duty Further clarify management a responsible person environmental liability of care� In terms of the liabilities and and liabilities for the negative and establishes the emergency incidents, responsibilities in environmental impact duty to indemnify NEMA requires that a emergency situations or to rehabilitate the the injured parties, responsible person or, after accidental releases� environment affected� regardless of fault, where the “incident� Clearly spell out MMA requires the for damages to the occurred in the course whether the liability holder of a license to environment or for of that person’s provisions would apply rehabilitate or reclaim causing temporary or employment, his or her retrospectively� the mining area from definitive interruption employer must forthwith time to time� of economic activities� after knowledge of Common law of delict It also provides the incident, report to applies in case of for the state to act a range of stipulated accidental leaks� proactively to clean up organs of state and all environmental damage persons whose health for the account of the may be affected by the 84 person that caused it incident� and later recover the NWA places a duty costs so spent� on an owner of land, a person in control of land, or a person who occupies or uses the land on which an activity or process is, or was performed, or any other situation exists which causes, has caused, or is likely to cause pollution of water resources, to take all reasonable measures to prevent any pollution from occurring, continuing or recurring� NEM: WA applies to the contamination of land even if the contamination occurred before the commencement of the Act� Third-party Contract laws would Land Law requires land Although not currently Extend the application of access rights most likely generally use rights by means applicable to CCS, a relevant laws to the CCS apply and govern third- of easements to build third party may have context� party access rights� a pipeline, although it access to hydrocarbon Clearly define the extent is not clear whether a pipelines, and these to which third parties partial protection zone provisions may serve may have access to the could be established as a guide to the CCS infrastructures� to insulate it against future regulation in the potential third party context of CCS projects claims� (Gas Act)� The Petroleum Law Piped Gas Regulations allows third-party make provision for access to oil, gas, and third-party access to refined fuel pipelines� transmission pipelines and to storage facilities� (continued on next page) Table C.3: Key Findings for Botswana, Mozambique, and South Africa (continued) Key findings 8 key issues Botswana Mozambique South Africa Recommendations Regulatory Appointment of an Regulatory compliance NEMA establishes Compliance would be compliance inspector (MMA, APA, and enforcement EMIs and their powers, easier to monitor and and Public Health Act, EIA schemes are mainly including powers enforce if requirements enforcement Act, or WMA)� ensured by MICOA relating to the seizure for monitoring and scheme The competent authority and, where necessary, of items, routine reporting are clearly may revoke or modify by the Ministry of inspections, the power defined for CCS authorization to Mineral Resources to issue compliance activities� implement an activity (MIREM) and the notices, and the Existing auditing and where there has been National Marine forfeiture of items� inspection powers must an unanticipated Institute (INAMAR) NEM: ICMA allows be extended to CCS irreversible adverse in coordination with for the minister to activities� environmental impact the former� The main issue a written coastal Punitive measures must or a developer fails to tools used for this protection notice, should be clearly defined in comply with any term are the audits and the minister have reason the event of violation of or conditions subject to inspections these to believe a person is provisions governing CCS which the developer’s entities are responsible carrying out, or intends activities� authorization was issued for carrying out, in to carry out, an activity 85 (EIA Act)� addition to punitive that is likely to have an Under WMA, the state powers provided by adverse affect on the can order the immediate law� coastal environment� closure of any existing A responsible authority Waste Management may by notice to any Facility on the grounds person entitled to use of risk of pollution to water under the NWA the environment or suspend or withdraw the harm to human animal entitlement if the person or plant life� fails to comply with any condition of the entitlement, to comply with the NWA, or to pay a charge that is payable� NEMA: WA may require any person to submit a waste impact report if an EMI suspects that such person has failed to comply or contravened any condition of a waste management license� Environmental EIA Act regulates any As a rule, all activities NEMA requires that Clearly define what impact “activity� that is likely posing potential risk an applicant for type of environmental assessment to cause a significant to the environment an environmental assessment must be adverse effect on are subject to authorization to carried out for CCS the environment� environmental undertake a listed activities� Involvement of the licensing� The licensing activity must consider, public with the affected process is preceded investigate, assess, communities is critical� by assessment risk (in and report the the form of plans and consequences for reports) and public or impacts on the consultation with environment of the stakeholders, following listed activity (or which a license may be specified activity) to granted or refused� the relevant competent authority� Public participation is an important requirement� Key Findings and Recommendations at the Domestic Level—the Balkan Region Table C.4 summarizes the key findings for each of the three countries (Bosnia and Herzegovina, Kosovo, and Serbia) and sets forth recommendations that may be adopted at the domestic level necessary for an effective regional framework on CCS. Table C.4: Key Findings for Bosnia and Herzegovina, Kosovo, and Serbia Key findings Bosnia and 9 key issues Herzegovina Serbia Kosovo Recommendations Classification of Traditionally, CO2 has Proposals for the Annex II of the Law on Since CO2 is not yet CO2 not been considered a inclusion of project EIA lists “installatio22 defined in any of 86 pollutant� activities pertaining for the capture of the three countries, to the production and CO2 streams for the the path is clear for use of nuclear energy purposes of geological the introduction of a and CCS into CDM storage� under the definition of CO2 and activities are mentioned Energy Industry captured CO2 in the in the National heading, not in the CCS context� These new Strategy on CDM— Waste heading� legal frameworks on Waste Management, CCS should take care Agriculture and Forestry to ensure that captured Sector� CO2 is excluded from the scope of any existing waste legislation� Jurisdiction over Currently, Bosnia and • The transportation of • The Law on Natural • These new legal the pipelines Herzegovina shares CO2 is not regulated Gas regulates frameworks on CCS and reservoirs its oil pipeline with by any specific law� domestic gas in each of the three Croatia and, on the • The provisions of transmission and countries need to other side, shares the Act on Pipeline storage operators clearly allocate the its gas pipeline Transport of and also gas jurisdiction, role, with Serbia� Cross- Gaseous and Liquid distribution system and responsibilities border transportation Hydrocarbons could operators� These of relevant players of oil and gas is apply� This defines operators also need in the operation of regulated on the transportation by to have a license domestic and cross- basis of bilateral pipeline as the from the Energy border pipelines and agreement, with transportation of Regulatory Office� reservoirs� Croatia and Serbia, gaseous and liquid • Oil pipelines, as well • Legislators should respectively� Cross- hydrocarbons by oil as the transport, consider developing border transportation pipelines, and product storage, import, and the existing legal of CO2 is also likely and gas pipelines� sale of petroleum frameworks to cover to be regulated on a The law distinguishes is regulated by CO2 pipelines and bilateral basis� interstate systems the Law on Trade reservoirs� for oil and natural of Petroleum and gas transport or Petroleum Products� their products when Persons engaging in it concerns cross- activities relating to boundary movement transport, storage, between other states import, and sale of or transit through petroleum need to Serbia� have a license from the Licensing Office� (continued on next page) Table C.4: Key Findings for Bosnia and Herzegovina, Kosovo, and Serbia (continued) Key findings Bosnia and 9 key issues Herzegovina Serbia Kosovo Recommendations Proprietary • The proprietary • The Agreement on Probably covered by Since there are no cross- rights to CO2 rights to a future Successions Issues bilateral agreements boundary CCS sites in CCS sites and cross-border CCS regulates the division in the future� the Balkan region at facilities site and facilities are of movable and present, should such likely to be set out in immovable property, projects look feasible in bilateral agreements including cross-border the future, efforts should between Bosnia and sites between the be made to regulate the Herzegovina and the successor states of the proprietary rights arising relevant neighboring Former Yugoslavia� from them by way of state or states� • The use of cross- bilateral agreement� • By analogy to the border sites is to be gas sector, inter- regulated by separate entity flow of gas agreements� (that is, from Bosnia • A Joint Committee and Herzegovina on Succession to Serbia and vice to Movable and 87 versa) is regulated Immovable Property on the basis of is to be established cooperation in by successor states to this area, through ensure implementation agreements between and the resolution of the relevant problems� The work of governments, the committee is still ministries, and in process and should regulatory be accelerated� commissions� Regulatory • There is no specific • Currently, there are • Currently no There is no specific schemes related licensing system in permits according to licensing scheme licensing system in place to management place yet for CCS the Spatial Planning is in place relating yet for CCS projects of storage and projects� and Construction Act, to CCS storage in any of the three transportation • The existing environmental and and transportation countries� These new facilities permitting system other legislation, and facilities� legal frameworks on from the gas sector permits according • Presently, licenses CCS should set out clear in both of the to the Mining must be obtained requirements on the entities might be Act, Geological from the Energy application process and applicable (that is, Explorations Act and Regulatory Office for responsibilities following the Serbian Law Energy Act� construction of new the grant of exploration on Gas and the • The use of CCS energy generation and storage permits Federation of Bosnia technology would capacities, new (such as monitoring, and Herzegovina be likely to include facilities, and reporting, procedure Decree on the permits required for pipelines to transmit in case of leakages, Organisation and certain hazardous and distribute gas closure, and post-closure Regulation of Gas activities and their and for storage of obligations)� Economy) effects on the natural gas� Possibly Given that many other environment and this framework permitting systems human health, as would be widened do exist in the three well as permits to cover licensing countries, care should required for geological of CCS storage be taken to ensure that explorations, mining and transportation there is not unnecessary sites, and energy facilities� duplication of facilities� requirements applying to CCS storage or transport systems� (continued on next page) Table C.4: Key Findings for Bosnia and Herzegovina, Kosovo, and Serbia (continued) Key findings Bosnia and 9 key issues Herzegovina Serbia Kosovo Recommendations Long-term Article 103 of the • Article 9 of the Law • Chapter 8 of General environmental management Serbian Law on on Environmental the Law on liability provisions and liabilities Environmental Protection establishes Environmental already exist in each Protection and Article a framework for Protection country’s legislation� 103 of Federation environmental liability establishes a However, it would be of Bosnia and based on the polluter framework for prudent if the new legal Herzegovina Law pays principle with environmental frameworks on CCS on Environmental a view to remedying liability based on set out the liabilities Protection regulate environmental the polluter pays of the different players liability concerning damage� principle with a involved in each aspect dangerous activities • Separate liability view to remedying of CCS for accidents that may cause provisions also environmental and leaks� Liability for significant risk to exist in the Law on damage� Article 65 environmental damage, people, health, Waters, Law on Waste establishes general as well as climate property, and/or the Management, and the liability for legal and damage, should be 88 environment� The legal Law on Health and natural persons, and covered� entity that performs Safety at Work� Article 66 provides dangerous activities • According to the that the polluter bears responsibility principle of duty of is responsible for for damages caused care, there is an damage caused and by that activity� obligation both for for making good the Although CCS projects the owner of certain damage� are not expressly property and for any • The Criminal Code included in the laws as other person who provides for the “dangerous activities,� according to law or punishment of it is likely that plants contract has a right various offenses containing equipment to possess and use relating to the to capture CO2, the lands, buildings, and environment, pipelines used to movable property� such as pollution transport concentrated The owner’s rights or destruction of CO2, and the plant and obligations are the environment, used to inject CO2 regulated in greater unlawful handling would be considered detail by the Act on of hazardous “locations that are Bases of Property substances and dangerous to the Relations, while the waste, and environment� and thus duty of care of other unlawful operation qualify as “dangerous persons is prescribed of hazardous activities�� by the Contracts and installations� Torts Act� • Separate liability provisions also exist in the Water Law and the Law on Air Protection from Pollution� (continued on next page) Table C.4: Key Findings for Bosnia and Herzegovina, Kosovo, and Serbia (continued) Key findings Bosnia and 9 key issues Herzegovina Serbia Kosovo Recommendations Financial • No provision made • No provision has been • No provision has The requirements of assurance on this as yet in made on this as yet in been made on this Articles 18 and 20 of for long-term relation to CCS relation to CCS sites as yet in relation Directive 2009/31/EC stewardship sites� or in any analogous to CCS sites or should be adequately • Both Entities’ Laws legislation� in any analogous reflected in the new on Environmental legislation� legal frameworks� Protection require Also the European that the legal entity Commission’s recent managing the Guidance Document dangerous activity 4 on Financial provides sufficient Security (Art� 19) and financial security to Financial Mechanism cover any damage (Art� 20) should be which potentially borne in mind� The might occur to Guidance concludes by third parties and recommending that the 89 compensation financial mechanism through insurance selected under Article 20 or by some other of Directive 2009/31EC means� be simple, established, • The Entities’ Laws on and low risk, and Waste Management cautions against require that sites complex financial holding hazardous arrangements� waste provide a financial guarantee that covers the costs of activities required after closure of such facility� (continued on next page) Table C.4: Key Findings for Bosnia and Herzegovina, Kosovo, and Serbia (continued) Key findings Bosnia and 9 key issues Herzegovina Serbia Kosovo Recommendations Third-party • Not governed in the • No rules yet on third- • This topic is not Third-party access access rights context of CCS as party access in terms developed yet rights are already yet� of CO2 transportation� in terms of CO2 governed in Bosnia and • Both the Federation However, the Energy transportation, but Herzegovina, Kosovo, of Bosnia and Act provides for third- detailed provisions and Serbia in the energy Herzegovina Decree party access and may exist in the Law and gas sector contexts� on Organisation and give an indication on Natural Gas Nevertheless, the new Regulation of Gas of the possible rules governing third- legal frameworks on Economy and the to be applied� The party access rights� CCS should provide for Serbian Law on Gas operator of the energy • The Law on Natural fair and open access place obligations on entity in charge Gas requires to the CCS transport the operator with of transmission, that transmission network and storage respect to third-party transportation, or and distribution sites� access right� distribution systems system operators must allow access of allow natural gas 90 third parties based undertakings and on the principles of eligible customers, transparency and including supply nondiscrimination� undertakings, Access may be refused to have when there are nondiscriminatory technical limitations� access to • Third party access transmission and rights are also distribution systems, regulated by pursuant to rules contractual provisions and tariffs approved provided they comply and published with the Energy Act� by the Energy • The Act on Pipeline Regulatory Office� Transport of Gaseous and Liquid Hydrocarbons and Distribution of Gaseous Hydrocarbons lays down the conditions for safe and uninterrupted pipeline transport of gaseous hydrocarbons and liquid hydrocarbons and distribution of gaseous hydrocarbons� • In the case of state pipelines, the Concession Act can apply� (continued on next page) Table C.4: Key Findings for Bosnia and Herzegovina, Kosovo, and Serbia (continued) Key findings Bosnia and 9 key issues Herzegovina Serbia Kosovo Recommendations Regulatory • Both Entities have a • The responsibilities • Regulatory Either the existing compliance and Law on Inspections� related to inspections enforcement of the inspection and enforcement • Both Entities and enforcement are energy sector is enforcement schemes scheme have an entity- determined by several performed by the that are in place in the level Directorate legal acts� Energy Inspectorate three countries should for Inspections • Competence for law as part of the be extended to cover (Inspectorate) enforcement in the Ministry of Energy CCS facilities and and inspections field of environmental and Mining� The pipelines, or the new established at protection is divided Energy Inspectorate legal frameworks on a local (canton/ between republic has powers to carry CCS should enshrine the municipal) level� inspectors, provincial out inspections both inspection requirements • A CCS project would inspectors, and local with and without found in Article 15 of likely be subject inspectors� notice� Also, energy Directive 2009/31/EC to a “technical • Other inspections facility operators and also the penalty inspection,� as well relevant to must inform this provisions� as an “urbanism- environmental issues Inspectorate of any 91 construction and include mining damage or error ecology inspection�� inspections, spatial that occurs as a • Inspectors have planning inspections, result of energy various powers building inspections, supply outages or to take action electro-energetic of any hazard to if they note any inspections, and life, health, or the noncompliance� health inspections� environment� • In terms of • The Law on State • Regulatory enforcement, both Administration and enforcement in the Entities have Laws certain other laws environmental sector on Offences� require cooperation is carried out by between inspectors the Environmental from different Protection domains� Inspectorate, which is part of the Ministry of Environment and Spatial Planning� (continued on next page) Table C.4: Key Findings for Bosnia and Herzegovina, Kosovo, and Serbia (continued) Key findings Bosnia and 9 key issues Herzegovina Serbia Kosovo Recommendations Environmental • Article 56 of the • According to the Law • An environmental The EIA legislation in impact Serbian Law in on Environmental consent is required Bosnia and Herzegovina assessment Environment Impact Assessment, by the Law on and Serbia is Protection requires EIA is required for Environmental established, but does not that “projects planned projects and Impact Assessment yet specifically mention that may have projects, changes for every public or activities relating to significant impact in technology, private project that the capture, transport, on environment reconstruction, the is likely to have injection, and storage because of their size, extension of capacity, significant effects of CO2� This should be nature and location, the termination of on the environment addressed� must be subject operations, and the by virtue, among to EIA and obtain removal of projects other things, of an administrative that may have its nature, size, decision approving significant impact on or location� These the Environmental the environment� consents are issued 92 Impact Study�� • EIA is obligatory for by the Ministry • The Serbian minister projects involving of Environment� responsible for pipelines for the Public participation environmental transport of gas, is an important protection is liquefied petroleum requirement� responsible for the gas, oil, or chemicals, • An environmental EIA decision making� and for storage consent is required Also, the ministry is facilities for petroleum, for projects involving obliged to inform petrochemical and the capturing local communities chemical products, and transport of in the territory of natural gas, CO2 streams for the planned project flammable liquids, and the purpose of and to ask for their fuels� geological storage opinion� • The competent and also storage • In The Federation authority may also sites� of Bosnia and decide that the EIA Herzegovina, the has to be applied in Rulebook on EIA case of other activities lists the categories that could have a of plants and significant impact on installations for the environment� which an EIA is • If a planned project obligatory in order to could cause a obtain an eco-permit significant impact on from the Federal the environment of Ministry in charge another state, or when of environmental another state whose protection� For environment could be all other plants threatened requests and installations the information, the not listed in the ministry responsible Rulebook, and for for environmental which an EIA is protection must send not needed, and this other state all for those with relevant information� capacities below the • Public participation thresholds defined and access to in the Rulebook, an information are eco-permit is issued regulated at the by the responsible national level� Cantonal ministry� APPENDIX D: THE ROLE OF CLIMATE FINANCE SOURCES IN ACCELERATING CARBON CAPTURE AND STORAGE DEMONSTRATION AND DEPLOYMENT IN DEVELOPING COUNTRIES Table D.1: Summary of Near-Term Demonstration Challenges for CCS Issue Description Technical All individual components of the chain of capture, transport, injection, and storage have been proven, but not in a fully integrated technology chain at a significant and replicable scale� Proven low-cost, low energy-consuming processes that can capture high-volume, low-pressure, dilute streams of CO2, such as those exiting the combustion process in coal- and gas-fired power plants have yet to be fully developed at scale� The availability of sufficient, accessible, and secure geological storage formations for storage has yet to be fully proven� Site appraisal and monitoring techniques also need further application and demonstration� There are challenges associated with the establishment of large networks of CO2 transportation 93 systems, especially pipeline infrastructure, to carry CO2 from the point of capture to suitable geological storage sites� Financial and Ongoing costs because of the energy penalty associated with capturing, cleaning, and compressing economic the CO2, as well as other materials consumption (such as chemical and physical CO2 solvents) mean a sustainable source of project revenue must be established� With the exception of certain niche circumstances where captured CO2 can be used as an input to production processes (for example, for EOR), urea manufacture, in greenhouses for vegetable growing or in the beverage industry), the benefits of deploying CCS are limited to that of climate change mitigation� This sets CCS apart from most other types of mitigation technologies, such as renewable energies, which deliver both clean energy benefits and fuel cost reductions, as well as mitigation benefits� This means that CCS requires the establishment of incentive mechanisms that provide a sufficiently high and long- term price signal, such that operators can be assured of avoided costs or revenue streams that adequately cover ongoing commercial costs of operating and maintaining capture, transport, and storage facilities� In the absence of sufficient incentive mechanisms, the prospects for securing appropriate levels of finance to support the investment needs for CCS will be limited� Legal, regulatory, The establishment of proven legal and regulatory frameworks that can confer the right to store CO2 and public onto operators, assign responsibilities and liabilities for the captured CO2, and enforce appropriate acceptance licensing to ensure secure storage site development has not been fully developed and tested in any jurisdiction� Public acceptance of the technology is required for various reasons, including: acceptance of additional costs associated with products produced from CCS-installed facilities, and the locating of CO2 pipeline corridors and CO2 storage sites� Methodological, Because CCS involves the storage of CO2 to avoid its emission rather than to avoid its production, accounting, and it poses the risk that it could reemerge into the atmosphere at some point in the future� This policy creates problems associated with the issue of “permanence� if credits are awarded for not emitting, potentially undermining the objectives of its use, and also the integrity of any ETS into which the credits have been used� Issues related to potential perverse outcomes, such as promoting fossil fuels and subsidizing oil production (in the case of EOR projects obtaining climate finance) need also to be resolved� Source: Zakkour 2011� Table D.2: Status of CCS in Developing Countries: Policy Initiatives, Project Implementation, and Other Enabling Activities, Select Examples International policy initiatives In-country activities China CSLF: Member Post combustion power (Gaobeidien) and pre-combustion power (IGCC; CCUS: Participant GreenGen) pilots and demonstration� IEA Roundtable Bilateral and multilateral initiatives include UK/EU-funded NZEC Program, COACH, and the China-Australian Geological Storage (CAGS) project� India CSLF: Member UK Government-funded assessment of CO2 storage capacity and capture-ready potential of Ultra Mega Power Plant (UMPP) projects� Latin CSLF: Colombia, Mexico, Brazil: EOR trials ongoing in Reconcavo Basin; Petrobras has two other America and Brazil (Members) CCS pilots (Bahia state)� BECCS from ethanol pilot under GEF SCCF� Caribbean CCUS: Mexico, (Participant) Established the Carbon Storage Research Centre, CEPAC� IEA Roundtable: Brazil and Mexico: Pemex trialing CO2-EOR� CFE working on CCS strategy� North Mexico American Carbon Atlas Partnership (NACAP) working with Mexico to map Brazil and Caribbean states storage potential� opposed to CCS in CDM Trinidad and Tobago: academic research in to CCS potential� 94 Other Indonesia supportive CCS in Vietnam: White Tiger CCS CDM proposal� developing CDM (3 x submissions) Thailand: feasibility study conducted for offshore CCS project� Asia IEA Roundtable: Indonesia Malaysia: Bintulu CCS CDM proposal� Petronas undertaking CO2-EOR and Malaysia and CO2 storage assessments� IEAGHG: South Korea, Indonesia: National agencies, Shell and World Energy Council have (Member) undertaken national CCS assessment� Africa CCS in NAMA: Botswana Algeria: In Salah project capturing c�1Mton CO2 from high-CO2 field� CSLF: South Africa, Member Other developers exploring similar projects (for example, GdF)� CCUS: South Africa, South Africa: SACCCS; Geological Storage Atlas compiled� Draft Participant regulations on capture readiness for power plants� IEA Roundtable (South Africa) Botswana: CCS feasibility study at Mmamabula Power� IEAGHG: South Africa CCS Africa: Awareness-raising in Botswana, Mozambique, Namibia, (Member) Senegal, and South Africa� Middle East CSLF: Saudi Arabia, UAE UAE: MASDAR Carbon 3 project plans (Abu Dhabi)� Ongoing CO2-EOR (Members) trials� CCUS: UAE (Participant) Saudi Aramco undertaking CCS application assessments (Saudi Arabia)� Other CSLF: Russia (Member) Russia: some academic studies on CCS have been undertaken� IEA Roundtable: Russia and Uzbekistan: Underground coal gasification (UCG) demonstrated� Ukraine Balkans: World Bank techno-economic assessment of CCS potential� Box D.1: Metrics Used to Describe CCS Deployment in This Report The IEA CCS Roadmap describes measures and actions according to one global pathway for CCS deployment to 2050� The rate of deployment is based on the IEA ETP Blue Map Scenario, which describes how energy technologies may be transformed by 2050 to achieve the global goal of reducing CO2 emissions to half that of 2005 levels� The model is a bottom-up market allocation (MARKAL) model that uses cost optimization to identify least-cost mixes of energy technologies and fuels to meet energy demand, given constraints, such as the availability of natural resources� The IEA CCS Roadmap describes a range of key “metrics� relating to deployment of CCS across world regions and sectors through 2050� A similar set of metrics have been calculated for the analysis presented in this report, using the same data, but focusing just on developing countries� Together these serve to describe the scale of needs for CCS in these regions over the next two decades in a cost-ordered portfolio of measures� The metrics and terms used in this report include the following� Captured emissions: The amount of CO2 captured from CCS equipped facilities, taking into account CO2 formation and capture efficiency� This metric gives the amount of CO2 that will be captured, transported, and injected in a given period, typically a year� Avoided emissions: The level of emissions abatement achieved by CCS-equipped facilities relative to the emissions of an equivalent facility (that is, with the same output) without CCS� It reflects the “energy penalty� associated with CCS equipment and is derived as 95 Avoided CO2 – captured CO2 / CE * [effnew / effold – 1 + CE] where CE = capture efficiency (fraction captured); effold = energy efficiency of plant without capture (%); effnew = energy efficiency of plant with capture (%) Project numbers: A translation of the mitigation contribution of CCS in the Blue Map Scenario (based on ton CO2 captured) into real-world numbers of CCS projects� It is derived from ranges of typical project sizes within each subsector analyzed, including small pilot CCS projects within the power sector to larger CO2 reinjection projects being employed at high-CO2 natural gas fields� Additional investment: The amount of financial capital needed to build CCS facilities that is additional, or incremental, to that required to build equivalent facilities without CCS� Additional costs: The annualized expenditures for just the CCS part of a facility, thereby reflecting the additional, or incremental, costs for operators relative to operating an equivalent facility without CCS� Costs include capital repayments, fuel and maintenance costs, and costs associated with CO2 transport and storage� It therefore reflects the additional costs for operators associated with building, operating, and maintaining CCS facilities� Costs in this report are based on the IEA CCS Roadmap� Cost of abatement: The unit cost of reducing emissions through the use of CCS compared to a non-CCS equivalent case� Abatement costs for CCS projects are expressed as US$ per ton CO2 avoided and calculated as Additional costs / Avoided CO2� Abatement costs can be presented graphically as a marginal abatement cost curve (MACC), in which the abatement potential of different reduction options are presented in order of cost (from least to highest cost), thus indicating the marginal cost of achieving a certain level of emission reduction� The MACCs presented in this report are based on the IEA CCS Roadmap data (IEAGHG 2008)� Sources: Adapted from IEA 2009� Table D.3: Main Components for Good Practice for CCS Project Design and Operation Component Description Geological CO2 storage site design and operation Site characterization and Appropriate geological storage site selection based on a thorough appraisal of subsurface selection geology is the most critical aspect of CCS project design� It is the primary means of avoiding the risk of non permanence of projects� It involves the collection of a range of geological data and the compilation of a reservoir simulation model using appropriate computer software� Information on potential receptors for leaking CO2 must also be collected� Risk assessment Testing of all assumptions gathered during site selection and characterization to evaluate factors, such as subsurface pressure fronts, identify potential pathways for leakage, and test critical operational parameters that could activate such features (for example, reservoir pressure) is required� This is largely achieved through computer modeling techniques involving reservoir simulator software� A consequence analysis must also be included based on the receptors identified during site characterization� Risk assessment frameworks are constantly evolving, since experience is gained in project design; a number of approaches are outlined in the literature, and a global research networks exist under the IEAGHG� 96 Modes of operation Based on the site characterization and risk assessment, the modes of operation for the storage site should be defined covering aspects, such as the location for injection wells, injection rates, and maximum tolerable reservoir pressures� Measurement and Components within the project boundary must be monitored during project operation� The monitoring, reporting, 2006 IPCC Guidelines suggest the following approach to the design of a monitoring plan for and verification (MRV) geological storage sites, which is critical to successful long-term geological storage of CO2: • Site characterization—confirmation that the geology of the storage site has been evaluated and that local and regional hydrogeology and leakage pathways have been identified� • Assessment of seepage—confirmation that the potential for seepage has been evaluated through a combination of site characterization and realistic models that predict both the movement of CO2 over time and the locations where emissions might occur� • Monitoring—ensuring that an adequate monitoring plan is in place� The monitoring plan should identify potential leakage pathways, measure leakage, and/or validate or update models as appropriate� • Reporting—reporting the CO2 injected and emissions from the storage site�* Subsurface components require the application of a series of steps and procedures that must be followed to design an appropriate monitoring plan, drawing on the site characterization and risk assessments carried out� The heterogeneity of the subsurface means that prospective approaches should not be used, since each project will need site-specific techniques, locations, and frequencies� The 2006 IPCC Guidelines includes a list of potential technologies that could be applied for geological storage monitoring in Table A5�1–5�6� A broad range of literature exists on monitoring plan design for geological storage, including IEAGHG (2007), UNFCCC (2008a), In Salah Gas (2009), and IEA (2010b)� The IEAGHG (2010) also maintains an online Monitoring Selection Tool to assist in monitoring plan design� Under the EU ETS, monitoring and reporting guidelines for CCS projects have been formally approved, which include methods for seepage calculation, and the US EPA has also introduced similar rules (EC 2010)� Closure Effective closure of a site will also be required to ensure that injection wells are properly plugged to appropriate standards so as to prevent migration of CO2 up well bores� Inappropriately completed or plugged wells will generally present the greatest source of seepage risk� Post-closure monitoring After a site has been closed, it will be necessary to continue monitoring, since CO2 is likely to remain mobile for some time after injection ceases� Over time, however, the reduction in motive pressure after injection ceases, and trapping through various mechanisms, such as pore space attenuation, residual trapping, dissolution, and mineral trapping, will reduce CO2 mobility, after which stabilization of the CO2 plume should occur� At this point, it may be possible to cease monitoring completely or at least to monitor only on a routine basis� (continued on next page) Table D.3: Main Components for Good Practice for CCS Project Design and Operation (continued) Component Description Other aspects of high-quality CCS project design Project boundaries There is broad consensus among a range of stakeholders, including Parties to the Kyoto Protocol, that the project boundary for a CCS project should cover the full lifecycle of activities encompassing GHG emissions from capture, transport, and injection (UNFCCC 2008a), and should be flexible enough to accommodate a range of storage types and different geological conditions, including coverage of enhanced hydrocarbons recovery techniques (UNFCCC 2008a)� Project boundary will need to cover all above-ground components (capture, transport, booster stations, holding tanks, and injection facilities) and the subsurface components (wells, the CO2 plume, the storage reservoir, as defined during characterization, and locations around the reservoir)� The subsurface boundaries of the storage reservoir will be defined during site characterization� Compliance with Projects will need to comply with any applicable domestic legislation, including for EIA and domestic and aspects of civil protection� International law will also need to be complied with� For offshore international laws projects, provision of the London Protocol—and in particular, the risk assessment guidelines developed hereunder—should be followed� Trans-boundary projects should require mutually agreeable approaches to project approvals, site management, and other issues can be 97 reached by all interested parties� * Based on UNFCCC (2008a), which is taken from IPCC 2006� Table D.4: Focus Areas for CCS Capacity Building Efforts in Developing Countries Activity Description Awareness-raising Develop understanding among policy makers regarding CCS technology and the role it could play in GHG mitigation strategies at a national and regional scale� Promote an understanding of the current issues relating to the creation of international carbon offsets by CCS projects (for example, under the CDM)� Raise awareness of potential climate finance framework and mechanisms and channels to support CCS deployment and possible requirements/limitations that might be formulated towards CCS carbon assets� Technical studies Review major CO2 sources and sector categories, and gain understanding of the range and costs associated with different types of CCS projects� Undertake provisional storage capacity assessments� Identify key regions where greatest potential exists� Consider scope for more detailed assessments� Develop studies to gain clearer understanding of issues associated with CO2 transport (source-sink matching, costs, health, safety, and environment issues)� Understand the role of clustering of sources and sinks (for example, identify clusters of major sources and their proximity to potential storage sites)� Supporting Consider the scope for matching R&D needs to potential support available through the proposed 98 measures Technology Mechanism� Review of existing domestic proposals for clean technology incentives and assess their applicability to CCS� Consider the interactions between domestic policies and the scope for internationally supported NAMAs in future climate finance frameworks� Legal and Develop awareness of legal and regulatory issues that will have impact on the attractiveness of regulatory needs CCS carbon assets for climate finance, and in particular, for market instruments (for example, assessments permanence and long-term liability issues)� Assess domestic options for managing long-term liability� Consult with stakeholders on liability issues associated with CCS� Review existing and proposed CCS-related legislation in developed countries and gain understanding of key components and modalities and procedures therein� Review existing subsurface laws to assess whether they can be modified to fit to CCS (for example, laws pertaining to mining, and oil and gas, or any laws relating to deep injection of liquid waste)� Assess which new elements might need to be added to complement or modify existing legislation� Institutional Review current institutions to assess capacity to oversee projects� Assess existing government capacity departments and agencies for competencies� Identify opportunities for regulators to engage in international activities (for example, those led by the IEA)� International Develop internal understanding of international bodies that may be involved in supporting CCS support needs (for example, validation and verification competencies; competencies of approval bodies/CDM Executive Board to evaluate projects)� Stakeholder Engage with relevant in-country stakeholders, including universities and research institutions, consultation industry, regulatory bodies, and public interest groups� Understand industry perspectives on the role of CCS in their sector� Understand industry views regarding regulatory aspects, including approaches to managing long- term liability and financial assurance mechanisms� APPENDIX E: PROJECT FINANCE Table E.1: Financial Assumptions Used in STRUCTURES AND THEIR IMPACTS ON LCOE Model THE LEVELIZED COST OF ELECTRICITY FOR Parameter Value POWER PLANTS WITH CCS Inflation rate 3% Table E.1provides the financial assumptions used in the O&M real escalation 0% model. Real fuel escalation rate 3% Technology Assumptions Tax rate 31% Debt fraction 65% The following tables give the technical and economic Equity rate 20% assumptions used in the financial model. Construction schedule (4 years) 15%, 35%, 35%, 15% Depreciation Straight line Plant life 40 years 99 Table E.2: Cost and Technical Assumptions for PC Technologies in Model Pulverized coal wet-cooled Pulverized coal dry-cooled Full Partial Full Partial Unit of capture capture capture capture Input measure No CCS CCS CCS No CCS CCS CCS Capacity MW 500 495 499 500 495 499 Capacity factor % 85 85 85 85 85 85 Heat rate Btu/kWh 8,653 12,460 9,710 9,108 13,116 10,221 Overnight cost US$/kW 2,163 4,048 2,944 2,253 4,211 3,061 Fixed O&M costs US$/kW/year 30 46�2 34�5 30 46�2 34�5 Variable O&M costs mills/kWh 6�45 11�94 7�98 6�45 11�94 7�98 Carbon intensity kg-CO2/MMBtu 300 300 300 300 300 300 Capture rate % 0 90 25 0 90 25 CO2 emitted kg CO2/kWh 1�025 0�103 0�769 1�025 0�103 0�769 CO2 captured kg CO2/kWh 0 0�9225 0�25625 0 0�9225 0�25625 CO2 captured tons CO2/year 0 3,402,452 952,020 0 3,402,452 952,020 Table E.3: Cost and Technical Assumptions for IGCC Technologies in Model IGCC wet-cooled IGCC dry-cooled Full Partial Full Unit of capture capture capture Partial Input measure No CCS CCS CCS No CCS CCS capture CCS Capacity MW 500 417 477 500 417 477 Capacity factor % 85 85 85 85 85 85 Heat rate Btu/kWh 8,989 12,405 9,938 9,016 12,172 9,893 Overnight cost US$/kW 2,083 2,866 2,492 2,147 2,950 2,565 Fixed O&M costs US$/kW/year 60 74�4 64 60 74�4 64 Variable O&M costs mills/kWh 6�00 7�80 6�50 6�00 7�80 6�50 Carbon intensity kg-CO2/MMBtu 300 300 300 300 300 300 Capture rate % 0 90 25 0 90 25 100 CO2 emitted kg CO2/kWh 1�025 0�103 0�769 1�025 0�103 0�769 CO2 captured kg CO2/kWh 0 0�9225 0�25625 0 0�9225 0�25625 CO2 captured tons CO2/year 0 2,864,017 910,474 0 2,864,017 910,474 Table E.4: Cost and Technical Assumptions for Oxy-fuel Technologies in Model Oxy-fuel Input Unit of measure No CCS Full capture CCS Partial capture CCS Capacity MW 500 495 499 Capacity factor % 85 85 85 Heat rate Btu/kWh 8,653 11,594 9,470 Overnight cost US$/kW 2,163 3,810 2,944 Fixed O&M costs US$/kW/year 30 42�6 33�5 Variable O&M costs mills/kWh 6�45 8�26 6�96 Carbon intensity kg-CO2/MMBtu 300 300 300 Capture rate % 0% 90% 25% CO2 emitted kg CO2/kWh 1�025 0�103 0�769 CO2 captured kg CO2/kWh 0 0�9225 0�25625 CO2 captured tons CO2/year 0 3,402,452 952,020 Table E.5: Explanation of Varied Parameters and Justifications Parameter Values and explanation Coal price US$1/MMBtu (low) US$3/MMBtu (medium) US$5/MMBtu (high) The values 1 and 5 are selected as extremes, with 3 as the average included� The low price is based on cheap domestic coal prices in South Africa (World Bank 2010b), the high price is the price of internationally traded coal (World Bank 2011a) and the medium is the average CO2 price US$0/ton US$15/ton US$50/ton These values are selected to represent no price, a low price, similar to prices seen in the EU ETS, and a high price on carbon, and are consistent with the prices used for the analysis in Chapter 5� Enhanced oil 1 million tons per year are injected and stored� recovery EOR takes place for 10 years� After 10 years, CO2 is assumed to be stored in alternative site� Capital costs are increased by US$184,200,000�* Assumed oil price US$70/bbl� Maximum recovery factor: 2�5 bbl/ton injected (NETL 2008b)� 101 Because of recycling, by year 10, only 50% of total CO2 injected is from capture in the plant� Enhanced coalbed 1 million tons per year are injected and stored� methane recovery After 10 years, CO2 is assumed to be stored in alternative site� ECBM recovery takes place for 10 years� Capital costs are increased by US$66,000,000* Assumed gas price: US$3�5/mcf� Maximum recovery factor: 0�317 tons gas/ton CO2 injected (Reeves 2002)� * Developed with expert consultation� Table E.6: Oil and Methane Recovery Rates Assumed for EOR/ECBM Recovery rates EOR ECBM Project operation year (bbl/ton CO2 injected) (ton methane recovered/ton CO2 injected) 1 0�2 0�00 2 1�0 0�05 3 1�8 0�08 4 2�3 0�22 5 2�5 0�29 6 2�5 0�32 7 2�5 0�32 8 2�5 0�32 9 2�2 0�32 10 1�0 0�28 Average 1�85 0�22 Table E.7: Assumed Revenue Streams for EOR and ECBM Recovery Project Revenues from EOR (US$m) Revenues from ECBM (US$m) operation year IGCC PC Oxy-fuel IGCC PC Oxy-fuel 1 13 13 13 0 0 0 2 58 61 61 8 9 9 3 94 99 99 13 14 14 4 107 112 112 37 39 39 5 103 107 107 49 51 51 6 89 93 93 53 56 56 7 74 78 78 53 56 56 8 60 63 63 53 56 56 9 41 42 42 53 56 56 102 10 13 13 13 47 49 49 Additional Results Figure E.1: Percentage Change in LCOE from Reference Plant without CCS to Plant with CCS Figure E.1 gives the results when revenues from both with Enhanced Hydrocarbon Recovery and CO2 prices and EOR/ECBM are available. Combining CO2 Price the revenue streams results in greater decreases in LCOE, as expected. The smallest change in LCOE is 70% seen for the IGCC case with a price of US$50/ton 60% combined with either EOR or ECBM (since both give 50% almost the same impact on LCOE in this study). 40% 30% 20% 10% 0% 0$/ton 15$/ton 50$/ton 0$/ton 15$/ton 50$/ton 0$/ton 15$/ton PC Oxy IGCC 50$/ton None EOR ECBM BIBLIOGRAPHY • Bakker, S. J. A., A. G. Aravanitakis, T. Bole, E. van de Brug, C. E. M. Doets, and A. Gilbert. 2007. “Carbon • The 1989 Basel Convention on the Control of Credit Supply Potential beyond 2012: A Bottom-up Transboundary Movements of Hazardous Wastes and Assessment of Mitigation Options.� ECN-C-07-090, their Disposal (Basel Convention). Point Carbon, Ecofys, November. • The 1991 Bamako Convention on the Ban on the • Bakker, S. J. A., T. Mikunda, and R. R. Tinoco. 2011. 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