39199 NILE BASIN INITIATIVE v.3 NILE EQUATORIAL LAKES SUBSIDIARY ACTION PROGRAM Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in The Nile Equatorial Lakes Region Final Report Volume 2 Appendices February 2007 This work was carried out by: SNC-Lavalin International In association with: - Hydro Quebec International - Vincent Roquet et Associés Inc. - Stratus Consulting Inc. - Michael A. Stevens, Consultant - WL Delft Hydraulics - Experco International (Burundi, Eastern DRC and Rwanda) - GIBB Africa Limited (Tanzania and Kenya) - Sustainable Resources Network (Uganda) The project was managed and supervised by: THE WORLD BANK With financial participation by: SNCeLAVALIN SNC*LAVAUN INTERNATIONALInc. International 455 Rene-Levesque Blvd. West February 26,2007 Montreal, Quebec Canada HZ2123 Telephone:(514) 393-1000 Fax: (514) 876-9273 Mr. Jakob Granit Sr. Water ResourcesManagement Specialist The World Bank, AFTNL 1818 H. Street, NW MailstopJ11-1102 Washington, DC 20433 USA Subject: StrategiclSectoralSocial and EnvironmentalAssessment of Power DevelopmentOptions inthe Nile EquatorialLakes Region Final Re~ort Dear Mr. Granit: We are pleased to submit our final report for this interesting and challenging project. The report consist of: The main report, including an executivesummary A volume of appendicescontainingall the basic informationused inthe analyses An executive summary in English and An executive summary in French This report provides a solid foundation for planning the development of the power sectors of the region as it contains a proposed development strategy and a NELSAP indicative development plan to the year 2020. It is based on a review of the current environmental and social context, the existing legal and regulatory framework, an assessment of the power needs for the region, an identification of the power development options available in the region and a comparison of these options in terms of environmental,socio-economic and risk considerations. It has been a pleasure working with you and your team as well as the NELSAP coordinating Unit, other members of the steering committee and the stakeholders who participated in the project. Sincerelyyours, //& Raymond Noel Team Leader, SNC-Lavalin InternationalInc. RNItc Encl. Member of the SNC*LAVALINGroup A Note to Readers This SSEA study is a general framework which was used to develop an indicative power development strategy for the NELSAP region. As such, it is based on information gathered from secondary sources initially in 2003 and updated in 2004. Much of the data received was developed by numerous consultants over long periods of time (some dating back 20 years) using a wide range of assumptions. Every reasonable effort has been made to put the information on the consistent basis needed for a strategic level analysis like this SSEA. The SSEA is not a substitute for detailed project specific studies and environmental/social impact assessments needed for the implementation of particular projects. Such studies would invariably incorporate updated and detailed information about various project aspects including alternate configurations, cost estimates, hydrology and plant output, and environmental and socio-economic impact analyses. LIST OF ABBREVIATIONS List of Abbreviations AEC African Economic Community AU African Union bcf Billion cubic feet BReTIN Backbone Regional Interconnection Network CEQ Council on Environmental Quality Cf Cubic feet CIA Cumulative Impact Assessment CITES Convention on International Trade in Endangered Species COMESA Common Market for Eastern and Southern Africa DRC Democratic Republic of Congo DSM Demand side management DWT Dead-weight tonnes EAC East African Community EAPMP East African Power Master Plan EIA Environmental Impact Assessment FOB Free on Board GHG Greenhouse Gases GJ Gigajoule GRDC Global Runoff Data Centre GNI Gross National Income GtC Gigatonnes of carbon emissions per year GWh Gigawatt-hour HEPP Hydroelectric Power Plant HIPC Highly Indebted Poor Countries kWh Kilowatt-hour IDA International Development Association IEA International Energy Agency IPCC Intergovernmental Panel on Climate Change IUCN World Conservation Union (formerly International Union for Conservation of Nature and Natural Resources) SSEA III - Final Report 1 017334-001-00 LIST OF ABBREVIATIONS LNG Liquefied Natural Gas MCA Multi-Criteria Analysis Mt Million tonnes MW Megawatt NBI Nile Basin Initiative NCAR National Center for Atmospheric Research NEL Nile Equatorial Lakes NEL-CU Coordinating Unit for NELSAP NELSAP Nile Equatorial Lakes Subsidiary Action Program NePAD New Partnership for African Development NGO Non Governmental Organization PET Potential Evapotranspiration PPP Purchasing Power Parity PSC Project Steering Committee PF Plant Factor PV Photovoltaic RDC République Démocratique du Congo (note English acronym used : DRC) SADC Southern African Development Council SAPP Southern Africa Power Pool SENOKI Société d'électrification du Nord Kivu SNEL Société national d'Électricité (the electric utility in DRC) SSEA Strategic/Sectoral Social and Environmental Assessment SSEA I SSEA applied to Burundi, Rwanda and western Tanzania SSEA II SSEA extended to include Kenya, Uganda, all of Tanzania and eastern DRC STC Standard Testing Conditions Tcf Trillion cubic feet TWf Terawatthour UNEP United Nations Environment Programme Wp peak-watt WWF Worldwide Fund for Nature (World Wildlife Fund) SSEA III - Final Report 2 017334-001-00 LIST OF ABBREVIATIONS List of Definitions Term Definition Captive Electricity produced for consumption by the producer of that energy Power (i.e. the energy produced by a power plant run by a hotel (or industry, agency or individual) for the exclusive use of that hotel Demand The maximum amount of electricity required by a system during any one-hour period over a year, measured in megawatts (MW) Electric The amount of electricity consumed over a period of time, measured Energy in kilowatt-hours (kWh). The summation of the demand by the system during each hour of the period Energy The ratio of the energy produced by a power development option Payback over its expected useful life divided by the amount of energy required Ratio to build and operate the facility Firm The maximum output of a power development option that can be Capacity guaranteed 19 years out of 20 based on historical records Group A In the transmission analysis, the countries of Burundi, eastern DRC and Rwanda Group B In the transmission analysis, the countries of Kenya, Tanzania and Uganda Option A specific proposed means of developing and producing electricity. It applies to the technology used (hydro, thermal wind, solar, etc.) and to the specific plant as identified by its location (i.e. the Bujagali hydroelectric development or the Mchuchuma Coal-fired thermal plant PF or Plant The output of a power development option in GWh on average over a Factor year divided by the installed capacity in MW divided by the number of hours in a year, all multiplied by 1000. Portfolio A grouping of options that are developed over time during the period of analysis in order to meet the selected load forecast scenario Project A specific and existing means of producing electricity. Scenario A hypothesis of how a country or a region will develop over the period considered in the assessment. This applies in this work to the regional electricity needs assessment Strategy A deliberate pattern for the development of options (i.e. all hydro, all thermal, geographic diversification, etc.) Suppressed Electricity that is demanded by customers that the utility cannot Demand supply SSEA III - Final Report 3 017334-001-00 TABLE OF CONTENTS PAGE VOLUME 1 ­ MAIN REPORT NOTICE TO THE READER EXECUTIVE SUMMARY LIST OF ABBREVIATIONS 1 INTRODUCTION 1-1 1.1 Purpose of the Strategic/Sectoral Social and Environmental Assessment 1-1 1.2 Scope of the SSEA 1-1 1.3 Decision-making Context: Energy, Environment and Development 1-2 1.4 Context 1-2 1.4.1 Energy 1-2 1.4.2 Water Resources 1-3 1.4.3 The Nile Basin Initiative and the Strategic Action Plan 1-3 1.4.4 The Power Development Program of NELSAP 1-4 1.4.5 NBI Shared Vision and NELSAP Scaling-up Strategy 1-4 1.4.6 Specific NEL-COM Objectives for NELSAP 1-5 1.4.7 Lake Victoria Basin Vision and Strategy Framework 1-5 1.5 Organization of the Report 1-6 2 APPROACH AND ANALYTIC PROCESS 2-1 2.1 Organization and Conduct of the Assessment 2-1 2.2 Overall Approach 2-2 2.3 Key Elements in the Approach 2-4 2.3.1 Role of the Project Steering Committee 2-4 2.3.2 Stakeholder Consultation Process and Communication Strategy 2-4 2.3.3 Use of Existing Data 2-5 2.3.4 Variable Project Level Information 2-5 2.3.5 Climate Change Impacts 2-5 2.3.6 Selection of Options 2-6 2.3.7 Spatial and Temporal Boundaries 2-6 2.3.8 Selection of Strategies to secure supply under different development approaches 2-9 2.3.9 Distribution of Benefits 2-9 3 LEGAL, POLICY AND ADMINISTRATIVE CONTEXT 3-1 3.1 National Legal and Institutional Frameworks Related to Environment and Power Development 3-1 3.1.1 Environmental Impact Assessment Procedures and Legal Requirements 3-1 3.1.2 Land Ownership and Land Use Rights 3-1 3.1.3 Resettlement Policy and Regulations 3-1 3.1.4 National Parks and Protected Areas 3-2 3.1.5 Water Management (including irrigation) 3-2 3.1.6 Forestry 3-2 SSEA III - Final Report i 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE 3.1.7 International Environmental Commitments 3-2 3.2 The World Bank's `Safeguard Policies' 3-7 3.3 Energy Policy 3-7 3.3.1 Power Trading with Neighboring Countries 3-8 3.3.2 Attracting Investments and Facilitating Financing 3-11 3.4 Regional Institutions 3-12 3.5 Analysis, Conclusions and Recommendations 3-12 3.5.1 Analysis and Conclusions 3-12 3.5.2 Recommendations 3-13 4 CURRENT SITUATION IN THE REGION 4-1 4.1 Environmental conditions and issues 4-1 4.1.1 Lake Victoria Basin 4-1 4.1.2 Victoria Nile Basin 4-3 4.1.3 Lake Nyasa/Malawi Basin 4-4 4.1.4 Lake Tanganyika Basin 4-5 4.1.5 Rufiji River Basin 4-6 4.1.6 Tana River Basin 4-6 4.2 Socio-Economic Conditions and Issues 4-7 4.2.1 Regional Issues 4-7 4.2.2 Lake Victoria and Victoria Nile Basins 4-9 4.2.3 Lake Nyasa/Malawi Basin 4-10 4.2.4 Lake Tanganyika Basin 4-13 4.2.5 Rufiji River Basin 4-15 4.2.6 Tana River Basin 4-16 4.3 Regional Environmental and Socio-Economic Outlook 4-17 5 REGIONAL ELECTRICITY NEEDS ASSESSMENT 5-1 5.1 Introduction 5-1 5.2 Context 5-1 5.3 Key Issues 5-1 5.4 Demand Side Management 5-3 5.5 Loss Reduction 5-4 5.6 Current Regional Conditions in the Power Sector 5-4 5.7 Approach and Methodology 5-6 5.8 Regional Electricity Needs Assessment 5-7 5.8.1 Development Scenarios 5-7 5.8.2 Regional Electricity Needs Assessment Summary 5-9 6 IDENTIFICATION OF NEW POWER OPTIONS 6-1 6.1 New Electricity Generation Options 6-1 6.2 Thermal Power Options 6-5 6.3 Geothermal 6-6 6.4 Biomass 6-7 6.5 Wind Energy Conservation Systems 6-10 6.6 Demand Side Management and Loss Reduction 6-10 6.7 Imports from Outside the NELSAP Region 6-11 6.8 Off-grid Options 6-11 7 SCREENING OF NEW POWER DEVELOPMENT OPTIONS 7-1 7.1 Approach 7-1 7.2 Screening Criteria 7-1 SSEA III - Final Report ii 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE 7.3 Status of Environmental and Social Impact Assessments of Power Options 7-2 7.4 Results 7-3 7.4.1 Options that Passed the Screening 7-3 7.4.2 Rejected Options 7-3 8 RETAINED OPTIONS 8-1 8.1 General Environmental and Social Issues of Retained Power Options 8-1 8.2 Hydroelectric Options 8-3 8.2.1 Bujagali Hydroelectric Development 8-3 8.2.2 Kabu 16 Hydroelectric Development 8-3 8.2.3 Kakono Hydroelectric Development 8-4 8.2.4 Karuma Hydroelectric Development 8-4 8.2.5 Masigira Hydroelectric Development 8-4 8.2.6 Mpanga Hydroelectric Development 8-4 8.2.7 Mutonga Hydroelectric Development 8-5 8.2.8 Ruhudji Hydroelectric Development 8-5 8.2.9 Rumakali Hydroelectric Development 8-5 8.2.10 Rusumo Falls Hydroelectric Development 8-6 8.2.11 Ruzizi III Hydroelectric Development 8-6 8.2.12 Songwe Hydroelectric Development 8-7 8.2.13 Upper Kihansi Hydroelectric Development 8-7 8.3 Gas-fired and Coal-fired Thermal Options 8-7 8.4 Geothermal Power Options 8-8 8.5 Wind Power Options 8-8 8.6 Lake Kivu Methane Development 8-8 9 COMPARATIVE ANALYSIS OF POWER DEVELOPMENT OPTIONS 9-1 9.1 Steps Involved in the Multi-Criteria Analysis Method 9-1 9.1.1 Step 1: Identification of Evaluation Criteria and Indicators 9-1 9.1.2 Step 2: Determination of the Relative Importance of Criteria 9-3 9.1.3 Step 3: Ranking of Options for Each Criterion 9-3 9.1.4 Step 4: Ranking of Options within Each Category of Criteria 9-4 9.1.5 Step 5: Selection of Options to be Included 9-5 9.2 Ranking of Options 9-5 9.2.1 Technical Criteria 9-5 9.2.2 Ranking on Economic Criterion 9-5 9.2.3 Ranking on Social Criteria 9-6 9.2.4 Ranking on Environmental Criteria 9-7 10 RISK ANALYSIS 10-1 10.1 Introduction 10-1 10.1.1 Opposition from Pressure Groups 10-1 10.1.2 Institutional and Legal Framework 10-1 10.1.3 Public Health 10-1 10.1.4 Risks to Designated Habitats or Natural Sites 10-2 10.1.5 Risk to Sites of Exceptional Biodiversity Value 10-2 10.1.6 Use of Local Resources 10-2 10.1.7 Risks of Sedimentation 10-3 10.1.8 Gestation Period 10-3 SSEA III - Final Report iii 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE 10.1.9 Hydrological Risks 10-3 10.1.10 Financial Risks 10-3 10.2 Overall Assessment of Risk 10-3 11 RANKING OF OPTIONS 11-1 11.1 Introduction 11-1 11.2 Dilemmas Raised by Environmental and Socio-economic Considerations and by Project Risks 11-1 11.3 Ranking of Options 11-4 11.4 Best evaluated options 11-4 11.5 Other options 11-5 12 POTENTIAL IMPACT OF CLIMATE CHANGE ON RUNOFF 12-1 12.1 Introduction 12-1 12.2 Methodology Outline 12-2 12.2.1 Time Frame and Emission Scenarios 12-2 12.2.2 Climate Change Analysis 12-4 12.2.3 Evaporation and Runoff Analysis 12-4 12.3 Estimates of Climate Change for the Nile Equatorial Lakes Region 12-5 12.3.1 Selection of General Circulation Models 12-5 12.3.2 Results for Uganda and Rwanda 12-5 12.3.3 Results for Tanzania 12-6 12.3.4 Other Results for the Region 12-7 12.4 Potential Climate Change Impacts on Runoff 12-8 12.4.1 Methodology and Model Description 12-8 12.4.2 Modeling Runoff 12-8 12.4.3 Climate change runoff modeling approach 12-9 12.4.4 Climate Change Runoff Results - Annual Results for all Scenarios 12-9 12.4.5 Summary of Predicted Runoff Changes 12-10 12.5 Potential Impact on Generation Capability 12-10 12.5.1 General Conclusions 12-10 12.5.2 Specific Results 12-11 12.5.3 Overall Conclusions Related to Portfolio Development 12-11 13 POWER DEVELOPMENT PORTFOLIOS 13-1 13.1 Objectives of Portfolio Development 13-1 13.2 Definition of Portfolios 13-2 13.2.1 Main Portfolios Examined 13-2 13.2.2 Sensitivity to Load Growth 13-4 13.2.3 Sensitivity Analysis 13-4 13.3 Summary of Information 13-5 13.3.1 Power Need Assessment 13-5 13.3.2 Power Development Options Retained 13-5 13.3.3 Load-Resource Balance 13-5 13.4 Independent Approach, Primarily National Options and Base Growth Scenario ­ Portfolio 1Aa 13-9 13.5 Regional Approach, Best Evaluated Options and Medium Load Growth Scenario ­ Portfolio 2Bb 13-11 13.5.1 Definition of Portfolio 13-11 13.5.2 Transmission Requirements 13-12 SSEA III - Final Report iv 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE 13.6 Regional Approach, Technological Diversification, Medium Load Growth Scenario ­ Portfolio 2Cb 13-14 13.6.1 Definition of the Portfolio 13-15 13.6.2 Transmission Requirements 13-15 13.7 Regional Approach, Geographical Diversification and Medium Load Growth Scenario ­ Portfolio 2Db 13-16 13.7.1 Definition of the Portfolio 13-16 13.7.2 Transmission Requirements 13-18 13.8 Comparison of Strategies Using Medium Load Growth Scenario 13-18 13.9 Comparison of Strategies under Different Load Growth Scenarios 13-21 13.9.1 High Load Growth Scenario 13-22 13.9.2 Regional Approach, Transformation Scenario ­ Portfolio 2d 13-22 13.10 Sensitivity Analysis 13-24 13.10.1 Impact of Including Options with less than the Minimum Level of Data Available [Portfolio 2Cb (S1)] 13-24 13.10.2 Impact of Imports [Portfolio 2Cb (S2)] 13-25 13.10.3 Impact of Eliminating Comparative Analysis [Portfolio 2Cb(S3)] 13-26 13.10.4 Analysis of Results of Sensitivity Analyses 13-27 13.11 Need for Flexibility 13-27 13.12 Conclusions 13-29 14 ASSESSMENT OF CUMULATIVE IMPACTS 14-1 14.1 Definition 14-1 14.2 Approach 14-2 14.3 Defining the spatial boundaries and timeframe 14-3 14.4 Main Regional Trends and Issues 14-4 14.5 Definition of Strategies Followed 14-4 14.6 Independent Development Strategy 14-5 14.6.1 Concept of the "Independent Development" Strategy 14-5 14.6.2 Criteria for the "Independent Development" Strategy 14-6 14.6.3 Portfolios at the country level for the Independent Development Strategy 14-6 14.6.4 Cumulative impacts of the "Independent Development" Strategy 14-6 14.7 Cumulative Impacts of the Portfolio for Portfolio 2Bb (Regional cooperation, Best evaluated options and medium growth) 14-10 14.7.1 Cumulative Environmental Impacts 14-10 14.7.2 Cumulative Socio-Economic Impacts 14-20 14.7.3 Cumulative Impacts Downstream of the Nile Equatorial Lakes Region 14-25 14.7.4 Summary of Cumulative Impacts of the Portfolio 2Bb 14-25 14.8 Cumulative Impacts of Other Portfolios 14-26 14.8.1 Portfolio 2Cb ­ Technological Diversification 14-26 14.8.2 Portfolio 2Db ­ Geographical Diversification With Medium Load Growth 14-27 14.9 Conclusions 14-28 14.10 Mitigation Measures 14-29 14.10.1 Hydropower Options 14-29 14.10.2 Fossil-Fuelled Thermal Power Options 14-31 SSEA III - Final Report v 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE 15 CONCLUSION, RECOMMENDATIONS AND NELSAP INDICATIVE POWER DEVELOPMENT STRATEGY 15-1 15.1 Conclusions 15-1 15.2 Recommendations and NELSAP Indicative Power Development Strategy 15-3 15.3 Institutional Issues 15-8 SSEA III - Final Report vi 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE VOLUME 2 ­ APPENDICES Appendix A Terms of Reference Appendix B Country Specific Synopses of Environmental and Social Policies and Legal and Administrative Frameworks Appendix C EAC Protocol on Environment and Natural Resources Management Appendix D Country Specific Synopses of Energy Policies and Legal and Administrative Frameworks Appendix E Load Forecast Support Appendix F Identification of New Power Options Appendix G Planning Parameters and Costing of Options Appendix H Mitigation Measures Appendix I Project Data Sheets Appendix J Comparative Analysis of Options Appendix K Climate Change and Impacts on Runoff Appendix L Climate Change and Impacts on Runoff - an Alternative Estimate Appendix M Development of Portfolios Appendix N References and Sources of Documents SSEA III - Final Report vii 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE LIST OF TABLES Table 3-1 - Status of Principal International Conventions 3-4 Table 3-2 - World Heritage Sites in the Nile Equatorial Lakes Countries 3-6 Table 3-3 ­ List of Ramsar Wetlands in Nile Equatorial Lakes Basin Countries 3-6 Table 4-1 - Some Socio-Economic Indicators of the Economies of the Lake Victoria and Victoria Nile Basins 4-12 Table 5-1 - Comparison of Annual Electricity Consumption per Capita 5-2 Table 5-2 ­ Technical Losses 5-5 Table 5-3 - Summary of Generation Capacity in the Region 5-5 Table 5-4 - Load vs. Resources Situation in Countries under Analysis 5-6 Table 5-5 - Regional NEL Power Needs Assessment Summary 5-10 Table 5-6 ­ Incremental Capacity Requirements for the NEL Region (MW) 5-10 Table 6-1 - List of Identified Hydroelectric Projects in the East African Community 6-3 Table 6-2 - List of Identified Hydro-electric Options in Burundi, Rwanda and Tanzania 6-4 Table 6-3 - Identified Hydroelectric Sites in the Eastern DRC 6-6 Table 6-4 - NELSAP Region ­ New Thermal Power Options 6-7 Table 6-5 - NELSAP Region ­ New Geothermal Power Options 6-8 Table 8-1 - Overview of Major Impacts by Technology 8-2 Table 9-1 - Criteria and Indicators Used for the Comparison of Power Options on the Basis of the MCA Method 9-2 Table 9-2 - Weights assigned to Criteria Selected for the Comparison of Options on the Basis of the MCA Method 9-3 Table 9-3 - Ranking of Power Options on the Basis of Unit Costs (listed in order of increasing cost) 9-7 Table 9-4 - Ranking of Options within the Socio-economic Category (listed in order of increasing overall impact) 9-10 Table 9-5 - Ranking of Options within the Environmental Category (listed in order of increasing overall impact) 9-12 Table 10-1 - Ranking of Power Options on the Basis of Risks (listed in order of increasing risk) 10-5 Table 11-1 - Options to be considered in Power Development Portfolios (listed in order of increasing unit cost) 11-4 Table 12-1 - New hydro options in the indicative plan 12-1 Table 12-2 - IPCC emission scenarios3 12-2 Table 12-3 - Projections for Uganda and Rwanda for the A1B scenarios 12-6 Table 12-4 - Projections for Tanzania for the A1B Scenarios 12-7 Table 12-5 - Annual runoff changes relative to the Base (1961-1990) 12-10 Table 12-6 - Impact of Climate Change on Runoff (Generation) for Preferred Hydro Options 12-13 SSEA III - Final Report viii 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE Table 13-1 - Nomenclature Used in Portfolio Development 13-2 Table 13-2 - Selected Growth Scenarios 13-6 Table 13-3 - Options to be considered in Power Development Portfolios (listed in order of increasing unit cost) 13-7 Table 13-4 - Load Resource Balance 13-8 Table 13-5 ­ Portfolios Reflecting an Independent Approach and the Base Load Growth Scenario 13-10 Table 13-6 - Comparison of Portfolios for Each Strategy of the Regional Cooperation Approach 13-19 Table 13-7 - Comparison of Portfolios Using Medium Load Growth Scenario 13-21 Table 13-8 - Comparison of Portfolios for Alternative Load Growth* Scenarios 13-23 Table 13-9 - Comparison of Strategies to various Load Growth Scenarios 13-24 Table 13-10 - Comparison of Sensitivity Tests Using Medium Load Growth Scenario 13-28 Table 14-1 - Steps in Cumulative Impact Analysis 14-2 Table 14-2 - Portfolio of Development Options for the Independent Development Strategy 14-7 Table 14-4 ­ Types of Cumulative Impacts for Various Activities 14-11 Table 15-1 ­ NELSAP Indicative Power Development Plan 15-5 Table 15-2 - Power Development Options Not Used in Indicative Power Development Plan 15-6 Table 15-3 ­ Urgent Actions Required to Achieve On-Power Dates 15-9 SSEA III - Final Report ix 017334-001-00 TABLE OF CONTENTS (cont'd) PAGE LIST OF FIGURES Figure 2-1 - Organisational Structure for SSEA 2-1 Figure 2-2 - Process Followed for SSEA of Power Development Options 2-2 Figure 2-3 ­ Overview of Nile River Basin Countries 2-7 Figure 2-4 - Nile River Basin at Lake Victoria 2-8 Figure 2-5 - The Democratic Republic of Congo ­ Provincial Map Showing the Region under Analysis 2-8 Figure 4-1 - Definition of Watersheds 4-2 Figure 5-1 - Regional Power Needs Assessment in the NEL Region for the Period 2005-2020 5-11 Figure 5-2 - Regional Power Needs Assessment per Country ­ Medium Scenario 5-12 Figure 6-1 - NEL Region - Identified Options and Existing Transmission Lines 6-9 Figure 7-1 - Retained Candidate Power Options 7-17 Figure 7-2 - Retained Candidate Power Options in Southern Tanzania 7-18 Figure 7-3 - Retained Candidate Power Options in Rwanda-Burundi Border 7-19 Figure 7-4 - Retained Candidate Power Options in Uganda ­ Lake Victoria Area 7-20 Figure 7-5 - Retained Candidate Power Options in Kenya-Tanzania Border 7-21 Figure 7-6 - Retained Candidate Power Options in Eastern Tanzania 7-22 Figure 9-1 - Comparison of Options on Basis of Economic Viability 9-9 Figure 9-2 - Comparison of Options on the Basis of Socio-economic Issues 9-11 Figure 9-3 - Comparison of Options on the Basis of Environmental Issues 9-13 Figure 10-1 - Comparison of Options on the Basis of Risks 10-6 Figure 11-1 - Comparison of Options on the Basis of Cost, Socio-economic, Environmental and Risk Issues 11-3 Figure 12-1 - NEL Region - Options in plan and hydrologic areas of interest 12-3 Figure 12-2 - Simplified Version of the WATBAL Model that is used to Compute Gridded Runoff 12-9 Figure 13-1 - Transmission Requirements 13-17 Figure 13-2 - Present Worth of System Investment, Operating and Fuel Costs 13-20 Figure 14-1 - Main regional trends 14-5 Figure 14-2 - Estimated Stress on Water Resources in 2025 14-10 Figure 15-1 - Map Showing Regional Development of Power and Transmission Requirements to 2015 (Regional Approach, Technological Diversification Strategy and Medium Load Growth Scenario) 15-10 SSEA III - Final Report x 017334-001-00 APPENDIX A TERMS OF REFERENCE SSEA III - Final Report 017334-001-00 APPENDIX A - TERMS OF REFERENCE Nile Equatorial Lakes Subsidiary Action Program (NELSAP) A TERMS OF REFERENCE A.1 Terms of Reference for Stage II (section 5 of World Bank Request for Proposal) IV. SCOPE OF WORK The Study will primarily build on the outputs of the SSEA of Power Options Stage 1, the East African Power Master Plan (Kenya, Tanzania, and Uganda), and the power master plans for each of the six countries and build on other recent studies in the context of e.g. East DRC and Uganda. The scope of work of the NEL-wide SSEA of Power Development Options will include, but not be limited to the following seven key steps: 1. Assessment of the Energy Policy, and Relevant Legal and Administrative Frameworks in D.R.C. - East1, Kenya, and Uganda. Analyze both (i) the social and environmental legal, regulatory and institutional framework and capacity in the three NEL countries as it relates to power development and rehabilitation2, and (ii) energy sector policies, regulations, guidelines and institutions3. The assessment should assess whether environmental and social issues are adequately covered by current practice in the energy sector. The process requires a review of these policies, regulatory frameworks and institutional capacity to identify and address elements that may hinder implementation. The assessment will integrate the findings of Stage 1 to provide a comprehensive picture of the policy, legal and administrative framework in the Nile Equatorial Lakes Region. 2. Energy Needs Assessment An assessment of energy needs for the next 20 years in D.R.C.- East4, Kenya, Tanzania and Uganda will be carried out based on the national access policies and targets set by their respective governments as well as affordability considerations. (Energy needs means electrical energy needs.) The demand projections need to be linked to these policies and its financial feasibility needs to be assessed. All energy needs at the national level will be considered during this assessment in order to identify and extract the grid-based electricity needs that will be further analyzed in this study. 1 Even tough this study will focus on power options in DRC-East, it is important to recognize the country wide policy and legal framework where relevant. For example, in looking at the institutional framework, the study needs to look at aspects relating to the power utility - Societe Nationale D'Electricite du Congo (SNEL)- which is more active in other parts of the country, but is also the relevant player in DRC-East. 2 Including reviewing of existing framework and practice of stakeholder participation processes in infrastructure project identification, design, and implementation, and resettlement policies. 3 This will include review of policies and possible barriers for private sector investment in power sector in the region and especially identify challenges for regional power trade. 4 See footnote 2. SSEA III - Final Report A-1 017334-001-00 APPENDIX A - TERMS OF REFERENCE The demand projections from stage 1 of the SSEA will be integrated with the demand projections from the three countries assessed to provide a comprehensive picture of the energy demand in the Nile Equatorial Lakes Region. 3. Power Options Identification The inventory of power development options (including transmission interconnections) in D.R.C.- East, Kenya, Tanzania and Uganda must respond to agreed development objectives, identified in the needs assessment performed for the four countries building on the Stage 1 of the SSEA and the EAC Power Master Plan. The inventory of power options needs to be sufficiently diverse in terms of technology options, scale, and geographic coverage. The power options will include hydropower, gas, oil, coal, geothermal etc., as well as optimizing existing investments by increasing operational efficiency and improving productivity, and demand side management. For the purpose of a sub-regional program such as NELSAP, the analysis should prioritize those options that will provide benefits to more than one country. The inventory will be based both on identified and available information as well as on information obtained by the consultant from similar projects and publicly available information from various literature sources, advertising, etc. It should a) consider all power projects of 10 MW or more; and b) use expert judgement to select or reject schemes under 10 MW identified in the course of the study, keeping in mind the criteria of regional cooperation. Import options and connection to foreign grids should also be considered if relevant for the Nile Equatorial Lakes Region. The consultant should for comparison purposes, include some "virtual projects" for thermal (combined cycle), wind, solar, and diesel options. A two tiered approach to the analysis of alternatives will be applied in order to identify the best power options available to meet the electricity requirements of the countries, taking into consideration the multi-purpose nature of some of the available options. First, a screening process of all technologies available will be undertaken based on factors such as availability of the technology to meet the identified project objectives, availability of resource requirements (at a macro-level), suitability in a particular situation, financial viability etc. Secondly, screening of alternative locations should consider the availability to meet project objectives, resource requirements for short- listed technologies, and broad environmental, social and economic considerations. This second screening will allow to eliminate those power options with unacceptable social and environmental consequences such as significant conversion or degradation of natural habitats, significant involuntary resettlement/loss of livelihoods and significant regional impacts up- and downstream. This second screening process should define a realistic range of alternatives for further consideration in the next steps. Power options could include bundles of projects mixing appropriate technologies. A methodology to compare options at different levels of maturity should be developed to avoid unjustifiably eliminating options, which may be good but could be handicapped, if they are compared with options that are at a more advanced study level. The assessment will integrate the power options identification of stage I to provide a comprehensive picture of the power options identified in the whole NEL region" 4. Cumulative Impacts Assessment The cumulative impact assessment will estimate (or forecast) the potential cumulative impacts of the power options (bundles of projects or individual projects) identified on the region's environment, natural resource base, and socio-economic conditions, taking into account the baseline situation, and power options identified under point 3. SSEA III - Final Report A-2 017334-001-00 APPENDIX A - TERMS OF REFERENCE above for the six countries. The first step will undertake limited, preliminary impact assessments of the major individual investments under consideration not addressed under Stage 1 of the SSEA or the EAC Power Master Plan. Where data is available it should be used. The second step is to look at the sum total of the individual activities and estimate their cumulative effects (positive and negative, direct and indirect, short-term and long-term)5 from a Nile Equatorial Lakes basin-wide perspective including potential effects on downstream riparians (Egypt and Sudan). 5. Risk Analysis A general analysis of financial, economic, environmental and social risks should be undertaken for the power options (bundles of projects or individual projects) because of the high levels of uncertainty and the potentially large impact of a low probability event (particularly drought). The results of the risk analysis should also serve as one of the criteria for the comparative analysis. 6. Comparative Analysis of Power Options The consultant will construct a table or matrix that summarizes an assessment of each option identified - including priority options identified under Stage 1 of the SSEA of Power Options and the EAC Power Master Plan - with regard to a range of criteria including political, economic and social, financial, technical, environmental, and legal and institutional (see annex 1). The matrix would present decision criteria on one axis and options on the other, with cells containing either qualitative or quantitative information as appropriate. The consultants will also propose a systematic approach to compare the different options with regard to each category of assessment criteria (Comparisons across categories of assessment criteria will involve normative judgements and are therefore beyond the scope of this study). The comparative methodology might involve the application of scaling, rating or ranking techniques. The methodology will be submitted to the project steering committee for approval. 7. Mitigation Plan for Selected Power Option Alternatives: After the Project Steering Committee has selected power options from the list of alternative assessed in stages I and II, the consultant will determine what can be done to mitigate, reduce or eliminate negative effects and enhance positive effects of the selected (high ranking) power option alternatives (stand alone projects or bundles of projects) from a Nile Equatorial Lakes perspective. The analysis would recommend broad strategic plans for eliminating, reducing to acceptable levels, or mitigating environmental and social impacts. V. PUBLIC CONSULTATION Public consultation is an integral part of the assessment. A communication program, including a clear communication strategy and consultation plan, is required to be developed including the tasks described below. The communication program will be submitted to the steering committee for approval. a) Stakeholder analysis: Stakeholders who should be involved in consultations will first be identified. Since the sub-regional strategic/sectoral social and environmental assessment of power development options will not assess the details in project location and design but more the general impacts of the projects, the contribution will primarily be from regional and national representatives of the relevant interest groups and not from potentially impacted 5This will assess likely cumulative impacts of regional significance and will not substitute for a more detailed project level assessment within a site specific EA later on. SSEA III - Final Report A-3 017334-001-00 APPENDIX A - TERMS OF REFERENCE individuals. The likely concerns of local people6, especially in the case of potential hydropower projects, will be articulated through representative bodies, such as district administrations. Civil society will be represented through representatives of the Nile discourse and other civil society organizations (see below). A stakeholder inventory will include a description of the mission of each stakeholder and, when appropriate, of their membership. Main categories of stakeholders to be considered are the following: · Ministries (incl. Energy, Natural Resources, Water Resources, Environment, Agriculture, Transport and Communication, Fisheries, Health and Social Welfare of the six upper NEL countries); · Local administrations concerned by specific projects; · Power utilities of the six countries; · Civil society organizations dealing with gender inequalities, indigenous people, poverty alleviation, rural development, environment at national level etc.; · Universities and other academic institutions with relevant specialist knowledge. · Religious communities that play a key role in the development of the sub-region. b) Methods to solicit stakeholder input and definition of consultation rules: Subjects to be submitted to stakeholders will be defined in accordance with the six main steps of the strategic/sectoral social and environmental assessment of power development options described above: assessment of energy policy, legal and institutional frameworks; energy needs assessment; power options identification, cumulative impacts assessment; comparative analysis of options; and mitigation plans for selected power option alternatives. For consultation purposes, the first two or three subjects may be combined. A typical approach will be the following: · Providing background information on the subject(s) submitted to stakeholders; · Soliciting comments on various courses of action related to the subject(s); · Gathering stakeholder viewpoints; · Providing feedback on decisions taken; · Stakeholder workshops. Rules will be defined about the role of the various actors in the process: stakeholders, steering committee and consultant team. The schedule and the expected output of the process will also be defined in detail. A draft schedule is outlined in section seven of these TOR. c) Information and consultation tools: Tools will also be defined for information dissemination and consultation. These tools will be adapted to cultural sensitivities, social and economic organisation and political structures. They may include: · Use of e-mails; 6Sensitive population groups include the Pygmies, mostly Batwas, that are present in the region. They represent a special concern both from the perspective of the Bank's safeguard polices, but also from the cultural and social perspective of very sensitive societies. Such groups need to be taken into account during the stakeholder identification and analysis phase. SSEA III - Final Report A-4 017334-001-00 APPENDIX A - TERMS OF REFERENCE · Establishment of a web site; · Synthesis documents; · Documentation centre; · Information sessions (e.g. in form of "open houses" at national NBI offices); · Workshop discussions; · Public hearings. VI. OUTPUTS/DELIVERABLES Key outputs include the following deliverables proposed to be prepared in the order below (see also section 7). Stakeholder workshops7 and Steering Committee Meetings are proposed to be organized back to back. a) Inception report (draft and final), including the detailed methodology and the stakeholder consultation plan that will be adopted to carry out the NEL-wide strategic/sectoral social and environmental assessment of power development options. The draft report will be presented first to the World Bank and the PSC for comments before the final report is produced. A two weeks time period would be allocated for submission of comments. b) Draft report No. 1 on the assessment of the (1) policy, legal and regulatory framework, (2) energy needs assessment, (3) power options identification and (4) cumulative impacts assessment. The report should also include a proposed methodology to undertake the comparative analysis of power options (5). c) Organization of first Steering Committee Meeting (SCM #1). d) Organization of first stakeholder consultation workshop (SW #1) and report on the workshop, feedback received and annexed list of participants e) Draft Report No. 2 on comparative analysis of (5) power options and (6) mitigation plan. Report 2 will also document the stakeholder consultation process (incl. Information provided and feedback received through various information and consultation tools. f) Organization of second Steering Committee Meeting (SCM #2). g) Organization of second stakeholder consultation workshop (SW #2) and report on the workshop, feedback received and annexed list of participants. h) Draft final report will be presented to the World Bank and the PSC for comments before the final report is produced. A two weeks time period would be allocated for submission of comments. i) Final report. 7The two regional stakeholder workshops are one tool in an overall communications and stakeholder involvement program, which will be developed by the consultant. The communications program will include a broad range of tools and time schedule for consultations on local, national, and regional level. SSEA III - Final Report A-5 017334-001-00 APPENDIX A - TERMS OF REFERENCE A.2 Clarifications - SSEA Stage 2 TOR Objective The purpose of this note is to inform the World Bank Nile Team that the clarifications on the SSEA Stage 2 Terms of Reference have been accepted by the Project Steering Committee Members who responded to our request. Therefore NELSAP-CU would like to request the World Bank Nile Team to request in turn the Consultant to include the suggested clarifications in the stage 2 of SSEA. Background Subsequent to the 5th PSC Meeting held at Paraa Lodge in Uganda, a Team consisting of the NELSAP-CU Program Officer Power Projects and the World Bank Nile Team traveled to in Uganda and in Kenya to brief the PS/Energy Ministry and the Managing Directors of power utilities and seek guidance on the NELSAP power projects. Key issues related to the terms of reference for stage 2 of SSEA assignment and stakeholder consultations came up in each meeting. In this context, the Team thought necessary to clarify the terms of reference for SSEA stage 2. The discussions continued at Kigali with the NELSAP Coordinator. As PSC members have also mentioned the need for a clarification of terms of reference for stage 2 of the SSEA assignment during the meeting held between the NELSAP-CU and the NEL power experts on 1st December 2004 after the full PSC meeting, NELSAP-CU requested also from PSC comments on TOR for SSEA stage 2. The PSC found the clarifications of the SSEA Stage 2 Terms of Reference reasonable. Therefore on behalf of the PSC, NELSAP-CU suggests for the stage 2 of SSEA to include three activities (suggestions) in the scope of work, as listed below: A NEL Backbone Regional Transmission Interconnection Network During deliberations at the 5th PSC Meeting it became abundantly clear that to realize the benefits of regional integration through power trade, each power generation option needs to benefit two or more countries and this requires in turn an interconnected network. Suggestion One option to realize this benefit is to develop a backbone regional transmission interconnection network (BReTIN) connecting the power systems of the six NEL countries, and to interconnect a power generation option to the nearest point on the BReTIN. In terms of developing the BreTIN, it is conceivable to develop new transmission lines as well as required reinforcement of existing lines to allow the NEL network to operate as one network. SSEA III - Final Report A-6 017334-001-00 APPENDIX A - TERMS OF REFERENCE B. NEL Regional Power Master Plan - System Planning (including transmission) Model The NEL power experts agreed that the stage 2 of the SSEA should essentially build upon the outcomes of SSEA stage 1 and EAC Power Master Plan and as such, stage 2 of SSEA will not require a fresh identification of new power options and screening of options (except yet to be identified Eastern DRC options), but will require preparation of a NEL power development strategy, that is a NEL Regional Power Master Plan to meet the long term load forecast for the NEL region. Therefore, the power generation options for stage 2 of SSEA will comprise options identified under stage 1 for Burundi, Rwanda and Western Tanzania (isolated network), options identified in the EAC Power Master Plan for Kenya, Tanzania, and Uganda, and the options identified in Eastern DRC. The combined set of options include hydropower, thermal power, purchased power from neighboring countries such as DRC and Zambia, and power purchase from independent power producers. The attached flow chart presents the clarification of the scope of work. SSEA of Power Development Options Stage 2 Burundi, DRC, Kenya, Rwanda, Tanzania, Uganda 1. Policy, legal & administrative review Given: EAC Power Master Plan 2. Regional Power needs assessment Kenya, Tanzania, Uganda 3. Inventory, screening & ranking of projects in DRC 3rd Stakeholder consultations in DRC All projects 4. System planning (including transmission) & simulation for 6 countries SSEA Stage 1 "Indicative sub- regional power development 5. Definition and preparation of project portfolios plan" to meet NELSAP power demand Burundi, 6th Project Steering Committee Rwanda, W Tanzania 6. Cumulative impacts, risks assessment & tsceojrp AESS mitigation measures on portfolios 1 e d ag 7. Indicative regional power master plan ­ least ttei St & cost mmoC CAE 4th Regional stakeholder consultations 7th Project Steering Committee Project preparation & SSEA OUTPUT: NELSAP Indicative implementation at Power Master Plan appropriate level Suggestion NELSAP-CU suggests that the TOR be made more clear by requiring the consultant to use a system planning model to prepare a NEL Region Power Master Plan that will present a least-cost optimum mix of power options ­ a portfolio of power generation options for different scenarios (similar to the scenarios in stage 1 of the SSEA). In analyzing each of the least-cost portfolios, the cost of the power generation option will include transmission costs to the nearest point of interconnection on the BReTIN system. Essentially, the "committed" power options in both the SSEA Stage 1 "Sub-Regional Indicative Power Plan" and the EAC Power Master Plan will be treated as fixed, and un- committed options will either be accelerated or delayed depending on the results of the system planning model. In presenting the results of each of the portfolios, the consultant will SSEA III - Final Report A-7 017334-001-00 APPENDIX A - TERMS OF REFERENCE prepare in a tabular format, the levelized energy cost, levelized capital cost, and levelized transmission cost, for each of the regional power generation portfolios. A C. Stakeholder Consultations Option 1 Two "regional" stakeholder consultations will be organized, one at the beginning, say in March 2005 to explain the SSEA process and consider the views of the stakeholders, and a second one in June 2005 to disseminate the results of the SSEA stage 2 assignments. Option 2 In SSEA stage 2, two stakeholder consultations will be held, one in eastern DRC for the new options that may be identified and another one, a regional consultation to seek inputs to the power options selection and portfolio selection. Expand the regional consultation meeting to include NEL senior officials (level of Permanent Secretary) in the ministry responsible for electricity matters. Suggestion: Based on meetings with the PSC power experts in Murchison Falls and subsequent meetings with the PS/Energy in Kenya and Uganda and with the MD of KPLC, NELSAP-CU recommends Option 2 because the regional consultation meeting could be expanded to include the participation of the Permanent Secretaries responsible for electricity in the six NEL countries. This will also deepen the engagement of NEL senior officials in the ministry responsible for electricity matters, and strengthen the linkages between EAC and NELSAP. Furthermore, the regional consultation can be organized within the existing budget for the previously contemplated two regional consultations. A.1 Terms of Reference for Update Task 1. Environmental and Social Policies and Legal and Administrative Framework (Section 3) Section 3 should be retitled ("Legal, Policy and Administrative Context") and revised to provide a more comprehensive review of the applicable environmental and social policies, laws and administrative structures in the cooperating countries. This information is necessary and is part of an SSEA. This section needs to include a review of the international and regional environmental conventions that the cooperating countries are party to in order to meet the requirements of the World Bank that the actions we consider are consistent with countries obligations under international law (World Heritage Convention, Ramsar Convention, etc.). The section needs to begin with the environmental and social aspects (national and international) and follow with power and investment aspects. The Bank will provide the consultant with some additional source information for the first section(s). Section 3.6 ­ "Possibilities of Development in National Parks." needs to be revised and retitled as "Constraints on Developments in Parks and Protected Areas". This is especially important given the policies of most multilateral development banks and bilateral donors that do not allow or significantly restrict support to development in parks and protected areas. The section will discuss such national legal/policy constraints, as well as those deriving from international/regional agreements. It will also specify similar policy constraints by the MDBs and bilaterals. Task 2. Environmental and Social Issues of Retained Power Options (Section 8) This section, and the preceding Section 7, needs to clearly describe (and re-emphasize as needed) the analytical process being employed ­ such as screening, MCA/risk analysis, portfolio development, and the criteria being used at each step. Similarly, wherever relevant, the analysis must emphasize that some of the proposed options are not acceptable under normal environmental and social criteria such as those involving major investment in parks SSEA III - Final Report A-8 017334-001-00 APPENDIX A - TERMS OF REFERENCE and protected areas; are only retained through the screening and MCA/risk analysis steps at the insistence of the country partners; and are dealt with appropriately at the portfolio development step (i.e. these options are not considered until absolutely necessary to meet demand projections). The analysis needs to provide significantly more depth on the environmental and social issues associated with the various power development options. This needs to include: direct and indirect upstream, site and downstream impacts, especially to aquatic habitats and fisheries; physical cultural resources; and management of HIV/AIDS and other sexually transmitted diseases as an issue associated with construction activities. The evaluation also needs to be included for the proposed transmission investments which will ultimately require detailed environmental and social impact assessments. To date, the SSEA has been based on environmental/natural resource information gathered from project reports made available to the project team through the SSEA process. The increased depth and breadth of analysis outlined above will require broader collection of additional secondary information on environmental and natural resource conditions in the project areas. Primary data collection is not expected. Additional secondary information could be gathered using local consultants. In his technical proposal, the Consultant will provide a detailed assessment of what information is already in hand, and what is needed and available for meeting the objectives of these TOR. The proposal will include a plan for gathering adequate new information to support meeting those objectives. During implementation of the assignment, the Consultant is expected to alert the Bank about any difficulties with obtaining the required information, and agree an action plan for addressing those difficulties. Task 3. Cumulative Impact Assessment The SSEA provides a preliminary assessment of potential cumulative impacts from the power development portfolios recommended in the study. The aim of this supplemental work is to have a full Section prepared for the Main Report supported by appendices that provide a clearer assessment of those cumulative impacts at the regional, basin, sub-basin levels as well as to identify alternative actions and formulate appropriate mitigation measures and monitoring. Programmatic mitigation and monitoring measures need to be developed since, currently; the mitigation measures proposed by the SSEA are too focused on individual projects. The cumulative impacts will concentrate on the baseline development portfolio. For the other portfolios, the differences in impacts and consequent mitigation measures from the first one will be noted. The process and rationale for this approach will be clearly described. The types of cumulative impacts that need to be explored include: · Define the environmental and social baseline for comparative analysis · Additive impacts of projects that individually have an insignificant impact but in total have a significant impact · Synergistic impacts where several projects' total impacts exceed the sum of their individual impacts · Threshold/saturation impacts where the environment may be resilient up to a certain level and then become rapidly degraded · Induced impacts where one project may trigger secondary development and its impacts · Time or space-crowded impacts where the environment does not have time to recover from one impact before it is subject to the next one · Direct and indirect impacts where an impact (e.g. changed downstream flow regime) causes another impact (e.g. reduced fish numbers) and perhaps another (e.g. reduced fisheries). · Include an analysis in each major transmission corridor of the cumulative impacts of investments in transmission given the access that is created by these activities which are incorrectly identified as having no impact in the current draft report. SSEA III - Final Report A-9 017334-001-00 APPENDIX A - TERMS OF REFERENCE · Time or space-delayed impacts (direct or indirect) where the impact is triggered at some time or distance away from the initiating change. The following principles should be followed in the identification of cumulative impacts: · Include past, present and reasonably future "other actions" as discussed in the current NELSAP SSEA report (15 years). · Identify cumulative impacts that are short, medium and long-term in their nature. · Focus on vulnerable resources, ecosystems and human communities. · Focus on impacts likely to be significant and/or irreversible. · Factor into the analysis the findings from work on climate change issues (see Task 4 below). The following steps are anticipated for the cumulative impact analysis: · Scope the analysis: 1. Bound the assessment in terms of the geographic scope (most likely by river basin), and timeframe (same as the SSEA analysis ­ 15 years). 2. Identify other actions affecting the resources, ecosystems and human communities. 3. Identify the resources and resource uses that could be subject to cumulative impacts such as flow regime, water quality and quantity, riparian and aquatic vegetative resources, wildlife, fish and fisheries, agriculture, irrigation, water supply, tourism, river navigation, and physical cultural resources. 4. Include an analysis of risk associated with HIV/AIDs and other sexually transmitted diseases. 5. Identify potentially significant cumulative impacts associated with the projects proposed in the baseline portfolio along with the other actions. · Describe the affected environment: 6. Describe the resources, ecosystems and human communities identified in the scoping step in sufficient detail to support the subsequent analysis of cumulative impacts 7. Characterize the existing stresses on these resources, ecosystems and human communities, as well as their capacity to withstand or adapt to change. · Analyze the cumulative impacts: 8. Forecast the significant cumulative impacts in terms of their magnitude, geographic scope, duration, frequency, reversibility, and likelihood of occurrence. Factor in potential climate change effects. 9. Make recommendations to modify, or add measures to, investments making up the development portfolio in order to avoid or minimize significant cumulative impacts. 10. Recommend management and monitoring measures. 11. Recommend further research priorities to fill vital information gaps in targeted areas so as to facilitate future environmental assessment of project options, and the potential cumulative effects of their implementation. As with Task 2 above, it is anticipated that the information gathered so far for the SSEA will be insufficient for completing the work described above, and that additional existing information will need to be gathered on the resources, ecosystems and human communities involved. SSEA III - Final Report A-10 017334-001-00 APPENDIX A - TERMS OF REFERENCE Task 4: Climate change analysis A key issue is the evaluation of potential management and investment actions in the NELSAP Region, in the short. medium and long term will be the implications of climate change and/or variability. This is a critical emerging issue in water resources management and should be integrated into the analytical work of the SSEA. Priority should be given to assessment of risk to existing and proposed infrastructure, land and water management issues and actions to be considered to support "adaptation" that should be included as an element of the proposed priority investment program or change that should be made to the investment program. According to the IPCC, "climate change has impacted, and is likely to impact, even more strongly in the future, all hydrological processes and regimes" at the global and regional scale. For the purpose of the SSEA it is therefore important to assess the state-of-the-art of our understanding of the relationships between climate and hydrological and production systems in the NELSAP region, and how climate change may affect them. Extreme hydrological events, such as floods and droughts, are of specific interest and relevance (blue water). The longer term impacts on crop production because of the change in access to stored water in the landscape as well as in the root zone (green water) are also critical for the productivity in the NELSAP region. African countries and in this case the Nile Equatorial Lakes countries do not contribute significantly to world GHG emissions. Egypt may be an exception in this case. GHG emission rates observed in African countries remain negligible due to their low level of industrialization. It is estimated that the continent as a whole produces less than 7% of total emissions and only 4% of CO2 emissions. On the other hand, Africa is one of the regions of the world that is particularly vulnerable to the potential impacts of climate change. From the perspective of sustainable development, African countries must be aware of the opportunities and possibilities for choosing environmental options. These options must be examined in light of the development priorities of each of the countries. The following steps should be included in the analysis: · An overall scientific, technical and socio- economic assessment of key climate change models with a focus on information relevant for the understanding of climate change, its potential impacts and options for adaptation and mitigation in the NELSAP region8. Deficiencies in current key models (poor performance at spatial and temporal resolutions applicable to regional NELSAP water cycle) should be discussed. · Draw conclusions on possible impacts of climate change focusing on the impacts to blue and green water in the NELSAP region. · Apply the findings on climate change to the cumulative impacts work so that conclusions can be drawn on potential impacts of climate change and possible mitigation measures on the base case scenario. · The information should be adapted to the other strategies in the NELSAP Indicative Power Master Plan. Task 5: Analysis of the "No Action" Alternative Currently the SSEA does not include a baseline scenario of the social and environmental impacts of the "no action" alternative. No action, in this case, refers to an expanded power development investment program not being undertaken at the regional and national levels in the NELSAP Region. This would include no new investment in generation, transmission or 8In this context NELSAP includes eight 8 countries (Burundi, DRC, Kenya, Rwanda, Tanzania, Uganda and Egypt and Sudan). For DRC the focus should be on Eastern DRC. The White Nile basin system and downstream impacts in Sudan and Egypt should be assessed, including cumulative impacts in the upper Congo basin and other in-country and inter-country basins in the region. Cumulative impacts may also be beyond the basin. SSEA III - Final Report A-11 017334-001-00 APPENDIX A - TERMS OF REFERENCE distribution facilities over the period being considered. The range of strategic development scenarios in the NELSAP Indicative Power Master Plan should also include a base-line scenario of no action. The following steps should be included in the analysis: · A qualitative analysis of the environmental and social impacts of no action. · The no action scenario included in the SSEA report where relevant and in the section on the NELSAP Indicative Power Master Plan. Task 6: Screening of New Power Options (Section 7) The SSEA necessarily had to eliminate from consideration project options which have not reached the prefeasibility level of study. For each of these options, the Consultant will provide a short analysis of the studies required to have them seriously considered in a future Indicative Power Master Plan, both in terms of their feasibility (hydrological, engineering, financial, etc.), and of their potential environmental and social impacts. The analysis should be presented in a new appendix to the Main Report. Task 7: Editorial work · Revise the presentation and edit the report to ensure that it provides the reader a report that is a Strategic/Sectoral Environmental and Social Assessment of an energy investment study rather than, as it currently is presented, as an energy investment study that makes reference to environmental and social assessment issues. The report needs to inform decision makers; including the cooperating governments, financial institutions and the public, about the environmental and social implications of the proposed energy investment program. · Restructure Sections and revised their titles to more fully reflect the SSEA approach and process. · Edit the report to include information related to Tasks 1 through 6 above. · In addition, the editing process should: o Ensure the report, wherever appropriate, documents situations that may not be compliant with World Bank policies. These sections will be closely reviewed, and perhaps edited, if necessary, by the World Bank to ensure their accuracy o Provide text that records the agreement between the World Bank and Uganda with regard to the Kalagala offset and the Bujagali power options (text to be provided by the Bank). · The draft final report may be copy edited by the World Bank for use by the Consultant. Any Consultant concerns with such edits will be discussed with the Bank before the report is finalized. This provision in no way diminishes the responsibility of the Consultant to carry out these terms of reference to meet best international practice. · Update and edit the Synopsis Report to reflect the structure and content of the new Main Report resulting from the work described above. · If necessary, update the Appendices to include new information related to the tasks outlined above. SSEA III - Final Report A-12 017334-001-00 APPENDIX B SYNOPSIS OF STAKEHOLDER CONSULTATIONS SSEA III - Final Report 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS TABLE OF CONTENTS PAGE B SYNOPSIS OF STAKEHOLDER CONSULTATIONS B-1 B.1 Introduction B-1 B.1.1 Context and Objectives of the Stakeholder Consultation Process B-1 B.1.2 Purpose of Stakeholder Consultation Process B-1 B.1.3 Planning of Stakeholder Consultation Process B-1 B.2 Contribution of Stakeholder Representatives to Stage I of the SSEA B-3 B.2.1 Comments Provided by Stakeholder Representatives in the Sub-region B-3 B.2.2 Comments Provided by Stakeholder Representatives During Workshops B-4 B.2.3 Main Lessons Learned from Stage I of the Stakeholder Consultation Process B-17 B.3 Contribution of Stakeholder Representatives to Stage II of the SSEA B-19 B.3.1 Discussions Held During Information Gathering Missions B-19 B.3.2 Organisation of Stakeholder Workshops B-23 B.3.3 Comments Provided by Stakeholder Representatives During Workshops B-24 B.3.4 Evaluation of Stakeholder Workshops Outcomes B-40 B.3.5 Main Lessons Learned from Stage II of the Stakeholder Consultation Process B-41 SSEA III - Final Report B-i 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS B SYNOPSIS OF STAKEHOLDER CONSULTATIONS B.1 Introduction This Appendix provides a summary overview of stakeholder consultations carried out during Stages I and II of the SSEA of Power Development Options in the Upper Nile Basin. B.1.1 Context and Objectives of the Stakeholder Consultation Process The Stakeholder Consultation Reports produced for Stages I and II of the SSEA present the context, objectives, process and results of the stakeholder consultation process that was put into place for the SSEA. In the context of the SSEA, "stakeholders" were defined as those that are potentially affected by the outcome ­ negatively or positively ­ or those who can affect the outcome of the proposed selection of power development options. Because of the regional scope of the assessment, "stakeholder representatives" were restricted to members of national or regional institutions, be they public or non-governmental (e.g.: private) institutions. B.1.2 Purpose of Stakeholder Consultation Process The purpose of the stakeholder consultation process put into place for the SSEA was to incorporate the points of view of concerned public and private institutions at the national and regional levels into the assessment. More specifically, stakeholder representatives were invited to contribute to the following aspects: a) The assessment of power needs in the sub-region; b) The identification and screening of power development options; c) The selection and ranking of evaluation criteria and indicators for the comparative analysis of selected options; d) The comparative analysis of selected options and selection of strategies for the development of power investment portfolios; e) The identification of mitigation actions and assessment of cumulative impacts. B.1.3 Planning of Stakeholder Consultation Process Because of the regional scope of the assessment, it was agreed from the onset with NEL- CU and the World Bank that the stakeholder consultation program would constitute a "macro" or regional "pulse-taking" of the different issues at hand. Such a "pulse- taking" exercise is a more limited and shorter process than an in-depth local public consultation program required for a specific project. Nevertheless, it constitutes an essential component of the SSEA of power development options to ensure that a wide variety of views are gathered besides those of decision-makers, as represented by the Project Steering Committee membership1. The consequences of such an approach are that national and regional stakeholder representatives invited to participate in the proposed stakeholder consultation program would: 1 The Project Steering Committee (PSC) set up for the study included representatives of NEL-CU and the World Bank, representatives of power ministries and utilities from each country concerned by the SSEA (Burundi, DRC, Kenya, Rwanda, Tanzania and Uganda) as well as observers from downstream states of the Nile Basin (Egypt and Sudan). SSEA III - Final Report B-1 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS a) Be relatively limited in numbers; b) Be required to speak for large numbers of people at national or regional levels; c) Be selected in order to cover to the widest extent possible the spectrum of issues involved in the assessment (e.g.: rural and urban development, environment and water resources management, poverty alleviation and public health, agriculture, industry, tourism, consumer interests, gender issues, etc.); and d) Be selected in order to reflect the concerns of national and regional governments, civil society organisations, and academia. In view of this, it was decided from the onset that the stakeholder consultation process would be structured around regional stakeholder workshops. During Stage I, two 2 day workshops involving a total of 21 representatives per workshop were held in the sub-region (Kigali and Dar-Es-Salaam). During Stage II, two other 2 day workshops involving a total of 42 representatives per workshop were held in the sub-region (Nairobi and Mombasa). These workshops included two power sector representatives per country selected from the Project Steering Committee as well as five governmental or non-governmental representatives of civil society per country. Such a number represented a trade-off between a search for a wide representation of cross-sectoral interests and perspectives and the need for a group that was reasonably small to enable fruitful exchanges and discussions. It was also agreed from the onset that the stakeholder consultation process would be further completed on an informal or "ad hoc" basis by meetings with national and local representatives held during the course of information gathering missions planned to the sub- region to collect secondary data and to visit potential power generation sites. Types of stakeholder representatives to be consulted by the Consultant in the course of such information gathering activities would include: a) Ministries of Energy, Natural Resources, Environment, Agriculture, Transport and Communication, Fisheries National Parks, Health and Social Welfare of Rwanda, Burundi and Tanzania; b) District administrations concerned by specific potential hydroelectric projects; c) Power utilities of Rwanda, Burundi and Tanzania; d) International and national civil society organisations (INGOs/NGOs) or religious organisations dealing at the national level with gender inequalities, ethnic minorities, poverty alleviation, public health, rural development and/or environmental resources; e) Universities and other academic institutions with relevant specialist knowledge. The communication strategy agreed to at the onset was based on the preparation of public information bulletins in English and in French (four bulletins were produced during Stage I and three bulletins were produced during Stage II). Although it was recognised that access to the Internet in the Upper Nile Basin countries is limited, it was proposed that information on the project as well as all documents produced in the course of the project be posted on a dedicated section of the consultant's Web site (www.ssea@snclavalin.com). Alternative means of communication adopted in the course of Stages I and II of the SSEA included national media events with press releases held at the end of each regional stakeholder workshop. During the First PSC Meeting, it was also recognised that alternative means of communication may also have to be considered for disseminating information to a broader audience where and when required. In this regard, representatives of National Discourse Forums met by the Consultant in Nairobi in early December 2003 offered to hold meetings with their member organisations in view of: SSEA III - Final Report B-2 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS a) Informing their members about the ongoing SSEA of power development options; b) Requesting the views and interests of their member organisations in regards to the assessment; c) Identifying among their membership potential stakeholder representatives for the planned workshops; and d) Providing regular feedback to their member organisations regarding the results of the SSEA. B.2 Contribution of Stakeholder Representatives to Stage I of the SSEA This section describes the contribution of stakeholder representatives to Stage I of the SSEA, both initially in meetings and informal interviews with stakeholder representatives carried out during information gathering missions to the sub-region and subsequently during the two regional stakeholder consultation workshops held in May 2004 in Kigali and in September 2004 in Dar-Es-Salaam. B.2.1 Comments Provided by Stakeholder Representatives in the Sub-region B.2.1.1 Meetings During Inception Mission During the Inception Mission, information on environmental and social issues in each of the three countries was obtained or the most relevant sources of information on these subjects were identified. A number of suggestions were also provided in regards to potential candidates from Burundi, Rwanda and Tanzania for the proposed stakeholder consultation workshops. The following observations were made for the three countries with regards to social, environmental and consultation issues: · In Rwanda and Burundi, recent studies have been completed on biodiversity and wetlands. · In all three countries, air pollution levels are considered to be very low. In Burundi, an inventory of greenhouse gas emissions has been completed in 2001 and measures to reduce them have been defined. · Population censuses were carried out recently in Tanzania (2002) and in Rwanda (2002). In Burundi, the last census dates back to 1990. · 1:50,000 maps covering the areas concerned by potential hydropower options have been produced in each country but, except for Rwanda, they date back to the 1960s or 1970s and several maps are out of print. · It was suggested to explore the possibility to link the SSEA consultation process to the "International Discourse on the Nile River Basin" which has recently been set up with a secretariat in Entebbe. The objective of this organisation is "to promote a broad based, open dialogue, discussion and sharing of views on development in the Nile River Basin, mainly through the Nile Basin Initiative between all role-players, stakeholders and affected parties, including civil society, academia, NGOs, the private sector, communities, governments at national, regional and international levels in all areas including, poverty, conflict, the environment and development." National Discourse Forums have already been set up under the auspices of the Nile Basin Discourse in Tanzania, Burundi and Rwanda. SSEA III - Final Report B-3 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS B.2.1.2 Meetings with Representatives of the Nile Basin Discourse During the Second General Assembly of the Nile Basin Discourse (NBD) held in Nairobi in December 2003, discussions with the Discourse Facilitator, NBD Desk in Entebbe, confirmed the interest of co-operating with the NBD, and in particular with its recently created National Discourse Forums (NDFs) that are represented by members elected from among participating NGOs (environmental associations, religious organisations, etc.). The Discourse Facilitator explained the recent evolution of the NBD towards: a) a more democratic network of civil society organisations (based on an elected membership authorised to vote in the upcoming First General Assembly of the NBD); b) a network less dependent upon outside sources of funding and administrative guidance (the bonds linking the NBD with the International Union for the Conservation of Nature ­ IUCN ­ are gradually being loosened); c) a legally established network benefiting from a formal relationship with the Nile Basin Initiative (a MOU should shortly be signed to this effect between the NBI and the NBD). He also explained the need for capacity building of NGOs, particularly in countries such as Burundi and Rwanda where civil societies are still emerging from major internal conflicts. Subsequent discussions with a member of the Follow-up Commission for the Application of the Arusha Peace Accord in Burundi (and also President of the Alliance for a Durable Peace in Burundi, member of the International Network of Liberal Women N.L.W, and President of Liberal Women of Burundi), helped in gaining a better understanding of the issues confronting civil society in Burundi. B.2.1.3 Meetings and Interviews During Information Gathering Mission The most significant contributions to the assessment with respect to environmental, social or consultation issues made by stakeholder representatives met and/or interviewed during the information gathering mission to the sub-region undertaken by the Consultant in February 2004 are summarised below: · The preliminary identification of environmental and socio-economic evaluation criteria and indicators by the study team was reviewed and adjusted during discussions with national environmental and socio-economic experts (in particular, certain criteria relative to: a) indigenous communities and ethnic minority groups and b) heritage, cultural, religious or sacred sites were reviewed with stakeholder representatives in regards to their relevance in the context of the assessment); · The preliminary identification of environmental and social concerns in regards to relatively promising thermal (Lake Kivu methane gas project) and hydropower (Rusumo Falls, Nyaborongo, Ruzizi III) power options in the sub-region was also discussed with national environmental and socio-economic experts, as well as with stakeholder representatives from communities situated in the vicinity of the potential hydropower project sites. B.2.2 Comments Provided by Stakeholder Representatives During Workshops B.2.2.1 Comments on Power Needs Assessment As regards the assessment of power needs in the sub-region, comments provided by stakeholder representatives during the first workshop stressed the urgent need for electricity in rural areas and the relation between deforestation and the lack of alternative energy sources. During the second workshop, a presentation was made on the methodology used and the results of the assessment of power needs in the sub-region, as described in the SSEA III - Final Report B-4 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Draft Final Report for Stage I of the SSEA. A number of comments resulted from the presentation of this section, including the following: · Concern was raised on the treatment of rural electrification, as assumptions might impact significantly on the load forecasts. · It was noted that an objective of the assessment is to assist the sector in developing new energy resources, and thus improving access to electricity. · It was also noted that ability / willingness to pay were not usually the primary obstacle. Rather, the primary obstacle to increasing rural electrification rates is the ability of the electricity companies to extend medium / low voltage lines, and to support the connection cost, since some level of subsidy is usually required. · Because of the duality between Rwanda and Burundi, the methodology has to be based on the same hypothesis and the result of forecasts has to be compatible. · The exercise should also address the energy losses in the system (distribution and transmission) and propose ways to reduce them. · Rwanda has evaluated that electricity losses through the system are approximately 25% but an objective to reduce these losses by half within the next five years has been set. B.2.2.2 Comments on Identification and Screening of Power Options With respect to the identification of power options, suggestions were made during the first workshop to consider other types of energy options such as biogas and biomass. It was also suggested to seek guidance from the Project Steering Committee on the following question: "Up to what point should the assessment consider off-grid options in rural areas within the context of NELSAP (one of whose main objectives is regional co-operation)?" Another comment was made that interconnections do not represent an additional source of power and cannot be considered as an option. They should be considered only when they can be used to export surplus energy from one country to another and in a way that is profitable to both countries. During the second workshop, the discussion focussed on the process followed to screen the candidate power options prior to the comparative analysis of selected options. The main criteria considered to date for screening out power options were: a) excess cost of power generation; b) lack of required documentation; and/or c) excess environmental or social impacts. A revised version of Table 4-7 of the Draft Final Report was presented to the stakeholder representatives, with the following changes: The mid-size Rusumo scheme was added as a viable alternative for the site. The Kagunuzi and Mule 34 projects were included in the projects to be evaluated, as their indicated costs were now below the newly established cut-off of 8-9 cents/kWh. The combined cycle gas turbine (conceptual ­ No 2 fuel) was deleted due to its high cost but the Lake Kivu (Gas combined cycle) was maintained. It was noted that the criteria for short term was solely limited to a feasible on-power date of less than three years. The three candidates for the short term therefore included: a) a new diesel plant, despite its high cost; b) the Ruzizi I hydropower rehabilitation project (capacity only); and c) the Kivu gas power generation project, due to its assumed short on-power lead time. It was also proposed that Table 4-7 should include all variants at any site or river reach, such as for the Igamba hydropower site. SSEA III - Final Report B-5 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Stakeholder representatives noted that the Mpanda hydropower site in Burundi has potentially significant benefits from irrigation, and had been planned as a multipurpose project. A detailed study had also been recently completed for this project. It was suggested that for multipurpose projects, the Consultant should distinguish electricity-related costs from irrigation-related costs. Consequently, although the indicated generation cost was above the cut-off cost level of 8-9 cents/kWh, it was recommended that Mpanda should be included in the list of candidates, and secondary benefits should be considered for the screening of the project. It was agreed that the screening process would be modified to include multiple purpose projects and that when information exists for multipurpose projects, the evaluation should take into consideration the benefits and differentiate the costs according to the multipurpose functions of the option. It was also proposed to modify the statement concerning both Rusumo Falls options in the Draft Final Report. Indeed, the reference to severe environmental impacts appeared a little excessive in light of the screening process adopted. B.2.2.3 Comments on Criteria for the Comparison and Ranking of Power Options The Draft Final Report presented the Consultant's initial view of the criteria that should be used in the comparative evaluation of the power development options. These fell within six major categories, namely: Political, Economic and Social, Financial, Environmental, Technical, Legal and institutional. Participants in the first workshop arrived at a consensus on a new list of evaluation criteria for the comparison and ranking of power options. The main changes from the list proposed in the Consultant report were as follows: · The Political and Legal and institutional categories were removed and replaced by a Project risks category. · New titles were proposed for certain categories that better reflect the criteria considered in each category. · New titles were also proposed for certain evaluation criteria. · Criteria were added and some were combined. Overall, the number of criteria was reduced. The new list of evaluation criteria is provided hereafter in Table B-1. SSEA III - Final Report B-6 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Table B-1: Revised Criteria and Indicators for Evaluating Power Options Criteria Indicators Category: Economic and Financial Economic Viability Harmonized cost per kWh over the projected life of the facility, taking into account: · Direct investment ­ plant · Engineering costs · Operating and maintenance costs · Environmental and social mitigation costs (including resettlement cost) · Benefits (including those derived from the sale of CO2 emission credits) ­ where applicable · Time value of money Financial Viability · Potential Sources of financing · Probability of achieving financial close Gestation Period in Delivering Years required before the project can be commissioned Benefits Category: Technical Level of Service and Flexibility · Capability to supply peak demand (MW) · Average annual energy supply capability (GWh) · Level of ancillary services and flexibility provided by the option to the electricity grid (spinning and non-spinning reserve, frequency response, black start capability, voltage support, etc.) · Degrees of matching supply capabilities with daily, weekly, monthly and annual regional and national load curve characteristics Option's Level of Preparedness Delay before power supply option can be commissioned Diversification of Power Sources Increase mix between hydroelectric generation and thermal generation from domestic and imported fuel Category: Project Risks Technical Risks · Technical difficulties · Hydrological risk · Geological risk Financial Risks · Variability in cost of fuel · Continuity of supply Risks for Investors and Power · Amount at risk Utility Clients · Risk of meeting environmental opposition SSEA III - Final Report B-7 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Criteria Indicators Category: Socio-economic Public Health · Risks of increases in waterborne diseases · NOx emissions over the life cycle of the project (t/GWh) · SO2 emissions over the life cycle of the project (t/GWh) · Particulate matters over the life-cycle of the project (t/GWh) Impacts Due to Population · Number of persons affected by project infrastructure and Displacement ancillary facilities · Agricultural area affected by project infrastructure and ancillary facilities Contribution of Project to Poverty · Number of people employed during construction and operation Reduction of project (per MW) · Contribution of project to food security (irrigation, access to markets and services, fishing, etc.) Multiple-Use Benefits Ability of each project to provide services other than energy, such as irrigation, water supply, flood control, navigation or fisheries Impacts on Cultural, Historical and Degree of impact of each option on sites of significant or Religious Sites exceptional value at national, regional or local level Impacts on Indigenous Presence of indigenous community in the vicinity of the project that Communities could experience adverse social and cultural impacts from project construction and operation Impacts on Vulnerable Groups Contribution of project to improvement of the quality of life of vulnerable groups (including women) Socio-economic Impacts on the Hydraulic modifications in the downstream reaches Downstream Reaches Category: Environmental Impact on Resource Depletion · Energy payback ratio: ratio of energy produced during the normal life span of the option divided by the energy required to build, maintain and fuel the generation equipment. This indicator is a measure of the global pressure of an option on the environment · Use of renewable resources for electricity generation Impacts of Greenhouse Gas Net CO2 equivalent emissions over the life cycle of the project Emissions (t/GWh) Land Requirements Land area required for project infrastructure and facilities over the life cycle of the project (km2/GWh/year/km2). Impacts of Air Pollutant Emissions · NOx emissions over the life cycle of the project (t/GWh) on Biophysical Environment · SO2 emissions over the life cycle of the project (t/GWh) Impacts on Designated Habitats Number, area and importance of designated habitats and natural and Natural Sites sites (such as savannahs, migratory birds resting and wintering areas, wetlands, critical habitats for endangered species, etc.) lost or modified SSEA III - Final Report B-8 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Criteria Indicators Impacts of Sedimentation and · Percentage of reservoir storage volume lost per year due to Erosion within the Reservoir and sedimentation Downstream · Wetlands area of importance to wildlife affected downstream Proliferation of Invasive Aquatic · Area that could be covered with invasive aquatic vegetation Vegetation and Reservoir Eutrophication · Changes in the following parameters: water temperature, nitrates and organic matters, pH, dissolved oxygen Environmental Impacts on the Hydraulic modifications in the downstream reaches Downstream Reaches During the second workshop, the revised criteria and indicators presented in the Draft Final Report were reviewed and validated with participants. The results of these discussions are presented hereafter: a) It was agreed that the criteria related to "Diversification of power sources" in the Technical category of criteria should be deleted as this aspect would be taken into account in the development of the portfolios/strategies. b) The Project risks category of criteria now includes an indicator relative to environmental risks for the criteria "Risks for Investors and Power Utility Clients". It was pointed out that the real risk usually related to lobbying, often without a sound or real environmental basis. It was agreed that this indicator should thus be restated to refer to "Risk of opposition from external groups". c) Under the Socio-economic category of criteria, it was agreed that multipurpose aspects should be reflected in the Economic and financial viability category and be added to the indicator already stating different "benefits", as this was a financial or economic issue. However it was also noted that the overall subject of Integrated Water Resources Management (IWRM), such as water allocation, riparian interests, and other multipurpose uses or benefits (without direct revenue or subsidy possibilities) should continue to be reflected in the Socio-economic category of criteria. Consequently, multiple benefits or uses could be dealt with at both places but proper indicators should be developed for each category of criteria so that they do not overlap. If quantitative data is available, it should be included in the Economic and financial viability category. If information only exists in terms of potential uses, it should be included in the Socio-economic category. d) Under the Environmental category of criteria, it was agreed that the criteria "Impact on the downstream reaches" should include indicators for changes in hydrologic regime and an indicator on biodiversity. e) It was also recommended to take into consideration positive environmental impacts and not only negative ones. f) The possibility of deleting the criterion "Gestation Period in Delivering Benefits" under the Economic and financial viability category of criteria or the criterion "Option's Level of Preparedness" under the Technical category of criteria was discussed in view of avoiding possible double counting. However, it was decided to maintain the two criteria and it was agreed to clearly distinguish them on the basis of distinct indicators. SSEA III - Final Report B-9 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS B.2.2.4 Determination of the Relative Importance of Each Criterion As the last main objective of the first workshop, participants were invited to assign importance levels to each of the criteria. This exercise was necessary for the analyses to follow, which included the comparative analysis and ranking of individual power development options against each of the criteria and within each category of criteria. The relative importance of criteria was determined on the basis of the following three classes of importance: · Very important (I) · Important (II) · Less important (III) The consensus on the relative importance of criteria at the level of each of the three discussion groups is presented in Table B-2, using the following legend: F Francophone group of stakeholder representatives; A Anglophone group of stakeholder representatives; PSC Project Steering Committee members and other participants at the PSC meeting. However, due to the number of participants and limited time available, it was impossible to try to reach a consensus in plenary. Nevertheless, despite differences between group discussions' results on the relative importance of criteria, there were some areas of consensus in the following categories: 1. Economic and Financial Category: There is one strong consensus: economic viability is a very important criterion. For two groups, financial viability is also considered as very important. For two groups, the gestation period in delivering benefits is considered as less important than other criteria. 2. Technical Category: Two groups consider the diversification of power sources as less important than other criteria. The other group did not put it in the very important class. 3. Project Risks Category: Two groups consider technical risks as very important while the third group considers it of less important. For the other two criteria, all groups considered them as important or less important. 4. Socio-economic Category: There is another strong consensus on the criterion: contribution of project to poverty reduction. All groups put it in the very important category. There was also a consensus that the following two criteria are less important than others: impacts on cultural, historical and religious sites, impacts on indigenous communities. SSEA III - Final Report B-10 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Table B-2 - Relative Importance of Criteria per Stakeholder Group in First Stakeholder Workshop Relative Importance amongst stakeholders Anglophone Francophone PSC Overlay Category Criteria I II III I II III I II III I II III - Economic Viability F,A,PSC Economic & - Financial viability F, A PSC Financial - Lead-time to Deliver Benefits A, PSC F - Level of Service and Flexibility F, A PSC Technical - Option's Level of Preparedness A, PSC F - Diversification of Power Sources F, A PSC - Technical Risks A, PSC F Project Risks - Financial Risks PSC F, A - Risks for Investors and Utility Clients A F, PSC - Public Health A PSC F - Impacts Due to Population Displacement A F, PSC - Contribution of Project to Poverty Reduction F,A,PSC - Multiple-Use Benefits F, PSC A Socio-economic - Impacts on Cultural, Historical and Religious Sites PSC F, A - Impacts on Indigenous Communities A F, PSC - Impacts on Vulnerable Groups F A, PSC - Socio-economic Impacts in the Downstream Reaches A PSC F - Impact on Resource Depletion A F, PSC - Impacts of Greenhouse Gas Emissions A F, PSC - Land Requirements A F, PSC - Impacts of Air Pollutant Emissions on Biophysical Environment A F, PSC Environmental - Impacts on Designated Habitats and Natural Sites A F, PSC - Impacts of Sedimentation and Erosion within Reservoir and Downstream A F, PSC - Proliferation of Invasive Aquatic Vegetation and Reservoir Eutrophication A F, PSC - Environmental impacts in the Downstream Reaches A PSC F SSEA III - Final Report B-11 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS 5. Environmental Category: All groups considered that the following three criteria are more important than others: impacts on resource depletion, land requirements, impacts on designated habitats and natural sites. All groups considered the following two criteria as less important: impacts of greenhouse gas emissions and impacts of air pollutant emissions. In other words, there is a consensus among the three groups on the relative weight of 5 criteria out of the 8 criteria in the environmental category. During the session of the Second PSC meeting following the first workshop, it was decided to use the three "scenarios" of relative importance of criteria (Scenario F, Scenario A, Scenario PSC) for the ranking of options within each category of criteria. During the second workshop, the relative importance of evaluation criteria determined by stakeholder representatives during the first workshop was presented by the Consultant. This was followed by a discussion on how to combine the three alternative rankings provided in the Draft Final Report to provide a clearer result. The Consultant proposed that when the relative importance was shared by at least two of the stakeholder groups, this would reflect the selected relative importance retained for the analysis. The Consultant also proposed that where each of the three groups had identified a different level of importance, the mid- importance level (Level II) should be selected as the relative importance. After an extensive discussion on the matter, all of the stakeholder representatives agreed on the levels of importance for evaluation criteria proposed by the Consultant. The result of this discussion is presented in Table B-3. B.2.2.5 Review of Methodology for Comparative Analysis of Selected Power Options During the second workshop, initial results obtained for the comparative analysis of selected power options on the basis of the Holmes Method were reviewed and discussed with workshop participants. Following discussions, stakeholder representatives agreed that conclusions should not be drawn across the five categories of criteria, so as not to not imply a decision as to their relative importance (e.g.: the importance of economic criteria relative to environmental criteria or socio-economic criteria). They also agreed that trade-offs involved in such decisions are better left to the concerned political decision-makers. B.2.2.6 Comments on Cumulative Impacts Assessment and Mitigation Measures During the second workshop, a presentation was made of the methodology and results from this analysis, as described in the Draft Final Report. A number of comments resulted from this presentation, including the following: · There is a difficulty in the region in the evaluation and establishment of appropriate minimum environmental standards, particularly with respect to greenhouse gas emissions (GHG). Consequently there are problems in determining if an identified impact is acceptable or not. It was agreed that the Consultant should further address these issues. · It was noted that the report does not reflect the potential effectiveness of possible mitigation measures. · It was noted that more specific local experience would help in validating the SSEA findings and conclusions on potential environmental impacts. SSEA III - Final Report B-12 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Table B-3 ­ Consensus on Relative Importance of Criteria Obtained in Second Stakeholder Workshop Relative Importance Category Criteria I II III Economic & - Economic Viability Financial - Financial viability - Lead-time to Deliver Benefits Technical - Level of Service and Flexibility - Option's Level of Preparedness Project - Technical Risks Risks - Financial Risks - Risk of opposition from external groups Socio- - Public Health economic - Impacts Due to Population Displacement - Contribution of Project to Poverty Reduction - Multiple-Use Benefits Non-quantifiable) - Impacts on Cultural, Historical and Religious Sites - Impacts on Indigenous Communities - Impacts on Vulnerable Groups - Socio-economic Impacts in the Downstream Reaches Environ- - Impact on Resource Depletion mental - Impacts of Greenhouse Gas Emissions - Land Requirements - Impacts of Air Pollutant Emissions on Biophysical Environment - Impacts on Designated Habitats and Natural Sites - Impacts of Sedimentation and Erosion within Reservoir and Downstream - Proliferation of Invasive Aquatic Vegetation and Reservoir Eutrophication - Environmental impacts in the Downstream Reaches · Reference could be made to the experience of the Mtera reservoir, which has been studied and recorded by a Swedish unit. (It was confirmed that TANESCO has this report on file). Other studies for projects in the region may be available from SOGREAH. It was noted that the Consultant had experienced difficulties in getting access to the SOGREAH report. However the SSEA analysis had included information from the IHA study on Hydropower and the Environment (2001). B.2.2.7 Identification of Strategies for Development of Power Investment Portfolios During the second workshop, a presentation was made of the methodology used and results from a preliminary analysis of strategies for the development of power investment portfolios, as described in the Draft Final Report. It was noted that the procedure that had been adopted in the development of power investment portfolios included in the report was based on the following steps: a) review of criteria that could be applied to the development of SSEA III - Final Report B-13 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS alternative strategies; b) development of alternative strategies; and c) development of investment portfolios to reflect each strategy. The Consultant presented six overall strategies, or overall objectives, that could be used in the development of portfolios: · Strategy 1: Balanced mix of hydro and thermal options · Strategy 2: Emphasis on thermal projects · Strategy 3: Minimisation of investment at the risk of load shedding · Strategy 4: Maximisation of hydro projects · Strategy 5: Minimisation of unit cost of power (at the expense of other criteria) · Strategy 6: Ensure generation is not concentrated in any one location. The three portfolios provided in the report corresponded to the first three strategies identified in the list above. The purpose of presenting the longer list of strategies was to stimulate discussion of criteria and strategies with stakeholder representatives. Discussion on these options raised the following points (which were not necessarily agreed on by all of the stakeholder representatives): An additional strategy should be considered, e.g.: Strategy 7: Import of power from outside the region to minimise costs. Portfolios should reflect location issues, for example concentration of generation in one area that would require additional transmission and transmission reinforcement. Where strategies accept concentration of generation, the development or costing of the portfolio should include input from transmission planning studies, to ensure that supplementary transmission costs are included. Where potential severe environmental impacts are likely to occur, but have not yet been properly identified or evaluated, these should not be used to exclude new generation options at the candidate selection process. However, requirements for evaluating such environmental risks should be clearly stated in the assessment. One should not eliminate a low cost option because of concentration of generation options in one geographic location because of perceived potential political risks. On this location issue, it was noted that a high geographic concentration (e.g.: Kivu gas) would introduce a reliability risk due to extended transmission requirements. However, in the case of Lake Kivu gas, there would be two plants at separate locations that may reduce such a risk. The objectives given to the groups were to develop from two to four strategies with specific overall objectives. Also the strategies should be developed on a regional basis, rather than at a national level. The purpose of the discussions was for the stakeholder participants to identify their primary concerns or interests that should be reflected in the planning process. Four stakeholder discussion groups were formed as follows: · Burundi power and non-power representatives; · Rwanda power and non-power representatives; · Tanzania power and non-power representatives; · Other representatives (including other PSC members from NEL-CU, SINELAC, the World Bank, DRC, Uganda and observers from Egypt and Sudan). SSEA III - Final Report B-14 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS After some 60 minutes of group discussions, the results were reported back to the plenary group. The four groups generated the following strategies or sets of strategies: Group 1 ­ Burundi · Strategy 1: Maximisation of hydro projects to minimise cost of power; · Strategy 2: Regional projects to maximise regional benefits and sharing of costs (e.g.: Rusumo Falls Hydropower Project and Kivu Gas Power Generation Project); · Strategy 3: Balanced mix of hydro and thermal options for security and reliability. Group 2 ­ Rwanda · Strategy 1: Yes for mid-term when observing performance of Lake Kivu Methane (need for diversity, need for alternatives in case of failure of plant); · Strategy 2: Yes for long-term if gas is proven in the middle term; · Strategy 3: No; · Strategy 4: Yes if Lake Kivu Methane not suitable ­ becomes like Strategy 1 which would extended to the long term; · Strategy 5: No; · Strategy 6: Yes for technical/security of supply reasons; · Strategy 7: Yes for more flexibility. Group 3 ­ Tanzania · Strategy 1: Hydro and thermal mix at optimum cost; · Strategy 2: Generation should not concentrate in any one location; · Strategy 3: Import of power from outside the region. Group 4 ­ Other Participants Target based on need to install approximately 250 MW of new generation by year 2020. Alternative strategies proposed based on concept of varying the degree of diversification (technical, location, plant size, type etc) in a generation plan. Plant installations are indicative to show a mix level rather than referring to any particular plant option: · Scenario 1A - Low diversification ­ thermal priority - Kivu gas 200 MW and hydro 50 MW; · Scenario 1B - Low diversification ­ hydro priority ­ Hydro 200 MW and Kivu gas 50 MW; · Scenario 2 ­ Medium diversification ­ Kivu 100 MW and hydro 150 MW; · Scenario 3 ­ Maximum diversification ­ Kivu 75 MW, hydro 125 MW, diesel (oil) 50 MW. Discussion on these sets of strategies led to the following conclusions: · The stakeholder representatives agreed on the need for a firm recommendation on a short term emergency plan, to include Lake Kivu gas engines, a generic conventional SSEA III - Final Report B-15 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS diesel plant using No.2 oil, and the rehabilitation of Rusizi I. This plan would remove the current deficit, and allow time for the detailed evaluation and confirmation of other power options for the mid term. · The stakeholder representatives working in four discussion groups also generated strategies for the mid and long term that showed a considerable degree of agreement. It was generally agreed that proposals to the Consultant for evaluation in the finalisation of the report could be covered by the set of scenarios proposed by Group 4 (Other participants). · However the group of stakeholder representatives considered that a variation to the third scenario identified by Group 4 (Other participants), reflecting possible import from outside the region should also be evaluated. Similarly consideration should be given to including a multipurpose project. · It was agreed that principles derived from the workshop that will guide the definition of power generation portfolios for the region include the following: - Diesel generation in the short-term, to be used as standby power in the long- term; - Lake Kivu gas in the short-term, to be expanded to a sustainable level of 100 MW in the long-term when the reliability of this source of power has been fully demonstrated; - Expansion of hydropower in the middle and long terms if expansion of Lake Kivu gas does not proceed as well as expected. Otherwise, expansion of hydropower up to 100 MW over the time horizon considered for in the assessment (2020); - Diversification of hydropower sources around the region to maximize system reliability; - Consider low cost imports in the long-term if power is available outside the region; - Include a 20% standby capacity to account for technical problems and maintenance requirements. Other points raised (which were not necessarily agreed on by all of the stakeholder representatives) on the results of group discussions include: · It was noted that a number of stakeholder representatives were in favour of a mixed hydro/thermal strategy. · It was suggested that the proposed strategies should focus on realistic projects by emphasising the use of locally available sources of power. · It was recommended that the use of available hydropower resources be maximised; in this respect, many participants considered the Rusumo Falls hydropower scheme to be a truly regional project. · It was recommended that multipurpose projects be given full consideration in the context of the assessment. · Given the urgency of installing diesel generators to address immediate power demands, it was noted that there was a risk that environmental studies would be minimised. In case of such an occurrence, it was recommended to proceed with SSEA III - Final Report B-16 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS proper site identification and to plan for managing potential environmental risks associated with such facilities. · Mid-term: Slowly retire from hydropower if Lake Kivu gas is proven of interest. · Diesel should be considered only as a back up solution in the mid and long terms. · In the short-term, the countries of the region should immediately proceed with detailed studies of the promising hydropower projects so that such projects will be feasible in the mid-term. Burundi, Rwanda and Western Tanzania are currently experiencing severe power shortages and studies should be undertaken as soon as possible to avoid such situations in the future. · Certain doubts were expressed with regards to the potential of the Lake Kivu Methane gas project to generate significant amounts of power before 2008. As a result, a number of participants considered that alternate options (such as Rusumo Falls) should be given priority to address mid-term power demand. · It was noted that the Rusumo Falls hydropower scheme (even in its "Full" configuration) could have less significant environmental impacts than expected given changing conditions in the Kagera basin. Certain environmental and social benefits could also accrue from the implementation of such a scheme. · Given the potential impacts of power options under consideration, there is a need to take into account other national policies related to agriculture and human habitat in the framework of the assessment · It was noted that stakeholder representatives have a responsibility in regards to the results of the SSEA study. This led to questions regarding the expected role of stakeholder representatives with respect to the following steps of the SSEA. B.2.3 Main Lessons Learned from Stage I of the Stakeholder Consultation Process The main lessons learned from Stage I of the SSEA are briefly described hereafter. B.2.3.1 Opportunities Created by the Process The stakeholder consultation process adopted in the context of Stage I of the SSEA of power development options in Burundi, Rwanda and Western Tanzania created new opportunities for civil society organisations to actively contribute in the planning of power infrastructure programs that are critically needed to attain poverty alleviation objectives targets set out in the sub-regions' National Poverty Reduction Strategies. The stakeholder representatives selected for participation in the consultation workshops brought significant knowledge in regards to cross-sectoral environmental, social and community development issues in the sub-region. Invited experts and NGO representatives were given the opportunity to exchange with colleagues from neighbouring Nile basin countries on the basis of their common fields of expertise. They were also given the opportunity to learn from the invited power experts from the Project Steering Committee about the challenges involved in the planning of power infrastructure programs in the sub- region. In turn, the invited power experts from the Project Steering Committee and members of the Consultant's study team were able to learn from the invited experts and NGO SSEA III - Final Report B-17 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS representatives about cross-cutting environmental, social and community development issues that significantly affect the planning of power infrastructure programs in the sub- region. As a result of these exchanges, the contributions of the participants in the workshops are clearly reflected in the results and conclusions of the assessment. B.2.3.2 Limitations of the Process The main limitations to the stakeholder consultation process observed during Stage I of the SSEA were the following: · The limited number of selected participants in the workshops who were able to actually attend the two workshops (2 out of 5 from Burundi, 2 out of 6 from Rwanda2 and 2 out of 5 from Tanzania) had a significant impact on the level and quality of participation in the workshops. Participants who had attended the first workshop and were more familiar with the assessment and with workshop procedures tended to play a more active role in the second workshop. In certain cases, stakeholder representatives nominated to the workshops as replacements by their respective organisations came from other non-related organisations. In a few other cases, selected participants in the workshops (including two from Tanzania) could never be reached for the workshops. · Comments made by certain stakeholder representatives during the second workshop in regards to a need for a more integrated approach taking into account cross-cutting issues and policies related to agriculture and irrigation, fisheries, forestry and public health, indicate that due consideration should be given to widening the spectrum of interests and expertise of stakeholder representatives invited to participate in the workshops planned for Stage II of the SSEA. · Alternative means of communication for disseminating information to a broader audience have been discussed with stakeholder representatives involved in the consultation workshops. These included the forwarding of public information bulletins to National Discourse Forums and promoting exchanges of information between various civil society organisations involved or interested in the assessment process. However, these avenues have not been further explored given the time and logistical constraints involved in the assessment and would merit further consideration during Stage II of the SSEA3. In particular, due consideration should be given to making the project known to a wider public by, for instance, organising public information meetings in each of the countries at the onset of the second stage of the SSEA. · Members of the Project Steering Committee noted that there was a need for greater involvement on their part both with respect to the selection of stakeholder representatives and to the planning and management of future stakeholder workshops. A greater role could also be given to relevant National Discourse Forums in regards to the selection of stakeholder representatives and the organisation of public information meetings in each of the countries concerned by Stage II of the SSEA. 2 An additional stakeholder representative representing the "Office Rwandais du Tourisme et des Parcs Nationaux" attended both workshops at the invitation of NEL-CU and actively contributed to the proceedings. 3For instance, participants in the workshops indicated that there was insufficient time to consult with their membership prior to the workshops, in consideration of the fact that they received draft reports two weeks or less than two weeks before the workshop. SSEA III - Final Report B-18 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS B.3 Contribution of Stakeholder Representatives to Stage II of the SSEA This section describes the contribution of stakeholder representatives to Stage II of the SSEA, both initially in meetings and informal interviews with government representatives and environmental groups during information gathering missions to the Nile Equatorial Lakes region and subsequently during the two regional stakeholder consultation workshops held in April 2005 in Nairobi and in June 2005 in Mombasa. B.3.1 Discussions Held During Information Gathering Missions During the Sixth PSC Meeting in December 2004, the Consultant was requested to plan the stakeholder consultation process for Stage II of the SSEA in close co-operation with concerned PSC representatives from DRC, Kenya and Uganda. PSC representatives from Kenya and Uganda were particularly concerned about the potential impact of such consultations on other ongoing power planning activities in their respective countries (e.g.: the finalization of the East African Community Power Master Plan and the ongoing development of committed projects such as the Bujagali and Karuma Falls hydropower schemes in Uganda). In general, country representatives of the PSC expressed their intent to gain greater ownership over the stakeholder consultation process during the second stage of the SSEA. In consequence, during the Inception Mission undertaken by the Consultant in the DRC, Kenya, Tanzania and Uganda in October and November 2004 for Stage II of the SSEA, meetings were held with concerned government authorities in DRC, Kenya and Uganda to discuss the planning of the consultation process, including the selection process of candidates for the workshops. Additional meetings were held with national environmental NGOs and representatives of academia in Kenya and Uganda to discuss the proposed stakeholder consultation process, to obtain information on environmental and social issues related to the power options under consideration in each country, and to identify the most relevant sources of information on these subjects. A number of the environmental NGOs selected for these discussions (NAPE, Greenwatch) were vocal and articulate opponents of the Bujagali hydropower project and, as such, were considered as relevant contributors to the discussions. It should be noted that because of the circumstances involved in the production of the SSEA Stage II Draft Final Report (e.g.: less than a month a half to review reports and carry out the analysis before the last stakeholder consultation workshop held in June 2005), no additional in-country meetings took place during information gathering activities. The efforts of local consultants were concentrated on collecting reports and contributing to the social and environmental analysis of power options and to the socio-political inventory. The context was also quite different in Stage II: most if not all of the options under consideration had either been reviewed during Stage I of the SSEA (Burundi, Rwanda and western Tanzania) or reviewed in the East African Community Power Master Plan (Kenya, Tanzania and Uganda). Thus the need for additional field trips by local consultants was limited to eastern DRC where no options were retained following project screening.4 The following observations were made during the Inception Mission with regards to the stakeholder consultation process and to the project as a whole in the countries concerned. 4 Experco des Grands Lacs ltée carried out site visits of hydropower options in eastern DRC in April-May 2005. SSEA III - Final Report B-19 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS B.3.1.1 Democratic Republic of the Congo During the first stage of the SSEA, initial contacts had been established with representatives of two Congolese environmental and social NGOs active in the eastern provinces of the DRC at the First General Assembly of the Nile Basin Discourse held in Nairobi in December 2003. At the time, these NGOs (Observatoire du Bassin du Nil and Association pour le Développement Social et la Sauvegarde de l'Environnement ­ ADSSE) were involved in providing assistance to refugees in camps established with UN funding in the context of the conflict in eastern Congo. At the onset of the second stage of the SSEA, a preliminary search was carried out on the Internet for relevant government agencies and civil society organisations in the DRC5. This search indicated: a) that little publicly available information is available concerning relevant Congolese governmental and non governmental organisations; b) that a number of Congolese environmental and social NGOs of regional scope exist outside the country and play an increasingly active role in internal developments within the country; and c) that little information is available concerning relevant civil society organisations in the eastern provinces of Ituri, Kivu-Nord, Kivu-Sud and Nord-Katanga. In an October 2004 meeting held at the Kinshasa offices of the Ministry of Energy, the Ministry's Director of Electricity and the Directeur Attaché DPT of SNEL provided the Consultant with background information and guidance for Stage II of the SSEA. They suggested that the Consultant consider the candidacy of an NGO representative delegated by the Ministry of Energy to maintain contacts with NGOs involved in the energy sector throughout the country. The mandate of this representative is to promote NGOs' awareness regarding the importance of rural electrification for development, health, etc. and to ensure that this theme is included in their planning activities. They suggested that he could assist the Consultant in the collection and analysis of data on relevant government agencies and civil society organisations both at a national level and at a regional level in the eastern provinces of the country. The Consultant followed up on this suggestion and hired the proposed local consultant. B.3.1.2 Kenya A preliminary search was carried out on the Internet for relevant civil society organisations in Kenya. This search indicated that it would be very challenging to select from among the wide number of candidate organisations a few representatives to be invited to the two stakeholder workshops planned for Stage II of the SSEA. Following meetings in October 2004 with members of the PSC representing the Ministry of Energy of Kenya and the Kenya Power and Lighting Company (KPLC) who provided the Consultant with background information and guidance for Stage II of the SSEA, a meeting was held with a World Bank economist at the regional offices in Nairobi. The World Bank representative underlined the challenges associated with power generation in Kenya, due in particular to the relative importance of hydropower (70% of total generation), the concentration of hydropower plants in the Tana basin (one hydropower plant is under construction near Lake Victoria) and the impacts of prolonged droughts on power supply (the 1998 to 2000 drought led to a 70% drop in hydropower generation). Given the number of ongoing power initiatives in the region (SADC, East African Community Power Master Plan, 5The objectives pursued by such preliminary searches on the Internet were: a) to prepare for initial meetings during the Inception mission; and b) to provide local consultants with a template to be validated and completed on the basis of an inventory of relevant government agencies and civil society organisations. SSEA III - Final Report B-20 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Nile Basin planning), he emphasised the importance of integrating the results of the EACPMP and of other ongoing regional initiatives into Stage II of the SSEA. A meeting held in October 2004 at the regional offices with senior representatives of the International Union for the Conservation of Nature (IUCN) in Nairobi confirmed that the number of relevant environmental and social NGOs in Kenya was greater than in all of the other five countries concerned by the study taken together. Since the departure of the former President of Kenya, national NGOs have become much more aggressive and outspoken in pursuing their agendas. It was therefore considered likely that pressures would be brought to bear on the Consultant by certain NGOs to ensure their selection in the stakeholder consultation process. In view of this, IUCN's regional NGO specialist and representative to NePAD suggested that the Consultant consider hiring a local consultant to assist in the collection and analysis of data on relevant civil society organisations. The Consultant followed up on this suggestion and hired a specialised local consultant for such a purpose. Suggestions were also made regarding other organisations that could assist the Consultant in the collection and analysis of environmental and social data required subsequently in the course of the study as well as relevant NGOs to be considered as possible representatives in the planned stakeholder workshops for Stage II of the SSEA. In addition, it was noted that there were significant linkages between Stage II of the SSEA and other ongoing activities related to NePAD, the East African Union, and the South African Power Pool. B.3.1.3 Uganda A preliminary search carried out on the Internet for relevant civil society organisations in Uganda indicated that it would also be difficult to select from among the wide number of candidate organisations a few representatives to be invited to the two stakeholder workshops planned for Stage II of the SSEA. In addition, the high international profile of the Bujagali hydropower project and the ensuing environmental controversies were expected to attract the interest of a number of NGOs in regards to the proposed power options during Stage II of the SSEA. Meetings held in Kampala in October 2004 with the Permanent Secretary and the Principal Energy Officer of the Ministry of Energy and Mineral Development, with the Managing Director of Uganda Electricity Transmission Company Ltd., the Assistant Manager of Uganda Electricity Distribution Company Ltd. and the Executive Director of the Rural Electrification Agency of Uganda, provided the Consultant with background information and guidance for Stage II of the SSEA. Discussions with the Permanent Secretary of the Ministry of Energy confirmed that the Bugajali hydropower project should be considered as a project committed for implementation, given that the Government of Uganda has already authorised development of the project. In addition, it was agreed during the discussions that the process followed during Stage I of the SSEA for the selection of civil society representatives from Burundi, Rwanda and Tanzania could also be applied in Uganda in the context of Stage II of the SSEA. In a November 2004 meeting held at IUCN's Country Office in Kampala, IUCN's Uganda Country Representative suggested that a half-day Public information forum on the objectives and scope of Stage II of the SSEA be organised by an independent party in each of the three concerned countries. Given the high level of public interest for power-related issues in the region, such a Forum would enable interested parties to gather information and express their views on the planning of the study. According to the IUCN representative, a Forum of this nature could be planned and implemented by IUCN, given its expertise and active involvement in all three countries. The Consultant followed up on this suggestion and discussed it with the PSC. It was finally decided to not retain this approach. SSEA III - Final Report B-21 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS The IUCN representative also emphasised the importance of taking into account ongoing developments in the context of the East African Community (including a meeting of key donors in Arusha in the context of the East African Community Power Master Plan), of the South African Power Pool, of COMESA (trade) and of the Inter-Governmental Authority on Drought and Desertification. In the specific context of Uganda, he indicated that three issues stand out with respect to power planning: · The role of Egypt and Sudan downstream in the Nile basin; · Previous issues related to the Bujagali hydropower project; · Issues of regional integration related to the creation of the East-African Economic Community. The IUCN representative suggested that the Consultant consider hiring a local consulting firm to assist in the collection and analysis of data on relevant civil society organisations in Uganda and in the collection and analysis of environmental and social data required subsequently in the course of the study. The Consultant followed up on this suggestion and hired a specialised local consultant for such a purpose. In a subsequent November 2004 meeting in Kampala with the Chairwoman of the Uganda National Discourse and Executive Director of Greenwatch Uganda, the importance of exchanging and sharing information with concerned civil society groups in the course of Stage II of the SSEA was emphasised. The Greenwatch representative also expressed concerns about the need for capacity building for NGOs within the framework of the study in order to facilitate collaborative power planning processes in the future. Greenwatch is an environmental law advocacy group that was founded in 1995 and that provides training in environmental law. The objective of this NGO is to promote public participation in environmental management through the strengthening of legal and institutional frameworks, the training of lawyers, working with districts, and providing public awareness programs. Litigation tools are used by Greenwatch on a strategic basis. Issues such as the requirement for public disclosure in the case of the Bujagali hydropower project are identified for legal action by Greenwatch in view of setting precedents for future application of existing legislation. The Greenwatch representative suggested that the Consultant consider hiring a local consultant to assist in the collection and analysis of data on relevant civil society organisations in Uganda and agreed to provide the Consultant with the list of members of the Uganda National Discourse. The Consultant also held a meeting in Kampala in November 2004 with the Executive Director of the National Association of Professional Environmentalists (NAPE), as well as with three other members of NAPE. This association, which is linked to the International Rivers Network, was an influential and vocal player in the campaign against the Bujagali hydropower project. The representatives of NAPE expressed their satisfaction with the proposed scope and contents of Stage II of the SSEA. Even if the number of stakeholder representatives was likely to be restricted to five persons per country, they expressed an interest in promoting a wide participation of stakeholders in the study through exchanges and sharing information with concerned civil society groups. A NAPE representative who is a member of the Ugandan Parliament's Standing Committee on Energy and Natural Resources, suggested that the Consultant be invited to make a presentation of the scope and contents of Stage II of the SSEA to the Standing Committee. As an engineer specialised in water resource management, he also expressed a number of ideas concerning potential power options to be considered in the course of the study and suggested that the Consultant obtain power master plan studies produced in Uganda by SSEA III - Final Report B-22 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Acres and by Kennedy and Donkin. NAPE representatives provided the Consultant with information materials produced by the association and indicated that they were developing a guide on geothermal power for Uganda. They also referred the Consultant to wind power studies carried out by German firms in the Karamoja and the Kampala plains. Further contacts were established subsequently the Director of the Institute of Environment and Natural Resources at Makerere University, in view of identifying other civil society organisations to be considered as possible representatives in the planned stakeholder workshops for Stage II of the SSEA. B.3.2 Organisation of Stakeholder Workshops The third workshop which was held in April 2005 in Nairobi, constituted the first of two regional workshops planned during the second stage of the SSEA. A total of 61 participants attended, including: - 13 PSC members attending as power experts; - 27 stakeholder representatives out of a total of 30 invited by the PSC; - 8 Permanent Secretaries ­ or their representatives ­ and NELTAC representatives also attending as power and water resource experts; - 1 East African Community, 1 SINELAC and 3 Nile Basin observers from Egypt, Sudan and the Nile Secretariat; - 2 representatives of the World Bank and CIDA; - 2 independent reviewers; and - 4 members of the Consultant team. About half of the participants in the Third Stakeholders Consultation Workshop were new to the SSEA process (e.g., participants from eastern DRC, Kenya and Uganda). In view of this, during the morning of Day 1 of the workshop, the Consultant provided: a) a brief overview of the results obtained during Stage I of the SSEA; b) a summary description of the power options identified to date for Stage II of the SSEA as well as the screening criteria proposed for selecting options for further study within the scope of the SSEA; and c) a summary description of the Multi-criteria approach proposed to compare and rank selected power options. Participants were presented with the table of criteria and indicators developed during Stage I of the SSEA as well as with a simplified table of criteria and indicators proposed by the Consultant in the SSEA Stage II Inception Report. The fourth workshop was held in June 2005 to review the contents of the SSEA Stage II Draft Final Report. A total of 61 participants attended, including: - 16 PSC members attending as power experts; - 23 stakeholder representatives out of a total of 30 invited by the PSC; - 6 Permanent Secretaries (or their representatives) and NELTAC representatives also attending as power and water resource experts; - 1 East African Community, 1 SINELAC and 5 Nile Basin observers from Egypt, Sudan and the Nile Secretariat; - 3 representatives of the World Bank and CIDA; - 2 independent reviewers; and SSEA III - Final Report B-23 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS - 4 members of the Consultant team. B.3.3 Comments Provided by Stakeholder Representatives During Workshops The two stakeholder consultation workshops contributed in particular to the following components of the overall process for the SSEA of power development options in the Nile Equatorial Lakes region: a) Inventory of power options; b) Screening of power options; c) Regional power needs assessment; d) Identification of criteria, risks and indicators for comparison of power options; e) Weighting of criteria and risks for comparison of power options; f) Review of results of comparison of power options; g) Definition of the "Transformation scenario"; h) Definition of strategies for the selection of power investment portfolios; i) Assessment of cumulative impacts and identification of mitigation measures for selected power investment portfolios. Views expressed by stakeholder representatives and power experts, including suggestions for amendments to the Consultant's reports, constituted the basis for rich and informative discussions and debates, both between country representatives and the Consultant and among country representatives themselves. Discussions were held in an open and constructive manner. Stakeholder representatives from all six countries expressed the urgent need for power in the NEL region including the need for rural electrification as a means to alleviate widespread poverty. In this respect, they reaffirmed the need to promote a regional framework for sharing benefits, which in turn could help countries implement rural electrification programs that have for a long time only existed on paper. The main contributions of stakeholder representatives and power experts during the two workshops are summarised hereafter according to each of the SSEA project's components. B.3.3.1 Inventory of Power Options During the third workshop, the Consultant presented a preliminary long list of power options for the NEL region, including: a) power options recently selected in the context of Stage I of the SSEA in Burundi, Rwanda and Western Tanzania; b) power options selected in the context of ongoing preparation of the East African Community Power Master Plan in Kenya, Tanzania and Uganda; and c) power options identified on the basis of the availability of pre- feasibility level reports in eastern DRC. Following the presentation, stakeholder representatives and power experts expressed reservations about certain inadequacies in the data, particularly in relation to rehabilitation projects. A number of stakeholder representatives requested additional explanations for the exclusion by the Consultant of a number of potential power projects on the basis of the lack of a full pre-feasibility study. Representatives from DRC noted that such an approach resulted in eliminating all possible power options from eastern DRC. The Consultant explained that in the absence of such studies and associated field investigations, environmental and social data and maps, it would not be possible to evaluate and compare power options on the basis of a Multi-Criteria Analysis (MCA) method. SSEA III - Final Report B-24 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Following further discussions on this issue, a tentative list of additional power options in eastern DRC, Kenya, Tanzania and Uganda was identified during a breakout session by stakeholder representatives and power experts (see list in Table B-4). Power experts from DRC, Kenya, Tanzania and Uganda also committed to providing the Consultant with missing full pre-feasibility reports and data by the end of April 2005. Table B-4 - Additional Power Options Per Country Country Name Energy produced Level of preparation DRC Piana Mwanga (hydro) Upgrade from 9 MW to Rehabilitation/Upgrade 37 MW DRC Kiyimbi (hydro) Upgrade from 17.2 Rehabilitation/Upgrade MW to 43 MW DRC Budana (hydro) 10.5 MW Rehabilitation DRC Mepoko (hydro) 140 MW Pre-feasibility stage DRC Kisala-Ivuga (hydro) 12.5 MW Pre-feasibility stage DRC, Rwanda Sisi-4 on Ruzizi river 205 MW Project identification (hydro) stage Kenya Mumias Sugar 60 MW Expansion (thermal) Kenya Magwagwa (hydro) 90 MW Rehabilitation Kenya Webuye (hydro) 40 MW Feasibility stage Kenya Gogo Falls (hydro) 18 MW Rehabilitation Uganda Mashinzi (hydro) 50 MW Rehabilitation Uganda Muzizi (hydro) 20 MW Pre-feasibility stage Uganda Bizeruka (hydro) 10 MW Pre-feasibility stage Uganda Nengo Bridge (hydro) 10 MW Pre-feasibility stage Tanzania Sonwe (hydro) 300 MW Feasibility stage Tanzania Kidunga (hydro) ? ? Tanzania Mgeta (hydro) ? ? Tanzania Ngeregere (hydro) ? ? The following additional changes were suggested to the Consultant's revised long list of power options during the fourth workshop: · That all potential hydropower sites on the Ruzizi River (on the border of DRC and Rwanda) be clearly identified and commented on in the long list of power options. · That the Consultant produce a separate long list of power options identified in eastern DRC, explaining why all of these options were "screened out", and suggesting a way that these resources could be developed (e.g., the options that would warrant further studies in the short-term). It was also suggested that the Consultant give further consideration to potential interconnections between the DRC and the NEL region. SSEA III - Final Report B-25 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS B.3.3.2 Screening of Power Options Questions and comments provided during the third workshop regarding the identification and screening of power options included the following: · The criteria used for the screening of power options are of critical importance to the process and should be clearly presented to stakeholder representatives so that they may be reviewed and validated during the workshop. · What does the screening criteria "lack of required documentation" specifically refer to? How can the application of such a criteria result in there being no power options selected for further study from eastern DRC? (The mandate of the Consultant should have included the provision of undertaking additional studies for certain power options in eastern DRC to bring them up to the required standards in terms of project documentation)6. A number of comments were provided regarding criteria considered to date for screening out power options, including a suggestion that a uniform minimum plant size of 30 MW should be applied across the region7. Following extensive discussions, it was agreed that the four screening criteria proposed by the Consultant could be applied to the identified power options. It was agreed that a minimum power plant size of 30 MW should be applied in Kenya, Tanzania and Uganda and a minimum plant size of 10 MW should be applied in eastern DRC, Burundi and Rwanda in order to account for regional differences. It was also agreed that requirements in terms of required documentation could be less stringent for proposed rehabilitation or upgrading of existing power plants. Additional comments regarding the screening of power options were also provided during the fourth workshop: · It was noted that the Stieglers Gorge hydropower option was "screened out" for environmental reasons (presumably because it is in a Game Reserve) while the Murchison Falls and the Ayago South hydropower options located in Murchison Falls National Park were retained following the screening of power options. The rationale for this should be clearly explained. · It was suggested that the Consultant give further thought to the most sustainable way of making use of available power options in the NEL region, including hydropower developments in National Parks that could be planned as multi-purpose projects that could actually benefit parks, by providing power, better facilities for tourists and water resources that are often scarce. 6The Consultant responded that the criteria "lack of required documentation" refers to the lack of a full pre- feasibility study report. According to modern standards, the cost of a full pre-feasibility study report typically represents 1% of the capital costs of a power project ­ for a 500 million US dollar project, such a study would cost in the order of 5 million US dollars and would involve a relatively substantial amount of exploratory drilling, as well as preliminary layouts and cost assessments for the project. No such study reports for power options have been identified to date by or for the Consultant in eastern DRC. 7The main criteria considered to date for screening out power options were: a) excessive cost of power generation (e.g., more than US 10 ç/kWh); b) lack of required documentation (e.g., full pre-feasibility study report not available); c) excessive environmental or social risks that cannot be mitigated; and d) minimum power plant size of 30 MW in Kenya, Tanzania and Uganda or of 10 MW in Eastern DRC, Burundi and Rwanda. SSEA III - Final Report B-26 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS B.3.3.3 Selection of Criteria and Indicators for Comparison of Power Options Questions and comments provided during the 3rd workshop in April 2005 regarding the selection of criteria and indicators for the comparison and ranking of power options on the basis of a Multi-criteria analysis included the following: · Have power transmission lines been considered in the selection of criteria? (Energy provided on a regional basis will most likely require the building of new power transmission facilities). If we are faced with an option that performs well in terms of generation but poorly in terms of transmission, how will this be dealt with?8 · Are the criteria applicable to all power options and potential sites? (Certain environmental and social issues related to power options are very site specific).9 · Have the categories of criteria (e.g., Economic, Environmental and Social) been given a relative weighting in view of producing an integrated assessment of the relative merits of each option?10 · Have legal and institutional frameworks been considered in the selection of criteria? (The assessment should take into account regional and national handicaps related to regulatory rigidity and lack of environmental and social awareness).11 · Do the criteria take into account the potential impact of the environment on certain power options? (For instance, the risk of drought or sedimentation for a hydropower plant).12 · Do the criteria take into account impacts on the geology of areas surrounding a proposed power option? (For instance, risks of increased seismicity associated with the creation a large reservoir).13 · With respect to the Socio-economic category of criteria, the indicator relative to "Food security" selected for the criterion "Contribution of Project to Poverty Reduction" was considered either inappropriate, biased in favour of hydropower or too restrictive by a number of participants. Participants agreed that this was a very important criterion and that indicators selected for it should focus on the relative effects of power options 8 The Consultant responded that power options are defined as generation options including all ancillary facilities (e.g., transportation and housing facilities and power transmission line to the closest regional power transmission corridor or substation). 9 The Consultant responded that criteria are selected in view of being applicable to all power options, irrespective of the technology or location involved. 10 The Consultant responded that there is no relative weighting given to categories of criteria, because it is important to clearly set out for decision-makers the economic, environmental and social dilemmas and trade- offs involved in the ranking of power options. 11 The Consultant responded that Legal and institutional frameworks were initially considered as a category of criteria at the onset of SSEA Stage I but were subsequently deleted because they were not considered relevant to the comparison and ranking of power options. 12 The Consultant indicated that hydrological risks, geological risks, technical risks, etc. are explicitly taken account of in the criteria. 13 The Consultant indicated that where relevant, such considerations would be taken into account on the basis of existing criteria (e.g., "Environmental Impacts on the Downstream Reaches". SSEA III - Final Report B-27 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS on this criterion. An alternative suggested was to consider an indicator relative to quality of life (e.g., "Contribution of project to improvement of the quality of life through diversification of livelihoods") which is less restrictive. An other alternative suggested was to consider an indicator relative to vulnerable groups (e.g., "Contribution of project to improvement of the quality of life of vulnerable groups ­ including women"). Yet another alternative suggested was to consider an indicator relative to the "Level of access to power".14 · In regards to the environmental category of criteria, it was suggested that the issue of National Parks and Reserves was perhaps not sufficiently accounted for in the selection of criteria (ref: "Impacts on Designated Habitats and Natural Sites"), given that these could eventually constitute constraints to the implementation of a power option. National Parks or Reserves also have differing levels of environmental sensitivity, from one Park or Reserve to another (e.g., some constitute internationally protected areas) and within each Park or Reserve. It was added that this issue highlighted the importance of taking into account national legal and institutional frameworks. It was suggested that this issue could possibly be considered at the screening stage (e.g., "Impact on the Integrity of National Parks and Reserves"), depending upon the level of protection given to National Parks and Reserves under relevant national regulations. · Following a discussion on the relevance of giving greater importance to areas designated by international treaties and agreements (e.g., Ramsar sites), it was suggested that this issue would be more properly addressed at a subsequent stage (e.g., during preparation of an Environmental Impact Assessment) and that national regulations governing National Parks and Reserves are more constraining than areas designated by international treaties or agreements. · For the criteria "Impacts on Designated Habitats and Natural Sites", it was suggested that an indicator relative to "Biodiversity" be considered. For the criteria "Proliferation of Invasive Aquatic Vegetation and Reservoir Eutrophication", it was suggested to consider invasive species other than vegetation, such as invasive animal species.15 14 The Consultant indicated that a lot of effort has been put into finding an appropriate indicator (or indicators) for this criterion. Indicators based on the concept of "Quality of life" raise the difficult question of how to evaluate or measure such indicators at the SSEA stage, and even more so when they apply to particular vulnerable sub-groups,. Following the workshop, the suggestion of an indicator relative to "Level of access to power" led the Consultant to recommend changing the title of the criterion from "Contribution of Project to Poverty Reduction" to "Promotion of Rural Electrification" because a) the criterion "Contribution of Project to Poverty Reduction" is one of the objectives of the NBI and does NOT discriminate among options; and b) it better accounts for specific concerns expressed by stakeholder representatives. 15 The Consultant responded that both of these proposed indicators raise the difficult question of how to evaluate or measure them in the context of the SSEA. SSEA III - Final Report B-28 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS · Has the criteria relative to "Public Opinion" been taken into account? (This becomes an issue when power transmission lines must be routed through densely populated areas or through National Parks or Reserves).16 · How can the important issue of uncontrolled post-project impacts be dealt with in the criteria? (For instance, power transmission right-of-ways are frequently built upon or used for a variety of incompatible activities).17 The list of criteria and indicators agreed upon in workshops held during Stage I of the SSEA was reviewed and validated with workshop participants in view of: a) Adapting it to the context of SSEA Stage II (where options considered represent a relatively balanced mix of hydro and thermal options rather than a dominance of hydro options); b) Simplifying it in order to facilitate the comparison and ranking of power options on the basis of a Multi-Attribute Analysis . 18 For the second goal related to this assignment, workshop participants were referred to the SMART principles (i.e., Simple, Measurable, Appropriate, Relevant, Timely) which had been suggested by a stakeholder representative or to an adaptation thereof proposed by the Consultant (i.e., Discriminating, Significant, Simple, Timely, Relevant, No Double Counting). Discussions on criteria and indicators were initially held in three break-out groups, i.e., an Anglophone group composed of a dozen power experts and stakeholder representatives from Kenya, Tanzania and Uganda (self-described as the East African Community group), a Francophone group composed of a dozen power experts and stakeholder representatives from Burundi, eastern DRC and Rwanda, and a small group of Other representatives (mainly composed of a few Independent reviewers). While there was a relatively strong convergence of views between the Anglophone and Francophone groups of national power experts and stakeholder representatives, the small group of Other representatives proposed a very different approach which was based on different assumptions. While the first two groups took the table of criteria and indicators developed during Stage I of the SSEA as a starting point for discussions (e.g., a table with 5 categories of criteria and 25 criteria), the group of Other representatives mistakenly started their discussions on the basis of the simplified table proposed in the Consultant's Inception Report (e.g., a table with 3 categories of criteria and a total of 11 criteria).19 16 The Consultant responded that this issue would more properly addressed at a subsequent stage (e.g., during detailed routing studies and preparation of an EIA and of a Resettlement Action Plan). The issue of public acceptability of power lines then becomes an issue of appropriate mitigation or compensation in consideration of internationally accepted standards or guidelines. 17 The Consultant responded that again, this issue is more properly addressed at a subsequent stage. 18 The table of criteria and indicators used during Stage I of the SSEA contained 5 categories of criteria (Economic and financial, Technical, Project risks, Socioeconomic and Environmental) and 25 criteria. In the SSEA Stage II Inception Report, the Consultant proposed a simplified table based on 3 categories of criteria (Economic, Social and Environmental) and 11 criteria. These were both provided for discussions. 19 It was subsequently agreed with members of the small group of Other representatives that their ideas would not be retained given that they had been based upon the wrong reference table. SSEA III - Final Report B-29 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS The main changes proposed by the Anglophone and Francophone groups were the following: a. Economic and Financial Category: Maintained. - Economic Viability: Maintained; - Financial Viability: Maintained; - Lead Time to Deliver Benefits: Maintained. b. Technical Category: Maintained. - Level of Service and Flexibility: Maintained; - Options Level of Preparedness: Deleted because already considered in screening of options; - Diversification of Power Sources: Deleted and replaced by criterion titled: "Access to Local Resources". c. Project Risks Category: Maintained. - Technical Risks: Deleted because already included in project costs; - Financial Risks: Deleted because already included in project costs; - Risks for Investors and Power Utility Clients: Maintained with new indicator titled "Risk related to institutional and legal framework". d. Socio-economic Category: Maintained. - Public Health: Maintained; - Impacts due to Population Displacement: Maintained; - Contribution of Project to Poverty Reduction: Maintained with new indicators: "Contribution of project to improvement of the quality of life through diversification of livelihoods", "Local access to power", and "Contribution of project to improvement of the quality of life of vulnerable groups (including women)"; - Multiple-Use Benefits: Maintained; - Land Requirements and Tenure Systems: New criterion to account for issues related to tenure systems when siting power stations and transmission facilities; - Impacts on Cultural, Heritage and Religious Sites: Maintained; - Impacts on Indigenous Communities: Maintained; - Impacts on Vulnerable Groups: Deleted because already included in "Contribution of Project to Poverty Reduction"; - Socio-economic Impacts on the Downstream Reaches: Maintained. e. Environmental Category: Maintained. - Impact on Resource Depletion: Maintained; - Impacts of Greenhouse Gas Emissions: Maintained; - Impacts of Air Pollutant Emissions on Biophysical Environment: Maintained; - Impacts on Designated Habitats and Natural Sites: Maintained; - Land Requirements: Maintained with suggestion to find more appropriate title (such as "Deforestation"); - Impacts of Sedimentation and Erosion within the Reservoir and Downstream: Maintained with addition of indicator referring to "Ash Disposal"; - Proliferation of Invasive Aquatic Vegetation and Reservoir Eutrophication: Maintained; - Environmental Impacts on the Downstream Reaches: Maintained. SSEA III - Final Report B-30 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Comments provided following the presentation of results are provided hereafter: · It was considered regrettable by many participants that the number of categories of criteria (5 retained) and of evaluation criteria (22 retained) had not been reduced significantly in the context of group discussions. · It was also considered regrettable by certain observers that the issue of National Parks and Reserves had not been dealt with conclusively in the context of discussions on screening criteria and on evaluation criteria for selected options. It was agreed that there was a need to closely examine national legislation and to determine whether they ban power development in National Parks or protected areas ­ or not. · A number of participants observed that there were important considerations that they wished clearly spelled out in the table of criteria and indicators, even if this may be at the risk of increasing the number of criteria. Inversely, they were concerned that by consolidating the table to too large an extent, important considerations may be left out or not sufficiently well spelled out even when taken properly into account. · It was also noted that a few of the additional indicators were suggested to reflect impacts of both hydro and thermal options, issues related to power transmission lines as well as the potential contribution of power options to improved livelihoods. · It was agreed that all power options, whether they were identified during the first or the second stage of the SSEA, should be assessed according to the same set of criteria and indicators during Stage II of the SSEA. · There was a general consensus that the Consultant should review the categories of criteria, the criteria and the indicators proposed by stakeholder representatives with a view of simplifying the selected table on the basis of the SMART principles, inasmuch as stakeholders' concerns were fully accounted for in the process. B.3.3.4 Weighting of Criteria for Comparison of Options Participants in the third workshop discussed the relative importance of the criteria in plenary, and assigned weights to each criterion within the socio-economic and environmental categories. Because of the size of the group involved and of differing levels of awareness between participants who had been involved in previous workshops and those who were new to the process, the discussions on the relative importance (or weighting) of evaluation criteria were relatively difficult and quite challenging to summarise. When there were inconclusive debates about the relative importance of criteria, previous rankings were maintained. At the onset of the plenary session, the relative importance (e.g., Very Important, Important or Less Important) given to criteria by stakeholder representatives during Stage I of the SSEA was presented by the Consultant20. Workshop participants were subsequently invited 20Initially, three distinct levels of importance for criteria were obtained in group discussions (i.e., "Anglophone group", "Francophone group", "PSC group") during the First Stakeholders Consultation Workshop held in Kigali in May 2004. Subsequently, these three different evaluations were integrated into one common evaluation of the relative importance of criteria within each of the categories of criteria during the Second Stakeholders Consultation Workshop held in Dar-Es-Salaam in September 2004. The Consultant proposed that when the relative importance was shared by at least two of the stakeholder groups, this would reflect the selected relative importance retained for the analysis. The Consultant also proposed that where each of the three groups had identified a different level of importance, the mid-importance level (Level 2) should be selected as SSEA III - Final Report B-31 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS to provide the relative importance (or weighting) of new criteria selected during previous breakout group discussions, as these not had yet been provided so far. Participants were also invited to validate the relative importance (or weighting) given to criteria that had been retained from Stage I of the SSEA, given that participants from eastern DRC, Kenya and Uganda had not been involved to date in the process. The relative importance proposed for each criterion were the following: a. Economic and Financial Category - Economic Viability: Very Important (maintained); - Financial Viability: Very Important (maintained); - Lead Time to Deliver Benefits: Important (maintained). b. Technical Category - Level of Service and Flexibility: Very Important (maintained); - Access to Local Resources: Very Important (new criteria). c. Project Risks Category - Risks for Investors and Power Utility Clients: Very Important (new weighting). d. Socio-economic Category - Public Health: Important (maintained); - Impacts due to Population Displacement: Important (maintained); - Contribution of Project to Poverty Reduction: Very Important (maintained); - Multiple-Use Benefits: Very Important (maintained); - Land Requirements and Tenure Systems: Very Important (new criteria); - Impacts on Cultural, Heritage and Religious Sites: Less Important (maintained); - Impacts on Indigenous Communities: Less Important (maintained); - Socio-economic Impacts on the Downstream Reaches: Important (maintained). e. Environmental Category - Impact on Resource Depletion: Important (maintained); - Impacts of Greenhouse Gas Emissions: Important (maintained); - Impacts of Air Pollutant Emissions on Biophysical Environment: Less Important (maintained); - Impacts on Designated Habitats and Natural Sites: Important (maintained); - Land Requirements: Important (maintained); - Impacts of Sedimentation and Erosion within the Reservoir and Downstream: Less important (maintained); - Proliferation of Invasive Aquatic Vegetation and Reservoir Eutrophication: Less important (maintained); - Environmental Impacts on the Downstream Reaches: Important (maintained). Comments provided on the relative importance (or weighting) of evaluation criteria in the third workshop are summarised hereafter: the relative importance. After an extensive discussion on the matter, all of the workshop participants in Dar-Es- Salaam agreed on the levels of importance for evaluation criteria proposed by the Consultant. SSEA III - Final Report B-32 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS · It was suggested that in the wider six country context associated with Stage II of the SSEA, certain criteria such as "Impacts of Greenhouse Gas Emissions" and "Proliferation of Invasive Aquatic Species and Reservoir Eutrophication" should be given a greater relative importance or weighting than during Stage I of the SSEA. · The Consultant was asked whether the information available in study reports was sufficient to properly address environmental and social issues such as population resettlement or impacts on habitats associated with power options21. · It was suggested that, given the amount of work and discussions involved in the weighting of criteria during the first two stakeholder consultation workshops, the Consultant should avoid changing the weightings of criteria unless it was deemed absolutely necessary. For the benefit of new participants in the SSEA process, a stakeholder representative recalled the reasons for giving certain relative levels of importance to a number of socio-economic and environmental criteria during Stage I of the SSEA and suggested that these weightings remain unchanged. · It was also suggested that the Consultant carefully review the proposed weighting of criteria to ensure that they were coherent within each category of criteria. For example, certain relatively linked environmental criteria were considered in one instance as being "Important" (ref: "Environmental Impacts on the Downstream Reaches") and in another instance as being "Less Important" (ref: "Impacts of Sedimentation and Erosion within the Reservoir and Downstream"). B.3.3.5 Review of Revised Criteria and of Results of Comparison of Options During the preparation of the Draft Final Report, the Consultant substantially revised the list of criteria and indicators retained at the end of the third workshop on the basis of the following principles: · Criteria that do not lend themselves to being assessed on the basis of a ratio scale (taking into account the magnitude of impacts) are removed from the Multi-Attribute Analysis and subjects related to these criteria are addressed separately in the assessment of project risks and/or in the cumulative impacts assessment; · Criteria retained in the Multi-Attribute Analysis are assessed quantitatively on the basis of one indicator only. As a result, the list of criteria and indicators retained for the Multi-Attribute Analysis was reduced to three categories of criteria (Cost, Socio-economic and Environmental) and 11 criteria and indicators. The remaining 11 criteria retained after the third workshop were considered on a qualitative basis in the assessment of project risks and/or in the cumulative impacts assessment (refer to Tables B-5 and B-6). Participants in the fourth workshop discussed the revisions made to the list of criteria, project risks, indicators and weightings and the results of the comparison of power options on the basis of the Multi-Attribute Analysis of the assessment of project risks. Comments provided are summarised hereafter: 21 The Consultant responded that the availability of full pre-feasibility study reports with associated preliminary layouts and maps of reservoirs should, with the assistance of additional data collection and/or site visits, be sufficient to provide an appreciation of the environmental and social issues involved at the SSEA level. Additional detailed data will be required subsequently for preparation of a project-specific EIA and/or RAP. SSEA III - Final Report B-33 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS · It was suggested that the Consultant clarify the rationale behind the selection of the "Rural Electrification" criterion. · It was noted that the Consultant referred to nine types of project risks in the Draft Final Report, but only assessed seven types of project risks in the comparison of power options. · It was noted that the main reasons for giving Rusumo Falls a lower rating than other hydropower projects were linked to the criterion "Impacts on Land use "and to the project risk "Risk of opposition from external groups". There was a concern that the evaluation by the Consultant of the socio-economic impact of the Rusumo Falls hydropower option was too severe. It was also suggested that the less than positive comments on the Rusumo Falls hydropower option in Chapter 7 of the Draft Final Report should be reworded. It was added that it was important to comment on possible mitigation actions that could be put into place and on the importance of the project to the region. · The Consultant identified a greater hydrological risk for hydropower options on the Victoria Nile than in the Kagera River Basin, even if minimum hydrological risks have been observed on the Victoria Nile on the basis of hydrological data collected over a number of years. · The Bujagali hydropower project was given a less good score in regards to population displacement requirements, even if all resettlement activities have been completed. It was also given a less good score in regards to power transmission requirements, when the required power lines are very short. It was also noted that the Consultant gave the Bujagali project a higher "risk of opposition from external groups" than the Murchison Falls hydropower option that is located in a National Park. · The method used for the grouping of power options (e.g., "best evaluated options" and "other options") following the comparative analysis needed to be further clarified in the Final Report. B.3.3.6 Validation of Criteria, Risks, Indicators and Weightings The list of criteria, project risks, indicators and weightings used for the comparison of power options was validated with participants at the end of the fourth workshop (refer to Tables B-5 and B-6). Comments provided by participants on criteria, risks, indicators and weightings used for the comparison of power options are summarised hereafter: · A consensus emerged to the effect that the indicator used to evaluate the criterion "Promotion of Rural Electrification" was inappropriate and that a more appropriate indicator would be "Population density close to the power station and along the likely power transmission line route". · There was a need to clarify the differences between certain criteria, such as "Land Requirements" and "Land Issues" (under Socio-economic criteria), "Downstream Impacts" (under both Socio-economic criteria and Environmental Criteria), etc. There was also a need to clarify, through the use of footnotes or other means, where certain important criteria that have been removed from the Multi-Attribute Analysis have been assessed (e.g., "Use of Local Resources", "Designated Habitats", "Public Health", etc.). SSEA III - Final Report B-34 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS · It was suggested that the "Risk of opposition from external groups" should be extended to internal groups that can also play an important role in supporting or opposing the development of a power option. It was also suggested that indicators relative to "Cultural Heritage" and to "Indigenous Communities" (re: removed criteria) be added to the assessment of this risk. Table B-5 - Revised Evaluation Criteria, Indicators and Weights Following the Fourth Stakeholder Consultation Workshop Criteria Indicators Category: Cost Economic Viability Unit cost of firm energy per kWh over the projected life of the facility (US¢/kWh), taking into account: - Direct investment ­ plant - Engineering and owners costs - Interest during construction - Operating and maintenance costs - Environmental and social mitigation costs (included in the civil works contingency amount) - Multi-purpose benefits (irrigation, fisheries) ­ treated by cost sharing for the dam - Contingency allowance for uncertainties (e.g. technical, financial and geological risks) Weight: 100% Category: Socio-economic Impacts Due to Population Number of persons affected by project infrastructure and ancillary Displacement facilities (People/GWh) Weight: 15% Promotion of Rural Number of persons living in a 10 km radius of the power station and in a Electrification 10 km wide corridor along the transmission line between the option and the main transmission grid (People/GWh) Weight: 35% Socio-economic Impacts on Number of persons living in a 1 km corridor along the river with altered the Downstream Reaches flow downstream of the dam (People/GWh) Weight: 15% Land Issues Area required for project infrastructure, including reservoir and transmission facilities (ha/GWh) Weight: 35% Category: Environment Impact on Resource Depletion Energy payback ratio: ratio of energy produced during the normal life span of the option divided by the energy required to build, maintain and fuel the generation equipment. This indicator is a measure of the global pressure of an option on the environment Weight: 25% Impacts of Greenhouse Gas Net CO2 equivalent emissions over the life cycle of the project (t/GWh) Emissions Weight: 10% SSEA III - Final Report B-35 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Criteria Indicators Impacts of Air Pollutant SO2 equivalent emissions over the life cycle of the project (t/GWh) Emissions on Biophysical Environment Weight: 10% Land requirements Area required for project infrastructure, including reservoir and transmission facilities (ha/GWh) Weight: 25% Waste Disposal Land area required for ash disposal (ha/GWh) Weight: 5% Environmental Impacts on the Length of river with altered flow downstream of the dam (km/TWh) Downstream Reaches Weight: 25% Table B-6 - Revised Project Risks and Weights Following the Fourth Stakeholder Consultation Workshop Risks Factors Considered in Assessing Risks Risks of Opposition from - Potential for significant population resettlement External or Internal Groups - Potential impacts on unique habitats as a result of reservoir impoundment or hydraulic modifications downstream of the dam - Potential for significant increased risks to public health - Potential impacts on cultural, historical and religious sites - Potential impacts on indigenous communities Weight: 11% Risks of impacts on unique - National parks, Ramsar sites, etc. habitats as a result of reservoir - Scenery of exceptional beauty impoundment or hydraulic modifications downstream of Weight: 15% the dam Increased risks to public health Risks of malaria and bilharzia for hydroelectric projects and risks of pulmonary diseases for thermal projects Weight: 15% Risks related to Institutional - Option located in a country with a weak framework or one whose and Legal Framework framework has been affected by recent social unrest - Option that have a direct impact on two or more countries Weight: 11% Use of Local Resources Rate of use of local sources of energy (renewable and non renewable) Weight: 11% Gestation Period Minimum lead time before the project can be commissioned, including time for further investigations, decisions, design, tendering and construction Weight: 7% Risks of Sedimentation Expected sediment load in river at project site Weight: 7% Hydrological Risk Historical hydrologic record Weight: 7% SSEA III - Final Report B-36 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS Risks Factors Considered in Assessing Risks Financial Risk - Risk of not being able to attract sufficient financing - Risk of financial over-runs Weight: 15% · It was suggested that the former criteria "Impacts on Designated Habitats and Natural Sites" be retained as an additional Project risk considering that it was not sufficient to address such an important issue only at the cumulative impact assessment stage22. · No other consensus emerged regarding changes to be made to criteria, indicators and weightings used for the Multi-Attribute Analysis. In regards to the assessment of project risks, participants were asked to identify the most important risks and the least important risks among the seven types of risks retained in the Draft Final Report. "Risks of sedimentation", "Risks related to the gestation period", and "Hydrological risks" were deemed as "Less important" by certain participants. "Risks of opposition from external groups" and "Institutional and legal risks" were deemed "Less Important" by certain participants and as "Important" by others. "Financial risks" were deemed as "Very important" by certain participants. It was agreed that the Consultant should adjust the weightings of Project risks on the basis of comments provided by participants. B.3.3.7 Definition of "Transformation Scenario" Participants in the fourth workshop discussed the assumptions underlying a "Transformation scenario" in the Nile Equatorial Lakes region. Comments provided on this aspect of the Regional Power Needs Assessment are summarised hereafter: · It was suggested that a Transformation scenario was required to indicate the annual growth rates required to pull the NEL region out of poverty within the time horizon of the project. The 15% annual growth rate hypothesised for the period between 2010 and 2020 could thus serve as a benchmark. It could also serve as a strong argument to use against environmental lobbies by providing an indication of the extent of regional power needs. It was thus agreed that the 15% annual growth rate proposed for the Transformation scenario should be maintained. · With respect to the Transformation scenario, the Consultant referred to a target of 100% electrification by 2020 for the NEL region with a per capita level of consumption of 300 kWh per year. What percentage of electrification would be obtained in the case of the Base case scenario (e.g., 5% to 7% annual growth from 2010 to 2020)? What would be the annual growth rate required to attain 100% electrification by 2020 for the NEL region with a per capita level of consumption of 500 kWh per year? · In reference to the Transformation scenario, the Consultant noted that less than 4,000 MW of additional power could be provided to the NEL region on the basis of power options retained following the screening process, and that an additional 6,000 MW would be required by 2020, either through imports of coal for thermal 22The Consultant agreed with this suggestion and, applying the same rationale, added a ninth Project risk on the basis of the former criteria " Public Health". SSEA III - Final Report B-37 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS generation or from direct imports of power from outside the region. This raised the question of the potential impact of small power generation units (i.e., less than 30 MW in the EAC region and less than 10 MW in Burundi, Rwanda and eastern DRC) that could also serve to provide additional power to the region. B.3.3.8 Definition of Strategies for Selection of Power Investment Portfolios Participants in the fourth workshop discussed possible power development strategies and related power investment portfolios for the NEL region. Comments provided are summarized hereafter: · It was noted that the Consultant used various terms interchangeably in Chapter 7 of the Draft Final Report (e.g., "forecast" and "scenario" ­ "scenario" and "strategy" ­ "portfolio", "expansion plan" and "indicative plan"). There is a need for clear definitions and consistency in the use of such terms. · It was suggested that the term "portfolio" be replaced by "NELSAP Development Plan". · Concern was expressed about potentially good options being left out of the NEL region power master plan because of lack of data. What happens if the required data is found or obtained over the next 15 years (e.g., the time horizon of the regional power master plan)? Break-out group discussions were held subsequently to select power development strategies for the NEL region. Three groups were formed, i.e., two groups made up of power experts from the PSC and of stakeholder representatives from member countries and one group constituted of other representatives (Permanent Secretaries and NELTAC representatives, East-African Community, SINELAC and Nile Basin observers from Egypt, Sudan and the Nile Secretariat, representatives of the World Bank and CIDA and independent reviewers). The results of group discussions were set out in a list of principles that were identified by participants in the three groups (refer to Figure B-1). The main conclusions were as follows: · The regional power master plan should adhere to the "Least total cost principle" (cost of energy, environmental impact, social impact plus a credit for multipurpose benefits). · The regional power master plan should ensure security of supply at national and regional levels (through technological diversification to minimise hydrological risks and through geographical diversification to ensure an equitable distribution of power generation facilities among countries). · Three load forecast scenarios should be considered in the Final Report for Stage II of the SSEA: Base Case, High Growth and Transformation. B.3.3.9 Assessment of Cumulative Impacts and Identification of Mitigation Measures for Selected Power Investment Portfolios At the end of the fourth workshop, suggestions were provided by participants regarding the methodology to be used for the assessment of cumulative impacts and the identification of mitigation measures for selected power development portfolios. It was suggested, in particular, that the Consultant provide an outline of baseline environmental conditions in the portions of the Nile basin that could be affected by proposed hydropower options. SSEA III - Final Report B-38 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS B.3.3.10 Other Comments Concerning the SSEA Stage II Draft Final Report Other comments provided by participants in the fourth workshop on the SSEA Stage II Draft Final Report are provided hereafter: Figure B-1 - Guiding Principles for NEL Regional Power Development/Master Plan What is NEL Regional Power Master Plan? - A plan that optimally matches choice of project options with a defined demand forecast in a manner that attempts to ensure geographical distribution of projects as well as equitable sharing of energy. - A plan that is consistent with national level plans and conforms to the principle of "least total cost" defined to include cost of energy, cost of investment, cost of environmental & social mitigation and credits for multipurpose benefits. - A plan that ensure security of supply - geographic diversification and technological diversification. - A Plan that responds to demand forecast that includes base case (GDP growth rate of 5.7%), high forecast (10% GDP growth) and regional transformation scenario (15% GDP growth). - Geographical diversification - maps out the power generation resource endowment in each country and import limits starting from the time of an interconnected network. - A Plan that responds to three time frames - short term, medium term, and long term - The gradual but planned evolution of the NEL regional power market development - financing for interconnections and regional dispatch centre in the medium term through institutional support of the Nile Basin Power Forum {Jointly with the NBI RPT Project} - Ensuring strengthening/leveraging the role of existing regional institutions (EAC, SINELAC, EGL, etc.) in regional power development - Conducting detailed feasibility study, design & engineering of power generation projects for the medium and long term. - A plan that shows a detailed cost-benefit analysis from a national and regional perspective - A plan that is a "living document" - flexible in order to respond to new and emerging technologies, prevailing and possible future scenarios. · It was strongly recommended that a more positive tone be provided in Chapter 2 (Regional context) by mentioning encouraging recent developments in Burundi, DRC and Rwanda since 2002. It was also suggested that the Consultant ensure that the analysis in Chapter 2 be fully grounded in facts and that added information be provided about CPGL, a regional grouping including Burundi, Rwanda and DRC. · It was also noted that a table in Chapter 3 (page 3-27) referred the reader to comments on environmental legislation in Burundi and Rwanda with no information provided. SSEA III - Final Report B-39 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS · It was suggested that the conclusions of the Final Report should be fully consistent with those of the SSEA Stage I Final Report, in particular regarding the assessment of the environmental and social impact of the Rusumo Falls hydropower project. It was also recommended that in the event where the Consultant provided differing assessments of power options reviewed in the East African Community Power Master Plan (EACPMP), that the rationale for such differences be clearly stated. · A more in depth analysis should be provided regarding the possible development of hydropower schemes in Natural Parks (such as Murchison Falls and Ayago South in Murchison Falls National Park in Uganda). Proper consideration should also be given to the application of a multi-purpose approach for development schemes in National Parks. · Project data sheets should be produced for each of the power options included in the power investment portfolios presented in the SSEA Stage II Final Report. These data sheets should contain a description of available environmental and social studies carried out for each project as well a summary review of environmental and socio- economic impacts and related mitigation, optimisation or compensation measures. B.3.4 Evaluation of Stakeholder Workshops Outcomes The stakeholder consultation workshops during Stage II of the SSEA were chaired with considerable skill and patience by a PSC member from Kenya-Generation in Kenya (third workshop held in April 2005) and by the NEL-TAC Chairman (fourth workshop held in June 2005). This reflected a significant transformation between Stage I and Stage II of the SSEA which saw country representatives from the PSC progressively taking charge of the process and the Consultant and international development agency representatives gladly taking a back seat to the process. Both the 3rd and 4th workshops fully met all of the objectives initially set out by the PSC and the Consultant. Nearly all of the invited stakeholder representatives participated in the two regional workshops. All of the participants actively joined in the discussions. Significant contributions were made by participants in regards to all of the themes submitted for discussions during the workshops. These contributions guided the work of the Consultant during preparation of the Final Report for the second stage of the SSEA. In addition, participants in the third workshop provided suggestions for the subsequent workshop which included the following: · Providing an information kit to participants upon arrival at the hotel selected for the workshop (workshop agenda, arrangements for food and lodging, etc.); · Sharing documents for the meeting early enough to enable participants to acquaint themselves with areas of discussion; · Providing summaries in French of the documents to be discussed; · Provided explanations of terms used be in order to avoid misunderstandings especially for those new to the SSEA process; · Availability of appropriate maps or posters to better support discussions. · Improving upon time management during workshops. These suggestions were followed up upon by the Consultant when planning the fourth workshop. A particular effort was put into preparing large-format colour maps of the NEL SSEA III - Final Report B-40 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS region indicating the locations of power generation and transmission options under consideration. A total of 19 stakeholder representatives (for both workshops) responded to the Consultant's request to produce an evaluation of the stakeholders consultation workshops during the second stage of the SSEA. The responses showed a considerable degree of satisfaction regarding the venue selected for the workshops, the quality of reports and supporting materials, time allowed for the review of reports and supporting materials before and during the workshop, the active role given to participants in planning of the SSEA, and, in particular, the openness of discussions and time given to participants to express their points of view. One of the workshop participants wished, in the name of all the stakeholder representatives invited, to thank the workshop organisers for bringing so many different voices to the table. He also expressed the hope that such workshops would be held more often in the region in the future. Primary issues identified by participants in the fourth and final workshop and requiring attention for future workshops included: · Improved time management during workshops, including the possibility of adding a third day to ensure that all issues are addressed in appropriate depth; · Better balancing the time allowed for Consultants' presentations in comparison with the time allotted to discussions with stakeholders; · Making sure the regional focus is maintained instead of country-specific discussions; · Availability of French language summary reports and supporting materials. B.3.5 Main Lessons Learned from Stage II of the Stakeholder Consultation Process The main lessons learned from the implementation of the stakeholder consultation process adopted for the second stage of the SSEA are briefly described below. B.3.5.1 Opportunities Created by the Process Members of the PSC noted at the onset of Stage II of the SSEA that there was a need for greater involvement on their part both with respect to the selection of stakeholder representatives and to the planning and management of future stakeholder workshops. Careful attention was given to addressing this concern. PSC members played an important role in getting Permanent Secretaries of Energy and NELTAC representatives from their respective countries involved in the process and played a much more active role both in the selection of invited participants and in the management of both stakeholder workshops. Ultimately, the stakeholder consultation process adopted in the context of the SSEA of power development options in the NEL region created new opportunities for civil society organisations to actively contribute in the planning of power infrastructure programs that are critically needed to attain regional poverty alleviation objectives. The stakeholder representatives selected for the consultation workshops brought significant knowledge in regards to cross-sectoral environmental, social and community development issues. Invited experts and civil society representatives were given the opportunity to exchange with colleagues from neighbouring Nile basin countries on the basis of their common fields of expertise. They were also given the opportunity to learn from the invited power experts from the PSC and from Nile basin observers from Sudan, Egypt and the Nile Secretariat about the challenges involved in the planning of power infrastructure programs in the NEL region. SSEA III - Final Report B-41 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS In turn, the invited power experts from the PSC and members of the Consultant's study team were able to learn from the invited experts and stakeholder representatives about cross- cutting environmental, social and community development issues that significantly affect the planning of power infrastructure programs in the NEL region. As a result of these exchanges, the contributions of participants in the workshops are clearly reflected in the outcomes and conclusions of the assessment. B.3.5.2 Limitations of the Process The main limitations of the stakeholder consultation process were as follows: · The limited knowledge about the SSEA process by participants from the DRC, Kenya and Uganda had a significant impact on the level and quality of participation in the workshops, particularly in the case of the third workshop held at the onset of the second stage of the SSEA. Participants from Burundi, Rwanda and Tanzania who had attended the first two workshops during the first stage of the SSEA and were more familiar with the assessment and with workshop procedures tended to play a more active role in the third workshop and were a little frustrated by the time required to bring other participants "up to speed". Increasing the length of the workshops (for instance, from two to three days) would have added to the difficulty of retaining very busy people over two days in an isolated environment. For instance, several PSC and stakeholder representatives (including a number from Kenya) did not participate in the workshops held in Nairobi and Mombasa because they could not make themselves available over a period of two days. · Participants in the workshops (including PSC representatives) tended to focus on national concerns at the expense of wider-ranging issues at the level of the NEL region. This was an unavoidable aspect of the multinational consultation process associated with the project. In particular, a lot of time was spent during the third workshop discussing the important local concerns of stakeholder representatives from eastern DRC. A number of participants from other countries expressed their concern about the risk that regional issues covered in the workshops could be subsumed by local concerns. This risk was addressed by the Consultant in the fourth workshop by holding separate discussions with the delegation from the DRC to address their legitimate local concerns23. · Certain critical methodological activities required for the comparison of power options, such as the selection of evaluation criteria and indicators and reaching a consensus on the relative weighting of criteria, involved complex discussions that are better adapted to small groups of people (e.g., two to six persons sharing the same culture and backgrounds) than to groups of 60 people from a number of different countries and cultural backgrounds. This challenge was overcome with considerable difficulty by addressing these issues in all four stakeholder workshops and by benefiting from the considerable patience and understanding of all participants. 23 The participation of representatives from eastern DRC constituted a distinct challenge inasmuch as: 1) they had been selected by groups of local development NGOs to represent their interests during the workshops; 2) they had paid their own way to travel over long distances by road and by air to participate in the workshops prior to being reimbursed by the Consultant; 3) they were confronted with a situation where all regional power options in eastern DRC were screened out for lack of appropriate information; and 4) they were required to report back to the NGOs that had delegated them to the workshops. In such a context, the workshop chairmen showed a lot of tact by allowing then to fully express their concerns during the workshops. SSEA III - Final Report B-42 017334-001-00 APPENDIX B ­ SYNOPSIS OF STAKEHOLDER CONSULTATIONS · Even if the quality of English and French interpreter services was considered quite good by participants in the workshops, Francophone participants from Burundi, the DRC and Rwanda were often at a disadvantage given that a majority of the discussions were held in English. This made it difficult for Francophones to "jump into discussions" and led them sometimes to intervene out of context. · In general, strong interest was expressed in the public information bulletins by representatives of French-speaking countries due to the fact that reports were mainly produced in English. A number of stakeholder representatives from Burundi, DRC and Rwanda indicated that they had accessed project-related documents on the project Web site. However, eastern DRC representatives were the only ones that indicated that information bulletins distributed at the workshops were disseminated to other parties in their respective countries. Alternative means of communication for disseminating information to a broader audience were discussed with stakeholder representatives. These included the forwarding of information bulletins to National Discourse Forums and promoting exchanges of information between various civil society organisations interested in the assessment process. However, these avenues were not further explored given the time and logistical constraints involved in the project and would merit further consideration24. In particular, due consideration should be given to making similar projects known to a wider public by, for instance, organising information meetings in each of the countries at the onset of the project25. 24 For instance, participants in the workshops indicated that there was insufficient time to consult with their peers/colleagues prior to the workshops, in consideration of the fact that they had received draft reports two weeks or less than two weeks before the workshop. 25 With the assistance of the World Bank and the NBI Secretariat, two public information meetings were set up with the national media in Dar-es-Salaam at the end of the second workshop in September 2004 and in Mombasa at the end of the fourth workshop in June 2005. SSEA III - Final Report B-43 017334-001-00 APPENDIX C SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AND LEGAL AS WELL AS THEIR ADMINISTRATIVE FRAMEWORKS SSEA III - Final Report 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS TABLE OF CONTENTS PAGE C SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AND LEGAL AS WELL AS THEIR ADMINISTRATIVE FRAMEWORKS C-1 C.1 Introduction C-1 C.2 Burundi C-1 C.2.1 Overall Environmental and Social Framework and Environmental Assessment Procedures C-1 C.2.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights C-2 C.2.3 Resettlement Policies and Regulations C-2 C.2.4 Constraints on Development in Parks and Protected Areas C-2 C.2.5 Laws and Regulations Specific to Water Management (including irrigation)C-3 C.2.6 Laws and Regulations Specific to Forestry C-3 C.2.7 Environmental Commitments C-3 C.2.8 Greenhouse Gases C-4 C.3 The Democratic Republic of Congo (DRC) C-4 C.3.1 Overall Environmental Framework and Environmental Assessment Procedures C-4 C.3.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights C-5 C.3.3 Resettlement Policies and Regulations C-5 C.3.4 Constraints on Development in Parks and Protected Areas C-5 C.3.5 Laws and Regulations Specific to Water Management (including irrigation) C-6 C.3.6 Laws and Regulations Specific to Forestry C-6 C.3.7 Environmental Commitments C-6 C.3.8 Greenhouse Gases C-7 C.4 Kenya C-7 C.4.1 Overall Environmental Framework and Environmental Assessment Procedures C-7 C.4.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights C-8 C.4.3 Resettlement Policies and Regulations C-8 C.4.4 Constraints on Development in Parks and Protected Areas C-9 C.4.5 Laws and Regulations Specific to Water Management (including irrigation) C-10 C.4.6 Laws and Regulations Specific to Forestry C-10 C.4.7 Environmental Commitments C-10 C.4.8 Greenhouse Gases C-11 C.5 Rwanda C-11 C.5.1 Overall Environmental Framework and Environmental Assessment Procedures C-11 C.5.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights C-11 C.5.3 Resettlement Policies and Regulations C-12 C.5.4 Constraints on Development in Parks and Protected Areas C-12 C.5.5 Laws and Regulations Specific to Water Management (including irrigation) C-13 SSEA III - Final Report C-i 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS C.5.6 Laws and Regulations Specific to Forestry C-13 C.5.7 Environmental Commitments C-13 C.5.8 Greenhouse Gases C-14 C.6 Tanzania C-14 C.6.1 Overall Environmental Framework and Environmental Assessment Procedures C-14 C.6.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights C-16 C.6.3 Resettlement Policies and Regulations C-16 C.6.4 Constraints on Development in Parks and Protected Areas C-16 C.6.5 Laws and Regulations Specific to Water Management (including irrigation) C-16 C.6.6 Laws and Regulations Specific to Forestry C-17 C.6.7 Environmental Commitments C-17 C.6.8 Greenhouse Gases C-17 C.7 Uganda C-18 C.7.1 Overall Environmental Framework and Environmental Assessment Procedures C-18 C.7.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights C-19 C.7.3 Resettlement Policies and Regulations C-20 C.7.4 Constraints on Development in Parks and Protected Areas C-20 C.7.5 Laws and Regulations Specific to Water Management (including irrigation) C-21 C.7.6 Laws and Regulations Specific to Forestry C-22 C.7.7 Environmental Commitments C-22 C.7.8 Greenhouse Gases C-22 C.8 International Environmental Commitments C-22 C.8.1 Convention Concerning the Protection of the World Cultural and Natural Heritage C-23 C.8.2 African Convention on the Conservation of Nature and Natural Resources (Algiers Convention) C-23 C.8.3 Ramsar Convention C-28 C.8.4 Convention on Biological Diversity C-29 C.8.5 Convention for the Establishment of the Lake Victoria Fisheries Organization C-29 C.8.6 UN Convention to Combat Desertification (UNCDD) C-30 C.8.7 International Commitment Concerning Illegal Trade of Wild Fauna and Flora C-30 C.8.8 International Commitments Concerning Greenhouse Gas Emissions and Hazardous Waste C-30 C.9 The World Bank's `Safeguard Policies' C-31 C.10 Regional Institutions C-33 C.10.1 African Union (AU) C-33 C.10.2 New Partnership for Africa Development (NePAD) C-33 C.10.3 Economic Community of the Great Lakes Countries (CEPGL) C-34 C.10.4 East African Community (EAC) C-34 C.10.5 Southern Africa Development Community (SADC) C-36 C.10.6 Common Market of Eastern and South Africa (COMESA) C-37 C.10.7 Communauté Économique des États de l'Afrique centrale (CEEAC) C-37 C.10.8 Inter-Governmental Authority for Development (IGAD) C-37 SSEA III - Final Report C-ii 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELL AS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS C SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AND LEGAL AS WELL AS THEIR ADMINISTRATIVE FRAMEWORKS C.1 Introduction This Appendix provides a country-specific overview of environmental frameworks that include descriptions of: · The overall environmental and social framework and environmental impact assessment procedures; · Laws and regulations specific to land ownership and land use rights; · Resettlement policies and regulations; · Constraints on development in parks and protected areas; · Laws and regulations specific to water management (including irrigation); · Laws and regulations specific to forestry; · International commitments; · Greenhouse gas emissions. Furthermore, this appendix provides a short description of the World Bank's `Safeguard Policies' and of the main international environmental commitments of the Upper Nile Basin countries. The main sources and references underpinning the description of the environmental legal and administrative frameworks of the six countries can be found in Appendix N. C.2 Burundi C.2.1 Overall Environmental and Social Framework and Environmental Assessment Procedures In 2000 Burundi enacted an Environmental Code, the "Loi No 6/2000 ­ Portant Code de l'Environnement de la République du Burundi"1. Chapter III of the Environmental Code provides for an Environmental Assessment process for projects/activities that are likely to affect the environment. In particular, Article 21 stipulates that requests for proposals relative to such works must contain an environmental impact studies section. Article 23 defines the mandatory content of the environmental impact study and Article 34 specifically identifies dams as works that are subject to this procedure. Title III sets out principles of protection and enhancement of natural resources. Under Chapter III of Law No. 6/2000 (Article 27), the `Ministère de l'Aménagement du Territoire et de l'Environnement' is given the power of enforcement and of ensuring compliance. The Politique nationale de Gestion des Ressources en Eau et Plans d'Actions ­ Juillet 2001 calls for reinforcing the ecological equilibrium and the protection of wetlands by applying the RAMSAR Convention ("renforcement de l'équilibre écologique et protection des zones humides par la mise en oeuvre de le Convention RAMSAR"). 1 Law No. 6/2000, Environmental Code of the Republic of Burundi. SSEA III - Final Report C-1 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS Law No. 1/014 of 11 August 2000, regulates the use of natural resources, including licensing, water management plans and water quality standards. There are no air pollution standards since it is not perceived as a problem in Burundi at the present time (few cars, little industrial activity, etc.). However, there is a private initiative (BRARUDI) to reduce emissions. There is no specific legislation relative to cultural heritage and indigenous rights,. For the Twas (Pygmies), there are programs for progressive integration through poverty alleviation. Occupational health and safety legislation is covered by: · The Labor Code, which governs employer/employee relations; · The Public Health Code; · The Social Security Code which regulates interventions in favor of social groups, such as pensions, medical assistance, work injuries, unemployment insurance, and allows for the creation of « Associations Mutuelles » for identified sectors; · There are no special rules or prohibitions regarding occupational health and safety applicable to the energy sector; only normal safety rules need to be followed. No references were found on Strategic Assessment Processes related to the electricity sector. C.2.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights In Burundi, expropriation rules are governed by the `Loi 1/008 du 1er septembre 1986 portant code foncier and by the Décret-loi 1/41 du 26 novembre 1992 portant instauration du domaine public'. Under the dispositions of Law No. 1/014 of 11 August 2000, REGIDESO can occupy lands in the public domain without compensation2. According to Article 32, REGIDESO must ask the Government to resort to expropriation when negotiations are not successful. Articles 40, 41 and 49, for their part, impose the obligation to put lands required for public use at the disposal of the State. Indemnities are set under the terms of the Expropriation Law. Compensation rates have been actualised by the `Ordonnance Ministérielle n°720/CAB/667/2003 portant actualisation des tarifs d'indemnisation des terres, des cultures et des constructions en cas d'expropriation pour cause d'utilité publique'. C.2.3 Resettlement Policies and Regulations This issue is not adressed in Burundi's policy, legal and administrative framework. C.2.4 Constraints on Development in Parks and Protected Areas Burundi's Loi portant Code de l'Environnement does not specifically exclude power projects from integral reserves, national parks or natural reserves, but specifies that such areas can be determined by government decree when they present a special interest and must be 2 Law No. 1/014, art. 30 SSEA III - Final Report C-2 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS protected from all human intervention that would be liable to alter or spoil them . 3 Consequently, no activity thus liable to alter or spoil the areas comprised in national parks and natural reserves will presumably be allowed within these areas. Protection measures relative to integral reserves will be even more rigorous. Also, buffer zones can be decreed around national parks and natural reserves where special mitigation measures can be applied. Burundi is not party to the African Convention on the Conservation of Nature and Natural Resources (Algiers Convention), of 15 September 1968. C.2.5 Laws and Regulations Specific to Water Management (including irrigation) According to Article 52 of the Burundi Environmental Code (Loi n° 1/010 du 30 juin 2000, sortie par le Ministère chargé de l'environnement portant code de l'Environnement de la République du Burundi), works and construction susceptible of modifying the hydraulic network ecosystem must be subject to the EIA procedure and cannot be carried out until the agreement of the Minister in charge of Environment. Furthermore, Law No. 1/014 of 11 August 2000, regulates the use of natural resources, including licensing, water management plans and water quality standards. C.2.6 Laws and Regulations Specific to Forestry Forest management in Burundi is under the responsibility of the `Ministère de l'Aménagement du Territoire et de l'Environnement' The `Ministères de l'Agriculture et de l'Élevage, du Développement Communal et de l'Artisanat, du Commerce et Industrie, de l'Énergie et des Mines, des Travaux Publics, de l'Éducation Nationale' are also involved. Some legislation related to Forest Reserves dates back to the colonial period (1934, 1951,1964). Since 1985, Burundi has a Forestry Code known as the `Décret-loi n° 01 / 02 du 25 mars 1985 portant code forestier'. Burundi's National Strategy on Environment and the National Environmental Action Plan updated in 1997 promote a rational use of forest resourcea according to a sustainable development vision. C.2.7 Environmental Commitments Burundi is a signatory to the following conventions and protocols: · Basel Convention on Hazardous Wastes; · Convention on Biological Diversity (SCBD); · Convention on International Trade in Endangered Species (CITES); · Convention on Wetlands of International Importance especially as Waterfowl Habitat (RAMSAR); · United Nations Framework Convention on Climate Change (UNFCCC); · United Nations Convention to Combat Desertification (UNCCD); 3 Chapt. V ­ Les espaces naturels protégés et la diversité biologique SSEA III - Final Report C-3 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS · Vienna Convention for the Protection of the Ozone Layer. Burundi is not a signatory to the Kyoto Protocol to the United Nations Framework Convention on Climate Change. It has, however, "acceded" to it4. C.2.8 Greenhouse Gases The Politique sectorielle du Ministère de l'Énergie et des Mines addresses greenhouse gases issues under: · Motives, p. 4 , where it is stated that emphasis will be put on new, decentralized, approaches to produce electricity, such as solar panels, small hydro, etc. ("L'accent est mis sur la recherche de nouvelles approches d'approvisionnement en énergie électrique, en particulier l'approche décentralisée par système solaires ou petites centrales hydroélectriques, celle par l'extension de réseaux s'étant avérée très coûteuse eu égard au faible pouvoir d'achat des populations et à l'habitat dispersé qui caractérise le monde rural... ") · Problems to be solved ­ Electric Energy sub-Sector, p. 18, where it is noted that the dispersal of land uses makes it expensive to extend the electric network and that it would be preferable to resort to alternative modes of rural electrification such as solar panels ("L'habitat dispersé rend l'extension du réseau électrique difficile et non rentable. Pour contourner ce problème, il est nécessaire de recourir à des solutions alternatives, en particulier l'énergie solaire photovoltaïque, ... ") However, this last statement is somewhat at odds with the one contained in the Objectives, p. 21, to the effect that to facilitate access of a greater part of the population to modern energy sources, it would be necessary to improve the rate of electrification by extending the network ("..les objectifs spécifiques à viser sont ... augmenter le taux d'électrification du pays par l'extension du réseau..."). C.3 The Democratic Republic of Congo (DRC) C.3.1 Overall Environmental Framework and Environmental Assessment Procedures It would appear that the following are in place: · Legislation regarding environmental protection, regulatory standards and permits; · Legislation governing the use of natural resources, including licenses, water management plans and water quality standards; · Air Pollution Standards; · Occupational health and safety legislation; · Cultural heritage and indigenous rights; · Conservation and threatened species. 4 "Accession" is the act whereby a state accepts the offer or the opportunity to become a party to a treaty already negotiated and signed by other states. It has the same legal effect as ratification. SSEA III - Final Report C-4 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS However, copies of the relevant laws, regulations, etc. were not available. A draft Water Code "Avant-projet de décret-loi portant Code de l'Eau" has been under discussion since July 2000. When finalized, the Department of the Environment will have the mandate to protect water resources and their quality. In DRC, all projects theoretically require an Energy-Environment study to be carried out by the Ministry of Energy concurrently with the Ministry of Environment. In practice however, even though many legal texts are in place, little coherence exists and the Ministry of Environment lacks the human, technical and financial resources to carry out the missions it is mandated with5. Furthermore, as stated on page 61 of the Report "Évaluation de l'impact environnemental et social du PMURR" , an analysis of the environmental laws and 6 regulations now in place shows that successive governments were focused on reacting to immediate problems which did not permit them to devote the time required to ensuring coherence and efficiency of the successive legislation. There was, in 1999, an attempt to vote a framework law that would have addressed environmental issues. It appears this is again attempted now. This should allow identifying priorities as regards environmental actions, and favor the updating of the organization of the Ministry of Environment structures so as to meet theses objectives. No references were found on Strategic Assessment Processes related to the electricity sector. C.3.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights Land ownership in DRC is governed by the `Loi n°73-021 du 20 juillet 1973', changed and completed by the `loi n° 80-008 du 18 juillet 1980' which makes the State the sole owner of lands aboveground and underground. Land ownership is uneven because land rights are influenced by customary rules which allow the ownership of vast domains by a chief. This law provides for the preliminary agreement of the chief of a clan owning the land before attribution of land by the government. The `Décret du 16 avril 1931 portant transport de l'énergie électrique au travers des terrains privés (expropriation)' provides for compensation either in the case of material damages or of loss of enjoyment of property. C.3.3 Resettlement Policies and Regulations There is no policy or legislation regarding involuntary resettlement in the DRC. C.3.4 Constraints on Development in Parks and Protected Areas In the DRC, the `Ordonnance-Loi du 22 août 1969 relative à la conservation de la nature' and the `Loi du 22 juillet 1975 relative à la création des secteurs sauvegardés' define the specific parameters that environmental impact studies relative to projects in integral nature reserves and safeguarded sectors must observe. They also provide that State-owned lands, situated in integral nature reserves, cannot be allocated to uses that are incompatible with the protection of nature. In particular, the laws forbid works to be carried out in rivers, and 5 A thorough analysis of the situation can be found in the Report « Évaluation de l'impact environnemental et social du PMURR (Programme Multisectoriel d'urgence de réhabilitation et de reconstruction), Vol. 1, SOFRECO, 21 June 2004 (Report E1014), cited above, starting at page 61. 6 (Programme Multisectoriel d'urgence de réhabilitation et de reconstruction), Vol. 1, SOFRECO, 21 June 2004 (Report E1014) SSEA III - Final Report C-5 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS they prohibit pollution of waters either directly or indirectly. Similarly, the Order creating a safeguarded sector can forbid industrial works within this sector. The DRC is party to the African Convention on the Conservation of Nature and Natural Resources (Algiers Convention), of 15 September 1968. Under this Convention, "any work tending to alter the configuration of the soil or the character of the vegetation, any water pollution, etc." is forbidden in strict nature reserves and in national parks. Only the competent legislative authority, i.e., the Government of DRC can alter or alienate any portion of these "strict nature reserves" and national parks7. Thus, while the Government retains ultimate power to allow the implementation of power projects in "strict nature reserves" and national parks, by legislatively altering their boundaries or alienating some of their area, such areas should be considered as very unlikely sites for power projects. However, as noted under S. 3.6.1 ­ XIII - Legal feasibility of power projects in National Parks, specific environmental management measures could be applied to a power installation considered for implementation in "strict nature reserves", national parks, wetlands, rivers, etc., if legislative intervention was deemed feasible. C.3.5 Laws and Regulations Specific to Water Management (including irrigation) The main institutions dealing with water management in DRC are a) The `Ministère de l'Environnement, Conservation de la nature, Eaux et Forêts', with its `Direction des ressources en eaux' (DRE) which has the responsibility to manage water in an ecosystemic way; b) the `Ministère de l'Agriculture et de l'Élevage with its Service national d'hydraulique rurale (SNHR) which is part of the Direction du génie rural ; and c) the Ministère du DéveloppementRural. Concerning dams building, the `Loi du 20 juillet 1973 portant régime général des biens, régime foncier et immobilier' states that nobody can pollute water or divert it, which means that all polluting action must be avoided or remedied through anti- pollution measures. Furthermore the Law provides for the protection of downstream ecosystems; anti-pollution and anti-erosion measures must accompany the construction of infrastructures affecting the provision of water in downstream ecosystem. A draft Water Code "Avant-projet de décret-loi portant Code de l'Eau" has been under discussion since July 2000. When finalized, the Department of the Environment will have the mandate to protect water resources and their quality. C.3.6 Laws and Regulations Specific to Forestry In the DRC, forestry activities and management come under the Forestry Code (`Loi du 29 août 2002 portant Code Forestier'). This Code of general scope calls for the adoption of specific regulations but indicates that the government will to improve its management of the environment. The Code includes the obligation to consult affected populations but does not explicitly provide for EIAs even if it mentions that EIAs are part of modern management of forestry resources. The `Ministère de l'Environnement, Conservation de la nature, Eaux et Forêts' created in 1975 is in charge of managing water and forest ecosystems and of creating and managing Nature Reserves. C.3.7 Environmental Commitments The DRC is a party8 to the following principal international conventions and protocols: 7 Cf. s. 3 (d) 8 It's exact status (Signed, Accessed, in force, etc.) can be found in Table 3-1 SSEA III - Final Report C-6 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS · African Convention on the Conservation of Nature and Natural Resources (Algiers Convention); · Basel Convention on Hazardous Wastes; · Convention on Biological Diversity (SCBD); · Convention on International Trade in Endangered Species (CITES); · Convention on Wetlands of International Importance especially as Waterfowl Habitat (RAMSAR); · Kyoto Protocol to the United Nations Framework Convention on Climate Change; · United Nations Convention to Combat Desertification (UNCCD); · Vienna Convention for the Protection of the Ozone Layer and Subsequent Protocols and Amendments. C.3.8 Greenhouse Gases No references were found on this issue in regards to the electricity sector. C.4 Kenya C.4.1 Overall Environmental Framework and Environmental Assessment Procedures Kenyan environmental provisions are contained in some 77 statutes. Most are sectoral, either covering natural resource sectors (water, fisheries, forestry, etc.) or functional sectors (public health, agriculture, etc). For a comprehensive overview, it is recommended to read Environmental Legislation and Domestication of International Environmental Law in Kenya, by Anne Angwenyi, Principal Legal Officer, National Environment Management Authority (NEMA) Kenya ­ A paper presented at the SISEI 9 Programme Sub-Regional Legal Workshop held in Nairobi, 13th-17th December 2004 ­ which can be found at http://www.nema.go.ke/environmental_legislation_and.htm The main legislation governing the use of natural resources, including licenses, water management plans and water quality standards, are the Environmental Management and Co-ordination Act (1999), and the Water Act (2002). The Environmental Management and Co-ordination Act (1999) provides for the National Environmental Management Authority (NEMA) whose object and purpose is to exercise general supervision and coordination over all matters relating to the environment and to be the principal instrument of the Government in the implementation of all policies relating to the environment. This Act also provides for the establishment of a committee under NEMA known as the National Environment Action Plan Committee that is required to prepare a National Environment Action Plan (NEAP) every five years for consideration and adoption by the National Assembly. Section 38 of the Act states that the NEAP must among others set out 9 SISEI : Système de Circulation d'Information et de Suivi de l'Environnement sur Internet en Afrique SSEA III - Final Report C-7 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS operational guidelines for the integration of standards of environmental protection into development planning and management. Under Section 59 of the Environmental Management and Coordination Act (1999), project proponents are obliged to conduct an EIA to which all persons have the right to participate. The Second Schedule of the Act identifies electrical infrastructures, including electricity generation stations, storage dams and river diversions, as projects that must undergo such EIAs. According to Part-II of the Environmental Impact Assessment and Audit Regulations (2003), the EIA process is initiated by a project report, which must be submitted to the NEMA. In particular, the public must be notified of the intention to carry out an EIA, be given specific information concerning the project and it has 60 days within which to submit comments. The 2003 Environmental Impact Assessment and Audit Regulations, provided additional specific regulation regarding EIAs. According to these regulations, no proponent shall implement a project for which an EIA is required unless this EIA has been concluded and approved in accordance with the regulations. C.4.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights Land tenure in Kenya is complex, as the Registered Land Act of 1963 (Cap 300) which intends to introduce modern/private land tenure systems has as not yet been enforced on all Kenyan territory. According to 1990 data, privately-owned lands comprised 6% of the territory while Government-owned land accounted for 20% of the territory. The remaining 64% of the territory is either trust lands or group ranches that are communally owned under the Trust Land Act10. Furthermore, some customary rules still apply in certain areas under trust land tenure. Section 75 of the Constitution offers protection from compulsory acquisition but lists numerous exceptions to this principle. However, it gives a right of direct access to the High Court in such cases for: (a) The determination of his interest or right, the legality of the taking of possession or acquisition of the property, interest or right, and the amount of any compensation to which he is entitled; and (b) The purpose of obtaining prompt payment of that compensation. Compulsory acquisition is used as a last resort. Power to expropriate is usually given under enabling legislation of the Agency of the Government or the public body. Compulsory acquisition or the use of land for the purposes of a generating station, substation or switching station, must first be authorized by the Minister and follow the procedure set out in section 110 of the Electric Power Act, 1997. C.4.3 Resettlement Policies and Regulations With respect to invountary resettlement, the rules laid out in the World Bank's Operational Procedure OP 4.12 (Revised 2004) apply. 10Kameri-Mbote, 2005 SSEA III - Final Report C-8 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS C.4.4 Constraints on Development in Parks and Protected Areas There is no specific prohibition of power projects in national parks, wetlands, rivers, etc. under Kenyan law. The legal provisions directly relevant are: · The Environmental Management and Coordination Act, 1999, which directs, under s. 42, that "No person shall, without prior written approval of the Director General given after an environmental impact assessment, in relation to a river, lake or wetland in Kenya, carry out any of the following activities: (a) erect, reconstruct, place, alter, extend, remove or demolish any structure or part of any structure in, or under the river, lake or wetland; ..." · The Forest Act Cap 385: under this Act, unalienated Government land can be declared a "nature reserve" where strict preservation of flora and fauna is enforced; · The Wildlife (Conservation and Management) Act of 1989, which enforces a strict control of activities in any area declared a "national park", "nature reserve" or "sanctuary" by Gazette notice by the Minister of Environment and Natural Resources. The Kenya Wildlife Service is the Agency legally mandated to enforce these dispositions. Kenya is party to the African Convention on the Conservation of Nature and Natural Resources (Algiers Convention). Under this Convention, "any work tending to alter the configuration of the soil or the character of the vegetation, any water pollution, etc." is forbidden in "strict nature reserves" and in national parks11. Only the competent legislative authority, i.e. the Government of Kenya, can alter or alienate any portion of these "strict nature reserves" and national parks.Thus, while the Government retains ultimate power to allow the implementation of power projects in National Parks, by legislatively altering their boundaries or alienating some of their portions, such areas should be considered as very unlikely sites for power projects. However, the Hell's Gate and Longonot National Parks were gazetted in 1984, three years after commissioning of the Olkaria I Power Station. This imposed constraints on the management of the operation of the power station and the park. These were resolved by the signing of a Memorandum of Understanding (MoU) in 1994, between KenGen and the Kenya Wildlife Service (KWS), which outlines the harmonious operations of the two parties for the mutual benefit of the country12. More particularly, under this MoU, "envisaged environmental impacts and mitigation measures to be undertaken and areas that require collaboration between KenGen and KWS to ensure that no conflicts arise during operations are clearly stated in the agreement. The chairmanship for MoU meetings is rotational between KenGen and KWS divisional heads depending on the venue of the meeting. The MoU document is always attached to the tender document issued by KenGen for geothermal projects in order to inform the contractors of the environmental obligations within the Park. KWS is currently reviewing the MoU document especially with the incoming IPPs such as OrPower4 in Olkaria III." 11 Cf. s. 3 (d): A "strict nature reserve" is an area under State control throughout which any work tending to alter the configuration of the soil or the character of the vegetation, any excavation or prospecting, drilling, leveling of the ground or construction, etc. are strictly forbidden. The boundaries of a "strict nature reserve" may not be altered nor any portion alienated except by the competent legislative authority. These prohibitions also apply to National Parks. 12See Geothermal Power Development in a National Park, Olkaria, Kenya, at http://www.worldbank.org/html/fpd/energy/geothermal/case_studies.htm SSEA III - Final Report C-9 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS Of course, these environmental management measures applied to a power installation already in place before the National Parks were gazetted. Similar protocols could also be envisaged when power projects are considered in "strict nature reserves", national parks, wetlands, etc., in Kenya or elsewhere, even where the Algiers Convention is in force, if legislative intervention is deemed feasible. C.4.5 Laws and Regulations Specific to Water Management (including irrigation) Water management in Kenya is under the responsibility of the Ministry of Water and Irrigation. A National Policy on Water Resources Management and Development was adopted in 1999. The Policy outlines the need for decentralization of operational activities, for welcoming the participation of the private sector and for participatory management. The Water Act of 2002 provides the institutional and legal framework for implementing the National Water Policy and is the basis of the country's water sector reform currently under implementation. The Water Act of 2002 aims at providing for a harmonized and streamlined management of water resources and water supply and sewerage services. The current reform involves the separation of water resources and water and sewerage service provision13. It vests all Kenyan water resources in the State14 and specifies how rights to water usage may be acquired. It creates a corporate body called the Water Resources Management Authority that will, in particular, receive and determine applications for permits for water use. It also creates a Regulatory Board, called the Water Services Regulatory Board, with powers over the provision of water services. C.4.6 Laws and Regulations Specific to Forestry Forest management in Kenya is under the authority of the Forest Department of the Ministry of Environment and Natural Resources. NEMA plays a role in the sustainable management of forests. A new Forestry Act was adopted in 2005 and should start being implemented in 2007. This Act will replace the Forest Act Cap 385 (1962 and revised in the 1990s). The new Act provides for the sustainable management of forestry resources through community participation. C.4.7 Environmental Commitments Kenya is a party15 to the following principal international conventions and protocols: · African Convention on the Conservation of Nature and Natural Resources (Algiers Convention); · Basel Convention on Hazardous Wastes; · Convention on Biological Diversity (SCBD); · Convention on International Trade in Endangered Species (CITES); 13 Source: Kenya Office of Public Communication Website www.communication.go.ke 14 Save for rights of use already granted (art. 3) 15 It's exact status (Signed, Accessed, in force, etc.) can be found in Table 3-1 SSEA III - Final Report C-10 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS · Convention on Wetlands of International Importance especially as Waterfowl Habitat (RAMSAR); · Kyoto Protocol to the United Nations Framework Convention on Climate Change; · United Nations Convention to Combat Desertification (UNCCD); · Vienna Convention for the Protection of the Ozone Layer and Subsequent Protocols and Amendments. C.4.8 Greenhouse Gases The need to reduce greenhouse gases emissions is addressed indirectly in the Energy Bill, 2004, and the Environmental Management and Coordination Act, 1999, which requires the licensing of activities likely to emit "a substance or energy which is likely to cause air pollution" (s. 80 et seq.). C.5 Rwanda C.5.1 Overall Environmental Framework and Environmental Assessment Procedures In Rwanda, according to the National Policy on Environment issued in 2003, Environmental Impact Assessments (EIAs) must be carried out prior to development of infrastructure projects. The `Office Rwandais de Gestion de l'Environnement' (REMA) was set up to implement this policy. In April 2005, Rwanda adopted a legal framework in accordance with its National Policy on Environment, the `Loi organique N° 4/2005 du 8 avril 2005 portant modalités de protéger, sauvegarder et promouvoir l'environnement au Rwanda,' which stipulates that EIAs must be carried out prior to works on wetlands and watersheds. The EIA must outline the costs and benefits of the protection of watersheds and of other related ecosystems. There is no specific legislation regarding conservation and protection of threatened species in Rwanda. Legislation regarding environmental protection associated regulatory standards and permits is being drafted. Law No. 51/2001 of 30/12/2001 establishes the Labor Code. It covers occupational health and safety legislation. However, there are no special rules or prohibitions specific to the energy sector. There is no specific legislation regarding cultural heritage and indigenous rights in Rwanda. No references were found on Strategic Assessment Processes related to the electricity sector. C.5.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights In Rwanda, land ownership is divided into "formal written rights" and customary tenure. The first type recognisese lands that are subject to private ownership. It enables a small part of the population who has the economic means to acquire property to have absolute rights over it. Customary tenure characterises important areas of lands where the real owner of the land is the State but where inhabitants have rights to use the land. In 2004, a new Land Act (`Avant-projet de loi portant régime foncier du Rwanda') was prepared by the `Ministère des Terres, de l'Environnement, des Forêts, de l'Eau et des Ressources naturelles' (MINITERE) SSEA III - Final Report C-11 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS and voted by the Parliament. This new Act defines land ownership, rights and duties of land owners and transaction rules. The Act recognises private ownership, State ownership and communal ownership16. Under the `Décret Énergie électrique, 2 juin 192817, - Conditions générales, Décret - Transport de l'énergie électrique au travers des terrains privés, 16 avril 193118; and the Arrêté Royal ­ Règlement général des concessions de distribution de l'énergie électrique, 9 octobre 1956'19, Electrogaz is empowered to install power lines across public and private property. In all cases, where private property must be expropriated, Electrogaz must compensate the owner, either under an agreed settlement or under a court decision. The power to expropriate and the pertaining procedure can be found in: · Under the Décret du 6 mai 1952, Concession et Administration des eaux des lacs et des cours d'eau 20 , water use rights can be granted for up to 30 years, by Government decree, where the proposed power is of 5,000 HP or more; · Under the Décret Énergie électrique, 2 juin 192821, ­­­ Conditions générales, Décret - Transport de l'énergie électrique au travers des terrains privés, 16 avril 193122; and Arrêté Royal ­ Règlement général des concessions de distribution de l'énergie électrique, 9 octobre 195623, Electrogaz is empowered to install power lines across public and private property; · In all cases, where private property must be used, Electrogaz must compensate the owner, either under an agreed settlement or under a court decision. C.5.3 Resettlement Policies and Regulations This issue is not adressed in Rwanda's policy, legal and administrative framework. C.5.4 Constraints on Development in Parks and Protected Areas In Rwanda, little information is available on the constraints to development in National Parks. In the late 1990s, the area of the Akagera National Park had to be reduced due to the relocation of displaced populations within the park. The National Strategy and Action Plan on Biodiversity adopted in June 2000 covers the country's strategy on protected areas and the `Loi organique N° 4/2005 du 8 avril 2005 portant modalités de protéger, sauvegarder et promouvoir l'environnement au Rwanda' regulated environmental issues in a broad sense (land, agriculture, forests, water, biodiversity, etc.). The management of protected areas falls under the jurisdiction of the `Office Rwandais du Tourisme et des Parcs Nationaux' (ORTPN). 16 Source: FAO Aquastat - Rwanda 17 Decree on Electric Energy, 2 June 1928. General Conditions 18 Decree ­ Transmission of Electricity through Private Property, 16 April 1931. 19 Royal Decree ­ General Regulation on Electric Distribution Concessions, 9 October 1956. 20 Decree of 6 May 1952 ­ Concession and Administration of waters of lakes and rivers. 21 Decree on Electric Energy, 2 June 1928. General Conditions 22 Decree ­ Transmission of Electricity through Private Property, 16 April 1931. 23 Royal Decree ­ General Regulation on Electric Distribution Concessions, 9 October 1956. SSEA III - Final Report C-12 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS Rwanda is party to the African Convention on the Conservation of Nature and Natural Resources (Algiers Convention).. As already noted, under this Convention, "any work tending to alter the configuration of the soil or the character of the vegetation, any water pollution, etc." is forbidden in strict nature reserves and in national parks. Only the competent legislative authority, i.e. the Government of Rwanda, can alter or alienate any portion of these "strict nature reserves" and national parks24. Thus, while the Government retains ultimate power to allow the implementation of power projects in "strict nature reserves" and national parks, by legislatively altering their boundaries or alienating some of their area, such areas should be considered as very unlikely sites for power projects. However, as noted under S. 3.6.1 ­ XIII - Legal feasibility of power projects in National Parks, specific environmental management measures could be applied to a power installation considered to be implemented in "strict nature reserves", national parks, wetlands, rivers, etc., if legislative intervention was deemed feasible. C.5.5 Laws and Regulations Specific to Water Management (including irrigation) In general, the `Politique Nationale de l'Environnement' (PNE) of 2003 and the `Loi organique N° 4/2005 du 8 avril 2005 portant modalités de protéger, sauvegarder et promouvoir l'environnement au Rwanda' provide for measures to protect watersheds in order to prevent wetlands deterioration. The main department in charge of water management in Rwanda is the `Ministère des Terres, de l'Environnement, des Forêts, de l'Eau et des Ressources naturelles'(MINITERE) which, through its `Direction de l'eau et de l'assainissement', is in charge of rural water supply, management of water resources and water treatment. In 2004 the MINITERE issued a Sectoral Policy on Water and Sanitation which recognizes the sustainable management principle and has the stated objectives, among other things, of improving access to drinking water, access to water for agricultural use and the use of water as energy source. A Water Act is currently in preparation. C.5.6 Laws and Regulations Specific to Forestry Rwanda's Forest Regime was enacted in 1988 following the `Loi no 47/1988 du 5 décembre 1988 portant organisation du régime forestier au Rwanda' which led to the creation of the `Service Forestier National'25. The Department in charge of forest development is the `Direction des forêts' of the `Ministère des Terres, de l'Environnement, des Forêts, de l'Eau et des Mines' (MINITERE). The `Office Rwandais du Tourism et des Parcs Nationaux' (ORTPN) is in charge of the management of natural forests classified as National Parks. According to the National Environment Policy, the abusive exploitation of forests is the third government priority in terms of environmental problems and the Policy calls for the rehabilitation of degraded ecosystems. The implementation of the National Environmental Policy is carried out by the Office Rwandais de Gestion de l'Environnement' (REMA). C.5.7 Environmental Commitments Rwanda is a signatory to the following conventions and protocols: 24Cf. s. 3 (d) 25Source: FAO Forest Department, 2001 SSEA III - Final Report C-13 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS · Convention on Biological Diversity (SCBD); · Convention on International Trade in Endangered Species (CITES); · Comprehensive Nuclear-Test-Ban Treaty (CTBT); · United Nations Framework Convention on Climate Change (UNFCCC); · United Nations Convention to Combat Desertification (UNCCD); · Vienna Convention for the Protection of the Ozone Layer. Rwanda ratified the Kyoto Protocol to the United Nations Framework Convention on Climate Change on 22 July 2004. C.5.8 Greenhouse Gases No references were found on this issue as it applies to the electricity sector. C.6 Tanzania C.6.1 Overall Environmental Framework and Environmental Assessment Procedures Law No. 19 of 1983 is the main existing environmental protection legislation. It sets out the functioning and the duties of the National Environment Management Council (NEMC), which are mainly advisory in nature. The main legislation governing the use of natural resources, including licenses, water management plans and water quality standards, is the Water Utilization Act No. 42, 1974. This Act is in the process of being revised according to the National Water Policy. Air Pollution Standards are to be set by the National Environment Management Council (NEMC) under Powers given by Law No. 19 of 1983 - An Act to provide for the establishment of the National Environment Management Council, to provide for its functions and for other matters related to and incidental to the establishment of the Council. The Consultant was informed that there was an attempt to set standards about three years ago but none have been set so far. There is no specific legislation regarding conservation and threatened species. However, a precedent was set at Kihansi, in South East Tanzania: under pressure from environmental groups, water was set aside to maintain threatened species, even though it diminished the energy production potential from 180 MW to 60 MW. An "Environmental Impact Assessment (EIA) Regime" is specifically stipulated in the National Environmental Policy, December 1997, in the following paragraphs of the Policy: · Para. 65 ­ Chap. 4 Instruments for Environmental Policy "It is in the context of an Environmental Impact Assessment (EIA) Regime that policy guidance and choices to maximise long term benefits of development and environmental objectives can be revealed and decided upon. EIA as a planning tool shall be used to ..."; · Para. 66 ­ Chap. 4 Instruments for Environmental Policy "...One of the cornerstone of the Environmental Impact Assessment (EIA) process will be the institution of public consultations and public hearings in the EIA procedures"; and SSEA III - Final Report C-14 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS · Para. 67 ­ Chap. 4 Instruments for Environmental Policy "...In order to mitigate the effects of existing and future policies on the environment, strategic environmental impact assessment will be applied on those policies which impact on the environment". With respect to energy, the National Environmental Policy, December 1997, states that the "main objective is sound management of the impacts of energy development and use in order to minimize environmental degradation..." (Sectoral Policies paragraph 52). The 2004 Environmental Management Act (Part VI) provides for mandatory EIA prior to the beginning or financing of project defined in the Third Schedule of the Act. The Environmental Management Act provides for the National Environment Management Council (NEMC) to enforce and monitor the Environmental Impact Assessment procedure. Following the submission of an EIA the NEMC shall decide if Public Hearings are required. Only registered experts or firms are allowed to conduct impact assessment. The acceptation of the EIA and issuance of an Environmental Impact Assessment Certificate rest into the hands of the Minister responsible for Environment. This Act also provides the framework for Environmental Monitoring and Environmental Audit procedures. The specific regulations concerning the EIA and Audit procedures have been issued in the 2005 Environmental Impact Assessment and Audit Regulations (G.N. No 349) The issue of Environmental Impact Assessment was also addressed in the National Energy Policy of February 2003. Policy Statement 54 (Section 5.4 Environment, Health and Safety) recognizes the need to: "Promote environmental impact assessment as a requirement for all energy programs and projects". Issues related to institutional frameworks are addressed in the National Energy Policy, February 2003, as follows: · Art. 1.4.3 Environmental Framework; · Art. 1.4.4 Institutional Framework: "A transparent institutional framework with a clear division of roles and responsibilities is desirable and in line with the global trends of accountability and liberalization of the economy"; · 6.2 Strategies (f) Environmental Management: "...Environmental impacts and hazards shall be addressed by rigorous environmental management regimes on all energy activities and by applying the economic instruments for changing market behavior. This will discourage any use of environmentally unsound energy technologies "; · 6.2 Strategies (j) Legal Interventions: "Legislation is one of the main instruments by which the Government steers and controls the development of the energy sector. Generally, some legislation is missing and applicable existing laws are outdated and consequently do not reflect recent developments. There is a need to update the legislation and existing laws". Under part VII of the Energy and Water Utilities Regulatory Authority Act, 2001, the Regulatory Authority is given enforcement and compliance powers. The Workman Compensation Ordinance covers occupational health and safety legislation. There are no specific rules or prohibitions applicable to the energy sector. Normal safety rules are followed. With regards to cultural heritage and indigenous rights, the Order in Council 1920 sets out the principle that "Things must be done in accordance with local customs". SSEA III - Final Report C-15 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS C.6.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights Tanesco can expropriate "for public purposes" under the terms of article 5, paragraph (2), of Electricity Ordinance CAP. 131 ­ Supp. 57 (1931). Applicable procedures are outlined in the Land Acquisition Ordinance, CAP. 118. C.6.3 Resettlement Policies and Regulations This issue is not adressed in Tanzania's policy, legal and administrative framework. C.6.4 Constraints on Development in Parks and Protected Areas Tanzania's wildlife protected area covers 28% of the total land area, of which 19% is devoted to wildlife in protected National Parks where no human settlement is allowed. In the rest of the land areas, wildlife co-exists with humans. The wildlife sector contributes approximately 2% to the GDP. However, there seems to be no legal prohibition to implementing projects in National Parks, Reserves, etc. Indeed, the National Environmental Policy, December 1997, notes that "environmentally adverse impacts of development projects in wildlife conservation areas (e.g. tourist hotels, rail construction) will be minimized by environmental impact studies." and calls for "finding the right balance between natural processes and unavoidable human interventions." 26 It calls however for protection of natural forests with biological diversity value and genetic resources. 27 The 2004 Environmental Management Act states that each National Protected Area shall be managed in accordance with their respective written law and shall be subject to an Environmental Management Plan prepared by the concerned management authorities. Tanzania is party to the African Convention on the Conservation of Nature and Natural Resources (Algiers Convention). Under this Convention, "any work tending to alter the configuration of the soil or the character of the vegetation, any water pollution, etc." is forbidden in strict nature reserves and in national parks. Only the competent legislative authority, i.e. the Government of Tanzania, can alter or alienate any portion of these "strict nature reserves" and national parks28. Thus, while the Government retains ultimate power to allow the implementation of power projects in "strict nature reserves" and national parks, by legislatively altering their boundaries or alienating some of their area, such areas should be considered as very unlikely sites for power projects. However, as noted under S. 3.6.1 ­ XIII - Legal feasibility of power projects in National Parks, specific environmental management measures could be applied to a power installation considered to be implemented in "strict nature reserves", national parks, wetlands, rivers, etc., if legislative intervention was deemed feasible. C.6.5 Laws and Regulations Specific to Water Management (including irrigation) Water management in Tanzania is under the Water Resources Division of the Water and Livestock Development Ministry. The National Water Policy of July 2002, lays down the "Main Policy Principles in Water Resources Management" in article 3.3. It states, more 26s. 58 ­ Wildlife and s. 64 ­ Environmental Impact Assessment 27 s. 59 - Forestry 28Cf. s. 3 (d) SSEA III - Final Report C-16 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS particularly, that "Water related activities should aim to enhance or to cause least detrimental effect on the natural environment". This policy also includes the country's obligation toward shared watercourses contracted through the SADC Protocol on Shared Watercourses. The 2004 Environmental Management Act sets principles for the protection and management of river beds and shore which provides that construction works in these area cannot be carried out prior obtaining permit or authorisation issued by the Minister responsible for Environment. C.6.6 Laws and Regulations Specific to Forestry Forest management in Tanzania falls under the Minister of Natural Resources and Tourism. In 1998, Tanzania adopted a National Forest Policy to deal with the degradation of the forest resources. The policy outlines the value of forest in watershed management. In order to preserve the forest resource the policy put emphasis on participatory community-based forest management and the creation of village forest reserve in order to reduce rural poverty29. C.6.7 Environmental Commitments Tanzania is a signatory to the following conventions and protocols: · Basel Convention on Hazardous Wastes; · Convention on Biological Diversity (SCBD); · Convention on International Trade in Endangered Species (CITES); · Convention on Wetlands of International Importance especially as Waterfowl Habitat (RAMSAR); · United Nations Convention to Combat Desertification (UNCCD); · United Nations Convention on the Law of the Sea; · Vienna Convention for the Protection of the Ozone Layer. Tanzania is not a signatory to the Kyoto Protocol to the United Nations Framework Convention on Climate Change. It has, however, "acceded" to it30. C.6.8 Greenhouse Gases The National Energy Policy, February 2003, indirectly addresses this issue as follows: · 3.6.4 Renewable Energy 29Source: Meghji, 2003 30"Accession" is the act whereby a state accepts the offer or the opportunity to become a party to a treaty already negotiated and signed by other states. It has the same legal effect as ratification. SSEA III - Final Report C-17 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS Policy Statement 36: "Establish norms, codes of practice, guidelines and standards for renewable energy technologies, to facilitate the creation of an enabling environment for sustainable development of renewable energy sources"; Policy Statement 38: "Ensure inclusion of environmental considerations in all renewable energy planning and implementation, and enhance co-operation with other relevant stakeholders"; Policy Statement 39: "Support research and development in renewable energy technologies". · 5.1 Energy Efficiency and Conservation Policy Statement 49: "Enhance energy efficiency and conservation initiatives in all sectors"; Policy Statement 50: "Ensure energy audits in industries, particularly the energy intensive ones". C.7 Uganda C.7.1 Overall Environmental Framework and Environmental Assessment Procedures The main legislation and regulations related to environmental protection in Uganda consist of the following: · The National Environment Management Policy, March 1995; · The National Environment Statute (Statute No 4 of 1995); · The Environmental Impact Assessment Regulations 1998; · The National Environment (Wetlands, River banks and Lakeshores Management) Regulations, 1999. Furthermore, the Ugandan Constitution provides that Parliament must define measures for protecting the environment, managing it in a sustainable manner and promoting environmental awareness. Other legislation and policies relevant to environmental management are: · The Investment Code (No.1/9 1); · The Electricity Act, 1999; · The Water Statute, 1995 and its regulations; · The Rivers Act, 347; · The Land Act, 1998; · The Town and Country Planning Act, CAP 30; · The Wildlife Statute, 1996; SSEA III - Final Report C-18 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS · The Local Government Act, No.1/1997; and · The Riparian Agreements respecting the River Nile. Generally, under Part II ­ General Principles, of the National Environment Statute (1995) the following rights are legally asserted: `(c) to use and conserve the environment and natural resources of Uganda equitably and for the benefit of both present and future generations, taking into account the rate of population growth and productivity of the available resources; .... (i) to require prior environmental assessments of proposed projects which may significantly affect the environment or use of natural resources; ........ (k) to ensure that the true and total costs of environmental pollution are borne by the polluter'. The right of every person to a healthy environment is also asserted, including the right to require that any on-going activity be subjected to an environmental audit and to request a court order for the taking of other measures that would ensure that the environment does not suffer any significant damage. More specifically, under section 20 of the National Environment Statute, 1995, project proponents are obliged to conduct an Environmental Impact Assessment (EIA) where the lead agency31, in consultation with the Executive Director (of the National Environment Management Authority), is of the view that the project may or is likely to have an impact on the environment. Dams and works on rivers and water resources are among the categories of projects that must undergo such EIAs (cf. Third Schedule ­ Projects to be considered for Environmental Impact Assessment). In 1998, NEMA issued guidelines on EIA and together with the National Environment Statute (1997) they recognized the following steps: Project Brief formulation, Screening, EIA/EI study, Decision making, Environmental monitoring and auditing. The National Environment Management Authority (NEMA) has been given adequate powers to enforce environmental regulations under the National Environment Statute, 1995. C.7.2 Laws and Regulations Specific to the Land Ownership and Land Use Rights In Uganda, there are three types of land ownership, namely: customary tenure, mailo32 tenure and freehold tenure. The 1995 Constitution introduced changes to land rights as enacted in the 1998 Land Act: Protected areas, sensitive areas (eg National Parks - Murchison Falls, Forest Reserves, Wetlands, etc) and lands in towns are public lands to be held in trust for the Government of Uganda. Lands in town are leased to individuals for 31Meaning "..any ministry, department, parastatal agency, local government system or public officer in which or whom any law vests functions of control or management of any segment of the environment" ­ s. 2 - Interpretation 32The Uganda Agreement of 1900 set in place a form of freehold tenure for political elite (such as heads of indigenous kingdom) based on square mile block (Rew, Fisher, Pandey, 2000) SSEA III - Final Report C-19 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS development. Public lands are allocated to the Municipalities by the Uganda Land Commission (ULC) and the Municipalities are then responsible for leasing lands to suitable applicants for development on a lease hold basis. The Land Act (1998) makes provisions for the procedures and methods of compulsory acquisition of land for public purposes. According to this act, the Government or the developer must give fair compensation to any affected person prior to development33. The Electricity Act (1999) also contains provisions for land acquisition and the pertaining procedures can be found under Part VIII--Use of Land for Installations. Section 69 states that land can be acquired by agreement between licensee/developer and the owner. If private land cannot be acquired through agreement, Section 72 provides for forced acquisition of the land by the State through the District Land Board. The Land Regulations (2004) ­ Section 24 gives an account of what should be considered in calculating compensation rates. These regulations stipulate that compensation of crops and trees grown legally is based on their local market values while the compensation of non-permanent buildings is based on their replacement cost, less depreciation. The power to expropriate and the pertaining procedures can be found under Part VIII--Use of Land for Installations, of the Electricity Act, 1999, and in particular s. 72 as regards forced acquisition. C.7.3 Resettlement Policies and Regulations A resettlement policy was drafted in line with the World Bank requirements in 1995 but this policy was not adopted. It should also be noted that the 1998 Land Act created a Land Fund whose main objective is to help gain land title but that can be used to resettle people rendered landless by Government action. A lot of resettlement occurred in the 1990s in order to halt the degradation of National Parks and Reserves due to human settlement. The 1999 Uganda Wildlife Policy seeks to protect National Parks and Reserves from human settlement. In 1999, the High Court of Uganda ruled against the Kabarole District Council concerning the forced eviction of 35,000 people from the Kibale Forest Reserve which occurred with serious violation of human rights.34 C.7.4 Constraints on Development in Parks and Protected Areas There seems to be no legal prohibition to implementing projects, be they power or otherwise, in National Parks in Uganda, under Ugandan Law. The Uganda Wildlife Statute (1996) requires that an EIA be carried out for any project that is likely to have an impact on any wildlife species or community. Under the National Environment Statute, 1995, electrical infrastructures including electricity generation stations, electrical transmission lines, electrical substations and pumped-storage schemes are identified as "Projects to be considered for environmental impact assessment" (Third Schedule, s. 10). As such, they are subject to the procedure dictated in s. 20 of the Law, and undergo an EIA as described in the Environmental Impact Assessment Regulations, 1998. The Third Schedule also identifies some types activities in National Parks that must be submitted to EIAs, but there are no specific references to electrical infrastructures in National Parks. 33Source: Rew, Fisher and Pandey, 2000 34Source: Rew, Fisher and Pandey, 2000. SSEA III - Final Report C-20 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS The EIA process must also take into account the guidelines and measures that the National Environment Management Authority (NEMA) must issue under s. 46 as regards "forests in protected areas, including forest reserves, national parks and game reserves." No such guidelines are presently to be found on the NEMA Web site, but it should reasonably be expected that stricter standards would apply to electrical infrastructures proposed in National Parks, forest reserves, game reserves and the like, even though no legal prohibitions appear to apply to them. Uganda is party to the African Convention on the Conservation of Nature and Natural Resources (Algiers Convention). Under this Convention, "any work tending to alter the configuration of the soil or the character of the vegetation, any water pollution, etc." is forbidden in strict nature reserves and in national parks. Only the competent legislative authority, i.e. the Government of Uganda, can alter or alienate any portion of these "strict nature reserves" and national parks35. Thus, while the Government retains ultimate power to allow the implementation of power projects in "strict nature reserves" and national parks, by legislatively altering their boundaries or alienating some of their area, such areas should be considered as very unlikely sites for power projects. However, as noted under S. 3.6.1 ­ XIII - Legal feasibility of power projects in National Parks, specific environmental management measures could be applied to a power installation considered to be implemented in "strict nature reserves", national parks, wetlands, rivers, etc., if legislative intervention was deemed feasible. C.7.5 Laws and Regulations Specific to Water Management (including irrigation) In Uganda, water resources are under the responsibility of the Department of Water Development (DWD) under the Ministry of Water, Lands and Environment. The legal framework for management of water resources includes the Water Act, Cap 153 (1995) also called Water Statute, as well as the two water regulations of 1998 on water resources and wastewater discharge, the National Environmental Act (1995) and the National Water Policy of 1999. The Water Statute (1995) "provides for the use, protection and management of water resources and supply". The National Environment Statute (1995) requires a developer to obtain a permit prior to any construction on a water resource and that an EIA must be carried out before the DWD issues permits to construct a hydropower project. The National Environment Statute (1995) empowers NEMA, in consultation with DWD (lead agency), to set water quality standards, establish standards for discharge of effluents into water, set limits on the use of lakes and rivers, establish regulations for environmental impact assessments, manage riverbanks and lakeshores, restrict use of wetlands, and manage wetlands. Furthermore a National Water Policy (1999) was adopted in 1999 with the overall objective of managingand developing water resources in an integrated and sustainable way in order to secure and provide water for all social and economic needs, with the full participation of all stakeholders36. 35Cf. s. 3 (d) 36Source: Badosa and Kabirizi, 2005 SSEA III - Final Report C-21 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS C.7.6 Laws and Regulations Specific to Forestry The management and conservation of forests in Uganda fall under the National Forest Authority. Forest Reserves are considered as protected areas (see 3.1.4). The Forest Policy revised in 2001 and the National Forest Plan provide principles and strategies for the sustainable use of forests. A Forestry Bill has been prepared that provides a framework for forestry development outside and inside forest reserves that balances the needs between conservation and production.37 C.7.7 Environmental Commitments Uganda is a party38 to the following principal international conventions and protocols: · African Convention on the Conservation of Nature and Natural Resources (Algiers Convention); · Basel Convention on Hazardous Wastes; · Convention on Biological Diversity (SCBD); · Convention on International Trade in Endangered Species (CITES); · Convention on Wetlands of International Importance especially as Waterfowl Habitat (RAMSAR); · Kyoto Protocol to the United Nations Framework Convention on Climate Change; · United Nations Convention to Combat Desertification (UNCCD); · Vienna Convention for the Protection of the Ozone Layer and Subsequent Protocols and Amendments. C.7.8 Greenhouse Gases The question of the need to reduce greenhouse emissions is specifically addressed in s. 3.10 - Climate of the National Environment Management Policy, March 1995, where the monitoring of the climate and atmosphere of the country in order to better guide land-use and economic development decisions, and better manage air pollution and greenhouse gas emissions is a stated objective. Likewise, the incorporation of economic, social and environmental sustainability in energy planning is addressed in s. 3.7.1 - Environmental Accounting of the National Environment Management Policy, March 1995, where the integration of environmental costs and benefits into economic planning and development at all levels of government in order to reflect the true costs and benefits of development is a stated objective. C.8 International Environmental Commitments States signal their intention to bind themselves to the terms of a treaty (also known as a convention) by signing the treaty. The final indication that a state is prepared to implement 37Source: Andrua, 2002 38It's exact status (Signed, Accessed, in force, etc.) can be found in Table 3-1 - SSEA III - Final Report C-22 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS the terms of the treaty is ratification. Occasionally, ratification may be achieved by signing a treaty. However, in the majority of states, ratification of a treaty requires a separate process, and the executive or legislature must consider the agreement closely and give its final approval before it has domestic effect. In the United States, treaties must be approved by the United States Senate before they have domestic effect; similarly, in many parliamentary systems, the approval of parliament is required to ratify a treaty. Most treaties do not enter into force until a certain number of states ratify the treaty. Once this number is achieved, a treaty will therafter be `in force'. The number of ratifications required to bring a treaty into force is a matter of political negotiation and is usually set at a diplomatic conference where the agreement is signed. Once a treaty is in force, the terms of the treaty become binding legal obligations. States that are signatories to a treaty but have not ratified it will still be bound in international law not to take measures that defeat the purposes of the treaty, but the terms are the unratified treaty are unlikely to have any domestic effect in practice. This is because in most states, national (domestic) law is considered to be implemented separately from international law. Accession is the act whereby a state accepts the offer or the opportunity to become a party to a treaty already negotiated and signed by other states. It has the same legal effect as ratification. The main International Conventions dealing with environment and their status in the different Upper Nile Basin countries are listed in Table B-1. The description of each convention is provided in the following sub-sections. C.8.1 Convention Concerning the Protection of the World Cultural and Natural Heritage The 1972 Convention Concerning the protection of the World Cultural and Natural Heritage or World Heritage Convention was adopted by the general conference of UNESCO in 1976. The idea of the Convention arose after UNESCO was asked to carried out safeguarding campaigns to protect endangered sites. The first of those campaign was the one carried out in 1959 for protecting the Abu Simbel temples in Egypt form the consequences of the construction of the Aswan High Dam. The World Heritage Convention sets out the duties of the 138 States Parties in identifying, protecting and preserving Natural or Cultural sites of outstanding universal value. The Convention defines the kind of sites which can be considered for inscription on the World Heritage List. C.8.2 African Convention on the Conservation of Nature and Natural Resources (Algiers Convention) The African Convention on the Conservation of Nature and Natural Resources (Algiers Convention) which came into force in June 1969, establishes general obligations to conserve, utilise and develop natural resources (soil, water, flora, fauna), especially where national actions have transboundary effects. This includes the development of land-use plans, and water conservation/utilization policies. The Convention also obliges Parties (which include the DRC, Kenya, Rwanda, Tanzania and Uganda) to maintain conservation areas ("strict nature reserves", "national parks", "special reserves" and "partial reserves" or "sanctuaries") existing at the time the convention went into force and to extend these where possible. "Construction or work tending to alter the configuration of the soil or the character of the vegetation or likely to disturb or harm the fauna or flora is prohibited in `strict nature reserves' and is permitted in national parks only if it is necessary to enable park authorities to propagate, protect, conserve or manage vegetation and wild animals, to protect sites, land-spaces or geological formations of particular scientific or aesthetic value. In national SSEA III - Final Report C-23 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS parks, killing, hunting and capture of animals and the destruction or collection of plants is prohibited except for scientific and management purposes when taken under the direction or control of a competent authority."39 Concerning wildlife conservation, Tanzania is also party to two other regional agreements ­ the SADC Protocol on Wildlife Conservation and Law Enforcement and, under the Convention on Migratory Species (the "Bonn Convention"), the Agreement on the Conservation of African-Eurasian Migratory Waterbirds. The SADC Protocol obliges Tanzania "to adopt and enforce legal instruments necessary to ensure the conservation and sustainable use of wildlife resources, and to integrate management and conservation programs into national development planning. The Protocol provides sanctions for non-compliance. The Agreement sets out general conservation provisions on the migratory waterbirds listed in Annex 2 of the Agreement, and more detailed provisions in an Action Plan, including the protection of targeted species and preservation of their habitat. There are strict exceptions to these obligations in paragraph. 6.1.3 of the Action Plan (for example, "overriding public interests")."40 39Source: Africa Power provided by The World Bank 40Source: Ibid. SSEA III - Final Report C-24 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS Table B-1 - Status of Principal International Conventions United Convention/Protocol Burundi DRC Kenya Rwanda Republic of Uganda Tanzania African Convention on the Conservation of Nature and Natural Resources (Algiers Signed In force In force In force In force In force Convention) (Open for accession by any independent African State) Basel Convention on Hazardous Wastes Accessed Accessed Accessed Accessed Accessed Accessed Convention on Biological Diversity (SCBD) Ratified Ratified Ratified Ratified Ratified Ratified Convention on International Trade in In Force In force In force In force In force In force Endangered Species (CITES) Convention on Wetlands of International Importance especially as Waterfowl Habitat In force In force In force Ratified In force In force (RAMSAR) Kyoto Protocol to the United Nations Accessed Accessed Accessed Accessed Accessed Accessed Framework Convention on Climate Change United Nations Convention to Combat In force In force In force In force In force In force Desertification (UNCDD) Vienna Convention for the Protection of the Accessed + Signed + Signed + Signed + Accessed Initial Signed Montreal Ozone Layer and Subsequent Protocols and Accepted Accepted Accepted Accepted Protocol and Protocol and Amendments Subsequent Subsequent Subsequent Subsequent Subsequent Accessed or Ratified Amendments Amendments Amendments Amendments Amendments Subsequent and Protocols and Protocols and Protocols41 and Protocols and Protocols Amendments and Protocols 41Except for Bejing Amendment (2004) SSEA III - Final Report C-27 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS Table B-2 - World Heritage Sites in the Nile Equatorial Lakes Countries States Parties World Heritage Sites (year of designation) Eastern DRC Virunga National Park (1979) Garamba National Park (1980) Kahuzi-Biega National Park (1980) Salonga National Park (1984) Okapi Wildlife Reserve (1996) Burundi None Kenya Lake Turkana National Park (1997, 2001) Mount Kenya National Park/Natural Forest (1997) Lamu Old Town (2001) Rwanda None Tanzania Ngorongoro Conservation Area (1979) Ruins of Kilwa Kisiwani and Ruins of Songo Mnara (1981) Serengeti National Park (1981) Selous Game Reserve (1982) Kilimanjaro National Park (1987) Stone Town of Zanzibar (2000) Kondoa Rock Art Sites (2006) Uganda Bwindi Impenetrable National Park (1994) Rwenzori Mountains National Parks (1994) Tombs of Buganda Kings at Kasubi (2001) SOURCE : UNESCO website (www.unesco.org) C.8.3 Ramsar Convention With the inclusion of Rwanda on 1 April 2006, all Nile Basin states are Parties to the Convention on Wetlands of International Importance (Ramsar), and have obligations regarding wetland areas, whether or not these areas are included or not on the Ramsar convention List (see Table B-2). Parties to the Convention designate suitable wetlands within their territory for inclusion in a List of Wetlands of International Importance. Parties to the Ramsar Convention are obliged to formulate and implement their planning to promote the conservation of the wetlands included in the List, and to establish and conserve other wetlands in their territory, whether or not these are included in the List. A Party may delete or restrict the boundaries of a wetland included in the List only if it is in its urgent national interest. At any rate, it is obliged to compensate for any loss of wetland resources (as far as possible), and to create additional nature reserves for waterfowl and for the protection, either in the same area or elsewhere, of an adequate portion of the original habitat. There is a duty to consult with other Parties about implementing the obligations of the convention, particularly where wetlands extend over the territory of more than one Party or represents a shared water system of Parties. This means that obligations arising out of membership of RAMSAR extend beyond the wetlands designated in the List. SSEA III - Final Report C-28 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS Table B-3 ­ List of Ramsar Wetlands in Nile Equatorial Lakes Basin Countries State Ramsar Wetlands Burundi - Rusizi Delta of the Réserve Naturelle de la Rusizi and the northern part of the Lake Tanganyika littoral area DRC - Parc national des Virunga - Parc national des Mangroves Kenya - Malagarasi-Muyovozi Wetlands - Lake Natron - Kilombero Valley Floodplain - Rufiji-Mafia-Kilwa Marine Ramsar Site Rwanda - Rugezi-Bulera-Ruhondo (from 1 April 2006) Tanzania - Malagarasi-Muyovozi Wetlands - Lake Natron - Kilombero Valley Floodplain - Rufiji-Mafia-Kilwa Marine Ramsar Site Uganda - Lake George - Lake Nabugabo wetland system SOURCE: Convention on Wetlands of International Importance - List of Wetlands of International Importance C.8.4 Convention on Biological Diversity All Nile Basin States are Parties to the Convention on Biological Diversity signed in June 1996. "The Convention on Biological Diversity (CBD) commits Parties to conserve biological diversity, to use biological resources in a sustainable manner, and to ensure the fair and equitable sharing of benefits from the use of genetic resources through the development of national strategies, policies or programs and appropriate legislation. Among other requirements, Parties must identify protected areas where special measures need to be taken to preserve biological diversity, and develop management guidelines for these areas to minimize or avoid loss of biological diversity (including the use of environmental impact assessments), to promote the protection of ecosystems and to engage in environmentally sound and sustainable development. Conservation and sustainable use of biological resources must enter into national decision-making."42 C.8.5 Convention for the Establishment of the Lake Victoria Fisheries Organization The Convention for the Establishment of the Lake Victoria Fisheries Organization signed by Tanzania, Kenya, and Uganda establishes the Lake Victoria Fisheries Organization which is in charge of the joint management of Lake Victoria and conservation of its resources. "This convention will not affect proposed power developments in the Nile Basin that are not located on or near Lake Victoria."43 42Source: Africa Power provided by The World Bank 43Source: Ibid. SSEA III - Final Report C-29 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS C.8.6 UN Convention to Combat Desertification (UNCDD) All Nile Basin States Are Parties to the United Nations Convention to Combat Desertification (UNCDD) signed in 1991. The UNCDD obliges parties to prepare National Action Programmes to combat desertification (NAPs), to identify factors contributing to desertification and measures necessary to combat desertification. The UNCDD includes provisions ensuring public participation in relevant decision-making processes, and the protection and use of relevant traditional and local technology and knowledge. Burundi, DRC, Kenya, Tanzania and Uganda have submitted NAPs, many of which set out domestic programs and policies affecting the energy sector, and use of water resources. "The Convention also obliges Parties to work to achieve coordination among the various levels of government for sustainable use of land and water resources; and to cooperate with other Parties to prepare regional and sub-regional programs to complement NAPs."44 C.8.7 International Commitment Concerning Illegal Trade of Wild Fauna and Flora Upper Nile Basin countries are parties to some international and regional agreements preventing illegal trade in wild flora and fauna. These instruments are unlikely to have significant implications for power development projects. The main objective of the Convention on International Trade in Endangered Species (CITES) is to ensure that international trade in specimens of wild animals and plants does not threaten their survival. "Under CITES, the import, export or re-export and introduction from the sea of species covered by the convention must be authorized by a licensing system under a state-designated Management Authority. Species covered by CITES are set out in the three appendices to the convention according to the level of protection required (aquatic flora and fauna are included in those Appendices)."45 Kenya and Tanzania are also Party to the Lusaka Agreement on Co-operative Enforcement Operations directed at Illegal Trade in Wild Fauna and Flora. This Agreement establishes a co-operative Task Force to combat illegal trade in wild fauna and Flora. C.8.8 International Commitments Concerning Greenhouse Gas Emissions and Hazardous Waste All Nile Basin States are Party to the 1997 Kyoto Protocol, and amendment to the United Nations Framework Convention on Climate Change (UNFCCC). None of the Nile Basin States have specific, legally-binding emission reduction targets. They are obliged to formulate, implement, publish and regularly update national and, where appropriate, regional programmes containing measures to mitigate climate change, especially concerning the energy sector. As all Nile Basin States (with the exception of Kenya) have the UN status of `least developed country', they have access to a special fund to assist them in carrying out this work. All Nile Basin States have made commitments to monitor production and take appropriate measures (including legislative and administrative measures) to control emissions of substances that harm or destroy the ozone layer, or trade in controlled substances. Kenya and Uganda have not agreed to introduce control measures for production and trade in HCFCs or the production and consumption of Bromochloromethane or BCM. 44Source: Ibid. 45Source: Africa Power provided by The World Bank. SSEA III - Final Report C-30 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS All Nile Basin States have made commitments to manage the transboundary movement and disposal of hazardous wastes. The Vienna Convention obliges Parties to monitor production of substances that harm or destroy the ozone layer and to take appropriate measures (including legislative and administrative measures) to control their emissions. The Convention encourages intergovernmental cooperation on research, exchange of information, and systematic observation of the ozone layer. Subsequent protocols and amendments to this Convention have, among other thing, accelerated phase-out schedules, introduced new kinds of control measures and added new controlled substances to the list. Burundi, DRC, Rwanda and Tanzania are party to the Convention and all subsequent protocols and amendments. Kenya and Uganda are party to the Convention and subsequent protocols and amendments with the exception of the Beijing Amendment. The Beijing Amendment provides control measures for production for HCFCs and further introduced control measures for both production and consumption for one new group of substances, Bromochloromethane or BCM. Burundi, DRC, Kenya, Rwanda, Tanzania and Uganda are all Parties to the Basel Convention on Hazardous Wastes. This Convention obliges Parties to take necessary measures to ensure that the management of hazardous wastes and other wastes is done in accordance with the protection of human health and the environment. "The Convention includes provisions allowing both for the controlled movement of hazardous wastes and prohibitions in the import and export of hazardous wastes"46. C.9 The World Bank's `Safeguard Policies' Among the overall set of Operational Policies guiding the operations of the World Bank, Bank management has identified ten key policies, known as the `Safeguard Policies', that are critical to ensuring that potentially adverse environmental and social consequences of projects are identified, minimized, and mitigated. These ten policies are summarized hereafter: · OP/BP 4.10 Environmental Assessment: This policy is considered to be the umbrella policy for the Bank's environmental 'safeguard policies'. This policy requires Environmental Assessment of projects proposed for Bank financing to ensure that such projects are environmentally sound and sustainable. All projects proposed must be screened by the Bank and put into one of four categories for Environmental Assessment purpose. If a project falls into categories A or B, a Comprehensive Environmental Assessment (also know as EIA) must be conducted to respond to Bank requirements. An EIA must include a comprehensive environmental management plan. · OP 4.04 Natural Habitats: This policy seeks to ensure that development projects take into account the conservation of biodiversity, as well as the numerous environmental services and products which natural habitats47 provide to human society. The policy prohibits Bank support for projects which would lead to the significant loss or degradation of any Critical Natural Habitats which are natural habitats either legally protected, officially proposed for protection, or unprotected but of known high conservation value. 46Source: Ibid. 47Natural Habitat is defined as : `land and water areas where most of the native plant and animal species are still present' (World Bank Website: www.worldbank.org) SSEA III - Final Report C-31 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS · OP 4.36 Forests: This policy aims to reduce deforestation, enhance the environmental contribution of forested areas, promote afforestation, reduce poverty, and encourage economic development. This policy prohibits Bank support for projects that would involve significant conversion or degradation of critical forest areas or related critical natural habitats. The Bank may finance projects involving the significant conversion or degradation of natural forests or related natural habitats that are not critical, if there are no feasible alternatives to the project and its siting, if a comprehensive analysis demonstrates that overall benefits from the project substantially outweigh the environmental costs, and if such project incorporates appropriate mitigation measures. The Bank requires governments receiving funding to show commitment toward sustainable management and conservation-oriented forestry. · OP 4.09 Pest Management: This policy provides that rural development projects and health sector projects have to avoid using harmful pesticides. The preferred approach is the Integrated Pest Management (IPM) techniques that must be encourage in the whole of the sectors concerned. If pesticides have to be used in the protection of crop or in the fight against vector-borne diseases, the borrower must prepare a Pest Management Plan (PMP). · OP/BP/GP 4.12 Involuntary Resettlement: This policy aims to avoid involuntary resettlement when feasible, or to minimize and mitigate its adverse social and economic impacts. This policy promotes participation of displaced people in resettlement planning and implementation. The policy main key economic objective is to assist displaced persons in their efforts to improve or at least restore their incomes and standards of living. This policy also prescribes compensation and other resettlement measures and requires that project submitted includes adequate resettlement planning instruments. · OP/BP 4.10 Indigenous Peoples: This policy underscores the need for project proponent and Bank staff to identify indigenous peoples and to engage in a process of free, prior, and informed consultation. The policy also aims to ensure that that adverse impacts on Indigenous People are avoided, or where not feasible, minimized or mitigated and that they participate in project and benefit from it in a culturally appropriate way. · OP. 4.11 Physical Cultural Resources: This policy aims to avoid, or mitigate, adverse impacts on cultural resources48 from development projects that the World Bank finances. Project falling under category A or B must addresses impacts on physical cultural resources as an integral part of the environmental assessment (EA) process. · OP 4.37 Safety on Dams: This policy requires that the design and supervision of construction of dam project must be carried out by experienced and competent professionals and that dam safety measures be adopted and implemented through the project cycle. The policy also applies to existing dams where they influence the performance of a project. In such case, a dam safety assessment should be carried out and necessary additional dam safety measures should be implemented. 48Physical cultural resources are defined as "movable or immovable objects, sites, structures, groups of structures, and natural features and landscapes that have archaeological, paleontological, historical, architectural, religious, aesthetic, or other cultural significance" (Source : World Bank Website: www.worldbank.org). SSEA III - Final Report C-32 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS · OP/BP 7.50 Projects on International Waterways: This policy underscores the importance of riparian states making appropriate agreements or arrangements for the entire waterway, or parts of it. If there are no such agreements or arrangements, the Bank requires, as a general rule, that the borrower notify the other riparians of the project. The Policy lays down detailed procedures for the notification requirement, including procedures in case there is an objection by one of the riparians to the project. · OP/BP 7.60 Projects in Disputed Areas: The Bank will only finance projects in disputed areas when the other claimant to the disputed area have no objection to the project, or when the special circumstances of the case support Bank financing, even in case of objection. C.10 Regional Institutions Emerging regional development structures that co-operate actively with the Nile Basin Initiative (NBI) and NELSAP include the new African Union (AU), the New Partnership for Africa's Development (NePAD), the East African Community (EAC ­ three member states), the Southern Africa Development Community (SADC ­ 14 member states), the Common Market of Eastern and Southern Africa (COMESA ­ 20 member states), the Economic Community of the Great Lakes Countries (CEPGL) ­ three member states, and the Inter- Governmental Authority for Development (IGAD ­ seven member states). C.10.1 African Union (AU) In 2001, the African Union (AU) was launched with the mission to strengthen and advance the process of political and socio-economic integration begun by the former Organisation for African Unity (OAU). It addresses the many issues facing the continent, from Human rights to economic development and from safeguarding territorial integrity of the member States to promoting co-operation within the framework of the United Nations. The Union counts 53 members including all African countries except Morocco. The Africa Union's administrative structure is based on 5 regions: North, West Africa, Central Africa, Southern Africa and East Africa and the horn of Africa. The African Union is composed of an Assembly, an Executive Council, a Commission, a Peace and Security Council, a permanent Representative Committee, a Pan-African Parliament and a Court of Justice. The African Union has special programs, among which the Infrastructure and Energy Program which deals with energy, transport, communication, infrastructure and tourism. The AU takes as its guide the provisions of the Abuja Treaty, which came into force in 1994 with plans for the establishment of an African Economic Community (AEC) by 2028. The regional communities are supposed to be the "building blocks" of the AEC. However, to date, Africa's urgent political priorities have taken precedence over economic integration. Since its foundation, the AU has concentrated on peacekeeping and has established a Peace and Security Council. C.10.2 New Partnership for Africa Development (NePAD) The New Partnership for Africa's Development (NePAD), which began in 2001 as a "framework document" to define the continent's relationship with the countries of the G7/G8, has developed into an important vehicle for channeling development funds to African countries. Numerous regional infrastructure development and cross-boundary business activities are being generated, or endorsed, by the South Africa-based NePAD secretariat. Multilateral development banks are establishing special facilities and funds to finance NePAD projects, while the UN system is realigning its work in Africa in support of NePAD. SSEA III - Final Report C-33 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS NePAD was initially designed as an initiative to encourage and reward African countries that practice "good political, economic and corporate governance" (i.e., countries that offer their populations a voice and accountability, effective government and regulatory quality). The initiative aims to encourage the emergence of regional economic leaders and to provide additional incentives for private sector investment in Africa. The initiative is based on a voluntary "peer review" process, the African Peer Review Mechanism (APRM), which is handled by a seven-member Panel of Eminent Persons made up of Africans. In October 2002, South African president Thabo Mbeki announced that the peer review process would focus on monitoring codes of economic and corporate governance, with political peer review to be conducted by the newly formed African Union. So far, 23 African countries have signed up for the peer review process, and technical missions have already been fielded in four countries ­ Ghana, Kenya, Mauritius and Rwanda. NePAD key priorities action area are: · Operationalising the African Peer Review Mechanism; · Facilitating and supporting implementation of the short-term regional infrastructure programmes covering Transport Energy, ICT, Water and Sanitation; · Facilitating implementation of the food security and agricultural development program in all sub-regions; · Facilitating the preparation of a coordinated African position on Market Access, debt relief and ODA reforms; · Monitoring and intervening as appropriate to ensure that the Millennium Development Goals in the areas of health and education are met.49 C.10.3 Economic Community of the Great Lakes Countries (CEPGL) The Communauté Économique des Pays des Grands Lacs (CEPGL) was created in 1976 to promote the economic integration and facilitate people and goods movement in the Great Lakes region. CEPGL was composed of three member states, DRC, Burundi and Rwanda. It was above all an agency created to promote cooperation and the management of common interests among member countries, including in particular the existing hydropower stations on the Ruzizi River that supply Burundi, Rwanda and the Kivu region in DRC. Électricité des Grands Lacs (EGL) and SINELAC, member organisations of the CEPGL, are responsible for operating hydropower stations on the Ruzizi River. The institutional effectiveness of the CEPGL has been limited. In 1994 the crisis in Burundi and the genocide in Rwanda initiated a crisis in the CEPGL and in 1996 all CEPGL treaties were suspended after Rwanda's incursion into DRC territory. In 2004 Belgium was promoting the reactivation of the CEPGL.50 C.10.4 East African Community (EAC) The East African Community (EAC) is the regional intergovernmental organisation of the Republics of Kenya, Uganda and Tanzania (and possibly Burundi and Rwanda in due course). Its headquarters are located in Arusha, Tanzania. The East African Heads of State 49 Source: NePAD Website: www.nepad.com 50 Press release of July 7th, 2004 from the Belgium Foreign Affairs, Foreign Trade and Development Cooperation available online at www.diplomatie.be SSEA III - Final Report C-34 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS signed the Treaty for the Establishment of the East African Community in Arusha on 30th November 1999. The three East African countries cover an area of 1.8 million square kilometres and have a population of 92 million who share a common history, language, culture and infrastructure. These advantages provide the Partner States with a unique framework for regional co-operation and integration. The EAC launched a customs union in January 2005. Prior to re-launching the East African Community in 1999, Kenya, Tanzania and Uganda had enjoyed a long history of co-operation under successive regional integration arrangements. These included the Customs Union between Kenya and Uganda in 1917, which the then Tanganyika later joined in 1927; the East African High Commission (1948-1961); the East African Common Services Organisation (1961-1967); the East African Community (1967- 1977), and the East African Co-operation (1993-1999). The main organs of the EAC are the Summit of Heads of State and or Government; Council of Ministers; Co-ordination Committee; Sectoral Committees; East African Court of Justice, East African Legislative Assembly; and the Secretariat. The East African Community operates on the basis of a five-year Development Strategy. The Strategy document spells out the policy guidelines, priority programs and implementation schedules. The EAC strategy emphasises economic co-operation and development with a strong focus on the social dimension. The role of the private sector and civil society is considered as central and crucial to the regional integration and development in a veritable partnership with the public sector. The regional co-operation and integration envisaged in the EAC is broad based, covering: trade, investments and industrial development; monetary and fiscal affairs; infrastructure and services; human resources, science and technology; agriculture and food security; environment and natural resources management; tourism and wildlife management; and health, social and cultural activities. Other areas of co-operation include free movement of factors of production; and co- operation in political matters, including defense, security, foreign affairs, legal and judicial affairs. The EAC collaborates with other African organisations in the spirit of the Abuja Treaty for the establishment of the African Economic Community. Among these organisations are the African Union, Common Market for East and Southern Africa, Inter-Governmental Authority on Development and Southern African Development Community. The core budget of the EAC's Secretariat is funded by equal contributions from the Partner States. Regional projects and programmes are funded through the mobilisation of resources from both within and without the region. In 2006, the East African Community states adopted the Protocol on Environment and Natural Resources Management (see Appendix C). The objectives of this Protocol are to promote sustainable development and sustainable utilization of environment and natural resources and to promote the cooperation of the States in the management of those resources including those that are transboundary. The Protocol promote development and harmonisation of policies, laws and strategies for environment and natural resources management to support sustainable development including the Environmental Impact Assessment regulations and policies. The Protocol established the Sectoral Committee on Environment and Natural Resources. (EAC Protocol). SSEA III - Final Report C-35 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS C.10.5 Southern Africa Development Community (SADC) The Southern Africa Development Community (SADC) is composed of 14 member countries (including Burundi, DRC, Rwanda and Tanzania from the NEL-region51). Uganda has applied for membership and is waiting approval. SADC focuses on the harmonisation and rationalization of policies and strategies for sustainable development in areas of regional economic integration and poverty alleviation. The Southern African Development Community was established in 1992, but it was not until March 2001 that it began to promote integration as opposed to policy coordination. SADC has planned measures to promote the economic integration of the region and eventually create a common market. A free-trade area, scheduled for 2008, is not expected until 2016. SADC have set up protocols in different areas to harmonize policies and strategies among its member states. These include protocols in the energy sector, shared watercourses, and fisheries. The DRC is not signatory of the SADC Protocol on Energy while Tanzania is. Tanzania is Party to the protocols in the energy sector, shared watercourses, and fisheries. These place obligations on Tanzania with regards to SADC member states when projects occur in the Tanzanian jurisdiction, whether or not they involve resources shared with other SADC member states. However, the protocol does not otherwise prohibit Tanzania from entering into arrangements with non-SADC member states. The SADC Protocol on Energy commits Tanzania to regional co-operation with other SADC members in the energy sector, including harmonization of energy policies, energy-pooling initiatives (transmission, conveyance and storage of energy to obtain optimum reliability of service, economy of operation, and equitable sharing of costs and benefits), and the facilitation of private sector participation in the energy sector. "Co-operation with non-SADC States in energy matters is permitted provided it is not inconsistent with the objectives of the Protocol or impedes a Party from meeting its obligations under the Protocol' (Art. 7). The Protocol is unlikely to have an affect on Tanzania's capacity to enter into a power arrangement with the Nile Basin countries. Tanzania is Party to the SADC Revised Protocol on Shared Watercourses which obliges the Parties to utilize shared watercourses equitably, to establish close cooperation with regards to the study and execution of all projects affecting watercourse systems in the SADC region, to harmonize legislation on shared watercourses, and to establish agreements and institutions for the management of shared watercourses. The Protocol also contains detailed provisions for timely notification to, and consultation with, other Parties of measures that may have a significant effect on them. Furthermore, the Protocol obliges Tanzania to cooperate with other SADC states with regards to any projects likely to have effect on watercourses in the region, and not just watercourses shared with other SADC states. As Party to the SADC Protocol on Fisheries, Tanzania is obliged to take measures to regulate aquatic resources on its territory and to prevent their overexploitation. Where aquatic resources are shared, Parties may enter into management arrangements. According to this Protocol, Protocol stakeholders must be included in the decision-making processes affecting the management of shared resources. In similar fashion to the Revised Protocol on Shared Watercourses, this Protocol does not only apply to shared watercourses but to all living aquatic resources and aquatic ecosystems in the country. 51 SADC comprises Angola, Botswana, DRC, Lesotho, Malawi, Mauritius, Mozambique, Namibia, Seychelles, South Africa, Swaziland, Tanzania, Zambia and Zimbabwe. Note: DRC is not a signatory to the Protocol on Energy. SSEA III - Final Report C-36 017334-001-00 APPENDIX C - SYNOPSIS OF ENVIRONMENTAL AND SOCIAL POLICIES AS WELLAS THEIR LEGAL AND ADMINISTRATIVE FRAMEWORKS C.10.6 Common Market of Eastern and South Africa (COMESA) The Common Market for Eastern and Southern Africa (COMESA) was initially established in 1981 within the framework OAU Lagos Action Plan. It was then referred to as the Preferential Trade Area for Eastern and Southern Africa and was transformed into COMESA in 1994. COMESA is the largest African economic grouping and is comprised of 20 states including Burundi, DRC, Kenya, Rwanda and Uganda. Only nine countries (Djibouti, Egypt, Kenya, Madagascar, Malawi, Mauritius, Sudan, Zambia and Zimbabwe) formally belong to the free-trade area set up in 2000. Tanzania withdrew from COMESA in 2000, citing regional trade imbalances. C.10.7 Communauté Économique des États de l'Afrique centrale (CEEAC) The Communauté Économique des États de l'Afrique centrale (CEEAC), regroups eleven (11) countries of Central Africa, including Burundi, République Démocratique du Congo and Rwanda. CEEAC was created following the OAU Lagos Action Plan trough a treaty signed in October 1983 which entered into force in Décembre 1984. Its main mission statements was to contribute to the cooperation and economic integration process among central African states. The CEEAC was put hold between 1992 and 1997, because of the many conflicts affecting the area. The CEEAC was restarted in 1998 and a new vision of the entity's role was adopted in 1999. The new vision of regional integration is focused on: Human integration; Capacity building; Physical, economic and monetary integration; Development of capacity in maintenance of peace, security and stability. C.10.8 Inter-Governmental Authority for Development (IGAD) The Inter-Governmental Authority for Development (IGAD) of north-east Africa, with seven members52, was originally intended to promote environmental protection and food security in the Horn of Africa. Over the years it has been expanded to a fully-fledged regional entity dealing with political, economic and security issues. However, since 1996, it has taken on a role as a regional forum and an interface for peace initiatives in Somalia and Sudan. IGAD's three priority areas are 1) conflict prevention; 2) infrastructure development; and 3) food security and environmental protection. IGAD aims at expending areas of regional co- operation and promoting peace and stability in the region. IGAD is one pillar of the African Economic Community and collaborates with COMESA and the East African Community to avoid duplications of effort.53 52 The Inter-Governmental Authority for Development (IGAD) members countries are Djibouti, Somalia, Eritrea, Sudan, Ethiopia, Uganda and Kenya. IGAD was formally known as the Inter-Governmental Authority on Drought and Development (IGADD). 53 Source: IGAD website: www.igad.org SSEA III - Final Report C-37 017334-001-00 APPENDIX D SYNOPSES OF ENERGY POLICIES AND LEGAL AND RELATED ADMINISTRATIVE FRAMEWORKS SSEA III - Final Report 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS TABLE OF CONTENTS PAGE D SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS D-1 D.1 Introduction D-1 D.2 Burundi D-1 D.2.1 The Overall Legal and Regulatory Framework D-1 D.2.2 Laws and Regulations Specific to the Power Sector D-2 D.2.3 The Structure of the Power Sector D-3 D.2.4 Attracting Foreign Investment and Facilitating Financing D-3 D.2.5 Issues and Concerns D-3 D.3 Democratic Republic of Congo (DRC) D-7 D.3.1 The Overall Legal and Regulatory Framework D-7 D.3.2 Laws and Regulations Specific to the Power Sector D-8 D.3.3 The Structure of the Power Sector D-8 D.3.4 Attracting Foreign Investment and Facilitating Financing D-9 D.3.5 Issues and Concerns D-10 D.4 Kenya D-13 D.4.1 The Overall Legal and Regulatory Framework D-13 D.4.2 Laws and Regulations Specific to the Power Sector D-14 D.4.3 The Structure of the Power Sector D-15 D.4.4 Attracting Foreign Investment and Facilitating Financing D-17 D.4.5 Issues and Concerns D-17 D.5 Rwanda D-22 D.5.1 The Overall Legal and Regulatory Framework D-22 D.5.2 Laws and Regulations Specific to the Power Sector D-23 D.5.3 The Structure of the Power Sector D-23 D.5.4 Attracting Foreign Investment and Facilitating Financing D-24 D.5.5 Issues and Concerns D-24 D.6 Tanzania D-27 D.6.1 The Overall Legal and Regulatory Framework D-27 D.6.2 Laws and Regulations Specific to the Power Sector D-27 D.6.3 The structure of industry and the regulatory role over the power sector D-28 D.6.4 Attracting Foreign Investment and Facilitating Financing D-29 D.6.5 Issues and Concerns D-30 D.7 Uganda D-34 D.7.1 The Overall Legal and Regulatory Framework D-34 D.7.2 Laws and Regulations Specific to the Power Sector D-35 D.7.3 The Structure of the Power Sector D-35 D.7.4 Attracting Foreign Investment and Facilitating Financing D-36 D.7.5 Issues and Concerns D-37 SSEA III - Final Report D-i 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS D SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS D.1 Introduction This Appendix provides country-specific synopses that include descriptions of: · The overall legal and regulatory framework; · Laws and regulations specific to the power sector; · The structure of the power sector; · Various specific issues and concerns. The main sources and references underpinning the review, analysis, recommendations and conclusions regarding the national energy policies and the legal and administrative frameworks of the six countries can be found in Appendix L. D.2 Burundi D.2.1 The Overall Legal and Regulatory Framework The legal and regulatory framework of Burundi can be summarized as follows: · Burundi is a unitary State; · The Central Government sets policies and rules; · Burundi's political system is based on German and Belgian civil codes as well as its own customary law. Burundi' s court system is comprised of: · A Supreme Court; · A Constitutional Court; · Courts of Appeal (there are three in separate locations); and · Tribunals of First Instance (17 at the province level and 123 small local tribunals). The general legal framework of Burundi also applies to the electricity and water sectors. It consists of the following instruments: · Code général du Commerce (Code of Commerce); · Code du Travail (Labour Code); · Code civil, Livre 2 ­ Réglementation des Biens (Civil Code ­Book 2 ­ regulations on Property); · Code civil, Livre 3 ­ Obligations (Civil Code ­ Book 3 ­ Obligations); SSEA III - Final Report D-1 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS · Statut de la Fonction publique; · Loi No 1/002 du 6 mars 1996 portant Code des Sociétés privées et publiques1. In principle, there are no incompatibilities with the realization of power projects in common with the neighboring countries. The above-cited laws are of general purview, and, as such, are subsidiary to specialized Laws. Furthermore, these general laws are in agreement with the international agreements and protocols that Burundi ratifies. · Burundi is a member of: - Communauté économique des Pays des Grands Lacs (CEPGL); - Common Market for Eastern and Southern Africa (COMESA); - Communauté Économique des États de l'Afrique centrale (CEEAC), which groups eleven (11) countries of Central, including République Démocratique du Congo and Rwanda. · Burundi has not accepted compulsory the International Court of Justice (ICJ) jurisdiction. D.2.2 Laws and Regulations Specific to the Power Sector The main law concerning the organization, the management and the development of the power sector consists of Loi No 1/014 du 11 août 2000, portant Libéralisation et Réglementation du Service public de l'Eau potable et de l'Énergie électrique2. An enabling decree (art. 35) which institutes a regulatory Agency independent of political interests is being drafted but is still yet to be passed. The Loi No 1/014 of 11 August 2000, along with all its required enabling decrees establishes the rules for: · Tariffs setting: Tariffs are currently set and proposed by REGIDESO to the Ministre de l'Énergie et des Mines3 for approval and implementation; · The export and import of electricity; · The use of natural resources, including licensing, water management plans and water quality standards; · The supply of electricity to outlying areas; and · The delivery of subsidies to vulnerable and low-income groups. 1Law No. 1/002 of 6 March 1996, Relative to Private and Public Companies. 2Law No. 1/014 of 11 August 2000, Relative to the Liberalization and Regulation of Drinking Water and Electric Energy Public Services. 3Minister of Mining and Energy ­ Minister exercising supervision over the Power sector. SSEA III - Final Report D-2 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS D.2.3 The Structure of the Power Sector The power industry is characterized by a vertically integrated utility, REGIDESO which encompasses generation, transmission, distribution and retail components. REGIDESO is a State owned Utility responsible for the supply of both water and electricity as stipulated in Section 2 within the Law No. 1/002 of 6 March 1996. With regard to the development of the national network, it must be mentioned that as stipulated in the Décret No 100/072 du 21 avril 1997 « portant délimitation des responsabilités entre la DGHER Direction Générale de l'Hydraulique et des Énergies Rurales) et REGIDESO » , the DGHER is mandated to carry out water supply and 4 electrification projects in rural areas The Ministère de l'Énergie et des Mines is the institution responsible for performing the regulatory functions over the power and water sectors5. The Ministère de l'Aménagement du Territoire, de l'Environnement et du Tourisme6 and the Ministère de la Santé Publique7 are also taking part in the regulatory task by way of their control over the water sector, more particularly for potable water. All the specific attributes and responsibilities of these Ministries can be found in Loi No 1/014 du 11 août 2000, except the quality standards for drinking water, which may be found in the Code de la Santé publique. D.2.4 Attracting Foreign Investment and Facilitating Financing No references were found on the country's policy and legal framework regarding the encouragment of foreign investments. Consequently, it would need to be verified whether foreign investors : - are offered adequate Government protection against undue appropriation or expropriation without just compensation; - would face restrictions as regards repatriation of profits or sale proceeds; - would face restrictions as regards ownership of real property. This issue should be brought to the Burundi government for its consideration, and policies similar to those of the neighbouring countries should be put forward. D.2.5 Issues and Concerns I - Does Burundi have the means for the establishment of a data collecting and processing system with regard to its own energy sector and that of neighbouring countries in promoting regional cooperation? The issue of data collecting and processing is addressed in the Politique sectorielle du Ministère de l'Énergie et des Mines as follows: · In Tableau 2, Plan d'Actions Secteur de l'eau ­ Indicateur de Vérification 1: « Base de données disponible et actualisée », the databank has information on drinking 4 Decree No. 100/072 of 21 April 1997, delimitating the responsibilities of REGIDESO and the General Direction of Hydraulics and Rural Energies. 5 These two sectors are intimately linked since water and electricity are supplied by the same utility, REGIDESO. 6 Minister of Land Use Planning, Environment and Tourism. 7 Minister of Public Health. SSEA III - Final Report D-3 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS water only (See also "Conclusions", p.54). However, it could also be used for the purpose of estimating hydro energy potential. The issue of data collecting and processing is also addressed in the Politique nationale de Gestion des Ressources en Eau et Plans d'Actions ­ Juillet 2001: · Objectifs ­ Connaissance parfaite des disponibilités en eau du pays; mise en place d'une Institution nationale unique de coordination + Plan d'Actions (2001-2010) Objectif spécifique Nos 1 & 6; p. 22. · Action Plan ­ Specific Objective No. 11 ­ Améliorer les bases de données existantes. Other than the above two documents no others were found that address this issue. II ­ Is Burundi preparing and updating inventories, assessments and master plans related to each energy sub-sector, taking into account the evolution of the situation? No references were found on this subject relating to the electricity sector. However, this issue is generally addressed in the Politique Nationale de Gestion des Ressources en Eau et Plans d'Actions ­ Juillet 2001, under the following headings: 8 · Chap. IV. Les Stratégies de développement durable du secteur de l'eau9, p.23, which calls for reinforcing the IGEBU's (Geographic Institute of Burundi) capacities in order to achieve a thorough knowledge of the water resources of the country and for updating the Plan Directeur national de l'eau. ; 10 · (2) Action Plan, Specific Objective No. 11 calls for an improvement of the existing data bases relating to water. It is also addressed in the Politique sectorielle du Ministère de l'Énergie et des Mines11, at page 32, which sets as specific objectives improving the knowledge of the Country's water resources and ensuring the coordination of interventions in the Sector, for more efficient management and sustainable development: III - Is Burundi intending to produce or producing transparent energy pricing policies that take into account its economic realities and the development and growth characteristics in each sub-sector? The Politique sectorielle du Ministère de l'Énergie et des Mines, at page 39, recommends a series of measures that aim to improve the management and financial situation of REGIDESO. In particular, it is recommended that electricity tariffs be progressively adapted to real costs. IV ­ What are the government policies on taxation and subsidies related to different forms of energy (see also point VI, below)? 8 National Policy on Water Resources Management and action Plans. 9 Strategies for the Sustainable Development of the Water Sector 10 National Master Plan for Water 11 Sectorial Policy of the Ministry of Energy and Mines SSEA III - Final Report D-4 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS Chapter VII of Law No. 1/014 of 11 August 2000 calls for the creation of a " Fonds de Développement du Secteur public de l'eau potable et de l'énergie électrique ". There is no enabling decree at this time. Nor is there any legislation regarding taxes, duties, taxes, levies, and royalties for the use of water. V ­ Is Burundi facilitating the process of attracting private and public participants to the energy sector by facilitating open access to power markets and water resources so as to attain the set efficiency objectives? The Sectorial Policy of the Ministry of Energy and Mines adresses this issue as follows: · In the Exposé des Motifs12 (page 4), it is stated that the private sector will be called upon to play an increasing role in the day-to-day management of both the power and water sectors. The role of the State is to define the policies and ensure control and regulation. · On page 18, point 3 of Le Cadre légal actuel13, it is acknowledged that the present exclusively public electricity sector is not conducive to flexibility in the management of sector enterprises or better financing opportunities. · In Section 1.2, which lists the problems that must be solved ("Les Problèmes à résoudre"), it is recommended that the participation of private operators be favoured and that the management of REGIDESO be privatized. This issue is also addressed in the Law No. 1/014 of 11 August 2000, under: · Section 2, on the delegation of public services; and · Title III (art. 78 et seq.), by setting the framework for the electricity sector that will constitute an industrial and commercial public service under State responsibility ("un service public industriel et commercial placé sous la responsabilité de l'État"); and · Article 4, by stipulating that the state will be able to delegate this public service to public or private companies ("sous forme de délégation de service public, à une ou plusieurs personnes de droit public ou de droit privé burundais"). VI ­ Is Burundi intending to proceed with or already in the process of the reorganization, revision and optimisation of the financial programs required in the short, middle and long term to satisfy the energy demand necessary to sustain the national economy (see also point IV, above)? This issue is addressed in general terms in the Sectorial Policy of the Ministry of Energy and Mines: · Under the Problems to solve sub-section, on p. 18, it is recognized that financing the development of the Energy sector is problematic, due to the lack of financial resources of the government and of REGIDESO and to the difficulties in obtaining outside financing (" ..le financement de son développement pose problème car les 12 Preamble 13 The present legal framework SSEA III - Final Report D-5 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS capacités financières de l'Etat et de la REGIDESO sont très faibles et les conditions d'obtention de crédits extérieurs sont devenues très contraignantes"); · In the Plan d'Actions du Secteur de l'Énergie pour 2002 à 200414, where the "Source (s) de Financement" are all characterized as to be found ("à chercher"). The Politique nationale de Gestion des Ressources en Eau et Plans d'Actions ­ Juillet 200115 addresses this issue under "Orientations", (p. 19). It is stated that the State will need to invest heavily in the development of hydro electric power in order to supply the majority of people ("L'État devra consentir beaucoup d'investissements dans le développement de l'hydro-électricité pour raccorder le maximum de la population"). Finally, Law No. 1/014 of 11 August 2000, in art. 38, recommends the creation of a development fund for the development of the drinking water and electric energy sectors Fonds de Développement du Secteur public de l'eau potable et de l'énergie électrique. However, none of these provides concrete measures to effectively address this issue. The Plan d'Actions du Secteur de l'Énergie pour 2002 à 2004 of the Politique sectorielle du Ministère de l'Énergie et des Mines characterizes all the required "Sources de Financement" as "à chercher". The Fonds de Développement du Secteur public de l'eau potable et de l'énergie électrique will require enabling legislation to be put in effect. VII ­ What is the legislation governing power trade in Burundi ? The basic rule set in article 7 of Loi No 1/014 du 11 août 2000 portant Libéralisation et Réglementation du Service public de l'Eau potable et de l'Énergie électrique is that the import and export of electricity are open ("libres") under the conditions prescribed by the Law. Article 24, for its part, defines electricity as "moveable property.16". The conditions are set by decree and the Minister responsible for electrical energy can limit import and export for a limited time for the purpose of operational security of the Network, quality of supply and respecting the State supply policy. Before setting such conditions, the Minister must, however, consult with the Regulatory Agency. The legal framework presents the required flexibility that is recommended. VIII ­ Is Burundi intending to proceed with or in the process of the preparation of appropriate policies to build institutional and human capacity for regional power trade? The Politique sectorielle du Ministère de l'Énergie et des Mines adresses this issue by recognizing that ("La géopolitique de la sous-région, caractérisée par des conflits internes et entre pays, a pour conséquence de bloquer leur coopération dans le secteur de l'énergie en général et les projets hydroélectriques communautaires en particulier, susceptibles d'offrir des opportunités d'économie au niveau de leur montage financier.") 14 2002-2004 Energy Sector Action Plan 15 National Policy for the Management of Water Resources and Action Plans, July 2001 16 In civil law systems, movable property (personal property or chattel in Common Law systems) is any property that can be moved from one location or another. As opposed to "immoveable" property ("real" property in Common Law Systems) which generally refers to land and buildings. SSEA III - Final Report D-6 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS The Politique nationale de Gestion des Ressources en Eau et Plans d'Actions ­ Juillet 2001 notes that Burundi is concerned with ("deux bassins hydrographiques internationaux qui ne font pas l'objet d'une vision commune..."), and that cooperation is required to jointly manage these resources (cf. p. 6, Introduction, and p. 7, Chap. I - Principes de base). Section 1.7 of Chapter IV addresses the need to reinforce cooperation with respect to sharing and management of transboundary waters and, more particularly, for the integrated development of the Nile Basin. These lucid findings are reflected into "Objectif Spécifique No 10" in the Action Plan for 2001-2010, which recommends the establishment of a transboundary water utilisation Master Plan, in particular. D.3 Democratic Republic of Congo (DRC) D.3.1 The Overall Legal and Regulatory Framework The legal and regulatory framework of Democratic Republic of Congo can be summarized as follows: · Democratic Republic of Congo is a unitary and centralized State. · The country is governed by the President assisted by four (4) vice-presidents: - Economy & Finances - Politique, Défense et Sécurité - Socio-Culturel - Construction et Développement · The Central Government sets policies and rules. · Civil and criminal codes are based on Belgian civil code as well as Congo's own customary law. The Military court which was instituted because of the war is no more in force and it has been replaced since the year 2003 by the Auditorat militaire general which presently dispenses justice on the basis of the following court system: · The Auditorat de Garnison which stands for the Crown Court. They are located in all military installations and in most urban areas, and they are opened to the public at the discretion of the military judge. The Government claimed that its use of military courts rather than civilian courts was a result of the ongoing war in the country17; · The Cour Supérieure Militaire which stands for the Court of Appeal; · The Haute Cour Militaire which stands for the Supreme Court; · Democratic Republic of Congo has accepted ICJ jurisdiction in 1970. In addition, the Project Appraisal Document on Private Sector Development and Competitiveness in the Democratic Republic of Congo, July 2, 2003 (Report No: 25707 ZR) has indicated that no credible, professional, effective judiciary system currently exists in the 17 Taken from Jurist Legal News and Research at http://jurist.law.pitt.edu/world/congo.htm SSEA III - Final Report D-7 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS DRC, although islands of excellence may be found in all areas of the legal and judiciary system. · Democratic Republic of Congo is a member of: - Communauté économique des Pays des Grands Lacs (CEPGL); - Communauté Économique des États de l'Afrique centrale (CEEAC), which groups eleven (11) countries of Central Africa, including Burundi and Rwanda; - Southern African Development Coordination Conference (SADCC) 18 which includes thirteen (13) member states of Central, Eastern and Southern Africa, including Tanzania. · Democratic Republic of Congo has accepted ICJ jurisdiction in 1970. D.3.2 Laws and Regulations Specific to the Power Sector The main lawful document governing the sector is the Ordonnance no 78-196 du 5 mai 1978 portant statuts de la S.N.E.L. which specifically relates to the State Owned Utility SNEL This document is complementary to the various rules, decrees of which the following can be mentioned: · Décret du 2 juin 1928 : les conditions générales du transport et de distribution de l'énergie électrique (General Conditions for transmission and distribution of electricity); · Décret du 16 avril 1931 portant transport de l'énergie électrique au travers des terrains privés (expropriation); · Décret du 31 juillet 1953 portant importation et exportation d'énergie électrique (imports and exports of Electricity); · Arrêté Royal du 9 octobre 1956 portant règlement général et cahier des charges générales fixant les principes applicables aux concessions de distribution publique de l'énergie électrique (General conditions for Distribution concessions); · Ordonnance no 91/348 du 27 décembre 1991 - Libéralisation du Secteur. D.3.3 The Structure of the Power Sector The industry is presently managed by a vertically integrated utility (SNEL) which is responsible for generation, transmission and distribution. Even though there are a few mining enterprises which produce electricity for their own consumption, they do not have the right to commercialize their power surplus. Hence, the State Owned Utility, SNEL, has a de facto monopoly on generation, transmission and distribution of electricity because of its national cover and sheer presence some auto producers. Nevertheless, private power generation has been possible since 1994, subject to the authorization of the Energy Minister19. An agreement with the Ministry of Energy is also 18 http://en.wikipedia.org/wiki/Southern_African_Development_Community SSEA III - Final Report D-8 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS required to commercialize (i.e. sell bulk or retail)20 with the tariff being appointed by the Ministry of Economy21. As regards the water sector, which is central to the RDC's development, two main organizations are in charge: · REGIDESO, which is responsible for production, distribution and commercialization of potable water in existing city and centres; · The Service national de l'Hydraulique Rurale, which is responsible for rural area populations. The government's short-term strategy is to provide a minimum supply of electricity to the main cities by the means of the State Owned Utility, while starting to reinforce institutional capacities in the country. The long-term strategy is to invest in new infrastructure (through the Emergency Multisector Rehabilitation and Reconstruction Project (EMRRP)), to promote a new law which will successfully govern the whole sector, to create an independent regulatory authority, and then to reform the Société Nationale d'Électricité (SNEL)22. The Ministre du Portefeuille (Minister of Economy) is the institution responsible for administrative and financial supervision of both the Water and power Sectors, while the Ministère de l'Énergie is in charge of the technical supervision (Cf. "Ordonnance no 78-196 du 5 mai 1978 portant statuts de la S .N.E.L. », art. 21). There are presently some thoughts taking place towards the establishment of a regulatory Authority independent of political interest, through the Comité de Pilotage de la Réforme des Entreprises Publiques (COPIREP) preliminary works. COPIREP is a steering committee put in place by the RDC Government to implement the reforms and develop ad hoc regulations for a development of public/private partnerships. D.3.4 Attracting Foreign Investment and Facilitating Financing The business climate in DRC is gradually improving as a result of both its government's policies and the measures adopted to give confidence to foreign investment. These policies and measures include: Restructuring the tax regime; Improving the regulatory, legal, and judiciary framework to both attract private investment and generate government revenues; Offering sovereign risk guarantees against expropriation of private assets; 19 Arrêté 0072/CAB-ENER/94 du 16 novembre 1994 ­ instituant l'autorisation de construction de centrales hydroélectriques, and Arrêté 0074/CAB-ENER/94 du 16 novembre 1994 - fixant les conditions pour l'obtention de l'autorisation de construction de centrales hydroélectriques 20 Arrêté 0074/CAB-ENER/94 du 16 novembre 1994, s. 8 21 Presently, some seven (7) private power generation and commercialisation projects are being studied, and a pilot project, SENOKI (5 MW) in the North Kivu province, initiated by the inhabitants of Butembo, is being built. 22 Project Appraisal Document on Private Sector Development and Competitiveness in the Democratic Republic of Congo, July 2, 2003 (Report No: 25707 ZR) SSEA III - Final Report D-9 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS Restructuring public enterprises to encourage more private sector involvement and to improve quality of and access to services; Reforming the financial sector. Also, a number of laws and regulations such as the Charter of the Central Bank, the Banking Act, and the Cooperative Banking Act have been revised and approved by the government to enhance economic governance and to move towards comprehensive financial sector reform Finally, DRC offers a number of investment incentives designed to attract foreign capital, which offsets the country's major economic instability and political uncertainty. Eligibility for these various incentives, which are mainly in the form of tax breaks and duty exemptions, is based on the location and type of the enterprise.23 Under Congolese laws, there is no substantial difference in treatment between foreign and domestic enterprises and expropriation is not a factor in DRC's investment climate24. In addition, DRC is a member of the World Bank's Multilateral Investment Guarantee Agency (MIGA), which offers insurance to new foreign investments against foreign exchange risk, expropriation and civil unrest. Indeed, during the 1980's DRC took formal steps to attract foreign investment, approving a new Investment Code, new regulations on transfer of dividends, and a bilateral investment treaty. Finally, the 1986 Investment Code guarantees the transfer of all indemnities in the event of expropriation. Congolese law allows for the transfer of dividends and other funds associated with investments and procedures for doing so have been simplified substantially in recent years, with authorizations now obtainable within days of application. A dividend transfer (withholding) tax is imposed on such transactions. There are no restrictions on reinvestment or on acquisition or takeovers."25 Since the overall situation in the country is significantly improving, the legal framework allows the involvement of private investors for power sector development or power trade. The government's policies and actions are indeed implementing the reforms and developing the best surroundings for profitable public/private partnerships, on the basis of promising local initiatives such as Société d'électrification du Nord Kivu (SENOKI).26 D.3.5 Issues and Concerns I - Does the Democratic Republic of Congo have the means for the establishment of a data collecting and processing system with regard to its own energy sector and that of neighbouring countries in promoting regional cooperation? It is not believed the DRC possesses those means. In principle, various structures, Ministries, Entities, etc., are entrusted with data collection responsibilities, each in own field. 23 Cf. Investment Climate at http://www.congofinance.com/ and World Bank Report Project Appraisal Document on Private Sector Development and Competitiveness in the Democratic Republic of Congo, July 2, 2003 (WB Report No: 25707 ZR) 24 From Investment Climate at http://www.congofinance.com/ 25 Investment Climate at http://www.congofinance.com/ 26 A company organized by business people of Butembo to build a power development on the Mususa River near Butembo. SSEA III - Final Report D-10 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS Also in principle, data is centralized and correlated, and the Ministry of Energy is charged with this function as regards the Energy field. Finally, the DRC participates in regional organizations such as the Southern African Development Community (SADC), the Union of Producers, Transporters and Distributors of Electric Power in Africa (UPDEA), the Communauté économique des Pays des Grands Lacs (CEPGL) and Électricité des Grands Lacs (EGL). A similar analysis is not available as regards the Energy sector but, also in view of the conclusions contained in the World Bank Document: Democratic Republic of Congo ­ Economic and Public Sector Work ­ Reforming Public Enterprises Through Improved Governance, March 10, 2004 (Report No: 28048-ZR), cited earlier, it is believed the situation is much the same. II ­ Is the Democratic Republic of Congo preparing and updating inventories, assessments and master plans related to each energy sub-sector, taking into account the evolution of the situation? Overall, the Government prepares and updates inventories, assessments and master plans related to each energy sub-sector through the sectorial ministries and/or Agencies: · SNEL is charged with preparing and updating inventories, assessments and master plans related to the electricity sub-sector, including hydro-electric resources and potential. · REGIDESO is charged with preparing and updating inventories, assessments and master plans related to the potable water sub-sector. · The Ministry of Environment is charged with preparing and updating inventories, assessments and master plans related to the irrigation water sub-sector. · COHYDRO ("Congolaise des hydrocarbures") is charged with preparing and updating inventories, assessments and master plans as regards hydrocarbon resources. However, the caveat expressed under Concern I above also applies here, that is, in practical terms, these organizations suffer from a deficit of resources and means, which greatly hampers them in carrying out their mandates. III - Is the Democratic Republic of Congo intending to produce or producing transparent energy pricing policies that take into account its economic realities and the development and growth characteristics in each sub-sector? In principle, yes, but this is not yet enforced. Tariffs for electricity and drinking water have been set since 1998 by the Ministry of Economy, assisted by the COSU "Comité de suivi des prix tarifs de vente d'eau potable et de l'électricité" with respect to economic realities and the development and growth characteristics of the country and, in particular, with the capacity to pay of the population. IV ­ What are the government policies on taxation and subsidies related to different forms of energy (see also point VI, below)? There is no overall policy; most decisions are taken on an ad hoc basis. Typically, when a project is judged interesting, the Energy Ministry will prepare a "technical data sheet" stating SSEA III - Final Report D-11 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS that the project is of social interest and should consequently be exonerated from the applicable taxes, levies, etc. Such exhoneration is also given to SNEL and REGIDESO, under the Arrêté ministériel du 23 mai 1998, portant détaxation des produits pétroliers destinés à la génération de l'énergie électrique de la SNEL et de la REGIDESO. As specifically regards the SNEL, the Government keeps the electricity tariffs artificially low but does not compensate the utility. V ­ Is the Democratic Republic of Congo facilitating the process of attracting private and public participants to the energy sector by facilitating open access to power markets and water resources so as to attain the set efficiency objectives? The Government is working towards facilitating the restructuring of the energy sector with COPIREP, the FEC "Fédération des Entreprises du Congo"27 and public enterprises, by facilitating such initiatives as SENOKI. VI ­ Is the Democratic Republic of Congo intending to proceed with or already in the process of the reorganization, revision and optimisation of the financial programs required in the short, middle and long term to satisfy the energy demand necessary to sustain the national economy (see also point IV, above)? This is being done through the Comité de Pilotage de la Réforme des Entreprises Publiques (COPIREP), the steering committee put in place by the RDC Government to implement the reforms and develop public/private partnerships. Five sectors have thus been identified as most apt to help rebuild the DRC economy: Mines, Energy, Transport, Telecommunications and Finances. COPIREP coordinates the action of the sectorial working groups who are mandated to formulate reform strategies. COPIREP will also oversee the revision of the current law on public enterprises, which currently does not allow for divestiture or liquidation. Finally, a new law on parastatal reform and public/private partnerships will be promulgated to set the stage for reform. VII ­ What is the legislation governing power trade in DRC? The legal framework for exports and imports is contained in the « Décret du 31 juillet 1953 relatif à l'importation et à l'exportation de l'énergie électrique », which stipulates that all imports and exports of electricity must be authorized "by the King."28 However, at present, there is little control over the exports or imports of electricity and, in practice, the DRC is in a deficit situation and has been importing from Uganda. Imports and exports are also conducted through bilateral understandings with Rwanda and Burundi, notably under the SINELAC arrangement. VIII - Is the Democratic Republic of Congo intending to proceed with or in the process of the preparation of appropriate policies to build institutional and human capacity for regional power trade? 27 Cf. http://www.fec.cd/index.html - The FEC undertakes the functions of Chamber of Commerce, Industry, Agriculture, Craft and professional association for employers 28 S. 1 ­ « Toute importation et exportation d'énergie électrique par lignes de transport aériennes ou souterraines est subordonnée à l'autorisation du Roi, qui en fixe, dans chaque cas, les conditions. » SSEA III - Final Report D-12 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS In practice, the DRC acts through Regional Organizations such as the Nile basin Initiative (NBI), the Southern African Power Pool (SAPP/SADEC), the Pool Énergétique de l'Afrique Centrale, etc. Regional integration policies already exist through the Communauté économique des Pays des Grands Lacs (CEPGL), which regroups the DRC, Burundi and Rwanda). D.4 Kenya D.4.1 The Overall Legal and Regulatory Framework 29 The overall legal and regulatory framework of Kenya can be summarized as follows: · The Republic of Kenya is a unitary State; · The head of State is the president; · The national assembly is unicameral and consists of 210 members elected to a term of up to five years, plus 12 members appointed by the president; · The president appoints the vice president and cabinet members from among those elected to the assembly; · Ministers draft policies and propose them to the National Assembly for approval; · Local administration is divided among 63 rural districts, each headed by a presidentially appointed commissioner; · Powers of Local Authorities are mostly outlined in the Local Government Act30; · Local Authorities can apply to the Government to expropriate ("acquire compulsively") for public purposes31, divert and canalise waters32 and undertake works for the supply of electricity, light, heat and power33; · The districts are joined to form seven rural provinces; · The Nairobi area has special status and is not included in any district or province; · The government supervises administration of districts and provinces. Kenya's legal system is based on British common law. The country has a four (4) level court system that consists of a Court of Appeals, a High Court, and two levels of magistrate courts, where most criminal and civil cases originate. The Chief Justice is a member of both the Court of Appeals and the High Court. There are no customary or traditional courts in the 29Information taken from Jurist Legal News and Research, at http://jurist.law.pitt.edu/world/kenya.htm 30Chapter 265 (Rev. 1998), in particular, Parts IX, X and XI 31Chapter 265, Art. 144 (2) 32Chapter 265, Art. 179 33Chapter 265, Art. 181 SSEA III - Final Report D-13 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS country. However, the national courts use the customary law of an ethnic group as a guide in civil matters so long as it does not conflict with statutory law. D.4.2 Laws and Regulations Specific to the Power Sector The Electric Power Act, 1997 (EPA) is the principal law governing the electric power sub-sector. It establishes a framework for the regulation of the sub-sector and creates the Electricity Regulatory Board (ERB). There are no specific rules for the exports and imports of electricity Other relevant statutes are34: · The Constitution of Kenya, which offers protection from compulsory acquisition, under section 75, but also lists numerous exceptions to this principle. The issue of protection from deprivation of property is central to investors and will be discussed later. · The Geothermal Resources Act, Act No. 12 of 1982, which vests all geothermal resources in the Government and empowers the Minister for Energy to authorize geothermal exploration and grant geothermal licenses subject to payment of royalties and such other terms and conditions. · The Standards Act, Chapter 496 of the Laws of Kenya, which empowers the ERB to enforce safety regulations and to ensure that electrical apparatus and works meet the standards set by the Kenya Bureau of Standards or, where no such standards exist, with the relevant international standards approved by the Kenya Bureau of Standards. · The Petroleum Act, Chapter 116 of the Laws of Kenya, which has an impact upon the operation of thermal power plants: since it regulates the importation, transportation, storage and retailing of petroleum products in Kenya. · The Petroleum Development Levy Fund Act, Act No. 4 of 1991, which empowers the Minister to impose a fuel levy that could have an impact on electricity tariffs, to finance activities related to energy development such as oil exploration and development. The EPA's provisions are broad and permit the enactment of subsidiary legislation to deal with specific aspects of regulation. The bulk of regulatory matters are to be addressed through subsidiary legislation in order to maintain a fair degree of flexibility in dealing with the changing needs of the power sub-sector. Also of note, the Electric Power Act, 1997, at s. 49-51, requires any licensee35 to liaise with local authorities affected by its proposed activities and serve notice of application for a licence on a local authority prior to submitting an application for a licence to the Electricity Regulatory Board. The EPA is presently in a process of revision and the Draft Electric Power Act ­ Final Draft ­ 20th July 2004 ("Energy Bill 2004") presently being considered appears to be implementing 34 Source: Appendix B - Kenya Power Market Reform Pre-Privatisation Report, Prepared by NERA in association with Deloitte Touche Tohmatsu, Decon & Rachier Advocates, July 2003, London 35 Defined as "..(a) public or local authority, company, person or body of persons to whom a licence (to generate, transmit, distribute or supply electricity) is granted" SSEA III - Final Report D-14 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS some of the recommendations contained in the study conducted in 2003 by the consortium consisting of National Economic Research Associates (NERA), Deloitte Touch Tohmatsu (DTT), Deutsche Energie-Consult Ingenieurgesellschaft (Decon), and Rachier Associates36, which aimed to identify the most appropriate structure for the Kenya power sector, as regards changes to the Electric Power Act (1997)37. D.4.3 The Structure of the Power Sector The current electricity supply industry (ESI) in Kenya takes the form of a single buyer type structure, in which the Kenya Power and Lighting Company Limited (KPLC) performs the role of wholesale power purchasing, transmission and distribution. Kenya Electricity Generating Company ("KenGen") and several Independent Power Producers (IPP)38 are responsible for generation in the sector. Each IPP is remunerated through a Power Purchase Agreement with KPLC, providing for energy and capacity-related payments. Kenya Electricity Generating Company is the successor of Kenya Power Company Limited (KPC) and several authorities with responsibility for hydroelectric power generation. It undertook its current name in 1998. KenGen owns and operates all the hydro plant on the interconnected system and several thermal (steam, diesel and gas turbines) and geothermal plants. KenGen also owns about 5MW of isolated diesel plant. KenGen is 100% government-owned. It has been responsible for investing in new power plant with a combination of government debt and retained earnings. It is planned, however, that after the completion of KenGen's Sondu Miriu hydro project, all future additions to capacity will be secured through a competitive procurement programme run by KPLC. KenGen would be permitted to bid in any such future procurement process. The Kenya Power and Lighting Company Limited assumed its current name in 1983, to become the successor of the East African Power and Lighting Company, a private company founded in 1922. KPLC is the only entity licensed to purchase power from KenGen and the Independent Power Producers. It also enjoys exclusive rights to sell power to customers connected to the grid, at tariffs approved by the ERB. KPLC is the only institution licensed to distribute electricity in Kenya and therefore, owns all the major transmission and distribution facilities. The Government of Kenya, Kenya residents and non-residents through the Nairobi Stock Exchange and institutional investors own KPLC. Currently 51.03% of the stock is owned by the Kenyan Government and Government-owned entities. Of this, about 11% is owned by the National Social Security Fund (NSSF). The NSSF's equity in KPLC would not be affected by future privatisation of KPLC. 36 Power Market Design and Pre-Privatisation Study Draft Final Report - A Final Report for the Restructuring Task Force 37 In particular as regards the transfer of licensing functions and powers from the Minister to the regulator in order to improve the independence of the regulatory framework, provide for greater investor security, and assist in leveraging private sector participation in KenGen and KPLC's operations. 38 OrPower4 Inc, Iberafrica Power (EA) Limited, Westmont Power Company Limited and Tsavo Power Company Limited SSEA III - Final Report D-15 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS KPLC is responsible for the preparation of power expansion programmes and is the Government of Kenya's executing agency for designing, constructing and operating rural electrification schemes. The Ministry of Energy is responsible for energy policy formulation and for oversight of the operations of the organizations in the electric power and petroleum sub-sectors. It is also concerned with petroleum exploration and supply, and the development of biomass and other new and renewable energy sources. The Ministry is responsible for the rural electrification program and has contracted Kenya Power and Lighting Company (KPLC) to be the implementing agency. The Electricity Regulatory Board (ERB), was established by Parliament in 1997 under the Electric Power Act, 1997 to regulate the generation, transmission and distribution of electric power in Kenya. ERB is mandated to establish a transparent, predictable and credible regulatory framework that protects consumers, guarantees the economic and financial viability of the power sub-sector utilities and investors, and enhances the confidence of the Government, investors and lenders in the power sub-sector in Kenya. ERB mandate will be modify under the proposed revisions contained in the Energy Bill 2004. Of note, in keeping with the adage that says "Justice must not only be done, but must be seen to be done", the physical and financial means granted the ERB, which is lodged in modern facilities in the Integrity Centre39, attest to a will of the Government of Kenya to ensure that the reforms will go through. ERB is empowered to process and recommend applications for licenses, to set, review and adjust transmission and distribution tariffs, to enforce environmental and safety regulations, to investigate consumer complaints, to ensure there is competition40 and to approve power purchases, transmission and distribution contracts. However, a recent World Bank Project Appraisal Document41 raises the following concerns as regards the Kenyan legal and regulatory framework: · Electric power producers being restricted from selling power to entities other than public electric suppliers, of which the only licensed company is KPLC; · ERB not being exempt from the provisions of the State Corporations Act which exposes it to political interference; · Absence of light regulation for small systems, such as the requirement for licenses for all such systems; and · The vesting of authority to license operators and to resolve disputes in the Ministry of Energy42. The report notes that " ..these weaknesses represent potential constraints to private sector investment, both in large projects for the national grid, as well as in small systems in the 39 The Integrity Centre is also where the Kenyan Anti Corruption Unit is lodged. 40 Even though the Electric Power Act authorizes the ERB to ensure genuine competition within the power sub- sector, it is the Restrictive Trade Practices, Monopolies and Price Control Act, Chapter 504, that remains the principal law on competition in Kenya and establishes the legal framework for its regulation. 41 Project Appraisal Document on a Proposed Credit in the Amount of SDR55.20 Million (USD8O Million Equivalent) to the Republic of Kenya for an Energy Sector Recovery Project, June 10, 2004 (WB Report No: 28314-KE) 42 Under the proposed Electricity Bill, it is the ERB that will be responsible to issue, modify, suspend and revoke licences and permits - s. 7(1) SSEA III - Final Report D-16 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS rural and peri-urban areas. In addition to the weakness in the design of the regulatory framework, the capacity of the ERB to undertake its core functions of tariff setting, reviewing power purchase agreements (PPAs), monitoring and enforcing environmental and safety regulations is limited, partly because of the high turnover of management and staff". Finally, it raises concerns as to the capacity of the ERB to undertake its core functions of tariff setting, reviewing power purchase agreements (PPAs), monitoring and enforcing environmental and safety regulations is limited, partly because of the high turnover of management and staff. These concerns are serious, and neglect by the Government to address them could hinder the development of the energy sector. D.4.4 Attracting Foreign Investment and Facilitating Financing If a proposed investment is likely to benefit the Kenyan economy, foreign investors may be issued with a Certificate of Approved Enterprise under the Kenyan Companies Act of 1962. Foreign investors holding this certificate are protected under the Act from compulsory acquisition of their enterprises43. Which would imply that foreign investors could own real property. However, the following laws need to be reviewed to ensure that they provide adequate protection to foreign investors: The Constitution of Kenya, in particular section 75(1), as to the issue of protection from deprivation of property. This is advised in view of the numerous exceptions to the principle that no property of any description may be compulsorily taken possession of, and no interest in or right over property of any description may be compulsorily acquired; The Foreign Investments Protection Act (Cap 518), so as to determine the adequacy of the protection afforded to foreign investors; The Companies Act (Cap 486), so as to determine the adequacy of the provisions relating to minority rights. If a foreign investor has been issued with a Certificate of Approved Enterprise under the Kenyan Companies Act of 1962, he is entitled to the repatriation of both capital and profits. A deduction is allowed in computing taxable income that is designed to encourage industrial growth and attract foreign investments. This deduction is allowed with respect to capital expenditures on new manufacturing industries and hotels. It is given in the fiscal year in which the buildings and machinery are first used. It would remain to assert that electricity- generating units would be considered "new manufacturing industries"44. D.4.5 Issues and Concerns As stated in the Inception Report, Kenya generally appears to possess a modern, up to date, legal frameworks, and a fully functional Regulatory authority is already in place. 43 Cf. Setting up Business in Africa, at http://www.globeafrica.com/Kenya/kenya2.htm. See also The Foreign Investments Protection Act (Cap 518) 44 For example, in Canada there is an assize tax exemption for equipment used to generate electricity. SSEA III - Final Report D-17 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS Indeed, it has a recent Electric Power Act (1997), which is presently in a process of revision, a recent Environmental Act (1999) and a recent Water Act (2002), as well as the associated regulations. Furthermore, in 2003, a study, already referred to in this report, was conducted, by a consortium consisting of National Economic Research Associates (NERA), Deloitte Touch Tohmatsu (DTT), Deutsche Energie-Consult Ingenieurgesellschaft (Decon), and Rachier Associates, which aimed to identify the most appropriate structure for the Kenya power sector. The Energy Bill 2004 presently being considered seems to be implementing some of the recommendations contained in this study, as regards changes to the Electric Power Act (1997). Finally Kenya's Electricity Regulatory Board, looks like it is well equipped both in human and material resources and, presumably, fully able to play its assigned role in the energy sector, although a recent World Bank Project Appraisal Document45 (see below, under X - Is the Government of Kenya prepared to ensure it has the institutional capacity to enforce environmental regulations and to manage environmental and social impacts?) raises some doubt about the ERB's capacity to fully play its role. Even with this caveat in mind, it is felt that the existing institutional, legal and regulatory framework will not hinder the implementation of power projects and will address many of the important issues and concerns identified at the outset of the study. Hereinafter, these issues and concerns are examined one by one with a view to identify areas of possible improvement where need be. I - Does Kenya have the means for the establishment of a data collecting and processing system with regard to its own energy sector and that of neighbouring countries in promoting regional cooperation? At the time the interviews were conducted (i.e. September 2004), there was no Central data collecting and processing system in place. However, there were many sectoral ones, for instance: · Records on all rivers where there is electric power generation are kept by Kenya Electricity Generating Company; · The Ministry of Water keeps a data base on water resources. Although we were told the Government of Kenya is very much concerned with regional compatibility and with the great number of regional initiatives (NBI, East African Master Plan, etc) and worried that they could become at cross-purposes. Neither the Power Act 1997, the Draft Sessional Paper on Energy, May 2004, nor the Energy Bill, 2004, address this question. Consequently, and in particular taking into account these concerns, it would be desirable for the Government of Kenya to consider the establishment of a central data collecting and processing system with regard to its own energy sector and that of neighbouring countries, that could help in promoting regional cooperation. 45 Project Appraisal Document on a Proposed Credit in the Amount of SDR55.20 Million (USD8O Million Equivalent) to the Republic of Kenya for an Energy Sector Recovery Project, June 10, 2004 (WB Report No: 28314-KE) SSEA III - Final Report D-18 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS II ­ Is Kenya preparing and updating inventories, assessments and master plans relative to each energy sub-sector, taking into account the evolution of the situation? This question appears to be adequately addressed through the following, under the leadership of the Ministry of Energy in collaboration with the principal actors of the Sector (Utilities, ERB): · Updates, every 5 years, of the 20 year Master Plan as well as ad hoc reviews when the need arises; · The Least Cost Power Development Plan Update - 2005 ­ 2025 Draft 1; · Power Sector review and Update of the Development Plan and Inventory. These reviews and updates are conducted under the leadership of the Ministry of Energy, in collaboration with the principal actors of the Sector (Utilities, ERB). III - Is Kenya intending to produce or producing transparent energy pricing policies that take into account its economic realities and the development and growth characteristics in each sub-sector? Presently, kerosene is subsidized because poor people mostly use it, so are the first 50 kWh of electricity consumption. These are not official Governmental policies as such, though, but traditional practices. The first 50 kWh of electricity consumption is the lowest of four (4) electricity blocks composing the domestic tariff. The ERB considers that the subsidy provided in this block is poorly targeted with every domestic consumer benefiting from it, contrary to the objective of benefiting only vulnerable members of the society, and intends to rectify this situation in its Retail Electricity Tariffs review Policy; 2004 (Zero Draft, Sept. 2004 (cf. s. 3.2 (2)). These questions were addressed in the May 2004 Draft Sectoral Paper on Energy under Section 2.1.5 End-User Tariffs, which tries to identify the cause of high consumer tariffs, such as the operational inefficiencies of KPLC and the high generation tariffs charged by IPPs, and the consequences of these high tariffs, such as non-affordability of electricity and its inaccessibility to consumers, leading to marginalisation of low-income consumers, including some small-scale commercial and industrial enterprises. The Draft Sectoral Paper on Energy goes on to state that the appropriate strategies to set the situation right "should include cost effective operation and maintenance of generation and distribution companies, implementation of projects based on least cost criteria, prudent corporate governance, review of the fiscal regime including indirect taxes levied on power generation, transmission, distribution and supply equipment, plant and machinery, spare parts and related accessories; and, implementation of generation and transmission projects on schedule to avoid undue demand for tariff increases to finance the projects." For its part, and in carrying out its mandate under the Electricity Act, 1997, the ERB must "set, review and adjust tariffs for all persons who transmit or distribute electrical energy" and "investigate tariff structure even when no specific application for a tariff adjustment has been made" (s. 121 (1) (a) & (b)). When considering whether a reasonable return can be earned, Section 62 (3) of the Act also requires that the Board consider the ability of the licensee to maintain its financial integrity, attract capital, operate efficiently and fully compensate investors for the risks assumed. SSEA III - Final Report D-19 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS This is reinforced under the Draft Electric Power Act, under Section 56, which states that the tariff structure and terms of supply, while being just and reasonable, will need to take into account the licensee's total revenues from tariffs covering all reasonable costs and a reasonable return. Finally, all these principles and considerations are reflected in the ERB's own Retail Electricity Tariffs Review Policy. These would indicate that the Kenyan government and its agencies intend to produce transparent energy pricing policies that will take into account its economic realities and the development and growth characteristics in the electricity sub- sector. IV ­ What are the governmental policies on taxation and subsidies related to different forms of energy? Under general discretionary powers, the Minister of Finance can apply subsidies, such as a reduction on the VAT applicable to cooking gas, in 2004. The Uniform Tariff Policy could also be viewed as a form of subsidy since it imposes uniformity of tariffs throughout the country. Otherwise, at the time the interviews were conducted (i.e. September 2004), there were no specific governmental subsidy policies in place. For its part, and within its mandate, the ERB follows economic policy objectives to achieve more efficient resource allocation, financial policy objectives to ensure the short and long term financial viability of sector utilities and social policy objectives aiming to re-allocate costs with a view to safeguarding specific vulnerable consumer groups when setting retail tariffs46. It may also follow additional objectives such as regional equity. More particularly, as regards subsidies, the ERB notes that ".. the inherent conflicts in the policy objectives guiding tariff design, e.g., subsidies, may compromise the efficient allocation of scarce resources within the economy." In its Retail Electricity Tariffs Review Policy, 2004, it consequently proposes to address and correct these subsidies within the expressed guidelines, commencing with the derivation of cost-reflective tariffs to satisfy the economic policy objectives in order to ensure optimal resource allocation within the economy, and then adjusting the economic tariffs to satisfy financial and social policy objectives. V ­ Is Kenya facilitating the process of attracting private and public participants to the energy sector by making possible open access to power markets and water resources so as to attain the set efficiency objectives? Many initiatives were introduced in this regard over the past years: · The Government enacted the Electric Power Act in 1997; · Under this Electric Power Act, it established the ERB to regulate the generation, transmission and distribution of electric power in Kenya; · Since then, IPPs have been allowed to operate and there are now four (4) such ventures who supply 15% of the power. Also, the Energy Bill 2004 talks of " ... the need for other players in the electricity supply industry such as electric power producers to access electricity consumers thereby introduce 46Cf. Retail Electricity Tariffs Review Policy, 2004 ­ s. 3.3 SSEA III - Final Report D-20 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS competition in supply, where KPLC currently enjoys monopoly."(Cf. Energy Policy Objectives, at p. 2) and proposes reinforcing the ERB's powers to ensure competition in the power sub-sector, where this is feasible, such as in the generation function, by giving it powers to license new electricity producers (cf. s. 40 et seq., Licensing). Generally, it could be stated that the Government of Kenya is endeavoring to make electricity available for economic activities in rural areas, rural townships and commercial centers in order to favor a balanced socio-economic growth for all in Kenya, by facilitating the process of attracting private and public participants to the energy sector. VI ­ Is Kenya intending to proceed with or already in the process of the reorganization, revision and optimization of the financial programs required in the short, middle and long term to satisfy the energy demand necessary to sustain the national economy (see also point IV, above)? This is presently being carried out through the following initiatives, in accordance, generally, with the recommendations contained in the NERA Privatization Report - Kenya Power Market Reform Pre-Privatization Report 2003: · The Draft Sessional Paper on Energy, May 2004; · The Energy Bill 2004; · The Least Cost Power Development Plan Update - 2005 ­ 2025 Draft 1. For its part, the ERB is presently putting together a tariff policy that will clearly indicate to potential investors the rules of the game in its Retail Electricity Tariffs Review Policy, 2004 (cf. s. 2.2 Elements of Revenue Requirements and, more particularly, s. 2.3 Allowed Rate of Return). It is also anticipated that Kenya will enjoy an Open Access Transmission tariff within approximately five (5) years. VII ­ What is the legislation governing power trade in Kenya? At present, there is no specific legal rule governing exports or imports of electricity, but Kenya is in a situation of deficit and has been importing from Uganda. To enhance power supply security particularly during periods of severe droughts and hopefully evolve towards a position as an exporter, Kenya's Energy Policy puts emphasis on ensuring the implementation of regional power interconnection projects with Uganda and with the Southern Africa Power Pool (SAPP), through Tanzania and Zambia, and on encouraging the private sector to develop potential hydropower sites to generate electricity for their own consumption and for export of surplus electrical power to the national grid. In particular, as an incentive, it proposes to "provide letters of intent to serious investors to appropriately guarantee purchase of their electric power on more favourable terms than for investors in fossil fuel fired stations, including a better fiscal regime for hydropower developers." 47 47Cf. Energy Policy, s. 4.1.4 ­ Regional Interconnection and s. 6.1.1 Hydropower SSEA III - Final Report D-21 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS VIII - Is Kenya intending to proceed with or in the process of the preparing of appropriate policies to build institutional and human capacity for regional power trade? Kenya is actively collaborating to the following initiatives: · Nile Basin Initiative; · East African Master Plan; · Interconnection with Tanzania and Zambia. However, it experiences difficulties in finding qualified people to assign to these projects and would benefit from programs aimed at training Engineers to Master Degree level & higher in Power Planning in developed countries. D.5 Rwanda D.5.1 The Overall Legal and Regulatory Framework The overall legal and regulatory framework for Rwanda can be summarized as follows: · Rwanda is a unitary State; · The Central Government sets policies and rules; · Rwanda's legal system is based on the German and Belgian civil law systems and customary law; · The Supreme Court can carry out judicial review of legislative acts; · Rwanda has not accepted compulsory International Court of Justice (ICJ) jurisdiction. The fundamental law of Rwanda provides for a system of communal courts, appeals courts, and a Supreme Court of six justices. The President nominates two candidates for each Supreme Court seat, and the National Assembly may choose one or reject both; however, the latter is not known to have happened. The law provides for public trials with the right to a defense, but not at public expense. The shortage of lawyers and the abject poverty of most defendants make it difficult for many defendants to obtain representation. International NGO's such as Avocats Sans Frontieres (ASF or Lawyers Without Borders) provide defence and counsel some of those in need, but it is estimated that less than 50 percent of prisoners have defence counsel. Lawyers from ASF rarely accept individual cases and assist mostly in group trials; numerous individuals represent themselves without legal assistance. During the year, new judges, prosecutors, and judicial defenders were sworn in and assigned to courts throughout the country. Over 100 judicial defenders trained by a foreign NGO began their work. However, the Government does not have sufficient prosecutors, judges, or courtrooms to hold trials within a reasonable time48. 48 Jurist Legal News and Research, at http://jurist.law.pitt.edu/world/rwanda.htm#Courts. SSEA III - Final Report D-22 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS D.5.2 Laws and Regulations Specific to the Power Sector The main legislation related to electricity sector management and development in Rwanda consists of a series of Decrees and Legislative Ordinances, dating back from the colonial era. They include: · Decree - 2 June 1928 ­ General conditions of supply; · Decree ­ 14 July 1930 ­ Standardization; · Decree ­ 16 April 1931 ­ Expropriation; and · Royal Decree ­ 9 October 1956- Electric Distribution Concessions ­ Specifications; Obligations; Tariffs. There is no legislation specifically addressing imports and exports of electricity. These transactions are covered by bilateral and trilateral agreements (such as SINELAC) with Uganda, R.D. Congo and Burundi. The following summarizes the regulatory situation in Rwanda: · The Minister of Energy, Water and Natural Resources exerts regulatory powers over the power and water sectors49; · Loi No 39/2001 du 13/09/2001 portant création de l'Agence de Régulation des services d'Utilité publique50 specifies the creation of a Regulatory Agency to regulate enterprises in the energy and water sectors (art. 5 and art. 1, point 20). D.5.3 The Structure of the Power Sector ELECTROGAZ is the sole vertically integrated utility supplying electricity and water in Rwanda. It was created by Décret-Loi No 18/76 of 20 April 1976 ­ Dispositions Organiques relatives à l'Établissement public de Production, de Transport et de Distribution d'Électricité, d'Eau et de Gaz (ELECTROGAZ)51. Until August 1999, ELECTROGAZ enjoyed monopoly status with regard to generation, transmission and to distribution of water and electricity, "dans les secteurs où il est établi"52. The monopoly status had been granted for a period of 99 years, but this disposition was abrogated by Law No. 18/99 of 30th/08/1999; paving the way for private sector involvement in the energy Sector. The Government is currently in the process of restructuring ELECTROGAZ to increase this private sector involvement, in an attempt to improve managerial and operational performance. A management contract has already been concluded. Under the new regime, 49These two sectors are closely linked since water and electricity are supplied by the same enterprise, ELECTROGAZ. 50Law No. 39/2001 of 13/09/2001 creating the Public Utilities Regulatory Agency. 51Decree-Law No. 18/76 of 20 April 1976 ­ Organic Provisions Relative to the Public Body for Generation, Transmission and Distribution of Electricity, Water and Gas (ELECTROGAZ). 52"...in the sectors where it is established" according to article 3, paragraph 3 of Decree-Law No. 18/76 of 20 April 1976. SSEA III - Final Report D-23 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS generation would be opened to competition while Electrogaz would remain the single buyer. Transmission and distribution would remain in a monopolistic position until Nov. 2008. The decrees to enforce the Law No. 39/2001 by establishing a regulatory agency have not yet been passed. D.5.4 Attracting Foreign Investment and Facilitating Financing The Rwanda Investment Code53 sets up the Rwanda Investment and Export Promotion Agency (RIEPA) whose mandate is, among others, to promote investment opportunities with foreign investors. Section 20 of the Code, for its part, promises foreign investors who invest and participate in the operation of any business in Rwanda, incentives and facilities no less favourable than those enjoyed by local investors. This would mean that, with regards to ownership of real property, foreign investors would face no restrictions and would have the same benefits as the local investors. However, to fully benefit from incentives and facilities provided by the Government, which include fiscal incentives and investment allowances, foreign investors are advised to apply for, and obtain, a Certificate of Registration, from the Rwanda Investment Promotion Agency.54 Furthermore, Section 38 of the Investment Code states that "the rights of an investor in a registered business enterprise, its assets, a claim of interest or right over any property or undertaking forming part of the registered business enterprise shall not be taken possession of or acquired by the Government except upon payment of adequate compensation, in convertible currency, paid within twelve months from the date of acquisition, and freely repatriate to a country of the investor's choice without being subject to any form of tax whatsoever." Finally, Sections 39 to 42 set clear rules for resolution of disputes between foreign investors and the Rwanda Investment Promotion Agency or the Government of Rwanda. The Rwanda Investment Code stipulates the situations where funds can be "externalized". These include payments of dividend to shareholders, repatriation of profits or proceeds on disposal of capital assets and repatriation of the enterprise sale product55. Payments of wages and salaries and other benefits to foreign staff employed in Rwanda in connection with the business enterprise can also be repatriated. D.5.5 Issues and Concerns I - Does Rwanda have the means for the establishment of a data collecting and processing system with regard to its own energy sector and that of neighboring countries in promoting regional cooperation? The issue of a data collecting and process system is entrusted to the Energy Directorate of the Ministry of Energy, Water and Natural Resources. This ministry is in charge of: · Organizing and coordinating the Energy Databank; 53Law N° 14/98 of 18/12/1998 Establishing the Rwanda Investment Promotion Agency 54Cf, S. 30, Rwanda Investment Code. 55Cf. Article 43 SSEA III - Final Report D-24 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS · Centralizing all energy related information; · Controlling the reliability of the data; · Publishing the semi-annual energy data report; · Programming inquiries into databank related activities; · Keeping records of projects, services and persons initiating actions in the renewable energy sector. II ­ Is Rwanda preparing and updating inventories, assessments and master plans related to each energy sub-sector, taking into account the evolution of the situation? No references were found relating to the issue of preparing and updating assessment and master plans for the Electricity Sector. The issue of inventories is addressed, to a certain extent, under the attribution of the Energy Directorate of the Ministry of Energy, Water and Natural Resources, which is mandated with making the inventory of projects, services and persons initiating actions in the renewable energy sector. Vision 2020 (Draft), envisions the preparation of a National Land Use Master Plan that would identify and highlight current and potential socio-economic activities and necessary support infrastructure, as well as identify and promote development poles, the installation of electricity networks and the provision of basic infrastructure (para. 50). If implemented, this could conceivably impact hydro and thermal power generation development. Objective 5 of the Sectoral Water Policy specifically envisions the preparation of inventories for the generation of hydroelectric energy and the development of a data bank for the use of geothermal waters in the generation of electricity. III - Is Rwanda intending to produce or producing transparent energy pricing policies that take into account its economic realities and the development and growth characteristics in each sub-sector? Under Chapter 5 ­ Of Competition, of Law No. 39/2001 of 13/09/2001 Creating the Public Utilities Regulatory Agency, the Agency is mandated to put special emphasis on : · Promoting efficient competition; and · Putting an end to anti-competitive practices, more particularly abuse of dominant position. IV ­ What are the government policies as to taxation and subsidies relative to different forms of energy (see also point VI below)? Law No. 14/98 Establishing the Rwanda Investment Promotion Agency addresses this issue as follows: · Art. 20 Subject to the provisions of this Law, "...foreign investors may invest and participate in the operation of any business in Rwanda, and ... shall enjoy incentives and facilities no less favourable than those enjoyed by local investors." · Chapter IV sets out the assistance and incentives for investments, such as: SSEA III - Final Report D-25 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS - Exemption from import duties and sales tax (art. 29); - Fiscal incentives (art. 30); - Investment allowances (art. 31); - Work permits and first arrival privileges (art. 32), etc. Moreover, it is understood that the Law No. 14/98 is being revised and will contain more incentives for investing in the Energy Sector. The Avant projet de Loi No ... du ... portant protection et gestion des ressources en eau56 proposes the imposition of a discretionary "Eco-Tax Regime" that would apply to all uses of water other than domestic and agricultural (Art. 43). V ­ Is Rwanda facilitating the process of attracting private and public participants in the energy sector by facilitating open access to power markets and water resources so as to attain the set efficiency objectives? Law No. 39/2001 of 13/09/2001 Creating the Public Utilities Regulatory Agency addresses this issue in: · Art. 5 ­ Attributions of the Public Utilities Regulatory Agency. In particular the Agency is mandated to ensure: 1) Transparency of supply conditions; 2) That utilities have adequate means to perform services; 3) That there is no unfair competition or market abuse; and 4) Facilitate private sector involvement. · Chapter V lays down the principles or fair competition and prevention of market abuse. It provides the guidelines for the Energy Sector. · This question is also addressed to some extent in Rwanda: Vision 2020 (Draft). VI ­ Is Rwanda intending to proceed with or in the process of the reorganization, revision and optimization of the financial programs required in the short, middle and long term to satisfy the energy demand necessary to sustain the national economy (see also point IV above)? No references were found on this issue with regard to the electricity sector. VII ­ What is the legislation governing power trade in Rwanda? At present, there is no legislation addressing the import and export of electricity. Activities of this nature are conducted through bilateral understandings with Uganda and DRC and under the SINELAC arrangement with DRC and Burundi. VIII - Is Rwanda intending to proceed with or in the process of preparing appropriate policies to build institutional and human capacity for regional power trade? 56Draft Law Relative to the Protection of Water Resources. SSEA III - Final Report D-26 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS No references were found on this issue with regard to the electricity sector. D.6 Tanzania D.6.1 The Overall Legal and Regulatory Framework The overall legal and regulatory framework of Tanzania can be summarized as follows: · Tanzania is a republic. · Except for Zanzibar's House of Representatives, which has jurisdiction over all non- union matters, the Federal Government sets policies, rules, etc. at the national level. Local authorities have little power. There are no regional or local government policies except for the observance of local customs. · Tanzania's political system is based on the British parliamentary system. Its basic legal framework is that of English common law. · Judicial review of legislative acts is limited to matters of interpretation. · Tanzania has not accepted compulsory International Court of Justice jurisdiction. Tanzania has a five-level judiciary combining the jurisdictions of tribal, Islamic, and British common law. Christians are governed by customary or statutory law in both civil and criminal matters. Muslims may apply either customary law or Islamic law in civil matters. Appeal is from the primary courts through the district courts, resident magistrate courts, to the high courts, and Court of Appeals. Judges are appointed by the Chief Justice, except those for the Court of Appeals and the High Court who are appointed by the president. Advocates defend clients in all courts, except in primary courts. There is no trial by jury. The law also provides for commercial courts, land tribunals, housing tribunals, and military tribunals. However, military tribunals have not been used in the country since its independence. Military courts do not try civilians, and there are no security courts. Defendants in civil and military courts may appeal decisions to the High Court and Court of Appeal. In refugee camps, Burundian mediation councils called abashingatahe, comprised of male refugee elders, often handle domestic abuse cases of Burundian refugees even though the law does not allow these councils to hear criminal matters. Zanzibar's court system generally parallels that of the mainland but retains Islamic courts to adjudicate Muslim family cases such as divorce, child custody, and inheritance. Islamic courts only adjudicate cases involving Muslims. Cases concerning Zanzibar constitutional issues are heard only in Zanzibar's courts. All other cases may be appealed to the national Court of Appeal.57 D.6.2 Laws and Regulations Specific to the Power Sector The main legislation and regulation relative to electricity sector management and development in Tanzania consists of the Electricity Ordinance of 1957 - CAP58 131. 57 Text taken from Jurist Legal News and Research, at http://jurist.law.pitt.edu/world/tanzania.htm#Courts 58 "CAP": Law enacted during Colonial Period, i.e. before 1961. A Law enacted since then is an "Act". SSEA III - Final Report D-27 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS It covers: · Setting of electricity tariffs; · The obligation to supply electricity to outlying areas; · The delivery of subsidies to vulnerable and low income groups; · Expropriation; and · The exportation of Electricity. Imports are covered by specific contracts with Uganda and Zambia. Following the adoption of the National Energy Policy, new framework legislation for the electricity sector will replace the Electricity Ordinance of 1931. Indeed, the National Energy Policy addresses many of these issues, for example: · Art. 2.1 (d) Rural Electrification: "Electricity needs to be made available for economic activities in rural areas, rural townships and commercial centres. Rural electrification is, therefore, a case of long-term national interest and a prerequisite for a balanced socio-economic growth for all in Tanzania." The National Energy Policy is examined under Issues and Concerns in the next section. D.6.3 The structure of industry and the regulatory role over the power sector TANESCO is the sole vertically integrated electricity supplier in Tanzania. The following summarizes the legal framework of the company. · It is incorporated under Company Ordinance-CAP 212; · It has the attributes of a private company; · Company Ordinance-CAP 212 sets out TANESCO's obligations with regard to financial and environmental reporting; and · Since 1931, the Government has been its single shareholder. The generation segment is opened to independent production and there are presently three independent power producers (IPPs) that also supply power to Tanesco: a 100 MW diesel plant by Independent Power Tanzania Ltd., and two small plants of Kiwira Coal Mine and Tanganyika Wattle Company; both supply bulk power of about 4 MW. IPP capacity will increase when the 112 MW Ubungo diesel turbines are converted into gas to electricity generation and privatised in year 2004. Tanzania also imports electricity through cross- border interconnections of about 8 MW and 5 MW from Uganda and Zambia, respectively. The Ministry of Energy and Minerals is the institution responsible for performing the regulatory powers over the power sector, under Government Notice No. 478, pub. 23/11/62 (Cf. s. 10, which refers to the Electricity Ordinance). An Energy and Water Utilities Regulatory Authority Act (Act No. 11) was adopted in June 2001, but is not yet in force. SSEA III - Final Report D-28 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS D.6.4 Attracting Foreign Investment and Facilitating Financing The Tanzania Investment Act, 1997 (No. 26 of 1997) covers investment activities in Tanzania and provides for favourable conditions for investors. It also provides, among others, clear definitions for local investor, foreign investor and foreign capital.59 Under the Act60, the Tanzania Investment Centre (TIC) will also grant all bona-fide investors Certificates of Incentives. These Certificates give investors several fiscal benefits as well as extensive guarantees that cover ownership of properties, dispensation of assets and repatriation of income and others. They also carry automatic recognition by the Government that the investor is bona-fide and facilitates getting assistance from Government ministries.61 For its part, the Tanzania National Energy Policy addresses this issue from a strategic perspective. It proposes to promote private initiatives at all appropriate levels and, in particular, to make local and foreign investors aware of the potentials within the energy sector.62 Also, recognizing that the energy sector represents a substantial part of the national economy, it proposes that the Government should balance between the use of the energy sector for revenue generation and the need for affordable energy by limiting the impact of high taxes, levies and other duties on energy production costs. It also proposes that the state should apply transparent fiscal (taxes, duties, levies) and non-fiscal (fees, subsidies, concessional credits, guarantees) measures to direct market forces and, when necessary, correct market failures.63 There are no restrictions on repatriation of profits, earnings, proceeds of sale, etc., which can be transferred through any authorised bank in freely convertible currency. 64 Investments in Tanzania are guaranteed against nationalisation and expropriation. Tanzania is a member and signatory of several international agreements for protecting investments. Any dispute arising between the Government and investors are settled amicably through negotiations or may be submitted for arbitration before appropriate international organizations under the multilateral, regional bi-lateral treaties Tanzania is part to.65 59Cf. s. 1 - Interpretation 60Part III, Section 17 (1-8) 61See Laws and Regulations Governing Investments in Tanzania at http://www.tic.co.tz (Tanzania Investment Center) 62Policy Statement 58 63S. 2.2 Strategies (c) and (h) 64See Laws and Regulations Governing Investments in Tanzania at http://www.tic.co.tz (Tanzania Investment Center). 65From Laws and Regulations Governing Investments in Tanzania at http://www.tic.co.tz (Tanzania Investment Center) SSEA III - Final Report D-29 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS D.6.5 Issues and Concerns I - Does Tanzania have the means for the establishment of a data collecting and processing system with regard to its own energy sector and that of neighbouring countries in promoting regional cooperation? The question of A data collecting and processing system is addressed in both the National Energy Policy and the National Water Policy. · National Energy Policy ­ February 2003: - 3.1.7 Information Technology Sector - Policy Statement 18: "Promote and enhance use of modern information technology for planning, assessments, policy analysis, database networks and managerial services in the energy sector"; and - 5.3 Energy Information system ­ Policy Statement 53: "Establish and strengthen a proper information and communication system in the energy sector and mobilise human resources to undertake sensitisation, advocacy and dissemination of information to stakeholders". · National Water Policy - July 2002: - 4.5 Data and Information Objective: "To have correct and timely data and information for design, construction and operation of different projects." II ­ Is Tanzania preparing and updating inventories, assessments and master plans relative to each energy sub-sector, taking into account the evolution of the situation? Except for 3.1.7 Information Technology Sector - Policy Statement 18, quoted above, there are no references to this issue regarding the Electricity Sector in the National Energy Policy. The National Water Policy - July 2002, states that: · 4.4.1 Water Resources Assessment: "Objective: To have appropriate and sustainable procedures for management and preparation of water use plans. Water resource assessment, of both surface water and groundwater, quantitatively and qualitatively, is a very fundamental element of the water resources planning process. Generally, effective planning cannot proceed without a thorough assessment of the water resources available. The assessment refers to all sector wide basin and national level comprehensive collection and assembly of information." It also specifies in the same section: "In order to have appropriate basis for sustainable planning and development of water resources the following will be done: (i) Water resources assessment will be done on the basis of sound scientific and technical information and understanding. SSEA III - Final Report D-30 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS (ii) The status of surface and groundwater resources in terms of quantity and quality and its use will be defined regularly on the basis of river basin and in conjunction with aquifer boundaries; and the information made easily accessible to users, stakeholders and decision makers." III - Is Tanzania intending to produce or producing transparent energy pricing policies that take into account its economic realities and the development and growth characteristics in each sub-sector? The National Energy Policy ­ February 2003, addresses this issue explicitly as follows: · 2.2 Strategies: (h) Financial and Fiscal Implications " ....The cost of energy represents a significant part of the total cost structure of companies. Consequently, it affects the competitiveness of products in domestic as well as export markets. Cost effectiveness in the production and supply of energy may be achieved through continued opening up and liberalisation of energy markets and further introduction of competition at all levels of the sector. The elimination of cross-subsidisation from large energy consumers to households and other smaller consumers will go a long way towards improving product competitiveness at the market place"; and · 3.2 Energy Supply 3.2.1 Electricity "....In the new emerging energy market, prices have to be monitored, and predictable and transparent mechanisms established for necessary adjustments." IV ­ What are the governmental policies on taxation and subsidies related to different forms of energy (see also point VI, below)? The National Energy Policy ­ February 2003, addresses this issue in the following sections: · 2.2 Strategies: (c) National Interest versus Market Forces: "The reliance on market forces in order to achieve the national development objectives of economic growth and poverty reduction is not intended to hinder the role of the state to intervene when and where market forces fail to deliver desired results. Keeping its role as facilitator of an enabling environment for the market, the state shall regulate or deregulate the market in order to enhance the benefits of development for the economically weaker communities and groups. The state needs to unconditionally protect and promote the interests of society as a whole. Thus, the state will apply transparent fiscal (taxes, duties, levies) and non-fiscal (fees, subsidies, concessional credits, guarantees) measures to direct market forces and, when necessary, correct market failures."; and · 2.2 Strategies: (h) Financial and Fiscal Implications: "The energy sector represents a substantial part of the national economy. The Government shall balance between the use of the energy sector for revenue generation and the need for affordable energy by limiting the impact of high taxes, levies and other duties on energy production costs. This balance could include ... the requirement of the sector for subsidies, incentives and other costs, which need to be covered within the sector itself or by the national state budget.... " The issues of reinforcement of duties and levies have not been addressed in these government documents. V ­ Is Tanzania facilitating the process of attracting private and public participants to the energy sector by making possible open access to power markets and water resources so as to attain the set efficiency objectives? SSEA III - Final Report D-31 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS Generally, in Development Vision 2025, the Government states that it intends to spearhead investment in infrastructures and involve the private sector and communities in the initiatives. It also states that it considers government investment in energy, water and telecommunications as essential to stimulate local and foreign investment and to create wealth-generating and employment-generating activities. (4.2 Competence and Competitiveness - ii. Infrastructural development). More specifically, the National Energy Policy ­ February 2003, addresses this issue as follows: · Art. 2.1: - (a) Challenges " there is a need to promote and enhance private investment in electricity generation, transmission and distribution"; - (d) Rural electrification: "Electricity needs to be made available for economic activities in rural areas, rural townships and commercial centres. Rural electrification is, therefore, a case of long-term national interest and a prerequisite for a balanced socio-economic growth for all in Tanzania." · Policy Statements 19 to 27, and in particular: - 19 - Competition to apply for the energy market; - 20 ­ Generation to be fully open to private and public investors; - 21 ­ Open access to the transmission grid; - 24 - Opening for strategic partnerships with technically suitable and financially strong investors; - 26 - Ownership contracts in the electricity distribution system; and - 27 - "Government shall establish a new governance system in the power sector by differentiating the roles for (a) policy making and legislative functions carried out by the Government and the Parliament; (b) the regulatory functions carried out by an independent regulator; and (c) other functions carried out by public and private operators". · Policy Statements 43-48, regarding Rural Energy, address this investment issue in the following way: - 46 ­ "Ensure continued electrification of rural economic centers and make electricity accessible and affordable to low income customers"; and - 47 ­ "Facilitate increased availability of energy services, including grid and non-grid electrification to rural areas". - The National Water Policy, July 2002, addresses the issue of access to water resources through article 3.2, which offers a new approach and rationale for an integrated water resources management. VI ­ Is Tanzania intending to proceed with or already in the process of the reorganization, revision and optimisation of the financial programs required in the SSEA III - Final Report D-32 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS short, middle and long term to satisfy the energy demand necessary to sustain the national economy (see also point IV, above)? The National Energy Policy, February 2003, addresses this issue by recognizing: · "The need to reform the market for energy services and establish an adequate institutional framework that will facilitate investment, expansion of services, efficient pricing mechanisms and other financial incentives" (1.1.1 Revision of the 1992 National Energy Policy); · "(That) the energy sector represents a substantial part of the national economy and that the Government will need to balance between the use of the energy sector for revenue generation and the need for affordable energy by limiting the impact of high taxes, levies and other duties on energy production costs."; · "(That) this balance could include strict cost pricing in markets of major energy products, as well as the requirement of the sector for subsidies, incentives and other costs, which need to be covered within the sector itself or by the national state budget. ..." (Strategies ­(h) Financial and Fiscal Implications). However, no concrete measures or plans to effectively address this issue are discussed. VII ­ What is the legislation governing power trade in Tanzania? Exports are covered by Electricity Ordinance CAP 131, which dates back to 1931. The basic rule set in Article 7 of CAP 131 is that a licensee is forbidden to supply electricity "outside the area of supply" or to export it. This prohibition to export also applies to a person supplied by the licensee. The Government, presumably by decree can, however, authorize such exports by a licensee or by a person supplied by the licensee. Imports are covered through Power Purchase Agreements with Uganda, Zambia and the Southern Africa Power Pool. VIII - Is Tanzania intending to proceed with or in the process of the preparing of appropriate policies to build institutional and human capacity for regional power trade? The National Energy Policy, February 2003, addresses this issue in the following paragraphs: · 2.1 Energy Sector Challenges: (c) Regional interconnection: "Regional and international integration of power systems is essential for Tanzania and its neighboring countries to reach the projected economic growth"; · 3.2 Energy Supply; 3.2.1 Electricity Policy Statement 22: "Regional co-operation and integration shall be given priority in investment to ensure reliable supply, exploiting low cost energy sources for regional trade and balancing the erratic availability of hydro-based power"; · 5.2 Energy Trade and Co-operation Policy Statement 52: "Facilitate international collaboration in research, exchange of data, information and documentation"; SSEA III - Final Report D-33 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS · 5.7.3 Research & Development ­ Policy Statement 62: "Promote and co-operate regionally and internationally on research and development of energy forms and of related advanced and innovative environmentally sound technologies in the energy sector". The National Water Policy, July 2002, addresses the issue under the following headings: · 2.6 Energy ­ The need for agreements among riparian countries for the development of hydropower in River Mara and River Kagera; · 2.12 Transboundary Water Resources ­ The need for promotion of regional cooperation and integration with riparian state; · 3.2 Policy Principles regarding the use of transboundary water resource; and · 4.1.2 Prioritization of Water Uses Agreements among the riparian state, and respect for the principle of international obligations on the utilization of transboundary water resource. Finally, the National Environmental Policy, December 1997, addresses this issue under Overall Policy Objective 18 (f), which aims at promoting international cooperation on the environmental agenda and expanding Tanzania's participation and contribution to relevant bi-lateral, sub-regional and regional organizations, treaties, programs, etc. Consequently, Tanzania shows a clear intention to proceed with appropriate policies to build institutional and human capacity for regional power trade. D.7 Uganda D.7.1 The Overall Legal and Regulatory Framework 66 The overall legal and regulatory framework for Uganda can be summarized as follows: · Uganda is a Republic; · It has a unicameral National Assembly (303 members - 214 directly elected by popular vote, 81 nominated by legally established special interest groups [women 56, army 10, disabled 5, youth 5, labor 5], 8 ex officio members; members serve five- year terms); · Elections were last held 26 June 2001. Next are to be held May or June 2006; Election campaigning by party was not permitted; · There are 56 districts and the Central Government sets policies and rules; · In 1995, the government restored the legal system to one based on English common law and customary law; · The Supreme Court can carry out judicial review of legislative acts; · Uganda accepts compulsory ICJ jurisdiction, with reservations. 66Information taken from the World Fact Book at http://www.cia.gov/cia/publications/factbook/index.html SSEA III - Final Report D-34 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS The highest court in Uganda is the Supreme Court, followed by (in descending order) the Court of Appeal (which also functions as the Constitutional Court for cases of first instance involving constitutional issues), the High Court, the Chief Magistrate's Court, and local council (LC) level 3 (sub-county) courts, LC level 2 (parish) courts, and LC level 1 (village) courts. A minimum of six justices may sit on the Supreme Court and the Court of Appeal or Constitutional Court. In addition there are a few specialized courts that deal with industrial and other matters. There is also an Industrial Court (IC), which arbitrates labor disputes, structurally is parallel to the chief magistrate's court. The Constitution provides for an independent judiciary; however, the President has extensive legal powers that influence the exercise of this independence. The President nominates, for the approval of Parliament, members of the Judicial Service Commission, which makes recommendations on appointments to the High Court, the Court of Appeal, and the Supreme Court. D.7.2 Laws and Regulations Specific to the Power Sector The main legislation and regulation related to electricity sector management and development in Uganda consist of the following: · The Energy Policy for Uganda, September 2002; · The Electricity Act, 1999; · Rural Electrification Strategy and Plan, covering the period 2001 to 2010. Imports and exports of electricity are subject to licenses under section 61 of the Electricity Act, 1999. D.7.3 The Structure of the Power Sector Until 1999, the Uganda Electricity Board (UEB), the national utility company, enjoyed a monopoly on the power sub-sector, which covers electricity generation, transmission and distribution including rural electrification. This monopoly was terminated through the enactment of the Electricity Act, 1999, which created the Electricity Regulatory Authority (ERA) and liberalized the sector. Consequent to this Electricity Act, UEB was unbundled to create different business entities for generation, transmission and distribution known as Uganda Electricity Generation Company Limited (UEGCL), Uganda Electricity Transmission Company Limited (UETCL) and Uganda Electricity Distribution Company Limited (UEDCL) respectively. In November 2002, the UEGCL was privatized through a long-term concession of 20 years with M/s ESKOM Enterprises (U) Ltd. The concessionaire took over the operations of the power generation business at the Kiira and Nalubaale power stations with effect from 1st April 2003. For its part, UETCL continues to own and operate the transmission infrastructure above 33KV. It is responsible for buying power in bulk from power generators and sells it to the distribution company. UETCL is also responsible for power exports and imports in Uganda as well as system coordination and dispatching generation installations. It remains Government owned but is operated as an independent and profit making business unit. SSEA III - Final Report D-35 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS Finally, UEDCL owns and operates the distribution infrastructure operating at 33KV and below. It is responsible for the retail of electricity including metering and billing of consumers. UEDCL buys bulk power from UETCL in accordance with terms set in a Power Purchase Agreement. Since March 2005, it has been operated under a 20 Years concession agreement with the Government of Uganda. Also of interest, UEB, was left in place as a statutory corporation ("UEB (SC)") to manage the long term debt not yet restructured, operate the isolated diesel systems and sell off the Corporation's residential houses. UEB (SC) together with the Government of Uganda, is also responsible for the payment of pensions and terminal benefits due to former UEB employees. UEB (SC) also coordinates ongoing projects and at their completion, the assets will be transferred to the successor companies.67 The Ministry of Energy and Mineral Development (MEMD), is responsible for energy policy formulation, and oversight of the operations in the electric power sub-sector. The Electricity Regulatory Authority (ERA) exerts regulatory powers over the power sector, under the mandate assigned by the Electricity Act (1999). ERA has been given adequate powers to enforced environmental regulations and manage environmental and social impacts, under the Electricity Act, 1999. In its Strategic Plan 2003-2013, the ERA has also proposed a financing and Resource Plan that should ensure it is able to fulfill its mandate. D.7.4 Attracting Foreign Investment and Facilitating Financing Through the Investment Code, Statute No. 1 of 1991, the government of Uganda provides the necessary legal policy and physical infrastructure for private investment to flourish. The government is further privatising parastatals and revising regulations to promote foreign investments. The law permits 100 per cent ownership of investments and, with very few exceptions, investors can invest in any economic activity. 68 This policy also benefits foreign investments duly licensed under the Investment Code. The Constitution of the Republic of Uganda 1995 recognises and gives protection to private property. In particular, under Article 26 (1) it is provided that every person has a right to own property either individually or in association with others. Under the Investment Code, a licensed business enterprise, or an interest or right over any property or undertaking forming part of that enterprise can not be compulsorily taken possession of or acquired, except in accordance with the provisions of the Constitution of Uganda, and that if it is compulsorily taken possession of or acquired, compensation in respect of the fair market value of the enterprise will be paid within a period not exceeding twelve months from the date of taking of possession or acquisition. Such compensation will be freely transferable out of Uganda and will not be subject to exchange control restrictions.69 According to a recent (2005) report from the Multilateral Investment Guarantee Agency (MIGA) 70 , Uganda has received high scores in investor surveys both for investment 67Source: UEDCL site, at http://www.uedcl.co.ug/newframework.html 68See also Investing in Uganda at http://www.wakili.co.ug/new/investment.html 69Cf. Investing in Uganda at http://www.wakili.co.ug/new/investment.html 70Competing for FDI : Inside the operations of four national investment promotion agencies, Vol. 1 of 1 ­ (WB Report 31916), in particular at p.51 SSEA III - Final Report D-36 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS protection and for favorable policies toward repatriation of profits. It also has many double taxation agreements with Western Countries and has adopted liberal foreign exchange policies. D.7.5 Issues and Concerns Uganda generally appears to possess a modern, up-to-date, legal frameworks and a fully functional Regulatory authority is already in place. Indeed, it has a recent Electricity Act (1999), which is presently in a process of revision, a recent National Environment Statute (1995) and a recent Water Statute (1995), as well as the associated regulations. Also Uganda's Electricity Regulatory Authority (ERA), although in need of more resources, looks like it is developing both in human and material resources and, presumably, will be more and more able to play its assigned role in the energy sector. Consequently, it is felt that the existing institutional, legal and regulatory framework will not hinder the implementation of power projects and will address many of the important issues and concerns identified at the outset of the study. Hereinafter, these issues and concerns are examined one by one with a view to identify areas of possible improvement where need be. I - Does Uganda have the means for the establishment of a data collecting and processing system with regard to its own energy sector and that of neighbouring countries in promoting regional cooperation? One of the short term objectives set by ERA in its Strategic Plan 2003-2013 is that of developing an information base on the Uganda electric supply industry performance and developments and establish the required data base. For his part, the Minister of Energy and Mineral Development is charged with maintaining a national rural electrification database to assist in the monitoring of progress and establishment of the targets of rural electrification. No other information was available on the subject. Consequently, it would be desirable for the Government of Uganda to consider the establishment of a central data collecting and processing system with regard to its own energy sector and that of neighbouring countries, that could help in promoting regional cooperation. This database could be under the responsibility of the ERA, but it would appear more desirable for the Minister of Energy and Mineral Development to be entrusted with this mandate since strategic planning and overview of the sector are under his responsibility. II ­ Is Uganda preparing and updating inventories, assessments and master plans related to each energy sub-sector, taking into account the evolution of the situation? Within the East African sub-region, Uganda is spearheading the New Partnership for Africa's Development (NEPAD)71 efforts, which it feels offers the greatest opportunity for integrating 71NEPAD arises from a mandate given by the Organisation of African Unity (OAU) to develop an integrated socio-economic development framework for Africa. It is designed to address the current challenges facing the African continent. SSEA III - Final Report D-37 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS Africa's energy systems (e.g., planning, interconnected grids and cross-border oil pipelines) to enhance energy trade, optimize the development and use of resources and provide cost- effective energy services. A key undertaking so far, in line with the NEPAD initiative, is the development of the East African Energy Master Plan. The plan will address energy trade, exchange of information72. III - Is Uganda intending to produce or producing transparent energy pricing policies that take into account its economic realities and the development and growth characteristics in each sub-sector? This question was addressed explicitly in the Uganda Power Sector Restructuring and Privatization, New Strategy Plan & Implementation Plan, June 1999, (s. 5.1 "...tariff will be developed to encourage sales of energy and capacity from existing and new plant to the Transmission Company"; s. 5.2 - Bulk Purchase and Supply: "formulate a fair and cost reflective bulk supply tariff for sales to distributors"; s. 5.2 - Third Party Access: "A cost reflective and non-discriminative tariff will be developed to encourage auto generators and others to sell excess energy to the Transmission Company." In keeping with these orientations, the ERA was given the mandate to "establish a tariff structure and to investigate tariff charges, whether or not a specific complaint has been made for a tariff adjustment", under Section 11 (f) of the Electricity Act, 1999. IV ­ What are the government policies as to taxation and subsidies relative to different forms of energy (see also point VI below)? Up until a few years ago, the Uganda Electricity Board (UEB) had consistently posted operating losses, despite large Government subsidies. Consequently, one of the main objectives of the New Strategy Plan & Implementation Plan, June 1999, which was the product of an exercise of extensive stakeholder consultation, was to make the power sector financially viable and able to perform without subsidies from the Government Budget. For its part, the ERA has identified electricity pricing reform, and the consequent establishment of a realistic pricing regime, as one of its main objectives in order to facilitate sustainability and increased efficiency. V ­ Is Uganda facilitating the process of attracting private and public participants in the energy sector by facilitating open access to power markets and water resources so as to attain the set efficiency objectives? The New Strategy Plan & Implementation Plan, June 1999, placed particular emphasis on the role of competition in promoting efficiency within the power sector and on private sector participation as being a key driver to enhance the power sector's performance. In particular, NEPAD aims to accelerate regional and continental integration and favour the build up of competitiveness of African countries and the continent. One of its main priorities is policy reforms and increased investment in priority sectors such as building and improving energy infrastructure. More information can be found on the NEPAD web site, at http://www.nepad.org/2005/files/home.php 72 Cf. The Energy Policy for Uganda, March 2002 SSEA III - Final Report D-38 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS Since the approval of this Plan, the Government of Uganda has been taking steps to implement these objectives. In particular, as noted above under S. 3.2.2.5 - Supply of Electricity, the Government of Uganda has unbundled the Uganda Electricity Board (UEB) and brought in private sector capital and skills into the generation and distribution businesses through long-term concessions. Under the market structure resulting from these reforms the generation concessionaire and IPPs now sells power under long-term Power Purchase Agreements to the publicly owned, but corporately and operationally independent, transmission company (UETCL), which owns and operates the transmission grid. UETCL in turn, sells the power to Uganda Electricity Distribution Company Ltd. (UEDCL) for final sale to end-users. VI ­ Is Uganda intending to proceed with or in the process of the reorganization, revision and optimization of the financial programs required in the short, middle and long term to satisfy the energy demand necessary to sustain the national economy (see also point IV above)? The only such Program alluded to in the documents available and consulted was the rural Electrification Programme, of which the Minister must periodically evaluate the impact (Electricity Act, s. 64(3)), and about which the ERA proposes to collaborate with the Government in streamlining the framework for the development of `smart' subsidies. VII ­ What is the legislation governing power trade in Uganda? Uganda closely regulates the export and import of electricity. No person can import or export electricity without an export or import licence, as the case may be, granted by the Electricity Regulatory Authority (ERA).73 Also, the wording of the Electricity Act74 implies that such licences must be requested for each individual import or export contract, or agreement, which considerably complicates potential transactions, especially if a trading market were to develop. However, Uganda's Energy Policy states, at page 11 that Uganda intends to contribute to the NePAD initiative by supporting faster development of Uganda's hydropower resources through private sector investments, development of interconnections, cross-border infrastructure to facilitate energy trade and sharing of information on petroleum resources and exploration and the development and use of new renewable energy resources, which would indicate an openness to trade in electricity. Appropriate changes to Uganda's legislation that would relax the existing regulatory control on importation and exportation of electricity along the lines suggested above would be helpful in meeting these goals. For instance, in Canada, since 1994, the National Energy Board (NEB) has been issuing so called "umbrella permits" under which utilities in Canada can export up to a given amount of power and energy without having to obtain further authorization, thus eliminating the need to petition the NEB for each and every export contract. There is no regulation of imports. These "umbrella permits" greatly facilitate power trade, especially in the context of spot market activities. 73 Electricity Act, Art. 61 (1) "No person shall import or export electricity without an export or import licence as the case may be granted by the Authority". 74 Art. 61. (2) "An agreement for the import or export of electricity shall accompany an application for a licence under subsection (1)". SSEA III - Final Report D-39 017334-001-00 APPENDIX D - SYNOPSES OF ENERGY POLICIES AND RELATED LEGAL AND ADMINISTRATIVE FRAMEWORKS VIII - Is Uganda intending to proceed with or in the process of preparing appropriate policies to build institutional and human capacity for regional power trade? Uganda closely regulates the export and import of electricity. No person can import or export electricity without an export or import licence, as the case may be, granted by the Electricity Regulatory Authority (ERA).75 Also, the wording of the Electricity Act76 implies that such licences must be requested for each individual import or export contract, or agreement, which considerably complicates potential transactions, especially if a trading market were to develop. However, Uganda's Energy Policy states, at page 11 that Uganda intends to contribute to the NePAD initiative by supporting faster development of Uganda's hydropower resources through private sector investments, development of interconnections, cross-border infrastructure to facilitate energy trade and sharing of information on petroleum resources and exploration and the development and use of new renewable energy resources, which would indicate an openness to trade in electricity. Appropriate changes to Uganda's legislation that would relax the existing regulatory control on importation and exportation of electricity along the lines suggested above would be helpful in meeting these goals. For instance, in Canada, since 1994, the National Energy Board (NEB) has been issuing so called "umbrella permits" under which utilities in Canada can export up to a given amount of power and energy without having to obtain further authorization, thus eliminating the need to petition the NEB for each and every export contract. There is no regulation of imports. These "umbrella permits" greatly facilitate power trade, especially in the context of spot market activities. As noted above, under II, Uganda is spearheading NEPAD's initiative in the development of the East African Energy Master Plan. The plan will address energy trade, exchange of information. 75 Electricity Act, Art. 61 (1) "No person shall import or export electricity without an export or import licence as the case may be granted by the Authority". 76 Art. 61. (2) "An agreement for the import or export of electricity shall accompany an application for a licence under subsection (1)". SSEA III - Final Report D-40 017334-001-00 APPENDIX E LOAD FORECAST SUPPORT SSEA III - Final Report 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT TABLE OF CONTENTS PAGE E LOAD FORECAST SUPPORT E-1 E.1 Introduction E-1 E.2 Current Conditions in the Power Sector E-1 E.2.1 Current Conditions in Burundi, Rwanda, and Eastern DRC E-1 E.2.2 Current Conditions in Kenya, Tanzania, and Uganda E-4 E.3 Methodological Approach E-5 E.3.1 Review of Demand Forecast Methods E-5 E.3.2 Method Selected E-6 E.4 Key Assumptions and Data Inputs for Demand Forecast E-8 E.4.1 Selection of Base Year and Period of Demand Forecast E-8 E.4.2 System Losses E-9 E.4.3 Rural Electrification E-9 E.4.4 Suppressed Demand E-10 E.4.5 Electricity Tariffs E-11 E.4.6 Prices of Competing Energy Sources E-11 E.4.7 Ability and Willingness to Pay E-12 E.4.8 Load Factors E-12 E.4.9 Allowance for System Reserve E-13 E.5 Review of the Reference Load Forecasts E-14 E.5.1 Review of Reference Documents and Selection of Reference Forecasts E-14 E.5.2 Burundi E-15 E.5.3 East Democratic Republic of Congo (DRC) E-18 E.5.4 Kenya E-26 E.5.5 Rwanda E-30 E.5.6 Tanzania E-33 E.5.7 Uganda E-37 E.5.8 Power Needed to Transform the Region E-42 E.6 Supporting Data and Details of Forecast Calculations E-46 LIST OF FIGURES Figure D-1 Forecast Process E-8 Figure D-2 Burundi's Historical Demand Characteristics3 E-16 Figure D-3 Burundi Demand Forecast for the 2002-2020 Period E-18 Figure D-4 The Democratic Republic of Congo ­ Provincial Map Showing the Region under Analysis E-20 Figure D-5 Updated East DRC Demand Forecast for the 2002-2020 Period E-26 Figure D-6 Historical GDP Growth Rates and Electricity Sales for Kenya 1997-2003 E-27 Figure D-7 Kenya Power Needs Assessment for the 2002-2020 Period E-29 Figure D-8 Rwanda's Historical Demand Characteristics12 E-30 Figure D-9 Rwanda Demand Forecast for the 2002-2020 Period E-32 Figure D-10 Tanzania's Gross Domestic Product (billions of TShs at 1992 prices)17 E-33 Figure D-11 Tanzania Demand Forecast for the 2002-2020 period E-36 Figure D-12 Historical Generation Data in Uganda, 1957-2001 E-37 Figure D-13 Uganda Demand Forecast for the 2002-2020 Period E-41 Figure D14 Impact of the Lake Victoria Vision on the E-46 SSEA III - Final Report E-i 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT LIST OF TABLES Table E-1 Existing Generation Capacity in Burundi E-2 Table E-2 Existing Generation Capacity in Rwanda E-2 Table E-3 Existing Generation Capacity in Eastern DRC E-3 Table E-4 Existing Generation Capacity in Kenya E-4 Table E-5 Existing Generation Capacity in Tanzania E-4 Table E-6 Existing Generation Capacity in Uganda E-5 Table E-7 Basic Assumptions for the Burundi Load Forecast E-17 Table E-8 Burundi Forecast Summary E-17 Table E-9 Basic Assumptions for the East-DRC Load Forecast E-23 Table E-10 East DRC Forecast Summary E-25 Table E-11 Basic Assumptions for the Kenya Load Forecast E-28 Table E-12 Forecast Summary5 E-29 Table E-13 Basic Assumptions for the Rwanda Load Forecast E-31 Table E-14 Rwanda Forecast Summary E-32 Table E-15 Basic Assumptions for the Tanzania Load Forecast E-35 Table E-16 Tanzania Forecast Summary E-35 Table E-17 Basis Assumptions for the Uganda Load Forecast E-39 Table E-18 Uganda Forecast Summary E-40 Table E-19 GNI per Capita for the Forecast Countries E-43 Table E-20 Summary of the Scenario Reflecting the Lake Victoria Vision: the Regional Transformation Forecast E-45 SSEA III - Final Report E-ii 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E LOAD FORECAST SUPPORT E.1 Introduction The Nile Equatorial Lakes (NEL) region is characterized by constrained isolated power systems where demand exceeds present generation capacity. Access to commercial energy sources is limited. In 20001, it was estimated that only 8% of the energy needs in Tanzania were fulfilled by electricity ­ the rest were met by biofuel (wood fuel) and coal. This situation is common among all countries included in the study area. Improving access to electricity constitutes an important issue and forecasting the power needs of the population in the region is then key to promoting steady growth and improving the economy. This appendix presents the regional power needs forecast in Kenya, Uganda, Burundi, Rwanda, Tanzania and Eastern DRC. The future demand for generation capacity is determined by the following factors: 1) The underlying growth in energy requirements in areas already connected; due to economic growth, demographic developments, etc.; 2) Removal of constraints on demand (e.g.: load shedding etc.); 3) Reduction in technical losses; 4) Increase in number of connections (electrification) beyond the increase implied from historic trend included in 1); 5) Decommissioning of existing plants; and 6) The level of reserve margin desired by the utility or the Government in order to ensure a reliable supply. The appendix begins with a brief description of the methodological approach used to derive the underlying growth in demand. Inputs and assumptions are then discussed, and a detailed review of the reference forecasts is carried out so that the most appropriate candidate forecasts can be selected based on the chosen forecasting method and the power sector issues that were put forward. Finally, the electricity demand forecasts for each of the six countries and for the entire region are presented. E.2 Current Conditions in the Power Sector E.2.1 Current Conditions in Burundi, Rwanda, and Eastern DRC Most of the electricity produced in Burundi and Rwanda is generated through hydroelectricity. Hence, the highly variable climate in central and eastern Africa exposes the power systems of the two countries to great fluctuation in hydropower generation. This has resulted in power rationing of various degrees being introduced in recent years. Even in wet years, there is insufficient reliable energy for supplying new customers and rural electrification. Industrialization processes and, hence, their economic development are severely constrained by the lack of power. The installed capacity in Burundi and Rwanda totals 37 MW and 41 MW respectively. These figures are shown in Table E-1 and Table E-2. 1Estimation by US/DOE/EIA. SSEA III - Final Report E-1 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT In Eastern DRC, the Société Nationale d'Électricité, the government owned utility, owns three hydroelectric and six thermal stations for a total nine generating installations, all characterized by extreme wear, lack of maintenance and the need for complete rehabilitation. Although the total installed utility capacity is in the order of 110 MW, only about 36 MW of hydropower are actually available. Hydro stations exhibit a 45% deficit in production, while thermal stations suffer from shortages of fuel and plundering. As a result, of all thermal stations, only the Kisangani group (4 MW) is currently operational2. The current supply situation is shown in Table E-3. Only a very small proportion of the population (2% to 6%) of these three areas have access to electricity: between 2% and 3% for Burundi and Rwanda and 6% for Eastern DRC. However, the percentage for DRC is misleading since the electricity to which the population have access is very unreliable. Table E-1 - Existing Generation Capacity in Burundi Capacity Firm Plant name Type (MW) Generation Comments (GWh) Rwegura Hydro 18 35.7 Mugere Hydro 8 19 Ruvyironza Hydro 1.3 10.5 Gikonge Hydro 0.9 2.1 Nyemanga Hydro 1.4 12.2 Isolated load Kayenzi Hydro 0.8 1.3 Isolated load Mini-Hydros Hydro 1.4 3.1 Isolated load Bujumbura Diesel 5.5 -- Backup Total Domestic 37.2 83.9 Import facilities Rusizi I Hydro 3.5 20 Rusizi II Hydro 13.8 67 Table E-2 - Existing Generation Capacity in Rwanda Capacity Firm Plant name Type (MW) Generation Comments (GWh) Mukungwa Hydro 12.5 48 Ntaruka Hydro 11.2 22 Gihira Hydro 1.8 9.8 Gisenyi Hydro 1.2 8.4 Gatsata Diesel 2.0 15 Recently refurbished 2Plan directeur national de l'électricité à l'horizon 2015, SNEL, June 2003. SSEA III - Final Report E-2 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Firm Plant name Type Capacity (MW) Generation Comments (GWh) Kigali Diesel 12.2 85 Total Domestic 40.9 188.2 Import Facilities Rusizi I Hydro 3.5 20 Rusizi II Hydro 13.8 67 Table E-3 - Existing Generation Capacity in Eastern DRC Capacity Firm Plant name Type (MW) Generation Comments (GWh) Tshopo I Hydro 19 164 Ruzizi I Hydro 28.2 247 Only 36.3 MW available due to lack of maintenance Kyimbi Hydro 17.2 150 Ruzizi II Hydro 29.2 250 Owned by SINELEC Tshopo Thermal 12.8 38.4 Only 4.1 MW operational Kasongo Thermal 0.4 1.1 Unused ­ no fuel Kindu Thermal 1.7 5.0 Unused ­ no fuel Kabalo Thermal 0.4 1.1 Unused ­ no fuel Kongolo Thermal 0.2 0.6 Unused ­ no fuel Budana Hydro 10.3 90 Private- needs rehabilitation Soleniama I Hydro 1.1 10 Private ­ out of service Soleniama II Hydro 1.1 10 Private Belia Hydro 2.2 19 Private Kailo Hydro 2.2 19 Private Kampene Hydro 1.6 14 Private Lutshuruku I-II Hydro 6.9 60 Private Moga Hydro 1.3 11 Private Kabule Hydro 4.0 35 Private Kilubi Hydro 9.0 70 Private Piana-Mwanga Hydro 29.0 254 Private ­ needs rehabilitation Other Hydro 6.8 59 Private Aketi Thermal 0.4 1.4 SNCZ-cogeneration Isiro Thermal 1.5 4.4 SNCZ-cogeneration Mungbere Thermal 0.1 0.3 SNCZ-cogeneration Ubungu Thermal 0.2 0.7 SNCZ-cogeneration Dilolo Thermal 0.2 0.5 Private-cogeneration Gecamines Thermal 18 54 Private-cogeneration Kamina Thermal 0.1 0.3 Private-cogeneration Kaniama Thermal 0.1 0.4 Private-cogeneration Sakania Thermal 0.9 2.5 Private-cogeneration SSEA III - Final Report E-3 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.2.2 Current Conditions in Kenya, Tanzania, and Uganda Kenya benefits from both hydro and thermal generating stations, for a total effective capacity of 1,121 MW, mainly owned by KenGen, the government owned utility. Construction work on the Sondu-Miriu 60 MW hydropower project was delayed until 2007. Other developments include the 12 MW Olkaria III geothermal project, which is expected to reach its full commercial operation in the near future. The current supply situation is shown in Table E-4. Again, only a small proportion of the population of these countries have access to electricity about 3% for Uganda, 7% for Tanzania and 9% for Kenya. Table E-4 - Existing Generation Capacity in Kenya Capacity Firm Plant name Type (MW) Generation Comments (GWh) Tana Hydro 12 50 Wanji Hydro 7 30 Kamburu Hydro 84 336 Gitaru Hydro 215 860 Kindaruma Hydro 40 160 Masinga Hydro 40 160 Turkwel Hydro 106 424 Kiambere Hydro 144 576 Other Hydro 5 22 Kipevu Steam 26 182 Kipevu Diesel 70 491 Kipevu GT 60 420 Nairobi South GT 10 70 Iberafrica Diesel 57 396 Westmount GT 43 301 Tsavo Diesel 74 519 Olkaria I GEO 45 315 Olkaria II GEO 70 491 Olkaria III GEO 12 84 Wind Wind 0 2 Sondu-Miriu Hydro 60 240 Under construction The Tanzanian system is comprised of both hydro and thermal generation units. The hydro capacity is comprised of six TANESCO hydro plants totalling an effective capacity of 555 MW. The installed capacity of thermal generating sets within the Tanzania grid totals 230 MW, for a total capacity of 785 MW. The current supply situation is shown in Table E-5. Table E-5 - Existing Generation Capacity in Tanzania Capacity Firm Plant name Type (MW) Generation Comments (GWh) Mtera Hydro 80 420 Kidatu Hydro 204 1100 Hale Hydro 17 300 3 plants Kihansi Hydro 180 540 SSEA III - Final Report E-4 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Firm Plant name Type Capacity (MW) Generation Comments (GWh) Pangani Falls Hydro 66 580 Nyumba Ya Mungu Hydro 8 70 Ubongo Thermal 40 280 Ubongo II Thermal 80 561 Diesels II Thermal 0 0 unused Tegeta Thermal 100 657 Other Thermal 10 26 Total of 4 In Uganda the main part of the energy demand is being met by wood fuel, while only 1% of the total energy demand is actually met by electricity. Electrical energy is supplied mainly by two hydroelectric plants, namely the Nalubaale generating station and the Kiira generating station. The total installed capacity amounts to 327 MW. The current supply situation is shown in Table E-6. Table E-6 - Existing Generation Capacity in Uganda Plant name Type Capacity Firm Generation (MW) (GWh) Comments Owen Falls 1-10 Hydro 180 403 Nalubale Owen Falls 11-13 Hydro 120 535 Kiira Other Hydro 17 0 Kakira Thermal 10 60 Kiira 14-15 Hydro 80 357 Under construction E.3 Methodological Approach E.3.1 Review of Demand Forecast Methods Three methods can be used for forecasting electricity demand: Trend method; End-use; and Econometric method. The trend method is based on the major assumption that historical relationships between energy consumption and time hold into the future. Broadly speaking, the trend method is an extrapolation of past data. This method has its limitations. Moreover, its inability to represent structural changes limits its usefulness for long-term projections. The end-use method is based on taking an inventory of electrical appliances in a customer category and estimating the average consumption of each type of appliance. It depends upon regular customer surveys to obtain the stock of appliances in use as well as the degree of saturation of these appliances (i.e. the number in use as compared to the maximum number judged likely). This approach allows the utility to take into account the ability and willingness to pay of the population not currently served. SSEA III - Final Report E-5 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT The econometric method relates sales to demographic (population ­ both urban and rural, housing by types, etc.) and socioeconomic (Gross Domestic Product and its components, per capita income, electricity tariffs, prices of competing energy sources, etc.) explanatory variables by making use of mathematical models (equations). More precisely, the econometric method is a two-step process. For the forecast of electricity consumption, the first step is to establish the historical relationship between consumption and the other relevant demographic and socioeconomic factors. This relationship would generally be represented by an equation of the form: Sales (t) = + · (demographic indicators, t) + · (economic indicators, t) where: t = Time Sales = Consumption in GWh demographic indicators = Population, housing, etc. economic indicators = GDP (or subset thereof), tariffs, prices of competing sources, etc. and , and are the (estimated) coefficients. The second step involves: Making assumptions that the same relationship between consumption and other variables, such as population (demographic variable) and GDP (economic variable) will hold true in the future; and On the basis of reasonable assumptions as to the evolution in the future of these (independent3) variables, obtain the forecast values of the Sales at a future time t, by substituting the forecast values of the independent variables in the equation. E.3.2 Method Selected The last method, that is the econometric method, was used in most of the reference forecasts analyzed in this study to estimate electric power demand for Rwanda, Burundi, Tanzania, Uganda, Kenya and Eastern DRC; a forecast produced by SNEL, based on a modified trend method, for DRC is modified and used in this study. The econometric method is illustrated in Figure E-1. The forecasting equations are developed by exploring different relationships between historical energy demand, on one hand, and economic and demographic indicators, on the other. Many statistical `tests of fit' can be applied to assess the validity of these equations. The most often-used and simplest one is the closeness to one of the so-called correlation coefficients (R2). R2, a real number between 0 and 1, measures the relationship between the `explained' or dependent variable (in this case, the demand) and the `explaining' or independent variables (e.g., economic and/or demographic indicators). The overriding consideration in assessing the `fit' for a set of variables is that the derived relationship be reasonable and logical. If, for example, the model shows, over the years, that the demand decreases when the GDP and/or the number of households increase, the 3 The term "independent" variable is used to designate an explanatory factor as opposed to "explained" or forecasted factor --in this case, Consumption-- which is also termed as the "dependent" variable. SSEA III - Final Report E-6 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT model clearly does not give a correct representation of the behaviour of the variables in question and must be rejected. Fitting a model is, thus an exercise consisting of trying the variables one by one or trying to fit a combination of them into the model and, then, observing the results. If the use of one set of variables does not produce a model that is strong statistically (i.e. has a high R2) and that is logical, another set of variables should be tried. Advanced statistical or econometric software programs provide routines to select variables that need to be used in a model. These are useful when dealing with a large number of variables that all seem to be good candidates for the model. For the forecasting model on hand, the number of variables to be considered is not unwieldy and, hence, MS-Excel's Analysis ToolPak is used to run the model. An important point to be mentioned is that the forecast model is to be fitted from historical data. Hence, to obtain a forecast value of the demand for, say, 2006, one needs the values of the `explaining' variables (e.g. the GDP and the population) for that given year. This is where economic and demographic assumptions come into play as they would be needed to determine the values of the explaining variables at time t = 2006. Another essential point about forecasting is that scenarios do not interfere with the `fitting' of the model. Scenarios are used to determine the values of `explaining' variables according to certain sets of hypotheses, and to provide these values for use in the model. Models are fitted on the basis of real (actual) data and not on future scenarios. Finally, the number of years and the reliability of the available historical data are also important as they may determine the limitations of the model. The process of `fitting' and applying model equation to forecast demand from economic activities and demography are illustrated in the diagram below. It should be noted that this approach provides an estimate of the underlying trend in load, which would be a continuation of past relationships between selected variables and government and utility policies. Any significant changes in policies (such as an increased rate of electrification or a new program to significantly reduce losses) will change this trend and must be estimated separately. SSEA III - Final Report E-7 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Figure E-1 - Forecast Process Primary s L A orcteSci Secondary CI mo on R Ec Existing Energy O Tertiary FIT Requirements T MODEL SI H yh ap gro Population meD Primary s T orcteSci Secondary S mo A on C Ec Tertiary E R APPLY Forecast Energy O MODEL Requirements F yh ap gro Population meD E.4 Key Assumptions and Data Inputs for Demand Forecast E.4.1 Selection of Base Year and Period of Demand Forecast A load forecast is usually based on a starting point that is the latest year for which the relevant data for the purpose of load forecast is available and one that can be considered "normal". The year 2002 in each of the countries did not have any occurrences that would provide either an abnormally high or low starting point to the analysis. A population census was conducted in Rwanda in 2002 while an estimate for 2003 is also available from different sources. In Burundi, however, no recent population census is available (the last census was in 1990). ISTEEBU (the National Statistical Institute of Burundi) carried out a major SSEA III - Final Report E-8 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT household survey in 2002, which provided an estimate of the Burundi population for 2002. Demographic data for Kenya, Uganda and Tanzania is also available for 2002 from various sources. In Eastern DRC however, the last census was conducted by the Centre Francais Sur La Population et le Développement in 1992. More recent estimates on demographic data are available only from certain non-governmental and humanitarian organisations. Economic indicators required for the present study are available in various recent load forecast studies conducted by utilities in each country. For electricity data (i.e., sales, production, losses, and peak load), historical values are available for 2002 for Tanzania, Burundi, Rwanda, Uganda and Kenya. However the only figures available for Eastern DRC are dated 2003. Although not all relevant data and figures are available for year 2002, actual population (census) and economic data are available for most countries for that year. It thus seems suitable that the base year for the study should be 2002. Therefore, considering that the DRC data for the year 2002 is not readily available, data used for the year 2002 will be the best estimates based on data from consecutive years. The forecast period is set as 2002- 2020. E.4.2 System Losses Losses, both technical and non-technical, are very high throughout the region. For an analysis for the power needs of the region, the level of commercial losses is not generally relevant as a reduction in these looses is usually accompanied by a commensurate increase in sales (i.e., someone who is caught stealing power will generally become a customer instead of losing the use of the energy). A reduction in technical losses, on the other hand, usually results in a decrease in the energy that needs to be supplied to meet the same customer demand (or more energy available to serve additional load). Assumptions regarding these technical losses and their reduction over time are included in the analysis of each of the areas. E.4.3 Rural Electrification Presently, a very small proportion of the population of the regions, as shown below, has access to electric power supply: Rwanda: 2.4% Burundi: 2.5% Tanzania: 7% Uganda: ~3% Kenya: 9% East DRC: 6% The potential electricity demand in the region, merely from the electrification of the rural areas is enormous; full electrification could increase the load in the region by a factor of 2.3 times the current load. On the other hand, the cost of such electrification would also be very high ­ just the cost of service entries to the houses plus the low tension lines supplying the houses would be substantial. Such electrification programs are usually not economical and are usually implemented to fulfil social objectives. SSEA III - Final Report E-9 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Rural Electrification programs are documented for Uganda, Tanzania, and Kenya, but there are currently no clear targets for rural electrification in Rwanda, Burundi and Eastern DRC, although Rwanda is about to mandate a study of rural electrification. On the other hand, the Steering Committee and the stakeholders, at the meetings held in Dar es Salaam in late September 2004, felt that emphasis would soon be placed on this aspect in government planning for Rwanda and Burundi. As there are no planned rural electrification plans in Rwanda, Burundi and Eastern DRC to base the assumptions on, the Consultant made assumptions for the load forecasting based on rural electrification plans with a reasonable program. The reasonable program falls in between the following two polar cases and takes the third into consideration: A program where there is no rural electrification seems untenable; A program where there is full electrification of all households in the area also seems unreasonable; and A program is needed where the utility can physically manage the annual number of connections implied by the program. This broad framework is part of what defines the assumptions used in the model. The electricity demand is discussed in three scenarios where the electrification rate increases by two times to eight times the current level over the studied period. E.4.4 Suppressed Demand Suppressed demand is the amount of energy demanded by the customers that is not met by the utility. This would be a combination of electricity use foregone by the customer plus the amount of energy generated by the customer from its own sources due to an absence of power from the utility or a poor quality of the power that is available. When there are shortages of power, utilities plan for the orderly shut down of portions of their system until the demand in the portions of the system still supplied is equal to or below the amount of power they can provide. This amount of "load shedding" can be calculated from the records kept by the load dispatch office of the utilities. This measure of load shedding gives an accurate estimate of the amount of energy not supplied to the customer by the utility. It does not, however, take account of the amount of energy produced by the customer to make up for the shortage. In addition, this estimate of load shedding does not give an estimate of the amount of energy produced by a customer because of unacceptable quality of supply. The amount of energy produced and consumed by customers due to poor quality of supply is unknown and assumed in this report to be small relative to the load shedding. All areas of the study region have shortages of installed capacity and are, therefore, not able to satisfy the demand in the region. For instance the government of Rwanda has indicated that there is suppressed demand in the country and the local utility has estimated this amount to be about a 10% shortage of capacity at time of system peak and about a 4% shortage in energy. The Government of Burundi has indicated that there is suppressed demand in the country but has not quantified the amount. The utility in Uganda has indicated that it is not able to meet the peak demand of the country, although it is able to export power during the off-peak periods. The respective suppressed energy estimates are taken into account in the specific assumptions for the load forecast for each area. The suppressed peak demand is taken into account by a reduction in the load factor. SSEA III - Final Report E-10 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT The East DRC forecast on the other hand directly calculates the amount of electricity required to satisfy demand, with the assumption that no load shedding will occur at all. E.4.5 Electricity Tariffs There are two issues on electricity tariffs that are applicable to the load forecast. They are: The impact on consumption of increases and decreases in tariffs; and Tariffs as a barrier to electrification. Conceptually, if there is a significant increase in tariffs, in real terms (i.e. an increase above the inflation rate), to a category of customers, the sales in that category is expected to decrease. This is represented by the negative price elasticity of demand. This factor is estimated as part of the analysis of historic data. To do so, a statistical relationship is estimated between sales and relevant explanatory variables, including the average tariff. If the statistical tests on the relationship obtained shows that the variable of tariffs should be included in the relationship, the coefficient associated with that variable is the estimate of the price elasticity of demand. An issue is identified in using the results of such analyses: the future level of tariffs is usually in the control of either the government or the Regulatory Commission and, therefore, out of the control of the electric utilities. Associated with this difficulty is the uncertainty of projecting a set of new tariffs that might be implemented. On the one hand, there is the tendency for costs to go up which would put upward pressure on tariffs. On the other hand, the results of this study may lead to the provision of low-cost energy, which would have the tendency to reduce tariffs. Tariffs usually include fees paid by consumers to cover the cost of connecting the applicant to the system. These costs include such materials as the cables going from an existing distribution line to the customer's house and the meter required to measure the consumption of electricity. The costs may also include an inspection of the premises to ensure that electrical installations have been carried out in accordance with applicable standards. For people of low income this charge may act as a barrier to connection to the system. Thus a change in these charges can affect the rate at which electrification takes place. For purposes of this analysis, it is assumed that the electricity tariffs will increase at the rate of inflation. It is also assumed that the connection fees will remain at the same relative levels over the study period. E.4.6 Prices of Competing Energy Sources Conceptually, if there is a significant increase in prices in real terms (i.e. an increase above the inflation rate) of competing energy sources available to a category of customers, the sales of electricity in that category is expected to increase ­ this is represented by the price elasticity of demand which would be positive. This factor is estimated as part of the analysis of historic data in which a statistical relationship is estimated between sales and relevant explanatory variables, including the average price of competing energy sources. If the statistical tests on the relationship obtained shows that the variable of the price of one or more of these competing energy sources should be included in the relationship, the coefficient associated with that variable is the estimate of the price elasticity of demand. The following tabulation indicates the uses of electricity in the region and the competing sources of energy: SSEA III - Final Report E-11 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Uses of Electricity Competing Sources of Energy Lighting Partial competition only: Kerosene, candles Ventilation (ceiling or table fans) None Air conditioners None Television, radios None Cooking Kerosene, LPG, wood Refrigeration None Other household appliances None Motors Diesel, Kerosene Pumps Diesel, Kerosene The main competition for electricity would be found in the commercial and industrial categories in the pumping and motor loads. When statistical relationships involving these categories and fuels are found to be useful, there is a difficulty in using the results of such analyses: the future level of prices is usually the result of either free market forces or of government intervention and, therefore, out of the control of the electric utilities. For purposes of this analysis, it is assumed, too, that the prices of competing energy sources will increase at the rate of inflation. E.4.7 Ability and Willingness to Pay In assessing the growth in electricity sales and, particularly, for rural electrification programs, it is useful to incorporate assessments of both the ability of the prospective consumer to pay the electricity charges as well as his willingness to pay. One way of assessing the ability to pay is through a study of the substitution of energy sources. For example, if a family uses two candles per evening for their lighting needs, it is assumed that that family would be willing to pay up to the cost of those two candles for electric lighting. This presupposes two crucial conditions: The family has the disposable income to buy two candles every day; and The family would be willing to pay for the electricity, particularly as there would assuredly be additional uses for the power. The willingness to pay of a family is usually inferred from the results of detailed customer surveys. Such surveys have not been done recently in the study region. In this analysis, it is assumed that the constraint on number of customers will be on the utilities' ability to connect new customers and not on the ability or willingness of prospective new customers to pay for the new service. E.4.8 Load Factors The load factor is a measure of the relationship between the average use of the power plants and the maximum "instantaneous" use (usually defined as a fifteen-minute period or a half-hour or a one-hour period) of the power system. It is the relationship between the consumption of energy, which requires fuel in the thermal plants or water from the hydro SSEA III - Final Report E-12 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT plants, and peak demand, which determines the investment required in new equipment. Typical load factor values for the region are as follows: Rwanda: 59% Burundi: 59% Tanzania: 65-66% Kenya: 69% Uganda: 59-61% East DRC: 52% For Rwanda, the figures observed for years 1993-1994 were considered as outliers as they represent data at the height of the civil strife. The average load factor was then calculated while discarding those two years. The load factors for Rwanda and Burundi are based on conditions of suppressed demand and need to be adjusted for the removal of the constraints on generation. If the constraint on energy is equal to about 4% and the constraint on peak demand is about 11%, the impact on the load factor would be about 7% [(1+11%)/(1+4%)-1]. Therefore, the unconstrained load factors for Rwanda and Burundi will be taken as 55% (59% less 7% of 59%). E.4.9 Allowance for System Reserve An electric power system is expected to serve the load with a certain degree of reliability. This implies that the amount of generation available must exceed the expected load. This allows the load to be served even if: The actual load varies from the forecast; One or more of the generating units is removed from service for repairs or maintenance; and One or more of the units breaks down. Planners assess the level of reserve margin in several ways, including: Being able to meet the load with the largest unit out of service (a variation would be to use the two largest units out of service) ­ this is known as the N-1 or N-2 criterion; Applying a fixed percentage to the load such as 20% or more; Taking account of the probabilities of any unit being out of service at any given time and ensuring that there is enough generation in place so that the probability of not being able to meet the load is one hour per year or one day per year (or other similar benchmark) depending upon how reliable the system needs to be. The dilemma faced by planners is that the more reserve margin planned for, the higher will be the capital investment required. On the other hand, too little reserve will cause slow- downs in economic growth of the country or the region. Since this forecast focuses on the expected electric power requirements only, the reserve margin aspect will be covered in subsequent work dealing with the proposed Nile Basin generation expansion plan. SSEA III - Final Report E-13 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.5 Review of the Reference Load Forecasts The goal of this section is to reconcile the set of forecasts selected from the different source documents to obtain six individual, but mutually consistent load forecasts that will provide the basis for the Regional Power Needs Assessment. The original load forecasts as they appear in the source documents are presented in turn for each individual country along with their respective assumptions. Any necessary modifications or updates to the assumptions will be implemented in each case so that the final results reflect a common regional scenario. E.5.1 Review of Reference Documents and Selection of Reference Forecasts The Power Needs Assessment will be built upon key studies performed in the region, meetings with government officials and key stakeholders and other relevant documentation. The key studies to be reviewed are the following: (a) Stage I - SSEA of Power Development Options in Burundi, Rwanda and Western Tanzania, 2004 (b) East African Power Master Plan Study for Kenya, Tanzania and Uganda, BKS-Acres, 2005 (c) Plan Directeur National du Secteur de l'Électricité à l'Horizon 2015, SNEL, 2003 (d) The Least Cost Power Development Plan Update 2005-2025, The Kenya Power & Lighting Company LTD, 2004 (e) The TANESCO Master Plan, 2004 (f) Annual Report, Uganda Electricity Transmission Company Limited, 2002 (g) Analysis and Projection of Rwanda's Electricity Demand, Final Report, Lahmeyer International, 2004 (h) Coordination Est-Goma, Synthèse des états des lieux, SNEL, October 2004 Based on these documents, a detailed review of the various forecasts available for each country is carried out. The major conclusions are the following: · A consistent set of forecast assumptions is used across all of the countries studied within the framework of the EAPMP and SSEA reports respectively; · The forecasts (d) to (g), prepared by the utilities in Kenya, Tanzania, Uganda and Rwanda respectively, yield results that are either consistent with or fully enclosed within the limits of the EAPMP and SSEA forecasts for each country. This conclusion will be explicitly demonstrated in the next section; · The SSEA report considers only the western part of Tanzania, while the EAPMP forecast accounts for the entire country's electricity demand, as required by the Terms of Reference; · Reference document (c), prepared by SNEL for the Democratic Republic of Congo (DRC), presents a detailed demand forecast for every urban centre in DRC. This SSEA III - Final Report E-14 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT document then provides the capability of differentiating between the regions of interest located in the East and in the rest of DRC. It follows from the above analysis that the EAPMP is the best candidate for Kenya, Uganda and Tanzania whereas the SSEA-Phase I is the best candidate for Rwanda and Burundi. The SNEL master plan is also selected to form the basis of a more detailed East DRC forecast. Based on this review, the following forecasts are used as a starting point for the regional power needs assessment: Burundi: SSEA Stage I forecast Eastern DRC: SNEL master plan Kenya: EAPMP forecast Rwanda: SSEA Stage I forecast Tanzania: EAPMP forecast Uganda: EAPMP forecast Each of the above forecasts is derived for low, medium and high scenarios. In the analyses carried out of the power development options, a base forecast is defined as the most likely to be achieved if all countries continue to develop independently. In this case, the base scenario is the sum of the low forecasts for each country. The medium forecast is used in the analyses to represent a reasonable forecast for integrated planning. The high forecast is a somewhat optimistic forecast E.5.2 Burundi Burundi experienced severe political and civil strife in the 1990s and consequently its economy suffered and the power demand dropped sharply, particularly in 1995-964. Burundi's historical demand from the 1981 to 2001 period is shown in Figure E-2, showing a steady growth (about 8%) in energy demand from 1981 to 1994, followed by a severe drop in 1995-1996. The electricity demand has since returned to an average 8% growth. Thus, forecasts prepared prior to the years of political unrest overestimated the peak power and energy demand as they did not take into account the negative impacts on the economy, on the population and the damage caused to the electrical infrastructure. The SSEA-Phase I report prepared in 2004 takes into account only the latest forecast prepared for Burundi by EGL and EDF, and dated July 2002. 4 Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in Burundi, Rwanda, and Western Tanzania, Stage I, prepared by SNC-Lavalin International, February 2005, pages 4-16, 4-17 SSEA III - Final Report E-15 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Figure E-2 - Burundi's Historical Demand Characteristics3 Burundi - Historical Demand Characteristics 160 30 140 25 120 100 20 h 80 15 GW MW 60 10 40 20 5 0 0 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 Energy Consummed (GWh) Energy Supplied (GWh) Demand Peak (MW) E.5.2.1 Approach and Assumptions Burundi's economy experienced very little real growth in the last 20 years, (1.6% from 1980 to 1998). Historically, the GDP sectors of Burundi, primary, secondary and tertiary, grew at an average rate of 1.3%, 0.5% and 2.6% respectively, for an overall average growth of 1.8%. This is considered in the SSEA as the low scenario. Growth rates of 3.5% and 4.5% are used for the overall GDP growth rates for the base and high scenarios. Population growth is assumed to occur at the same average historical rate of 2.6%. The rural electrification rate is considered to increase from its current level of 2.5% to reach 15% in 2020 in the base case. Technical losses are also assumed to decrease from 14% in 2002 to 10% in 2020 as a result of eventual network reinforcements. A summary of all assumptions is shown in Table E-7. The econometric method is used to predict the energy demand for Burundi in the target forecast period in terms of GDP growth rates for each sector and population growth. The predictions are calculated on an "energy sent out" basis, meaning that not only sales are accounted for, but also transmission losses5. 5 Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in Burundi, Rwanda, and Western Tanzania, Stage I, prepared by SNC-Lavalin International, November 2004, page 4-20 SSEA III - Final Report E-16 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Table E-7 - Basic Assumptions for the Burundi Load Forecast Assumptions Low Base High Suppressed demand 2002 Energy 1% 2% 5% Demand Included in choice of load factor Rural Electrification Current level 2.5 2.5 2.5 included in trend 3.00% 3% 3% target in 2020 6% 15% 24% Increase 2X 5X 8X Technical losses 2002 14% 14% 14% 2020 12% 10% 8% Load Factor 55% 55% 55% Specific consumption of rural loads 75 kWh/month Growth in specific consumption 0.50% 1.00% 2.00% E.5.2.2 Results The results are shown in Table E-8 and illustrated in Figure E-3 (a) and (b) for peak power demand and energy demand respectively. Complete tabulated values are shown in section C.4. Table E-8 - Burundi Forecast Summary Annual Annual Annual Low Base High Year Growth Growth Growth Energy (GWh) 2002 145 7.5% 150 10.1% 150 10.1% 2005 180 4.6% 200 7.3% 200 10.2% 2010 225 5.2% 285 8.6% 325 12.1% 2015 290 4.7% 430 9.6% 575 13.3% 2020 365 680 1,075 Demand (MW) 2002 30 8.7% 30 12.6% 35 7.7% 2005 40 4.1% 40 7.0% 40 11.2% 2010 45 4.9% 60 8.4% 70 11.3% 2015 60 5.2% 85 10.1% 120 12.8% 2020 75 140 220 SSEA III - Final Report E-17 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Figure E-3- Burundi Demand Forecast for the 2002-2020 Period Peak Power Demand - Burundi 250 High 200 (MW) 150 Base 100 Demand 50 Low - 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Year Energy Demand - Burundi 1200 High 1000 800 (GWh) 600 Base 400 Energy 200 Low 0 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Year E.5.3 East Democratic Republic of Congo (DRC) Since 1975, Congo has been going through a deep economic and social crisis. The 1975 to 1982 period marked the beginning of Congo's economic difficulties, due to both internal and external causes. From 1983 to 1990, the government initiated several reforms aimed at stabilizing the economy. These were met with partial success: real GDP growth in 1980 was registered as 2.4%, increasing to 2.9% in 1981, and dropping sharply to -3.0% in 1982, due to the decline in the price of copper. Thereafter, GDP increased once again and sustained positive real growth rates of 1.3% in 1983, 2.7% in 1984, 2.5% in 1985, 2.7% in 1986 and 1987, and 0.5% in 1988. SSEA III - Final Report E-18 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT From 1990 to 1997, a long institutional crisis hampered economic growth. The decline was worsened by an embargo from the major world funding agencies. During that period, the GDP growth rate fell to -1.3% and continued its decline with negative growth rates of -2.6% in 1990, -7.3% in 1991, and -8.0% in 1992. The 1998 civil war, followed by the partial occupation of the Congolese territory brought even more severe repercussions on the economy and on population growth. In his address to the nation, the new president launched in 2001 a national program aimed at a long-term economic recovery. Today, DRC is still struggling to recover from the conflict that continues to destabilize Central Africa and cause immense suffering to the country's civilian population. The Congolese industry has come to a virtual halt and most international companies have stopped their activities. Mines are however being exploited everyday by thousands of independent workers extracting metals manually. Since 1998, the government has not implemented any census or population count. Births and deaths are not registered, and there is very little or no up-to-date data on both demographic and economic issues. Official statistics on the composition and growth of GDP can be taken as rough approximations at best, especially given the chaotic nature of the Congolese economy and society. The Société Nationale D'électricité, the government owned utility, owns three hydroelectric and six thermal stations for a total nine generating installations. The first three have a total installed capacity of 65 MW, of which only 36 MW are available, or 55%. All generating stations in DRC are characterized by extreme wear, lack of maintenance and the need for complete rehabilitation. The deficit in production is also significant, or 45% of the installed capacity, in spite of the increasing electricity demand due to the increase in population. The thermal stations together have an installed capacity of 15 MW, of which only 4.1 MW are available, or 27%. Due to the lack of fuel and to plundering, only the Kisangani group remains operational today6. E.5.3.1 Approach and Assumptions The latest load forecast was prepared by the Société Nationale d'Électricité (SNEL), in its Plan Directeur National du Secteur de l'Électricité à l'Horizon 2015 (PDN) in 2003. A macro- economic approach based on economic GDP projections and socio-political assumptions would not be realistic given the current political climate in DRC. This is why the SNEL document relies heavily on its records as to the number of customers in each city and their specific consumption. Since the industry has come to a virtual halt in Congo, SNEL considers that almost all of the electricity demand comes from the domestic sector. However, the SNEL forecast does not take into account the following elements: Rural load; Additional rural electrification; Transmission losses, and Sensitivity analysis. These elements must be taken into account if all six countries' forecasts are to be mutually consistent. For this purpose, the SNEL forecast has been adapted to incorporate the above elements. 6Coordination Est-Goma: Synthèse des états des lieux, Société Nationale d'électricité, October 2004, page I SSEA III - Final Report E-19 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.5.3.2 Geographical Region under Analysis In the framework of the SSEA-Phase II project, the regional load forecast is concerned only with the eastern part of DRC. This includes the provinces of North and South Kivu, as well as the eastern parts of Katanga and of the Oriental Province. The region under analysis is illustrated in Figure E-4. Given that the SNEL report offers detailed load forecasts for individual provinces and provincial districts, it is possible to consider only the eastern districts of the Oriental Province: the Haut-Uélé and the Ituri, the eastern districts of the Katanga province: the Taganika and the Haut Katanga and the totality of the North and South Kivu provinces. The shaded region in Figure E-4 also entails a small part of Maniema, namely the District of Kabambare. With a highly rural population and an electrification rate of 0.1%, this district contributes a negligible amount to the total Eastern DRC load as shown in the detailed results shown in section D.5.3. Figure E-4 - The Democratic Republic of Congo ­ Provincial Map Showing the Region under Analysis E.5.3.3 Rural Load The SNEL forecast only takes urban centers into account. Despite a very low national rural electrification rate, rural loads do however contribute a non-negligible amount to Congo's electrical power consumption. The rural electrification rates for the provinces under analysis are the following: North Kivu: 1.47%; South Kivu: 4.43%; SSEA III - Final Report E-20 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Oriental Province: 2.69%; Katanga Province: 4.43%; Maniema: 0.1%. No official census was recently done in Congo and basic demographic data can only be found through non-governmental and humanitarian organizations. In particular, a recent study entitled Mortality in the Democratic Republic of Congo: a Nationwide Survey, was produced by the Burnet Institute and the International Rescue Committee and is dated July 2004. This document provides population data for each province as well as an up-to-date average national population growth rate of 2.7%7. The average size of households in eastern DRC as well as the number of households per address was found in Données de Base sur la Population: Zaire, prepared by Centre Français sur la Population et le Développement, in 1992. It is assumed for the purpose of this forecast that these two key numbers have remained approximately constant since 1992: Size of households in eastern Congo: 7 persons/household8; Number of households per electrified point: 3 in urban areas, 1 in rural areas9. The people living at a single address (or "electrified point") constitute one single client from the utility's point of view. It follows that in urban areas, the consumption of "one customer" actually accounts for the electrical consumption of 21 people (7 persons per household times 3 households per address). Although the source is dated 1992, this result is in good agreement with the 2004 humanitarian survey quoting an average of 20-30 people sharing a single address in urban areas. This number drops down to a single household (7 people) per address in rural areas, considering the lower population density. For specific consumption, rural areas were taken to be equivalent to what SNEL refers to as "partially electrified centers": 1200 kWh/year. It was further assumed that specific consumption would grow at a rate of 1%/year in the base case. E.5.3.4 Additional Rural Electrification No additional rural electrification was taken into account in the SNEL report. In our forecast, an assumption similar to that taken for Rwanda and Burundi is used, namely that the level of rural electrification will grow by a factor of 5 in the base case over the period of the forecast. E.5.3.5 Transmission Losses The SNEL forecast assumes a constant level of 10% for transmission losses throughout the duration of the forecast period. For consistency with the forecasts of neighbouring countries, it is assumed that eventual improvements to the network will contribute to reducing the transmission losses to 8% in 2020 in the base case. 7 Mortality in the Democratic Republic of Congo: a Nationwide Survey, the Burnet Institute, The International Rescue Committee, July 2004 8 Données de Base sur la Population: Zaïre, Centre Français sur la Population et le Développement, 1992 9 Croissance urbaine et modifications de l'environnement - cadre de vie des citadins en Afrique subsaharienne, Nicolas Remy-Thomas, Mémoire de Maîtrise, Université de Provence Aix-Marseilles I SSEA III - Final Report E-21 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.5.3.6 Load Factor No load factor is specified explicitly in the SNEL report. However, from the results it presents, an equivalent can be calculated showing a typical load factor of 52% throughout the forecast period. This value is in good agreement with the assumed load factors for the other countries and does correspond to the typical values found in that part of Africa. E.5.3.7 Sensitivity Analysis In the SNEL report only the "most probable outcome" is presented. It is however vital useful to consider upper and lower limits on decisive factors such as specific consumption, transmission losses and rates of rural and urban electrification. The assumptions corresponding to the different scenarios examined are shown in Table C-3. E.5.3.8 Other Assumptions Since only a partial forecast is required for the Katanga and Oriental Provinces, the following assumptions have to be made to ensure consistent results: No separate demographic data is available to account for the eastern populations of the Taganika and Oriental Provinces. Therefore, the number of customers reported by SNEL for the Haut-Katanga and Taganika regions in the Katanga Province and the Haut-Uélé and Ituri regions of the Oriental Province were used along with each province's given rate of urban electrification to obtain an estimate of the urban population. The rural population estimate was calculated based on the national urban/rural population ratio. The specific consumption in each province is calculated in the SNEL forecast by taking the ratio of the total provincial load to the total provincial population, thus representing a provincial average. This assumption is acceptable when analyzing the entire province, as in the case of North and South Kivu. On the other hand, when taking into account only a small portion of a very large territory such as the eastern parts of the Katanga and Oriental provinces, a local specific consumption estimate is necessary. This number can be calculated directly from the SNEL forecast to be 700 kWh/year for Eastern Katanga and 600 kWh/year for the Eastern Oriental province. These reduced consumption rates are due to the fact that these sub regions are mostly rural, and the few villages that are partly electrified have access to electricity for a few hours a day. As a result, the local population does not look at electricity for a reliable source of energy and turns to biofuels (wood, coal, etc). However, it will be assumed in this forecast that with the eventual implementation of power development options and additional rural electrification, the local specific consumption will increase gradually and in a sustained fashion throughout the target period. The full set of assumptions for each province under analysis is shown in Table E-9. SSEA III - Final Report E-22 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Table E-9 - Basic Assumptions for the East-DRC Load Forecast GENERAL ASSUMPTIONS Population Growth Rate 2.70% per year Average size of households 7 persons/household Average Households per 3 in urban areas in 2005, decreasing 2% per year lodging 1 in rural areas Proportion of urban population 32% Losses 10% going to 10%, 8% and 6% in low, base and high scenarios NORTH KIVU Specific Consumption Cx Cx Rate of Increase Remarks Urban (MWh/y) Low Base High City of Goma: 9,719 clients 1.68 0% 1% 2% 20% at 3.6 and 80% at 1.2 MWh/y Other urban centers: 4,424 clients 1.20 0% 1% 2% 100% at 1.2 MWh/y Weighted average Cx 1.53 0% 1% 2% Rural 1.20 0% 1% 2% 100% at 1.2 MWh/y Rate of Electrification rx rx Low Base High Urban linearly with a 35% 20% 1% ceiling Rural 1.47% increasing 5X by 2020 SOUTH KIVU Specific Consumption Cx Cx Rate of Increase Remarks Urban (MWh/y) Low Base High City of Bukavu: 12,201 clients 1.68 0% 1% 2% 20% at 3.6 and 80% at 1.2 MWh/y Other urban centers: 9746 clients 1.2 0% 1% 2% 100% at 1.2 MWh/y Weighted average Cx 1.20 0% 1% 2% Rural 1.47 0% 1% 2% Rate of Electrification rx rx Low Base High Urban linearly with a 35% 20% 1% ceiling Rural 4.43% increasing 5X by 2020 SSEA III - Final Report E-23 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT ORIENTAL PROVINCE ­ HAUT-UÉLÉ AND ITURI Specific Consumption Cx Cx Rate of Increase Remarks Urban (MWh/y) Low Base High All urban centers 0.60 0% 1% 2% Rural 0.60 0% 1% 2% Rate of Electrification rx rx Low Base High Urban linearly with a 55% 40% 1% ceiling Rural 2.69% increasing 5X by 2020 KATANGA ­ TAGANIKA AND HAUT-KATANGA Specific Consumption Cx Cx Rate of Increase Remarks Urban (MWh/y) Low Base High All urban centers 0.70 0% 1% 2% Rural 0.70 0% 1% 2% Rate of Electrification rx rx Low Base High Urban linearly with a 55% 40% 1% ceiling Rural 4.43% increasing 5X by 2020 Note: The Kabambare region of Maniema contributes a minimal amount to the overall regional forecast. It is taken into account by using an estimation based on the SNEL forecast. Details are shown in section C.4. E.5.3.9 Results For any given region x, it is possible to estimate the load Lx and peak power Px using the appropriate assumptions and the following equations: Lx = POPx rx Cx Lx 1000 H N Px = F (24365) where: Lx = load in region x in GWh/year; Px = peak power in region x in MW; POPx = population of area x, growing at a rate of 2.7%; rx = electrification rate in region x, growing 5 times by 2020; Cx = specific consumption in region x, growing at a rate of 1%/year; N = number of households per address, 3 in urban centers decreasing; 2%/year and 1 in rural areas staying constant; F = load factor, constant; and H = size of households, constant. These calculations yield a new demand forecast, where it is now possible to model the eventual growth of the rural load and to conduct a sensitivity analysis based on demographic and specific consumption data. SSEA III - Final Report E-24 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT The full forecast calculations are shown in E.6. The results are summarized in Table E-10, and illustrated in Figure E-5. The observed difference between this forecast and the SNEL forecast comes from the increasing additional rural load. This difference becomes significant around 2010. By 2020, the total load in East DRC is approximately the double of SNEL's urban forecast, thereby showing that the rural load will eventually grow to reach the same level as the urban load. This is due to the fact that the majority of the population lives in rural areas, so that every 1% increase in the rate of rural electrification yields a large number of new clients. Thus, a slow but sustained electrification of rural areas would eventually contribute a significant portion to the total Eastern DRC load. Table E-10 - East DRC Forecast Summary Annual Annual Annual Low Base High Year Growth Growth Growth Energy (GWh) 2002 225 8.8% 225 8.8% 225 8.8% 2005 300 6.9% 300 7.9% 300 8.9% 2010 405 7.1% 425 8.2% 445 9.5% 2015 570 8.3% 630 8.6% 700 9.5% 2020 825 950 1100 Demand (MW) 2002 50 8.0% 50 8.0% 50 9.1% 2005 60 7.4% 60 8.6% 60 9.0% 2010 90 6.8% 95 8.1% 100 8.4% 2015 125 7.6% 140 8.4% 150 10.3% 2020 180 210 250 SSEA III - Final Report E-25 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Figure E-5 - Updated East DRC Demand Forecast for the 2002-2020 Period Demand Forecast in East DRC 300 250 High Base (MW) 200 Low 150 Power 100 Urban SNEL Peak 50 Forecast 0 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Year Energy Forecast in East DRC 1,200 High 1,000 Base 800 Low (GWh) 600 Energy 400 Urban SNEL 200 Forecast 0 2002 2003 2004 2005 200 2007 2008 2009 2010 2011 201 2013 2014 2015 2016 2017 2018 2019 202 6 2 0 Year E.5.4 Kenya The results presented in the East African Power Master Plan (EAPMP) for the future electricity consumption of Kenya are based upon an update of the 2003 Least Cost Power Update, which in turn has retained the same forecasting models, and techniques that were originally developed in the National Power Development Plan (NPDP) in 1986. SSEA III - Final Report E-26 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.5.4.1 Approach and Assumptions The 2003 update was prepared based on the assumption that Kenya would come out of the period of slow economic growth that started in 1997. This period was characterized by particularly low GDP growth rates between 1999 and 2003: 1.8%, 1.4%, -0.3%, 1.1%, and 1.4% respectively. In comparison with the historic trend, the economic activity in 2003 was slightly stronger than in 2001 and 2002. This positive growth in the economy also led to a growth in the number of customers, especially in the industrial category, thereby contributing to increased electricity sales. In 2002/2003, there was adequate and surplus capacity to meet demand and sales grew by 5% from previous years. Similarly, maximum peak demand rose from 760 MW in 2001/2002 to 786 MW in 2002/200310. Both historical GDP growth data and electricity sales are shown in Figure E-6. The recovery in 2003 reflects on one hand the enhanced investor confidence due to the improved political and economic governance, and on the other hand the favourable weather conditions that supported the agricultural sector. However, the improvement in growth remains far below the economy's potential. Historical GDP data indicates that the economy has not exceeded an average growth rate of 5% for the last 20 years. The actual growth rate has consistently remained below government projections since 19711. Figure E-6 also illustrates the consequences of the severe drought that hit Kenya in 2001, when KPLC suffered severe losses and emergency generation had to be leased. This led to the observed slowdown in the economy. It is also clear from Figure E-6 that historic as well as future trends in electricity consumption are strongly correlated to economic indicators. Figure E-6 - Historical GDP Growth Rates and Electricity Sales for Kenya, 1997-200311 10The Least Cost Power Development Plan Update 2005-2025, The Kenya Power & Lighting Company LTD, 2004, pages 7-8 11Reforming the Electricity Industry in East Africa, David Newbery, Cambridge University, The Cambridge-MIT Institute Electricity Project Autumn Seminar, 2004, page 13 SSEA III - Final Report E-27 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT The EAPMP predictions assume a reference forecast GDP growth rate of 4.5% in 2004, and 6% for the 2005-2020 period. Electricity tariffs are not assumed to change in real terms and ongoing Loss Reduction and Demand Side Management Projects are expected to reduce the total system losses to 15% in the fiscal year 2007/20083. Non-technical losses were held at 2% of net generation over the entire forecast period. A summary of the base case assumptions used is shown in Table E-11 below. Table E-11 - Basic Assumptions for the Kenya Load Forecast EAPMP Assumptions GDP System Non technical for year Growth Load Factor Losses losses 2004 4.50% 69% 16% 2% 2005 6% 69% 16% 2% 2006 6% 69% 15% 2% 2007-2020 6% 69% 15% 2% A scenario for a low forecast was developed under the assumption that GDP growth rates will continue to be impacted negatively by several destabilizing factors such as politics, global economy, and conflicts in the Middle East12. The high forecast on the other hand is based on the assumption that the government will achieve GDP growths higher than the World Bank predictions by resuscitating the economy. In the base case, the growth rate from fiscal years 2001/02 to 2019/20 averages to 6.4% per annum, while growth in the low and high scenarios is 4.0% and 7.4% respectively. The EAPMP plan develops sales forecasts based on the econometric method for each of four tariff categories: domestic, commercial/industrial, off-peak and rural electrification. The domestic forecast uses historical sales data as well as non-agricultural GDP data to predict future sales using a log-linear regression. The commercial/industrial forecast is performed using past data as well as the GDP for the manufacturing and services sectors as parameters to perform the regression. Off-peak sales are modelled using the number of off- peak clients and time as parameters as these showed a strong correlation. Finally, Kenya's ongoing rural electrification program is taken into account by using past cumulative investment and rural sales data. E.5.4.2 Results The forecast data is shown in Table E-12, and the energy and demand forecast are plotted in Figure E-7 (a) and (b) and compared to the Kenya Power and Lighting Company (KPLC) forecast. As illustrated, KPLC results are consistent with the EAPMP forecast. 12East African Power Master Plan Study, Final Report, produced by BKS Acres for the East African Community, March 2005, page 4-3 SSEA III - Final Report E-28 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Table E-12 - Kenya Forecast Summary5 Low Annual Base Annual High Annual Year Growth Growth Growth Energy (GWh) 2002 4,620 4,620 4,620 4.0% 4.7% 5.5% 2005 5,200 5,300 5,420 4.4% 6.0% 7.3% 2010 6,450 7,100 7,700 4.0% 5.4% 6.8% 2015 7,850 9,250 10,700 4.0% 5.3% 6.7% 2020 9,550 12,000 14,800 Demand (MW) 2002 800 800 800 2.4% 3.2% 4.0% 2005 860 880 900 4.5% 6.0% 7.2% 2010 1,070 1,175 1,275 4.0% 5.4% 6.8% 2015 1,300 1,530 1,770 4.0% 5.5% 6.7% 2020 1,580 2,000 2,450 Figure E-7 - Kenya Power Needs Assessment for the 2002-2020 Period Kenya Demand Forecast 3,000 2,500 High Base 2,000 (MW) Low nd 1,500 ma De1,000 EAPMP 500 KPLC 0 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Year SSEA III - Final Report E-29 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Kenya Energy Forecast 16000 14000 High )h 12000 Base 10000 (GW Low 8000 6000 Energy 4000 EAPMP 2000 KPLC 0 6 2 0 2002 2004 200 2008 2010 201 2014 2016 2018 202 Year E.5.5 Rwanda Like Burundi, Rwanda also suffered civil strife in the 1990s. Historical demand in Rwanda is illustrated in Figure E-8. As shown in Figure E-8, the 1981-1992 period saw a steady growth in electricity demand (about 8%), while a large drop occurs at the height of the civil strife in 1993-1994. From 1995 onwards the electrical demand increased irregularly, but at an average annual rate of 10%. Figure E-8- Rwanda's Historical Demand Characteristics12 Rwanda - Historical Demand Characteristics 250 45 40 200 35 30 150 25 GWh 20 MW 100 15 50 10 5 0 0 198119821983198419851986198719881989199019911992199319941995199619971998199920002001 Energy Consumption (GWh) Supply (GWh) Peak Load (MW) SSEA III - Final Report E-30 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.5.5.1 Approach and Assumptions A number of load forecasts have been prepared for Rwanda prior to the instability period, and their predictions have proven to be overoptimistic. Only the most recent forecast, prepared by Lahmeyer International in 2004, was taken into account in the SSEA. Several econometric equations have been developed and explored in order to express the national electricity demand in terms of economic and demographic indicators. Other important aspects were included in the demand forecast developed in the SSEA, namely, the removal of constraints on demand, the inclusion of an allowance for rural electrification and the reduction of technical losses13. A summary of all assumptions used is shown in Table E-13. Table E-13 - Basic Assumptions for the Rwanda Load Forecast Assumptions Low Base High Suppressed demand 2002 Energy 2% 5% 8% Demand Included in load factor Rural Electrification Current level 2.42% 2.42% 2.42% included in trend 2.50% 2.50% 2.50% target in 2020 5% 13% 20% Increase 5X 8X Major Industrial Load 7MW 2008 7MW 2008 7MW 2007 Technical losses 2002 14% 14% 14% 2020 12% 10% 8% Load Factor 55% 55% 55% Specific consumption of rural loads 75 kWh/month Growth in specific consumption 0.50% 1.00% 2.00% E.5.5.2 Results The results for the energy and peak power demand predictions in Rwanda are shown Table E-14 and plotted in Figure E-9 (a) and (b). It is important to note that the results include the underlying trend of electricity consumption as well as an allowance for additional electrification and losses. Complete tabulated values are shown in section C.4. 13Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in Burundi, Rwanda, and Western Tanzania, Stage I, prepared by SNC-Lavalin International, February 2005, pages 4-12 to 4-16 SSEA III - Final Report E-31 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Table E-14 - Rwanda Forecast Summary Low Annual Base Annual High Annual Year Growth Growth Growth Energy (GWh) 2002 230 240 245 3.5% 4.6% 7.0% 2005 255 275 300 5.6% 8.0% 9.8% 2010 335 405 480 3.1% 6.7% 9.3% 2015 390 560 750 3.6% 7.9% 11.3% 2020 465 820 1,280 Demand (MW) 2002 50 50 50 2.7% 5.3% 7.7% 2005 55 60 60 4.2% 6.3% 8.9% 2010 65 80 95 2.4% 6.5% 9.4% 2015 75 110 150 4.1% 8.4% 11.3% 2020 90 160 250 Figure E-9 - Rwanda Demand Forecast for the 2002-2020 Period Peak Power Forecast - Rwanda 300 High 250 (MW) 200 150 Base Power 100 Peak Low 50 0 8 2002 2004 2006 200 2010 2012 2014 2016 2018 2020 Year SSEA III - Final Report E-32 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Energy Demand Forecast - Rwanda 1400 1200 High 1000 (GWh) 800 600 Base Energy 400 Low 200 0 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Year E.5.6 Tanzania The load forecast appearing in the EAPMP is based upon the original TANESCO plan that is currently being updated as part of the country's master plan. In the years since the load forecast was first prepared, the power sector has faced some hardships, including a serious drought, that in turn affected the Great Ruaha river in the south of Tanzania14. On the other hand, the government has embarked on a series of dynamic reform processes in various sectors of the economy, including mining, tourism, agriculture, infrastructure, and manufacturing. The historic evolution of GDP for the agriculture, industry and services sectors in Tanzania is illustrated in Figure E-10 for the 1980-2002 period, showing steady growth. Figure E-10 - Tanzania's Gross Domestic Product (billions of TShs at 1992 prices)17 2,050 1,850 1,650 1,450 1,250 BILLIONS) 1,050 850 (TShs 650 450 GDP 250 50 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 YEARS Agriculture Industry Services Total GDP 14The Tanesco Master Plan, 2004, page 4-1 and table 4-1 SSEA III - Final Report E-33 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.5.6.1 Tanzania's Rural Electrification Program In the framework of the SSEA-Phase I project, a Power Steering Committee meeting was held in Dar es Salaam in late September 2004, where both the committee members and the stakeholders felt that the government's emphasis would soon be placed on rural electrification. In the domestic sector, TANESCO has since embarked on an accelerated rural electrification program with an expected 50,000 new connections in 2004, 100,000 in 2005 and an annual increase of 10% per annum thereafter. This project is to be funded by TANESCO. Furthermore, the government recognizes that in the industrial sector, the economic growth of Tanzania is strongly dependent on the mining industry, where a significant portion of the demand is currently met by isolated generation. The sector is projected to grow at a rate of 22% per annum in the mid term and has attracted the attention of a number of foreign investors in gold, nickel, cobalt and gemstone mining activities17. The gradual connection of mining loads to the national grid will require a significant amount of reliable power. E.5.6.2 Approach and Assumptions The load forecast model uses a regression analysis with electricity sales, tariff levels, generation, system losses and GDP as exogenous variables. The forecast is divided into several categories: general, commercial, public lighting and bulk sales to Zanzibar. The mining load is also explicitly taken into account. Since isolated diesel units are currently meeting a major part of the mining load, scenarios are developed with regards to its eventual connection to the national grid. The low and high scenarios then take into account not only the economic and customer growth factors but also industrial development and the mining industry: Reference case: overall GDP and number of customers both grow at an average of 5%/year, while average consumption grows 4%/year. New industries are assumed to grow to their full potential within three years after commissioning. On the other hand, existing mines will keep using auto generation and will not contribute to the grid demand. Low Case: overall GDP grows at 3.5%/year. The number of customers still grows at a rate of 5%/year, but there is no increase in the specific consumption. New industries will reach their full potential 5 years after commissioning and existing mines will keep using auto generation. High Case: overall GDP grows at 5.9%/year. The number of customers as well as specific consumption will grow at 5%/year. New industries will reach full capacity 3 years after commissioning and all mining loads will be connected to the national grid at specified times. In all cases, technical losses are assumed to decrease steadily from their original 12% level in 2003, to stabilize at 7.5% in 2007. Non-technical losses start at 10% in 2003 and decrease steadily to stabilize at 6.5% in 2007. The load factor is calculated based on load factors specified in each tariff category, weighted on the relative sales in each category. The assumptions are summarized in Table E-15. SSEA III - Final Report E-34 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Table E-15 - Basic Assumptions for the Tanzania Load Forecast EAPMP GDP Customer Specific Years to full Load Assumptions growth growth Consumption industrial Exports growth capacity Factor Low 3.50% 5% 0% 5, no mines 200 MW 65-66% Base 5% 5% 4% 3, no mines to 65-66% High 5.90% 5% 5% 3, with mines Kenya 65-66% Technical losses 12% in 2003 to 7.5% in 2007+ Non-technical losses 10% in 2003 to 6.5% in 2007+ E.5.6.3 Results The EAPMP results in the case of Tanzania are shown in Table E-16 and illustrated in Figure E-11 (a) and (b), compared to the TANESCO Master Plan reduced industrial and full industrial scenarios. Figure E-11 clearly shows that the EAPMP takes into account a broader range of possibilities. Table E-16 - Tanzania Forecast Summary15 Year Low Growth Base Growth High Growth Energy (GWh) 2002 2,800 2,800 2,800 4.9% 7.7% 10.0% 2005 3,230 3,500 3,730 4.0% 5.9% 8.2% 2010 3,925 4,670 5,520 3.6% 4.5% 5.2% 2015 4,675 5,825 7,125 3.5% 4.5% 5.2% 2020 5,550 7,245 9,195 Demand (MW) 2002 500 500 500 5.1% 8.0% 10.8% 2005 580 630 680 4.4% 6.2% 8.8% 2010 720 850 1,035 3.5% 4.5% 5.1% 2015 855 1,060 1,325 3.5% 4.5% 5.1% 2020 1,015 1,320 1,700 15East African Power Master Plan Study, Final Report, produced by BKS Acres for the East African Community, March 2005, page 4-9 SSEA III - Final Report E-35 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Figure E-11 - Tanzania Demand Forecast for the 2002-2020 period Tanzania Demand Forecast 1,800 1,600 High 1,400 1,200 Base (MW) 1,000 800 Low Demand 600 EAPMP 400 Tanesco Reduced Industrial 200 Tanesco Full Industrial 0 6 2002 2004 2006 2008 2010 2012 2014 201 2018 2020 Year Tanzania Energy Forecast 10,000 9,000 High 8,000 7,000 Base 6,000 (GWh) Low 5,000 4,000 Energy EAPMP 3,000 Tanesco Reduced Industrial 2,000 Tanesco Full Industrial 1,000 0 4 8 2002 200 2006 200 2010 2012 2014 2016 2018 2020 Year SSEA III - Final Report E-36 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.5.7 Uganda The people of Uganda have an extremely low electricity access rate, less than 3% on average. This is mainly due to the continuous economic decline throughout the 70s and 80s and the Uganda Electricity Board's difficulties in managing and expanding the system in the early 90s. However, during the 90s, the improved economy saw the electricity demand increase by over 8%/year to 199916. Over the same time period the GDP grew by 6.3%/year on average. The Electricity Act of 1999 provides that the minister responsible for electricity shall prepare a sustainable and co-ordinated Rural Electrification Strategy and Plan for Uganda17. The government has since embarked on an extensive rural electrification program, aimed at reducing inequalities in access to electricity, as explained in Section C.3.2.1. From a historical point of view, because of Uganda's unique historical circumstances, there is no useful pattern from which to derive reliable relationships between economic growth and electricity requirements. Historical electricity demand is illustrated in Figure E-12. Although the historic data in the last decade shows a generally increasing trend, there is no overall pattern to extrapolate future demand. Figure E-12 - Historical Generation Data in Uganda, 1957-200118 Several forecasts have been produced for Uganda in the last five years. In 1998, Électricité de France produced a forecast in the framework of an optimization study. This forecast is based on economic factors such as GDP growth, increase in household income, and connection rates as well as loss reduction and electrification rate. Considering the uncertain 16Bujagali Project, Summary of Due Diligence, International Finance Corporation, 2001, page 12 17Rural Electrification Strategy and Plan Covering the Period 2001 to 2010, Ministry of Energy and Mineral Development, The Republic of Uganda, February 2001, page V 18Reforming the Electricity Industry in East Africa, David Newbery, Cambridge University, The Cambridge-MIT Institute Electricity Project Autumn Seminar, 2004, page 6 SSEA III - Final Report E-37 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT future behaviour of these factors, the EDF forecast assigns probability distributions to each variable and produces a probabilistic forecast model based on Monte Carlo simulation. The EDF forecast was then updated in 2000 with the latest data from 1998 and 1999, which was much lower than previously assumed. The same forecast was again updated in 2001, and finally in 2003 by SWECO as part of the UEB Transmission and Sub-Transmission Study (NDF 103-3). This study is also based on the detailed UEDCL billing system data, which presents sales by tariff category for each district19. The EAPMP results are in turn based on the SWECO report, where the results have been updated to reflect a consistent set of assumptions with the Kenya and Tanzania forecasts. E.5.7.1 Uganda's Rural Electrification Program According to the Electricity Act of 1999, the Minister responsible for electricity shall "prepare a sustainable and co-ordinated Rural Electrification (RE) strategy and Plan for Uganda for the approval Cabinet and once each year to submit to Parliament a report on progress and achievement of the Plan"20. The rural electrification plan also forms part of the government's wider rural transformation and poverty eradication agenda. Electricity is currently available to 2% of rural households. The Uganda Electricity Board (UEB) has a total of 170,000 customers of which 80,000 live outside the urban Kampala- Jinja-Entebbe triangle8. The RE strategy aims to achieve for 2010 a rate of rural electrification of 10%. This implies that 400,000 additional rural customers (from the year 2000 figure), for a total of 480,000, will need to be serviced by 2010. This plan also implies that by 2010, the electrified area should also include a total of 1.2 million households, some of which may become eventual customers. This means that 30% of the rural population will live in electrified areas and will have the choice of switching to electricity as their main power source. To achieve these ambitious goals, a Rural Electrification Master Plan has been prepared by the RE agency in cooperation with the system operator. Investment opportunities and development will be demand-driven, so that any capable sponsor (private companies, NGOs, local authorities or communities) will be able to initiate electrification projects. Small- scale power generation projects, especially using clean and renewable energy are expected to play an important role in Uganda's RE effort. The target is to have at least 70 MW of clean energy (such as solar power generation) other than the large-scale hydropower developments by the year 2010. Maximum use will be made of the opportunity for attracting grant support from financing tools related to the Kyoto Protocol8. Following discussions with government officials, it appears that the objectives set in the rural electrification plan remain on on-target for 2010 despite a lower than anticipated new connections rate in 2004. E.5.7.2 Approach and Assumptions The EAPMP applies a growth factor to each tariff category based on information from the detailed UEDCL data. The tariff categories are the following: Domestic tariffs: customers are separated into 6 sets based on their consumption level. It is assumed that the number of customers in each set will increase each year 19 East African Power Master Plan Study, Final Report, produced by BKS Acres for the East African Community, March 2005, page 4-5 20 Rural Electrification Strategy and Plan Covering the Period 2001 to 2010, Ministry of Energy and Mineral Development, The Republic of Uganda, February 2001, pages v-vii SSEA III - Final Report E-38 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT over the forecast period, while the average specific consumption remains constant. The same percentage increase in the number of customers is used in all districts. Small Commercial tariffs: the growth in electricity consumption for small commercial and agricultural customers as well as customers in the service sector is related to the total GDP growth forecast. Medium industrial tariffs: this category includes industrial and commercial clients both public and private. The growth in consumption in this sector is also correlated to the overall GDP growth forecast. Large industrial tariffs: the growth rate in this category is correlated to the growth in the formal GDP for manufacturing forecast. Technical losses for the base year amount to 21% of net generation. A decreasing tendency is assumed at approximately 1%/year until 10% is reached in 2016, after which they are expected to remain constant. A constant allowance for non-technical losses is assumed in the original UEDCL data. This assumption is updated in the EAPMP to start with a 15% rate of non-technical losses in 2001 that is reduced at a rate of 0.7% with a lower limit of 10%. Assumptions are summarized in Table E-17. It should be noted that technical losses continue to decline until they are at 10% of net generation in 2016. The non-technical losses also keep decreasing to approximately 10% by 2016. The load factor is estimated from the base year load factor for each category. The resulting figure varies between 59% and 61% over the forecast period. Table E-17 - Basis Assumptions for the Uganda Load Forecast EAPMP Load Technical Non RE Assumptions GDP Factor Losses technical Program losses 2002 59-61% 21% 15% 2003 59-61% 18% 15.00% 10% of 2004 According to 59-61% 17% 14.20% rural households 2005 categories 59-61% 15% 13.60% electrified 2006 59-61% 14% 12.90% by 2010 2007+ 59-61% 13% 12.30% The rural electrification program established following the Electricity Act 1999 is taken into account in SWECO's 2003 generation planning assumptions, on which the EAPMP forecast is based. E.5.7.3 Results The high and low forecasts are based on different growth rates in the number of domestic clients, as well as on different scenarios regarding economic growth. The results are shown in Table E-18 and illustrated Figure E-13 (a) and (b) where they are compared to the 2001 update of the EDF forecast. As shown in Figure E-13, the previously published Monte-Carlo based EDF forecast is consistent and enclosed within the limits of the EAPMP forecast. SSEA III - Final Report E-39 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Table E-18 - Uganda Forecast Summary21 Low Annual Base Annual High Annual Year Growth Growth Growth Energy (GWh) 2002 1,450 1,500 1,550 0.7% 4.0% 5.7% 2005 1,480 1,700 1,850 2.8% 6.2% 8.3% 2010 1,700 2,300 2,750 4.7% 7.5% 9.0% 2015 2,160 3,400 4,400 6.0% 10.0% 9.7% 2020 2,900 5,000 7,000 Demand (MW) 2002 275 280 290 0.6% 4.4% 6.0% 2005 280 320 350 2.1% 5.5% 7.4% 2010 310 420 500 4.2% 7.3% 8.6% 2015 385 615 785 5.3% 7.9% 9.2% 2020 500 900 1,220 21East African Power Master Plan Study, Final Report, produced by BKS Acres for the East African Community, March 2005, page 4-6 SSEA III - Final Report E-40 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Figure E-13 - Uganda Demand Forecast for the 2002-2020 Period Uganda Demand Forecast 1,400 High 1,200 ) 1,000 Base (MW 800 and 600 Dem 400 Low 200 EAPMP EDF 0 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Year Uganda Energy Forecast 8,000 High 7,000 6,000 5,000 Base (GWh) 4,000 3,000 Low Energy2,000 1,000 EAPMP EDF 0 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Year SSEA III - Final Report E-41 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT E.5.8 Power Needed to Transform the Region The previous section presents a base case forecast along with a low and a high forecast. It should be noted that these forecasts are based on extrapolations of the status quo for the region with some variations about the long-term average. It does not reflect any radical departure from the historical situation. The Project Steering Committee, during its meeting of April 2005, requested the Consultant to provide an alternative forecast that would reflect the optimism expressed in the Lake Victoria Vision as well as the NELSAP five-year Scaling-up strategy. Accordingly, the Consultant has approached the situation from a different perspective than is usually followed. The resulting forecast will be referred to as the Regional Transformation Forecast. The approach followed is to: Review the relevant documents to assess their implications in quantitative terms; Stipulate target growth rates in Gross National Income (GNI) that would be required for the region to attain the vision as defined; Postulate a relationship between GNI growth and electricity growth that could be applicable to the region; Derive the growth rate in electricity consumption that would be required to produce the GNI required to attain the Lake Victoria Vision. Each of these elements is examined separately below. E.5.8.1 Document Review As explained in section 4.3, the Vision and Strategy Framework for Management and Development of Lake Victoria Basin22 includes as a principle focus the development of a broad consensus on realistic, achievable objectives and indicators for sustainable management of the Lake basin in a time frame of 15 years, and to develop appropriate stakeholder participation mechanisms to monitor progress towards achieving the sustainable development goals set in the vision process. To achieve the goal of sustainable development, the categories prioritized in the framework include Ecosystems, Natural Resources and Environment, Production and Income Generation, Living Conditions and Quality of Life, Population and Demography and Governance, Institutions and Policies. The NELSAP five-year Scaling-up strategy includes promoting economic growth, peace and stability. As shown in section 1.3, it can be summarized by a set of three separate time periods: 2005 to 2010 - The Scaling­up Period: the first five years correspond to the implementation of the NELSAP 5 year Scaling-up Strategy aiming at an improved regional political stability; 2010 to 2015 - The Expansion Period: according to the goals set in the strategy, the following five year period would be characterized by significant GNI growth rates as the main economic sectors expand and foreign investments increase due to regional stability and cooperation; 22A report by Statkraft Grøner in association with Norwegian Institute for Urban and Regional Research, Cornell University, Makerere Institute of Social Research, Dar es Salaam University College of Land and Architectural Studies, Agrechs Development Consultants in collaboration with The Regional Task Force, September 2003 SSEA III - Final Report E-42 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT 2015 to 2020 - The Stabilization Period: following the rapid expansion, the regional economies would be expected to stabilize, and this would be reflected by a steadily increasing quality of life and flourishing industries. E.5.8.2 Target growth rates in GNI A relatively common measure of wealth or standard of living is the gross national income (GNI) per capita (also referred to as the Gross National Product (GNP) per capita). The current GNI/capita for the region containing 118 million people is approximately US $275/cap23 as derived in the Table E-19 below. Table E-19 - GNI per Capita for the Forecast Countries Country Population GNI/capita Burundi 6.22 90 Eastern DRC 12.88* 100 Kenya 30.77 400 Rwanda 7.31 220 Tanzania 36.23 300 Uganda 23.98 250 Weighted Average 277 (say 275) * Estimate of the portion of DRC included in the area covered by the analysis An issue is the definition of the target level of GNI per capita that represents a "high standard of living" in the context of the Nile Equatorial Lakes Region. Various target levels can be readily identified: The African country with the highest GNI/capita (Botswana - $3,530); The average of the highest three to five African countries (RSA - $2,750; Botswana - $3,530; Morocco - $1,310; Algeria - $1,930; Egypt - $1,390); The world average GNI/capita ($5,510). It seems more appropriate to focus this analysis on the countries in Africa; in examining the five best, it is noted that four of them owe a large part of their wealth to mineral resources and the populations of these countries may not be benefiting directly from these resources. On that basis, a target rate similar to that of Egypt can be considered as reasonable for the Nile Equatorial Lakes Region. For purposes of this analysis, therefore, the GNI per capita for Egypt has been selected as the target level of wealth for the region. Thus the target GNI/capita value at the end of the 15-year period is assumed to be US$ 1 390. Over a 15-year period, this implies a compound annual growth rate of per capita gross domestic product of 11.4% per year. If population grows at about 2.5% to 2.7%, this implies a growth in overall gross domestic product in real terms of about 14.5% per year. E.5.8.3 Relationship between GNI growth and Electricity Growth As was mentioned during the PSC meeting in Nairobi in April 2005, several countries in Asia had sustained growth rates in electric power consumption over several years of four percentage points greater than the GNI. Experience elsewhere (e.g. in the Cameroon) the growth in electricity consumption has been about 1.2 times the growth in GNI. The former 23 GNI/capita figures in this section are estimates for the year 2005 as obtained from the World Development Indicators Database, World Bank, April 2005. SSEA III - Final Report E-43 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT relationship implies a growth in electricity consumption of 17% per year and the latter relationship suggests a growth of about 16%. A review of the forecasts prepared for the Nile Equatorial Lakes Region implies that the load is expected to grow at roughly the same range as gross domestic product, which would be about 13%. For purposes of this analysis, a growth rate in electricity consumption required to achieve the Lake Victoria Vision is assumed to be about 15%, about the middle of the estimates derived above. E.5.8.4 Growth in Electricity Consumption Needed to Attain the Lake Victoria Vision: the Regional Transformation Forecast Based on the relationships shown above and the required growth in GNI to attain the Lake Victoria Vision, the growth in electricity consumption over a 15-year period would need to average about 15%. Based on the above the following scenario is suggested as being required to attain the Lake Victoria Vision within a relatively short period: 2005 ­ 2010: the scaling up period during which the infrastructure required for rapid and sustained growth is put in place ­ growth equal to the base case; 2010 ­ 2020: the expansion period (extended to a longer period because of the high target) ­ growth of 15% per year. The results are shown in Table E-20 and Figure E14 below. E.5.8.5 Reasonableness of the Transformation Estimate Two other approaches were considered that would provide the population of the region with a comfortable amount of electricity. Three approaches were used, as described below: A scenario in which all households are electrified but at a low level by the year 2020. In this case it is assumed that the medium growth forecast would apply AND, to this would be added the electrification of all remaining households to a level of 100 kWh per month per household (a level used by SNEL in its forecast of rural electrification in eastern DRC). This would yield a target of 67,200 GWh calculated as follows: - Estimated population of the region in 2020: 190 million - Estimated number of households: in 2020: 37 million - Estimated customers in 2020 under the medium growth load forecast: 3.3 million - Additional households to be electrified to a minimal level: 37.0 ­ 3.3 = 33.7 million - Additional load from this minimal electrification: 33.7 x 100 kWh/customer/mo x 12 months = 40,400 GWh - Total target: 40,400 + 26,800 = 67,200 A scenario in which the entire population has access to and uses electricity at the same level as is currently used. This would yield 216,900 GWh calculated as follows: - Unit consumption in 2002 (the year used as a starting point for the forecast): 465 kWh/customer/month or 5,574 kWh/customer per year - Number of households in 2020: 37 million SSEA III - Final Report E-44 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT - Number of customers in 2020: 37 million - Target in 2020: 37 million customers X 5,600 kWh/customer = 210,900 GWh The first of these is similar to the Lake Victoria Vision scenario. The second implies an electricity demand growth rate of 30% per year from 2010, or the same 15% growth rate applied to almost 2030. As a further check on the reasonableness of these identified needs another approach was also studied. Discussions during the PSC meeting held in Mombasa in June 2005 suggested that a reasonable target for household electricity consumption in the region should be about 500 kWh/month/household. Using a population size of 120 million and a household size of 6 people per house, the 2003 consumption in the region of about 9,500 GWh implies a monthly consumption of about 40 kWh per household per month ­ and this includes industrial, commercial and administrative consumption. To attain 500 kWh per household per month from this level implies a growth rate of 15% per year from 2002 to 2020. Thus the level calculated to respond to the Lake Victoria Vision would be well within this target. Table E-20 - Summary of the Scenario Reflecting the Lake Victoria Vision: the Regional Transformation Forecast Year Energy Demand Growth (GWh) Growth (%) (MW) (%) 2002 9,450 1,670 5.5% 5.1% 2005 11,100 1,940 6.1% 6.0% 2010 14,900 2,600 15.0% 15.0% 2015 30,000 5,230 15.0% 15.0% 2020 60,400 10,520 SSEA III - Final Report E-45 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Figure E14 - Impact of the Lake Victoria Vision on the Regional Power Needs Assessment in the NEL Region for 2005-2020: the Regional Transformation Forecast Regional Energy Requirements 70,000 60,000 The Regional 50,000 Transformation Forecast Wh)G( 40,000 gy High 30,000 Base Ener 20,000 Low 10,000 0 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year Regional Peak Demand 12,000 10,000 ) (MWre 8,000 Regional Transformation 6,000 Forecast High Pow 4,000 Base Peak 2,000 Low 0 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year E.6 Supporting Data and Details of Forecast Calculations For reference purposes, this section contains the tabulated load forecast data from the different sources quoted in chapter 5 as well as in this appendix. The following information is included: Kenya: tabulated power and energy figures from the East Africa Power Master Plan and by the Kenya Power and Lighting Company; SSEA III - Final Report E-46 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Tanzania: tabulated power and energy figures from the East Africa Power Master Plan and by the Tanesco Master Plan; Uganda: tabulated power and energy figures from the East Africa Power Master Plan and by Électricité de France; Burundi and Rwanda: tabulated power and energy figures from the Strategic/Sectoral, Social and Environmental Assessment of Power Development Options Phase I: Final Report; East DRC: complete calculation details for each region under consideration based on data provided in the SNEL Master Plan; Regional Load Forecast: tabulated values for total regional energy forecast and demand. SSEA III - Final Report E-47 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Kenya : Tabulated Load Forecast Data 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Energy (GWh) East African Power Master Plan Study - March 2005 Low 4,623 4,804 4,993 5,189 5,423 5,667 5,922 6,189 6,468 6,726 6,994 7,272 7,562 7,863 8,177 8,503 8,843 9,196 9,563 Base 4,623 4,839 5,066 5,303 5,620 5,957 6,313 6,691 7,092 7,480 7,888 8,320 8,774 9,254 9,759 10,291 10,852 11,443 12,067 High 4,623 4,875 5,140 5,420 5,815 6,239 6,694 7,182 7,705 8,225 8,780 9,372 10,004 10,679 11,396 12,162 12,979 13,851 14,782 Demand (MW) Low 793 814 836 859 898 938 980 1,024 1,070 1,113 1,157 1,203 1,251 1,301 1,353 1,407 1,463 1,521 1,582 Base 793 820 848 877 930 985 1,044 1,107 1,173 1,237 1,305 1,376 1,452 1,531 1,614 1,702 1,795 1,893 1,996 High 793 826 861 897 962 1,032 1,108 1,188 1,275 1,361 1,453 1,551 1,655 1,767 1,886 2,012 2,148 2,292 2,446 Energy (GWh) Kenya Power & Lighting Company March 2004 Low 4,693 4,842 4,995 5,200 5,491 5,760 5,991 6,231 6,481 6,740 7,009 7,288 7,578 7,879 8,191 8,515 8,852 9,208 9,583 Base 4,667 4,851 5,043 5,314 5,688 6,051 6,385 6,737 7,078 7,466 7,907 8,339 8,794 9,273 9,777 10,307 10,867 11,461 12,092 High 4,641 4,860 5,089 5,431 5,888 6,337 6,769 7,230 7,721 8,244 8,801 9,395 10,027 10,701 11,420 12,185 13,000 13,875 14,812 Demand (MW) Low 780 805 830 861 910 954 993 1,033 1,075 1,118 1,163 1,209 1,257 1,307 1,359 1,413 1,470 1,529 1,592 Base 774 805 837 880 943 1,003 1,059 1,118 1,180 1,245 1,314 1,386 1,462 1,542 1,626 1,715 1,808 1,908 2,013 High 768 805 843 900 976 1,051 1,124 1,201 1,283 1,370 1,463 1,563 1,669 1,782 1,902 2,030 2,167 2,313 2,470 Tanzania : Tabulated Load Forecast Data 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Energy (GWh) Tanesco Master Plan - 2004 Reduced Industrial 2708 2910 3128 3362 3613 3883 4173 4485 4820 5021 5230 5448 5675 5911 6158 6415 6683 6961 7252 Full Industrial 2708 2937 3186 3456 3749 4066 4410 4784 5189 5519 5869 6242 6638 7060 7310 7568 7836 8113 8400 Demand (MW) Reduced Industrial 475 510 548 589 633 680 731 785 844 879 916 955 995 1,037 1081 1126 1174 1223 1,275 Full Industrial 475 517 563 613 667 726 791 861 937 990 1046 1106 1169 1,235 1279 1325 1373 1422 1,473 Energy (GWh) East African Power Master Plan Study - March 2005 Low 2,800 2,937 3,080 3,230 3,358 3,492 3,631 3,775 3,925 4,065 4,209 4,359 4,514 4,675 4,838 5,007 5,182 5,363 5,550 Base 2,800 3,016 3,249 3,500 3,708 3,928 4,161 4,408 4,670 4,881 5,102 5,332 5,573 5,825 6,085 6,356 6,640 6,936 7,245 High 2,800 3,081 3,390 3,730 4,034 4,363 4,719 5,104 5,520 5,809 6,113 6,433 6,770 7,125 7,498 7,890 8,303 8,738 9,195 Demand (MW) Low 500 525 552 580 606 632 660 690 720 745 771 798 826 855 885 916 948 981 1,015 Base 500 540 583 630 669 710 754 801 850 888 928 970 1,014 1,060 1,108 1,157 1,209 1,263 1,320 High 500 554 614 680 740 804 875 952 1,035 1,087 1,142 1,200 1,261 1,325 1,393 1,464 1,539 1,617 1,700 SSEA III - Final Report E-48 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Uganda : Tabulated Load Forecast Data 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Energy (GWh) Electricité de France Low 1,439 1,553 1,676 1,809 1,957 2,118 2,292 2,480 2,683 2,879 3,090 3,317 3,559 3,820 4,100 4,400 4,722 5,068 5,469 Base 1,502 1,626 1,759 1,904 2,064 2,238 2,426 2,631 2,852 3,064 3,292 3,538 3,801 4,084 4,388 4,715 5,066 5,443 5,896 High 1,550 1,680 1,800 1,989 2,150 2,325 2,500 2,700 3,000 3,236 3,490 3,764 4,060 4,379 4,723 5,094 5,494 5,926 6,360 Demand (MW) Low 274 295 319 344 372 403 436 472 510 548 588 631 677 727 780 837 898 964 1,041 Base 286 309 335 362 393 426 462 500 543 583 626 673 723 777 835 897 964 1,036 1,122 High 295 320 342 378 409 442 476 514 571 616 664 716 772 833 899 969 1,045 1,128 1,210 Energy (GWh) East African Power Master Plan Study - March 2005 Low 1,458 1,465 1,473 1,480 1,522 1,565 1,610 1,656 1,703 1,786 1,873 1,965 2,060 2,161 2,283 2,411 2,547 2,690 2,841 Base 1,507 1,564 1,623 1,684 1,789 1,901 2,020 2,146 2,280 2,467 2,670 2,889 3,126 3,383 3,659 3,957 4,280 4,629 5,007 High 1,545 1,650 1,752 1,849 2,050 2,240 2,450 2,675 2,751 3,021 3,318 3,644 4,003 4,396 4,819 5,283 5,792 6,350 6,961 Demand (MW) Low 274 276 277 279 285 291 297 304 310 324 338 353 369 385 405 426 448 471 496 Base 283 294 306 318 336 355 375 396 418 452 488 527 570 616 665 718 774 836 902 High 290 307 326 345 372 400 431 464 500 547 598 654 716 783 855 935 1,021 1,116 1,219 Burundi : Tabulated Load Forecast Data 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Energy (GWh) SSEA Phase I Report Low 146 157 167 178 187 197 207 217 227 238 250 262 275 288 302 316 332 348 365 Base 148 162 178 194 209 226 244 264 285 309 335 364 396 431 470 514 563 618 680 High 152 169 188 208 227 249 274 302 333 369 411 458 512 574 647 730 828 941 1,074 Demand (MW) Low 30 33 35 37 39 41 43 45 47 49 52 54 57 60 63 66 69 72 76 Base 31 34 37 40 43 47 51 55 59 64 70 75 82 89 98 107 117 128 141 High 32 35 39 43 47 52 57 63 69 77 85 95 106 119 134 152 172 195 223 Rwanda : Tabulated Load Forecast Data 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Energy (GWh) SSEA Phase I Report Low 232 239 246 254 262 271 297 324 334 344 355 366 378 390 403 417 432 447 463 Base 239 246 260 274 290 324 361 381 404 429 456 487 520 557 599 645 696 753 817 High 246 262 280 300 323 383 412 444 480 521 568 620 681 750 829 919 1,023 1,142 1,280 Demand (MW) Low 48 50 51 53 54 56 59 63 65 67 69 71 74 76 79 82 85 88 91 Base 50 51 54 57 60 65 70 74 79 84 89 96 102 110 118 127 138 149 162 High 51 54 58 62 67 75 81 87 94 103 112 123 135 149 165 183 204 228 256 SSEA III - Final Report E-49 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Forecast Calculations for East Democratic Republic of Congo North Kivu 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total population ('000) 4,411 4,530 4,653 4,778 4,907 5,040 5,176 5,316 5,459 5,606 5,758 5,913 6,073 6,237 6,405 6,578 6,756 6,938 7,126 Rural Demand Estimate Rural Population ('000) 3,000 3,081 3,164 3,249 3,337 3,427 3,520 3,615 3,712 3,812 3,915 4,021 4,130 4,241 4,356 4,473 4,594 4,718 4,845 Households ('000) 429 440 452 464 477 490 503 516 530 545 559 574 590 606 622 639 656 674 692 Number of lodgings ('000) 429 440 452 464 477 490 503 516 530 545 559 574 590 606 622 639 656 674 692 Rate of electrification 1.34% 1.47% 1.62% 1.78% 1.95% 2.15% 2.36% 2.59% 2.85% 3.14% 3.45% 3.79% 4.16% 4.58% 5.03% 5.53% 6.08% 6.69% 7.35% Customers ('000) 6 6 7 8 9 11 12 13 15 17 19 22 25 28 31 35 40 45 51 Consumption (MWh/y)- Low 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 -Base 1.20 1.21 1.22 1.24 1.25 1.26 1.27 1.29 1.30 1.31 1.33 1.34 1.35 1.37 1.38 1.39 1.41 1.42 1.44 -High 1.20 1.22 1.25 1.27 1.30 1.32 1.35 1.38 1.41 1.43 1.46 1.49 1.52 1.55 1.58 1.62 1.65 1.68 1.71 Losses - Low 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% -Base 10.0% 9.9% 9.8% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 9.0% 8.9% 8.8% 8.7% 8.6% 8.4% 8.3% 8.2% 8.1% 8.0% -High 10.0% 9.8% 9.6% 9.3% 9.1% 8.9% 8.7% 8.4% 8.2% 8.0% 7.8% 7.6% 7.3% 7.1% 6.9% 6.7% 6.4% 6.2% 6.0% Rural Energy - Low 8 9 10 11 12 14 16 18 20 23 25 29 32 37 41 47 53 59 67 Forecast (GWh) - Base 8 9 10 11 13 15 17 19 21 24 28 32 36 41 47 53 61 69 79 - High 8 9 10 11 13 15 17 20 23 26 30 35 40 46 53 61 70 80 92 Urban Demand Estimate Urban Population (000) 1,412 1,450 1,489 1,529 1,570 1,613 1,656 1,701 1,747 1,794 1,843 1,892 1,943 1,996 2,050 2,105 2,162 2,220 2,280 Households ('000) 202 207 213 218 224 230 237 243 250 256 263 270 278 285 293 301 309 317 326 Number of lodgings ('000) 67 69 71 73 75 77 79 81 83 85 88 90 93 95 98 100 103 106 109 Rate of electrification 19% 20% 21% 22% 23% 24% 25% 26% 27% 28% 29% 30% 31% 32% 33% 34% 35% 35% 35% Customers ('000) 13 14 15 16 17 18 20 21 22 24 25 27 29 30 32 34 36 37 38 Specific consumption per household (MWh/year) 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 Specific consumption - Low 4.59 4.59 4.59 4.59 4.50 4.41 4.32 4.24 4.16 4.08 4.00 3.92 3.84 3.77 3.69 3.62 3.55 3.48 3.41 per lodging -Base 4.59 4.59 4.59 4.59 4.54 4.50 4.46 4.41 4.37 4.33 4.28 4.24 4.20 4.16 4.12 4.08 4.04 4.00 3.96 (MWh/year) -High 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 4.59 Losses - Low 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% -Base 10.0% 9.9% 9.8% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 9.0% 8.9% 8.8% 8.7% 8.6% 8.4% 8.3% 8.2% 8.1% 8.0% -High 10.0% 9.8% 9.6% 9.3% 9.1% 8.9% 8.7% 8.4% 8.2% 8.0% 7.8% 7.6% 7.3% 7.1% 6.9% 6.7% 6.4% 6.2% 6.0% Urban Energy - Low 64 70 75 81 85 89 94 98 103 107 112 116 121 126 131 136 141 142 143 Forecast (GWh) - Base 64 70 75 81 86 91 96 101 107 113 119 125 131 137 144 151 157 160 162 - High 64 70 75 80 86 92 98 105 112 119 126 133 141 150 158 167 176 180 185 ENERGY - Low 72 78 85 92 97 103 109 116 123 130 137 145 154 163 172 182 193 201 210 FORECAST - Base 72 78 85 92 98 105 113 120 129 137 147 156 167 178 191 204 218 229 241 (GWh) - High 72 78 85 92 99 107 116 125 135 145 156 168 181 196 211 228 246 261 277 DEMAND - Low 16 17 19 20 21 23 24 25 27 28 30 32 34 36 38 40 42 44 46 FORECAST - Base 16 17 19 20 22 23 25 26 28 30 32 34 37 39 42 45 48 50 53 (MW) - High 16 17 19 20 22 24 25 27 30 32 34 37 40 43 46 50 54 57 61 SSEA III - Final Report E-50 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT South Kivu 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total population ('000) 3,512 3,607 3,704 3,804 3,907 4,012 4,121 4,232 4,346 4,464 4,584 4,708 4,835 4,965 5,100 5,237 5,379 5,524 5,673 Rural Demand Estimate Rural Population ('000) 2,388 2,453 2,519 2,587 2,657 2,728 2,802 2,878 2,955 3,035 3,117 3,201 3,288 3,377 3,468 3,561 3,657 3,756 3,858 Households ('000) 341 350 360 370 380 390 400 411 422 434 445 457 470 482 495 509 522 537 551 Number of lodgings ('000) 341 350 360 370 380 390 400 411 422 434 445 457 470 482 495 509 522 537 551 Rate of electrification 4.03% 4.43% 4.87% 5.35% 5.89% 6.47% 7.11% 7.82% 8.59% 9.45% 10.39% 11.42% 12.55% 13.80% 15.17% 16.67% 18.33% 20.15% 22.15% Customers ('000) 14 16 18 20 22 25 28 32 36 41 46 52 59 67 75 85 96 108 122 Consumption (MWh/y)- Low 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 -Base 1.20 1.21 1.22 1.24 1.25 1.26 1.27 1.29 1.30 1.31 1.33 1.34 1.35 1.37 1.38 1.39 1.41 1.42 1.44 -High 1.20 1.22 1.25 1.27 1.30 1.32 1.35 1.38 1.41 1.43 1.46 1.49 1.52 1.55 1.58 1.62 1.65 1.68 1.71 Losses - Low 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% -Base 10.0% 9.9% 9.8% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 9.0% 8.9% 8.8% 8.7% 8.6% 8.4% 8.3% 8.2% 8.1% 8.0% -High 10.0% 9.8% 9.6% 9.3% 9.1% 8.9% 8.7% 8.4% 8.2% 8.0% 7.8% 7.6% 7.3% 7.1% 6.9% 6.7% 6.4% 6.2% 6.0% Rural Energy - Low 18 20 23 26 29 33 38 42 48 54 61 69 78 88 99 112 126 143 161 Forecast (GWh) - Base 18 21 24 27 31 35 40 45 51 59 67 76 87 99 112 128 146 166 189 - High 18 21 24 28 32 36 42 48 55 63 73 84 96 111 127 146 168 193 222 Urban Demand Estimate Urban Population (000) 1,124 1,154 1,185 1,217 1,250 1,284 1,319 1,354 1,391 1,428 1,467 1,506 1,547 1,589 1,632 1,676 1,721 1,768 1,815 Households ('000) 161 165 169 174 179 183 188 193 199 204 210 215 221 227 233 239 246 253 259 Number of lodgings ('000) 54 55 56 58 60 61 63 64 66 68 70 72 74 76 78 80 82 84 86 Rate of electrification 19% 20% 21% 22% 23% 24% 25% 26% 27% 28% 29% 30% 31% 32% 33% 34% 35% 35% 35% Customers ('000) 10 11 12 13 14 15 16 17 18 19 20 22 23 24 26 27 29 29 30 Specific consumption per household (MWh/year) 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 1.47 Specific consumption - Low 4.40 4.40 4.40 4.40 4.31 4.23 4.15 4.07 3.99 3.91 3.83 3.76 3.68 3.61 3.54 3.47 3.40 3.34 3.27 per lodging -Base 4.40 4.40 4.40 4.40 4.36 4.31 4.27 4.23 4.19 4.15 4.11 4.07 4.03 3.99 3.95 3.91 3.87 3.83 3.80 (MWh/year) -High 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 4.40 Losses - Low 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% -Base 10.0% 9.9% 9.8% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 9.0% 8.9% 8.8% 8.7% 8.6% 8.4% 8.3% 8.2% 8.1% 8.0% -High 10.0% 9.8% 9.6% 9.3% 9.1% 8.9% 8.7% 8.4% 8.2% 8.0% 7.8% 7.6% 7.3% 7.1% 6.9% 6.7% 6.4% 6.2% 6.0% Urban Energy - Low 49 53 57 62 65 68 72 75 78 82 85 89 93 96 100 104 107 108 109 Forecast (GWh) - Base 49 53 57 62 65 69 73 77 82 86 91 95 100 105 110 115 120 122 124 - High 49 53 57 61 66 70 75 80 85 91 96 102 108 114 121 127 134 138 141 ENERGY - Low 67 74 81 88 94 102 109 117 126 136 146 158 170 184 199 216 234 251 270 FORECAST - Base 67 74 81 88 96 104 113 123 133 145 157 171 187 203 222 243 266 288 313 (GWh) - High 67 74 81 89 97 107 117 128 140 154 169 186 204 225 248 273 302 331 363 DEMAND - Low 15 16 18 19 21 22 24 26 28 30 32 35 37 40 44 47 51 55 59 FORECAST - Base 15 16 18 19 21 23 25 27 29 32 35 38 41 45 49 53 58 63 69 (MW) - High 15 16 18 20 21 23 26 28 31 34 37 41 45 49 54 60 66 73 80 SSEA III - Final Report E-51 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT ORIENTAL PROVINCE 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total population ('000) 1,802 1,888 1,979 2,076 2,178 2,287 2,403 2,525 2,655 2,776 2,904 3,038 3,180 3,330 3,489 3,656 3,832 4,092 4,369 Rural Demand Estimate Rural Population ('000) 1,135 1,189 1,246 1,307 1,371 1,440 1,513 1,590 1,672 1,748 1,828 1,913 2,002 2,097 2,197 2,302 2,413 2,576 2,751 Households ('000) 162 170 178 187 196 206 216 227 239 250 261 273 286 300 314 329 345 368 393 Number of lodgings ('000) 162 170 178 187 196 206 216 227 239 250 261 273 286 300 314 329 345 368 393 Rate of electrification 2.45% 2.69% 2.96% 3.25% 3.57% 3.93% 4.32% 4.75% 5.22% 5.74% 6.31% 6.93% 7.62% 8.38% 9.21% 10.12% 11.13% 12.24% 13.45% Customers ('000) 4 5 5 6 7 8 9 11 12 14 16 19 22 25 29 33 38 45 53 Consumption (MWh/y) - Low 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 -Base 0.60 0.61 0.61 0.62 0.62 0.63 0.64 0.64 0.65 0.66 0.66 0.67 0.68 0.68 0.69 0.70 0.70 0.71 0.72 -High 0.60 0.61 0.62 0.64 0.65 0.66 0.68 0.69 0.70 0.72 0.73 0.75 0.76 0.78 0.79 0.81 0.82 0.84 0.86 Losses - Low 10% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10% -Base 10% 9.9% 9.8% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 9.0% 8.9% 8.8% 8.7% 8.6% 8.4% 8.3% 8.2% 8.1% 8.0% -High 10% 9.8% 9.6% 9.3% 9.1% 8.9% 8.7% 8.4% 8.2% 8.0% 7.8% 7.6% 7.3% 7.1% 6.9% 6.7% 6.4% 6.2% 6% Rural Energy - Low 3 3 3 4 5 5 6 7 8 9 11 13 14 17 19 22 25 30 35 Forecast (MWh) - Base 3 3 4 4 5 6 6 8 9 10 12 14 16 19 22 25 29 35 41 - High 3 3 4 4 5 6 7 8 9 11 13 15 18 21 24 29 34 40 48 Urban Demand Estimate Urban Population (000) 668 699 733 769 807 847 890 935 983 1,028 1,075 1,125 1,178 1,233 1,292 1,354 1,419 1,516 1,618 Households ('000) 95 100 105 110 115 121 127 134 140 147 154 161 168 176 185 193 203 217 231 Number of lodgings ('000) 32 33 35 37 38 40 42 45 47 49 51 54 56 59 62 64 68 72 77 Rate of electrification 39% 40% 41% 42% 43% 44% 45% 46% 47% 48% 49% 50% 51% 52% 53% 54% 55% 55% 55% Customers ('000) 12 13 14 15 17 18 19 20 22 24 25 27 29 31 33 35 37 40 42 Specific consumption per household (MWh/year) 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 Specific consumption - Low 1.80 1.80 1.80 1.80 1.76 1.73 1.70 1.66 1.63 1.60 1.57 1.54 1.51 1.48 1.45 1.42 1.39 1.36 1.34 per lodging -Base 1.80 1.80 1.80 1.80 1.78 1.76 1.75 1.73 1.71 1.70 1.68 1.66 1.65 1.63 1.62 1.60 1.58 1.57 1.55 (MWh/year) -High 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 Losses - Low 10% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10% -Base 10% 9.9% 9.8% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 9.0% 8.9% 8.8% 8.7% 8.6% 8.4% 8.3% 8.2% 8.1% 8.0% -High 10% 9.8% 9.6% 9.3% 9.1% 8.9% 8.7% 8.4% 8.2% 8.0% 7.8% 7.6% 7.3% 7.1% 6.9% 6.7% 6.4% 6.2% 6% Urban Energy - Low 25 26 28 30 32 34 36 37 39 41 43 45 47 50 52 54 57 60 62 Forecast (GWh) - Base 25 26 28 30 32 34 36 39 41 43 46 48 51 54 57 60 64 67 71 - High 25 26 28 30 32 35 37 40 43 46 49 52 55 59 63 67 71 76 81 ENERGY - Low 27 29 32 34 37 39 42 45 48 51 54 58 62 66 71 76 82 89 97 FORECAST - Base 27 29 32 34 37 40 43 46 50 54 58 62 67 73 79 85 93 102 112 (GWh) - High 27 29 32 34 37 41 44 48 52 57 62 67 73 80 87 96 105 116 129 DEMAND - Low 6 6 7 8 8 9 9 10 10 11 12 13 14 15 16 17 18 20 21 FORECAST - Base 6 6 7 8 8 9 9 10 11 12 13 14 15 16 17 19 20 22 25 (MW) - High 6 6 7 8 8 9 10 11 11 12 14 15 16 18 19 21 23 25 28 SSEA III - Final Report E-52 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Katanga 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total population ('000) 3,157 3,307 3,465 3,365 3,813 4,003 4,204 4,418 4,645 4,864 5,096 5,341 5,600 5,874 6,164 6,470 6,794 7,266 7,771 Rural Demand Estimate Rural Population ('000) 1,988 2,082 2,182 2,019 2,401 2,520 2,647 2,782 2,924 3,062 3,208 3,363 3,526 3,698 3,881 4,074 4,278 4,575 4,893 Households ('000) 284 297 312 288 343 360 378 397 418 437 458 480 504 528 554 582 611 654 699 Number of lodgings ('000) 284 297 312 288 343 360 378 397 418 437 458 480 504 528 554 582 611 654 699 Rate of electrification 4.03% 4.43% 4.87% 5.35% 5.89% 6.47% 7.11% 7.82% 8.59% 9.45% 10.39% 11.42% 12.55% 13.80% 15.17% 16.67% 18.33% 20.15% 22.15% Customers ('000) 11 13 15 15 20 23 27 31 36 41 48 55 63 73 84 97 112 132 155 Consumption (MWh/y)- Low 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 -Base 0.70 0.71 0.71 0.72 0.73 0.74 0.74 0.75 0.76 0.77 0.77 0.78 0.79 0.80 0.80 0.81 0.82 0.83 0.84 -High 0.70 0.71 0.73 0.74 0.76 0.77 0.79 0.80 0.82 0.84 0.85 0.87 0.89 0.91 0.92 0.94 0.96 0.98 1.00 Losses - Low 10% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10% -Base 10% 9.9% 9.8% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 9.0% 8.9% 8.8% 8.7% 8.6% 8.4% 8.3% 8.2% 8.1% 8.0% -High 10% 9.8% 9.6% 9.3% 9.1% 8.9% 8.7% 8.4% 8.2% 8.0% 7.8% 7.6% 7.3% 7.1% 6.9% 6.7% 6.4% 6.2% 6% Rural Energy - Low 9 10 12 12 16 18 21 24 28 32 37 42 49 56 65 75 86 101 119 Forecast (GWh) - Base 9 10 12 12 16 19 22 25 30 34 40 47 54 63 73 85 99 118 140 - High 9 10 12 13 17 20 23 27 32 37 44 51 60 71 83 98 115 137 164 Urban Demand Estimate Urban Population (000) 1,169 1,225 1,283 1,346 1,412 1,482 1,557 1,636 1,720 1,801 1,887 1,978 2,074 2,176 2,283 2,396 2,516 2,691 2,878 Households ('000) 167 175 183 192 202 212 222 234 246 257 270 283 296 311 326 342 359 384 411 Number of lodgings ('000) 56 58 61 64 67 71 74 78 82 86 90 94 99 104 109 114 120 128 137 Rate of electrification 39% 40% 41% 42% 43% 44% 45% 46% 47% 48% 49% 50% 51% 52% 53% 54% 55% 55% 55% Customers ('000) 22 23 25 27 29 31 33 36 39 41 44 47 50 54 58 62 66 70 75 Specific consumption per household (MWh/year) 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 Specific consumption - Low 2.10 2.10 2.10 2.10 2.06 2.02 1.98 1.94 1.90 1.86 1.83 1.79 1.76 1.72 1.69 1.66 1.62 1.59 1.56 per lodging -Base 2.10 2.10 2.10 2.10 2.08 2.06 2.04 2.02 2.00 1.98 1.96 1.94 1.92 1.90 1.88 1.87 1.85 1.83 1.81 (MWh/year) -High 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 2.10 Losses - Low 10% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10% -Base 10% 9.9% 9.8% 9.7% 9.6% 9.4% 9.3% 9.2% 9.1% 9.0% 8.9% 8.8% 8.7% 8.6% 8.4% 8.3% 8.2% 8.1% 8.0% -High 10% 9.8% 9.6% 9.3% 9.1% 8.9% 8.7% 8.4% 8.2% 8.0% 7.8% 7.6% 7.3% 7.1% 6.9% 6.7% 6.4% 6.2% 6% Urban Energy - Low 50 54 58 62 65 69 73 76 81 84 89 93 97 102 107 112 118 123 129 Forecast (GWh) - Base 50 54 58 62 66 70 74 79 84 89 94 99 105 111 118 125 132 139 147 - High 50 54 58 62 66 71 76 82 87 93 100 106 114 121 129 138 147 157 168 ENERGY - Low 59 64 70 74 81 87 93 100 108 116 125 135 146 158 172 187 204 225 249 FORECAST - Base 59 64 70 74 82 89 96 104 114 123 134 146 159 174 191 210 231 257 287 (GWh) - High 59 64 70 74 83 91 99 109 119 131 143 158 174 192 212 236 262 294 332 DEMAND - Low 13 14 15 16 18 19 20 22 24 26 27 30 32 35 38 41 45 49 55 FORECAST - Base 13 14 15 16 18 19 21 23 25 27 29 32 35 38 42 46 51 57 63 (MW) - High 13 14 15 16 18 20 22 24 26 29 31 35 38 42 47 52 57 65 73 SSEA III - Final Report E-53 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT Maniema (Kabambare)* 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Energy Forecast (GWh) 0.4 0.4 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.9 0.9 1.0 1.0 Peak Demand (MW) 0.09 0.10 0.10 0.11 0.11 0.12 0.13 0.13 0.14 0.15 0.15 0.16 0.17 0.18 0.19 0.19 0.20 0.21 0.22 East DRC 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 ENERGY - Low 226 245 267 288 310 331 354 378 405 433 463 496 532 571 614 661 713 766 825 FORECAST - Base 226 246 267 289 313 338 365 394 425 459 496 536 580 629 683 742 808 877 954 (GWh) - High 226 246 268 290 317 345 376 410 447 486 530 579 632 692 758 832 915 1,002 1,101 DEMAND - Low 50 54 59 63 68 73 78 83 89 95 102 109 117 125 135 145 157 168 181 FORECAST - Base 50 54 59 63 69 74 80 86 93 101 109 118 127 138 150 163 177 192 209 (MW) - High 50 54 59 64 70 76 83 90 98 107 116 127 139 152 166 183 201 220 242 *Estimation based on SNEL Masterplan results SSEA III - Final Report E-54 017334-001-00 APPENDIX E - LOAD FORECAST SUPPORT SSEA III - Final Report E-55 017334-001-00 APPENDIX F IDENTIFICATION OF NEW POWER OPTIONS SSEA III - Final Report 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS TABLE OF CONTENTS PAGE F IDENTIFICATION OF NEW POWER OPTIONS F-1 F.1 Objectives F-1 F.2 New Hydroelectric Generation Options F-2 F.2.1 EAC Region - Kenya, Tanzania and Uganda F-4 F.2.2 SSEA I Region - Burundi, Rwanda and Western Tanzania F-5 F.2.3 Eastern DRC F-8 F.3 Thermal Power Options F-15 F.3.1 EAC Region - Kenya, Tanzania and Uganda F-15 F.3.2 SSEA I Region - Burundi, Rwanda and Western Tanzania F-19 F.3.3 Eastern DRC F-22 F.3.4 NELSAP Region ­ Candidate New thermal Power Options F-22 F.4 Biomass F-22 F.5 Wind Energy Conversion Systems F-26 F.6 Demand Side Management and Loss Reduction F-32 F.7 Transmission and Interconnections F-33 F.7.1 Imports from Outside the NELSAP Region F-35 F.7.2 Interconnections Within the NELSAP Region to Supply the SSEA 1 Region F-35 F.8 Off-grid Options F-36 F.8.1 Mini/Micro Hydroelectric Power F-36 F.8.2 Diesel F-38 F.8.3 Solar PV F-38 SSEA III - Final Report F-i 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS F IDENTIFICATION OF NEW POWER OPTIONS F.1 Objectives This appendix provides an inventory of candidate new generation options to meet the forecast power needs of the region. The NELSAP study area includes three components: The region covered by the Phase 1 of this program, i.e., Burundi, Rwanda, and Western Tanzania (presently not connected to the main Tanzania grid); The EAC countries of Kenya, Tanzania and Uganda; The Eastern Democratic Republic of the Congo. It should be noted that this study is considering the region as a whole. Thus small generation units, or options such as demand side management, are treated in terms of regional demands. Specific country interests may identify other priorities for meeting local loads. The first step was to establish an inventory of identified new generation options, and then to complement this list of known resources with conventional appropriate generic thermal options, which may become preferred options, depending on lead time for implementation, cost, diversity of location, size and other factors. This inventory is made up from projects identified in three separate previous reports, one for each area,1 2 3 with further reference to the original study reports. The initial inventory included all previously identified projects, whether or not they had been rejected in the previous studies. As generation cost from any given project is only one of the factors that are taken into account, it was important to include all identified projects in the starting list of candidates, and then to apply a common set of criteria to all candidate projects. As this is a regional study it is implicit that this process should be based on energy demands and supply options for the interconnected systems. However information has also been provided on some off-grid options such as solar power PV, mini/micro hydropower, wind energy conversion systems and diesel. Indicative costs and potential application for these generic options (i.e., not assessed on a site specific basis) provide useful context for assessing cost and performance of on-grid options that are the target for this assessment. The potential for "Demand Side Management" to reduce new generation requirements is also noted. The scope of the power options identification component covered the following: Compilation of basic information on previously identified new hydroelectric sites, including generation capability, capital cost and, very importantly, the level of preparation and project status that, to a large degree, defines earliest possible on- power dates. For the EAC countries the candidate projects were primarily limited to 1 NBI/NELSAP ­ Final Report Strategic/Sectoral and Environmental Assessment of Power Development Options in the Nile Equatorial Region ­ Stage 1 ­ Burundi, Rwanda and Western Tanzania, February 2005. SNC- Lavalin 2EAC ­ Eastern African Power Master Plan Study, final Phase II Report, March 2005, BKS Acres 3 NBI/NELSAP ­ Strategic/Sectorial and Environmental Assessment of Power Development Options in the Nile Equatorial Region ­ Stage II ­ Preliminary Evaluation of New Power Options in Eastern Democratic Republic of Congo ­ April 2005, SNC-Lavalin SSEA III - Final Report F-1 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS those evaluated in the least cost generation plan, however the Songwe and Magwagwa projects were added; Identification of generic and specific thermal alternatives, including diesel engines, gas fired engines, combined cycle, oil and coal fired steam plants. Thermal options included specific projects at the planning stage, such as the proposed Mchuchuma coal fired steam plant in Kenya, and generic options, such as new coal fired thermal plant in the Mombasa region; Evaluating the status of each candidate new power option, in terms of studies that have already been carried out, and estimating the probable minimum lead time for the implementation of the project, including further investigations, financing, design and construction, thereby establishing the probable earliest on-power date; Preparing a long list of candidate projects, that potentially could be economic, and implemented within the time horizon of the study, i.e., before year 2020. F.2 New Hydroelectric Generation Options An initial objective of the assessment was to identify all the hydroelectric sites that had been assessed in the past. However the study concept is that candidate projects should be selected in the context of meeting regional loads, and thus be able to provide benefits in neighbouring countries. This resulted in the selection of an approximate lower limit of 30 MW in the EAC, and 10 MW in the DRC and SSEA I regions. New options of hydroelectric generation were compiled and evaluated in three previous studies: EAC ­ Eastern African Power Master Plan Study, final Phase II Report, March 2005. NBI/NELSAP ­ Strategic/Sectoral and Environmental Assessment of Power Development Options in the Nile Equatorial Region ­ Stage 1 ­ Burundi, Rwanda and Western Tanzania, February 2005. NBI/NELSAP ­ Strategic/Sectoral and Environmental Assessment of Power Development Options in the Nile Equatorial Region ­ Stage II ­ Preliminary Evaluation of New Power Options in Eastern Democratic Republic of Congo ­ April 2005. The locations of the existing and identified future generation sources, and associated primary transmission is shown in Figure F-1. SSEA III - Final Report F-2 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Figure F-1- NEL Region - Identified Options and Existing Transmission Lines SSEA III - Final Report F-3 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS These identified hydroelectric options are summarised in the following subsection by sub- region. Further information on the options that passed the first level screening is given in the project data sheets in Appendix H. Capital costs and corresponding generation costs are shown in Appendix F, as part of the screening process. F.2.1 EAC Region - Kenya, Tanzania and Uganda The EAPMP included an extensive review of past reports on hydroelectric prospects in each of the three countries. A total of 15 sites were considered as candidates, excluding Bujagali, which the study treated as committed, and counting Ayago as one project (Ayago North and Ayago South being alternative scheme to develop the head at the same site). The candidate list was drawn from studies that ranged from outline concepts to fully detailed tender stage design. The following table, Table F-1, is taken directly from the EAPMP systems analysis report4 for record purposes. Table F-1 - EAC Candidate Hydro Projects (EAPMP) Installed Capital Average Project Location Capacity Cost Annual Energy (MW) (US$ x106) (GWh) Bujagali 5th Unit Uganda 50 26.4 222 Kalagala Uganda 450 511.6 2,525 Karuma Uganda 200 428.9 1,747 Ayago North Uganda 304 557.6 2,624 Ayago South Uganda 234 437.2 2,050 Murchison Falls Uganda 420 511.7 3,679 Masindi Uganda 720 1,633.3 5,318 Ewaso Ngiro Kenya 220 385.9 609 Mutonga Kenya 60 196.7 328 Low Grand Falls Kenya 140 378.3 715 Upper Kihansi Tanzania - 81.2 11 Mpanga Tanzania 144 190.8 1,028 Masigira Tanzania 118 157.0 695 Ruhudji Tanzania 358 384.0 1,930 Rumakali Tanzania 222 351.3 1,141 Mandera Tanzania 21 42.1 149 Stiegler's Gorge Tanzania 1200 1,067.7 6,203 To the above list should be added Bujagali Unit 1-4 (200 MW), and it should be noted that for Murchison Falls and Ayago various alternatives have been considered. Also the Masindi project would be developed in two equal phases of 360 MW each, and Stiegler´s Gorge would be developed in three phases. 4 BKS Acres East African Power Master Plan Study - System Analysis Report - Table 2.5 - December 2004 SSEA III - Final Report F-4 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS The EAPMP only considered projects with installations above 30 MW. The hydroelectric projects that were retained by BKS Acres as candidate generation unit additions for developing the generation expansion sequences in the EAPMP are shown in Table F-2. Table F-2 - EAC Retained Hydroelectric Projects (EAPMP) Total Capacity Project (MW) Bujagali 5th Unit 50 Mpanga 144 Ruhudji 358 Kalagala 450 Masigira 118 Ayago North 304 Karuma 200 Ayago South 234 Mandera 21 Rumakali 222 The above table and further information on these sites is given in the EAPMP report5. The full list of EAC candidate projects is shown in Table F-3. However this table includes the Songwe and Magwagwa projects that were not included in the EAPMP assessment. Project locations are shown in Figure F-1. F.2.2 SSEA I Region - Burundi, Rwanda and Western Tanzania The projects identified from the previous study for the SSEA I region are listed in Table 5-4. Ruzizi I is a rehabilitation program, which has been committed. This project will increase peak capacity and ensure continued energy generation at the plant. This project has been approved as part of a short-term action plan, and therefore is not part of the project comparison process. Igamba Falls Stage II is one of the options for the Malagarasi River. The project concept was for power supply to Kigoma only67. Thus this site needs to be re-evaluated as a large project to make better use of the available flow of the Malagarasi River and head at the site (see recommendation in Section 10.2. 5BKS-Acres ­ East African Power Master Plan Study ­ Phase II Final Report ­ March 2005 6 Norconsult, Malagarasi Hydropower Project ­ Kigoma Region, Feasibility Study Report, volume 1, TANESCO/NORAD, August 1983 7SECSD (P) Ltd., Joint UNDP/ESMAP, Tanzania Mini Hydropower Study, Kigoma Region, Pre-Investment Report on Mini Hydropower Development, Case Study on the Malagarasi River , March 2000 and October 1999 SSEA III - Final Report F-5 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Table F-3 - EAC Hydroelectric Projects Installed Average Firm Name Original Cost US $ MILLION Capacity Energy Energy (MW) (GWh) (GWh) Uganda Ayago North 1-4 446.60 228 1981 1981 Ayago North 5-6 111.00 76 643 643 Ayago South 437.20 234 2050 2050 Bujagai 5 26.40 50 222 14 Bujagali 1-4 395.00 200 1703 1390 Kalagala 1-7 444.70 315 2364 1697 Kalagala 8-10 66.80 135 161 0 Karuma 428.90 200 1748 1619 Masindi - 2 729.40 360 2302 1798 Masindi -1 903.80 360 3016 2615 Murchison 1-6 phase 2 349.30 315 2759 2759 Murchison 7-8 78.40 105 920 920 Kenya Ewaso Ngiro 385.90 220 609 448 Low Grand Falls 378.30 140 715 324 Magwagwa 294.50 120 669 244 Mutonga 196.7 60 328 293 Tanzania Mandera 42.10 21 149 109 Masigira 157.00 118 695 528 Mpanga 190.80 144 1028 863 Ruhudji 384.00 358 1930 1476 Rumakali 351.30 222 1141 1170 Stiegler Gorge 1 653.40 300 2715 2598 Stiegler Gorge 2 233.00 600 2525 693 Stiegler Gorge 3 191.30 300 963 1754 Songwe (3 dams-P4) 359.00 330 1352 1352 Upper Kinansi 81.20 0 124 11 SSEA III - Final Report F-6 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Table F-4 - List of Identified SSEA I Projects ­ by Country Name Study Installed capacity level (MW) Tanzania Igamba Falls Stage 2 PF 8.0 Igamba Falls FSL 980 m PF 80.0 Igamba Falls FSL 865 m R 11.4 Kishanda PF 207.0 Kakono (High) PF 53.0 Luiche R 15.3 Malagarasi Cascade: R 40.0 Rusumo Falls (Full) D 61.5 Rusumo Falls (no reservoir) F 50.4 Rusumo Falls (low Head) R 34.1 Rwanda Nyabarongo F 27.8 Ruzizi I rehab F 8.7 Ruzizi III PF 82.0 Burundi Jiji 03 PF 15.5 Kabu 16 F 20.0 Kaburantwa F 14.6 Kaganuzi A R 34.0 Kaganuzi C F 16.4 Kaganuzi D R 24.6 Mpanda F 10.4 Mule 34 PF 16.5 Siguvyaye F/D 90.0 D = detailed design; F = feasibility; PF = pre-feasibility; R = reconnaissance Malagarasi Cascade would include Uvinza, Igamba Falls Stages 1,2,3, and Illagala sites SSEA III - Final Report F-7 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS F.2.3 Eastern DRC At the 6th PSC meeting in Uganda on December 1, 2004, it was agreed that the study area in eastern DRC should be extended beyond Kivu South and Kivu North provinces to the Oriental province and the northern portion of the Katanga province, thus options in the DRC beyond this region should be dealt with as import options. Consequently the identification of options in the DRC in this Stage II program is limited to parts of the following provinces, each of which includes some watershed area within the Nile Basin (see shaded area in Figure 5-2). Oriental; Kivu North; Kivu South; Maniema; Katanga. The most important of the existing and potential hydroelectric resources in the DRC are in the western part of the country, on the lower reaches of the Congo River. Such potential resources outside the study area can be taken into account through interconnections, where the availability and timing of such new generation can be reasonably established. In reality the candidate resources from western DRC would be additional generation that would result from the rehabilitation of the existing Inga 1 and 2 plants. A number of studies have been carried out in the DRC, particularly in the period from 1970 to 1985, with the objective of identifying renewable generation sources to offset the sharp rise in thermal fuel costs in the early 1970s. These studies took the form of inventories in different regions of the country. Relevant to the SSEA study area are the following studies and reports: 1972 Reconnaissance of hydroelectric resources in the North-East, by SICAI- Tractionel8 This study covers two components: - the Ruzizi River, including three sites: Panzi 36 MW (4 x 9 MW) Kitimba 34 MW (4 x 8.5 MW) Kamaniola 240 MW (4 x 60 MW or 390 MW) ­ diversion into Luvimva River, and - the Lualaba River for the development of 38 m of head available between Kisangani and Ubundu. This study identified two sites, Kisangani and Wanie Rukula, for a total installation in the order of 1000 MW. 8 Reconnaissance des ressources hydro-électriques dans le nord-est, Vol2 ­ esquisses d´aménagements, SICAI- Tractionel, Juin 1972 SSEA III - Final Report F-8 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Figure F-2 - Eastern DRC - Project Area This study also considered smaller sites to supply Kisangani, such as the Tshopo site with 50-75 MW, possible extension to the existing Kiymbi plant, and mini-hydro options. These studies were at the reconnaissance level; however, they mostly used 1:5000 scale mapping and resulted in relatively detailed quantity and cost estimates. 1972 Energy study of Kivu Province, by Energoprojekt, in collaboration with the Office National de la Recherche et du Development of Zaire (ONRD)9 This study included demand forecasts, and alternative new generation sources, primarily hydroelectric generation. Generation from Lake Kivu gas, and from diesel was also evaluated. Hydroelectric sites of more than 10 MW from this study are included in Table 5-5, however with data added from the 1994 report by Male Cifarha10. The most important sites are: Sisi on the Ruzizi River with 110 MW (note different alternatives /installations for this site have been proposed in other studies); 9Étude du système électroénergétique de la Province du Kivu, Energoprojekt y ONRD, 1972 10Les ressources hydro-électriques du Zaïre ­ Male Cifarha, 1994 SSEA III - Final Report F-9 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Ruzizi on the Ruzizi River with 270 MW ­ diversion into Luvimva River. (This scheme is approximately the same as the Kamanyola or Kamaniola projects referred to in other reports); Mugombo on the Lubero River with 40 MW. These site evaluations are at the reconnaissance level. There are no detailed site descriptions, quantity or cost estimates in the report. Basic quantities are provided. 1982 Inventory study of hydroelectric sites for mini or micro hydroelectric development, SEEE and OCCR-Inter G11 This report covers sites in four locations and, despite the title, includes mid-sized projects. Kisangani (Oriental Province) ­ this part of the study evaluated the sites of Wagenia, Bengamisa and Wanie-Rukula. (This report also referred to a study of the Wagenia site by Sogreah in 1972). Yamgambi (Oriental Province) ­ to supply the town of Yamgambi on the Congo, 100 km downstream of Kisangani. This part of the study considered a site on the Lobilo of 800 kW. Mbandaka (Oriental Province) ­ to supply the town. A site of 5 MW was evaluated. Tshimbubulu (Kasai Province) ­ to evaluate alternative small sites for supply to the town. Nepoko (Oriental Province) ­ the site on the Nepoko River, 90 km south of Isiro, was determined to have an available flow of 240 m3/s and a head of 70 m ­ providing the possibility of up to 134 MW of installed capacity. An installation of 6 MW to meet local loads only was suggested. These studies were all at the very preliminary or reconnaissance stage. 1992 Regional energy master plan ­ study of the hydroelectric potential of the Ruzizi valley ­ by Tractebel for EGL12 Development on the Ruzizi River has been the subject of studies since the 1980s, both on behalf of SNEL and Energie des Pays des Grand Lacs (EGL). These studies and the sites that were identified have been the subject of considerable discussion during the current study, and therefore these are outlined below. In 1992 Tractebel completed an assessment of the hydroelectric potential of the river that consisted of two parts. Phase 1 provided for the identification of sites, which included comparison of 13 alternative base lines or dam sites, and Phase II was a prefeasibility study of the preferred (RD 2) site. The Ruzizi River may be considered in two sections, the reach between Ruzizi I and Ruzizi II, which has a total drop of 44 metres, and the section downstream of Ruzizi II between the plant tailrace and the plains areas above Kamanyola, which has a total drop of 400 metres. 11 Études inventaires des sites hydrauliques en vue de leur équipement avec des mini ou microcentrales hydro- électriques au Zaïre, S.E.E.E ­ O.C.C.R.-INTER G 12 Plan directeur régional de développement de l'énergie ­ Rapport No 2 ­ Étude du potentiel hydroélectrique de la vallée de la Ruzuzi, Tractebel, Octobre 1992 SSEA III - Final Report F-10 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS One site named Panzi had been studied in the upper reach by SICAI in 1972. The Tractebel study changed the baseline location and renamed the site Panzi Amont (Upstream). In the downstream section, a single site at Kamanyola to develop most of the head downstream of Ruzizi II by diversion into the adjacent Luvimvi River had been studied earlier ­ 1972 study by SICAI (project referred to as Kamanyola), and was re-examined by Tractebel (project referred to as Ruzizi). Other options evaluated in more detail included the following: Five options were considered for the Sisi bend (méandre de Sisi) immediately downstream of Ruzizi 2. (Sisi 1/2/3/4/5). Depending on the baseline, the installation would be between 160 and 207 MW. The 1992 study considered that such a development was too large for limited loads in the sub-region, and in any case extensive investigations would be required to further evaluate the site. The Sisi 3 or 5 scheme represents a major potential with low generation cost and should be studied further in the context of regional power supply). Downstream of the Sisi bend two alternative baselines for the RA site were considered. These would have developed 60 to 75 metres of head, with corresponding installations of 77 and 97 MW. These sites were negatively assessed due to the presence of a large active slide. The RB site further downstream would develop 36 metres of head and result in an installation of 46 MW. The next set of baselines was coded RC1, RC2 and RC2 bis. These sites would develop between 27 and 48 metres of head, corresponding to installation between 34 and 61 MW. The next set of baselines downstream were coded RD1/2/3/4/5. In effect RD 1 and 3 are at one site, and RD 2 and 4 at another site slightly farther downstream. Developed heads ranged from 60 (RD2) to 76 metres (RD3), and nominal installations were between 77 and 93 MW. The RD2 site, that was later identified as the preferred development and named Ruzizi 3, would develop 76 metres of head and have a nominal installation of 77 MW (later revised to 82 MW). The RD 5 site immediately downstream would be similar to a head of 46 to 455 metres and installation of 60 to 71 MW, depending on the scheme. The most downstream site was coded RE and would develop 56 metres of head, corresponding to an installation of 73 MW. The projects were ranked on the basis of cost per kW. This showed that two groups of alternatives were the most attractive: the sites on the Sisi bend, and the alternatives at, or close to, the site now known as Ruzizi III. The study then ranked combinations or portfolios of projects. This included comparison of Sisi 3 in a portfolio with RD4, RA1 and Panzi. The Sisi single plant development was the most expensive option for meeting the demand for the next 30 years, while the plan with the RD4 site was the least cost. This result clearly illustrated the penalty from the large size of the Sisi scheme when considered only in relation to the local demand. The Phase II Tractebel study then evaluated the RD site to a prefeasibility level. During this more detailed study the RD2 site became the preferred option, and that site is the proposed Ruzizi III project. SSEA III - Final Report F-11 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS 1992 - Kiymbi (Bendera II) rehabilitation project ­ SNEL13 The present station includes two turbines, with a nominal output of 17 MW. There is a proposal to add a third unit to increase the plant capacity to 26 MW. The addition of the third unit was studied by Sicai-Tractionel in 1972. A further study was done by TECSULT in 1990, including costs for rehabilitation of the existing units and the addition of a further unit. Estimated costs from the TECSULT study as reported by SNEL are considered to be probably low (US$ 76/kW for complete rehabilitation of the existing electro-mechanical equipment and US$ 475/kW for the additional unit (at 1990 price levels). 1994 - Hydroelectric Resources of Zaïre ­ Male Cifarha14 This report provides a compilation on information from the above and other previous studies, and provides an evaluation of the overall hydroelectric potential of the country. Information used in the current study is mostly taken from the Cifarha report. 1995 - Perspectives d'électrification des centres de l'est du Zaïre ­ Male Cifarha15 This report covers the eastern provinces only. Project information is the same as in the 1994 report; however, more information on rural electrification and development opportunities is provided. Other reports relevant to this study, which were not available are: 1982 ­ Sicai-Tractionel on Ruzizi River sites; 1977 ­ TEE-PDN on Lualaba sites in Kivu and Katanga provinces; 1970 study by Tractionel of the Busanga site on the Lualaba River; 1966 study by SOGEFOR of the Nzilo II site on the Lualaba River. Information on these sites was obtained from the Cifarha study. Table 5-5 provides a listing of all identified sites with a potential of more than 10 MW. This table provides basic information on river, capacity and energy. The only source reports reviewed for the current study are those referred to above. However based on these reports, and the Cifarha reports, it is understood that no sites have been studied to a modern prefeasibility level, i.e., including a limited field investigation program of surveying and drilling. 13Expertise centrale de Kiymbi et description travaux de réhabilitation ­ Mianza Kapit, SNEL, 1992 14Les ressources hydro-électriques du Zaïre ­ Male Cifarha, 1994 15Perspectives d'électrification de centres de l´este du Zaïre ­ Male Cifarha, 1995 SSEA III - Final Report F-12 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Figure F-3 - Location of Hydro Sites in the Eastern DRC Kisangani Tshopo II Wagenia I Muhuma Rutsuhuru Panzi Kiliba Sisi 3 Kamanyola Ruzizi Mwana Ngoye Kitete Portes d'enfer SSEA III - Final Report F-13 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Table F-5 - Identified Hydroelectric Sites in the Eastern DRC Region Site River Identified Average Capacity (MW) Energy (GWh) HAUT-ZAIRE (PROV. ORIENTALE) Babeba I Tshopo 50 351 Bangamisa Lindi 48 420 Budana Shari 13 70 Kisangani Zaire 460 30 Tshopo II Tshopo 17 149 Wagenia I Zaire 50 400 Wanie Rukula Lualaba 688 6000 KIVU NORD/SUD Kamanyola Ruzizi 390 1880 Kiliba Kiliba 15 65 Kitete Lualaba 21 153 Mugomba Luhola 40 160 Muhuma Talya Sud 25 100 Mwana ngoye Lualaba 46 336 Panzi Ruzizi 36 175 Rutshuru Rutshuru 10 55 Ruzizi (Alt to Kamanyola) Ruzizi 270 1300 Semliki Semliki 28 120 Sisi 3 Ruzizi 110/174 515/888 SHABA (PROV. KATANGA) Kiymbi (Bendera II) Kiymbi 43 377 Busanga Lualaba 224 1304 Nzilo II Lualaba 33 720 Piana Mwanga Luvua 38 193 Portes d'enfer Lualaba 36 263 Source les ressources hydroélectriques du Zaïre - 1994 - Male Cifarha The above table excludes a number of identified sites of less than 10 MW, including 17 in Haut-Zaire, 17 in Kivu provinces and 6 in Shaba. SSEA III - Final Report F-14 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS F.3 Thermal Power Options F.3.1 EAC Region - Kenya, Tanzania and Uganda The EAPMP provided an initial assessment of a wide range of thermal options, both by type or technology, and by unit size. A separate candidate list was prepared for each EAC country, taking into account the availability of indigenous fuels and access to port facilities. The availability of thermal options for each EAC country is summarized as follows. F.3.1.1 Kenya - Future New Thermal Generation Options Kenya's known energy resources include geothermal power, biomass, wind and solar energy. No significant hydrocarbon resources (oil, coal, gas) have been identified. Thermal power would be based on fuels imported into Mombasa. Alternatives that are being considered for new generation include several medium-to-large size hydroelectric projects, a conventional range of oil or coal fired thermal options, and geothermal. Geothermal The Rift Valley includes several potential geothermal areas. Generation to date has been based on 35 MW units at Olkaria II. Planning for future installation is being based on 70 MW units. Potential new plants identified in the EAPMP include: Suswa: 70 MW Longonot: 70 MW Menengai: 2 x 70 MW Other sites have been identified in Kenya, including Ol Banita, Arus and Bogoria, and consequently a further 2 x 70 MW geothermal was assumed to be available in the longer term. The World Bank has a proposed project (appraisal document June 200416) which includes financing for further studies on geothermal, including a reservoir optimization study, and a study to establish a geothermal development company (US$ 10 million). The World Bank is recommending that the geothermal development be separated from KenGen. The program would also finance the Olkaria II project, including the 35 MW unit, and steam gathering systems for Olkaria I and II. (US$ 54 million) Oil and Coal As there are no indigenous fuel sources, the thermal option would depend on imported oil or coal or LNG. Any such plants would probably be near Mombasa; however they would require new harbour and docking facilities. Thermal options in the EAPMP included: · Oil fired gas turbine: 2 x 60 MW and 2 x 90 MW · Oil fired combined cycle: 3 x 60 MW and 3 x 90 MW 16World Bank ­ Project Appraisal Document on a Proposed Credit in the amount of US$ 80 Million (equivalent) to the Republic of Kenya for an Energy Sector Recovery Project ­ June 2004 SSEA III - Final Report F-15 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS · Diesel ­ 20 MW medium speed: 30 MW and 50 MW for low speed units · Oil fired conventional steam: 2 x 100 MW and 2 x 150 MW · Coal fired conventional steam: 2 x 100 MW and 3 x 150 MW F.3.1.2 Tanzania ­ Future thermal generation options Future generation options include new thermal using indigenous fuels. Tanzania depends on imported petroleum products (crude and finished product); however the country has indigenous natural gas on the coast, specifically at Songo Songo Island, and coal fields in the southwest region of the country. There is a proposal to develop a colliery and 400 MW thermal plant at the Mchuchuma site. Geothermal There are no existing or planned geothermal sites in Tanzania. Coal Proven coal reserves in Tanzania are estimated at about 300 Mt, with a potential as high as 1,200 Mt. By comparison a 400 MW thermal plant would require 600,000 to 800,000 Mt/year These deposits are at Kiwira, northwest of Lake Nyasa, and at Mchuchuma east of the lake. The latter site has enough proven reserves to fuel a 400 MW power plant for up to 35-50 years. The Mchuchuma thermal plant would be a mine-mouth plant some 25 km east of Lake Nyasa. Various studies have shown this project would be marginally uneconomic when compared to Songo Songo gas or other options. It is not expected that thermal effects from plant cooking water would impact Lake Nyasa. There is some uncertainty over the cost of the project and the cost of generation17. The project is not part of the Tanzania least cost generation plan. It is understood that the developers will not proceed with detailed investigations of the reserves until the government has approved the project. The project would be an IPP, consequently actual probable energy sales prices from the project cannot be estimated directly. Costs used in this report are calculated as "economic" costs, using the criteria given in Section 5. Natural gas The proven gas reserves at Songo Songo are in the order of 0.4 to 0.8 Tcf. It is estimated that this would be sufficient to fuel about 400-500 MW of generation for 20 years. Thermal options considered in the current master plan included: · Oil/gas fired gas turbine: 2 x 60 MW, 3 x 60 MW · Oil/gas fired combined cycle: 3 x 60 MW · Diesel ­ 20 MW medium speed: 30 MW and 50 MW for low speed units · Oil fired conventional steam: 2 x 100 MW · Coal fired conventional steam: 2 x 150 MW 17Communication from the World Bank to Col Simbakalia of the Matinal Development Corporation, August 2004, and attached letter from the World Bank to the Ministry of Finance, January 2001 SSEA III - Final Report F-16 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS F.3.1.3 Uganda - Future thermal generation options Thermal power options for Uganda are probably limited to geothermal generation. Fossil fuel thermal and diesel costs would be high due to the high cost of delivered fuel, with transport costs of the same order as the direct cost of the fuel. Geothermal should be a real option due to the potential in the Rift Valley area. However geothermal suffers from certain uncertainties, and has high front-end costs, which are negative considerations in the context of private generation. Geothermal The availability and development of this resource was stated as speculative in the IFC due diligence report18. Based on information from ESMAP and the UEB, as much as 450 MW of geothermal potential might be available in the western Rift Valley. The EAPMP used a total cost of US$ 2000/kW including all costs from exploration to commissioning, however excluding IDC. Earliest on -power would be about 2010 (2001 report). A 2002 government report19 refers to hot springs on the shores of Lake Albert and three potential geothermal fields: the Katwe volcanic field to the south, the Burunga field in the foothills of the Rwenzori mountains, and the Kibiro field in the north part of the rift valley. The Katwe field is considered the most promising, and is located 35 km from the 132 kV transmission line / substation at Kasese. The government had developed a Geothermal Development Plan for the period 2003 to 2008, for the above three areas. Investigations were to be funded by the International Energy Agency and the government. The status of these investigations is not known. Thermal options Uganda does not have indigenous presently commercial sources of fuel, and imports 90% of required petroleum products via Kenya. There is an existing oil pipeline from Mombasa to Eldoret in Kenya. As a minimum any thermal plant in Uganda would require a new pipeline from Eldoret to Kampala, or possible a new line from Mombasa to Kampala (1060 km). A delivery cost of US$ 0.03 to 0.10/m3/km should be expected. It is understood that gas has been found in the Semliki basin, however this is not yet a proven commercial resource. However the developer (Heritage Oil Corporation) is claiming potential for a world class gas/oil field20. F.3.1.4 EAC ­ Evaluated thermal options Thermal options evaluated in the EAPMP included: · Oil fired gas turbine: 2 x 30 MW and 2 x 60 MW · Oil fired combined cycle: 3 x 30 MW and 3 x 60 MW · Diesel: 20 MW medium speed 50 MW for low speed units · Oil fired conventional steam: 2 x 100 MW and 2 x 150 MW Table F-6 lists all EAPMP thermal power options. 18IFC ­ Bujagali Project ­ Summary of Economic Due Diligence ­ October 2001 19Investing in Uganda's Energy Sector ­ Ministry of Energy and Mineral Development - 2002 20Heritage news release February 2005 ­ "Heritage Oil Reports Uganda Update" www.heritageoilcorp.com SSEA III - Final Report F-17 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Table F-6 - Thermal Power Options Evaluated in the EAPMP Technology Fuel Uganda Kenya Tanzania Coal Steam Plant Coal - 2x100 MW - - 2x150 MW 2x150 MW Oil Steam Plant HFO/ LRFO 2x100 MW 2x100 MW 2x100 MW 2x150 MW 2x150 MW - Combustion Turbine IDO 2x30 MW - - 2x60 MW 2x60 MW 2x60 MW 2x90 MW - Natural Gas - - 2x60 MW Combustion Turbine IDO 3x30 MW - - Combined Cycle 3x60 MW 3x60 MW 3x60 MW - 3x90 MW - Natural Gas - - 3x60 MW Low Speed Diesel LRFO 2x30 MW 2x30 MW 2x30 MW 2x60 MW 2x60 MW 2x60 MW Medium Speed Diesel LRFO 2x20 MW 2x20 MW 2x20 MW Geothermal - 1x70 MW - Mchuchuma Coal - - 4x100 MW Source ­ EAPMP ­ Systems Analysis Report ­ Table 6.33 In the EAPMP the following thermal plants and unit sizes were retained as candidates in the development of generation expansion sequences. Table F-7 - Thermal Plants Retained for EAPMP Planning Studies Country Retained Thermal Plants and Unit Sizes Uganda 30 MW, 60 MW Combustion Turbines and associated Combined Cycle (oil fired) Kenya 60 MW, 90 MW Combustion Turbines and associated Combined Cycle (oil fired), 150 MW Coal, 70 MW Geothermal Tanzania 60 MW Combustion Turbines and associated Combined Cycle (both gas and IDO), Mchuchuma, 150 MW Coal Source ­ EAPMP Systems Analysis Report - Table 6.42 SSEA III - Final Report F-18 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS F.3.2 SSEA I Region - Burundi, Rwanda and Western Tanzania Generation from Lake Kivu Methane Gas Background and Description A natural phenomenon was discovered in the 1960's in Lake Kivu: methane gas is formed at the bottom of the lake from the decomposition of organic matter. A large quantity of this gas remains dissolved in the water, below a depth of 250 m. In natural conditions, on an annual basis, there is an equilibrium between the amount of methane gas produced and the amount of gas released to the atmosphere. Methane is oxidized as it percolates through the water column and CO2 is released at the surface of the lake. A pilot plant ­ which is still in operation - has been constructed in 1962 at Gisenyi. This plant extracts gas from the lake to supply energy to a local brewery. A private firm, Dane and Associates Ltd, has prepared a detailed project for large-scale extraction. The plant would be located in Kibuye, on the shore of Lake Kivu, in Rwanda to feed a thermal power plant. Initially, the capacity would be 30 MW of gas fired engines ­ suggested as 4 x 7.5 MW units. Depending on the load growth 12 MW units could be used later. The capacity could be brought up to 200 MW without jeopardizing the reserves of gas in the Lake (i.e. the amount of gas extracted would correspond to the amount which is naturally produced at the bottom of the lake). For the purpose of this assessment, it has been proposed that, in the first phase (30 MW), the power would be produced by engines. The Dane report provides a cost of US$ 848/kW for the engine, plus US$ 1209/kW for the gas processing system for the first unit. The second unit costs would be US$ 837 plus US$ 1134 . Annual generation of the 30 MW plant at 60% capacity factor would be 160 GWh. It should be noted that station service or self-consumption rates are higher than for conventional diesel, due to the load from the gas processing plant. Estimated generation cost at 60 % capacity factor is 7.4 cents/kWh. The Dane report notes that CO2 scrubbing facilities would be included in the plant, using lake water, however no information is given to assess the adequacy of the system or possible impacts. The Tietze report does not cover potential environmental impacts from gas treatment. However, it should be noted that no public information is available for evaluation. In addition, this is expected to be a private power project with a power purchase agreement. No assessment has been made of possible commercial energy prices. Available Information Two groups have studied this option: Dr. Klaus Tietze21 and a detailed project for large-scale extraction has been prepared by a private firm, Dane and Associates Ltd.22 21Dr. Klaus Tietze, Lake Kivu Gas Development and Promotion-related issues: Safe and Environmentally Sound Exploitation, Final Report, Republic of Rwanda, Ministry of Energy, Water and Natural Resources, Kigali, December 2000. SSEA III - Final Report F-19 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Lake Kivu Methane Combined Cycle Gas Turbines In the further phases, the units could consist of combined-cycle turbines. The Dane report23 refers to 32 MW modules. The report stated that the first unit would cost US$ 954/kW for the CCGT, plus US$ 1208/kW for the gas processing system. The second unit would cost US$ 803/kW plus US$ 805/kW for the gas system. Station service or self consumption would be 7.1% of output. The estimated energy cost from the first of this type of unit is also 7.4 cents/kWh at 60% capacity factor. Full development of this project would have the potential for supplying a large share of the power needs in the SSEA area for the short to medium term. The present proposal is to install 3 x 32 MW units, with the associated gas supply system. Due to the size of these units they would probably not be an applicable technology until the interconnected load in the sub-region is at least 300 MW. This criterion would not be applicable if the total NELSAP region was fully integrated. Rwanda Committed Diesel Commitments have been made to provide additional generation for Rwanda in the short term. It is understood that procurement is underway for groups of diesel units, with each group understood to be in the 6-10 MW size range. It is understood that the first group of these units (6 x 1.2 MW + 1 x 4.7 MW) will be on line in mid-2005, and the second group very shortly thereafter. Generic Diesel No report was available to quantify a diesel option for the supply of energy to the SSEA area. A conceptual project was set up for the sake of evaluating the resulting cost of energy. The characteristics of the unit would be as follows: · Installed capacity: 7.5 to 10 MW (it is understood that about 12.6 MW of generation has been committed) · Type of equipment: medium speed diesel · Cost of equipment: US$ 800/kW · Type of fuel: Residual oil (No. 2) · Cost of fuel: US$ 105/MWh (Referenced to cost of crude of US$ 40/bbl and delivery to Kigali area) · Useful life: 20 years · Capacity factor: 60% · Cost of energy: 13 cents/kWh 22Dane Associates Ltd. The Israel Electric Corporation Ltd., Expansion Plan for the Power System of Rwanda, Electricity Generation, Transmission and Gas Production Systems, Final Report, Part - 1, The Republic of Rwanda Ministry of Energy, Water and Natural Resources, July 2002. 23Dane Associates Ltd. The Israel Electric Corporation Ltd., Expansion Plan for the Power System of Rwanda, Electricity Generation, Transmission and Gas Production Systems, Final Report, Part - 1, The Republic of Rwanda Ministry of Energy, Water and Natural Resources, July 2002 SSEA III - Final Report F-20 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Generic Combined Cycle Gas Turbine As for the diesel option, no report was available to evaluate a specific a combined cycle gas turbine option for the supply of energy to the SSEA area. Generic information on a typical unit is as follows: · Installed capacity: 100 MW (made up of 3 units) · Type of equipment: combined cycle gas turbines · Cost of equipment: US$ 1000/kW · Type of fuel: Diesel/Distillate Oil · Cost of fuel: US$ 101/MWh (Referenced to cost of crude of US$ 40/bbl and delivery to Kigali) · Useful life: 20 years · Capacity factor: 60% · Cost of energy: 13 cents/kWh Geothermal These three countries are located in the Rift Valley or close to it. The crust of the Earth in this area is thinner than the average, and this makes it a good candidate for the development of geothermal energy. International experts have done some theoretical evaluation of the geothermal potential. It was estimated that the potential for Rwanda was in the order of 300 MW. However, such options could only be considered as long term, due to the absence of appropriate pre-feasibility, or more detailed, studies. Thermal power options therefore consist of three groups: · Short term - committed - Short term committed diesel plant in Rwanda · Uncommitted generic oil fired diesel - Generic uncommitted diesel units ­ expected to be medium speed units in the 7.5 to 10 MW size range. · Generation from Lake Kivu methane gas - Medium speed engines using methane gas from Lake Kivu as fuel. The proposed scheme is to install 4 x 7.5 MW units at Lake Kivu, together with the necessary gas extraction and processing system. (The 2002 Dane plan24 proposed different combinations of 7.5 MW units and 12 MW units ­ depending on the expected load growth). It is understood that the first units should be on-power in late 2007. 24Dane Associates Ltd. The Israel Electric Corporation Ltd., Expansion Plan for the Power System of Rwanda, Electricity Generation, Transmission and Gas Production Systems, Final Report, Part - 1, The Republic of Rwanda Ministry of Energy, Water and Natural Resources, July 2002. SSEA III - Final Report F-21 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS F.3.3 Eastern DRC Coal There is some coal available in Shaba. An early reference25 noted that Gecamines produces about 100,000 Mt of low calorie, high ash coal a year from two deposits. Most of this comes from the Kaluku Mine of the Luena deposit in Shaba Province. Gecamines is also the major consumer of the coal, which is blended with 55,000 Mt of metallurgical grade coal and 80,000 Mt of coke to meet the company's smelting needs. It is understood that current coal production is less. By comparison a 100 MW coal fired thermal plant would use about 200,000 Mt of coal, depending on quality etc. Given the unattractive energy characteristics of DRC's coal, and the scattered nature of the deposits, any large-scale exploitation is unlikely in the medium term, consequently coal thermal is not considered as an option. Lake Kivu Gas Lake Kivu is a shared resource between the DRC and Rwanda. Information on thermal possibilities form exploitation of the methane gas in Lake Kivu are outlined in the previous section. Thermal power options for the eastern DRC area are therefore assumed to be: Diesel engines ­ medium speed ­ 10 MW size range; Power supply from engines burning Lake Kivu methane. Thermal power costs were developed for Rwanda for these two options, with the cost of diesel being based on an offshore crude oil cost of US$ 40/bbl. These would be applicable to the Bukavu area. F.3.4 NELSAP Region ­ Candidate New thermal Power Options The major new thermal power options are in the EAC countries. However the DRC/Rwanda development of methane gas fuelled generation will provide significant new generation, and further medium speed diesel installations will be required in the SSEA 1 area until improved transmission and generation supply allow more economical power supply. The thermal power options for the NELSAP region are shown in Table F-8. F.4 Biomass Biomass was initially considered within this project as a possible renewable source of energy. This consideration arose from the widespread belief that exploitation of biomass for electrical generation could be feasible in the region. However only one major study was obtained on the usage of peat in Rwanda, which related to heating for a cement plant. The primary potential for biomass fuel for electrical generation in the region is in agro- industrial waste. The potential use of biomass for electricity has been commented on in various reports. The EAPMP notes availability of peat (at Lake Kyoga) and bagasse in 25Zaire - Overseas Business Report ­ US Dept Commerce ­ International Trade Administration SSEA III - Final Report F-22 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Uganda and that UAERAUS (Uganda Alternative Energy Resources Assessment and Utilization Study) had recommended further study of bagasse as a fuel. The EAPMP also refers to bagasse potential in Kenya and Tanzania. The environmental assessment of Bujagali26 refers to biomass generation as a potentially viable alternative energy source, especially for off grid applications. The IFC due diligence report on Bujagali27 refers to the planned 33 MW Kakira bagasse plant in Uganda. However neither the latest Tanzania master plan update or the Kenya least cost development plan update28 refers to biomass generation as an option. Information has been made available on significant biomass operations in the region, including sugar mills in Tanzania generating up to 12 MW, and delivering several MW of power to TANESCO. Potential fuel quantities also exist from sources such as wood waste from barking operations (resulting in waste of 70,000 t/year), palm oil, coconut and other waster or residue sources. Biomass fuelled power production can be achieved by several core processes, but mass burning furnaces with steam turbine-generators are generally used for the larger sized plants connected to the national grid. Ideally, the power plant simultaneously provides steam to a neighbouring consumer- this is referred to as cogeneration. In the sugar industry, which is very well suited to cogeneration, only a few countries have really promoted such options. Most have been successful when the administrative barriers to independent power producers where removed, and when the purchase price of power reflects marginal cost of production. Biomass is now a conventional fuel for electricity generation. In the USA biomass is used to generate about 15,000 GWh/year. Given the normal limits to fuel availability, a maximum plant size in a developed country would be 50 MW, although much larger plants have been built (i.e., to 350 MW in the USA). Given the significant amounts of potential fuel in the region, it is assumed that obstacles to generation from biomass may be related to private ownership of operations that result in fuels, and low rates paid by utilities for biomass electricity. Some of the specific issues that could affect investor decision to proceed with such plants are related to: Availability and sustainability of the fuel source, and potential for combining fuels to offset seasonal operations such as sugar production. A 10 MW plant would require in the order of 500-600 Mt/day, or 200,000 Mt per year. Plant life is 20 years; Plant operation ­ outputs should be maintained at high load factors; Energy sale price (or the possibility to displace purchased electricity) in relation to production cost. The cost of a biomass generation plant varies from US$ 1000/kW for a steam unit to US$ 1600/kW for a combined cycle unit using gasified fuel. Fuel transport, handling and especially any requirement for drying provides a significant cost, but is very site specific. Typical total generation costs will range from 10 to 15 cents/kWh, depending on the situation consequently the purchase price (or offsetting cost reduction) has to be in this order. 26ESG International ­ Atkins ­ Bujagali Environmental Impact Assessment ­ Executive Summary, March 2001 27International Finance Corporation ­ Bujagali Project. Summary of Economic Due Diligence ­ October 2001 28KPLC - The Least Cost Power Development Plan Update ­ 2005-2025 ­ March 2004 SSEA III - Final Report F-23 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS For a project to be identified and evaluated to the point at which it could be considered as a specific alternative to other identified generation options, a feasibility study would be required to establish costs and sustainability, as the power plant size and configuration are very site-specific. Such a study would have such aspects as: The inventory of available biomass, including location, quality, moisture content and seasonal availability. The presence of major heat or steam consumers would greatly improve the economics of a project, especially if the project reduces fossil fuel consumption. It will also set the plant location since steam cannot be transported. Proximity to the electrical grid will influence capital cost by reducing transmission costs. Transportation infrastructures must be capable of supplying the biomass to the plant. Water must be available. The available quantity will effect the plant configuration and performance. Technically oriented human resources must be available to operate and maintain the power plant. This aspect can even dictate the plant performance since the operation of a modern plant is technically demanding. SSEA III - Final Report F-24 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Table F-8 - NELSAP Region ­ New Thermal Power Options Plant NAME Country Installed Plant Maximum Capital Capacity Fuel Type Life Capacit Energy Cost (MW) (Years) y (%) (GWh) US$/kW Olkaria ext - Geothermal Kenya 35 Geothermal 25 80 245 2645 Longonot Geothermal Kenya 70 Geothermal 25 80 491 2352 Suswa Geothermal Kenya 70 Geothermal 25 80 491 2352 Menengai Geothermal Kenya 140 Geothermal 25 80 981 2352 Mombasa - LNG gas CCGT-4$ Kenya 180 LNG Gas 20 80 1261 895 Mombasa - LNG gas CCGT-5$ Kenya 180 LNG Gas 20 80 1261 895 Mombasa - LNG gas CCGT -6$ Kenya 180 LNG Gas 20 80 1261 895 Mombasa - Coal steam Kenya 300 Coal 25 80 2102 1678 Mchuchuma - Coal steam Tanzania 400 Coal 25 80 2803 1909 GT 60 MW- gas - generic x 4 units Tanzania 240 Gas 20 80 1682 591 GT 60 MW- gas - generic x 2 units Kenya 120 Gas 20 80 841 591 CC 60 MW - gas /steam cycle x 2 units Tanzania 120 Gas 20 80 841 1532 CC 60 MW - gas cycle x 3 units Tanzania 180 Gas 20 80 1261 895 Kivu methane engines 30 MW x 4 units Rwanda/DRC 120 Methane 20 80 841 2505 MSD Generic 10 MW x 2 units Rwanda 20 Imported Diesel 20 75 131 872 MSD Generic 10 MW x 2 units Burundi 20 Imported Diesel 20 75 131 872 MSD Generic 10 MW x 2 units W. Tanzania 20 Imported Diesel 20 75 131 872 It should be noted that the Tanzania 180 MW combined cycle plant is only a theoretical option, as Tanzania gas fired plant will be limited to about 440 MW, including the 2 x 35 MW units at Ubungo (2004 and 2005).29 30 29World Bank ­ Tanzania ­ Project appraisal document ­energy sector recovery project ­ June 2004 30World Bank Songo Songo economic analysis - Annex 4 SSEA III - Final Report F-25 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS The typical cogeneration plant would be equipped with a biomass-fired boiler that delivers steam to a steam turbine. The turbine-generator set will produce electrical power while lowering the steam pressure from the boiler pressure to the condenser pressure. Some process steam could be extracted from the turbine at an intermediate pressure, reducing the electrical power produced. While no biomass generation options have been identified, it is clear that, given the high cost of alternative thermal generation, efforts should be made to encourage proposals for such generation. F.5 Wind Energy Conversion Systems Wind energy is now being recognized as a potential new power option in the region. Wind speed has to be greater than 4 m/s to start producing energy, but a more acceptable amount of energy is produced when the wind speed is greater than 6 m/s. Most economic operation requires wind velocities in the order of 15 m/s. Economic viability of a wind generator also depends on wind distribution with time. Normally a plant has to be able to generate at a plant factor of 25% to 30% to be viable, and many wind farms are located where plant capacity factors of 35% to 40% can be achieved. One of the obstacles so far has been the lack of useful data for planning studies. Conventionally wind speeds are measured at about 10 metres height above ground, whereas windpower estimates should be based on velocities at 30-40m above ground. Consequently detailed feasibility studies require installation of metering masts for these higher level measurements. Wind velocities are affected both by regional location, and by local site conditions, so the viability of sites is very site specific. In Tanzania studies have been under way for a number of years, sponsored by the Ministry of Energy of Tanzania, TANESCO, TaTEDO (Tanzania Traditional Energy Development and Environment Organization) with technical and financial support from RISO (Denmark National Laboratory, and DANIDA. This program that resulted in a final report issued in 2003 31. The study involved installation of metering masts and evaluation of potential and costs at four locations: Gomvu near Kimbiji, southwest of Dar es Salaam Litembe, southwest of Mtwara Mkumbura near Mkomazi in the Pare/Usambara mountains Near Karatu The Gomvu and Litembe sites were selected to represent coastal conditions, while Mkumbara and Karatu represented specific favourable local topographic conditions. Average wind speeds at a height of 31 metres were measured over a one-year period, as follows: 31Danida . RISO (Denmark) ­ Wind Measurements and Wind Power Feasibility at Selected Sites in Tanzania ­ 2000-2003 ­ Final Report SSEA III - Final Report F-26 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Table F-9 ­ Wind Velocities at Study Sites in Tanzania Site Average velocity m/s Gomvu 4.8 Litembe 4.7 Mkumbara 4.9 Karatu 5.5 The study concluded that the best site was Mkumbara due to local wind patterns, and the study then evaluated a 50 MW project at this site, made up of 2 MW machines. Total investment was estimated as US$ 50 million. Corresponding generation costs were estimated as 7 to 9 cents/kWh. The study concluded that wind energy was potentially viable, however more studies were required, and the equipment selection had to be optimized to match the relatively low wind velocities at the site. The data for the Mkumbura site has been reviewed, and generation costs estimated using the RetScreen model32. This confirmed the estimated cost of 8 cents/kWh presented in the Danida report. This value has been used in the comparative analysis of alternative new power options (Section 8). However it should be noted that wind energy is not firm (i.e. equalled or exceeded all the time), and there is no firm capacity from the unit. Consequently this energy should be valued as replaced thermal, or secondary energy. This would be in the order of 6 cents/kWh for oil fired diesel or gas turbine. It is understood that a 15 MW site is being studied for Kenya33. Fro the purposes of this study it has been assumed that one or two 30 MW wind farms may be developed, and these are included in some of the portfolios in Chapter 9. Wind statistics in the region To clarify the potential for wind power in the region, wind velocity statistics were obtained from the sites shown in Table F-10. Note - the wind velocities at meteorological stations are recorded at 10 metres height. The above values, extrapolated to 50 metres, were included in the NASA data. Wind data for the above stations with the highest velocities are shown overleaf in the form of duration curves. Data for Mkumbara and Karatu were taken from the Danida report, and the other data is from the NASA database. For all sites wind speeds are adjusted to a 70 metre height (approximate hub height for a 2 MW horizontal axis machine). 32 www.retscreen.net 33 Ecogen Wind Farms Ltd ­ Environmental Impact Assessment for a 15 MW Proposed Wind Farm - January 2005 SSEA III - Final Report F-27 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Table F-10 ­ Average Wind Velocities ­ Meteorological Stations in the NELSAP Region34 Country Site Average wind at 50 m ­ m/s Kenya Garisa 4.33 Kitole 432 Mandera 4.99 Mombasa 5.11 Highest velocity Nairobi 4.76 Voi 4.90 Uganda Arna 3.89 Entebbe 4.91 Highest velocity Gulu 3.95 Masindi 4.68 Tanzania Bukoba 3.47 Dar es Salaam 5.75 Highest velocity Mbeya 4.80 Mtwara 6.20 Highest velocity Mwanza 4.16 Songea 5.37 Tabora 4.69 Burundi Bujumbura 3.15 Highest velocity Mugomba 2.05 DRC Goma 2.56 Highest velocity 34http://eosweb.larc.nasa.gov SSEA III - Final Report F-28 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Figure F-4 ­ Wind Statistics (at 70 m) SSEA III - Final Report F-29 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS SSEA III - Final Report F-30 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Corresponding capacity factors for each site and energy outputs, based on 2 MW machines, are shown below. Velocities are adjusted to 70 metres above ground. Data were calculated using the RetScreen model. SSEA III - Final Report F-31 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS Table F-11 - Wind Energy Plant Capacities Factors Average wind at Plant Energy for Country Site 70 m ­ m/s Factor % 2 MW unit - GWh Kenya Mombasa 5.37 10.9 1.9 Uganda Entebbe 5.14 8.7 1.5 Tanzania Mtwara 6.36 14.8 2.6 Mkumbara 6.72 20.4 3.6 Gomvu 6.33 14.2 2.5 Karatu 7.00 20.0 3.5 Burundi Bujumbura 3.31 1.7 0.3 DRC Goma 2.68 3.7 0.7 F.6 Demand Side Management and Loss Reduction Demand side management and energy efficiency in developing regions have to be viewed in the context of the loads, the adequacy of the present supply situation, and the need for investment in corporate systems and training for the implementation of such programs. The rational use of energy is a key objective in all jurisdictions, especially in areas where energy is at a premium. Programs to promote efficient use of energy are designed to change a customer's `normal' consumption patterns for the benefit of both the consumer as well as the producer of power. Energy efficiency normally refers to the efficient utilization of energy through the use of energy efficient products or procedures while demand side management (DSM) programs are normally designed to shift energy used during peak periods to off-peak periods. DSM programs are usually associated with tariff incentives to shift demand. With higher on- peak tariffs, cost conscious customers shift their demand to off-peak hours. The total amount of energy consumed does not change but the shift in usage reduces the capacity requirements of the electricity producer. Energy efficiency is normally achieved through programs that promote energy efficient products and behavioural changes. For example, the use of fluorescent tubes or compact fluorescent lights instead of incandescent lights can have a significant impact on energy consumption while maintaining adequate level of lighting. By using energy efficient products, the amount of energy is reduced as well as the capacity requirements. DSM programs are relatively easy to implement if there is flexibility in establishing incentives through tariffs. Energy efficiency, on the other hand, requires a significant infrastructure to design and implement programs that would produce a significant impact. Energy efficiency programs are most effective in regions where the unit cost of energy is high. The reduction in capacity requirements that can be achieved by DSM programs is a function of the tariff structure, the system load profile, the load profile of users and the flexibility in SSEA III - Final Report F-32 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS changing the time of day where energy can be used. The capacity saving from DSM can vary from a few percentage points to a significant amount depending on specific local conditions. The reduction in capacity and energy requirements from energy efficiency programs is a function of the effectiveness of local energy conservation and utility companies to manage the programs. Energy efficiency in small systems is sometimes not cost effective given the nature of smaller systems and the infrastructure required to manage energy efficiency programs. However this remains an option that should be promoted in the future to reduce loads and investment requirements. Within the context of the SSEA I, EAC and eastern DRC sub-regions, and particularly taking into account the present supply deficit, it is not considered that DSM is a realistic option for at least the mid term. It is noted that no electric utilities in the region have initiated such demand side management programs. Another option to reduce demands is to reduce technical losses (reduction in non-technical losses will not reduce demand). Investment in loss reduction may be more economic. Losses in the region are relatively high, and this suggests that loss reduction program could provide benefits, at least in Uganda. Table F-12 ­ Technical Losses Country Technical loss % Kenya 1635 Tanzania 12 Uganda 21 Burundi 1436 DRC (East) 10 (total)37 Rwanda 14 F.7 Transmission and Interconnections Transmission costs will be included in the assessment of individual projects and overall comparative plans. Transmission in the overall NEL grid was considered under two categories: The primary grid, including mid-term future additions, is mostly at 220 kV for the EAC countries, and at 110 kV for the eastern DRC and the SSEA I sub-region. An interconnection between Goma in the DRC and Kigali in Rwanda was be assumed as part of the SSEA 1 grid. It should be noted that the EAPMP least cost plan was associated with a single transmission grid plan, with additions (and their scheduling) being directly associated with the selected 35Technical losses for Kenya, Tanzania and Uganda were taken from the EAPMP 36 Losses for Burundi and Rwanda and based on Laymeyer International ­ Analysis and Projection of Rwanda's Electricity Demand. for ELECTROGAZ ­ May 2004 37SNEL ­ 2003 ­ Plan directeur National de Secteur de l'Electricité à l'Horizon 2015 SSEA III - Final Report F-33 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS power options for the recommended integrated plan. For the SSEA I area, a single backbone grid option was proposed in the Phase 1 study, which would have the primary function of integrating loads, so that any new power projects will provide regional benefits. It was assumed that this sub-grid would be unchanged, even if some of the SSEA 1 region load is supplied for the EAC countries in the future. All the plans shown in Section 7 include a significant proportion of the new generation recommended for within the SSEA 1 area, so any modification to the original Phase 1 plan to reflect alternate portfolios, would have minor cost impact. Costs of the grid have not been included in the comparison of portfolios; however, significant changes that would result from implementation of any given portfolio are identified and costed (See Section 9). Transmission from individual projects to deliver power to the primary grids. As for the EAPMP and the SSEA I studies, the cost of transmission to the grid will be included in the project costs. Portfolio Development and Transmission In terms of the development of alternative portfolios of specific projects, the Stage II concept therefore considered the NEL region in two parts: EAC countries; The region comprised by the eastern DRC, Burundi, Rwanda and the western part of Tanzania (that is presently electrically isolated from the rest of the country). The adopted concept for the transmission system was to treat the EAC system as the primary grid, and the smaller SSEA 1 and DRC systems as sub-grids. Consequently the following concepts were applied: For the EAC countries the upgraded grid included in the least cost plan was retained without change. It was assumed that any change to scheduled on-power dates for EAC selected projects, due to the integration of the two loads, would not significantly affect the timing of transmission additions. Consequently the transmission plan proposed in the EAPMP was retained. For the eastern DRC the currently planned/committed lines at 110 kV was added to the grid shown in the 2003 master plan 38for the eastern provinces covered by this assessment. The additions included a proposed 110 kV line from Goma to Beni, and the planned upgrade of the existing 15 kV line from Bujumbura to the Kiliba substation to 110 kV. It is noted that Bujumbura is not on the proposed backbone 110 kV grid for the SSEA 1 area, however this can line to serve as part of an integrated NEL network, as the existing Burundi line from Bujumbura to Gitega has been upgraded to 110 kV. For the SSEA 1 region, i.e., Burundi, Rwanda and western Tanzania, the plan assumed the upgraded "backbone" grid that is shown in the Stage 1 report. The integration of the EAC and SSEA systems can be achieved by an extension of the SSEA I backbone, to provide an interconnection between Kigali and Masaka in Uganda or Bukoba in Tanzania. 38Société Nationale d´Électricité, Plan directeur national du secteur de l´électricité a l´horizon 2015, Tome 1, volume de synthèse, juin 2003 SSEA III - Final Report F-34 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS F.7.1 Imports from Outside the NELSAP Region Potential imports from outside the study region were treated as projects located at the nearest substation in the exporting country. Potential imports from the Inga projects assumed delivery to Lubumbasha in Katanga, and thence to Pensulu in Zambia. Potential imports from Zambia would be assumed to be delivered from Pensulu in Zambia to Mbeya in southwest Tanzania. The Zambia-Tanzania interconnection would be treated as a cost for either Inga imports or Zambia imports, and therefore included in the delivery price at Mbeya. F.7.2 Interconnections Within the NELSAP Region to Supply the SSEA 1 Region One of the possible options to supply energy to the SSEA 1 countries is to have transmission interconnection. These interconnections would make it possible to import power from neighbouring countries (Uganda, the rest of Tanzania, DRC, Kenya) if excess power is available. Power generation costs in neighbouring countries may differ substantially and it may be worthwhile to have transmission interconnections so that power from a country that has relatively lower cost of generation can be exported to a country that has high generation costs. Depending on the economics, the import of power through transmission interconnections may be used to replace the relatively expensive diesel or other generation from within the country. This may also result in environmental benefits. The possible sources of energy and interconnection options that may be considered for supplying power to the load centres through the transmission interconnection include the following: Imports to the SSEA 1 region from Uganda: A substation at Mbarara can be a useful source of feeding power to the interconnection. Power capacity in the range of 20 MW can be imported in Rwanda from this source. The transmission interconnection between Mbarara and Gikondo would be approximately 230 km long. Bulk power to the SSEA 1 region from the main grid in Tanzania: Tractebel made a technical study in the late 1980's for the Rusumo Falls hydropower project. This study envisaged interconnection between Rusumo Falls and Mwanza in Tanzania, Rwinkwavu in Rwanda and Gitega in Burundi. This transmission interconnection was considered as part of the of the Rusumo Falls hydro plant project. However, in case Rusumo Falls hydro plant project does not materialize, a transmission interconnection from Mwanza to Bihalamulo could be considered. From Bihalamulo the transmission interconnection could then be extended to Rwinkwavu in Rwanda and Gitega in Burundi. The total length of the interconnection would be around 620 km. This interconnection would supply 20 MW power to each of the countries. In addition to the above possible sources of energy, alternative electrification projects being planned by TANESCO for electrification of Western Tanzania can be considered for supplying power to the region. One of the projects is the interconnection between Masaka (Uganda) and Mwanza (Tanzania) including Bukoba, Kagera, Biharamulo and Gieta. This interconnection can be extended further to supply power to Rwanda depending on the availability of surplus power feeding this interconnection. In the context of this current project, the lack of detailed studies and more importantly the lack of surplus capacity from neighbouring regions, imply that interconnection options cannot SSEA III - Final Report F-35 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS be considered further in the comparative analysis against the other power options in the SSEA I region. F.8 Off-grid Options While off-grid generation options are outside the context of this assessment, the following information is included to give a reference point for alternative energy costs. As has been noted, governments in the region are pursuing policies of poverty alleviation, including improving access to electricity. This section presents the available and more commonly used technological options for off- grid electrification. The following options are outlined below: Mini/micro hydroelectric power; Diesel; Solar PV. (Wind energy is an option for off-grid as well as on grid applications, however this concept is described in Section 5.5 above.) In order to compare costs for such projects, electricity requirements for a hypothetical village have been assumed as follows: 500 inhabitants 100 houses (average of 5 occupants) Load factor 35% Load per house 260 W per village 26 kW Annual energy per house 800 kWh per village 80 MWh These values are consistent with a recent rural electrification planning study for Honduras39. Approximate costs for alternatives have assumed a total demand of 300 W, and 1000 kWh/year. F.8.1 Mini/Micro Hydroelectric Power Design of the hydro plant The amount of power that can be produced at a hydroelectric site is a function of the available head and flow. A conservative, "rule-of-thumb" relationship is that power is equal to seven times the product of the flow (Q-m3/s) and gross head (H-m) at the site i.e., (P-kW = 7QH). The hydro turbine size depends primarily on the flow of water it has to accommodate. Thus, the generating equipment for higher-head, lower-flow installations is generally less expensive than for lower-head, higher-flow plants. The same cannot necessarily be said for 39Proyecto Regional de Energía Eléctrica, Istmo Centroamericano ­ Plan Nacional de Electrificación Social ­ SNC-Lavalin/Consorcio PREEICA ­ marzo 2004 SSEA III - Final Report F-36 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS the civil works components of a project, which are related much more to the local topography, and physical nature of a site. A small hydro generating station can be described under two main headings: civil works; and mechanical and electrical equipment. The figure below shows a typical arrangement. Small Hydro System Schematic For a mini hydro plant, a reverse pump can be used. Construction involves preparing the site, grading roads, building the power plant, installing the electrical lines and transformers, erecting the turbines, and construction of the substation and buildings. Normally, the construction itself can be completed within one year. Operation and maintenance The supplier of the power plant can provide training of operators during the stages of construction and commissioning of the plant. The supplier of the plant will assume Training and responsibility for maintenance. Cost estimate The cost of a mini hydro plant is very site specific; however, it would usually be in the order of US$ 3,000 - 4,000/kW. Consequently, the cost of equipment and installation for a 30 kW hydro power plant is would be at least US$ 90,000. This assumes a favourable site, and use of a standard turbine /generator design. It may also be noted that the cost will be affected by the engineering cost. There is a conception that this cost has to be very high, potentially 20% of the cost of the project. However, for programs involving multiple sites total engineering costs typically will cost 5% of the direct project cost. Items included in this cost are owner's cost, indirect costs, cost of environmental mitigation, interest during construction, access, electric lines, etc. The annual production would depend on minimum river flows; however, would be in the order of 90 MWh in a dry year, if the project is to respond to the village needs. The cost of operation and maintenance may be assumed as 1% of the capital cost. SSEA III - Final Report F-37 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS The unit cost of energy based on the above data would be in the order of 12 cents/kWh. The life of the plant used in the calculation is 50 years and the assumed discount rate is 10%. F.8.2 Diesel Source of fuel In the case of a diesel power plant, diesel oil has to be imported. The diesel cost of US$ 580/Mt, delivered to the remote plant has been assumed in the present evaluation (which corresponds to an offshore crude oil cost of US$ 40/bbl). Design of the diesel power plant The diesel engine could be a standard generator set, such as the Caterpillar D13P2S, which generates a power of 12 kW in a continuous mode of operation. The efficiency is assumed to be 35%. Construction involves preparing the site, grading roads, building turbine foundations, installing the electrical lines and transformers, construction of the substation and buildings. The construction can be completed within 6 months. Cost estimate The cost of equipment and installation for the small diesel power plant is about US$ 1 400/kW. For a 30 kW unit the resulting total cost would be US$ 40 000. Items included in the costs are owner's cost, indirect costs, cost of environmental mitigation, interest during construction, access, electric lines, etc. The annual production is assumed as 90 MWh, assuming an average load factor of 35%. Based on the above parameters, and assuming additional fuel transport costs from a centre such as Kigali, the variable cost of energy would be in the order of 17 cents/kWh, and including capital charges, the cost would be in the order of 25 cents/kWh. The life of the plant used in the calculation is 20 years and the discount rate is assumed to be 10%. F.8.3 Solar PV Sunshine statistics A example of a solar power application is based on average solar radiation in Rwanda of 5.15 kWh/m²-day ( 1900 kWh /m²-year) 40. The annual variations of the solar radiation in those areas close to the equator are small. Design of the solar energy system The main element in the photovoltaic (PV) market is the PV module. PV modules are rated on the basis of the power delivered under Standard Testing Conditions (STC) of 1 kW/m² of 40Organisation des Nations Unies pour le développement industriel Programme d'appui institutionnel pour développer l'usage des énergies renouvelables et faciliter l'accès à l'énergie des populations rurales. http://www.univ-pau.fr/~scholle/ecosystemes/2-dev/24-rwa/24-pg-fr.htm SSEA III - Final Report F-38 017334-001-00 APPENDIX F - IDENTIFICATION OF NEW POWER OPTIONS sunlight and a PV cell temperature of 25 degrees Celsius (°C). Their output measured under STC is expressed in terms of "peak Watt" or Wp nominal capacity. PV modules are integrated into systems designed for specific applications. A PV system typically includes a device for storing the energy collected by the modules, a power management subsystem and a mounting structure. The components added to the module constitute the "balance of system" or BOS, like DC-AC power inverters, batteries, controllers, etc. The most common PV projects are for off-grid applications. Currently, PV is most competitive in remote sites requiring relatively small amounts of power, typically less than 10 kWp. In these off-grid applications, PV is typically used for the charging of batteries that store the energy captured by the modules and provides the user with electrical energy on demand. The list of key competitors for PV in remote off-grid power applications includes the electric grid extension, primary (disposable) batteries, diesel, gas and thermoelectric generators (solid state generators based on the Pelletier principle, used for cathodic protection on pipelines, telecommunications and small isolated loads up to 1 kW). PV competes particularly well against grid extension for small loads, far from the utility grid. Compared to diesel generators and primary batteries, the key advantage of PV is the reduction in operation, maintenance and replacement costs. The estimated life duration of a unit is about 25 years for the BOS equipment, and about 10 years for the PV module. The implementation schedule is short, installation is very simple, and can be done by the inhabitants of the village. Backup power source No backup source is required with a PV system that includes a storing device. Operation and maintenance The supplier of the PV systems usually provides to villagers training for operating and maintaining their own PV systems. Cost estimate The KIST in Kigali has quoted US$ 1 000 for a 50 W PV system. This can be extrapolated to US$ 1,500 for a 300 W PV household system. However estimates obtained with the RETSCREEN41 model suggest a total cost of 1100 US$/kW for a 70 kW installation, of which about 55 % is for the PV inverter. For a 300 W household system the cost would be 4,500 US$. An alternative source42 suggests PV inverter costs of about US$ 5/W, which would yield a total installation cost of about US$ 10/W, and thus a household cost of US$ 3,000 similar unit energy cost. Assuming a 25 % capacity factor, the corresponding unit energy cost would be in the order of 40-60 cents/kWh. Interim replacements would include the PV module and the battery. 41Natural Resources Canada (Ministry)- RETSCREEN International ­ www.retscreen.net 42www.altersystems.com SSEA III - Final Report F-39 017334-001-00 APPENDIX G PLANNING PARAMETERS AND COSTING OF OPTIONS SSEA III - Final Report 017334-001-00 Appendix G - Planning Parameters and Costing of Options TABLE OF CONTENTS PAGE G.1 Planning Criteria for On-grid Options G-1 G.1.1 Calculation of Unit Costs of New Generation G-1 G.1.2 Cost Reference Year, Future Escalation and Discount Rate G-1 G.1.3 Plant Service Life G-2 G.1.4 Operation and Maintenance and Other Costs G-2 G.2 Level of preparedness G-3 G.3 Feasibility study scope G-4 G.4 Lead Times to On-Power G-5 G.4.1 Lead times for hydroelectric options G-5 G.4.2 Lead Times for Thermal plants G-7 G.5 Hydrologic Information G-7 G.5.1 Lake Victoria Flow Pattern G-9 G.5.2 Kagera River at Rusumo Falls G-9 G.5.3 The Lake Victoria Flow Controversy G-10 G.5.4 Conclusion G-10 G.6 Cost Estimates for Hydroelectric Options G-10 G.7 Procedure for Updating Estimates G-10 G.7.1 Standard Unit Costs G-14 G.7.2 Procedure for Escalating Costs from Earlier Estimates G-16 G.7.3 Interest During Construction G-18 G.8 Mitigation Costs for Hydroelectric Projects G-18 G.9 Multipurpose Projects ­ Shared Costs G-19 G.10 Fuel prices G-21 G.10.1 Fuel Prices - Oil G-21 G.10.2 Fuel Price ­ Coal G-22 G.10.3 Fuel Price ­ Natural Gas G-23 G.10.4 Fuel Price ­ Liquefied Natural Gas (LNG) G-24 SSEA III - Final Report G-i 017334-001-00 Appendix G - Planning Parameters and Costing of Options APPENDIX G Planning Parameters and Costing of Options G.1 Planning Criteria for On-grid Options A number of planning criteria were adopted for use in calculating unit generation costs, as well as to provide input to the approximate scheduling of plants that was done as part of the development of alternative portfolios. The following values and information were used. These values are generally consistent with those that were used in the East Africa Power Master Plan . 1 G.1.1 Calculation of Unit Costs of New Generation For the purpose of comparing alternative new generation options, unit capacity (US$/kW) and energy costs have been estimated using a simplified economic analysis. The capital cost includes interest during construction, which is a function of the scheduling of capital expenditures during construction, the length of the construction period, and the discount rate. It should be noted that, in this context and in accordance with normal practice for this type of study unit generation costs are not intended to reflect either economic or financial values.. For example shadow or efficiency prices, impact of foreign exchange, and secondary benefits to the economy would be included in an economic analysis, while taxes, incentives, project financing aspects would be included in a financial analysis. There are other differences if one considers IPP models, for example the use of EPC by the IPP adds cost but reduces risk. Clearly the SSEA (as for the EAPMP) has assumed government construction with traditional contracting and public sector/donor to government financing. The unit cost of capacity is estimated from the capital cost, including interest during construction, and the nominal plant installed capacity. (Note that the firm capacity of the plant, especially for run-of-the-river hydroelectric projects may be significantly lower.) Unit energy costs (US$/kWh) are calculated from capital charges and variable operation and maintenance costs, and fuel costs where applicable. For hydroelectric projects, unit costs have been calculated for both estimated average annual and firm energy. The calculation of energy costs takes into account the service lives attributable to each technology. The total cost of energy generation is a function of plant capacity factor and combines the fixed annual capacity component (US$/kW-year/hours of operation) with the variable energy component (US$/kWh). In the case of the hydroelectric option the plant capacity factor, and thus average hours of operation, is defined. The thermal plant may operate from a minimum of about 5% of the time, up to its maximum annual availability of about 80-90% of the time, depending on the type and age of the plant. This procedure does not take into account any future escalation in fuel or operating costs. G.1.2 Cost Reference Year, Future Escalation and Discount Rate All costs are expressed in terms of mid 2004 costs. No further escalation is applied to capital costs or operating costs. Fuel costs for alternative thermal generation are also applied without any escalation. The identification and assessment of new power options to meet the forecast load growth covers the period 2005 to 2020. In the system planning studies covered in Chapter 13 of this 1 EAC ­ Eastern African Power Master Plan Study, final Phase II Report, March 2005, BKS Acres SSEA III - Final Report G-1 017334-001-00 Appendix G - Planning Parameters and Costing of Options report, the simulations of system operations and production costs include an additional evaluation period to 2056 to allow the different service lives of the various technologies to be taken into account. A real discount rate of 10% (i.e. excluding inflation) was used in determining annual costs for interest and capital repayment (expressed as a uniform annual payment), and interest during construction, for hydroelectric and thermal plants. It is noted that a real discount rate of 10%, excluding inflation is conservative. However these project evaluations or comparisons are being presented in terms of economic rather than financial criteria. While the discount rate or interest rate may be considered as the time value of money, the selection of an appropriate value should reflect the opportunity cost of capital, and will tend to be higher in regions or countries where capital is relatively scarcer. In the context of this study, the interest rate of 10% has been used for very preliminary comparisons of unit generation costs shown in Chapter 17. It is also relevant in comparing the total system capital and operating costs for alternative portfolios, as is shown in Chapter 13. Use of a higher interest rate would tend to favour thermal plants in costs comparisons due to their lower initial costs, but higher yearly operating costs, while lower interest rates would favour hydroelectric plants, where most of the expenditures are at the beginning of the project cycle. Actual financing costs for projects in the region will depend on the donor, and would be less than 10%. The EAPMP used a discount rate of 12% excluding inflation. G.1.3 Plant Service Life The following service lives were used in determining average unit generation costs (Chapter 7) and in the comparison of total system costs for alternative portfolios (Chapter 13): · Gas turbines: 20 years · Combined cycle gas turbines: 20 · Medium speed diesel: 20 · Coal and oil steam plants: 25 · Geothermal: 25 · Hydroelectric plant: 50 It should be noted that retirement of existing plant was not taken into account in the calculation of costs for alternative portfolios (Chapter 13), as this replacement generation would be common to all alternatives and no large size generation would be subject to retirement. This would also mean that estimates would be required for extending the service life of thermal projects, which is very project specific (depending on maintenance history, run time etc). Thus adding any such costs would not improve the accuracy of the assessment of alternative portfolios. G.1.4 Operation and Maintenance and Other Costs Unit generation costs included allowances for operation and maintenance, interim replacement, and insurance. For thermal plants, the operation and maintenance cost is separated into fixed and variable components. For hydroelectric plant, all O and M cost is considered as fixed. Interim replacement is an annual allowance to cover periodic replacement of major equipment items that have a shorter service life than the overall project, such as turbines in a hydroelectric project. SSEA III - Final Report G-2 017334-001-00 Appendix G - Planning Parameters and Costing of Options The following allowances were assumed: Table G-1- Operation and Maintenance, and Other Annual Costs Variable Interim Plant type Unit size Fixed O&M Insurance MW US$/kW/yr O&M Replace- US$/kWh ment% % Coal steam thermal 150 70 0.0045 0.35 .025 Oil steam thermal 150 35 0.0050 0.35 .025 Geothermal 30-70 12 0.002 1.5 0.25 Gas turbine All 15 0.0075 0.35 0.25 Combined cycle gas All 20 0.0075 0.35 0.25 turbine Medium speed diesel All 40 0.0075 0.35 0.25 Hydroelectric All 10 0 0.25 0.10 G.2 Level of preparedness Hydropower planning consists of the steps required to identify and evaluate potential hydroelectric sites, and then to arrange implementation of a selected hydroelectric project. This can include upgrades of existing projects, as well as new plants. The hydropower planning and implementation process therefore comprises the following steps: · Identification and inventory of potential sites; · Reconnaissance investigation of selected sites; · Prefeasibility study of preferred sites; · Feasibility studies of best sites; · Design and tender documents; · Construction. The project evaluation studies leading up to project commitment at each stage includes the full range of activities needed to define the project scheme, to estimate generation benefits, and to evaluate the project. The difference between each phase is the level of effort applied to each phase, in terms of engineering and extent of field investigations and, to a large degree, the accuracy of the estimated project costs is directly related to the extent of the field investigations (as shown in Table G-2 below). Table G-2 - Data Requirements at Different Study Stages Reconnaissance Prefeasibility Feasibility Topography 1:50 000 1:50 000 1:1000 Min. X-Sections X-Sections Ground Survey Profiles Profiles Air Photos Hydrology 10-year duration 25-year sequence 25-year sequence curve Regional flood data PMP/PMF Regional flood data Geology Reports 200 m drilling 1000 m to 3000 m drilling Economics --- Env. reports Env. study Thermal costs Generation planning data basis for shadow prices SSEA III - Final Report G-3 017334-001-00 Appendix G - Planning Parameters and Costing of Options It is also necessary to understand the levels of generally accepted contingency allowances with the amount of field investigations in the various study phases and overall expected accuracy of the cost estimates, that are directly related to the adequacy of the information used in the preliminary design process. One has to remember that contingency allowances are intended to cover undefined costs that will be identified between the time the preliminary evaluation and the final design/construction stage. Typical values are as follows. Table G-3 - Reliability of Results at Different Study Stages Reconnaissance Prefeasibility Feasibility Total Contingency allowances %* 25 10 - 15 8 - 10 -- Accuracy % +/- 35 20 15 -- Field investigation costs as % 15 40 50 -- of cost of each study phase** Study cost as % of total 0.25 0.5 1.0 2 capital cost * Indicated contingency allowances are percentages of total costs for construction, engineering and construction supervision. ** Based on approximate cost of field investigations. G.3 Feasibility study scope In the context of evaluating the level of preparedness of the new generation options that have been studied in the past one may use the expected scope of a full feasibility study as a point of reference. The definitions of the meaning of a "feasibility study" vary. In this context it denotes the "last" study i.e., beyond this stage a reasonably firm commitment to construct a generation source is made. A feasibility study will cover the following scope: · Conceptual design and optimization of the generation plant configuration; · Sufficient detail design to fully define the key physical dimensions (quantities); · Investigation of site-specific conditions to ensure that any potentially serious problems are discovered; · Confirmation of the technical feasibility of the project; · Evaluation of the expected operating performance of the plant i.e., power and energy capability, efficiency, reliability, operation and maintenance etc.; · Study of environmental and socio-economic impacts; · Detailed construction schedule; · Based on all of the above, a detailed estimate of capital and operating costs. At this point the technical feasibility of the proposed plant should be confirmed and the cost of generation is known. To evaluate whether the proposed plant is the best choice for the system and, if not, to determine what is the best generation option, a detailed system planning study is made which yields both an economic and financial evaluation of the proposed expansion. This may be part of the feasibility study or done as part of a master plan. The difference between the feasibility and pre-feasibility study is the level of effort, the resulting confidence in the results, and the near final dimensioning of the project. Typically the feasibility study includes extensive field investigations, both to confirm the technical SSEA III - Final Report G-4 017334-001-00 Appendix G - Planning Parameters and Costing of Options feasibility of the project and to fully define the availability and cost of construction materials as well as the cost of managing site specific problems such as leakage or river bank instability. The feasibility study provides the information for a management decision to commit, in total or conditionally, funds for the construction of the project. Consequently, expenditures on feasibility studies are more or less directly related to the estimated project capital cost. The relationship between feasibility study cost and capital cost is not linear and will vary according to the location and type of scheme and the extent of the environmental problems that are to be resolved. Engineering costs for conventional projects (larger than 50 MW) (apart from environmental, economics and generation planning activities) generally are between 0.5 and 1.5% of the estimated capital cost. Approximately half of this will be for field investigations. For smaller projects the overall percentage may be higher. G.4 Lead Times to On-Power A critical issue in determining the possible scheduling of new plant is the minimum lead time that would be required to complete the project implementation process up to commercial on- power. A major consideration in the estimate of minimum lead time to on-power is the level of preparation of the project. All the hydroelectric options, and the specifically identified thermal plants, including the proposed Lake Kivu methane thermal plants have been subject to study and evaluation at some level. However these evaluations range from very preliminary to detailed "pre-design" studies. A further issue is that the level of evaluation claimed by the study reports may not be realistic. For example a number of studies are stated as being at the feasibility level where no significant field investigations have been carried out, so this classification is not justified. It is important to realize that it can take from two to six years to complete sufficient studies on a project for a final decision to be made to implement. Typically, the overall period from start of prefeasibility study to earliest on-power date will be more than eight years, even for a small project. Where lead times have been provided for the EAC projects these have been used. This is because in most cases the reference reports used by the EAPMP were relatively recent and comprehensive. For all other projects the following guidelines have been applied to determine earliest on-power dates. Earliest on-power rates are basis on the lead time, after January 2006. G.4.1 Lead times for hydroelectric options Based on the above consideration and review of the available study reports, approximate lead times for each project have been estimated. These are based on the indicated level of preparedness of each project in the reference reports, and the following generic times for each of the individual activities leading up to implementation and on-power. Activity Time in months Prefeasibility study, following a reconnaissance level project identification 6-12 Feasibility study (including consultant selection) 12-24 Feasibility study update (where required) 6-12 SSEA III - Final Report G-5 017334-001-00 Appendix G - Planning Parameters and Costing of Options Activity Time in months Environmental study and approval 12 Preparation of IPP process and tendering (where applicable) 12 Project financing (IPP or public ownership) 12 Final design (including consultant selection) ­ depending on size/complexity 12-18 Tendering 6-12 Construction (depending on size/complexity) 36-60 Actual times will vary considerably, depending on environmental approval process, private or public ownership, commitment of the host government, feasibility of financing, size and complexity of the project, and the extent to which activities may be fast tracked (i.e., carried out in parallel, such as final design and preparation of the EIA). Overall implementation times used in this assessment for each hydroelectric candidate are based on the following minimum timeframes, expressed in years. Table G-4 - Minimum On-power Lead Times for Hydroelectric Plants (in years) Present project status Project preparation Tender/Construct Total Reconnaissance/preliminary less than 70 MW 3 4 7 70 to 150 MW 4 5 9 more than 150 MW 4 6 10 Prefeasibility less than 70 MW 2 4 6 70 to 150 MW 3 5 8 more than 150 MW 3 6 9 Feasibility less than 70 MW 2 4 6 70 to 150 MW 2 5 7 more than 150 MW 2 6 8 Design/tender documents less than 70 MW 1 4 5 70 to 150 MW 1 5 6 more than 150 MW 1 6 7 These values allow no margin for delays between successive development stages. They also do not provide for additional delays for approval and financing activities. At least one year should be added to the above values for any project that is not being fast tracked. (These values have been increased by one year from these shown in earlier SSEA reports.) It must also be emphasized that the level of preparedness indicated by a reference study title is not always indicative of the real level of preparation of a project. For example a study title may use the term "feasibility study" when only limited field work has been carried out. SSEA III - Final Report G-6 017334-001-00 Appendix G - Planning Parameters and Costing of Options Even when tender documents have been issued several years ago, it is certain that additional fieldwork and a design review will be required, together with updating the tender documents. Also where the intention is to have the project developed by a private investor, usually considerably more preparation time is required for the tendering and financing stages. The resulting earliest on-power dates are based on either: · The minimum lead times provided in the EAPMP for EAC projects, or the estimated minimum lead times that would result from the criteria shown in Chapter 6 (the standardized estimate). Where the EAPMP value differed from the standardized estimate, the EAPMP value has been selected. In the case of significant differences (longer minimum lead times suggested in the EAPMP), these are usually associated with projects that involved complex development issues, such as development in a national park. · Standardized estimates shown in Table G-4 have been used for all projects outside of the EAC. On power dates were obtained by adding the lead time to January 2006. Thus estimated on- power dates are in January of the year G.4.2 Lead Times for Thermal plants For the purpose of this assessment, the following lead times have been assumed: Table G-5 - Minimum On-power Lead Times for Thermal Plants Technology Project preparation Procure/Construct Total Coal steam 3 3 6 Oil steam 3 3 6 Conventional diesel 1 1 2 Gas fired engines 2 1 3* Combined cycle gas 2 1 3 turbine *The Dane report provides a 3-year schedule for both types of plant using Lake Kivu Methane gas. It is assumed this provides adequate time for the finalization of the design of the gas recovery and treatment system. These time frames do not include any allowance for times to reach agreement on the use of binational resources, such as the Ruzizi River, Rusumo River or Lake Kivu. G.5 Hydrologic Information The energy potential of a hydroelectric scheme is calculated from the historical hydrologic record obtained at the site, or a synthetic record based on historic records. This assumes that the hydrological pattern that will be observed in the future will be similar to the hydrological pattern observed in the past, and that the hydrological record available is accurate and representative. SSEA III - Final Report G-7 017334-001-00 Appendix G - Planning Parameters and Costing of Options Most of the area under study is located in the basin of the Victoria Nile, the Kagera River, which is the main tributary of Lake Victoria, the Semliki River, the upper reaches of the Congo, and the Ruaha and Rufiji rivers in Tanzania. The issue of the apparently abnormal hydrological phenomena that occurred in the basin of Lake Victoria, where a sharp increase of the outflow was observed in 1961, was considered important, as it could affect confidence in recorded flows and on the selection of a historical period to be considered representative of what is to be expected in the future. This phenomenon has cast some doubt on the validity of the hydrological records, and on the historical period which should be considered representative of what is to be expected in the future. Several studies have been carried out on this subject. This appendix reviews the problem and outlines some conclusions from observed data. With the exception of the alternatives for the Rusumo project, generation estimates included in this report are as reported in the source documents. For the EAC countries the generation capabilities were re-estimated by BKS-Acres, and these estimates have been used. In the case of Rusumo Falls a revised estimate was made for the SSEA 1 study, based on Kagera recorded and estimated flows. It should be noted that the EAPMP generation estimates for Uganda have been based on an assessment of the hydrologic regime of the Nile, that assumes that the relatively higher outflows from Lake Victoria that have occurred since 1961 will be maintained in the future. An alternative assessment by the IOH (Institute of Hydrology, UK) has placed more weight on the longer term record, especially the selection of the historic low flows that would define the firm energy values for the Nile projects2 . It may be assumed that the same uncertainty 3 in the validity of hydrological records also applies to other rivers in the Lake Victoria region, especially the Kagera River, and thus the firm energy estimates for Rusumo. The Rusumo energy estimates used in this study are taken from the 1992 Tractebel study4, and firm energy values were derived from a very low flow period from 1944 to 19525. As was noted in the Acres review of 2003, the recorded flows at Rusumo Falls were significantly lower during the period 1940 to 1961 (average 150 m3/s), than from 1961 to 1984 (average 239 m3/s), and that this step change is consistent with records of the Nile at Owen Falls. If a satisfactory/reliable sequence of flows at Rusumo can be constructed for the period after 1961, both the firm and average energy attributable to the project would increase from those values used in this study. The Acres report did not provide any re- estimate of energy values6. 2International Finance Corporation. Bujagali Project ­ Summary of Economic Due Diligence, October 12, 2001 3BKS-Acres ­ East African Power Master Plan Study ­ Final Phase II Report, March 2005 4 Tractebel previously Tractebel Electrobel Engineering, KBO, Rusumo Falls Hydro-Electric Scheme, Phase II ­ Part 3, Tender documents, Lot 1 ­ Civil works, Technical specifications, April 1989 Revised January 1992 Draft. 5 It is noted that the energy values in this report for Rusumo were taken from the 1992 Tractabel study. This followed the procedure for all hydro options where original estimates were used (except for EAC sites where energy estimates from the EAPMP were used. Importantly this reflects the view that the whole hydrological record for Rusumo should be used, as was concluded by IOH and Sutcliffe, irrespective of the relatively high values since 1962, which implied some discontinuity in the record. Two separate analysis on Nile and Kagera flows, done as part of this study, also concluded that pre- and post- 1961 data were equally valid components of the Rusumo flow series, and thus provided agreement to this view. 6 Acres International Limited, Review of existing documents for the Rusumo Falls HEP, Final Review Report, August 2003. SSEA III - Final Report G-8 017334-001-00 Appendix G - Planning Parameters and Costing of Options The EAPMP energy values were derived from modelling the integrated generation resource, rather than on a plant-by-plant basis. Consequently values of firm energy assigned to projects are increments resulting from the addition of the project to the generation resource. It is assumed this is why the firm energy values assigned to Rumakali and Upper Kihansi are marginally higher than the average energy capabilities of the projects. G.5.1 Lake Victoria Flow Pattern The drainage area of Lake Victoria is 194,000 km². The area of the Lake itself is 67,850 km². The main tributary of this lake is the Kagera River, which has a drainage area of 60,000 km² at its outlet. The drainage basin of Lake Victoria are illustrated on Figure 1. Hydrological records at the outlet of Lake Victoria are available without interruptions since 1900. Those records show that an unusual hydrologic phenomena occurred on the in the early 1960's; it is described as follows and illustrated on Figure 2: From 1900 until 1961, the outflow from Lake Victoria fluctuated around 659 m³/s; From 1962 to 1964, the outflow increased to 1463 m³/s; From 1964 to 1980, the outflow gradually receded from 1463 to 1052 m³/s; Since 1980, the outflow fluctuates around 1052 m³/s. This phenomena is unique in the world. Dry or wet flow sequences have been observed in other areas on the Earth, but never with such an abrupt transition. No physical explanation has been found so far for this phenomena, except that the rainfall in the years 1962 to 1964 was higher than normal. No explanation is given neither for the fact that a new stable regime seems to have established since 1980, which is significantly different of the regime which prevailed from 1900 until 1962 and which was also relatively stable. Until 1954, the daily discharge at the outlet of Lake Victoria was evaluated from a rating curve established at the Ripon Falls, close to the outlet of Lake Victoria. The flow measurements used to establish this rating curve were carried out at Namasagali, 70 kilometres downstream from the Ripon Falls. In 1954, the hydroelectric development of Jinja, at the outlet of Lake Victoria, was commissioned. The discharge is now computed from the turbine flow at the plant plus the spillway flow. The Jinja project has submerged the Ripon Falls and, in order to minimize the head losses to the Jinja plant, the river channel was excavated, including the Ripon Falls; it is therefore impossible to check now the rating which was established prior to 1954 and to verify the records obtained prior to that date. G.5.2 Kagera River at Rusumo Falls The discharge of the Kagera River has been recorded at the Kyaka Ferry since 1940, and at Rusumo Falls from 1956 until 1984. The drainage area of the Kagera River at Rusumo Falls is 30,200 km². The annual flow series from 1940 to 1984 has been reconstituted for the Rusumo Falls Station, and is illustrated in Figure 3. This Figure exhibits a hydrological pattern similar to the one observed at the outlet of Lake Victoria. During the site visit in February 2004, information on the measurements carried out at the Rusumo Falls hydrometric station was collected at the department of hydrology of the MINITERE and at the department of meteorology at the MINIMFRA in Kigali; the hydrometric station was inspected during the site visit to Rusumo Falls. Those verifications led to the conclusion that the records at the station of Rusumo Falls are reasonably reliable, and that the sharp increase in flow observed in the early 1960's is probably not due to an error in measurement or in data compilation. SSEA III - Final Report G-9 017334-001-00 Appendix G - Planning Parameters and Costing of Options G.5.3 The Lake Victoria Flow Controversy A controversy is going on relatively to the reliability of the records at the outlet of Lake Victoria: One side believes that the flow records at the outlet of Lake Victoria are reasonably reliable, at least since 1925, and that the sharp flow increase in the early 1960's is due to a natural phenomena; The other side believes that the discharge measurements carried out prior to 1954 are unreliable. As a consequence, the only records which should be used for evaluating the energy production of the hydroelectric plants in this basin should be those recorded since 1954. Figure 4 illustrates the comparison between the hydrological patterns on the Kagera River at Rusumo Falls and the outlet of Lake Victoria; it demonstrates that both patterns are reasonably similar. The only difference is that the curve for the outlet of Lake Victoria reflects the strong routing effect of this lake, outflow volumes are significantly delayed as compared to observed records on the Kagera River. G.5.4 Conclusion The fact that the same hydrological pattern is observed at two different locations based on totally independent measurements tends to favour the opinion that the flow increase observed in the early 1960's was real, and it is not the consequence of an error in data record or compilation. However, a physical explanation remains to be found for this phenomena. This conclusion confirms that the hydrological records observed at Rusumo Falls provide a reliable basis for the estimation of the energy potential at that site. They could also be used as a reliable base for the derivation of historical hydrologic records for other hydroelectric sites in the same basin or nearby. G.6 Cost Estimates for Hydroelectric Options Information on the projects being assessed in this assessment is provided in the various study reports done previously. These various studies are at different levels of engineering development, and were done at different times in the past. Also in some case the documentation on these projects is not complete. Built into these estimates are possibilities for different criteria or approaches to have been used, such as application of contingencies, environmental mitigation, and overheads such as owner's costs. It is assumed that in accordance with normal practice for "economic" assessment of projects with the expectation of public sector implementation, taxes and duties have not been included. G.7 Procedure for Updating Estimates For the purpose of making the comparisons in this assessment, it was necessary to compare projects with all capital costs adjusted to a common reference year, 2004. Ideally all project costs would be re-estimated using standard criteria, however this was not practical because of the incomplete reference material. Consequently a hybrid approach has been adopted. SSEA III - Final Report G-10 017334-001-00 Appendix G - Planning Parameters and Costing of Options SSEA III - Final Report G-11 017334-001-00 Appendix G - Planning Parameters and Costing of Options Figure 2 - Long-term fluctuation of the outflow of Lake Victoria. 1900-2002 1800 1900 - 1961 1980 - 2002 1600 Mean outflow = 659 m³/s 1463 m³/s Mean outflow = 1052 m³/s 1400 s)/³ 1200 m( Long term trend wolftuO 1000 airo 800 ctiV akeL 600 400 Monthly flows 200 0 0 4 8 2 6 0 4 8 2 6 0 4 8 2 6 0 4 8 2 6 0 4 8 2 96 0 04 190 190 190 191 191 192 192 192 193 193 194 194 194 195 195 196 196 196 197 197 198 198 198 199 19 200 20 Figure 3 - Long-term fluctuation of the Kagera River flow at Rusumo Falls. 1940-1984 800 700 Flow computed based on Recorded data Kyaka hydrometric station at Rusumo Falls hydrometric station 600 )s/³ Monthly flows m(sllaF 500 o musuRta 400 Long term trend 300 Annual flows ow Fl 200 100 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 SSEA III - Final Report G-12 017334-001-00 Appendix G - Planning Parameters and Costing of Options Figure 4 - Comparison of long-term fluctuations: Lake Victoria outflow and Kagera River at Rusumo Falls 2.00 Rusumo Falls (1940-1984) 1.75 Lake Victoria outflow (1940-2002) 1.50 1.25 woflti 1.00 Un 0.75 0.50 0.25 0.00 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 EAC Projects The EAPMP provided updated cost estimates to 2004. These have been used without modification, except to recalculate the interest during construction at 10% in accordance with the criteria adopted for the SSEA study. It may be noted that for the re-estimates made during the SSEA 1 study (see below), a series of unit costs for major items were developed. It was noted that these are generally similar to those used in the EAPMP7. Thus the re-estimated costs for SSEA1 may be considered to be consistent with those re-estimates made as part of the EAPMP Eastern DRC Projects For the DRC projects, costs as of 1990 were provided for most of these sites in the Cifarha 1994 report8. The ONRD9 estimates include a 20% provision for contingencies, and 15% for owner's costs. Estimates are provided for various transmission alternatives, however these are not directly included in the capital cost estimates. The Sicai-Tractionel study 10included 10% for contingencies, and a further 30% is added for "complementary " costs. No reference is given to transmission costs. 7BKS-Acres ­ East African Power Master Plan ­ Inception Report, July 2003 8Les ressources hydro-électriques du Zaïre ­ Male Cifarha, 1994 9Étude du système électroénergétique de la Province du Kivu, Energoprojekt et ONRD, 1972 10Reconnaissance des ressources hydro-électriques dans le nord-est, Vol. 2 ­ esquisses d'aménagements, SICAI- Tractionel, Juin 1972 SSEA III - Final Report G-13 017334-001-00 Appendix G - Planning Parameters and Costing of Options The SEEE/Inter G 11 estimates include transmission, but do not refer to overheads or contingencies. It was assumed that none of the DRC estimates include interest during construction, or an allowance for environmental or mitigation costs. With regard to mitigation costs, no specific major potential environmental risks were stated or indicated in the supporting reports. For the purpose of the initial screening covered by this report, the capital costs shown in the original source reports were retained and escalated to 2004 values, using the same procedure as was applied in the SSEA I study, as described below. Interest during construction and a 5% allowance for mitigation costs were added, for consistency with the SSEA estimates. SSEA 1 Projects (Burundi, Rwanda and Western Tanzania) For six projects, new cost estimates were prepared for the SSEA 1 study, using a standardized set of unit costs, and allowances for contingencies and overheads. The projects for which new estimates were provided were: · Rusumo Falls - (Three alternative schemes); · Ruzizi III; · Kabu 16; · Nyabarongo; · Mpanda; · Igamba Falls 2. The unit costs and allowances for overheads used to derive these new estimates were determined to be similar to those used in the EAPMP, and thus may be considered as comparative. These unit costs and allowances are outlined below. For the remaining eight SSEA 1 projects the original capital costs were revised by applying escalation factors, as is outlined below. G.7.1 Standard Unit Costs The unit costs and allowances used in the SSEA 1 re-estimates are outlined as follows. Site preparation, campsite and permanent townsite Cost in the various original estimates were estimated as an allowance or shown as lump sum amounts. The amounts usually varied between 10 and 20% of the civil works costs. It is noted that in some cases, such as the 1992 Tractebel estimate for Rusumo Falls a higher amount (32%) was provided, possibly due to specific owner requirements. An amount of 20% of the civil works costs, before contingencies, was used in the re- estimates. Civil works Typical unit costs for major quantity items are shown in Table G-6 below. 11Études inventaires des sites hydrauliques en vue de leur équipement avec des mini ou microcentrales hydro- électriques au Zaïre, S.E.E.E ­ O.C.C.R.-INTER G SSEA III - Final Report G-14 017334-001-00 Appendix G - Planning Parameters and Costing of Options Table G-6 - Civil Works Unit Prices for Hydroelectric Projects - 2004 Item Unit Unit cost US$ Excavation of loose soil m3 4.00 Excavation of rippable soil m3 5.50 Rock excavation m3 17.00-20.00 Tunnel excavation ­ not coherent m3 70.00 Tunnel excavation ­ coherent rock m3 80.00 Riprap backfill m3 25.00 Structural concrete m3 150.00-165.00 Mass concrete m3 150.00 Concrete - underground m3 165.00 Shotcrete m3 40.00 Formwork m2 40.00-50.00 Reinforcing steel kg 1.05 Structural steel kg 4.00 Fill for dam m3 12.00 Filter m3 36.00 Compacted fill m3 18.00 These costs include contractor's overhead. Electromechanical costs Costs for all electromechanical equipment are based on international experience, and are derived for each item based on ratings and weights, using an in-house model that is periodically recalibrated with new bid and trade information. The electromechanical equipment includes: · Turbines; · Generators; · Powerhouse crane; · Auxiliary powerhouse mechanical equipment; · Auxiliary powerhouse electrical equipment; · Main transformers; · Switchyard equipment; · Gates for the spillway, diversion facilities, intake and the powerhouse. Costs generated for the re-estimates of projects in SSEA I, before contingencies, were in the following ranges: Turbines and generators from US$ 223 to 574/kW, with an average of US$ 345/kW Total E/M equipment from US$ 442 to 885/kW, with an average of US$ 640/kW SSEA III - Final Report G-15 017334-001-00 Appendix G - Planning Parameters and Costing of Options Contingencies The following allowances were used: Civil works - surface and underground 25% of civil works plus site preparation and townsite costs Electromechanical costs 15% Indirect costs Total cost for the generating plant included an allowance for owners' costs including engineering for design and construction supervision. The allowance used for these owners' costs was 15%. The total cost for the generating plant thus excludes interest during construction or any other financing or administration costs. Transmission The concept is that any of the new power options would supply power to the sub-region grid whether to existing line or a substation on the new interconnection grid system. For those project options for which new estimates have been prepared, the transmission cost was based on the distance to the nearest population centre in the grid (existing or new). For the other sites the previous estimates have been retained and escalated to 2004, as part of the total project cost. The reference reports usually provide the distance to a substation in the interconnected system and the voltage level. Conductor size and number of circuits were normally not indicated. Transmission costs were estimated as US$ 90,000/km, which is a representative cost for 110 kV single circuit line. The cost of additions to the grid substation to take the project infeed was assumed as US$ 500,000. For Rusumo Falls previous studies had proposed various transmission arrangements for delivery to Burundi, Rwanda and Tanzania. The 1992 Tractebel estimate included about US$ 45 000 000 for transmission, i.e. about 45% of the costs for the generation project. The estimates in this SSEA report have included allowance for a nominal distance of 10 km to the proposed grid, that would pass close to Rusumo Falls, irrespective of whether the Rusumo Falls project was constructed or not. G.7.2 Procedure for Escalating Costs from Earlier Estimates Cost data for the EAC projects were escalated to January 2004 price levels and were used as presented in the EAPMP, with the exception for adjustment of the IDC calculation to correspond to the 10% interest rate use in the current study. For the SSEA 1 and DRC projects, the estimated costs provided in the original reference reports have been escalated to present (2004) price levels using the following procedure, which reflects the fact that all prices are expressed in US$, and which therefore has to take into account exchange rate changes, as well as productivity, and increase in the extent to which labour, material and fabricated parts may be provided locally from the region. SSEA III - Final Report G-16 017334-001-00 Appendix G - Planning Parameters and Costing of Options It is recognized that there has been no escalation, or possibly even cost reduction in local costs, which may include skilled and unskilled construction labour, fabrication of certain equipment, especially gates and structural elements, construction materials, and transport of imported equipment and supplies. Also there has been a general long-term tendency to reduce costs of manufactured electromechanical equipment that may more than offset normal escalation. It is also recognized that construction costs overall have been stable for some time. Recognizing these factors, the procedure developed for the adjustment of costs using escalation indices has been to apply international escalation rates to only the foreign cost component of the civil works costs, and to assume that such escalation only applies up to the end of year 1999. On a generalized or average basis it is assumed that the civil works comprise 65% of the overall project costs, and the foreign component of the civil works cost is 50%. Consequently the foreign component of the civil works makes up approximately 32.5% of the total project cost. Thus the adjusted capital cost for a project is calculated as: Original capital cost x 32.5% x inflation index, plus Original capital cost x 67.5% x 1.00. The foreign component of the civil works costs will be made up primarily from contractors' supervisory staff, construction equipment, and fuel. In order to calculate the inflation index, figures from the United States Bureau of Reclamation (USBR) have been used. Table G-7 - Annual USBR Indices (Construction Costs Trends - Composite trend Index for January of each year) Year Index Year Index Year Index 1977 (1) 100 1990 177 1997 213 1984 153 1991 183 1998 219 1985 156 1992 186 1999 220 1986 158 1993 189 2000 228 1987 160 1994 195 2001 234 1988 163 1995 201 2002 236 1989 169 1996 207 2003 244 2004 252 For the adjustments applied in this assessment, the ceiling index was set at 220, corresponding to 1999 price levels. The formula for adjusting costs to 2004 levels is therefore: Cost 2004 = 0.325 * (Cost in year X) * 220/(Index in year X) + 0.675 * (Cost in year X) where year X is prior to 1999. Cost for projects estimated from 1999 onwards were therefore not adjusted. SSEA III - Final Report G-17 017334-001-00 Appendix G - Planning Parameters and Costing of Options G.7.3 Interest During Construction Interest during construction was added to the direct project costs to provide a more realistic approximation of the total cost of the project, to be used in calculating unit generation costs. Total interest was calculated using an interest rate of 10% and standardized schedules of expenditures during construction. Interest amounts were calculated for 3, 4 and 5-year construction programs. Interest During Construction Year of Construction % of total cost 3 15.68 4 18.05 5 25.40 For the purpose of calculating IDC, and thus generation costs, the project construction period was selected on the basis of project size. A three-year construction period (excluding tendering) was assumed for projects less than 70 MW, a four-year construction period was assumed for projects 70 MW to 150 MW, and a five-year period for larger projects. G.8 Mitigation Costs for Hydroelectric Projects Mitigation, compensation and enhancement measures are normally developed as part of environmental impact assessment studies, socio-economic impact assessment studies and resettlement plans. However, as described above, studies of this nature have been carried out on only some of the considered options. In the case where these measures and associated costs are known, the exact figure and proposed mitigating measures have been used. In other cases, it has been assumed that internationally recognized standard mitigation measures which have proven to be effective over the years would be applied. Such measures are described in Appendix G for each type of considered power options (hydropower options, fossil-fuelled thermal options, wind power options, geothermal options) as well as transmission lines. They are based on the professional experience of the Consultant and a review of current literature, particularly the following documents: · International Energy Agency. May 2000. Hydropower and the Environment: Present Context and Guidelines for Future Action. Volumes 1, 2 and 3. · International Energy Agency. May 2000. Hydropower and the Environment: Effectiveness of Mitigation Measures. · World Commission on Dams. 2000. Dams and Development: A new Framework for Decision-Making. · UNEP, United Nations Foundation, IUCN, 1999. Improving the Environmental Performance of Dams. · World Bank. Pollution Prevention and Abatement Handbook. · World Bank Safeguard Policies. The EAPMP included an allowance for mitigation costs for all projects, based on the estimates and scope provided in the original references reports. These costs were then escalated to 2004 for the EAPMP analyses. These escalated 2004 costs have been retained. SSEA III - Final Report G-18 017334-001-00 Appendix G - Planning Parameters and Costing of Options For the SSEA 1 projects, some of the reference project reports showed some allowance for mitigation measures, while others have stated that any such costs would be covered by the civil works contingency amount. In the latter cases the civil works contingency amount was usually about 25%, which is relatively high. Normally civil works contingencies will be in the order of 15%, although higher amounts would be included if there are major underground works. A contingency of 25% on civil works typically would correspond to about 15-18% of the overall project cost. By comparison, aside from special situations, mitigation costs could range from 1- 2% for a run of the river project to 5-8% of total project cost for a project with a significant upstream reservoir area. For the purpose of the SSEA I study and this stage II study it was assumed that the civil works contingency will cover routine mitigation costs for run of the river and projects with pondage. For reservoir projects a further 5% has been added. This applies to the following SSEA 1 sites: · Rusumo Falls ­ full development ­ FSL 1325 m; · Mpanda; · Luiche; · Kaganuzi; · Kishanda; · Kakono. The 5% amount has been calculated on the total project cost, exclusive of IDC, and has been added to the total cost with IDC for the calculation of unit generation costs. G.9 Multipurpose Projects ­ Shared Costs A number of identified power options also have the potential for providing benefits from flow regulation, i.e. for flood control and irrigation. These options are listed in the following table. Table G-8 - Options with Potential to Provide Benefits from Flow Regulation Option Irrigation Flood control Ewaso Ngiro Yes Yes Magwagwa Yes Yes Songwe Yes Yes Mpanda Yes Luiche Yes Yes Kaganuzi Yes Kishanda Yes Kakono Yes It may be noted that the original assessments of benefits from Rusumo Falls also referred to benefits from reduced flood flows and improved dry season flows downstream, and SSEA III - Final Report G-19 017334-001-00 Appendix G - Planning Parameters and Costing of Options consequent benefits to irrigation projects at Kyaka. However these benefits have not been a factor in the more recent planning of the project . 12 In carrying out a ranking of preferred projects, it is important that project costs be related to benefits, including those secondary (or non-power) benefits from multipurpose projects. The alternatives are either to assume some cost sharing with the non-power or secondary function, or to estimate the value of such benefits. In the case of the projects under review, for the SSEA I area, in most cases the studies are old, and at a preliminary level, and with the exception of Mpanda and Kaganuzi, no specific plans for downstream irrigation or calculations of revenues are available. In the case of Mpanda and Kaganuzi the annexes from the 1976 report on these sites that may provide some revenue estimates were not available to the consultant. Ewaso Ngiro, Mawgawa and Songwe have relatively recent and detailed reports that include the multipurpose aspects. It should also be noted that most of these studies provided reservoir operation simulations to justify assumptions on downstream-improved flows for irrigation that almost always results in a reduction of the power benefits. Conventionally for projects where the operation of the reservoir will provide significant benefits from irrigation /increased downstream regulated flows in dry periods, and/or flood control, the project may receive a government annual subsidy, or the cost of the dam will be shared directly or indirectly between power and non- power entities. For this study, given the scarcity of estimates of potential benefits, or data from which these could be estimated, for each of the above projects it has been assumed that 50% of the cost of the dam would be shared, i.e., financed by some agency responsible for the irrigation scheme or civil protection aspects such as flood control. This measure is intended as a proxy for results that may be obtained from future detailed studies. It may be noted that this nominal credit or reduction to the overall capital cost results in reductions to total capital costs in the range of 0 to 20%, as indicated below. Project Reduction as % of total cost Ewaso Ngiro 5 Kaganuzi complex 8 Kakono 18 Kishanda 3 Luche 5 Magwagwa 6 Mpanda 20 Songwe 19 12 Tractionel Electrobel Engineering, Brussels, KBO, Rusumo Falls Hydroelectric Scheme, Phase II, Part 1, Technical Feasibility, Volume 2, Preliminary Project of Structures and Works, Kingdom of Belgium, Administration for Development Cooperation, June 1987 SSEA III - Final Report G-20 017334-001-00 Appendix G - Planning Parameters and Costing of Options G.10 Fuel prices All estimated fuel prices used in this study are exclusive of taxes that may be applicable in the region. G.10.1 Fuel Prices - Oil The EAPMP Phase 1 program considered a range in crude oil prices of US$ 20 to 30/bbl and the latest least cost power development plan for Kenya assumes a base case price of US$ 25/bbl. The SSEA 1 study assumed a base or median price of US$ 40/bbl. Considering that crude oil prices have been above US$ 50/bbl with very minor exceptions for more than 1 year, and current 5 year forecasts are projecting prices in the order of US$ 50-65/bbl, it is considered appropriate to use a nominal long term crude oil price of US$ 40/bbl, exclusive of inflation, for this study. However it should be noted that minimal new oil-fired generation is included in the portfolios that are compared in Chapter 13. Consequently the selected reference oil price is not a major factor. However significantly higher assumed future oil prices would tend to favour portfolios with a high hydroelectric content. The cost of thermal generation was referenced to an offshore crude oil price of US$ 40/bbl, and delivery via Mombasa. Reference costs for alternative fuel grades are shown below. (Prices referenced to crude oil prices of US$ 30 and 50/bbl are for comparative purposes only, to show the relation between delivered diesel fuel and the reference crude oil price.) Oil fired diesel and gas turbine plants have only been assumed as an option in the Lake Victoria area. Diesels have not been considered for the EAC countries, and gas turbines (and combined cycle plants) in the EAC would be expected to be gas fired. To estimate generic diesel or oil fired combined cycle generation costs in the Lake Victoria region it was assumed that these plants would use No. 2 industrial diesel oil. Medium speed diesel units may use either industrial diesel oil or heavy fuel oil (No. 6); however, long distance truck transport of heavy fuel oil to the Lake Victoria area is problematic. The combined cycle plants in the Lake Victoria region would normally use gas or industrial fuel oil. Consequently generation costs for both type of plant have assumed use of industrial fuel oil (or alternatively gas for gas turbines). Prices for heavy fuel oil and light residual fuel are shown for comparative purposes only. Table G-9 - Reference Fuel Cost vs. Crude Oil Price - Mombasa - US$/bbl Fuel type Factor 30 US$/bbl 40 US$/bbl 50 US$/bbl Heavy fuel oil (No. 6) 0.85 31.00 39.50 48.00 Light residual fuel (No. 4) 0.90 32.50 41.50 50.50 INDUSTRIAL DIESEL (NO. 2) 1.35 46.00 59.50 73.00 "Factor" is a historical average conversion to be applied to the price of on shore crude oil. Values are from the EAPMP, and are appropriate. Price delivered to Mombasa includes US$ 5.5/bbl for transport, handling, terminal charges, insurance and losses. Equivalent values expressed at US$/Mt are as follows: SSEA III - Final Report G-21 017334-001-00 Appendix G - Planning Parameters and Costing of Options Table G-10 - Reference Fuel Cost vs. Crude Oil Price - Mombasa - US$/Mt Fuel type bbl/Mt Price at Price at Price at US$ 30/bbl US$ 40 /bbl US$ 50/bbl Heavy fuel oil (No. 6) ­ US$/Mt 6.45 200 255 310 INDUSTRIAL DIESEL (NO. 2) ­ US$/Mt 7.46 345 444 545 INDUSTRIAL DIESEL (NO. 2) ­ US$/GJ 9.7 Costs of fuel delivered to major centres in the region are derived as cost delivered at Mombasa, plus appropriate transport charges. The EAPMP has proposed a road transport cost of US$ 0.075/Mt/km, and this value has been used. For the generic diesel and combined cycle plants in the Lake Victoria area, a road distance of 1,200 km has been assumed, which is approximately the road distance from Mombasa to Kigali or Bujumbura or Kigoma. (The actual road distance from Mombasa to Kampala via Nairobi is 1134 km). This corresponds to a road transport charge of US$ 90/Mt. The resulting estimated total delivered cost of diesel fuel delivered to the Lake Victoria region is as follows: Price in US$ Offshore crude oil 40/bbl Port delivery and handling 5.5/bbl Diesel at port 59.5/bbl (= 444/Mt or 9.7/GJ) Transport ­ 1200 km 90/Mt (=12/bbl) Delivered to plant 534/Mt (=71.60/bbl or 11.63/GJ) By comparison, it is understood from Electrogaz, Rwanda, that actual June 2005 Mt delivery costs in Kigali were US$ 522/m3 or US$ 614/Mt, excluding tax. It should also be noted that fuel delivered to the Lake Victoria region (and Uganda) is normally supplied from the Eldoret pipeline terminal in Kenya. Transport costs indicated by Electrogaz for June 2005 for the Eldoret pipeline, plus road transport from Eldoret to Kigali were US$ 166/m3 or US$ 140/Mt. G.10.2 Fuel Price ­ Coal Coal prices for Kenya will depend on delivery point and source. A nominal rate of US$ 25/Mt has been indicated by the Ministry of Energy. The current least cost power development plan for Kenya has used a price of US$ 26.40/Mt13 for coal landed at Mombasa, with the assumption that it comes from South Africa. The primary reference for coal prices in Tanzania is the proposed Mchuchuma 400 MW coal fired thermal plant. There seems to be some differences of opinion on the price of coal. The latest TANESCO Master Plan makes reference to a range of US$ 25 to 27/Mt, and used a value of US$ 25.50/Mt for planning studies14. Indicated prices are in the order of US$ 22 to 32/Mt. 13 Kenya Power and Lighting company ­ The Least cost Power development Plan Update ­ 2005-2025, Draft 1, March 2004 14TANESCO ­ Power system Master Plan 2004 Update (partial copy) SSEA III - Final Report G-22 017334-001-00 Appendix G - Planning Parameters and Costing of Options New coal fired generation on the coast in Tanzania or Kenya would probably use coal imported from Richards Bay, South Africa. Alternative deliveries from South Africa were assumed by TANESCO as about US$ 25.00/Mt including US$ 5.00 for transportation and delivery. The recent history of bituminous coal prices from Richards Bay indicates significantly higher prices. On board prices quoted by Platts 15 have ranged between US$ 43 and 72/Mt between March 2004 and April 2005, as compared with less than US$ 10/Mt ten years earlier. Quoted spot market prices for coal from Richards Bay have ranged from about US$ 25/Mt in 2002 to US$ 35/Mt in 2003. This SSEA assessment uses a price of US$ 40.00/Mt FOB Richards Bay, plus transportation cost of 5 US$ plus handling charge of US$ 3 to provide a total estimated cost of US$ 48/Mt delivered to a plant on the coast at Mombasa. However the EAPMP suggested price of US$27/Mt or US$1.2/GJ has been retained in the current study. If the Mchuchuma coal price was assumed to rise to parallel cost increases for deliveries from Richards Bay, then a significant increase in generation cost at Mchuchuma would result (about 1 cents/kWh). No investigation has been made on possible siting for a thermal plant at Mombasa, and consequent local transport costs. However, it may be noted that a 2 x 150 MW plant would require an area of more than 600,000 m2, including ash storage, and the unloading facility, assuming 25,000 Mt DWT colliers would require 300 metres of dock, with storage space in the order of 50,000 m2, assuming six weeks storage with a volume of about 150,000 Mts. A greenfield unloading facility would require an investment in the order of US$ 50 million. The Mchuchuma project is being proposed as a merchant plant, and a sale price of 7 cents/kWh, at a plant factor of 85% has been discussed. This apparently includes transmission to Mufindi. G.10.3 Fuel Price ­ Natural Gas The primary source for natural gas is and will be Songo Songo in Tanzania. The EAPMP indicated that the reserves were in the order of 1 Tcf, which would be sufficient for 500 MW for about 35 years. This was costed in the EAPMP at US$ 1.5/GJ delivered to Dar es Salaam, and this was compared with then current world market prices in the order of US$ 3/GJ. The TANESCO master plan noted that Songas had assessed the gas recoverable reserves in 2003 as: Low 444 bcf Best estimate 639 bcf High 818 bcf These estimates would suggest that the median or best estimate corresponds to about 11,000 MW-years of generation at 60% CF. This in turn corresponds approximately to 500- 600 MW of generation over 20 years (the assumed economic life of a gas turbine or combined cycle plant). By comparison it is noted that the EAPMP preferred plan proposed 320 MW of gas turbine and 120 MW of combined cycle plant for Tanzania. The total of 440 MW would therefore be covered by the current best estimate of the reserve. The Songo Songo gas field was primarily developed (and financed) as part of the conversion of the Ubungo 112 MW thermal plant from oil to gas in 2004, and transfer of the plant to 15Platts Coal Trader International, March 2005 SSEA III - Final Report G-23 017334-001-00 Appendix G - Planning Parameters and Costing of Options Songas ownership16 17 18 . Songo Songo gas is designated either as protected, (i.e. for delivery to the Ubungo plant) or additional, in the latest TANESCO master plan. The 2004 plan refers to a price of US$ 0.5/GJ for protected gas supply to Ubungo, and US$ 2/GJ for additional gas supply. The master plan included sensitivity test for a range of gas prices from US$ 1.5 to 3.5/GJ. It is noted that current world market prices for gas are over US$ 5.50/GJ, and have been higher than US$ 4/GJ since the end of 2002. As natural gas alternatives for supply to gas turbines, and the addition of steam cycles to GT plants in Tanzania, as used in this study are generally common to all alternatives, the EAPMP unit price of US$ 1.50/GJ has been retained, and applies to the gas fired plants proposed in the EAPMP integrated plan. It would be assumed that the fuel cost for any additional new generation would be significantly higher. G.10.4 Fuel Price ­ Liquefied Natural Gas (LNG) Consideration was given to the use of a series of gas fired combined cycle plants to use LNG, as an alternative to further hydroelectric development on the Victoria Nile (see section 7). Because of the requirements for regasification at the delivery port, and location of the generation plant near the delivery port, this in turn requires a certain minimum delivery for LNG to be practical and economic. Primary factors that would affect the feasibility of LNG supplies include: Typical terminal and regasification capacity corresponds to about 25 to 35 million m3 per day. LNG prices are usually set by contracts in the order of 1-2 million Mt per year. A 300 MW combined cycle plant operating at 60% capacity factor would use about 1.2 million m3 of natural gas per day or 300,000 Mt of LNG/year. LNG ships usually have a capacity in the range of 125,000 to 138,000 m3 (equivalent to 60 000 to 70 000 Mt) per delivery. Thus, about 5-7 deliveries a year would be required, thus increasing on land storage requirements by a month, in addition to the normal 6 weeks reserve fuel storage for the power plant. The port delivery facilities would have to include the regasification plant, and storage would be required at the regasification plant or at the power plant. If a new greenfield harbour and unloading facility is required, the cost would be similar to that for a coal terminal, with a possible cost in the order of US$ 50 million. Current and recent LNG prices suggest a FOB price of US$ 4/Gigajoule (GJ), with a possible range of US$ 4 to 6/GJ, to which has to be added shipping, terminal charges, and regasification, and losses. Stipulated contractual prices are onboard, and include losses during liquefaction. Shipping and terminal charges are assumed as US$ 0.50 and 0.25/GJ respectively. Regasification cost would normally be between US$ 0.50 and 1.00/GJ. Costs for a small plant would be 16World Bank - Tanzania - Project appraisal document - energy sector recovery project June 2004 17World Bank - Songo Songo economic analysis - annex 4 18World Bank / IDA - Tanzania - Emergency power supply project and amendments to the legal documentation for the Songo Songo gas development and power generation project (Credit 3569 -TA), May 2004 SSEA III - Final Report G-24 017334-001-00 Appendix G - Planning Parameters and Costing of Options expected to be higher. However a regasification cost of US$ 0.75/GJ has been assumed. There will be further gas losses in the regasification and distribution process. These have been assumed at 5%. Typical makeup of a delivery cost would therefore include the following: Table G-11 - LNG prices at Mombasa LNG Costs US$/GJ 3.00 4.00 5.00 6.00 Ship/terminal 0.75 0.75 0.75 0.75 Regasification 0.75 0.75 0.75 0.75 Plant US$/GJ 4.50 5.50 6.50 7.50 Losses 5% 0.23 0.28 0.33 0.38 Total at plant US$/GJ 4.73 5.78 6.83 7.88 System cost simulations were made using a series of combined cycle plants at Mombasa, based on the plant delivery costs corresponding to FOB or contract prices of US$ 3, 4 and 5/GJ, as an alternative thermal option for replacing new hydroelectric generation on the Victoria Nile, for the sensitivity test described in Chapter 13. That analysis showed that to be an economic alternative for coal fired thermal, the LNG price would have to be less than US$ 3/GJ, which is improbable. It is also clear that delivery and regasification for the generation levels envisaged here would be uneconomic. Therefore, as is outlined above, there is no justification for assuming that LNG fuelled generation would be a feasible operation. SSEA III - Final Report G-25 017334-001-00 APPENDIX H MITIGATION MEASURES SSEA III - Final Report 017334-001-00 APPENDIX H ­ MITIGATION MEASURES TABLE OF CONTENTS PAGE H MITIGATION MEASURES H-1 H.1 Introduction H-1 H.2 Hydropower Options H-1 H.2.1 Environmental Mitigation, Compensation and Enhancement Measures H-1 H.2.2 Socio-economic Mitigation, Compensation and Enhancement Measures H-5 H.3 Fossil-Fuelled Thermal Power Options H-10 H.3.1 Environmental Mitigation, Compensation and Enhancement Measures H-10 H.3.2 Socio-economic Mitigation, Compensation and Enhancement Measures H-11 H.4 Wind Power Options H-11 H.5 Geothermal Options H-12 H.6 Transmission Lines H-12 SSEA III - Final Report 017334-001-00 APPENDIX H ­ MITIGATION MEASURES H MITIGATION MEASURES H.1 Introduction This appendix presents mitigation measures that can be used to reduce the negative environmental and social impacts of the power development options that have been retained. In many cases, mitigation will never fully compensate for natural resources and functions that are lost as a consequence of project construction and operation. Compensation measures can then be developed to compensate local populations for anticipated (or documented) negative impacts that can neither be fully avoided nor fully mitigated. Enhancement measures can also be used when it is technically and economically feasible to optimize positive impacts. Mitigation, compensation and enhancement measures are normally developed as part of environmental impact assessment studies, socio-economic impact assessment studies or resettlement plans. Since studies of this nature have been carried out on only some of the selected options, the cost associated to putting in place these measures has already been added to the total project cost, as mentioned in Chapter 7. In the case where these measures and associated costs are known, the exact figure and proposed mitigating measures have been used. Measures presented hereafter generally correspond to internationally recognized standard mitigation measures which have proven to be effective over the years. They are based on the professional experience of the Consultant and a review of current literature, particularly the following documents: · International Energy Agency. May 2000. Hydropower and the Environment: Present Context and Guidelines for Future Action. Volumes 1, 2 and 3. · International Energy Agency. May 2000. Hydropower and the Environment: Effectiveness of Mitigation Measures. · World Commission on Dams. 2000. Dams and Development: A new Framework for Decision-Making. · UNEP, United Nations Foundation, IUCN. 1999. Improving the Environmental Performance of Dams. · World Bank. Pollution Prevention and Abatement Handbook. · World Bank Safeguard Policies. Sections below present mitigation, compensation and enhancement measures related to each type of screened options (hydropower options, fossil-fuelled thermal options, windpower options, geothermal options) as well as transmission lines As much as possible, options to which such measures can be applied are identified. H.2 Hydropower Options H.2.1 Environmental Mitigation, Compensation and Enhancement Measures From the point of view of sustainable development, the best hydroelectric option is one that satisfies development requirements while maintaining the integrity of the environment as much as possible. In this sense run-of river hydroelectric projects have a less significant impact than projects with a reservoir. Run-of river hydroelectric options also have the least impact on hydrological conditions in the downstream reaches. The following are measures that can be applied to hydro options that will reduce the impacts indicated: SSEA III - Final Report H-1 017334-001-00 APPENDIX H ­ MITIGATION MEASURES H.2.1.1 Greenhouse Gas Emissions The removal of vegetation to be flooded will reduce the net greenhouse gas (GHG) emissions during the first five years of operation. Under normal conditions the decay of vegetation will produce mainly CO2; when flooded, the production of methane (a GHG equivalent to 23 times CO2) is anticipated as a result of decay in shallow tropical reservoirs. The presence of other organic material, difficult to remove, will add to net GHG emissions. This mitigation measure would be particularly relevant to the Rusumo Falls project. H.2.1.2 Land Requirements The flooding of terrestrial, aquatic and wetland habitats constitutes the main biophysical impact of hydropower projects. The most effective measures to mitigate the impact of reservoirs on land requirement are to minimize areas to be flooded by proper siting of the facility. The selection of construction camp and related installations (borrow areas, access roads, storage areas, maintenance areas, etc.) need to avoid designated habitats and natural sites and take the proper measures to avoid erosion and soil contamination. H.2.1.3 Air Pollutant Emissions and Noise Levels Particulate matter, NOx and SO2 emissions, in the case of hydroelectric projects, are mainly generated during construction (road construction and traffic, blasting excavation and quarries, wind erosion and other construction operations). In the absence of air quality standards, the promoter should determine, for particulate matter, NOx and SO2 emissions, the baseline conditions prevailing during the dry period before construction and maintain the World Bank/International Finance Corporation (WB/IFC) general guidelines for minimum ambient air conditions at the limit of the area required for construction activities. The promoter should use biodegradable soil sealing products in areas of dust generation to prevent high particulate emissions. Trucks carrying material generating dust should be covered to prevent spillage of particulate matter. For particulate matter, NOx and SO2 vehicle emissions, a maintenance program should be implemented and proper adjustment should be done regularly to minimize these emissions. A low sulphur diesel fuel should be used for internal combustion equipment at the construction site and for transportation of various material and workers. The WB/IFC recommends environmental noise standards aimed at minimizing the potential of long-term adverse effects but does not provide guidelines for noise during construction. If noise is more than 55 decibels at the construction site, ear protection equipment should be provided to the workers. At the construction camp, the noise level should be in the order of 45 decibels. If this level cannot be met, a noise absorbing wall or a mound should be erected between the noise source and the residences. H.2.1.4 Designated Habitats and Natural Sites Reservoirs are often created to the detriment of terrestrial and wetland habitats and resources. Some measures may be very effective locally to create or protect specific habitats. The loss of rare and threatened species as a result of flooding or changes in hydrologic regimes downstream has been identified as a significant issue in hydroelectric projects. SSEA III - Final Report H-2 017334-001-00 APPENDIX H ­ MITIGATION MEASURES The mitigation plans for the impacts on designated habitats and natural sites have to be site- specific and often involve enhancement of remaining habitats and natural sites nearby. The most successful mitigation, compensation and enhancement plans to restore designated habitats and natural sites are: 1. Protection of land area at a level equivalent to or better in ecological value than the lost land; this measure is easy to apply in certain areas. 2. Conservation of valuable land adjoining the reservoir for ecological purpose and erosion prevention. A conservation management plan should be initiated as soon as a decision to build the project is taken. 3. Creation of ecological reserves with rigorous and effective protective measures. 4. Enhancement of reservoir islands for conservation such on purposes, to encourage their use by migratory birds and to support a wide range of flora. 5. Development or enhancement of nesting areas for birds. 6. Creation and protection of spawning and rearing habitats for fishes in reservoirs or in tributaries. 7. Diversification of aquatic habitats in bays of the reservoir and construction of weirs to maintain water level. 8. Replacement of flooded designated habitats by habitats of similar value. 9. Morphological adjustment of land in selected area around the reservoir and revegetation to create specific habitats. 10. Targeted management plans for endangered species conservation. Murchison Falls, Ayago South being located in the Murchison Falls Natural Parks and Stiegler's Gorge being in the Selous Game Reserve will especially affect natural habitats and most of these measures apply to these options. For reservoirs with significant drawdown, habitat restoration is not appropriate especially when slopes are too steep. Measures to promote bank restoration and fast vegetation enhancement are favoured. H.2.1.5 Sedimentation and Erosion within the Reservoir and Downstream Sedimentation is a major concern for the life cycle of a reservoir. Concentration of suspended or entrained particles must be properly evaluated in order to assess all parameters that contribute to sedimentation. This requires precise knowledge about long term sediment inflow characteristics to the reservoir. The most effective measures to prevent reservoir sedimentation are: 1. Adequate bank protection in the catchment area. 2. Reforestation of area showing acute erosion process in the catchment area. 3. Changes in agriculture practices on slopes susceptible to erosion. 4. Use of sediment trapping devices upstream. SSEA III - Final Report H-3 017334-001-00 APPENDIX H ­ MITIGATION MEASURES 5. Use of bypassing facilities to divert floodwaters (run-of-river). 6. Adding sluices to the dam. This is particularly true for all reservoirs located on the Tana and Rufiji basins, respectively in Kenya and Tanzania. H.2.1.6 Invasive Aquatic Vegetation and Reservoir Eutrophication Water quality problems associated with the impoundment of reservoirs are the most difficult problems to mitigate especially if municipal waste water and agricultural runoff water are an important factor in the catchment area. These impacts can be reduced through appropriate design and operation. The water quality issues generally encountered in reservoirs are: · Dissolved oxygen depletion due to decomposition of flooded organic matter. · Water temperature changes. · Increased turbidity associated with bank erosion or sediment inflow from the catchment area. · Eutrophication due to proliferation of floating aquatic vegetation or water residence time. · Proliferation of waterborne diseases in shallow slow flowing areas. The best mitigation measures to reduce water quality problems are to reduce the area occupied by flooding and to reduce water residence time in the reservoir. Pre-impoundment vegetation clearing of reservoir is another possibility but one has to be careful that in many cases in tropical areas, growth is rapid and for large areas to be flooded, important quantities of organic material can appear between clearing and flooding. The most important problems are: · Rapid siltation in the reservoir; · Effects on water chemistry in the reservoir and downstream; · Interference with power generation (clogging intake); · Reduced fish diversity in the reservoir; · Difficulties for boats to access fishing areas or transportation of goods; · Proliferation of vectors of several human diseases (malaria and bilharzias); · Creation of cover for crocodiles and water snakes. The diversity of impacts observed in other projects suggests that the problem created by the proliferation of water hyacinth is difficult and expensive to solve. Biological control and mechanical controls are the only known methods to cope with the invasion of water hyacinth. SSEA III - Final Report H-4 017334-001-00 APPENDIX H ­ MITIGATION MEASURES Biological control of water hyacinth using weevil (beetles) has shown good results on Lake Victoria1. Water hyacinth could affect reservoirs such as Rusumo Falls and Kakono. Water hyacinth would have a tendency to colonise the shore of these reservoirs. The same biological control techniques as those applied to Lake Victoria should be applied to both reservoirs. H.2.1.7 Environmental Impacts on the Downstream Reaches Changes to downstream hydrology and sediment release have a potential to reduce local biodiversity. The disappearance of natural floods alters the natural life cycle of ecosystems downstream. The change in water quality downstream from a reservoir can be adverse for aquatic wildlife. Daily variation could also have adverse effect on the downstream habitats and increase erosion process. In order to maintain the quality of the aquatic habitats downstream, various mitigation measures are proposed and vary in terms of environmental issues. They are: 1. Application of a minimum flow at all times; 2. Water release policies that take account of ecological issues; 3. Construction of bottom outlets; 4. Periodic releases of water to recreate annual flooding cycle; 5. Surface spillway; 6. Decrease residence time of water in reservoir to provide a quality of water downstream that is similar to the water flowing into the reservoir; 7. Fish ladder. These measures will also have to take into account the impacts on the uses of the river downstream, such as fishing, irrigation, water supply or washing of clothes, particularly in the river stretch between the dam and the tailrace. If the dam becomes an obstacle to fish migration (valued scientifically or economically), the possibility to include a fish ladder into the design of the dam should be evaluated. It is easier to include fish ladders into the design of run-of-river hydroelectric installations than for high dam. The design of the fish ladder should take into considerations the species requirements. Where the fall was a natural obstacle to fish migration, it is important to evaluate if undesirable species will have access to new section of rivers upstream. Providing access to new species may be detrimental to the indigenous fish population upstream. H.2.2 Socio-economic Mitigation, Compensation and Enhancement Measures To a greater degree than for environmental impacts, the socio-economic impacts of hydropower projects are largely conditioned by the nature of project-related mitigation, compensation and enhancement measures as well as by the process leading up to their design and implementation. To a large extent, the design and implementation of such measures determine whether the project is likely to become a tool for local development and 1 Results from the Lake Victoria Management Plan (LVMP) 2005. Because of these results water hyacinth coverage of Lake Victoria is not considered a problem any more. Mary Bitekerezo, personal comm SSEA III - Final Report H-5 017334-001-00 APPENDIX H ­ MITIGATION MEASURES empowerment or a source of local impoverishment and dependence. An essential condition for a positive outcome is the meaningful consultation of all stakeholders so that their views and preferences are reflected in the mitigation measures and compensation packages developed as part of the project. The hydropower options that are considered in the comparative analysis raise the following three main socio-economic issues: · Involuntary displacement; · Public health risks; · Sharing development benefits. The following sections describe the most effective mitigation, compensation or enhancement measures to consider for each issue and to which project they apply. Considering that some of the screened options may have a high archaeological potential, mitigation measures concerning archaeological sites are also presented. H.2.2.1 Involuntary Displacement Except for the Ruzizi III, Ayago and Murchison Falls options, all hydroelectric options selected in he SSEA involve involuntary displacement. For the Bujagali option, resettlement has already been carried out in the affected area. Preliminary resettlement plans exist for the Karuma and Mutonga options. Involuntary displacement is the most sensitive issue surrounding hydropower development. It consists of two closely related yet distinct processes: (a) displacing and resettling people and (b) restoring their livelihoods through the rebuilding or "rehabilitation" of their communities. If unmitigated, involuntary resettlement often gives rise to severe economic, social, and environmental impacts. In such cases, as summarized in the World Bank Operational Policy 4.12, "production systems are dismantled; people face impoverishment when their productive assets or income sources are lost; people are relocated to environments where their productive skills may be less applicable and the competition for resources greater; community institutions and social networks are weakened; kin groups are dispersed; and cultural identity, traditional authority, and the potential for mutual help are diminished or lost". As stated by the World Commission on Dams: "Impoverishment of affected people is increasingly seen as unacceptable but it is also unnecessary since there are a wide range of opportunities available for making not only resettlers, but all affected people project beneficiaries. [ ... ] For resettlement to lead to development of those resettled, the process has to address the complexities of resettlement itself and to effectively manage the full range of political and institutional actors". Comprehensive guidelines that define this process, based on lessons learned from projects the world over, now exist. They are based on the following principles (as described in the World Bank Resettlement Policy): · Avoid or minimize involuntary displacement: All viable alternative project designs that minimize population displacement must be explored. · Improve livelihoods: The main objective of the resettlement is to assist all members of the displaced communities in their efforts "to improve their livelihoods and standards of living or at least to restore them, in real terms, to pre-displacement SSEA III - Final Report H-6 017334-001-00 APPENDIX H ­ MITIGATION MEASURES levels or to levels prevailing prior to the beginning of project implementation, whichever is higher". · Develop the resettlement plan around a development strategy: Cash payments often leave project-affected people worse off. Therefore, losses incurred by individuals and communities as a result of the project should be directly replaced and compensation should, as far as possible, be in kind, with preference to land-based resettlement strategies for displaced persons whose livelihoods are land-based. In addition to compensation measures, development assistance, such as land preparation, credit facilities, training, or job opportunities, must be provided. · Promote participation: Displaced persons must be meaningfully consulted and have opportunities to participate in planning and implementing resettlement programs. Draft plans must be disclosed in the project area to obtain the views of affected people before they are finalized. · Move people in groups: It is recommended that community groups not be split apart in order to minimize the adverse social consequences associated with community dislocation. · Rebuild communities: Displaced communities must be provided with municipal and social services (transportation, energy, water, telecommunications, education and health services, etc.) required to ensure their long-term viability. · Consider host's needs: Host communities that supply land and resources to settlers from displaced communities must be provided with the same benefits as those provided to displaced communities. · Protect vulnerable groups: Particular attention must be paid to the needs of vulnerable groups among those displaced, especially those below the poverty line, the landless, the elderly, women and children. The baseline surveys must consider all impacts that are caused by the taking of land resulting in (i) relocation or loss of shelter; (ii) lost of assets or access to assets; or (iii) loss of income sources or means of livelihood, whether or not the affected persons must move to another location. The resettlement plan must be based on sound social analysis, reliable demographic assessments and technical expertise in planning for development-oriented resettlement. It must include accurate cost assessments and commensurate financing, resettlement timetables tied to civil works construction as well as effective executing organisations. In addition, many resettlement measures depend on the involvement of other government institutions, for instance as regards, capacity building, agricultural extension services, education, etc. The resettlement plan must also include the agreements reached with relevant administrative jurisdictions and line ministries. Successful resettlement also depends on an appropriate resettlement policy framework. Current legislation on land tenure and resettlement has been reviewed for all six countries in Chapter 3 of this report. This review indicates that none of the six countries have explicit laws regarding compensation for resettlement. Thus the principles indicated above provide the best guidance available. Special attention must be paid to eligibility criteria for defining various categories of displaced persons, entitlements and methods of valuing affected assets. SSEA III - Final Report H-7 017334-001-00 APPENDIX H ­ MITIGATION MEASURES H.2.2.2 Public Health Risks All hydropower options considered in the comparative analysis involve risks of increase of malaria. Options such as Rusumo Falls, Kakono, Bujagali, Kalagala, Karuma, Mutonga and Songwe would also involve risks of increase of breeding sites for snail vectors of bilharzia. In addition, socio-cultural disruptions related to involuntary displacement can lead to health problems among the relocatees and the host populations. Epidemics can also occur as a result of the influx of migrant workers during construction as well as of migrant settlers around the reservoir. In particular, careful consideration must be given to the spread of HIV/AIDS and other sexually transmitted diseases. The control of public health risks will require co-operation between the project developer and public health authorities. Considering the underfunding of health services in all six countries, public health impacts must be considered and addressed at the very onset of the project and part of the cost of health care services should be included in the construction costs and, if required, in the project operation cost. Measures required at the initial planning and design stages should aim at gaining a proper understanding of current health conditions and at defining strategies to be implemented during construction and operation, such as: · A program of early interventions with national and local public health officials and specialists from NGOs to take into account foreseen population migrations as well as the implementation of disease prevention programs as soon as the project is announced. · The introduction of readily accessible medical clinics and dispensaries in project- affected communities and in areas where population densities are likely to increase, the hiring and training of the required staff for these new facilities, and regular support for acquiring the drugs required for disease control. · The design and implementation, by a team of specialists, of case detection and epidemiological surveillance programs to monitor changes to public health for local and regional populations. · The design and implementation of public health education programs directed at the populations affected by the project as well as at the construction workforce (in particular, a sexually transmitted diseases awareness program) During and after construction, measures must also include the design and implementation of waterborne disease vectors control programs. H.2.2.3 Sharing Development Benefits While the primary beneficiaries of the hydropower options considered in the comparative analysis live far away from the dam sites, other groups of people in the project-affected area may sustain most of the negative impacts of the projects. In view of this, there is a need for the project developer to commit to support measures for development and welfare opportunities for regional and local communities that are negatively affected by the dam. One way to fulfil this need is to share part of the benefits from project construction and operation with these communities. Opportunities provided by each project must be identified and appropriate measures to take full advantage of these opportunities must be taken. Some of these measures can be incorporated in the resettlement plan and contribute to its development objectives. SSEA III - Final Report H-8 017334-001-00 APPENDIX H ­ MITIGATION MEASURES All hydropower options considered in the comparative analysis offer opportunities for benefit sharing with local populations. Measures to optimize such benefits are described below. · Maximize employment during construction and operation: - Preferential hiring of local workers, directly for the construction works and for operation, as well as for the ancillary services (road maintenance, catering, security, etc.) and indirectly through suppliers. - Providing training for local workers in order to improve their competence and chances of employment. - Splitting construction contracts in order to allow smaller regional companies to bid. - Encouraging large construction companies to use local businesses to supply part of the services and/or equipment. · Developing multiple use of the reservoir and other facilities: - Developing irrigation perimeters downstream of the reservoir: one objective of the Songwe project is to use the reservoirs to develop irrigation. Other options such as Kakono and Stiegler's Gorge could also incorporate the development of irrigation areas downstream. - Developing reservoir fisheries on the basis of an assessment of reservoir productivity, experience of similar reservoir fisheries and the design of institutional mechanisms to maintain the long-term sustainability of the catch, employment and income. Possibilities to develop fisheries in the reservoir exist in most screened hydropower options. - Developing opportunities for pumped irrigation around the reservoir. This possibility has been identified for the Rusumo Falls project. - Wherever feasible, modify the routing of access roads to better suit the needs of the local populations. During operation, maintain roads that were built for construction to provide better access to markets and services. Access roads have to be built for the construction of all screened options, except for the Rusumo Falls option. - Electrification of local communities in the project-affected area. H.2.2.4 Archaeological Sites Some of the screened options could be located in areas with high archaeological potential, particularly options located in the Western Rift valley which includes Lake Tanganyika, the Ruzizi River and Lake Kivu. The environmental impact assessment of each project should thus include an evaluation of this potential in the affected project area (reservoir, construction camp, borrow pits, civil infrastructure, etc.) in order to identify sites with high potential. Mitigation measures could include the relocation of elements of infrastructure in order to avoid certain sites, archaeological tests, and the excavation of sites with high potential that would be destroyed, including recording and recovery. During construction, in cases of a find by chance of an archaeological site, salvage operations should be undertaken. All mitigation measures should be determined and carried out in consultation with the relevant authorities of each country. Such measures are detailed in the Bujagali, Karuma, Ruhudji and Rumakali EIAs SSEA III - Final Report H-9 017334-001-00 APPENDIX H ­ MITIGATION MEASURES H.3 Fossil-Fuelled Thermal Power Options H.3.1 Environmental Mitigation, Compensation and Enhancement Measures Air emissions are one of the main issues regarding fossil-fuelled thermal generation; emissions levels for the design and operation of each project must be established through the environmental assessment process on the basis of country legislation and the World Bank Pollution Prevention and Abatement Handbook. The concentrations of pollutants in the exhaust gases are a function of engine characteristics, operating practices and fuel compositions; poor operating or maintenance procedures can increase pollutant emissions to well above design levels. The following maximum emissions levels are normally acceptable to the World Bank: · Total SO2 emissions should be less than 0.2 metric tons/day/MW. · Total NOx emissions should be less than 320 mg/Nm3 for a gas-fired power plant; 125 mg/Nm3 for gas combustion units; 165 mg/Nm3 for combustion units fuelled with diesel No. 2; 13 gm/kWh for a diesel power plant. · Ambient noise should be lower than 55 dB(A) for residential, institutional and educational area during the day and 45 dB(A) during the night. These values apply at the boundary of the power plant property. In industrial and commercial areas noise should not exceed 70 dB(A) at any time. · Maximum values for effluent from thermal plants are: - PH: 9 - Total Suspended Solids (TSS): 50 mg/l - Oil and grease: 10 mg/l - Total residual chlorine: 0.2 mg/l - Temperature increase: <3°C A wide variety of control technologies is available. Combined cycle plants using natural gas currently have a decisive advantage in terms of costs, thermal efficiency and environmental performance. 1. Select the best power generation technology for the fuel chosen to balance the environment and economic benefits. The choice of technology and pollution control systems will be based on the site-specific environmental assessment. 2. For coal power plants coal washing should be used at the mine to reduce the SO2 emissions. 3. For coal power plants Flue Gas Desulphurisation (FGD) should be used to reduce the SO2 emissions. 4. For coal power plants Circulating Fluidised Bed (CFB) technology should be used to minimise polluting emissions. 5. For coal power plants, particulate removal equipment should be installed to remove particulates smaller than 10 microns (PM10) (health problems) especially if the power plant is built in an area of high population density. The options for removing particulates from exhaust gases are cyclones, fabric filters and electrostatic SSEA III - Final Report H-10 017334-001-00 APPENDIX H ­ MITIGATION MEASURES precipitators. The latter are available in a broad range of sizes for power plant and are efficient for particulate removal of all sizes. 6. For diesel generation, choose the cleanest fuel economically available; in any cases, natural gas is preferable to oil. 7. For diesel generation, use transportation handling and storage methods that minimize spilling of fuel. 8. Use low-NOx burners. 9. Recirculation of cooling systems where thermal discharges to water bodies may be of concern. 10. Comprehensive maintenance, monitoring and reporting system should be followed throughout the operational life of the power plant. H.3.2 Socio-economic Mitigation, Compensation and Enhancement Measures To a large extent, socio-economic impacts of fossil-fuelled thermal power options depend on determining an appropriate site for the project that takes into account socio-economic considerations. Such an approach can be considered as one of the most significant mitigation measures of thermal power plants impacts. As far as possible, sites in industrial areas, away from agricultural or residential areas, are preferred. The project layout must also take into account the increased demands on local infrastructure, such as roads, housing, medical facilities or schools that result from the influx of workers during construction and operation. As for hydropower options, involuntary displacement must be avoided or minimized. If resettlement is required, a resettlement plan must be prepared on the basis of the principles presented above. Although, thermal power options generally have fewer opportunities for multiple uses than hydropower plants, measures to share development benefits with the local population must also be considered. They will mainly concern measures to maximize employment during construction and operation. Impacts of noise and air pollutant emissions are often considered as the most significant impacts of thermal power plants. Especially in more populated areas, it is essential to follow the guidelines stated above under environmental mitigation measures. H.4 Wind Power Options Most impacts of wind power options can be minimized with an appropriate selection of the wind farm site that take into account land use conflicts, effects on landscapes and effects on wildlife. Main principles to be followed are described below with regards to land use, noise, natural and biological resources, visual impacts and soil erosion2. · Land use: avoid legally protected areas and high quality scenic areas; prefer areas that are already altered such as cultivated land; plan for efficient use of the land by consolidating infrastructure requirements. · Noise management: design sites with adequate setbacks from residential areas and rural homes; where acoustic levels are critical because of nearby residences and/or 2Most of these principles are taken from the Permitting of Wind Facilities Handbook: www.nationalwind.org/pubs/permit/permitting.htm. SSEA III - Final Report H-11 017334-001-00 APPENDIX H ­ MITIGATION MEASURES natural surroundings, investigate the possibility of using sound reduction technology on turbines. · Natural and biological resources: avoid key wildlife habitats such as migration corridors, staging/concentration areas and breeding areas; towers should not utilize lattice-type design that provide perches for avian predators. · Visual impacts: prepare accurate visual representations of potential projects for providing information to stakeholders, determining appropriate sites and adapting project design; identify scenic byways and popular vistas and avoid sites that are readily visible from those points. · Soil erosion: avoid sites that require construction activities on steep slopes. H.5 Geothermal Options Generally speaking geothermal energy is environment friendly since it only emits about 5% of greenhouse gases emitted by its fossil fuelled counterpart for the same amount of energy generated. Proper siting is the main mitigating measure to avoid land use conflicts or visual effects of the power plant. Other main mitigating measures include: · A closed circuit (re-injection) of geothermal waters to avoid air pollution (by sulphur compounds) and thermal pollution. · Appropriate solid waste disposal. · Proper sound shielding of power plant. · Filtration of water used for boring holes. H.6 Transmission Lines The best mitigation measure for transmission lines is the optimal routing of each section. The optimal routing is to avoid pre-identified constraint areas such as National Park sites (e.g., Ramsar), known areas for outstanding biodiversity and endangered species, scenic areas, urban areas, agriculture research centers and other areas to be identified at the time when routing studies are initiated. One of the most important sources of impact is related with the location of transmission towers; again, an optimal location of these structures using pre-established environmental parameters would result in minimizing the mitigation measures necessary to compensate environmental impacts. Mitigation related with the construction phase refer generally to erosion prevention, crossing water courses, identification of practices in agricultural areas; these are usually part of environmental impact assessment and should be integrated in the contract documents. SSEA III - Final Report H-12 017334-001-00 APPENDIX I DATA SHEETS FOR RETAINED POWER DEVELOPMENT OPTION SSEA III - Final Report 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Bujagali Hydroelectric Development Type Hydroelectric project ­ run of the river with pondage Location Uganda ­ Nile River d/s of Dumbbell Island, 8 km d/s of the existing Kiira/Owen Falls hydroelectric projects Project description Run of river project with about 12 hours of pondage. Conventional concrete gravity integrated intake and power house with initial installation of 4 x 50 MW turbine/generators with a normal discharge of 280 m3/s at full station output, and provision for a later 5th unit, gated spillway and overflow emergency spillway, rock/earthfill dam 400 m long, 30 m high. Full supply level 1111.5 m, tailwater 1088 m (normal operation). Capacity and Energy Installed capacity 200 MW Phase 1, plus 50 MW from 5th unit. Gross head 23.5 m. Energy values from EAPMP 4 Units 5th Unit Firm energy GWh 1390 0 Average Energy GWh 1703 222 Transmission 2 x 132 kV double circuit Bujagali to Owen Falls 2 x 5 km 220 kV double circuit Bujagali to Kawanda 70 km 132 kV double circuit Kawanda to Mutundwe 17 km Costs (2004) WB 2001 appraisal report gives Construction 321 US$M Development 74 IDC 88 Financing 98 Total 582 - Net 395 US$M without IDC and financing SSEA study used: Units 1-4 Unit 5 Units1-5 Capital cost ­ US$M 395.0 26.4 421.4 IDC - US$M 100.3 4.1 104.4 Total ­ US$M 495.3 30.5 525.8 Cost/kW US$ 2477 611 2103 Cost of firm energy - c/kWh 3.96 0 4.24 Cost of average energy - c/kWh 3.25 1.62 3.06 Implementation Project is understood to be at final design stage. AES has withdrawn its proposal to develop the project. The Uganda government is in discussions with interested developers. Project implementation period has been quoted as 44 months. For this SSEA study a 6 year total period has been anticipated, giving an earliest on-power date of January 2012 Main environmental Reservoir will require 125 ha of new land (75% agricultural land). issues Inundation of riverbanks and islands would result in loss of habitats for birds, bats and other animals. Mitigation measures (enhancement planting and gazettement of afforested areas as a forest reserve) to compensate for impacts on Jinja Animal Sanctuary. No additional impacts on water flows downstream (already influenced by Owen Falls Hydropower Project). Loss of natural habitats of Bujagali Falls. SSEA III - Final Report I-1 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Main socio-economic Resettlement already carried out in affected area. Inundation of issues Bujagali Falls would involve impact on aesthetics, loss of tourism revenues and loss of white water rafting opportunity over 2.5 km from Bujagali Falls to Dumbbell Island. Majority of rapids used for rafting are downstream of Dumbbell Island and will not be affected. Mitigation measures include the setting up of the Jinja Tourism Development Association, the construction of a Cultural Centre, of a Visitors Centre and of launching facilities for white water rafting. Provision of potable water and of alternative boat launching sites to 8 affected villages that will lose access to water. Risk of increase of breeding sites for snail vectors of bilharzia. Need for monitoring of development of snail colonies. Consulted studies and World Bank/IFC - Project appraisal document on financing to AES, reports November 2001 Knight Piesold - Bujagali Hydropower Project ­ Feasibility Study, July 1998 ESG International inc., WS Atkins Epsom, UK, prepared for AES Nile Power, Richmond, UK, Bujagali Hydropower Project, Environmental Impact Assessment, E464, March 2001 BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Appendix H, Kenya Tanzania Uganda, The East African Community, Arusha, Tanzania, November 2003 EIA status EIA approved by NEMA SSEA III - Final Report I-2 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Kabu 16 Hydroelectric Development Type Hydroelectric project ­ with hourly pondage Location Burundi, on the Kaburantwa River 16 km above confluence with Ruzizi, 50 km north of Bujumbura Project description Project would comprise a small conventional gravity dam in the main river channel with a full supply level of 1081m, approximately 11 metres above normal river levels. The dam would create a small headpond (0.02 km2 area) with live storage equal to 2 hours of plant output. The dam would be 18.5 metres high, and include spillway gates. Power facilities would include intake above the dam, a 3400 m of power tunnel and penstock, and a two unit powerhouse with an installed capacity of 20 MW under a head of 191 m. Capacity and Energy Installed capacity 20 MW Firm capacity 13 MW Average annual energy 112 GWh Firm energy 67 GWh Transmission Proposed new backbone grid would extend to Rwegura. Six km of 110 kV line with a cost of 2.5 $ million for the line and upgraded substation at Rwegura has been included in the total project capital cost. Costs (2004) SSEA study used: Capital cost US$M 38.34 IDC 6.01 Env. mitigation allowance 0.00 Total 44.35 Firm energy cost 7.40 cents/kWh Average generation cost 4.43 cents/kWh Implementation Field investigations and final engineering design required Environmental impact assessment and resettlement action plan are required Preparation of tender documents Minimum implementation time estimated as 6 years, corresponding to an earliest on-power date of January 2012 Main environmental Reservoir impact minimal due to small area (14 ha) and volume. 3 issues km river stretch with reduced flow between dam and tailrace (need for minimum flow release). During the dry period of 5 months/year, flow and level variations would be experienced downstream in the river stretch between tailrace and Ruzizi River. Main socio-economic Some 75 persons (1995 estimate) would be displaced from the issues small headpond and project area. Better access to markets and services with the construction of a 10.5 km road. Consulted studies and SOGREAH Feasibility study of Kabu 16 for Burundi MEM, reports November 1995, including a description of the main environmental and social issues. EIA status SOGREAH Feasibility study includes a description of the main environmental and social issues. Needs EIA and mitigation plan. Resettlement and rehabilitation plan required SSEA III - Final Report I-3 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Kakono (High) Hydroelectric Development Type Hydroelectric project ­ with daily pondage Location In Tanzania, on the Kagera River near the Uganda border, approximately 90 km to the west of Bukoba and Lake Victoria. Project description Project would comprise a 35 m high concrete gravity dam and spillway and earthfill dam, with a full supply level of 1182 m. The dam would create a small reservoir with live storage equal to 30 hours of plant output. Power facilities would include intake in the dam, and a two unit powerhouse at the toe of the dam with an installed capacity of 53 MW under a head of 26 m. Project was identified for power and for water supply to downstream irrigation (potential 70 000 ha). Reservoir would extend 40 km, however be about 15 km2 in area. Firm energy and flows would be increased if Rusumo dam is constructed. Potential multipurpose downstream benefits from increased dry weather flows at Kyaka irrigation project have been included in the evaluation. Capacity and Energy Installed capacity 53 MW Firm capacity 47 MW Average annual energy 300 GWh Firm energy 126 GWh Transmission Power would be delivered to the proposed new grid at Rusumo Falls over a 150 km 110 kV line. Costs (2004) SSEA study used: Capital cost US$M 71.10 IDC 11.14 Env. mitigation allowance 3.55 Total 85.79 Firm energy cost cents/kWh 7.67 Average generation cost cents/kWh 3.22 Note - cost of dam was assumed shared with downstream irrigation, so reduced by 50%. This reduced the cost of the project by 18%. Implementation Field investigations and feasibility study required, jointly with planning for downstream irrigation project at Kyaka Assessment of downstream irrigation benefits Environmental impact assessment and resettlement action plan are required Preparation of final design and tender documents Earliest on-power estimated as January 2012 Main environmental Reservoir area: 1500 ha. Project would flood part of the Minziro issues Forest Reserve. Plant could provide daily peaking, with consequent downstream flow and level variations over 75% of the year. Main socio-economic Reservoir located in medium population density area. Generation issues cost assumes 50% dam cost allocated to irrigation project. Several potential irrigation areas near Kyaka exist. Consulted studies and KBO study on the development of the Kagera River basin, 1982 reports Norconsult - prefeasibility studies of hydropower developments on the Kagera River in 1976 Norconsult ­ Kagera River basin - indicative basin plan 1976 EIA status No EIA, no resettlement and rehabilitation plan SSEA III - Final Report I-4 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Karuma Hydroelectric Development Type Hydroelectric project ­ with hourly pondage Location Uganda, Nile River, 1.5 km upstream of Kafu Bridge, immediately upstream of limit of Murchison Park. Project description Project was previously named Kamadini. Various schemes or variations were proposed in 1996 and 1996. Current scheme used for energy studies in the EAPMP is as described in the "Economic review of the Bujagali hydroelectric project" -World Bank 2001. (However data in the report refers to the 1997 master plan study). This is the scheme proposed by NORPAK. Project would consist a diversion weir at the intake, with gates to control level, diversion into an underground powerhouse with 4 x 50 MW units = 200 MW, and 2 km of tailrace tunnel. Plant discharge at full output is 1000 m3/s. Project uses natural drop of 28 meters at Karuma falls. Capacity and Energy Installed capacity 200 MW Gross head 28 M Average energy 1747 GWh Firm energy 1619 GWh Values from EAPMP Transmission Karuma to Masindi 220 kV, DC, 90 km Karuma to Lira 132 kV, SC, 90 km Costs (2004) SSEA study used: Capital cost ­ US$M 428.9 IDC - US$M 108.9 Mitigation cost US$M 6.6 Total ­ US$M 544.4 Cost/kW US$ 2722 Cost of firm energy - c/kWh 3.74 Cost of average energy - c/kWh 3.47 Implementation Pre-feasibility study in 1997. Project Definition Report issued by the developer NORPAK in 1999. Certificate of Approval of the Environmental Impact Study was issued by NEMA in 2000. Implementation time is assumed for SSEA as 8 years, giving an earliest on-power date of January 2014 Main environmental Reservoir impact minimal due to small area (1.8 ha) and volume. issues There would be a 2.8 km river stretch with reduced flow between dam and tailrace. A flow of 50 m3/s would be maintained. There would be no natural flow modification downstream from the outlet. About 7 hectares of terrestrial habitat would be lost. Main socio-economic Resettlement of some 35 households. Reduction of visual amenity of issues Karuma Falls and of potential for tourism (no white water rafting opportunity in impacted area). Better access to markets and services with the construction of access roads (about 4.5 km). SSEA III - Final Report I-5 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Consulted studies and Kennedy and Donkin, (Uganda) Hydropower Development reports Master Plan, 1997 BKS Acres, East African Power Master Plan Study, Phase II Report, March 2005 NORPAK memorandum ­ Karuma Falls Hydropower Project ­ Costs, time Schedules etc., March 2004 ESG International inc., WS Atkins Epsom, UK, prepared for AES Nile Power, Richmond, UK, Bujagali Hydropower Project, Environmental Impact Assessment, Facility EIA, Uganda, E464, March 2001 BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Appendix H, November 2003 Norplan A.S., Karuma Falls Hydropower Project, Uganda, Environmental Impact Assessment, Volume 1: Main report, Final Report, May 1999 EIA status EIA approved by NEMA Resettlement and rehabilitation plan required SSEA III - Final Report I-6 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Masigira Hydroelectric Development Type Hydroelectric project with pondage Location Tanzania, Ruhuhu River, 80 km to east of Lake Nyasa. Project description Two adjacent rock fill dams, with gated spillway, headpond with storage equal to 6 hours maximum plant flow. 1100 m of low pressure power tunnel, shaft, underground powerhouse with 2 x 59 MW units = 118 MW, 500 m tailrace tunnel. Total length of affected river is 2 km Capacity and Energy Installed capacity 118 MW Gross head 238 M Average energy 695 GWh Firm energy 528 GWh Values from EAPMP Transmission Masigira to Mufundi, 220 kV SC, 165 km Costs (2004) SSEA study used: Capital cost ­ US$M 157.0 IDC - US$M 28.3 Mitigation cost US$M 4.9 Total ­ US$M 190.2 Cost/kW US$ 1612 Cost of firm energy - c/kWh 4.06 Cost of average energy - c/kWh 3.08 Implementation Pre-feasibility completed in 1997, as part of a national masterplan. EAPMP proposed 7 years implementation time. SSEA has assumed earliest on-power as January 2013 Main environmental High erosion risk has been observed in the proposed reservoir issues area. The project is located in a pristine environment rich in wildlife. A minimum flow should be maintained to minimise effects on the river stretch with reduced flow. Change in flow and nutrient transport could affect Nyasa Lake. Main socio-economic Project located in low density population area. issues Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 SwedPower jv and Norconsult, Tanzania Power VI Project, Feasibility Studies for Hydropower Projects, Interim Report No. 2, Final, Volume 1, Tanesco, Tanzania Electric Supply Company Ltd, March 1997 EIA status No EIA, no resettlement and rehabilitation plan SSEA III - Final Report I-7 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Mpanga Hydroelectric Development Type Hydroelectric plant with pondage Location Tanzania, Mpanga River, 40 km downstream of the Lower Kihansi project or 65 km south east of Mufindi Project description Dam, low pressure power tunnel, surge tank, shaft, underground powerhouse, with 2 x 72 MW= 144 MW, tailrace tunnel. 6 km of river would be affected. Pondage would be equivalent to about 16 days of full plant discharge Capacity and Energy Installed capacity 144 MW Gross head 374 m Average energy 1028 GWh Firm energy 863 GWh Values from EAPMP Transmission Mpanga to Mufindi and Kihansi, 220 kV SC97 km Costs (2004) SSEA study used: Capital cost ­ US$M 190.8 IDC - US$M 34.4 Mitigation cost US$M 7.2 Total ­ US$M 232.4 Cost/kW US$ 1614 Cost of firm energy - c/kWh 3.03 Cost of average energy - c/kWh 2.55 Implementation Pre-feasibility completed in 1997, as part of a national masterplan. EAPMP proposed 8 years implementation time. SSEA has assumed earliest on-power as January 2014 Main environmental Could affect the hydrology of the Mpanga River which flows in issues Kilambero, an important floodplain and Ramsar site. Annual flooding is a crucial factor in the maintenance of the wetland habitats and the fertility of the soils for vegetation and fisheries. A minimum flow should be maintained to minimise effects on the river stretch with reduced flows. Transformation of terrestrial habitat to lacustrine habitat in pond area. More data required. Main socio-economic No settlement or farmland would be affected by the reservoir. issues Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 SwedPower jv and Norconsult, Tanzania Power VI Project, Feasibility Studies for Hydropower Projects, Interim Report No. 2, Final, Volume 1, Tanesco, Tanzania Electric Supply Company Ltd, March 1997 Rufiji Basin Development Authority, Rufiji Basin Hydropower Master Plan, Annex, Environmental Impacts and Multipurpose Benefits, November 1984 Rufiji Basin Development Authority, Rufiji Basin Hydropower Master Plan, Executive Summary, November 1984 Fishpole, L.D. and Evans, M.I. eds. 2001. Important Bird Areas in Africa and Associated Islands: Priority Sites for Conservation. Birdlife Conservation Series No. 11, Bird Life International. Cambridge. http://www.wetlands.org/reports/dbdirectory.cfm?site_id=108 EIA status No EIA/SIA SSEA III - Final Report I-8 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Mutonga Hydroelectric Development Type Hydroelectric project with hourly pondage Location Kenya, Tana River immediately downstream of the Kiambere hydroelectric project Project description Conventional concrete gravity dam 60 m high, including a gated spillway section, surface powerhouse at the dam with 2 x 30 MW units, pondage equivalent to 6 days of full plant discharge Capacity and Energy Installed capacity 60 MW Gross head 39 M Average energy 328 GWh Firm energy 293 GWh Values from EAPMP Transmission Mutonga to Kiambere to Masindi, 220 kV, DC, 4 km Costs (2004) SSEA study used: Capital cost ­ US$M 196.70 IDC - US$M 15.68 Mitigation cost US$M 1.90 Total ­ US$M 229.44 Cost/kW US$ 3824 Cost of firm energy - c/kWh 8.68 Cost of average energy - c/kWh 7.76 Implementation Feasibility study by Nippon Koei completed in 1997. EAPMP suggested a year implementation period, including further environmental studies, financing/tendering and 4.5 years of construction. SSEA has used 7 years with earliest on-power in January 2013 Main environmental Modification of terrestrial to lacustrine habitats related to the issues creation of a 11 km2 reservoir. Sediment trapping in the reservoir (at least some 5.5 Mt per year), which could lead to degradation of bottom life and productivity of the reservoir. Degradation of the riverbed downstream of the dam affecting river morphology, particularly in a 40 km reach downstream of Kora Rapids. Provision will be made to release sediments. Possible reduction of riverine forest area. The Mutonga alternative would have much less impact on downstream habitats than the High Grand Falls and Low Grand Falls alternatives. Main socio-economic Resettlement of some 1000 people from the reservoir area issues (estimate of people that would have been displaced in 2003). Risk of increase of malaria and bilharzia. The Mutonga alternative would have much less downstream effects on freshwater fisheries, traditional flood recession farming and flood plain grazing resources than the High Grand Falls and Low Grand Falls alternatives. Consulted studies and Nippon Koei Co, LTD. Pasco International Inc. Feasibility reports Study on Mutonga/Grand Falls Hydropower Project. Progress report, Volume 2: Environmental Assessment Report. Report prepared for the Japan International Cooperation Agency and the Tana and Athi Rivers Development Authority, February 1995 Republic of Kenya. Ministry of Energy, Japan International Cooperation Agency, Feasibility Study on Mutonga/Grand Falls Hydropower Project, Draft Final Report, Executive Summary for Environmental Assessment, October 1997 SSEA III - Final Report I-9 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION EIA status EIA published in 1995 called phase 2, considering importance of potential impacts a phase 3 EIA is recommended. This phase 3 would also include: Additional studies with regards to sediment trapping and downstream effects and the definition of reservoir operation rules taking into account power generation and controlled release of downstream floods. Resettlement and rehabilitation plan required. SSEA III - Final Report I-10 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Ruhudji Hydroelectric Development Type Hydroelectric plant with separate upstream storage reservoir Location Tanzania, Ruhudji River, approximately 70 km to the east of Njombe. Power scheme is approximately 8 km downstream of the Zanziberi storage dam Project description Upstream storage with seasonal regulation (equivalent to 70 days of full station discharge) would be provided by the Zanziberi storage dam. Earthfill dam 67 m high, 820 m crest length, and free overflow spillway. Power station would include a concrete gravity dam with a height of 32 metres, free overflow spillway, 7300 m long low pressure power tunnel, shaft, underground powerhouse, 4 x 89.5 MW units = 358 MW, and 3100 long tailrace tunnel. Full station discharge is 54 m3/s, compared with annual mean discharge of 35 m3/s. Flows would be regulated in the 13 km reach from the storage dam to the intake dam, and would be severely reduced for the 15 km river distance from the intake dam to the tailwater discharge. Capacity and Energy Installed capacity 358 MW Gross head 765 m Average energy 1930 GWh Firm energy 1476 GWh Values from EAPMP Transmission Ruhudji to Kihansi, 220 kV, 150 km Costs (2004) SSEA study used: Capital cost ­ US$M 384.0 IDC - US$M 97.5 Mitigation cost US$M 5.3 Total ­ US$M 486.8 Cost/kW US$ 1360 Cost of firm energy - c/kWh 3.74 Cost of average energy - c/kWh 2.86 Implementation Project was evaluated to a feasibility level in 1998. The EAPMP suggested an 8 year period for implementation. SSEA has used an earliest on-power date of January 2014 Main environmental Modification of terrestrial to lacustrine habitats in the Zanziberi issues storage dam. Total reservoir area: 1560 ha. Modification of hydrological and nutrient transport conditions in the stretch of river between the storage and the intake dam. 15 km river stretch with reduced flow between intake dam and tailrace (need for minimum water flow release). Could affect the hydrology of Ruhudji River which flows in Kilambero, an important floodplain and Ramsar site. Annual flooding is a crucial factor in the maintenance of the wetland habitats and the fertility of the soils for vegetation and fisheries. Main socio-economic Project located in a low population density area (reservoir and issues bypassed river section). Better access to markets and services with the construction of access roads. SSEA III - Final Report I-11 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 SwedPower jv and Norconsult, Tanzania Power VI Project, Feasibility Studies for Hydropower Projects, Interim Report No. 2, Final, Volume 1, Tanesco, Tanzania Electric Supply Company Ltd, March 1997 SwedPower jv and Norconsult, Tanzania Power VI Project, Feasibility Studies for Hydropower Projects, Ruhudji Hydropower Project, Environmental & Social Impact Assessment, Final Report, TANESCO, Tanzania Electric Supply Company Ltd, May 1998 Rufiji Basin Development Authority, Rufiji Basin Hydropower Master Plan, Executive Summary, November 1984 Fishpole, L.D. and Evans, M.I. eds. 2001. Important Bird Areas in Africa and Associated Islands: Priority Sites for Conservation. Birdlife Conservation Series No. 11, Bird Life International. Cambridge. http://www.wetlands.org/reports/dbdirectory.cfm?site_id=108 EIA status Further work required to firm up EIA and mitigation plan Further work required on sediment and nutrient transport. Resettlement and rehabilitation plan required SSEA III - Final Report I-12 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Rumakali Hydroelectric Development Type Hydroelectric project with storage Location Tanzania, Rumakali River, 85 km west of Njombe Project description Concrete gravity dam (RCC), 72 m high, 870 m crest length including fill embankments on abutments, free overflow spillway, low pressure unlined power tunnel, 3200 m long, lined power tunnel 1100 m long, surge shaft, high pressure penstock 3100 m long, underground powerhouse, 3 x 74 MW units= 222 MW, tailrace tunnel 3000 m long, maximum plant discharge 19 m3/s compared to average runoff of 13 m3/s. River flow would be severely reduced over 17 km Capacity and Energy Installed capacity 222 MW Gross head 1295 m Average energy 1141 GWh Firm energy 1170 GWh (system increment from adding project) Values from EAPMP Transmission Rumakali to Itwe, 220 kV, SC, 94 km Costs (2004) SSEA study used: Capital cost ­ US$M 351.3 IDC - US$M 89.2 Mitigation cost US$M 10.1 Total ­ US$M 450.6 Cost/kW US$ 2030 Cost of firm energy - c/kWh 4.32 Cost of average energy - c/kWh 4.43 Implementation Project was evaluated to a feasibility level in 1998. The EAPMP suggested a 10 year period for implementation SSEA has used an earliest on-power date of January 2016 Main environmental Modification of terrestrial to lacustrine habitat in the reservoir area issues (1320 ha). There would be a 17 km river stretch with reduced flow between dam and tailrace (need for minimum water flow release). Possible modification of water flows and levels in the wetlands downstream of the dam before Nyasa Lake. Main socio-economic Inundation of agricultural land and of a village with 80 buildings. issues Reduction of flood risks downstream. Better access to markets and services with the construction of access roads. Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 SwedPower jv and Norconsult, Tanzania Power VI Project, Feasibility Studies for Hydropower Projects, Rumakali Hydropower Project, Final Report, Volume RUM.1, Tanesco, Tanzania Electric Supply Company Ltd, May 1998 EIA status Further work required to firm up EIA and mitigation plan Further work required on sediment and nutrient transport in flood season. Resettlement and rehabilitation plan required SSEA III - Final Report I-13 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Rusumo Falls Hydroelectric Development Type Hydroelectric project ­ with storage Location Border between Rwanda and Tanzania, close to Burundi, on the Kagera River, at highway crossing between Rwanda and Tanzania Project description Project would comprise a conventional gravity dam in the main river channel with a full supply level of 1325 m, approximately 5 metres above normal river levels. The raised river levels from the forebay would provide some flooding upstream in the Ruvuvu River, and would marginally affect levels in Lake Rweru, approximately 70 km upstream on the Nyabarongo River. The dam would be 12 metres high, and include spillway gates. Power facilities would include intake above the dam, a 460 m power tunnel and a three unit powerhouse with an installed capacity of 61.5 MW under a head of 35 m. Project would increase downstream flows in dry periods, and potentially improve the viability of the Kakono hydro project and the Kyaka irrigation project. No downstream benefits have been allowed for in the evaluation Capacity and Energy Installed capacity 61.5 MW Firm capacity 55 MW Average annual energy 403 GWh Firm energy 308 GWh Transmission Proposed new backbone grid would pass the site. A nominal 10 km of 110 kV line with a cost of 1.4 $million has been included in the total project capital cost. Costs (2004) SSEA used: Capital cost US$M 94.07 IDC 14.75 Env. mitigation allowance 4.70 Total 113.52 Cost/kW US$ 1846 Cost of firm energy - c/kWh 4.14 Cost of average energy - c/kWh 3.16 Implementation Final engineering studies required to confirm reservoir levels and available storage, and to finalize the civil works design Environmental impact assessment and resettlement action plan are required Agreements required between Tanzania, Burundi and Rwanda Implementation time estimated as 6 years, corresponding to an earliest on-power date of January 2012 Main environmental Extent of upstream flooding in the Ruvuvu and Nyabarongo Rivers issues and in Lake Rweru to be confirmed by impacts assessment (satellite photo of estimated reservoir limits follows this data sheet). Upstream flooding from the dam estimated as in the order of 400 km2 , that includes 125 km2 of existing lake and 250 km2 of existing wetlands and 15 km2 of valley slopes. Reduction in downstream flood flows and levels could affect wetlands downstream, including in the Akagera National Park. A Run-of-River option would reduce the extent of reservoir area. Whichever design option is selected the sedimentation issue needs to be taken into account. Main socio- Approximately 3000 persons upstream of the dam may be affected economic issues and some displaced. Increase in water areas upstream could increase health risks due to bilharzia and malaria. Consulted studies Acres, Review of existing documents for the Rusumo Falls 2003 and reports Tractebel, KBO, Institutional/ tariff studies, Rusumo Falls, 1997 SSEA III - Final Report I-14 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Tractebel, Rusumo Falls ­ transmission studies 1994-1995 Tractebel, KBO, Rusumo Falls, Tender documents, civil works, electromechanical equipment, April 1989, revised January 1992. Tractionel, KBO, Rusumo Falls, technical feasibility, preliminary study of structures and works, June 1987 Tractionel-Electrobel - Rusumo Falls, Agriculture & other implications ­ inventory of the agriculture situation, March 1979 Norconsult A.S./Electrowatt, Kagera River Basin Development, Prefeasibility Studies, including Rusumo Falls Hydropower Project, April 1976 Visit made by the consultant to the Rusumo Falls Project site EIA status No EIA, no resettlement and rehabilitation plan SSEA III - Final Report I-15 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Ruzizi III Hydroelectric Development Type Hydroelectric project ­ with hourly pondage Location Site RD 2 on the Ruzizi River, which forms the border between Rwanda and the DRC. 25 km downstream (south) of the outlet of Lake Kivu. Project description Project would be located downstream of the Ruzizi I and II existing plants, and flows would be nearly completely regulated by Ruzizi I operation of Lake Kivu as a reservoir. Project would comprise a 20 m high concrete gravity spillway and earthfill dam, with a full supply level of 1082m. The dam would create a small headpond (0.1 km2 area) with live storage equal to 1 hour of plant output. Power facilities would include intake in the dam, a 340 m power tunnel and penstock, and a three unit powerhouse with an installed capacity of 82 MW under a head of 62 m. Capacity and Energy Installed capacity 82 MW Firm capacity 81 MW Average annual energy 418 GWh Firm energy 418 GWh Transmission Power would be delivered to the Mururu 2 substation at the Ruzizi I plant over a 23 km 110 kV line. Costs (2004) SSEA used: Capital cost US$M 89.09 IDC 16.08 Env. mitigation allowance 0.00 Total 105.17 Cost/kW US$ 1283 Cost of firm energy - c/kWh 2.86 Cost of average energy - c/kWh 2.86 Implementation Field investigations and feasibility study required Environmental impact assessment is required Preparation of final design and tender documents Implementation time estimated as 8 years, corresponding to an earliest on-power date of January 2014 Main environmental Reservoir impact minimal due to small area (10 ha) and volume. issues River flows would be diverted through the power facilities at all times except during floods, affecting 1 km of river (need for minimum flow release). Downstream flows may vary considerably during normal daily operation (from 50 to 175 m3/s). Main socio-economic Reservoir located in low population density area. Population issues farther downstream would be affected by flow and level variations. Consulted studies and Tractabel - study of the hydroelectric potential of the Ruzizi reports valley. 1993 Tractabel prefeasibility study of RD2 site in 1992 Visits made by the consultant to the Ruzizi III Project site EIA status No EIA, no resettlement and rehabilitation plan SSEA III - Final Report I-16 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Songwe Hydroelectric Development Type Hydroelectric development, 3 dams and hydro plants in cascade, with storage Location Tanzania and Malawi, Songwe River. Upper dam on border with Tanzania near Bupigu, middle and lower projects in Malawi. Middle dam near confluence with Sofwe, and lower dam near confluence with Manolo Project description Power projects are part of an overall basin development plan for the stabilization of the Songwe River. The November 2003 study by NORPLAN, considered a 4 packages with different combinations of dams and full supply levels, and with priorities for flood control or power. The report recommends Package 4 as the basis for the Songwe River Basin Development Plan. SSEA study has assumed Package 4, which consists of three dams with power plants, with operation priority on power generation, however with additional storage for flood mitigation at Middle and Lower dams. Upper dam (Bupigu) FSL 1245 34 MW Middle dam (Sofwe) FSL 1140 157 MW Lower dam (Manolo) FSL 780 149 MW Total 330 MW Dams are assumed as concrete gravity (RCC) Potential multipurpose downstream benefits from flood control and increased dry weather flows have been included in the evaluation. Capacity and Energy Installed capacity 330 MW Average annual energy 1352 GWh Firm energy Not available GWh Transmission Cost estimate assumes 200 km of 132 kV line ­ connecting to both Tanzania and Malawi. One option is to connect at 300 kV to the planned Zambia-Tanzania interconnection. The upper dam would only supply local loads - to Chitipa in Malawi and Itumba in Tanzania. Costs (2004) SSEA study used: Capital cost US$M 336.83 IDC 52.82 Env. mitigation allowance 17.95 Total 407.60 Firm energy cost cents/kWh N/A Average generation cost cents/kWh 3.43 Note - cost of the 3 dams was assumed shared with downstream flood control and irrigation, so reduced by 50%. This reduced the cost of the project by 19%. Implementation The assessment of the project is considered to be at the pre- feasibility stage, as no field work has been done, and the project is not fully defined. Based on the status of the project and its size, an overall lead time to earliest on-power is estimated as 9 years, corresponding to an earliest on-power date of January 2015. Main environmental Creation of three reservoirs (total area: 5600 ha) involving loss of issues wetlands and modification of terrestrial habitat. Seasonal regulation of water flows. River stretches totalling 12.4 km with reduced flow between dam and tailrace (need for minimum flow release). Dams will block fish migration. Possible encroachment in protected areas. SSEA III - Final Report I-17 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Main socio-economic The two downstream reservoirs are located in high population issues density area and would involve significant population displacement. Increased health risks (malaria and bilharzia). Significant flood control and irrigation benefits. Consulted studies and NORPLAN in association with COWI, DHI and WPES, reports Feasibility Study for the Stabilisation of the Course of the Songwe River, Feasibility Study Report, A joint project between the Government of the United Republic of Tanzania and the Government of the Republic of Malawi, November 2003 EIA status No EIA, no resettlement and rehabilitation plan SSEA III - Final Report I-18 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Upper Kihansi Hydroelectric Development Type Storage dam to regulate flows to an existing downstream hydro project Location Tanzania, Kihansi River in the Rufiji River basin, 12 km upstream of Lower Kihansi existing power project Project description Earthfill dam, 65 m high to provide storage, equivalent to 20 days of average river flow. Capacity and Energy Attributed benefits (EAPMP) at the Lower Kihansi power project are: Average annual energy 124 GWh Firm energy 11 GWh Transmission N/A Costs (2004) SSEA study used: Capital cost US$M 81.2 IDC 12.7 Env. mitigation allowance 4.2 Total 98.1 Firm energy cost cents/kWh N/A Average generation cost cents/kWh 8.7 Implementation Project is considered to be at the pre-feasibility level. Total estimated implementation time is 7 years (EAMPMP suggested 6 years), resulting in an SSEA earliest on-power date of January 2013 Main environmental Transformation of terrestrial to lacustrine habitat in reservoir. issues Reservoir will possibly encroach on primary forest habitat. Project could regulate the flow of the Kihansi River which flows in Kilambero, an important floodplain and Ramsar site. Annual flooding is a crucial factor in the maintenance of the wetland habitats and the fertility of the soils for vegetation and fisheries Main socio-economic No resettlement involved. A 3 km road stretch would be inundated. issues Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 SwedPower jv and Norconsult, Tanzania Power VI Project, Feasibility Studies for Hydropower Projects, Interim Report No. 2, Final, Volume 1, Tanesco, Tanzania Electric Supply Company Ltd, March 1997 Norplan A.S. in association with Norconsult and IVO International, Lower Kihansi Hydropower Project, Preliminary Environmental Baseline Study Report, Main Volume, Preliminary Version, Tanesco, Tanzania Electric Supply Company Limited 1995 Rufiji Basin Development Authority, Rufiji Basin Hydropower Master Plan, Annex, Environmental Impacts and Multipurpose Benefits, November 1984 Rufiji Basin Development Authority, Rufiji Basin Hydropower Master Plan, Executive Summary, November 1984 Fishpole, L.D. and Evans, M.I. eds. 2001. Important Bird Areas in Africa and Associated Islands: Priority Sites for Conservation. Birdlife Conservation Series No. 11 Bird Life International. Cambridge. http://www.wetlands.org/reports/dbdirectory.cfm?site_id=108 EIA status No EIA/SIA SSEA III - Final Report I-19 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Generic Wind Farm Type Wind energy conversion Location Non-specified. Tanzania is studying sites at Gomvu, Litembe, Mkumbara and Karatu. There is a proposal for a wind farm in South Kinagop in Kenya Project description SSEA study has considered a project that would consist of fifteen 2 MW generating wind turbines, for a total installed capacity of 30 MW. Estimated annual energy production of each of the 2 MW wind turbines would be 3.6 GWh, for a wind farm capacity factor (CP) approximating to 20%. Capacity and Energy Site specific- for viability plant factor would have to be greater than 24 to 30%. A 30 MW installation would have to yield at least 63 GWh Transmission Not specified for the generic plant. Power from a wind farm at Mkumbara would be delivered to the existing HV grid connecting Tanga to Moshi (15 km) Costs (2004) Average generation cost for a viable plant would be in the 7-9 cent/kWh range. The cost derived for the Mkumbara site is 8.3 cents/kWh Implementation Projects would be IPPs. Implementation time would include the feasibility studies, commercial process, supply and installation. A minimum lead time to on-power is assumed as 4 years Main environmental Potential impact on valued natural habitats. Possible collision of issues birds with blades. Main socio-economic Potential impacts on landscapes. Siting of wind turbines must issues take into account land tenure systems and potential land use conflicts and noise and infrasound effects. Consulted studies TaTEDO newsletter, Issue 10, July 2005-09-09 and reports RISO National laboratory, Denmark, Wind measurements and Windpower feasibility at selected sites in Tanzania, December 2003 Kenya Subsidiary Legislation, 2003, Environmental Impact Assessment (EIA) for a Proposed Wind Farm in South Kinangop, Kenya, for ECOGEN Wind Farms Ltd La filière éolienne, sommaire des impacts environnementaux au Québec, Vice-présidence Environnement, Hydro-Québec, 1995 EIA status Each project would require EIA/SIA SSEA III - Final Report I-20 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Generic geothermal Type Geothermal Power Plant Location Not specific. However identified sites for specific projects include Suswa-Longonot-Olkaria-Menengai Geothermal Fields, inside or close to Hell's Gate and Nakuru Nationals Parks, in Kenya Project description It is proposed that each new project would consist of 70 MW generating plants. (It is noted that the extension of existing Olkaria Geothermal Plant would consist of 35 MW additional capacity). Also Menengai geothermal field has enough potential for two 70 MW units, for a total of 140 MW installed capacity. Capacity and Energy Installed capacity and annual energy at 80% PF: 35 MW 245 GWh 70 MW 491 GWh 140 MW 981 GWh Transmission Not specific. However power from Olkaria, Longonot and Suswa geothermal plants would be delivered to the new proposed grid (backbone) connecting Nairobi to Lessos. Power from Menengai geothermal plant would be delivered to the existing grid at Nakuru City. Costs (2004) EAPMP provides a cost of 147.5 USM$ for a standard 70 MW geothermal station, i.e., 2107 $/kW, and a unit cost of 2021 $/kW for the Longonot, Suswa and Menengai planned stations. SSEA has used a cost of 2352 $/kW for these stations, including IDC, and this would be representative for a generic station. It has used 2645 $/kW for the Olkaria extension. Average Energy Costs (cents/kWh) Olkaria Other Plants 25% PF 16.26 14.55 50% PF 8.28 7.42 75% PF 5.62 5.05 Implementation A complete program of investigations would take 4-6 years, and commercial aspects, design and construction, a further 2-4 years. Total least time to earliest on-power would be 8-10 years following completion of initial field work Main environmental Requires land for the geothermal steam holes. Possible conflict issues with terrestrial habitat. Olkaria site is located in Hell's Gate National Park. Possible CO2 and H2S emissions depending on source. Main socio-economic Siting and design of plant must take into account land tenure issues systems and potential land use conflicts and noise effects. Consulted studies and GIBB Africa Ltd., Kenya Electricity Generating Company reports Limited, Environmental Impact Assessment for Olkaria II 3rd Unit Extension Project, Draft Report, June 2004 Sinclair Knight Merz, Environmental Baseline Report, Eburru Power Development Project, The Kenya Power Company Limited, June 1994 BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Appendix H, Kenya Tanzania Uganda, The East African Community, Arusha, Tanzania, November 2003 EIA status Each project would require EIA/SIA SSEA III - Final Report I-21 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Mombasa Gas/LNG Steam Type Gas fired steam electric thermal station Location Mombasa, adjacent to a dedicated dock and re-gasification plant, at a new, unidentified site. Project description Multiple 180 MW combined cycle units. Configuration assumed for the SSEA is 2 x 60 MW combustion turbines exhausting to 1 - 60 MW conventional condensing steam turbine = 180 MW/unit. Re-gasification facility would also have to be constructed. Gas requirements would be in the order of 200,00 MT of LNG per year for each 180 MW unit. This type of generation was not considered in the SSEA generation plans, due to relatively high generation cost and uncertainty over cost of low level of fuel deliveries. Capacity and Energy 180 MW per unit, generating 1260 GWh at 80% plant factor Transmission To the grid at Mombasa. Costs (2004) Capital cost 790 $/kW, or 895 $/kW with IDC. Average energy costs: PF 25% 11.36 cents/kWh PF 50% 8.38 PF 75% 7.39 Based on cost of offshore LNG at 4 $/Gj equivalent to 5.80 $/Gj regasified at the plant Additional capital cost would be incurred for the docking facility and the regasification plant Implementation Construction of the regasification plant and thermal plant would take 4 years, after approvals and commercial arrangements had been made. This suggest a total minimum lead time of 6-8 years Main environmental Greenhouse gas and air pollutant emissions. Thermal and issues conventional pollution of cooling water. Siting and construction of docking, re-gasification plant and transportation to power plant. Main socio-economic Siting and design of plant must take into account land tenure issues systems and potential land use conflicts and noise effects. Cumulative impacts of air pollutant emissions on public health. Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Appendix H, Kenya Tanzania Uganda, The East African Community, Arusha, Tanzania, November 2003 EIA status No EIA/SIA SSEA III - Final Report I-22 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Mombasa Coal/Steam Plant Type Coal fired steam electric plant Location Mombasa, adjacent to a dedicated dock and unloading facility and storage area at a new, unidentified site. Project description Multiple 150 MW units. Future multiple 300 MW units. Conventional coal fired boiler, condensing steam turbine generator, water treatment plant, coal handling, ash handling and disposal, flue gas treatment, primary cooling. A 2 x 150 MW plant would require an area of more than 600,000 m2 for the plant, and ash storage. The coal unloading facility would require 300 m of dock, and a coal storage area of 50,000 m2. A greenfield unloading facility would cost in the order of 50 USM$. Fuel would be supplied from Richards Bay in South Africa Capacity and Energy Capacity 2x150 =300 MW nominal. Station service would take 9%. Maximum energy generation would be 2102 GWh (80% PF), less 9% station service. Transmission To the grid at Mombasa. Costs (2004) Capital cost 1385 $/kW, or 1678 $/kW with IDC. Average energy costs: PF 25% 14.9 cents/kWh PF 50% 8.9 PF 75% 6.9 Based on cost of Richards Bay coal 40 $/tonne (FOB) equivalent to 48 $/tonne delivered to the plant Additional capital cost would be incurred for the docking facility Implementation SSEA has assumed an implementation period of 6 years, including approvals, final design/contracting and construction, giving an earliest on-power date of January 2012. Main environmental Greenhouse gas and air pollutant emissions. Particulate matter issues emissions. Thermal and conventional pollution of cooling water. Area used by docking facilities, plant itself and plant stockpiles of coal and ash disposal. Transportation of coal to power plant. Main socio-economic Siting and design of plant must take into account land tenure issues systems and potential land use conflicts and noise effects. Cumulative impacts of air pollutant emissions on public health. Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 TANESCO Power Master System Plan 2004 BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Appendix H, November 2003 EIA status No EIA/SIA SSEA III - Final Report I-23 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Mchuchuma Coal/ Steam Plant Type Coal fired steam electric generating plant at colliery Location Tanzania, Mchuchuma, 25 km east of Lake Nyasa, and 50 km south of Njombe Project description 4 x 100 MW coal fired thermal plant with dedicated open-mouth coal mine, and 240 km transmission line to Mufindi Capacity and Energy Capacity 400 MW nominal. Station service would take 9% Maximum energy generation would be 2803 GWh (80% PF), less 9% station service. Transmission Mchuchuma to Mufindi, 240 km Costs (2004) Developer cost estimate Plant 360 US$M, excluding transmission, mine development and upgrading of access Manda village 42 US$M Total 402 US$M EAPMP adjustment for emission control and access 45 US$M EAPMP total 457 US$M SSEA assumed 402 US$M + 285 US$M for transmission, mine development and access, as indicated in EAPMP Capital cost ­US$M 685.0 IDC 78.6 Total 763.6 Cost /kW 1909 Energy costs: at 50% PF 8.72 at 75% PF 6.50 Implementation Tanzania 2004 master plan considered early Mchuchuma on- power for 2010, depending on load and new plant scenario. SSEA has assumed an implementation period of 6 years, including approvals, final design/contracting and construction, giving an earliest on-power date of January 2012. Main environmental Greenhouse gas and air pollutant emissions. Particulate matter issues emission. Thermal and conventional pollution of cooling water. Potential impacts on natural habitats due to mine fields, plant and disposal area (some 1600 ha). Main socio-economic Resettlement related to mine fields, plant and disposal area. Siting issues and design of plant must take into account land tenure systems and land use conflicts and noise effects. Impacts of air pollutant emissions on public health. Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Appendix H, Kenya Tanzania Uganda, The East African Community, Arusha, Tanzania, November 2003 http://www.ndctz.com/colliery.htm EIA status First EIA reported to be produced in 1997, and an EMP in 1998. Further work required on EIA and mitigation plan SSEA III - Final Report I-24 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Generic Gas turbine Plant Type Gas turbine - Combustion turbine plant Location Not specified. EAPMP has recommended a number of projects to use Songo Songo gas in Tanzania. Project description Open cycle combustion plant fired by gas (Tanzania) or fuel oil. Largely preassembled, 60 MW units Capacity and Energy Capacity 60 MW nominal. Station service would take 1%. Maximum energy generation would be 420 GWh at 80% PF. Normal operation would be at lower plant factors, except for units fired by cheap natural gas. Transmission According to location Costs (2004) Capital cost 530 $/kW, or 590 $/kW with IDC. Average energy costs: PF 25% 6.7 cents/kWh PF 50% 4.5 PF 75% 3.8 Based on cost of Songo Songo natural gas at 1.5 $/Gj (Note this is a favourable rate and only applies to "protected" gas from Songo Songo) Implementation Nominally 2 years for supply and installation, plus any time for approval and financing Main environmental Greenhouse gas and air pollutant emissions. Thermal and issues conventional pollution of cooling water. Possible loss of terrestrial habitat by land use for plant and transportation of gas. Main socio-economic Siting and design of plant must take into account land tenure issues systems and potential land use conflicts and noise effects. Cumulative impacts of air pollutant emissions on public health. Consulted studies and BKS Acres, East African Power Master Plan Study, Phase I reports and II Reports, November 2003 and March 2005 TANESCO Power Master System Plan 2004 World Bank documents related to project appraisal energy sector recovery project 2004, and Songo Songo economic analysis BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Appendix H, November 2003 EIA status Each project would require EIA/SIA SSEA III - Final Report I-25 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Generic Combined Cycle Plant Type Combined cycle combustion plant Location Not specified. EAPMP has recommended a number of projects to use Songo Songo gas in Tanzania. Project description Configuration assumed for the SSEA is 2 x 60 MW combustion turbines exhausting to 1 - 60 MW conventional condensing steam turbine = 180 MW. Capacity and Energy 180 MW per unit, generating 1260 GWh at 80% plant factor Transmission According to plant location Costs (2004) Capital cost 790 $/kW, or 895 $/kW with IDC. Average energy costs: PF 25% 7.91 cents/kWh PF 50% 4.93 PF 75% 3.93 Based on cost of Songo Songo natural gas at 1.5 $/Gj (Note this is a favourable rate and only applies to "protected" gas from Songo Songo) Implementation Nominally 2 years for supply and installation, plus any time for approval and financing for the GT component. Steam cycle usually added later. Would require 3 years for supply and installation Man environmental Greenhouse gas and air pollutant emissions. Thermal and issues conventional pollution of cooling water. Possible loss of terrestrial habitat by land use for plant and transportation of gas. Main socio-economic Siting and design of plant must take into account land tenure issues systems and potential land use conflicts and noise effects. Cumulative impacts of air pollutant emissions on public health. Consulted studies and BKS Acres, East African Power Master Plan Study, Draft reports Phase I Report, Appendix H, Kenya Tanzania Uganda, The East African Community, Arusha, Tanzania, November 2003 EIA status Each project would require EIA/SIA SSEA III - Final Report I-26 017334-001-00 APPENDIXI ­DATA SHEETSFOR RETAINED POWER DEVELOPMENTOPTION Lake Kivu Methane Engines Type Combustion thermal plant ­ burning Lake Kivu methane gas as fuel Location On Rwanda side of Lake Kivu ­ Note Lake Kivu is on the border between DRC and Rwanda. Possible sites are at Kibuye and Kigufi Project description For comparison purposes it is proposed that the project would consist of up to four 30 MW generating plants, to be built over a number of years. Power supply to the grid would be via a power purchase contract. Each 30 MW plant would comprise 4 modified 7.5 MW medium or slow speed Diesel engines, and each plant would have its gas collection and processing system. A proposal by Dane to Rwanda Ministry of Energy, Water and Natural Resources in 2003 proposed an initial plant of 3 x 7.5 MW medium speed engines, followed by 2 x 12 MW units, followed by combined cycle gas turbine plants of 32 MW each. No public information is available on whether the technical viability of generation in this size range is feasible, and on probable costs Capacity and Energy Installed capacity - future 30 MW Annual energy at 60 % PF 160 GWh Annual energy at 80% PF 210 GWh Transmission Power from the Kivu plants would be delivered to the grid at Kigoma. No transmission cost has been added to the original Dane estimates Costs (2004) Capital cost 30 MW - engines 25.44 $ Million Capital cost ­ gas collection 36.27 Total capital cost 61.71 IDC 5.61 Env. mitigation allowance Unknown Total 67.32 Average generation cost 75% PF 6.1 c/kWh (economic cost) Actual price will be a PPA, which would normally include cost of delivery to the grid. Implementation Agreement between DRC and Rwanda on resource use; Final design and testing for gas system; EIA; Due diligence; Final proposal by promoter and PPA; Construction Earliest on-power assumed as 2008 Main environmental No significant negative impacts have been identified in consulted issues documents. Greenhouse gas and air pollutant emission will be comparable to a thermal power plant. Thermal pollution. There will be an expansion of O2 bearing waters in Lake Kivu. Main socio-economic Siting and design of plant must take into account land tenure issues systems and potential land use conflicts and noise effects. Impacts of air pollutant emissions on public health Consulted studies Data Environnement ­ Exploitation of methane in Lake Kivu, and reports 2003 Dane Associates ­ Electricity, transmission and gas production systems - 2002 Lake Kivu gas development ­ safe and environmentally sound exploitation, Klaus Tietze, 2000 Lake Kivu gas development and related issues ­ Moiffak Hassan, 2000 EIA status Further work required on EIA/SIA and mitigation plan SSEA III - Final Report I-27 017334-001-00 APPENDIX J COMPARATIVE ANALYSIS OF OPTIONS SSEA III - Final Report 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS TABLE OF CONTENTS PAGE J COMPARATIVE ANALYSIS OF POWER DEVELOPMENT OPTIONS J-1 J.1 Multi-Criterion Analysis J-1 J.1.1 Selection of Method of Analysis for Stage I of the SSEA J-3 J.1.2 Selection of Method of Analysis for Stage II of the SSEA J-4 J.1.3 Steps Involved in the Multi-Criteria Analysis Method J-7 J.2 Socio-economic Category J-15 J.2.1 Impacts due to Population Displacement J-15 J.2.2 Promotion of Rural Electrification J-17 J.2.3 Socio-economic Impacts in the Downstream Reaches J-18 J.2.4 Land Issues J-19 J.2.5 Ranking within the Socio-economic Category J-20 J.3 Environmental Category J-21 J.3.1 Impact on Resource Depletion J-21 J.3.2 Impact of Greenhouse Gas Emissions J-22 J.3.3 Impacts of Air Pollutant Emissions on Biophysical Environment J-23 J.3.4 Land Requirements J-24 J.3.5 Waste Disposal J-25 J.3.6 Environmental Impacts on the Downstream Reaches J-26 J.3.7 Ranking of options within the Environmental Category J-27 J.4 Project Risks J-28 J.4.1 Introduction J-28 J.4.2 Opposition from Pressure Groups J-28 J.4.3 Institutional and Legal Framework J-30 J.4.4 Public Health J-30 J.4.5 Risks to Designated Habitats or Natural Sites J-31 J.4.6 Risk to Sites of Exceptional Biodiversity Value J-31 J.4.7 Use of Local Resources (Fisheries, Agriculture, Land Uses, etc.) J-32 J.4.8 Risks of Sedimentation J-32 J.4.9 Gestation Period J-33 J.4.10 Hydrological Risks J-33 J.4.11 Financial Risks J-36 J.4.12 Overall Assessment of Risk J-37 J.5 Quantitative Assessment of Risks J-39 J.5.1 Risks of Opposition from External and Internal Groups J-39 J.5.2 Risks Related to Institutional and Legal Framework J-40 J.5.3 Risk to Public Health J-41 J.5.4 Risks to Designated Habitats or Natural Sites J-42 J.5.5 Risks to Biodiversity J-43 J.5.6 Use of Local Resources J-44 J.5.7 Risk of Sedimentation J-45 J.5.8 Gestation Period in Delivering Benefits J-46 J.5.9 Hydrological Risk J-47 J.5.10 Financial Risk J-48 J.5.11 Ranking of Power Options on the Basis of Risks J-49 SSEA III - Final Report 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J Comparative Analysis of Power Development Options The options retained from the screening and described in Chapter 8 are compared using a multi-criterion analysis (MCA) in Chapter 9 and an assessment of their risk is carried out in Chapter 10. This appendix provides the detailed analyses behind the comparative analysis and the risk analysis. J.1 Multi-Criterion Analysis The characteristic feature of MCA methods is the establishment of formal and to some extent quantified procedures for the following three phases of options assessment1: · Identification of criteria, i.e. points of view or axes of preference according to which possible courses of action can be distinguished; · Ranking, or more extensive evaluation, of alternative courses of action according to each identified criterion; · Aggregation across criteria to establish an overall preference ranking for the alternatives. There are a variety of MCA methods that define the procedures to be followed in each phase and several ways of classifying them. The following four methods or "schools" of methods can be considered: 1) value measurement, 2) goal programming and aspiration levels, 3) outranking methods and 4) ordinal methods. Each is summarized below; the first three of them were described in the World Commission on Dams report,2 as they were deemed appropriate for public sector decision-making such as water resource development. They all have been in existence for a number of years and have been extensively applied. · Value Measurement: Performance measures are used to evaluate each option against criteria. These measures are then represented in terms of numerical scores on a scale, e.g. from 0 to 10 or from 0 to 100. These scores are used to rank options against each criterion and to represent the magnitude of the gaps between the options. Weights are assigned to each criterion that represent their relative importance. The final value score for an option is obtained as a weighted average of the scores for each individual criterion. A multi-attribute utility function may also be set up to combine the various performance measures with natural scales or constructed scales. Sensitivity analyses are normally used to evaluate the impacts on the decision of variations in the scoring systems and in weights assigned to each criterion2. · Goal Programming and Aspiration Levels: As summarized by Nichols et Al. (2000), "this approach is based on finding alternatives which are in some sense closest to a set of goals or aspirations set by the decision makers. The process is generally iterative, in the sense that once a first set of solutions is obtained, decision-makers may re-assess their goals in the light of what has been achieved. The methods are restricted to situations in which all criteria are quantitatively assessed, and are thus most well suited to the first level of planning (technical pre-screening of alternatives)". 1Nichols, David and David Von Hippel (Tellus Institute, USA), Theo Stewart (University of Cape Town, South Africa). November 2000. Thematic Review. VI Planning Approaches. Chapter 4: Multi-Criteria Analysis Methods. Report Prepared for the World Commission on Dams. 2An example of application of the Multiattribute Analysis is given in the following article: Merkhofer, Miley W. and Ralph Keeney. 1987. A Multiattribute Utility Analysis of Alternative Sites for the Disposal of Nuclear Waste. In Risk Analysis, Vol. 7, No. 2. pp 173-194. SSEA III - Final Report J-1 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Figure J-1 - Methodology for the Comparison of Power Options MCA (Multi-Criteria Analysis) Assessment of Project Risks 11 criteria and indicators: 9 risks: - Cost criterion - Risk of opposition from external or - Socio-economic criteria internal groups Population displacement - Risk of impacts on unique habitats Rural electrification - Risks to public health Downstream effects - Risks related to institutional and legal Land issues framework - Environmental criteria - Use of local resources Resource depletion - Gestation period Greenhouse gas emissions - Risks of sedimentation Air pollutant emissions - Hydrological risk Land requirements - Financial risk Waste disposal Downstream effects Includes non-quantifiable aspects Use of ratio scales Selection of Options for Power Development Portfolio Analysis of trade-offs to be made between least cost and other factors on the basis of results from: 1) Application of Multi-Criteria Analysis 2) Assessment of project risks Separation of options into two groups: 1) Best evaluated options 2) Other options SSEA III - Final Report J-2 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS · Outranking Methods: This school of MCA is popular in Europe, particularly in France3. Outranking methods are based on pair-wise comparison of options. In determining whether option A can be said to be "at least as good as" option B, emphasis is placed on the weight of criteria favouring this choice and the possibility that this assertion may be vetoed by a large difference in the opposite direction for at least one criterion. The techniques used in outranking methods (such as ELECTRE or PREFCALC) are technically complicated but the process may be highly informative to decision-makers. · Ordinal Methods of Evaluation: In ordinal methods, options are ranked from the most preferred to the least preferred without specifying the magnitude of differences between options. One of these methods was developed by Holmes in reaction to criticisms of MCA that "some important aspects of life cannot be numbered with certainty or sometimes, indeed, with any meaning. This is confirmed when it is realized that many such evaluations contain a combination of exact and inexact data, reduced by assertion rather than demonstration, to the same units of measurement". Underlying the method is the basic assumption that arithmetical operations are inappropriate for dealing with unquantifiable data or criteria (i.e., under conditions where there is no absolute scale), or that it is questionable to use conventional measures such as monetary values. Besides, while some criteria are clearly more important than others, it is not realistic to assign relative numeric values to the relationship. The process thus involves the grouping of criteria in classes of importance (e.g. more important than, less important than, neither more nor less important than). Options are then evaluated against each criterion by determining which one is the best, second best, and so on, without using an absolute scale. J.1.1 Selection of Method of Analysis for Stage I of the SSEA The selection of an appropriate MCA method for the SSEA of power options in the Nile Equatorial Lakes Region has been based on the following three considerations: 1. The method must promote stakeholder involvement. 2. The method must allow for limited data availability. 3. The method must ensure transparency of results obtained. For Stage I of the SSEA, the comparative analysis of power options was based on the ordinal method of evaluation developed by J.C. Holmes4. This method was selected for the following two main reasons: · Stakeholder involvement: To a greater degree than other methods, the Holmes method facilitates the involvement of stakeholders. In particular, in many other MCA methods, percentage points are assigned to each criterion to represent their relative importance. The Holmes method does not require such a weighting of criteria, only the rating of the importance of each criterion. It is a less cumbersome process for a 3Bernard Roy is one of the leaders of this school of MCA. See for instance: Roy, B. 1989. Méthodologie multicritère d'aide à la décision. Ecomica. Paris. Roy, B. 1990. The Outranking Approach and the Foundation of ELECTRE Methods. In: Readings in Multi-Criteria Decision Aid, C.A. Bana e Costa (Ed.), Springer Verlag, Berlin, pp 155-183. 4Holmes, J.C. 1972. An Ordinal Method of Evaluation. Urban Studies 9 (1): 179-191. SSEA III - Final Report J-3 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS large group of stakeholders to determine the relative importance of each criterion than to determine their respective weighting. · Data availability: As an ordinal method, the Holmes method is well suited to a context where one has to consider a wide range of subjective opinions and where studies on most options are at a concept or pre-feasibility stage that does not allow for a precise measurement of each option against criteria. Indeed, an ordinal method does not require such a measurement since options are simply ordered from the most to the least preferred. Although the ranking of options provides less information than the rating of the relative performance of options against an absolute scale, it may still be sufficient to allow for informed decision-making on the selection of the preferred option. J.1.2 Selection of Method of Analysis for Stage II of the SSEA There were several lessons learned during SSEA Stage I regarding the use of the Holmes method, including: · The process used to rank options on the basis of "corresponding positions" is difficult to explain, even on an intuitive basis. As a result, a number of stakeholders and Project Steering Committee members considered the results of the ranking with some reservations. · The Holmes method does not allow for the measurement of the magnitude of the gaps between the options. The last option may be wrongly perceived as a "bad" option even if its performance is only slightly worse than the preceding options. This led to the decision that for Stage II of the SSEA to rank options on the basis of a Multi- attribute method. This method is part of the value measurement category of MCA school of methods referred to by the World Commission on Dams. With this method, each option is scored against each criterion and not simply ranked from the most preferred to the least preferred as in the Holmes method. Percentage points are associated with each criterion as an indication of their relative importance (the sum of the weights must add to 100), whereas, in the Holmes method, criteria are grouped in classes of importance. The final value score of each option is obtained as a weighted average of the scores for the individual criteria. In a review of MCA methods, Greening and Bernow5 suggest the types of problems that may be analysed with MCA methods and consider the identification of electricity generation expansion options as an appropriate field of application for weighting and scaling methods (such as the Multi-attribute method). This type of method has been applied to a number of energy and environmental planning problems. For instance, it is recommended by the Ontario (Canada) Ministry of Natural Resources for decision-making in water management planning for waterpower6. The main advantages and drawbacks of the Multi-attribute method, when compared to the Holmes method, are the following: Stakeholder involvement: As is the case for the Holmes method, the Multi-attribute method is "particularly well-suited for interactive use in conjunction with decision- makers or with specific interest or stakeholder groups". In particular, the same approach can be used for involving stakeholders in the identification of selection 5Greening, Lorne A. and Bernow, Steve. Design of coordinated energy and environmental policies: use of multi- criteria decision-making. Energy Policy (32), 2004. 6Ontario Ministry of Natural Resources. 2003. Decision-making in water management planning for waterpower. Waterpower Project. Draft. SSEA III - Final Report J-4 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS criteria and indicators. However, in the case of the Multi-attribute method, it is more cumbersome for a large group of stakeholders to determine the relative weighting of criteria using percentage points. Availability of data: The Multi-attribute method allows for the measurement of the gaps between the performance of each option. However, because of the mathematical operations inherent in this method, quantitative input data is essential. Thus, criteria scales must be ratio scales (e.g. net CO2 equivalent emissions over the life cycle of the project measured in t/GWh or area required for ash disposal measured in ha/GWh, etc.). Transparency of results: With the Multi-attribute method, the process used to rank options can be more easily understood and results will include an evaluation of the gaps between options. However, the method may give the wrong perception of precise measurement of the overall performance of each option against criteria. Indeed, since environmental impact studies are lacking for a number of options, the evaluation will often have to be based on expert judgment. Both methods considered for the Multi-Criteria Analysis (Holmes and Multi-attribute methods) involve five steps: Step 1: Identification of evaluation criteria and indicators Step 2: Determination of the relative importance of criteria Step 3: Ranking of options for each criterion using indicators Step 4: Ranking of options within each category of criteria taking into account the relative importance of criteria Step 5: Selection of options to be included in power development portfolios Table J-1 summarizes the main advantages and drawbacks of the Multi-attribute method versus the Holmes Method at each of the steps involved in the methods. Table J-1 - Advantages and Drawbacks of the Multi-Attribute Method versus the Holmes Method Holmes Method Multi-Attribute Method Step 1: Identification of evaluation criteria and indicators Same approach with both methods. Same approach with both methods. Step 2: Determination of the relative importance of criteria The Holmes method requires only the With the Multi-attribute method, percentage rating of the importance of each criterion points are assigned to each criterion to (e.g. using three classes of importance). represent their relative importance. It is a Such rating is more amenable to more cumbersome process for a large stakeholder involvement. group of stakeholders to determine the relative weighting of criteria using percentage points. SSEA III - Final Report J-5 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Holmes Method Multi-Attribute Method Step 3: Scoring and Ranking of options for each criterion using quantitative and qualitative indicators With the Holmes method, options are With the Multi-attribute method, the simply ordered from the most to the least performance of each option against criteria preferred. The ranking of options provides is represented in terms of numerical scores less information than the rating of the on a scale, e.g. from 0 to 10. These scores relative performance of options against an are used to rank options against each absolute scale (as in the Multi-attribute criterion and to represent the magnitude of method). For instance, The last option may the gaps between the options. However, be wrongly perceived as a "bad" option because of the mathematical operations even if its performance is only slightly inherent in this method, quantitative input worse than the preceding options. data is essential. Thus, criteria scales must However, the ranking of options against be ratio scales. The need to apply ratio criteria requires less information than in the scales results in a number of criteria being Multi-attribute method. It is thus better excluded from the Multi-attribute method adapted to a context where most projects when quantitative data is not available. are at a concept or prefeasibility stage and Excluded criteria will therefore be retained have no environmental impact assessment. as qualitative "issues" in the chapters dealing with the assessment of "Project Risks" and "Cumulative Impacts". Step 4: Ranking of options within each category of criteria taking into account the relative importance of criterion The process used to rank options on the The process used to rank options basis of "corresponding positions" is (weighted average of the scores for each difficult to explain. As a result, Results of individual criterion) can be more easily the ranking may be considered with some understood. However, it may give the reservations. wrong perception of a precise With this process, "very important" criteria measurement of the overall environmental have a determining role. or social performance of each option against criteria. Indeed, the evaluation will often have to be based on expert judgement. Step 5: Selection of options to be included in power development portfolios The ranking in the "Economic" category is The ranking in the "Cost" category is used used as a reference base for the as a reference base for the discussion on discussion on the selection of options to be the selection of options to be included in included in power development portfolios power development portfolios since since dilemmas are generally raised as dilemmas are generally raised as trade-offs trade-offs to be made between least cost to be made between least cost and other and other factors. When conclusions factors. When conclusions reached for reached for other categories of criteria other categories of criteria or issues differ differ from the economic ranking, dilemmas from the cost ranking, dilemmas raised are raised are spelled out and analyzed. In spelled out and analyzed. In SSEA Stage SSEA Stage I, options to be considered in II, options to be considered in power power development portfolios were development portfolios will be identified on identified on the basis of 5 categories of the basis of the 3 categories of criteria criteria. used in the Multi-attribute method and of project risks. SSEA III - Final Report J-6 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.1.3 Steps Involved in the Multi-Criteria Analysis Method The five steps to be followed in the MCA method are described below. Step 1: Identification of Evaluation Criteria and Indicators Each power development option will be evaluated against a set of criteria, i.e. points of view to be taken into consideration when comparing power options. One indicator will be associated with each criterion so as to guide the rating and the scoring of options. The following World Bank's "Safeguard Policies and Procedures" have also been considered in the selection of relevant evaluation criteria and the ranking of options: Environmental Assessment; Natural Habitats; Cultural Property; Indigenous People; Involuntary Resettlement; Forests; Projects in International Waterways. The list of criteria used in Stage I of the SSEA, based on five categories of criteria (economic and financial, technical, project risks, socio-economic and environmental) and 25 criteria, was reviewed in the Third Stakeholder Consultation Workshop. A revised list based on four categories of criteria (cost, project risks, socio-economic and environmental) and 22 criteria was produced integrating comments made during the Workshop. Subsequently, the Consultant substantially revised the list on the basis of the following principles: · Criteria that do not lend themselves to being assessed on the basis of a ratio scale (taking into account the magnitude of impacts) are removed from the MCA and subjects related to these criteria are addressed in the assessment of project risks and/or in the cumulative impacts analysis. · Criteria retained in the MCA are assessed on the basis of one indicator only. Criteria that were part of the revised list following the Third Stakeholder Consultation Workshop and that were not retained in the MCA were addressed as follows: · "Risks for Investors and Power Utility Clients" addressed in the assessment of project risks under "Risk of Opposition from External and Internal Groups" and "Risks Related to Institutional and Legal Framework" · "Use of Local Resources" addressed in the assessment of project risks. · "Gestation Period in Delivering Benefits" addressed in the assessment of project risks. · "Risks of Increases in Waterborne Diseases" addressed in the assessment of project risks under "Risks to Public Health" and in the analysis of cumulative impacts. · "Risk of Increases in Pulmonary Diseases" addressed in the assessment of project risks of project risks under "Risks to Public Health" and in the analysis of cumulative impacts. · "Multiple-Use Benefits" related to flood control and irrigation addressed under the criterion "Economic Viability" in the Cost category. SSEA III - Final Report J-7 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS · "Impacts on Cultural, Historical and Religious Sites" addressed in the assessment of project risks under "Risks of Opposition from External and Internal Groups" · "Impacts on Indigenous Communities" addressed in the assessment of project risks under "Risks of Opposition from External and Internal Groups"). · "Impacts on Designated Habitats and Natural Sites within the Reservoir or Project Site" addressed in the assessment of project risks under "Risks of Impacts on Unique Habitats" and in the analysis of cumulative impacts. · "Impacts of Sedimentation within the Reservoir" addressed in the assessment of project risks under "Risks of Sedimentation". · "Proliferation of Invasive Aquatic Vegetation" addressed in the analysis of cumulative impacts. Following these adjustments, the list of criteria and indicators retained for the comparison of power options on the basis of the MCA method was based on three categories (cost, socio- economic and environmental) and 11 criteria, as presented in Table J-2. The list of criteria, indicators and project risks was validated with participants at the end of Fourth Stakeholder Consultation Workshop. Table J-2 - Criteria and Indicators Used for the Comparison of Power Options on the Basis of the MCA Method Criteria Indicators Category: Cost Economic Viability Unit cost of firm energy per kWh over the projected life of the facility (US¢/kWh), taking into account: - Direct investment ­ plant - Engineering and owners costs - Interest during construction - Operating and maintenance costs - Environmental and social mitigation costs (included in the civil works contingency amount) - Multi-purpose benefits (irrigation, fisheries) ­ treated by cost sharing for the dam (unless a specific allowance has been included in the estimates, in which case that estimate is used) - Contingency allowance for uncertainties (e.g. technical, financial and geological risks) Category: Socio-economic Impacts Due to Population Number of persons affected by project infrastructure and ancillary Displacement facilities (People/GWh) Promotion of Rural Number of rural persons living in a 10 km radius of the power station Electrification and in a 10 km wide corridor along the transmission line between the option and the main transmission grid (People/GWh) Socio-economic Impacts on Number of persons living in a 1 km corridor along the river stretch the Downstream Reaches with altered flow downstream of the dam (People/GWh) Land Issues Area required for project infrastructure, including reservoir and transmission facilities (ha/GWh) SSEA III - Final Report J-8 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Criteria Indicators Category: Environment Impact on Resource Energy payback ratio: ratio of energy produced during the normal life Depletion span of the option divided by the energy required to build, maintain and fuel the generation equipment. This indicator is a measure of the global pressure of an option on the environment Impacts of Greenhouse Gas Net CO2 equivalent emissions over the life cycle of the project Emissions (t/GWh) Impacts of Air Pollutant SO2 equivalent emissions over the life cycle of the project (t/GWh) Emissions on Biophysical Environment Land requirements Area required for project infrastructure, including reservoir and transmission facilities (ha/GWh) Waste Disposal Land area required for ash disposal (ha/TWh) Environmental Impacts on Length of river with altered flow downstream of the dam (km/TWh) the Downstream Reaches The definitions of the selected Socio-economic and Environmental criteria are provided hereafter. Socio-economic category - Impacts due to population displacement: Social impacts related to the resettlement of people due to the presence of infrastructure (reservoir area, power station and related facilities, construction area, etc.). - Promotion of rural electrification: Ability of option to facilitate rural electrification in the vicinity of the power station and along the transmission line connecting the power station to the grid. - Socio-economic impacts on the downstream reaches: Impacts on riverside and water uses along the river stretch that would be affected by a reduced flow between dam and tailrace and by altered flows downstream of the tailrace. - Land issues: Impacts due to land use conflicts related to project infrastructure (including the reservoir in the case of hydroelectric options) and transmission right-of-way requirements. Examples of such impacts include the loss of agricultural areas due to the presence of infrastructure or impacts on landscape of transmission lines. Environmental category - Impact on resource depletion: Impact of option on resources used to produce energy. Projects that consume finite resources could be transferring costs to future generations, and those using abundant resources are preferable to those depleting scarce resources. - Impacts of greenhouse gas emissions: Potential social and environmental impacts of climate change due to greenhouse gas emissions over the life cycle of the option (extraction and transportation of fuel, construction and operation). SSEA III - Final Report J-9 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS - Impacts of air pollutant emissions on biophysical environment: Impacts on habitats and resources of nitrogen oxides (NOx) and sulphur oxides (SO2) emissions related to acid precipitation. - Land requirements: Impacts on habitats and resources related to project infrastructure (including the reservoir in the case of hydroelectric options) and transmission right-of-way requirements. Examples of such impacts include: for hydropower, the transformation of terrestrial habitats into aquatic habitats; for fossil-fuelled thermal stations, the use of large areas for extraction and transportation of fuel. - Waste disposal: Impacts on habitats and resources due to ash disposal in the case of coal-fired power plants (dust and possible contamination of adjacent soils). - Environmental impacts on the downstream reaches: Impacts on aquatic and riverine habitats along the river stretch that would be affected by a reduced flow between dam and tailrace and by altered flows downstream of the tailrace. Step 2: Determination of the Relative Importance of Criteria Within the Socio-economic and Environmental categories, weights are assigned to each criterion to reflect their relative importance using percentage points. These weights were assigned by the Consultant team on the basis of the grouping of criteria into three classes of importance: "Very important", "Important", "Less Important". This grouping was initially carried out during Stage I of the SSEA and was approved during the Third Stakeholders Consultation Workshop held at the onset of SSEA Stage II and confirmed during the Fourth Stakeholder Consultation Workshop at the end of SSEA Stage II. For the new criteria proposed during the Third Stakeholders Consultation Workshop, the Consultant selected the class of importance based on the discussions during the workshop. Since the Multi-attribute Method of the MCA uses a percentage weighting instead of relative importance, the Consultant used the following conversion process: · "Important" criteria were given a weight twice as high as "Less important" criteria and "Very important" criteria were given a weighting twice as high as "Important" criteria. · Percentages were then derived such that the total added up to 100% in each category. The "Land issues" criterion in the Socio-economic category is a new criterion. It was given the weight of a very important criterion (35%) because its indicator (area required for project infrastructure) is recognized as an overall indication of project impacts. The "Waste Disposal" criterion in the Environmental category is also a new criterion. It was given a weight of 5% because, although it represents a significant environmental issue for coal-fired thermal plants, the area used for waste disposal is already taken into account in the "Land Requirements" criterion. Table J-3 shows the weights assigned to the selected evaluation criteria. These weights were validated with participants at the end of the Fourth Stakeholder Workshop. In order to evaluate to what extent the results of the comparison of options on the basis of the MCA method are dependent on ascribed weights, sensitivity analyses were carried out on alternative sets of weights. Results of these are presented in Section 9.3.5. SSEA III - Final Report J-10 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Step 3: Ranking of Options for Each Criterion Using Indicators During this step of the comparative analysis, the performance of each option against each criterion is assessed according to quantitative indicators defined on the basis of ratio scales so as to measure the magnitude of impacts related to each criterion per unit of energy generated. Under the Cost category, there is only one criterion: "Economic viability" with only one quantitative indicator: "Average cost per kWh over the projected life of the facility". This indicator can thus be used directly for rating and ranking options in this category. This indicator includes a number of elements that must be factored into the cost assessment. In the Socio-economic and Environmental categories, there are several criteria and indicators. In order to arrive at a ranking within each category, the indicators are represented in terms of numerical scores on an absolute scale from 0 (best) to 10 (worst). For each criterion, the best value (conceivable from a practical point of view regardless of whether or not such a value applies to any of the options in the list) for the selected indicator will be defined as 0 and the worst value (again from a practical point of view) will be defined as 10. All power options will then be scored on a pro-rata basis using the numerical values of their indicators, as calculated for them. When an extreme value cannot be defined on the basis of existing literature on environmental and social impacts of electricity production options, the extreme value calculated for an option in the SSEA region is taken as a reference. It is important to note that full Environmental Impact Assessments (EIAs) are available only for the Bujagali, Karuma and Mutonga hydropower projects. Preliminary EIAs are available for the Ruhudji and Rumakali hydropower projects (see Section 6.1)7. In most cases, the evaluation of the performance of power options against criteria has been made on the basis of the following: · Environmental impacts known to occur in similar projects; · Internationally recognized mitigation measures (see Appendix H); · Information from government sources on environmental and socio-economic characteristics at country, province or district levels; · Visits made by the consultant to the Rusumo Falls, Murchison Falls, Karuma and Ruzizi III Project sites; · Information on technical characteristics of project components available in technical reports. 7 BKS Acres. November 2003. The East African Power Master Plan Study. Draft Phase 1 Report. Appendix H. and SNC-Lavalin International/HQI. February 2005. Strategic/Sectoral, Social and Environmental Assessment (SSEA) of Power Development Options in Burundi, Rwanda and Western Tanzania, Final Report, Stage I. Chapter 6. SSEA III - Final Report J-11 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Table J-3 - Weights assigned to Criteria Selected for the Comparison of Options on the Basis of the MCA Method Criteria Class of Importance Weight (%) Category: Cost Economic Viability 100 Category: Socio-economic Impacts Due to Population Displacement Important 15 Promotion of Rural Electrification Very important 35 Socio-economic Impacts on the Downstream Important 15 Reaches Land Issues Very important 35 Category: Environmental Impact on Resource Depletion Important 25 Impacts of Greenhouse Gas Emissions Less important 10 Impacts of Air Pollutant Emissions on Less important 10 Biophysical Environment Land Requirements Important 25 Waste Disposal Less important 5 Environmental Impacts on the Downstream Important 25 Reaches When information required for the evaluation of the indicators is not available, assumptions made are indicated at the bottom of tables presenting the detailed results of the comparative analysis. The Masigira, Mpanga and Upper Kihansi options could not be scored because the required information on technical characteristics of project components was not available in technical reports. For the latter project, some information on environmental and socio- economic impacts could be derived from the Lower Kihansi EIA report. For air pollutant emissions, mitigation measures are explicitly taken into account when determining the value of the indicator for each option. For other indicators, it is assumed that internationally recognized mitigation measures are applied to all options (see Appendix H), such as the implementation of a resettlement and rehabilitation plan or the release of a minimum water flow in a bypassed river section. The following presents the indicators associated with each criterion. Socio-Economic Category o Impacts Due to Population Displacement The indicator for this criterion is the number of persons that would be physically displaced by project infrastructure and ancillary facilities per GWh (People/GWh). A score of 0 is given to options that do not require population displacement. A score of 10 corresponds to the ratio of the Three Gorges SSEA III - Final Report J-12 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Project in China (14.2 people/GWh), which is considered among the hydropower projects with the highest number of displaced people per GWh8. o Promotion of Rural Electrification The indicator for this criterion is the number of persons living in a 10 km radius of the power station and in a 10 km wide corridor along the transmission line between the option and the main transmission grid per GWh (People/GWh). A score of 0 corresponds to the Rusumo Falls option, which has the highest ratio of people who could benefit from rural electrification per GWh among screened options (968 people/GWh)9. A score of 10 corresponds to zero population that could benefit from rural electrification. It is considered that a thermal station located near a city, such as a coal-fired station in Mombasa, does not contribute to rural electrification. o Socio-economic Impacts in the Downstream Reaches Scoring of options for this criterion is based on the number of persons living in a 1 km corridor along the river stretch with altered flow downstream of the dam per GWh (People/GWh). The following hydraulic modifications are considered as they may have negative impacts on riverside and water uses downstream of the dam: the reduction of water flows between dam and tailrace10 and frequent hourly, daily or weekly fluctuations downstream of the tailrace. A seasonal regulation of water flows was not included in the indicator as it could contribute to flood control and thus have positive impacts on riverside uses. A score of 0 is given to hydroelectric options that do not modify water flows downstream of the dam or to non-hydroelectric options. A score of 10 corresponds to the Siguvyaye option in Burundi that has the highest ratio of people affected by impacts on the downstream reaches per GWh among all considered options11. o Land Issues The indicator for this criterion is the area required for project infrastructure, including reservoir and transmission facilities over the life cycle of the option (in ha/GWh). A score of 0 is given to the option with the smallest land area required for project infrastructure. A score of 10 corresponds to the ratio of the Akosombo Project in Ghana (177 ha/GWh), which is considered among the hydropower projects with the highest area required for project infrastructure per unit of energy produced9. Environmental Category o Impact on Resource Depletion The indicator proposed for this criterion is the energy payback ratio (EPR), i.e. the ratio of energy produced during the normal life span of the option divided by the energy required to build, maintain and fuel the generation equipment. This indicator is a measure of the overall pressure of an option on the environment. If an option has a low EPR, it means that much energy is required to maintain it and it is likely to have more environmental impacts than an option with a high EPR. A score of 0 corresponds to an EPR of 270 (a run- of-river hydroelectric power project) and a score of 10 corresponds to an EPR 8Goodland, R. 1997. Large Dams. Learning from the Past. Looking at the Future. IUCN-World Bank. 9No other power development option, either within the region or elsewhere, was identified with a better ratio. 10Between dam and tailrace, the river may still receive flows from tributaries. 11No other power development option, either within the region or elsewhere, was identified with a higher ratio. SSEA III - Final Report J-13 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS of 1 (an option that consumes as much energy as it produces such as a thermal station using oil coming from tar sands). o Impact of Greenhouse Gas Emissions The indicator for this criterion is: Net CO2 equivalent emissions over the life cycle of the project (t/GWh). A score of 0 corresponds to CO2 emissions of 1 t/GWh (a run-of-river hydroelectric power project) and a score of 10 corresponds to CO2 emissions of 1095 t/GWh (a modern coal-fired thermal plant with SO2 scrubbing). Figures used come from the results of a literature survey of life cycle assessments that have been adapted to the options characteristics12. o Impacts of Air Pollutant Emissions on Biophysical Environment Both NOx and SO2 emissions contribute to acid precipitation. SO2 emissions can vary significantly depending on the type of fuel used, regulations or the efficiency of the processing plant to remove sulphur concentrations. Variations in NOx emissions are dependent upon the condition of combustion technology used. SO2 and NOx emissions associated with hydropower are produced during construction, maintenance and decommissioning only and can be considered as negligible. Total air pollutant emissions are measured in terms of tons of SO2 equivalent emissions per GWh, considering that the acidification potential of NOx emissions is 0.7 time the acidification potential of SO2 emissions13. It is assumed that thermal options would be built using internationally recognized pollution abatement measures. A score of 0 is assigned to hydroelectric options since they have a negligible contribution to acid rain. A score of 10 is assigned to the maximum emission values of a coal-fired thermal plant with SO2 scrubbing, i.e. 3.254 tons of SO2 equivalent emissions per GWh. o Land Requirements The indicator for this criterion is the same as the indicator used for the criterion "Land Issues", i.e. the area required for project infrastructure, including reservoir and transmission facilities over the life cycle of the option (in ha/GWh). This indicator is also considered as a global measure of the environmental impacts of an option on flora and fauna. o Waste Disposal The indicator for this criterion is the area required for ash disposal measured in ha/TWh. Only coal fired power plants need space for ash disposal. A value of 0 is given to all options that do not take up space for ash disposal; a value of 10 is given to the coal-fired plant that requires the largest area for ash disposal per GWh, i.e. a plant using coal with an ash content of 47%. o Environmental Impacts in the Downstream Reaches The indicator for this criterion is the length of river with altered flow downstream of the dam (km/TWh). As for socio-economic impacts in the downstream reaches, the following altered flows will be considered: the 12Gagnon, Luc, C. Bélanger and Yohji Uchiyama. Life-Cycle Assessment of Electricity Generation Options : The Status of Research in Year 2001. In Energy Policy 30 (2002) 1267-1278. 13Details on the calculation of the acidification potential of NOx emissions can be found on the following site: http://www.pe-product.de/GABI/documentation/IKP/Wirkkriterien/VERSAUERGUN.html SSEA III - Final Report J-14 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS reduced flow between dam and tailrace and frequent hourly, daily or weekly fluctuations downstream of the tailrace. A score of 0 is given to hydroelectric options that do not modify water flows downstream of the dam or to non- hydroelectric options. A score of 10 corresponds to the Siguvyaye option that has the longest length of river with altered flow downstream of the dam per TWh among all considered options. Step 4: Ranking of Options within Each Category of Criteria Taking into Account the Relative Importance of Criteria Following the scoring of power options for each criterion, the options are subsequently ranked within the Socio-economic and Environmental categories on the basis of the weighted average of the scores for each individual criterion. Step 5: Selection of Options to be Included in Power Development Portfolios Comparisons across sets of evaluation criteria involve normative judgments (e.g. the importance of the Cost category of criteria relative to the Environmental category of criteria or Socio-economic category of criteria) and would be beyond the scope of this study. The cost ranking is used as a reference base for the discussion on the selection of options to be included in power development portfolios since dilemmas are generally raised as trade-offs to be made between least cost and other factors. When conclusions reached for the Socio- economic and Environmental categories of criteria differ from the cost ranking of power options, dilemmas raised are spelled out and analysed. In addition, inputs from the assessment of project risks are also considered. Consequently, options to be considered in power development portfolios will be identified on the basis of the following categories of considerations: (1) Cost criterion; (2) Socio-economic criteria; (3) Environmental criteria; (4) Project risks. On this basis, two groups of options to be considered in power development portfolios will be identified: (1) best evaluated options and (2) other options. J.2 Socio-economic Category J.2.1 Impacts due to Population Displacement Average Options Number of People/ persons displaced energy Score (GWh) GWh Bujagali 0 1,925 0.00 0.00 Kabu 16 90 112 0.80 0.57 Kakono (High) 2,005 300 6.68 4.71 Karuma 200 1,748 0.11 0.08 Masigira 695 Insufficient Data Mpanga 1,028 Insufficient Data Mutonga 531 328 1.62 1.14 Ruhudji 359 1,930 0.19 0.13 Rumakali 1,693 1,141 1.48 1.04 Rusumo Falls 2,850 403 7.07 4.98 Ruzizi III 0 418 0.00 0.00 SSEA III - Final Report J-15 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Average Options Number of People/ persons displaced energy Score (GWh) GWh Songwe 8,735 1,352 6.46 4.55 Upper Kihansi (storage) 124 Insufficient Data Generic Wind 30 MW 0 66 0.00 0.00 Geothermal - Generic 20 491 0.04 0.03 Mombasa - Gas/LNG steam 188 2,102 0.09 0.06 Mombasa - Coal steam 300 2,102 0.14 0.10 Mchuchuma - Coal steam 610 2,803 0.22 0.15 GT 60 MW gas - generic x 150 1,682 0.09 0.06 4 units CC gas x 3 units 113 1,261 0.09 0.06 Kivu methane engines 118 841 0.14 0.10 30 MW x 4 units Best = 0 Worst = 10 and based on 14.2 people/GWh (Three Gorges project in China) Estimates of the number of displaced people or households are available in reports on Kabu 16 and Karuma. For the Rusumo Falls option, a rough estimate of displaced persons has been made on the basis of the latest census data (see SSEA 1 report). As resettlement has already taken place at Bujagali, the number of persons displaced by this project is set at 0. It is assumed that the population density in areas considered for thermal stations close to a city is 150 people/km2. For other options, estimates are based on the LandScan Global Population Database, Oak Ridge National Laboratory. LandScan is a worldwide population database at 30" X 30" resolution for estimating ambient populations at risk. Best available census counts are distributed to cells based on probability coefficients. Calculation of the probability coefficient for each cell depends on publicly available databases offering at scales of 1:1,000,000 or larger and resolutions of 1 km or finer worldwide coverage of: Roads (transportation networks are primary indicators of population); Slope (slope is an important variable in calculating the LandScan population probability coefficient because most human settlements occur on flat to gently sloping terrain); Land cover (perhaps, the best single indicator of population density is land cover type); Nighttime lights (several deficiencies of the previously discussed databases can be overcome with satellite data, which measures nighttime light emanating from the earth's surface at 1 km resolution), which, in turn, are based on road proximity, slope, land cover, and nighttime lights. Verification and validation is conducted routinely for all regions and more extensively for portions of the Middle East and the Southwestern United States indicate that greater spatial precision can been achieved with no sacrifice in aggregate accuracy compared to previous global population databases. Indeed, LandScan's inherent correspondence with best SSEA III - Final Report J-16 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS available census counts for finest available census units actually represents an improvement in accuracy over previous global population databases. All population estimates are made for year 2003. J.2.2 Promotion of Rural Electrification Options Number of rural persons People/ living near options* GWh Score Bujagali 605,916 315 7.01 Kabu 16 95,831 856 1.87 Kakono (High) 135,699 452 5.70 Karuma 121,663 70 9.34 Masigira 40,171 58 9.45 Mpanga 11,602 11 9.89 Mutonga 14,632 45 9.58 Ruhudji 28,474 15 9.86 Rumakali 117,835 103 9.02 Rusumo Falls 423,977 1,052 0.00 Ruzizi III 183,287 438 5.83 Songwe 234,897 174 8.35 Upper Kihansi (storage) 5,747 46 9.56 Generic Wind 30 MW 29,083 441 5.81 Geothermal - Generic 12,702 26 9.75 Mombasa - Gas/LNG steam 0 0 10.00 Mombasa - Coal steam 0 0 10.00 Mchuchuma - Coal steam 56,173 20 9.81 GT 60 MW gas - generic x 4 units 0 0 10.00 CC gas x 3 units 0 0 10.00 Kivu methane engines 30 MW 176,909 210 8.00 x 4 units *Note: Defined as number of rural persons living in a 10 km. radius of the power station and in a 10 km. wide corridor along the transmission line between the option and the main transmission grid. Best = 0 and based on 1,052 people/GWh (Rusumo Falls) Worst = and based on 0 people/GWh Most data on the length of the transmission line between the option and the main transmission grid comes from the BKS Acres Final Phase II Report of the East African Power Master Plan Study. March 2005 (Table 9.15: Transmission Additions and Costs). For Songwe and options in Rwanda and Burundi, data comes from project technical reports. For thermal options located in an urban area, it is assumed that no additional people would benefit from rural electrification. Calculations for the wind option is based on the Mkumbara site in Tanzania. Calculations for the geothermal option is based on the Longonot site in Kenya. SSEA III - Final Report J-17 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Source for data on population: LandScan Global Population Database, Oak Ridge National Laboratory (see notes for criterion 1.1). J.2.3 Socio-economic Impacts in the Downstream Reaches Number of persons living in a 1 km corridor along the river Options stretch with altered flow People/ Score downstream of the dam GWh (People/kWh) Bujagali 269 0.14 0.05 Kabu 16 1,080 9.64 3.44 Kakono (High) 776 2.59 0.92 Karuma 41 0.02 0.01 Masigira 0.00 0.00 Mpanga 0.00 0.00 Mutonga 108 0.33 0.12 Ruhudji 553 0.29 0.10 Rumakali 1,583 1.39 0.50 Rusumo Falls 1,289 3.20 1.14 Ruzizi III 4,471 10.70 3.82 Songwe 12,719 9.41 3.36 Upper Kihansi (storage) 0 0.00 0.00 Generic Wind 30 MW 0 0.00 0.00 Geothermal - Generic 0 0.00 0.00 Mombasa - Gas/LNG steam 0 0.00 0.00 Mombasa - Coal steam 0 0.00 0.00 Mchuchuma - Coal steam 0 0.00 0.00 GT 60 MW gas - generic x 4 units 0 0.00 0.00 CC gas x 3 units 0 0.00 0.00 Kivu methane engines 30 MW 0 0.00 0.00 x 4 units Notes: Best = 0; Worst = 10 Best set for 0 People/GWh; worst set for 28 People/GWh (Siguvyaye option). The length of the river stretch with reduced flow between dam and tailrace has been determined on the basis of each project technical characteristics and maps available in project reports. With regards to the river stretch with altered flow, it is considered that any project with a regulating pond can be used for providing peaking power, which results in frequent hourly, daily or weekly water flow variations downstream of the tailrace. There is not sufficient data to determine the exact length of river that would be affected by such variations. A figure of 5 km has been used as a proxy for this indicator where the next downstream major tributary is farther than 5 km; where the tributary is less than 5 km, the distance to that tributary is used, which is the case of the Rusumo Falls Project where the distance is 4 km. SSEA III - Final Report J-18 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Source for data on population: LandScan Global Population Database, Oak Ridge National Laboratory (see notes for criterion 1.1). J.2.4 Land Issues Land area (ha) required for Options project infrastructure and Area Score transmission facilities (ha)/GWh Bujagali 949 0.49 0.03 Kabu 16 74 0.66 0.04 Kakono (High) 1,719 5.73 0.32 Karuma 495 0.28 0.02 Masigira Mpanga Mutonga 1,116 3.40 0.19 Ruhudji 2,160 1.12 0.06 Rumakali 1,640 1.44 0.08 Rusumo Falls 27,795 68.97 3.90 Ruzizi III 79 0.19 0.01 Songwe 6,000 4.44 0.25 Upper Kihansi (storage) Generic Wind 30 MW 520 7.88 0.45 Geothermal - Generic 78 0.16 0.01 Mombasa - Gas/LNG steam 1,885 0.90 0.05 Mombasa - Coal steam 2,060 0.98 0.06 Mchuchuma - Coal steam 2,374 0.85 0.05 GT 60 MW gas - generic x 4 units 100 0.06 0.00 CC gas x 3 units 75 0.06 0.00 Kivu methane engines 30 MW 238 0.28 0.02 x 4 units Notes: Best = 0; Worst = 10 Best set for 0 ha/GWh; worst set for 177 ha/GWh (Akosombo Project, Ghana). Areas required for hydroelectric options come from project reports. Areas required for thermal options have been established on the basis of a literature survey on similar projects (except for the area required for Mchuchuma coal mine that is indicated on the following web site: http://www.ndctz.com/colliery.htm). In the case of the Rusumo Falls option, the area of Lake Rweru (12500 ha) has been subtracted from the reservoir area. The area required for transmission lines has been determined as follows: length of the line between power station and grid multiplied by the width of the right-of-way: 30 m for 132 kV line and 40 m for a 220 kV line (figures used in the Bujagali EIA. March 2001). SSEA III - Final Report J-19 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.2.5 Ranking within the Socio-economic Category Scores per Criterion Final Sensitivity Options S1 S2 S3 S4 Score 10%/40%/15%/35%/Equal Weighting 15% 35% 15% 35% 10%/40% 15%/35% Base Bujagali - 7.0 0.0 0.0 2.5 2.8 2.5 1.8 Kabu 16 0.6 1.9 3.4 0.0 1.3 1.2 1.3 1.5 Kakono (High) 4.7 5.7 0.9 0.3 3.0 3.0 3.0 2.9 Karuma 0.1 9.3 0.0 0.0 3.3 3.8 3.3 2.4 Masigira Mpanga Mutonga 1.1 9.6 0.1 0.2 3.6 4.0 3.6 2.8 Ruhudji 0.1 9.9 0.1 0.1 3.5 4.0 3.5 2.5 Rumakali 1.0 9.0 0.5 0.1 3.4 3.8 3.4 2.7 Rusumo Falls 5.0 - 1.1 3.9 2.3 2.2 2.3 2.5 Ruzizi III - 5.8 3.8 0.0 2.6 2.7 2.6 2.4 Songwe 4.5 8.3 3.4 0.3 4.2 4.2 4.2 4.1 Upper Kihansi (storage) Generic Wind 30 MW - 5.8 - 0.4 2.2 2.5 2.2 1.6 Geothermal - Generic 0.0 9.8 - 0.0 3.4 3.9 3.4 2.4 Mombasa - Gas/LNG steam 0.1 10.0 - 0.1 3.5 4.0 3.5 2.5 Mombasa - Coal steam 0.1 10.0 - 0.1 3.5 4.0 3.5 2.5 Mchuchuma - Coal steam 0.2 9.8 - 0.0 3.5 4.0 3.5 2.5 GT 60 MW gas - generic x 4 units 0.1 10.0 - 0.0 3.5 4.0 3.5 2.5 CC gas x 3 units 0.1 10.0 - 0.0 3.5 4.0 3.5 2.5 Kivu methane engines 30 MW x 4 units 0.1 8.0 - 0.0 2.8 3.2 2.8 2.0 SSEA III - Final Report J-20 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.3 Environmental Category J.3.1 Impact on Resource Depletion Options Energy payback ratio Score Bujagali 260 0.37 Kabu 16 255 0.56 Kakono (High) 205 2.42 Karuma 250 0.74 Masigira Mpanga Mutonga 220 1.86 Ruhudji 225 1.67 Rumakali 225 1.67 Rusumo Falls 205 2.42 Ruzizi III 267 0.11 Songwe 205 2.42 Upper Kihansi (storage) Generic Wind 30 MW 34 8.77 Geothermal - Generic 267 0.11 Mombasa - Gas/LNG steam 2.2 9.96 Mombasa - Coal steam 2.5 9.94 Mchuchuma - Coal steam 5.1 9.85 GT 60 MW gas - generic x 4 units 2.5 9.94 CC gas x 3 units 5 9.85 Kivu methane engines 30 MW x 4 units 3 9.93 Notes: Best = 0; Worst = 10 Best set for 270 (a run-of-river hydroelectric project with no underground tunnel); worst set for 1 (no net energy gained such as a thermal station using oil coming from tar sands) EPR values for Life cycle Assessment were taken from the following article: Gagnon, Luc. Bélanger, Camille. Uchiyama, Yohji. Update to Life Cycle assessment of electricity generation options: The status of research in year 2001. Energy Policy. Vol. 30. No. 14. November 2002, pages 1267-1278. No data is available for a geothermal plant. A geothermal plant does not consume much energy to build; on the lifespan of the plant, the electricity production resource is almost infinite. Therefore, the EPR value of a run-of-river plant was used for a geothermal plant. SSEA III - Final Report J-21 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.3.2 Impact of Greenhouse Gas Emissions Net CO2 equivalent emissions Options over the life cycle of the Score project (t/GWh) Bujagali 4 0.04 Kabu 16 3 0.03 Kakono (High) 4 0.04 Karuma 4 0.04 Masigira 10 0.09 Mpanga 10 0.09 Mutonga 10 0.09 Ruhudji 10 0.09 Rumakali 10 0.09 Rusumo Falls 10 0.09 Ruzizi III 3 0.03 Songwe 10 0.09 Upper Kihansi (storage) 10 0.09 Generic Wind 30 MW 10 0.09 Geothermal - Generic 79 0.72 Mombasa - Gas/LNG steam 440 4.02 Mombasa - Coal steam 1095 10.00 Mchuchuma - Coal steam 840 7.67 GT 60 MW gas - generic x 4 units 490 4.47 CC gas x 3 units 400 3.65 Kivu methane engines 30 MW x 4 units 577 5.27 Notes: Best = 0; Worst = 10 Best set for 1 t/GWh (a run-of-river hydroelectric project); worst set for 1095 t/GWh (a modern coal-fired thermal plant with SO2 scrubbing). Emission factors for life cycle assessment taken from the following two references: Comparison of Energy Systems Using the Life Cycle Assessment. A Special Report of the World Energy Council. London. July 2004. Gagnon, Luc. Bélanger, Camille. Uchiyama, Yohji. Update to Life Cycle assessment of electricity generation options: The status of research in year 2001. Energy Policy. Vol. 30. No. 14. November 2002, pages 1267-1278. SSEA III - Final Report J-22 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.3.3 Impacts of Air Pollutant Emissions on Biophysical Environment NOx SO2 SO2 Options emissions emissions equivalent Score (t/GWh) (t/GWh) emissions (t/GWh) Bujagali 0 0 0 - Kabu 16 0 0 0 - Kakono (High) 0 0 0 - Karuma 0 0 0 - Masigira 0 0 0 - Mpanga 0 0 0 - Mutonga 0 0 0 - Ruhudji 0 0 0 - Rumakali 0 0 0 - Rusumo Falls 0 0 0 - Ruzizi III 0 0 0 - Songwe 0 0 0 - Upper Kihansi (storage) 0 0 0 - Generic Wind 30 MW 0 0 0 - Geothermal - Generic 0 0 0 - Mombasa - Gas/LNG steam 0.83 0.33 0.911 2.80 Mombasa - Coal steam 1.1 1.21 1.98 6.08 Mchuchuma - Coal steam 1 1.1 1.8 5.53 GT 60 MW gas - generic x 4 units 0.75 0.5 1.025 3.15 CC gas x 3 units 0.75 0.3 0.825 2.54 Kivu methane engines 30 MW x 4 units 1.5 0.3 1.35 4.15 Notes: Best = 0; Worst = 10 Best set for 0 t SO2 equivalent emissions/GWh (hydroelectric options); worst set for 3.254 t SO2 equivalent emissions/GWh (worst case for emissions of a coal-fired thermal plant with SO2 scrubbing). Emission factors for life cycle assessment taken from the two following references: Comparison of Energy Systems Using the Life Cycle Assessment. A Special Report of the World Energy Council. London. July 2004 Gagnon, Luc. Bélanger, Camille. Uchiyama, Yohji. Update to Life Cycle assessment of electricity generation options: The status of research in year 2001. Energy Policy. Vol. 30. No. 14. November 2002, pages 1267-1278. The acidification potential of NOx emissions is 0.7 times the acidification potential of SO2 emissions (www.pe-product.de/GABI/documentation/IKP/Wirkkriterien/VERSAUERGUN). SSEA III - Final Report J-23 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.3.4 Land Requirements Land area required for project infrastructure Options including reservoir and Area Score transmission facilities ha/GWh (ha) Bujagali 949 0.49 0.03 Kabu 16 74 0.66 0.04 Kakono (High) 1,719 5.73 0.32 Karuma 495 0.28 0.02 Masigira 0 0.00 - Mpanga 0 0.00 - Mutonga 1,116 3.40 0.19 Ruhudji 2,160 1.12 0.06 Rumakali 1,640 1.44 0.08 Rusumo Falls 27,795 68.97 3.90 Ruzizi III 79 0.19 0.01 Songwe 6,000 4.44 0.25 Upper Kihansi (storage) 0 0.00 - Generic Wind 30 MW 520 7.88 0.45 Geothermal - Generic 78 0.16 0.01 Mombasa - Gas/LNG steam 1,885 0.90 0.05 Mombasa - Coal steam 2,060 0.98 0.06 Mchuchuma - Coal steam 2,374 0.85 0.05 GT 60 MW gas - generic x 4 units 100 0.06 0.00 CC gas x 3 units 75 0.06 0.00 Kivu methane engines 30 MW 238 0.28 0.02 x 4 units Notes: Best = 0; Worst = 10 Best set for 0 ha/GWh; worst set for 177 ha/GWh (Akosombo Development, Ghana). Areas required for hydroelectric options come from project reports. Areas required for thermal options have been established on the basis of a literature survey on similar projects (except for the area required for Mchuchuma coal mine that is indicated on the following web site: http://www.ndctz.com/colliery.htm). In the case of the Rusumo Falls option, the area of Lake Rweru (12500 ha) has been subtracted from the reservoir area. The area required for transmission lines has been determined as follows: length of the line between power station and grid multiplied by the width of the right-of-way: 30 m for 132 kV line and 40 m for a 220 kV line (figures used in the Bujagali EIA. March 2001). SSEA III - Final Report J-24 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.3.5 Waste Disposal Options Land area required for ash disposal (ha/TWh) Score Bujagali 0 0.00 Kabu 16 0 0.00 Kakono (High) 0 0.00 Karuma 0 0.00 Masigira 0 0.00 Mpanga 0 0.00 Mutonga 0 0.00 Ruhudji 0 0.00 Rumakali 0 0.00 Rusumo Falls 0 0.00 Ruzizi III 0 0.00 Songwe 0 0.00 Upper Kihansi (storage) 0 0.00 Generic Wind 30 MW 0 0.00 Geothermal - Generic 0 0.00 Mombasa - Gas/LNG steam 0 0.00 Mombasa - Coal steam 86 8.60 Mchuchuma - Coal steam 70 7.00 GT 60 MW gas - generic x 4 units 0 0.00 CC gas x 3 units 0 0.00 Kivu methane engines 30 MW x 4 units 0 0.00 Notes: Best = 0; Worst = 10 Best set for 0 ha/GWh; worst set for 100. Ash content for Mchuchuma coal = 32.86% (http://www.ndctz.com/colliery.htm). South African coal is a mixture of high ash content coal. Ash content is considered to be 40%. The Ministry of the Environment of India ratio of 0,6 ha of land for ash disposal per MW has been used (ash content: 40%). SSEA III - Final Report J-25 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.3.6 Environmental Impacts on the Downstream Reaches Dried-up River Stretch with hourly Length of Options River River with Stretch or daily Altered Flow Score (km) variations (km) (km/TWh) Bujagali 0 5 2.60 0.20 Kabu 16 3 5 71.43 5.52 Kakono (High) 0 5 16.67 1.29 Karuma 2.8 5 4.46 0.34 Masigira Mpanga Mutonga 0 5 15.20 1.17 Ruhudji 17 5 11.40 0.88 Rumakali 17 5 19.28 1.49 Rusumo Falls 1 4 14.89 1.15 Ruzizi III 1 5 14.35 1.11 Songwe 12.4 15 20.27 1.57 Upper Kihansi (storage) Generic Wind 30 MW 0 0 0.00 0.00 Geothermal - Generic 0 0 0.00 0.00 Mombasa - Gas/LNG 0 0 0.00 steam 0.00 Mombasa - Coal steam 0 0 0.00 0.00 Mchuchuma - Coal steam 0 0 0.00 0.00 GT 60 MW gas - generic 0 0 0.00 x 4 units 0.00 CC gas x 3 units 0 0 0.00 0.00 Kivu methane engines 0 0 0.00 30 MW x 4 units 0.00 Notes: Best = 0; Worst = 10 Best set for 0 km/TWh; worst set for 129.41 km/TWh (Siguvyaye). The length of the river stretch with reduced flow between dam and tailrace has been determined on the basis of each project technical characteristics and maps available in project reports. With regards to the river stretch with altered flow, it is considered that any project with a regulating pond can be used for providing peaking power, which results in frequent hourly, daily or weekly water flow variations downstream of the tailrace. There is not sufficient data to determine the exact length of river that would be affected by such variations. A figure of 5 km has been used as a proxy for this indicator where the next downstream major tributary is farther than 5 km; where the tributary is less than 5 km, the distance to that tributary is used, which is the case of the Rusumo Falls Project where the distance is 4 km. SSEA III - Final Report J-26 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.3.7 Ranking of options within the Environmental Category Scores for Each Criterion Sensitivity analysis Options Final E1 E2 E3 E4 E5 E6 Score Base Weighting 25% 10% 10% 25% 5% 25% 30%/5%/5%/ 25%/10%/10%/Ash 5% 30%/5%/25% 25%/5%/25% Others equal Bujagali 0.37 0.04 - 0.03 - 0.20 0.2 0.2 0.2 0.1 Kabu 16 0.56 0.03 - 0.04 - 5.52 1.5 1.6 1.5 1.2 Kakono (High) 2.42 0.04 - 0.32 - 1.29 1.0 1.1 1.0 0.8 Karuma 0.74 0.04 - 0.02 - 0.34 0.3 0.3 0.3 0.2 Masigira - 0.09 - - - - Mpanga - 0.09 - - - - Mutonga 1.86 0.09 - 0.19 - 1.17 0.8 0.9 0.8 0.6 Ruhudji 1.67 0.09 - 0.06 - 0.88 0.7 0.7 0.7 0.5 Rumakali 1.67 0.09 - 0.08 - 1.49 0.8 0.9 0.8 0.6 Rusumo Falls 2.42 0.09 - 3.90 - 1.15 1.9 2.2 1.9 1.4 Ruzizi III 0.11 0.03 - 0.01 - 1.11 0.3 0.3 0.3 0.2 Songwe 2.42 0.09 - 0.25 - 1.57 1.1 1.2 1.1 0.8 Upper Kihansi (storage) Generic Wind 30 MW 8.77 0.09 - 0.45 - - 2.3 2.8 2.3 1.8 Geothermal - Generic 0.11 0.72 - 0.01 - - 0.1 0.1 0.1 0.2 Mombasa - Gas/LNG steam 9.96 4.02 2.80 0.05 - - 3.2 3.3 3.2 3.2 Mombasa - Coal steam 9.94 10.00 6.08 0.06 8.60 - 4.5 4.2 4.5 5.4 Mchuchuma - Coal steam 9.85 7.67 5.53 0.05 7.00 - 4.1 4.0 4.1 4.7 GT 60 MW gas - generic x 4 units 9.94 4.47 3.15 0.00 - - 3.2 3.4 3.2 3.3 CC gas x 3 units 9.85 3.65 2.54 0.00 - - 3.1 3.3 3.1 3.0 Kivu methane engines 30 MW x 4 units 9.93 5.27 4.15 0.02 - - 3.4 3.5 3.4 3.7 SSEA III - Final Report J-27 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.4 Project Risks J.4.1 Introduction The purpose of this section is to identify and assess the risks that a power development option might face that would result in its performance being different from that planned (costs higher or lower than estimated, output higher or lower than expected, on-power date earlier or later than expected, etc.). During the review of power development options in Chapter 7 several such risks were identified: Risks of opposition from internal and external groups, Risks related to institutional and legal frameworks Increased risks to public health, Risks to designated habitats or natural sites, Risks to sites of exceptional biodiversity value, Risks in the use of resources, Risks of sedimentation, Gestation period in delivering benefits, Hydrological risk, and Financial risk. Each of these elements of risk is discussed below. It should be noted that all of the risks being evaluated in this section are, by their very nature, unquantifiable. In particular, they include environmental and social issues that cannot be readily quantified and could not be considered in the MCA. This distinguishes this section from the preceding Chapter on the comparison of alternatives based on the multi-criteria analysis using ratio scales on quantified indicators. J.4.2 Opposition from Pressure Groups The risk of attracting opposition from external groups is affected by, among other reasons, (1) the need for resettlement of populations (even though the cost estimates include an allowance to compensate people who are displaced and the multi-criterion analysis includes a criterion for the number of people displaced normalized to eliminate the effect of size of project, it is the Consultant's opinion that significant population displacement could attract opposition from social NGOs), (2) impacts on unique habitats (such as National Parks, Ramsar sites, exceptional biodiversity sites, etc.) or on scenery of exceptional beauty, as a result of reservoir impoundment or hydraulic modifications downstream of the dam, (3) the potential for significant increased risks to public health (malaria and bilharzia for hydroelectric projects and pulmonary diseases for thermal projects), (4) potential impacts on cultural, historical and religious sites, and (5) potential impacts on indigenous communities. A review of the power development options indicates that the resettlement issue varies from option to option, as summarized below: Virtually no resettlement required: most thermal plants, Bujagali14, and most run-of- river hydro plants (Kabu 16, Karuma and Ruzizi III). Some resettlement (say 300 to 2000 people): Kakono, Mutonga, Ruhudji, Rumakali hydroelectric projects, and the Mchuchuma coal-fired steam plant (due to the associated coal mine). 14Resettlement has already taken place at Bujagali. SSEA III - Final Report J-28 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Resettlement (beyond 2000 people): Rusumo Falls, and Songwe hydro options. Impacts on unique habitats or on scenery of exceptional beauty are expected to apply to the following options: · Bujagali would affect sceneries that are considered to be of exceptional beauty with high tourism potential. · Mutonga could affect riverine habitats along the Tana River due to changes to the hydraulic and sedimentation regime, in particular in the Tana River Primate National Reserve. · Rusumo Falls might affect riverine habitats in the Akagera National Park due to changes to the hydraulic and sedimentation regime of the Akagera River downstream of the dam. · Kakono could have an impact on the Minziro Forest Reserve. Kabu 16 might affect the Ruzizi National Park15 due to changes to the hydraulic and sedimentation regime of the Kaburantwa and Ruzizi Rivers downstream of the dam. The most significant risk to public health is expected from the Rusumo Falls and Songwe hydroelectric options and from both coal-fired steam plants. In particular, air pollutant emissions of the Mombassa coal-fired steam plant, together with air pollutant emissions from other sources in the Mombassa region, could generate a risk of increase of pulmonary diseases. These risks would add to the possibility of pressure from external groups With regards to potential impacts on cultural, historical and religious sites, available EIA reports on Bujagali, Karuma, Ruhudji and Rumakali hydropower projects mention impacts on archaeological sites and, in the case of Bujagali, impacts on family graves. No sites of exceptional value would be affected. Mitigation measures include the evaluation of archaeological potential in project-affected area, the relocation of elements of infrastructure in order to avoid certain sites, archaeological tests and the excavation of sites with high potential. During construction, in cases of a find by chance of an archaeological site, salvage operations should be undertaken. It is unlikely that other projects considered in the comparative analysis would generate impacts on sites of exceptional value. It is also assumed that the same type of mitigation measures would be implemented for these projects. It is thus considered that risks of potential impacts on cultural, historical, and religious sites are minor and about the same for all options. Available EIA reports do not mention any impacts on indigenous communities. Based on available documentation, it seems unlikely that other options would generate such impacts. It is thus considered that risks of potential impacts on indigenous communities are minor and about the same for all options. On the other hand, it should be considered that possibilities to encounter indigenous communities in marginalized areas and remote places might occur. As a mitigation measures, further studies, more especially on projects located in remote areas, will be required to validate the risk of affecting an indigenous communities by the implementation of a proposed project. 15Some sources (maps, texts or websites) mention this National Park; others refer to it as a Natural Reserve and others do not mention a Park or Reserve at this location. For the purpose of this study it is assumed that there is a National Park at that location. SSEA III - Final Report J-29 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.4.3 Institutional and Legal Framework Risks related to the legal and regulatory framework in each of the countries in the region are primarily affected by (1) projects located in a country with a weak framework or one whose framework has been affected by recent social unrest, (2) projects that have a direct impact on two or more countries and (3) projects located in a national park or natural reserve with a similar status. Chapter 3 indicates that all countries in the region have reasonably strong frameworks; however, in the case of the DRC, a prolonged period of social unrest has resulted in difficulties in ensuring that the framework is respected. This also applies to a lesser extent to the western provinces in Burundi and to the northern part of Uganda near the border with the Sudan. Only two power development options are affected by this risk: Ruzizi III and the engines fed by methane gas from Lake Kivu. Development options affecting two or more countries would require all agreements associated with them to be negotiated in light of the legal and regulatory frameworks of the countries involved. This can add complications to the negotiating process with the attendant risk of delays and increases in cost. Four development options are affected: Rusumo Falls, Ruzizi III16, Songwe and the engines fed by methane gas from Lake Kivu. Particular attention should be given for the Songwe project, as the border dispute between Malawi and Tanzania remained unresolved. J.4.4 Public Health For thermal options, increased risks to public health are related to nitrogen oxides (NOx) emissions, sulphur dioxides (SO2) emissions and particulate matter emissions. NOx emissions, together with volatile organic compounds, lead to the formation of ground-level ozone. Ozone causes breathing problems, reduced lung function, asthma and reduced resistance to cold and other infections. SO2 emissions also cause permanent damage to lungs. Particulate matter emissions infiltrate into the respiratory system and may cause significant damage, especially PM10 or particulate matter up to 10 micrometers in size. Risks to public health are considered to be higher for the Mombassa coal-fired steam plant: air pollutant emissions from this plant, together with air pollutant emissions from other sources in the Mombasa region, could generate a risk of increase of pulmonary diseases. For hydroelectric options, the presence of the reservoir and changes in water flows downstream of the dam may provide favourable habitats to vectors of waterborne diseases, in particular malaria and bilharzias (or schistosomiasis). Risks to public health are considered to be higher for Rusumo Falls and Kakono because these projects would entail an increase of bilharzia related to water hyacinth accumulation in the reservoir. The Songwe option also involves risks of increase of bilharzia in the reservoirs and in irrigation zones. In addition, socio-cultural disruptions related to involuntary displacement can lead to health problems among the relocatees and the host populations. Epidemics can also occur as a result of the influx of migrant workers during construction as well as of migrant settlers around the reservoir. In particular, careful consideration must be given to the spread of HIV/AIDS and other sexually transmitted diseases. Specific measures will be required to minimize these impacts, such as the introduction of readily accessible medical clinics and 16As mentioned in Chapter 3, under a Convention signed in 1984, Burundi, (then) Zaire and Rwanda agreed to jointly build and operate a hydroelectric station, Ruzizi II. Ruzizi II is the common property of the three countries. It supplies electricity to REGIDESO (Burundi), ELECTROGAZ (Rwanda) and SNEL (DRC). Although Ruzizi III straddles the boundary between the DRC and Rwanda, this convention is expected to be used as a starting point in negotiations for its development. SSEA III - Final Report J-30 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS dispensaries in project-affected communities and the design and implementation of public health education programs. Such risks to public health are higher for larger hydroelectric options. The risk to public health is expected from the Rusumo Falls and Songwe hydroelectric options and from both coal-fired steam plants. In particular, air pollutant emissions of the Mombassa coal-fired steam plant, together with air pollutant emissions from other sources in the Mombassa region, could generate a risk of increase of pulmonary diseases. Based on the above, the following scores have been used (0 = best and 10 = worst): · Mombassa, Rusumo Falls, Kakono, Songwe: 5 · Hydroelectric options larger than 200 MW (Bujagali, Karuma, Ruhudji, Rumakali): 3 · Other options: 1 J.4.5 Risks to Designated Habitats or Natural Sites The assessment of this risk factor is based on the following three indicators: · Projects affecting a National Park or a Ramsar site downstream of the dam: a Ramsar site is designated under the Convention on Wetlands, signed in Ramsar, Iran, in 1971. This Convention is an intergovernmental treaty which provides the framework for national action and international cooperation for the conservation and wise use of wetlands and their resources. Seven hydroelectric projects could affect a Ramsar site or a National Park downstream of the dam: Bujigali, Mpanga, Mutonga, Ruhudji, Rusumo Falls, Ruzizi III and Upper Kihansi · Projects affecting important scenic area: the following projects could affect important scenic areas: - Bujagali, on the Victoria Nile, would affect scenery that is considered to be of exceptional beauty with high tourism potential. · Projects affecting other important habitats, such as important wetlands other then Ramsar sites or forest reserves. Seven options could affect such habitats: Kakono, Masigira, Mutonga, Rumakali, Rusumo Falls, Songwe and Upper Kihansi. J.4.6 Risk to Sites of Exceptional Biodiversity Value The region, particularly the Lake Nyasa/Malawi, the Lake Tanganyika and several mountain ranges surrounding the Great Lakes, are renowned for their exceptional biodiversity. These areas contain several hundreds of endemic species (fish, amphibians, reptiles, birds, plants) that are not found anywhere else, many in a precarious situation because of a number of threats. To qualify this risk, projects in areas with the greatest biodiversity, have a score of 10 (worst) while projects in areas of less significant biodiversity have a lower score (better). · Projects in Lake Nyasa/Malawi basin: score = 10 · Projects in Lake Tanganyika basin: score = 8 · Projects in the Rufiji River basin: score = 5 · Projects in Lake Victoria and Victoria Nile basins: score = 4 · Projects in the Tana River basin: score = 2 SSEA III - Final Report J-31 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.4.7 Use of Local Resources (Fisheries, Agriculture, Land Uses, etc.) A hydroelectric plant uses the natural resources of a country and these resources are in principle renewed continuously. The only uncertainties are the amount of water that will flow in the river from year to year and the quantities of water used for other purposes such as small scale irrigation, which can be quite significant and conflict with hydroelectricity needs. Provided that there are good flow records available, the detailed design of a project should take account of the droughts that the river has been subjected to in the past as well as the impact of changes in other uses of the water in the river. Considering that fisheries in most of the lakes in the area is the main source of proteins and employment, hydroelectric projects located not far upstream on rivers discharging into lakes, and having an impact on the sedimentation patterns in the lakes or preventing migration of some fish species would also present a risk on the fisheries and livelihoods of local populations living in proximity to the river deltas. The risk of sedimentation is further examined in the next section. A class of risk that also needs to be considered is the risk associated with the supply of fuel for the plant and the control that a country has over the fuel that is used in a power plant. A thermal plant using imported fuel (oil, gas or coal) is at the mercy of policies of foreign governments or of international market forces, which can have a significant impact on the cost and availability of power. Between these two extremes are plants that use local but finite resources, such as coal. The supply of methane gas from Lake Kivu and geothermal energy might also be considered as a local but finite resource. The usefulness of such plants depends upon the reserves of those resources, and an incorrect assessment of those reserves puts at risk the expected output of the plant over its estimated useful life. J.4.8 Risks of Sedimentation Studies by Electrowatt and Norconsult in December 1975 indicate that the sediment load in the Ruvuvu and Kagera Rivers is less than 100 grams per cubic metre. By way of comparison, a river with a heavy sediment load can have a concentration of 1000 g/m3. However, site visits in the rainy season indicate that the sediment load of Kagera River is now more significant. It was thus rated with some sedimentation risk. The literature indicates that the power development options on the Nile River downstream of the outlet from Lake Victoria have relatively little sediment to contend with (the Lake would trap and retain most of the sediment coming into it). The same type of situation would prevail on the Ruzizi River. Studies carried out on sedimentation in the Stiegler's Gorge Project reservoir at the end of the 1970s and early 1980s indicate that the annual sediment transport volume of the Rufiji River at the dam site is about 25 million tons. The sediment deposition in the reservoir would have significant effects downstream such as the erosion of the riverbed and changes in the configuration of the delta area. The Seven Forks Complex on the Tana River (Mutonga project) is known to be plagued by important sedimentation problems, due in part, by agricultural practices in the watershed. On the other hand, project design can significantly attenuate this issue. Very little project-specific information is available on the quantities of sediment to be expected. Because of this, the following scale (and score) has been used: SSEA III - Final Report J-32 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS · Non-hydro options: by definition, no sediment ­ score = 0; · Options on the Kagera River: some sedimentation risk ­ score = 2; · Options on the Victoria Nile: virtually no sedimentation as most would be deposited in Lake Victoria ­ score = 1; · Mutonga option: sediment deposition in the reservoir and potential downstream effects (see Appendix F) ­ score = 4; · Ruzizi III: very little sedimentation ­ score = 1; and · Options on other rivers: sedimentation risk unknown; reviews of the little documentation available suggest that the risk for options on these rivers would be about the same as the risk for options on the Kagera River ­ score = 2. J.4.9 Gestation Period There are two technical risks associated with an option that can be considered together; one is related to the amount and reliability of the data available for an option and the other is its size. Options at the prefeasibility level have virtually no information on sub-surface conditions. There is therefore, a significant risk that geological faults could be identified with more information. To attempt to overcome this risk, a contingency is usually added to the cost estimates to cover such uncertainties. However, there remains the risk that the allowance for such uncertainties may be insufficient. To improve on the level and reliability of data, a project is usually submitted to several levels of study (prefeasibility, feasibility and detailed design). Each level of study has to be completed to determine if an option appears worth pursuing to the next level. Thus the lower the level of reliability of project data, the more time is required to implement a project. It is intuitively obvious that large and/or complex projects require more time to construct than smaller, simpler projects. Larger projects tend to have associated with them higher risks of delays, unforeseen costs and fuel supply. The gestation period for a project takes account of both of these issues. Some options can be implemented quickly: according to its proponent, the engines fed by methane gas from Lake Kivu can be installed by 2007. Others such as the Mombasa LNG/Gas option would require additional studies and infrastructure so that the earliest it could come on line would be about 2015. For this analysis, the scores for power development options are assumed to range from 0 (best) for options that can be implemented in 2007 to 10 (worst) for options that cannot be implemented until the end of the study horizon (2020). J.4.10 Hydrological Risks The energy potential of a hydroelectric scheme is calculated from the historical hydrologic record obtained at the site, or a synthetic record based on historic records. This assumes that the hydrological pattern that will be observed in the future will be similar to the hydrological pattern observed in the past, and that the hydrological record available is accurate and representative. This SSEA assessment concentrates on the Nile Equatorial basin. Many of the hydroelectric power development options under study are located on tributaries of Lake Victoria or on the Nile flowing out of Lake Victoria. The drainage area of the Lake Victoria basin is SSEA III - Final Report J-33 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS 194,000 km², and the area of the lake itself is 68,000 km². The main tributary of this lake is the Kagera River, which has a drainage area of 60,000 km² at its outlet. The issue of the apparently abnormal hydrological phenomena that occurred in the basin of Lake Victoria, where a sharp increase of the outflow was observed in 1961, was considered important, as it could affect confidence in recorded flows and on the selection of a historical period to be considered representative of what is to be expected in the future. Hydrological records at the outlet of Lake Victoria are available without interruption since 1900. These records include the discontinuity referred to above that occurred in the early 1960's. A controversy is going on relative to the reliability of the records at the outlet of Lake Victoria: · One side believes that the flow records at the outlet of Lake Victoria are reasonably reliable, at least since 1925, and that the sharp flow increase in the early 1960's is due to a natural phenomena; · The other side believes that the discharge measurements carried out prior to 1954 are unreliable. As a consequence, the only records which should be used for evaluating the energy production of the hydroelectric plants in this basin should be those recorded since 1954. Figure J-2 illustrates the comparison between the hydrological patterns on the Kagera River at Rusumo Falls and the outlet of Lake Victoria; it demonstrates that both patterns are reasonably similar. The only difference is that the curve for the outlet of Lake Victoria reflects the strong routing effect of this lake; outflow volumes are significantly delayed as compared to observed records on the Kagera River. The fact that the same hydrological pattern is observed at two different locations based on totally independent measurements tends to favour the opinion that the flow increase observed in the early 1960's was real, and it is not the consequence of an error in data record or compilation. However, a physical explanation remains to be found for this phenomenon. SSEA III - Final Report J-34 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Figure J-2 - Comparison of Long Term Fluctuations: Lake Victoria Outflow and Kagera River at Rusumo Falls 2.00 Rusumo Falls (1940-1984) 1.75 Lake Victoria outflow (1940-2002) 1.50 1.25 woflti 1.00 Un 0.75 0.50 0.25 0.00 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 It is the Consultant's view that the hydrological risk due to this controversy in the region is quite low. On a scale of 0 to 10 where 0 is the best, the following scores have been used: · Non-hydro options: score = 0 (ideal); · Options on the Victoria Nile: score = 4 (reasonably good); · Options on the Kagera River: score = 2 (better than those on the Nile); and · Options on other rivers: score = 3 (hydrology unknown; assumed between Victoria Nile and Kagera hydrology in terms of risk). It should be noted that this question will be looked at very closely during the detailed design stage of any power development option. This will be done as part of the analysis of the power output that can be expected from any project design. The assessment of the firm output of a hydroelectric project is usually defined on the basis of the hydrology that can be expected to be exceeded a certain percentage of the time, such as 95% (i.e. a year with flows that have been exceeded 19 years out of 20). Thus, the design of the project takes account of the risk of drought as well as the risk that the hydrology is uncertain. Most of the power development options that were identified in Chapter 7 are hydro-electric. Systems relying solely or principally on hydro options are open to the risk of droughts that could be more severe than experienced historically, which could, in turn, lead to either occasional power shortages or excess investment in generation to reduce these risks. For this reason, prudent planning suggests that technological diversification of power development options should be considered in the development of generation expansion portfolios SSEA III - Final Report J-35 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.4.11 Financial Risks Financial risk can be considered at two levels: (1) the risk of not being able to attract sufficient financing and (2) the risk of financial over-runs. Attraction of Capital The risk related to the attraction of capital depends upon several factors: Political stability in the country and the region; Financial health of the proponent of the option; Economic and financial viability of the option. The Euromarket Review, September 2005 issue (Volume 35, Number 425, pages 314 ­ 321) provides a ranking and a rating of country risk for each country in the world. Table J-4 provides the ranking of each of the countries in the region as well as the score under different criteria: Table J-4 - Euromarket Review Ranking and Rating of Country Risk Risk and maximum score Burundi DRC Kenya Rwan. Tanz. Ugan. Political Risk - 25% 5.47 2.73 9.77 4.39 8.78 8.07 Economic performance ­ 25% 3.99 7.29 5.85 3.57 6.17 6.06 Debt Indicators ­ 10% 6.54 0.00 9.05 8.55 8.82 8.89 Debt in default ­ 10% 10.00 0.00 10.00 10.00 9.79 10.00 Credit Ratings ­ 10% 0.00 0.00 0.00 0.00 0.00 0.00 Access to bank finance ­ 5% 0.00 0.00 0.00 0.00 0.00 0.00 Access to short-term finance ­ 5% 1.17 1.17 2.25 1.50 2.42 2.33 Access to capital markets ­ 5% 0.00 0.00 0.50 0.00 0.00 0.00 Forfaiting ­ 5% 0.00 0.00 0.58 0.00 1.17 0.58 Total score (overall country risk) 27.16 11.19 38.01 28.00 37.15 35.94 Overall rank out of 185 171 182 108 169 115 121 For comparison, the highest ranked country in Africa was Botswana with a rank of 56 and a score of 60.04%. The lowest ranked is Afghanistan with a rank of 185 and a score of 6.39%. None of the options has advanced enough in the development process to have a proponent (whether the utility, the government or an independent power producer) to be able to assess the risks related to the financial health of the proponent or the economic and financial viability of the option. Each option is evaluated on its financial risk in terms of the Euromarket Country Risk indicator. The options are given a country risk indicator equal to the indicator of the country in which it is located. For options straddling two countries, the average value is used. SSEA III - Final Report J-36 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS Financial Over-runs The risk of financial over-runs is a function of the level of study of the option; an option studied to the prefeasibility level has a higher risk of over-runs than one studied to the level of feasibility, since more information on the options is available in that latter case. To attempt to compensate for this varying level of site-knowledge, different levels of contingency are added to the cost estimate, which are a function of the level of study. Assessment of Financial Risk Although the Euromarket Review rates country risk as distinct from project risk, it is the Consultant's view that lending institutions will gauge the risks of investing in a project largely by the country in which it is located. The Euromarket Review rating of country risk is, therefore, taken as the indicator of financial risk for each power development option. For options that straddle two or more countries, several alternatives were considered: · The risk associated with the option would be higher than the risks of the option if it were located in only one of the countries; · The risks would be the same as the least risky of the two countries; · The risks would be the same as the more risky of the two countries; and · The risks would be the average of the two countries. The assessment used is the average of the two country risks ­ the first alternative would be purely subjective with no basis for selecting values and the second and third were discarded because it is expected that both countries would have an impact of the lenders' perception of the option. The scores used were based on the Rating of country risk where the best, which is defined by Euromarket Review as 100% was taken as 0 and the worst, which is defined as 0% would be given a score of 10. Mathematically, the scoring formula is: Score = 10 X (1 ­ Country Risk/100) J.4.12 Overall Assessment of Risk It would be convenient if an overall assessment of risk could be assigned to each option. However, there are two difficulties associated with that desire: · These risks cannot be quantified; · The relative importance of each risk is subjective; each analyst is likely to assign different weighting to each risk. An attempt is made at providing an overall assessment of risk using the following approach: 1. Each option is assigned a subjective score on the scale of 0 (best) to 10 (worst) for each of the following risks: · Risks of opposition from external groups · Risks related to institutional and legal frameworks · Increased risks to public health · Risks to designated habitats or natural sites SSEA III - Final Report J-37 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS · Risks to sites of exceptional biodiversity value · Risks in the use of resources · Risks of sedimentation · Gestation period in delivering benefits · Hydrological risk · Financial risk Because the values assigned to the different risk factors are not ratio data and lack reliability, it is not appropriate to calculate an overall weighted average risk score and conduct sensitivity tests. An un-weighted average risk score is thus only presented17. The detailed tables showing the risk factors used, their indicators and the values selected for each indicator are shown below. It should be noted that the data available for the Masigira, Mpanga and Upper Kihansi options was less than for the other options. The results of the above analysis indicate that: · Over half of the options fall in a narrow band of overall risk: between 2.5 and 3.5 out of 10.0. One quarter were better (under 2.5 and one quarter were somewhat more risky (3.7 to 5.3). · The band indicates that, overall, most options have low risks, even though each option has its risky features. · All options have a relatively high financial risk: between 6.2 and 8.0. · There are two hydroelectric options with a risk score exceeding 3.5 out of 10: Rusumo Falls at 4.1and Songwe at 4.2: - Both have significant risk of opposition. - Songwe has a long gestation period. - Rusumo Falls and Songwe seem to have increased risks to public health. - Rusumo Falls may have risks to designated habitats or natural sites. 17 For illustrative purposes, two sensitivity tests are presented: a weighting based on the results of the discussions held at the Fourth Stakeholder Consultation Workshop and a wider spread weighting. SSEA III - Final Report J-38 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5 Quantitative Assessment of Risks J.5.1 Risks of Opposition from External and Internal Groups Unique Options Reset- Public Risk of tlement Habitats/ Score Scenic Health opposition Bujagali - X X III 5.00 Kabu 16 - X II 3.00 Kakono X X XX V 9.00 Karuma - X II 3.00 Masigira X II 3.00 Mpanga X X III 5.00 Mutonga X X III 5.00 Ruhudji X X X IV 7.00 Rumakali X X III 5.00 Rusumo Falls XX XX XX V 9.00 Ruzizi III - X II 3.00 Songwe XXX X XX V 9.00 Upper Kihansi (storage) - X II 3.00 Generic Wind 30 MW - I 0.00 Geothermal - Generic - I 0.00 Mombasa - Gas/LNG steam - I 0.00 Mombasa - Coal steam - XX III 5.00 Mchuchuma - Coal steam X XX IV 7.00 GT 60 MW gas - generic x 4 units - - - I 0.00 CC gas x 3 units - - - I 0.00 Kivu methane engines 30 MW I 0.00 x 4 units - - - Notes: Best = 0; Worst = 10 Risk of Opposition: Class I: no impact on any of the indicators (Score: 0 out of 10) Class II: Impact of one indicator (Score: 3 out of 10) Class III: Impact of two indicators (Score: 5 out of 10) Class IV: Impact of three indicators (Score: 7 out of 10) Class V: Impact of four or more indicators (Score: 9 out of 10) Two or more 'X' considered equivalent to impact of two indicators SSEA III - Final Report J-39 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.2 Risks Related to Institutional and Legal Framework Risk related Country Two or to Options with weak more National institutional Score framework countries Park and legal framework Bujagali - - - I 0 Kabu 16 - - - I 0 Kakono - - - I 0 Karuma - - - I 0 Masigira - - - I 0 Mpanga - - - I 0 Mutonga - - - I 0 Ruhudji - - - I 0 Rumakali - - - I 0 Rusumo Falls - X - II 3 Ruzizi III X X - III 5 Songwe - X - II 3 Upper Kihansi (storage) - - - I 0 Generic Wind 30 MW - - - I 0 Geothermal - Generic - - - I 0 Mombasa - Gas/LNG steam - - - I 0 Mombasa - Coal steam - - - I 0 Mchuchuma - Coal steam - - - I 0 GT 60 MW gas - generic x 4 units - - - I 0 CC gas x 3 units - - - I 0 Kivu methane engines 30 MW x 4 units X X - III 5 Notes: Best = 0; Worst = 10 Risk related to institutional and legal framework Class I: no impact on any of the indicators (Score: 0 out of 10) Class II: Impact of one indicator (Score: 3 out of 10) Class III: Impact of two indicators (Score: 5 out of 10) Class IV: Impact of three indicators (Score: 7 out of 10) SSEA III - Final Report J-40 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.3 Risk to Public Health Options Score Bujagali 3 Kabu 16 1 Kakono 5 Karuma 3 Masigira 1 Mpanga 1 Mutonga 1 Ruhudji 3 Rumakali 3 Rusumo Falls 5 Ruzizi III 1 Songwe 5 Upper Kihansi (storage) 1 Generic Wind 30 MW 0 Geothermal - Generic 1 Mombasa - Gas/LNG steam 1 Mombasa - Coal steam 5 Mchuchuma - Coal steam 5 GT 60 MW gas - generic x 4 units 1 CC gas x 3 units 1 Kivu methane engines 30 MW x 4 units 1 Best = 0; Worst = 10 Scoring of options Mombasa, Rusumo Falls, Kakono, Songwe, Stiegler's Gorge: 5 Hydroelectric options larger than 200 MW (Ayago, Bujagali, Kalagala, Karuma, Murchison, Ruhudji, Rumakali, Stiegler): 3 Other options: 1 SSEA III - Final Report J-41 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.4 Risks to Designated Habitats or Natural Sites Project Project upstream Project Project Options in Park of park affecting affecting Class of or or scenic other Risk Score Preserve Ramsar area habitats site Bujagali X II 3.00 Kabu 16 X II 3.00 Kakono X II 3.00 Karuma I 0.00 Masigira X II 3.00 Mpanga X II 3.00 Mutonga X X III 5.00 Ruhudji X II 3.00 Rumakali X II 3.00 Rusumo Falls X X III 5.00 Ruzizi III X II 3.00 Songwe X II 3.00 Upper Kihansi (storage) X X III 5.00 Generic Wind 30 MW I 0.00 Geothermal - Generic I 0.00 Mombasa - Gas/LNG steam I 0.00 Mombasa - Coal steam I 0.00 Mchuchuma - Coal steam I 0.00 GT 60 MW gas - generic x 4 I 0.00 units CC gas x 3 units I 0.00 Kivu methane engines 30 MW I 0.00 x 4 units Notes: Best = 0; Worst = 10 Scoring of options Class I: no impact on any of the indicators (Score: 0 out of 10) Class II: Impact of one indicator (Score: 3 out of 10) Class III: Impact of two indicators (Score: 5 out of 10) Class IV: Impact of three indicators (Score: 7 out of 10) Class V: Impact of four indicators (Score: 9 out of 10) Two or more 'X' considered equivalent to impact of two indicators SSEA III - Final Report J-42 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.5 Risks to Biodiversity Options Total Score Bujagali 1-4 4 Kabu 16 8 Kakono 4 Karuma 4 Masigira 10 Mpanga 5 Mutonga 2 Ruhudji 5 Rumakali 10 Rusumo Falls 4 Ruzizi III 8 Songwe 10 Upper Kihansi (storage) 5 Generic Wind 30 MW 0 Geothermal - Generic 2 Mombasa - Gas/LNG steam 2 Mombasa - Coal steam 2 Mchuchuma - Coal steam 10 GT 60 MW gas - generic x 4 units 5 CC gas x 3 units 5 Kivu methane engines 30 MW x 4 units 8 Notes: The score of a project depends on the basin in which it is located and is evaluated on the basin's biological diversity, number of endemic, species and the presence of threatened species and biodiversity hotspots such as the Eastern Afromontane and Coastal Forests of Eastern Africa. Projects in the Laka Nyasa/Malawi basin: 10 Projects in the Lake Tanganyika basin: 8 Projects in the Rufiji River Basin: 5 Projects in the Lake Victoria and Victoria Nile basins: 4 Projects in the Tana River Basin: 2 Projects in other areas without significant biodiversity value: 0 SSEA III - Final Report J-43 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.6 Use of Local Resources Options Rate of use of local sources of energy Score Bujagali Renewable 0 Kabu 16 Renewable 0 Kakono Renewable 0 Karuma Renewable 0 Masigira Renewable 0 Mpanga Renewable 0 Mutonga Renewable 0 Ruhudji Renewable 0 Rumakali Renewable 0 Rusumo Falls Renewable 0 Ruzizi III Renewable 0 Songwe Renewable 0 Upper Kihansi (storage) Renewable 0 Generic Wind 30 MW Renewable 0 Geothermal - Generic Partially renewable, local 3 Mombasa - Gas/LNG steam Non-renewable, imported 9 Mombasa - Coal steam Non-renewable, imported 9 Mchuchuma - Coal steam Non-renewable, local 7 GT 60 MW gas - generic Non-renewable, imported 9 x 4 units CC gas x 3 units Non-renewable, imported 9 Kivu methane engines 30 MW Partially renewable, local 3 x 4 units Notes: Best = 0; Worst = 10 Hydro and Wind: local and renewable -score = 0 Geothermal: local and mostly renewable - score = 3 Lake Kivu methane: local and mostly renewable - score -= 3 Mchuchuma: local BUT not renewable - score = 7 Imported coal, gas and LNG - score = 9 SSEA III - Final Report J-44 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.7 Risk of Sedimentation Options Location of plant Score Bujagali Victoria Nile 1 Kabu 16 2 Kakono Kagera River 2 Karuma Victoria Nile 1 Masigira 2 Mpanga 2 Mutonga 4 Ruhudji 2 Rumakali 2 Rusumo Falls Kagera River 2 Ruzizi III Ruzizi 2 Songwe 2 Upper Kihansi (storage) 2 Generic Wind 30 MW Wind 0 Geothermal - Generic Thermal 0 Mombasa - Gas/LNG steam Thermal 0 Mombasa - Coal steam Thermal 0 Mchuchuma - Coal steam Thermal 0 GT 60 MW gas - generic x 4 Thermal 0 units CC gas x 3 units Thermal 0 Kivu methane engines 30 MW Thermal 0 x 4 units Notes: Best = 0; Worst = 10 Thermal plants by definition have no sedimentation; accorded a score of 0 Kagera River known to carry very little sediment: Options score: 2 Sediment load less than 100 grams/cubic metre Rivers with heavy sedimentation can exceed 1000 gr/cu.m. Victoria Nile has very little sedimentation; accorded a score of 1 Other rivers have unknown sediment loads; assumed same as the Kagera River SSEA III - Final Report J-45 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.8 Gestation Period in Delivering Benefits Minimum lead time before the project can be commissioned, including Options time for further Score investigations, decisions, design, tendering and construction Bujagali 2012 3.85 Kabu 16 2012 3.85 Kakono 2012 3.85 Karuma 2014 5.38 Masigira 2013 4.62 Mpanga 2014 5.38 Mutonga 2013 4.62 Ruhudji 2014 5.38 Rumakali 2016 6.92 Rusumo Falls 2012 3.85 Ruzizi III 2014 5.38 Songwe 2015 6.15 Upper Kihansi (storage) 2013 4.62 Generic Wind 30 MW 2008 0.77 Geothermal - Generic 2012 3.85 Mombasa - Gas/LNG steam 2015 6.15 Mombasa - Coal steam 2012 3.85 Mchuchuma - Coal steam 2012 3.85 GT 60 MW gas - generic x 4 units 2008 0.77 CC gas x 3 units 2008 0.77 Kivu methane engines 30 MW x 4 units 2007 0.00 Notes: Best = 0; Worst = 10 Best set for 2007; worst for 2020 Remainder pro-rated SSEA III - Final Report J-46 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.9 Hydrological Risk Options Location of plant Score Bujagali Victoria Nile 4 Kabu 16 3 Kakono Kagera River 2 Karuma Victoria Nile 4 Masigira 3 Mpanga 3 Mutonga 3 Ruhudji 3 Rumakali 3 Rusumo Falls Kagera River 2 Ruzizi III 3 Songwe 3 Upper Kihansi (storage) 3 Generic Wind 30 MW Wind 0 Geothermal - Generic Thermal 0 Mombasa - Gas/LNG steam Thermal 0 Mombasa - Coal steam Thermal 0 Mchuchuma - Coal steam Thermal 0 GT 60 MW gas - generic x 4 units Thermal 0 CC gas x 3 units Thermal 0 Kivu methane engines 30 MW Thermal 0 x 4 units Notes: Best = 0; Worst = 10 Thermal plants by definition have no hydrologic risk; accorded a score of 0 Some uncertainty on Victoria Nile flows; accorded a score of 4 Less uncertainty on Kagera River flows: Options score a 2 Hydrology of other rivers unknown; accorded a 3 SSEA III - Final Report J-47 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.10 Financial Risk Options Location of plant Country Risk Score (Euromarket Review) Score Bujagali Uganda 35.94 6.41 Kabu 16 Burundi 27.16 7.28 Kakono Tanzania W. 37.15 6.29 Karuma Uganda 35.94 6.41 Masigira Tanzania 37.15 6.29 Mpanga Tanzania 37.15 6.29 Mutonga Kenya 38.01 6.20 Ruhudji Tanzania 37.15 6.29 Rumakali Tanzania 37.15 6.29 Rusumo Falls Tanzania W-Rwanda 32.58 6.74 Ruzizi III Rwanda-DRC 19.60 8.04 Songwe Tanz/Malawi 37.15 6.29 Upper Kihansi (storage) Tanzania 37.15 6.29 Generic Wind 30 MW Kenya 38.01 6.20 Geothermal - Generic Kenya 38.01 6.20 Mombasa - Gas/LNG steam Kenya 38.01 6.20 Mombasa - Coal steam Kenya 38.01 6.20 Mchuchuma - Coal steam Tanzania 37.15 6.29 GT 60 MW gas - generic Tanzania 37.15 6.29 x 4 units CC gas x 3 units Tanzania 37.15 6.29 Kivu methane engines 30 Rwanda/DRC 19.60 8.04 MW x 4 units Notes: Best = 0; Worst = 10 Euromarket country risk scores vary from 0% (worst) to 100% (best) Scores used for each option calculated as follows: Score = 10 X (1 - Country Risk/100) Options affecting two countries given a country risk score equal to the average SSEA III - Final Report J-48 017334-001-00 APPENDIX J - COMPARATIVE ANALYSIS OF OPTIONS J.5.11 Ranking of Power Options on the Basis of Risks Scores for Each Criterion Options Final R1 R2 R3 R4 R5 R6 R7 R8 R9 R10 Score Weighting 10% 10% 10% 10% 10% 10% 10% 10% 10% 10% Bujagali 5.0 0.0 3.0 3.0 4.0 0.0 1.0 3.8 4.0 6.4 3.0 Kabu 16 3.0 0.0 1.0 3.0 8.0 0.0 2.0 3.8 3.0 7.3 3.1 Kakono 9.0 0.0 5.0 3.0 4.0 0.0 2.0 3.8 2.0 6.3 3.5 Karuma 3.0 0.0 3.0 0.0 4.0 0.0 1.0 5.4 4.0 6.4 2.7 Masigira 3.0 0.0 1.0 3.0 10.0 0.0 2.0 4.6 3.0 6.3 3.3 Mpanga 5.0 0.0 1.0 3.0 5.0 0.0 2.0 5.4 3.0 6.3 3.1 Mutonga 5.0 0.0 1.0 5.0 2.0 0.0 4.0 4.6 3.0 6.2 3.1 Ruhudji 7.0 0.0 3.0 3.0 5.0 0.0 2.0 5.4 3.0 6.3 3.5 Rumakali 5.0 0.0 3.0 3.0 10.0 0.0 2.0 6.9 3.0 6.3 3.9 Rusumo Falls 9.0 3.0 5.0 5.0 4.0 0.0 2.0 3.8 2.0 6.7 4.1 Ruzizi III 3.0 5.0 1.0 3.0 8.0 0.0 2.0 5.4 3.0 8.0 3.8 Songwe 9.0 3.0 5.0 3.0 10.0 0.0 2.0 6.2 3.0 6.3 4.7 Upper Kihansi (storage) 3.0 0.0 1.0 5.0 5.0 0.0 2.0 4.6 3.0 6.3 3.0 Generic Wind 30 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.8 0.0 6.2 0.7 Geothermal - Generic 0.0 0.0 1.0 0.0 2.0 3.0 0.0 3.8 0.0 6.2 1.6 Mombasa - Gas/LNG steam 0.0 0.0 1.0 0.0 2.0 9.0 0.0 6.2 0.0 6.2 2.4 Mombasa - Coal steam 5.0 0.0 5.0 0.0 2.0 9.0 0.0 3.8 0.0 6.2 3.1 Mchuchuma - Coal steam 7.0 0.0 5.0 0.0 10.0 7.0 0.0 3.8 0.0 6.3 3.9 GT 60 MW gas - generic x 4 units 0.0 0.0 1.0 0.0 5.0 9.0 0.0 0.8 0.0 6.3 2.2 CC gas x 3 units 0.0 0.0 1.0 0.0 5.0 9.0 0.0 0.8 0.0 6.3 2.2 Kivu methane engines 30 MW x 4 units 0.0 5.0 1.0 0.0 8.0 3.0 0.0 0.0 0.0 8.0 2.5 SSEA III - Final Report J-49 017334-001-00 APPENDIX K CLIMATE CHANGE AND IMPACTS ON RUNOFF SSEA III - Final Report 017334-001-00 Appendix K - Climate Change and Impacts of Runoff TABLE OF CONTENTS PAGE 1 INTRODUCTION 1 2 TERMS OF REFERENCE AND SCOPE 2 3 GENERAL CONSIDERATIONS 3 3.1 Hydro Generation Capability ­ Basic Data 3 3.2 Context of Assessment of Potential Climate Change Impacts 3 4 METHODOLOGY OUTLINE 7 4.1 Time frame and Emission Scenarios 7 4.2 Climate Change Analysis 7 4.3 Evaporation and Runoff Analysis 8 5 PREDICTED CLIMATE CHANGE SCENARIOS FOR THE NILE EQUATORIAL LAKES REGION 9 5.1 Method 9 5.2 GCM Selection 10 5.3 Scenarios 13 5.4 Results 13 6 POTENTIAL CLIMATE CHANGE IMPACTS ON RUNOFF 18 6.1 Introduction 18 6.2 Methodology and Model Description 18 6.3 Data Requirements 21 6.3.1 Geographical Data 21 6.3.2 Climate Data 21 6.3.3 Physiological Data 21 6.3.4 Model Calibration Data 21 6.4 Modeling Runoff 22 6.5 Model Calibration 23 6.6 Runoff Simulation 26 6.7 Climate Change Runoff Modeling Approach 26 6.8 Runoff Sensitivity Analysis 27 6.9 Climate Change Runoff Results - Annual Results for all Scenarios 31 6.10 Monthly Results for Model Average Scenarios 38 6.11 Climate Change Impact on Regional Reservoir Storage Yield 40 6.12 Summary 45 7 POTENTIAL IMPACT ON RUNOFF AND GENERATION CAPABILITY 47 7.1 General conclusions 47 7.2 Specific Results 48 7.3 Supplementary Analyses 48 7.4 Risk Analyses 49 SSEA III - Final Report K-i 017334-001-00 Appendix K - Climate Change and Impacts of Runoff TABLES 3.1 New hydro options in the indicative plan 3.2 Mid-long term indicative plan on-power dates 5.1 Error analysis for 16 GCMs in MAGICC/SCENGEN for grid area 5.2 Comparison of model average simulation of current climate 5.3 Projections for Uganda and Rwanda for the A1B scenarios 5.4 Projections for Uganda and Rwanda for model average the A1FI scenarios 5.5 Projections for Tanzania for the A1B scenarios 5.6 Projections for Tanzania for model average for the A1FI scenarios 6.1 Precipitation sensitivity analysis summary 6.2 Temperature sensitivity analysis summary 6.3 Annual absolute results 6.4 Annual relative results 7.1 Impact of climate change on runoff FIGURES 3.1 NEL Region - Options in plan and hydrologic areas of interest 5.1 Study areas (black boxes) and SCENGEN grid boxes (blue boxes) 6.1 Simplified version of the WATBAL model that is used to compute gridded runoff 6.2 Ratio of actual to potential evapotranspiration as the relative depth (z) declines (i.e., the catchment gets drier) 6.3 Mean annual runoff gridded at 0.5o latitude/longitude resolution (from University of New Hampshire) 6.4 WATBAL modeling regions 6.5a Kyoga Region WATBAL calibration summary 6.5b Tanganyika Region WATBAL calibration summary 6.5c Nyasa Region WATBAL calibration summary 6.6a Kyoga region precipitation sensitivity analysis 6.6b Kyoga region temperature sensitivity analysis 6.7a Tanganyika region precipitation sensitivity analysis summary 6.7b Tanganyika region temperature sensitivity analysis 6.8a Nyasa region precipitation sensitivity analysis summary 6.8b Nyasa region temperature sensitivity analysis 6.9a Kyoga region annual precipitation for climate change scenarios 6.9b Tanganyika region annual precipitation for climate change scenarios 6.9c Nyasa region annual precipitation for climate change scenario 6.10a Kyoga region annual PET for climate change scenario 6.10b Tanganyika region annual PET for climate change scenario 6.10c Nyasa region annual PET for climate change scenario 6.11a Kyoga region annual runoff for climate change scenarios 6.11b Tanganyika region annual runoff for climate change scenarios 6.11c Nyasa region annual runoff for climate change scenarios 6.12a Kyoga region monthly runoff results 6.12b Tanganyika region monthly runoff results 6.12c Nyasa region monthly runoff results 6.13 Typical shape of the storage-yield curve for Lake Nasser 6.14a 2050 Kyoga region storage-yield curves 6.14b 2100 Kyoga region storage-yield curves 6.15a 2050 Tanganyika region storage-yield curves 6.15b 2100 Tanganyika region storage-yield curves 6.16 2050 Nyasa region storage-yield curves 6.16b 2100 Nyasa region storage-yield curves SSEA III ­ Final Report K-i 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 1 INTRODUCTION The supplemental analyses that are being added to the SSEA study1 include an assessment of the potential impacts on hydroelectric generation that could result from climate change, and consequently whether any such impacts could affect the selection and scheduling of new power options in the portfolios being evaluated in the SSEA study. The objective is not to define whether global warming will take place, but rather to use the results of existing analyses and predictions in a risk analysis to define whether the selection and timing of new power options in the preferred portfolios would be affected if any such plausible changes from climate change were to be accepted for planning purposes. The overall climate change risk assessment covers: · Selection of climate change predictions; · Estimates of corresponding runoff changes; · Evaluation of potential impacts on generation estimates for new hydro power options; · Verification of the make up and comparison of alternative portfolios of new power options. This appendix covers the first three items only. 1Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in the Nile Equatorial Lakes Region, Stage II report, November 2005 ­ SNC-Lavalin Inc. SSEA III ­ Final Report K-1 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 2 TERMS OF REFERENCE AND SCOPE The terms of reference for this supplemental climate change component specified the following four steps that should be undertaken: · An overall scientific, technical and socio- economic assessment of key climate change models with a focus on information relevant for the understanding of climate change, its potential impacts and options for adaptation and mitigation in the NELSAP region2. Deficiencies in current key models (poor performance at spatial and temporal resolutions applicable to regional NELSAP water cycle) should be discussed; · Draw conclusions on possible impacts of climate change focusing on the impacts to blue and green water in the NELSAP region; · Apply the findings on climate change to the cumulative impacts work so that conclusions can be drawn on potential impacts of climate change and possible mitigation measures on the base case scenario; · The information should be adapted to the other strategies in the NELSAP Indicative Power Master Plan. The terms of reference and work steps therefore require two items as inputs to assessing potential impacts of climate change on future hydro generation: · An assessment of key climate change models; · Conclusions on possible impacts of climate change on net water yield (runoff) in the NELSAP region, and thus is concentrated on the new hydro options included in the preferred portfolios. The primary need is to define plausible forecast impacts on rainfall, temperature, from which evaporation changes and impact on net water yield (river flows) may be estimated. The output from the review of models and their forecasts focussed on the following three tasks: · Based on a range of current models, indicate which forecasts of temperature and precipitation changes are most plausible for the region; · Propose a range of potential average precipitation, temperature and evaporation changes from a historic average that, based on a range of world economic development scenarios, should be considered in evaluating hydroelectric generation in the future (say in years 2050 and 2100); · Propose corresponding adjustments to historic runoff averages, as a basis for proposing potential changes to hydro plant generation capabilities. 2In this context NELSAP includes eight 8 countries (Burundi, DRC, Kenya, Rwanda, Tanzania, Uganda and Egypt and Sudan). For DRC the focus should be on Eastern DRC. The White Nile basin system and downstream impacts in Sudan and Egypt should be assessed, including cumulative impacts in the upper Congo basin and other in-country and inter-country basins in the region. Cumulative impacts may also be beyond the basin. SSEA III ­ Final Report K-2 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 3 GENERAL CONSIDERATIONS The overall SSEA study has sought to identify and evaluate new power options for the region, and to develop a new generation portfolio for each of a series of three development strategies, each with its core concept, with the objective of linking costs with levels of acceptability. The basis for these strategies was described in Section 10 of the November 2005 report. A. Strategy 1 ­ Maximize the Use of Best-Evaluated Options B. Strategy 2 ­ Technological Diversification C. Strategy 3 ­ Geographical Diversification 3.1 Hydro Generation Capability ­ Basic Data The identification and evaluation of the generation capability of new hydroelectric power options has been based on previous studies, as is described in Section 5 of the November 2005 report. Information on probable capital costs, implementation lead times, environmental and social aspects was upgraded as part of the current study. However the comparison of generation costs, that is one of the key factors in ranking alternatives, was heavily dependant on the existing individual project generation estimates that were developed in previous studies. In practice the overall objective is to determine whether consideration of potential climate change impacts would have an impact on the comparison of the portfolios that have been developed for each of the selected strategies. Clearly, for example, a portfolio that is more dependant on use of hydroelectric renewable energy, would potentially be more at risk from significant reduction in river flows, than a thermal power dominated portfolio. 3.2 Context of Assessment of Potential Climate Change Impacts The first point that has to be appreciated is that that the purpose of conventional generation planning is to identify the best project or projects for immediate development, and those for which priority should be assigned to complete project preparation work, so that these will be available for the next round of comparisons and approvals. The longer term plant scheduling in any plan is only indicative, for use by energy planners. The same philosophy also applies to the portfolios that have been developed in this SSEA study. This means that the concern over changes in hydro project performance due to changes in runoff has to be viewed in the context of short or mid term recommended projects only. The long term aspect would only come into focus if a short term and long term project in a single portfolio were mutually dependant (e.g. where an upstream storage project forms part of a cascade). However even in such a scenario, a decision on a short term project is never dependant on later downstream development (although the benefits from the upstream project will increase with downstream development). Consequently the focus of the assessment of potential climate change on river flows has to relate to recommendations on short and mid term projects. The preferred indicative plan in the November 2005 report included the following hydroelectric sites: SSEA III ­ Final Report K-3 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Table 3.1 - New Hydro Options in the Indicative Plan Year Project River Country MW 2012 Bujagali 1-4 Nile Uganda 200 Rusumo Falls Kagera Burundi/Rwanda/Tanzania 62 2013 Kabu 16 Kaburantwa Burundi 20 2014 Bujagali 5 Nile Uganda 50 Ruzizi III Ruzizi Rwanda/DRC 82 2015 Ruhudji Ruhudji Tanzania 358 2017 Karuma Nile Uganda 200 2020 Rumakali Rumakai Tanzania 222 The basic indicative plan or portfolio, developed without consideration of potential climate impacts, is shown in Table 11-2 of the November 2005 report, which is repeated overleaf. This table is followed by a map of the area that indicates the immediate hydrologic areas of interest for the above projects. (Note these areas cover sites of the above projects, and not their river basins). SSEA III ­ Final Report K-4 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Table 3.2 - Mid-Long Term Indicative Plan On-power Dates Capacity Year Addition (on Power) Country Addition (MW) 2011 GT Tanzania 60 Lake Kivu Gas (30 MW) No.3 R/DRC 30 2012 Bujagali 1-4 Uganda 200 Rusumo Falls (Full) B/R/T 61.5 2013 GT Tanzania 60 Suswa geothermal Kenya 70 Kabu 16 Burundi 20 2014 Bujagali 5 Uganda 50 GT (oil) Kenya 60 Ruzizi III R/DRC 82 2015 Ruhudji Tanzania 358 2016 Menengai geothermal Kenya 140 2017 Karuma Uganda 200 Lake Kivu Gas (30 MW) No.4 R/DRC 30 Non-specified geothermal Kenya 140 2018 Wind (2 plants) Kenya 60 Mombasa 1 Kenya 150 2019 Mombasa 2 Kenya 150 2020 Rumakali Tanzania 222 Mchuchuma coal steam (1-2) Tanzania 200 Mombasa 3 Kenya 150 B/R/T Burundi + Rwanda + Tanzania / SSEA 1 region R/DRC Rwanda + Democratic Republic of the Congo Ruzizi III could be developed by Rwanda, DRC and Burundi SSEA III ­ Final Report K-5 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 3.1 - NEL Region - Options in Plan and Hydrologic Areas of Interest North: Bujagali Karuma West Central: Resumo Ruzizi III Kabu 16 South: Ruhudji Rumakali SSEA III ­ Final Report K-6 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 4 METHODOLOGY OUTLINE The approach taken in the climate change analysis consists of two parts ­ climate change analysis to propose potential values for temperature and precipitation change, and runoff analysis to provide corresponding estimates of changes in net water yield or runoff. This work was undertaken by the Stratus Consulting team of Joel Smith and Prof. Kenneth Strzepel (University of Colorado). The methodology for these two components is outlined as follows, and given in more detail in sections 5 and 6. 4.1 Time frame and Emission Scenarios The proposed time frame of the assessment is from 2000, i.e. current conditions, as represented by the 100 year climate data base referred to in Section 4.3, to 2100 (beyond the economic life of existing and planned projects). Predictions for temperature, precipitation, and consequent runoff changes were made for the years 2050 and 2100. Models generally link potential temperature change (and thus precipitation and evaporation change) to anthropogenic (CO2) emissions. The IPCC have proposed a number of economic development scenarios, with corresponding emission levels, which have been used as the basis for climate change predictions34. Global values are as follows: Economic change 1990 Cumulative Name to 2100 from GNP Population by emissions between increase Trillion US$ 2100 (million) 1990 and 2100 CO2 (Gt/C) A1F1 505 7140 2190 A2 225 15070 1860 A1B 510 7060 1500 B2 215 10410 1160 B1 310 7050 980 Source ­ see footnote 1 As is noted below the A1B and A1FI scenarios were used to provide upper (emissions forecast) and medium values5. 4.2 Climate Change Analysis The goal of the climate change analysis was to use the best available general circulation model output to assess the potential changes in temperature and precipitation in 2050 and 2100 relative to 2000 in the selected sites in East Africa. Outputs from various climate models were examined to determine the degree to which models agree or disagree on the 3Hadley Centre ­ Climate change, observations and predictions, recent research of climate change science from the Hadley Centre, December 2003 4IPCC Special Report on Emission Scenarios 5It is noted that for 2100 the CO2 concentrations for A1B and A1F1 would be 700 and 940 ppm respectively. The selection of A1B and A1F1 was arbitrary, however the use of A1B as a median prediction seems to be general practice. A1F1 was selected as the high case, because it provided the highest predicted values of cumulative emissions. A2 would have provided results somewhere between A1B and A1F1. As noted previously the objective was to do a risk analysis, hence selection of a median and the maximum impact scenario. A2 may have a higher probability of occurrence, however use of its lower emission value would not have added to the "robustness" of the risk analysis. SSEA III ­ Final Report K-7 017334-003-00 Appendix K - Climate Change and Impacts of Runoff sign (increase or decrease) and magnitude of change in temperature and precipitation in the region. The study used the NCAR6 model MAGICC/SCENGEN7, which readily enables users to specify greenhouse gas emissions scenarios and climate sensitivities, and to evaluate how well models simulate current patterns of climate, to select specific models, and determine degree of model agreement or disagreement on regional climate change projections. The NCAR model is loaded with simulations from some 16 global models (General circulation models), and thus can be used to determine which models best simulate the climate of East Africa, by assessing how well they matched the observed patterns and values for temperature and precipitation. From this analysis the models that best simulate East African climate were selected. The baseline climate data for the model was the 100 year monthly climate database, TS 2.1, produced by the Climate Research Unit of the University of East Anglia, United Kingdom. The historic sequence from 1961-1990 was used to establish baselines. The model projections of changes in temperature and precipitation for 2050 and 2100 relative to 2000 were examined and the A1B and A1FI scenarios were be used 8910. A1B is one of the suite of scenarios developed by the IPCC and projects a CO2 concentration of 700 ppm by 2100. A1FI has the highest greenhouse gas emissions and projects a CO2 concentration of about 940 ppm by 2100. A double CO2 sensitivity of 3oC was assumed. (This is how much global mean temperature would increase with a doubling of CO2 concentrations in the atmosphere). One estimate of climate was developed for the two most northern sites (see previous figure), i.e. the Nile river at Bujagali and Karuma and the Ruzizi and Kagera rivers for the Rusumo, Ruzizi and Kabu projects. A separate estimate of climate change was made for the southern site grouping in Tanzania, i.e., for the Ruhudji and Rumakali rivers. 4.3 Evaporation and Runoff Analysis The regional 1-D (one dimensional) monthly water balance model (WATBAL), developed for a ½ degree by ½ degree grid of Africa, was used to calculate potential evapotranspiration, actual evapotranspiration, runoff and relative soil moisture. The model was calibrated at the ½ degree level against the GRDC11 Global Gridded Runoff Database. 6 NCAR - US National Center for Atmospheric Research 7 Wigley, T. M. L. 2004. "MAGICC/SCENGEN." Boulder, Colorado: National Center for Atmospheric Research. http://www.cgd.ucar.edu/cas/wigley/magicc/ 8 For definitions and further information on the IPCC scenarios see web site www.grida.no/climate/ipcc/emission 9 See also Nebojsa Nakicenovic et al, Special Report on Emission Scenarios, Cambridge University Press, 2000, and IPCC web site 10See also Met Office Hadley Centre, Recent research on climate change science from the Hadley Centre, December 2003 11Global Runoff Data Centre - the digital world-wide repository of discharge data - www.bafg.de/grdc.htm SSEA III ­ Final Report K-8 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 5 PREDICTED CLIMATE CHANGE SCENARIOS FOR THE NILE EQUATORIAL LAKES REGION Given the current rates of greenhouse gas (GHG) emissions, global climate is expected to continue to change and global temperatures are projected to continue rising. This will affect climates around the world. However, changes in climate, particularly at the regional and local scale, are uncertain. In examining the Nile Equatorial Lakes region, it is known that climate will change, but there are many uncertainties as to exactly how. Temperatures will likely rise, but how much is uncertain. Change in precipitation may also be uncertain. Therefore, a number of general circulation models (GCMs) specifically focused on the Nile Equatorial Lakes region were examined to estimate potential changes in temperature and precipitation in these regions. 5.1 Method The MAGICC/SCENGEN (Wigley and Raper, 2002; Wigley, 2004) tool was used to examine changes in temperature and precipitation in 2050 and 2100 relative to 2000 using GCMs. MAGICC is a one-dimensional model that estimates green house gas (GHG) concentrations and increases in global mean temperature (GMT) and sea level. MAGICC allows users to select: · GHG emissions scenarios; · Climate sensitivity (including parameters for 2CO2 warming, aerosol feedbacks, carbon cycle, thermohaline circulation, and ice melt). SCENGEN uses the regional pattern of relative changes in temperature and precipitation across 16 GCMs. The changes are expressed relative to the increase in GMT by the model.12 This pattern of relative change is preferable to simply averaging regional GCM outputs because it controls for differences in climate sensitivity across models. Otherwise results from models with a high sensitivity would dominate. SCENGEN allows users to select any combination of the 16 GCM models. SCENGEN uses results from GCMs run for the Intergovernmental Panel on Climate Change (IPCC) Third Assessment Report (TAR; Houghton et al., 2001). These model runs were mostly done in the late 1990s. New GCM runs, done for the Fourth Assessment Report (scheduled to be published in 2007), have not yet been included in SCENGEN. SCENGEN estimates change in average temperatures and precipitation in grid boxes that are 5° across, and roughly 300 miles (~ 500 km) in length and width. In actuality, there is a lot of variation within the grid boxes, because of differences in topography within the grid. Temperatures are typically lower at higher altitudes, whereas precipitation amounts can differ, depending on altitude and whether a location is on the windward or leeward side of a precipitation event. SCENGEN does not capture those climatic differences within grid boxes. The analysis assumes that change across the region studied is uniform. This is a simple and most likely an inaccurate assumption. Nonetheless, it is still useful to examine GCM output to understand the sensitivity of key systems and how climate may change.13 12 . This is referred to as normalizing GCM results and involves determining the relative change in regional climate per change in GMT, e.g., per 1°C increase in GMT. A normalized temperature change would be expressed as TRGCM/TGMTGCM where TRGCM is the regional change in temperature from a GCM. TGMTGCM is the global- mean temperature change in the same GCM. 13 . Another approach that is beyond the scope of this project is to "downscale" from GCMs. This can involve applying statistical techniques or high level regional models. In general, these approaches provide more site specific information and can better account for regional features that will have an important affect on regional SSEA III ­ Final Report K-9 017334-003-00 Appendix K - Climate Change and Impacts of Runoff To capture the potential change in climate in the three locations being studied, the MAGICC/SCENGEN output was examined for two areas (displayed in Figure 1): · 5°N to 5°S by 25°E to 35°E; · 5°S to 15°S by 30°E to 40°E. The northern SCENGEN area captures changes in Rwanda and Uganda. The southern SCENGEN area captures changes in mid- and southern Tanzania. 5.2 GCM Selection It is possible to use output from all 16 GCMs included in SCENGEN to examine how climate in the Nile Equatorial Lakes region may change. Unfortunately, the 16 models are not all equal in their ability to simulate current climate. A model's ability to accurately simulate current climate is a test of its reliability in simulating the response of the climate system to increased GHG concentrations (Smith and Hulme, 1998). Therefore, a model's ability to simulate current climate better than other models is a measure of the model's relative reliability. The performance of model simulations of current precipitation patterns in the Nile Equatorial Lakes Region (an area from 5°N to 15°S by 20°E to 40°E) was examined. The results are shown in Table 5.1. MODBAR is the result for the average of all models. Correlation is between -1 and 1, with the best scores closest to 1. For the other two measures, the smallest number in absolute value is best. The models highlighted in yellow appear to do the best in simulating current climate. Note that the model average performs better in simulating current climate than any individual GCM. A further test is how well the average of the selected models simulate current climate. Table 5.2 compares the average of all 16 models listed in Table 5.1 with the seven highlighted models. The seven highlighted models have a higher spatial correlation and a much lower error rate than all 16 models, indicating that the seven better simulate current climate. and local climates. However, these approaches are driven by output from GCMs and like all models, have limitations as well. One limitation is that downscaling is expensive and time consuming, and often is only applied to a few GCMs. An advantage of the approach used here is that multiple GCMs are being examined. SSEA III ­ Final Report K-10 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 5.1 - Study Areas (Black Boxes) and SCENGEN Grid Boxes (Blue Boxes) (World Bank regions should read SSEA regions) SSEA III ­ Final Report K-11 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Table 5.1 - Error analysis for 16 GCMs in MAGICC/SCENGEN for grid area COSINE WEIGHTED STATISTICS MODEL SPATIAL CORR. RMSE MEAN DIFF mm/day mm/day BMRCTR .084 1.280 .609 CCC1TR -.392 1.786 -.992 CCSRTR .791 .673 .373 CERFTR .811 .709 -.476 CSI2TR .904 .671 .278 CSM_TR .967 2.252 -1.386 ECH3TR .707 .641 -.079 ECH4TR .862 .660 -.373 GFDLTR .597 .796 -.331 GISSTR .063 1.197 .043 HAD2TR .895 1.001 -.601 HAD3TR .939 1.052 -.715 IAP_TR .083 1.472 -.864 LMD_TR -.044 2.446 -1.724 MRI_TR .569 3.399 -3.121 PCM_TR .958 1.985 -1.451 MODBAR .925 .757 -.676 Table 5.2 - Comparison of model average simulation of current climate Number of models Spatial Root mean Mean included in average correlation square error difference 16 model average 0.925 0.757 -0.676 7 highlighted model 0.940 0.416 -0.228 average The seven highlighted GCMs that were selected and used are: · CERG ­ The European Centre for Research and Advanced Training in Scientific Computation (CERFACS), France · CCSR ­ National Institute for Environmental Studies, Japan · CSIRO ­ Commonwealth Scientific Industrial and Research Organization, Australia · ECHAM3 ­ Max Planck Institute for Meteorology, Germany · ECHAM4 ­ Max Planck Institute for Meteorology, Germany · HadCM2 ­ Hadley Model, United Kingdom Meteorological Office SSEA III ­ Final Report K-12 017334-003-00 Appendix K - Climate Change and Impacts of Runoff · HadCM3 ­ Hadley Model, United Kingdom Meteorological Office.14 5.3 Scenarios Two GHG emissions scenarios were selected from a family of GHG emission scenarios produced by the IPCC Special Report on Emissions Scenarios (SRES; Nakicenovic and Swart, 2000.) These scenarios yield a wide range of CO2 concentrations by 2100 (above the current level of about 380 ppm): 540 to 960 ppm. The first emissions scenario selected, which is called "A1B," assumes a world with rapid economic growth and a mix of high carbon and low carbon emitting technologies. It results in CO2 concentrations of approximately 700 ppm by 2100. This scenario is roughly in the middle of the range of the SRES scenarios and is considered the main scenario. The second scenario selected is the highest scenario, essentially a bad-case for GHG emissions. It also assumes a rapidly growing economic world with high use of fossil fuels. It is called "A1FI" and results in a CO2 concentration of 960 ppm by 2100. Since it is such a high scenario, it was used mainly to test the sensitivity of results should emissions end up being toward the high end of the projections. A "CO2 sensitivity" was also selected. Specifically, this is an estimate of how much GMTs will change with a doubling of CO2 concentrations in the atmosphere. Essentially, it is used to indicate the degree to which the Earth's climate will respond to increased GHG concentrations. In a survey of scientific views on CO2 sensitivity, Kerr (2004) concluded that the most likely sensitivity is 3°C, but it could be as low as 2°C or as high as 5°C or even greater. This study used a sensitivity of 3°C. The results would be correspondingly lower or higher had a lower or higher sensitivity had been used. 5.4 Results Uganda and Rwanda The projections from MAGICC/SCENGEN for the A1B scenario for the Rwanda and Uganda project areas are presented in Table 5.3. On average, the models project increased temperature, with some variation across the wet and dry models. Note however, that the wettest and driest models were selected, not the hottest and coolest. The difference between the model with the most warming (ECHAM3) and the model with the least warming (CERF) is less than 30%. 14 . See McAveney et al. (2001) for model descriptions and citations. SSEA III ­ Final Report K-13 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Table 5.3 - Projections for Uganda and Rwanda for the A1B scenarios assuming a 2CO2 sensitivity of 3°C Area covered is 5°N to 5°S by 25°E to 35°E. Changes are relative to the year 2000. Wet Dry CCS (Japan) Model average ECH3 (German) Temperature Precipitation Temperature Precipitation Temperature Precipitation (°C) (%) (°C) (%) (°C) (%) 2050 projections using the A1B scenario DJF 0.8 85.5 1.4 16.6 1.3 4.5 MMA 1.8 4.8 1.7 8.3 2.1 10.8 JJA 2.5 -13.6 2.0 16.3 2.4 147.8 SON 1.8 -0.9 1.6 3.7 1.7 1.6 Annual 1.7 14.2 1.7 7.4 1.9 4.3 2100 projections using the A1B scenario DJF 1.6 212.0 2.5 28.0 2.4 4.8 MMA 3.3 10.0 3.1 16.4 3.6 21.7 JJA 4.3 -10.4 3.5 41.3 4.1 518.3 SON 3.1 1.0 2.8 8.5 3.0 4.8 Annual 3.0 27.3 3.0 13.8 3.3 8.3 The precipitation results present an interesting pattern.15 On average, the models project an increase in precipitation, both annually and for each season. The largest percentage increase is projected for the dry months of June through August. Since there is little precipitation in those months, even a large increase will have a relatively small absolute effect on precipitation. It is interesting that wettest and driest models project an increase in precipitation. The range on an annual basis is 4-14% by 2050, and much larger by 2100. It is also interesting that on average, the models project increased precipitation for each three- month period. Surprisingly, the wettest annual model, CCS, projects decreased precipitation in two of the three-month periods in 2050. This indicates there is less agreement among the models about seasonal changes than annual changes in precipitation. MAGICC/SCENGEN calculates a "signal to noise" (SNR) ratio on precipitation. It is the average change across models divided by the inter-model standard deviation and indicates whether models are in agreement about whether temperature or precipitation will increase. If it is greater than 1, it means the average projection of change by the models is greater than the difference across models. The SNR for temperature in the region is well above 1, because all the models show significant warming, with little difference among them. In most parts of the world, models typically do not show the same sign of change in precipitation. Often, some models project an increase and some a decrease. The SNR ratio is often well below 1. In this region, the SNR on precipitation is 1.6, indicating a high level of model agreement. This region straddles the equator, where an increase in the hydrologic cycle as a result of higher temperatures may well result in increased precipitation. Table 5.4 shows the average model projections for the A1FI scenario.16 The temperature increase in 2050 is almost the same as in the A1B scenario, but the A1FI scenario projects a 15. Annual precipitation in the sites being studied is about 1,300 mm/year. 16. Individual model results for A1FI are not displayed for this area and in Tanzania, because some of the precipitation estimates appear to be quite large. We only have confidence in the average model results. SSEA III ­ Final Report K-14 017334-003-00 Appendix K - Climate Change and Impacts of Runoff much larger increase in precipitation. By 2100, under the A1FI scenario, there is substantially more warming and precipitation than in the A1B scenario. The dry and wet models under the A1FI scenario range from an annual increase of 11-23% by 2050 to 15- 50% by 2100. There is very little difference in the temperature projections across the models for each time period and emissions scenario (but as with A1B, with more time and higher emissions, temperatures are projected to rise more). So, whereas there can be substantial differences across individual GCMs on precipitation projections, temperature projections vary less. The major factors affecting the amount of temperature increase are emissions scenarios and climate sensitivity. Table 5.4 - Projections for Uganda and Rwanda for model average the A1FI scenarios assuming a 2CO2 sensitivity of 3°C Area covered is 5°N to 5°S by 25°E to 35°E. Changes are relative to the year 2000 Model average Temperature Precipitation (°C) (%) Model average projections in 2050 under the A1FI scenario DJF 1.3 28.4 MAM 1.9 14.1 JJA 2.4 17.5 SON 1.7 11.5 Annual 1.8 17.5 Model average projections in 2100 under the A1FI scenario DJF 4.1 52.7 MAM 4.9 28.4 JJA 5.8 83.1 SON 4.5 14.6 Annual 4.8 24.0 SSEA III ­ Final Report K-15 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Tanzania The projections from MAGICC/SCENGEN for the A1B scenario for The southern Tanzania project areas are shown in Table 5.5. Table 5.5 - Projections for Tanzania for the A1B Scenarios Assuming a 2CO2 Sensitivity of 3°C Area covered is 5°S to 15°S by 30°E to 40°E. Changes are relative to the year 2000. Wet Dry CSI2D2 Model average CCSRD2 Temperature Precipitation Temperature Precipitation Temperature Precipitation (°C) (%) (°C) (%) (°C) (%) 2050 projections using the A1B scenario DJF 0.9 25.7 1.7 5.5 3.3 -27.2 MMA 0.9 19.7 1.9 1.4 3.1 -17.1 JJA 1.2 5.3 2.1 -9.7 2.0 2.3 SON 1.1 37.5 1.8 -4.8 1.5 -29.6 Annual 1.0 23.3 1.8 2.2 2.5 -25.4 2100 projections using the A1B scenario DJF 2.8 47.0 3.0 8.1 5.8 -43.4 MMA 3.0 36.6 3.4 2.2 5.5 -27.6 JJA 3.3 12.7 3.7 -15.6 3.6 4.8 SON 4.1 85.7 3.1 -0.4 2.5 -38.7 Annual 1.8 44.0 3.3 3.8 4.3 -39.7 Here too, all the models project an increase in temperature. In this case, the wet and dry models give a wider range of change in temperature because the wettest and driest models in this region are also the coolest (least warming) and warmest (most warming). Interestingly, in this region, while the model average is a small increase in precipitation, the dry model projects a decrease in precipitation. Furthermore, the dry model projects a reduction in precipitation in three of the four three-month periods. Even the model average has a decrease in precipitation from June through November. The SNR on annual precipitation is about 0.9. That indicates there is disagreement across the models, but it is very close to 1. The projections for the model average for A1FI upper emission scenario are shown in Table 5.6. The A1FI scenario projects more warming than A1B, particularly by 2100. Like A1B, the model average shows a slight increase in precipitation. Since MAGICC/SCENGEN uses an extrapolation method to calculate the changes, these results lack credibility. SSEA III ­ Final Report K-16 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Table 5.6 - Projections for Tanzania for Model Average for the A1FI Scenarios Assuming a 2CO2 Sensitivity of 3°C Area covered is 5°S to 15°S by 30°E to 40°E. Changes are relative to the year 2000. Model average Temperature Precipitation (°C) (%) Model average projections in 2050 under the A1FI scenario DJF 1.9 7.6 MAM 2.2 0.0 JJA 2.6 -14.2 SON 2.1 -2.4 Annual 2.2 2.6 Model average projections in 2100 under the A1FI scenario DJF 4.8 14.0 MAM 5.5 3.7 JJA 6.0 -24.0 SON 5.0 -2.6 Annual 5.3 2.6 SSEA III ­ Final Report K-17 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 6 POTENTIAL CLIMATE CHANGE IMPACTS ON RUNOFF 6.1 Introduction Although considerable research efforts are being made, current understanding of the regional impacts, magnitude, and rate of climate change remain uncertain. Nevertheless, it is generally accepted that climate change will, in many places adversely impact farming, fishing, forestry, and many other industries that rely on weather and natural ecosystems. The African continent is particularly susceptible to climate change because it includes some of the world's poorest nations. Furthermore, high spatial and temporal variability in rainfall, as well as high evaporation rates, already place great stress on agricultural systems from which 70% of the continent's population derives its livelihood. One of the most significant impacts of climate change is likely to be on the hydrological system, and hence on river flows and regional water resources. This will be particularly true in arid and semi-arid areas of Africa where water resources are very sensitive to climate variability, particularly rainfall. This section describes the methods and hydrological model used to provide hydrological inputs for use in the analysis of runoff in the Nile Equatorial Lakes Region and implications for water management. The principal objectives were to: · Develop an approach that enables runoff to be derived for the "regions" of interest; · Develop a time series (1961-1990) of runoff for the "regions" that will provide a baseline for climate change scenarios. 6.2 Methodology and Model Description The objective was to apply a hydrological model to three regions of the Nile Equatorial Lakes Region (NELR) rather than to any particular catchment or water resource system. The model inputs were the climate variables of the 1961-1990 climatology and physiological parameters (e.g., soil properties) derived from global datasets and averaged over the 0.5o latitude/longitude cells in the region. The primary model output comprised a time series (monthly time step) of simulated runoff for each of the three NELRs. To address climate change impacts on runoff, hydrological models must characterize the dispersed nature of climate and hydrology over space and time while avoiding excessive complexity. The model used is a version of a conceptual rainfall-runoff model called WATBAL (Yates, 1997), which can be applied to regionally averaged data. The model simulates changes in soil moisture and runoff. It is essentially an accounting scheme based on a conceptualized, one-dimensional bucket that lumps both the root and upper soil layer. The model comprises two elements. The first is a water balance component that describes water movement into and out of a conceptualized basin (Figure 6.1). The second is the calculation of potential evapotranspiration, which, in the gridded version of the model, is computed using the Blaney-Criddle Method. The simplified representation of soil moisture dynamics has been shown to adequately represent runoff changes due to climate fluctuations (Yates and Strzepek, 1994; Yates, 1997). SSEA III ­ Final Report K-18 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.1 - Simplified Version of the WATBAL Model that is Used to Compute Gridded Runoff Evapotranspiration Effective Precipitation Surface runoff Soil moisture zone ­ maximum storage Smax Relative depth (z) Sub- Surface runoff The model parameters, which define the size of water storage in soil and the rate of water removal from it, are derived in part from physical characteristics and in part by calibration. The inputs are monthly rainfall and climatic data required to estimate potential evapotranspiration. Water enters the soil moisture store through precipitation and is removed either by evapotranspiration, surface runoff, or sub-surface runoff. The water balance component of the model comprises three parameters related to (1) surface runoff, (2) sub- surface runoff, and (3) maximum catchment water-holding capacity. The monthly soil moisture balance is written as: dz CSmax =Peff (t)- Rs(z,P,t)- Rss(z,t)- Ev(z,Pet,t) (1) dt where: Peff = effective precipitation (length/time) Rs = surface runoff (length/time) z = relative storage (length) (0 z 1) P = precipitation (length/time) Rss = sub-surface runoff (length/time) Ev = evapotranspiration (length/time) Pet = potential evapotranspiration (length/time) CSmax = maximum catchment storage (length) In WATBAL, the relative importance of water storage on the hydrological regime of a cell is expressed as: CSmax = Smax × AWCmult (2) where: Smax = maximum water holding capacity of the soil (mm) AWCmult = maximum rooting depth (m) SSEA III ­ Final Report K-19 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Smax is expressed as millimeter of water stored per meter depth of soil and is dependent primarily on the type of soils in the cell. AWCmult is dependent on the type of vegetation and hence is primarily a function of land-use within the cell. The storage variable, z, is given as the relative storage state and is a value between 0 and 1. Consequently, when CSmax is multiplied by z, it gives the volume of water stored in the cell at any given time. The Blaney-Criddle Method for potential evapotranspiration was used as the climate change scenarios only provided changes in temperature (FAO, 1992). A non-linear relationship (based on Kaczmarek, 1993) is used to compute actual evapotranspiration from potential evapotranspiration. Ev(z, Pet,t) = Pet 5z - 2z2 (3) 3 As z decreases, the ratio of actual to potential evapotranspiration declines (Figure 6.2). Figure 6.2 - Ratio of Actual to Potential Evapotranspiration as the Relative Depth (z) Declines (i.e., the Catchment Gets Drier) 1.0 0.8 etP/ 0.6 Ev 0.4 0.2 0.0 1.0 0.8 0.6 0.4 0.2 0.0 z (i.e. proportion of Smax) Surface runoff (Rs) is described in terms of the storage state, z, and the effective precipitation, Peff. Epsilon (), a calibration parameter, allows surface runoff to vary non- linearly with storage (Yates 1996). Rs (z, P,t) = z Peff (4) Sub-surface runoff (Rss) is a function of the relative storage state, multiplied by a coefficient . Rss = z2 (5) Total runoff for each time step is the sum of the two runoff components: Rtotal = Rs + Rss (6) More details of the model theory are presented in Yates (1996). SSEA III ­ Final Report K-20 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 6.3 Data Requirements The hydrologic modeling process is highly data intensive. The data types required for this study can be broadly divided into four types: geographical data, climate data for model input, physiological data, and model calibration data. This section describes the data sources and, where necessary, the steps taken to prepare them for use in this study. 6.3.1 Geographical Data The district boundaries for each of the NELRs were digitized into polygons with ARCGIS 9. The polygons were then used to develop average values of model variables over the regions. 6.3.2 Climate Data Average monthly rainfall and temperature were taken from a database provided by the Climate Research Unit (CRU), University of East Anglia, Norwich, UK. These data, provided on a 0.5o grid, represent the World Meteorological Organisation's (WMO's) standard reference "baseline" for climate change impact studies. The climate change scenarios (i.e., plausible descriptions of how things may change in the future) are expressed as anomalies from this baseline (see Section 6.6). 6.3.3 Physiological Data The physiological data required were obtained from a number of geographically referenced datasets. The soil water holding capacity (Smax) was taken from FAO's geonetwork. Values are dependent largely on soil texture. For areas of open water, values are set at 1,000 mm. The original dataset was organized at the 0.08o scale. The data were aggregated (by taking the numeric mean) into 0.5o grid cells. 6.3.4 Model Calibration Data The model was calibrated against simulated average monthly runoff generated on 0.5o grid by the University of New Hampshire (UNH) (see Section 6.5). The mean annual runoff is shown in Figure 6.3. The equivalent data are available for each month of the year. SSEA III ­ Final Report K-21 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.3 - Mean Annual Runoff Gridded at 0.5° Latitude/Longitude Resolution (from University of New Hampshire) Mean annual runoff (mm) 0- 10 11 - 25 26 - 50 51 - 75 76 - 150 151 - 200 201 - 400 401 - 600 601 - 10000 No Data 6.4 Modeling Runoff For this analysis, three areas of interest were identified and are presented in Figure 6.4. The northernmost area is the Uganda project area referred to here as the Kyoga Region, the central area covering the DRC and Rwanda/West Tanzania sites referred to as the Tanganyika Region, and the southern Tanzania area referred to as the Nyasa Region, all being labeled after the equatorial lake nearest to the region17. In the WATBAL modeling, the regions are assumed to homogeneous hydroclimatic regions and all parameters are spatially averaged over the region. While assumption of spatial heterogeneity is warranted on hydrologic grounds, within this study, with such large scale spatial estimations of changes in climate variables, hydrologic spatial homogeneity over the region is recommended because of the climate variable scale. 17The "Tanganyika" region, as shown in Figure 6.4, selected for modeling, was intended to cover the Nyaborongo and Rusumo basins. It isi noted that study was carried out in two parts - the prediction of temperature and precipitation change, using the MAGICC/SCENGEN model, and the subsequent estimate of evaporation losses, and resulting net water yield, using the WATBAL water balance model. The MAGICC model used a large grid area, as is shown in Figure 5.1. The upper 10 x 10 degree area covers both the Victoria Nile and the Rwanda region. The southern area covers the Tanzanian region. The WATBAL model used a smaller grid, with the three separate areas shown in Figure 6.4. The western area was targeted to cover the Ruzizi 3, Kabu 16 and Rusumo projects. The MAGICC model certainly covers these areas, and the WATBAL model may not completely cover the river basins, however is certainly representative. SSEA III ­ Final Report K-22 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Note that for the Kyoga Region, the Nile flow or the flow out of Lake Victoria is not being modeled, rather the study is modeling the tributary flow to the Nile in the region. To model Nile flow requires a complete modeling of the Victoria catchment, its tributaries, and the regulation policies of Owen Falls dam. The author of this runoff impact study has modeled this previously (Yates and Strzepek, 1998; Block and Strzepek, 2006), but this is outside of the scope of the current analysis. Figure 6.4 - WATBAL Modeling Regions 6.5 Model Calibration In WATBAL, hydrological processes are simulated on the basis of a conceptual approximation, as described in Section 6.2. Consequently, it is necessary to adjust or optimize parameters until the model output is an acceptable estimate of the observed runoff regime. In order to do this, it is necessary to have runoff data against which to calibrate parameter values. In this version of the model, three parameters are calibrated. Alpha () has units of mmd-1 and is directly related to soil water storage. Regions with higher runoff coefficients generally have higher values of alpha (i.e., boreal forests and tropical rain forests), while regions with lower runoff coefficients generally have lower values for alpha (i.e., deserts and dry forests). Epsilon () is unitless and defines the functional form of surface runoff, which depends on the magnitude of the precipitation event and the relative storage (see Equation 4). Smaller values of epsilon represent an increase in the contribution of surface runoff; therefore, smaller epsilons are generally associated with smaller soil moisture capacities and greater surface runoff (e.g., tundra and chaparral). Regions with larger baseflows and flatter runoff hydrographs generally have a higher contribution of runoff from sub-surface flow. Higher values of epsilon tend to reduce the contribution from surface runoff. SSEA III ­ Final Report K-23 017334-003-00 Appendix K - Climate Change and Impacts of Runoff AWCmult has units of meters and, as described above (Section 6.2), is directly related to land- use. The greater the rooting depth of vegetation, the higher the value of AWCmult. Higher values of AWCmult tend to reduce the contribution from surface runoff. For this study, the model was calibrated against an existing runoff dataset. Hence, for the calibration, simulated runoff data obtained from the CD of runoff fields were used. These were developed by the UNH and the Global Runoff Data Center (GRDC) (Fekete et al., 2000). The data on this CD have been endorsed by WMO, UNESCO, and IGBP and they are believed to be the best global runoff data currently available. The three parameters (i.e., alpha, epsilon and AWCmult) were calibrated for each NELR runoff region by simulating runoff for 24 years (1961 to 1984) and minimizing the mean square error of the WATBAL simulated average monthly runoff and the UNH simulated runoff data. This approach tends to maximize the "goodness of fit" of the total volume of runoff, but will not necessarily produce a good fit in periods of extreme high and/or low runoff events. However, since this study is primarily concerned with potential hydropower production, total volume is the most important aspect of the runoff regime to simulate correctly. A gradient search algorithm (Frontline Systems, 2003) was used to optimize the parameters. This approach enables the whole of the "solution space" to be searched and generally allows solutions to be obtained more rapidly than alternative optimization methods. The AWCmult parameters were constrained to lie within a range 0.1 to 5.0 m depending on the likely rooting depth of vegetation within the specified land-use class. Calibration results Figures 6.5a, 6.5b, and 6.5c present the calibration results for WATBAL for the three runoff regions. The figures show a good seasonal fit as well as total annual runoff fit. For all regions, the Sutcliffe-Nash model skill score is greater than 0.98. The "optimal" WATBAL parameters estimated via the calibration process were used in the models for all current climate and climate change runs. No changes in land use, land cover, or vegetation were assumed for when the changed climate occurs. These factors are likely to change, but the analysis to examine these changes is beyond the scope of this assessment. SSEA III ­ Final Report K-24 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.5a - Kyoga Region WATBAL Calibration Summary Kyoga Region Calibration 30 25 20 h ont Model m/ 15 m OBSERVED m 10 5 0 January y ril y t uar rch Ap Ma June July Febr Ma Augus ember vember cember Sept OctoberNo De Months Figure 6.5b - Tanganyika Region WATBAL Calibration Summary Tanganyika Region Calibration 60 50 40 h ont Model m/ 30 m OBSERVED m 20 10 0 January y h st uar Febr Marc April May June July ber ber AuguSeptem tober Oc vember No Decem Months SSEA III ­ Final Report K-25 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.5c - Nyasa Region WATBAL Calibration Summary Nyasa Region Calibration 70 60 50 hs 40 ont Modeled m/ OBSERVED m 30 m 20 10 0 January y ril y t uar rch Ap Ma June July Febr Ma Augus ember vember cember Sept OctoberNo De Months 6.6 Runoff Simulation The model was calibrated to estimate runoff on a monthly time step for all three regions for the period 1961-1984. The base case for this analysis was the simulation of the climate record from 1961 to 1990. The runoff, precipitation, temperature, potential evapotranspiration, and aridity indexes were generated for 1961-1990 with input data from the Climate Research Unit at the University of East Anglia. 6.7 Climate Change Runoff Modeling Approach To ascertain the possible impacts of climate change within the regions being investigated in this study, the two region climate change scenarios developed by Stratus Consulting for the northern and southern regions were used. The Northern scenario was used for the Kyoga and Tanganyika regions and the Southern scenario was used for the Nyasa Region. Two time periods were studied: 2050 and 2100. The quarterly seasonal changes in precipitation and temperature were applied to the appropriate monthly base climate conditions for the A1B model average runs only. For the A1B WET and DRY scenarios and the A1FI model average scenarios, annual changes are added uniformly to each month. The scenario changes were applied to the 1961 to 1990 base monthly temperature and precipitation record using the same climate change for each year of the record. Thus, the resulting 30 years of data are not a projected time series from 2051 to 2080 or 2101 to 2130 with progressively changing climate parameters, but a set of 30 possible years that might occur between 2050 and 2100 for the regions. So a 30-year Monte Carlo simulation of runoff for the years 2050 and 2100 was performed. SSEA III ­ Final Report K-26 017334-003-00 Appendix K - Climate Change and Impacts of Runoff WATBAL was run with the 30 years of monthly observed data for each scenario. The results for each region are provided in the following section. 6.8 Runoff Sensitivity Analysis Climate change scenarios provide insight into what global, regional, and local climate variables may be in the future under various economic scenarios. However, there is a need to understand the sensitivity of the hydrologic system and resulting runoff to these highly uncertain climate variables, so a sensitivity analysis was performed for each of the three runoff regions. The analysis used WATBAL to examine the impact on modeled runoff of a change of -50 to + 50% in annual precipitation relative to the 1961-1990 base climate and for an increase in annual temperature from 1 to 6 degrees centigrade. Table 6.1 provides a summary of change in annual runoff as a function of changes in total annual precipitation uniformly imposed on each month. Table 6.2 provides a summary of change in annual runoff as a function of uniform increase in annual temperature uniformly imposed on each month. Table 6.1 - Precipitation Sensitivity Analysis Summary Change in Change in Runoff Precipitation Kyoga Tanganyika Nyasa -50% -75% -79% -82% -25% -45% -48% -53% -10% -20% -22% -24% -5% -10% -11% -13% 0% 0% 0% 0% 5% 11% 12% 13% 10% 23% 24% 28% 25% 61% 65% 77% 50% 138% 149% 171% Table 6.2 - Temperature Sensitivity Analysis Summary Change in Change in runoff temperature Kyoga Tanganyika Nyasa +1 degree -2% -4% -4% +2 degree -4% -8% -8% +4 degree -8% -15% -16% +6 degree -12% -21% -22% Figures 6.6a and 6.6b, Figures 6.7a and 6.7b, and Figures 6.8a and 6.8b present the sensitivity analysis graphically for each of the runoff analysis regions. SSEA III ­ Final Report K-27 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.6a - Kyoga Region Precipitation Sensitivity Analysis Kyoga Runoff - Precipitation Sensitivity Analysis 150% 100% f unofR 50% ni ngeahC 0% -60% -40% -20% 0% 20% 40% 60% -50% -100% Change in Precipitation Figure 6.6b - Kyoga Region Temperature Sensitivity Analysis Kyoga Runoff -Temperature Sensitivity Analysis 0% 0 1 2 3 4 5 6 7 -2% -4% f unofR -6% ni ngeahC -8% -10% -12% -14% Delta T Degees C SSEA III ­ Final Report K-28 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.7a - Tanganyika Region Precipitation Sensitivity Analysis Summary Tanganyika Runoff - Precipitation Sensitivity Analysis 200% 150% ffon 100% Ru ni 50% egna Ch 0% -60 -40 -20 0 20 40 60 -50% -100% Change in Precipitation Figure 6.7b - Tanganyika Region Temperature Sensitivity Analysis Tanganyika Runoff -Temperature Sensitivity Analysis 0% 0 1 2 3 4 5 6 7 -5% f unofR -10% ni egnahC-15% -20% -25% Delta T Degees C SSEA III ­ Final Report K-29 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.8a - Nyasa Region Precipitation Sensitivity Analysis Summary Nyasa Runoff - Precipitation Sensitivity Analysis 200% 150% ffon 100% Ru ni 50% egna Ch 0% -60% -40% -20% 0% 20% 40% 60% -50% -100% Change in Precipitation Figure 6.8b - Nyasa Region Temperature Sensitivity Analysis Nyasa Runoff -Temperature Sensitivity Analysis 0% 0 1 2 3 4 5 6 7 -5% ff unoR -10% ni ngeahC -15% -20% -25% Delta T Degees C SSEA III ­ Final Report K-30 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 6.9 Climate Change Runoff Results - Annual Results for all Scenarios Tables 6.3 and 6.4 present the summary of results for all scenarios for annual average values. Table 6.3 provides absolute values: annual precipitation in mm/year; annual average temperature in degrees Celsius; the annual potential evapotranspiration in mm/year; and a measure of aridity [1 - Annual Precipitation /Annual Pet], where a value of 1 suggests very arid, and a value of -1 suggests very humid and runoff in mm/year. Table 6.4 presents the summary of results relative to base climate from 1961 to 1990. The values are changes in annual precipitation percent, annual average temperature, degrees Celsius, and aridity. A positive value in Precipitation/PET means it is getting wetter and a negative value means it is getting drier. Runoff is in percentage of the base year. In general, the scenarios project an increase in runoff for the three regions. The exception is the dry scenario for the Nyasa Region, under which a decrease in runoff is projected. Furthermore, the model averages for the A1B and A1FI scenarios in Nyasa involve virtually no change in runoff. The absolute changes should be interpreted with caution. SSEA III ­ Final Report K-31 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Table 6.3 - Annual Absolute Results Time Scenario Precipitation Temperature PET PREC/PET Runoff (mm/year) (°C) (mm/year) (ratio) (mm/year) Kyoga 1961-1990 Base -- 1338 22.9 1770 0.24 183 2050 A1B-Model Avg 1471 24.6 1847 0.20 224 A1B-Wet -- 1529 24.6 1845 0.17 251 A1B-Dry -- 1396 24.8 1852 0.25 190 A1FI-Model Avg 1552 24.7 1850 0.16 261 2100 A1B-Model Avg 1625 25.9 1901 0.15 283 A1B-Wet -- 1703 25.9 1903 0.30 323 A1B-Dry -- 1449 26.2 1915 0.24 199 A1FI-Model Avg 1852 27.8 1985 0.07 380 Tanganyika 1961-1990 Base -- 1249 20.2 1653 0.24 272 2050 A1B-Model Avg 1377 21.9 1723 0.20 325 A1B-Wet -- 1427 22.0 1728 0.17 349 A1B-Dry -- 1303 22.1 1735 0.25 280 A1FI-Model Avg 1480 22.1 1733 0.15 384 2100 A1B-Model Avg 1488 23.2 1784 0.17 372 A1B-Wet -- 1590 23.3 1786 0.30 429 A1B-Dry -- 1353 23.5 1798 0.25 290 A1FI-Model Avg 1625 25.1 1867 0.13 431 Nyasa 1961-1990 Base -- 1291 21.7 1715 0.25 254 2050 A1B-Model Avg 1327 23.5 1803 0.26 254 A1B-Wet -- 1592 22.7 1761 0.10 419 A1B-Dry -- 963 24.1 1823 0.47 106 A1FI-Model Avg 1335 23.9 1812 0.26 255 2100 A1B-Model Avg 1351 24.9 1860 0.27 252 A1B-Wet -- 1859 23.5 1797 0.28 596 A1B-Dry -- 779 26.0 1906 0.59 59 A1FI-Model Avg 1393 27.0 1950 0.29 254 SSEA III ­ Final Report K-32 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Table 6.4 - Annual Relative Results Time Scenario Precipitation Temperature PET PREC/PET Runoff (% of base) (°C) (%) (% change) (% of base) Kyoga 1961-1990 Base -- 100% 0.0 100% 0% 100% 2050 A1B-Model Avg 110% 1.7 104% 17% 123% A1B-Wet -- 114% 1.7 104% 30% 137% A1B-Dry -- 104% 1.9 105% -1% 104% A1FI-Model Avg 116% 1.8 105% 34% 142% 2100 A1B-Model Avg 121% 3.0 107% 41% 155% A1B-Wet -- 100% 3.0 108% -22% 177% A1B-Dry -- 108% 3.3 108% 0% 109% A1FI-Model Avg 138% 4.9 112% 73% 207% Tanganyika 1961-1990 Base -- 100% 0.0 100% 0% 100% 2050 A1B-Model Avg 110% 1.7 104% -18% 119% A1B-Wet -- 114% 1.7 105% -29% 128% A1B-Dry -- 104% 1.9 105% 2% 103% A1FI-Model Avg 118% 1.8 105% -40% 141% 2100 A1B-Model Avg 119% 3.0 108% -32% 137% A1B-Wet -- 100% 3.0 108% 23% 158% A1B-Dry -- 108% 3.3 109% 1% 107% A1FI-Model Avg 130% 4.9 113% -47% 159% Nyasa 1961-1990 Base -- 100% 0.0 100% 0% 100% 2050 A1B-Model Avg 103% 1.8 105% 7% 100% A1B-Wet -- 123% 1.0 103% -61% 165% A1B-Dry -- 75% 2.5 106% 91% 42% A1FI-Model Avg 103% 2.2 106% 6% 100% 2100 A1B-Model Avg 105% 3.3 108% 11% 99% A1B-Wet -- 100% 1.8 105% 14% 234% A1B-Dry -- 60% 4.3 111% 139% 23% A1FI-Model Avg 108% 5.3 114% 15% 100% Figures 6.9, 6.10, and 6.11 present the annual results for each scenario for precipitation, PET and runoff for each of the runoff analysis regions. SSEA III ­ Final Report K-33 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.9a - Kyoga Region Annual Precipitation for Climate Change Scenarios Kyoga Annual Precipitation 2000 1800 1600 1400 ar 1200 yerep 1000 m 800 m 600 400 200 0 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave Figure 6.9b - Tanganyika Region Annual Precipitation for Climate Change Scenarios Tanganyika Annual Precipitation 1800 1600 1400 1200 ar yerep 1000 800 m m 600 400 200 0 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave SSEA III ­ Final Report K-34 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.9c - Nyasa Region Annual Precipitation for Climate Change Scenario Nyasa Annual Precipitation 2000 1800 1600 1400 ar 1200 yerep 1000 m 800 m 600 400 200 0 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave Figure 6.10a - Kyoga Region Annual PET for Climate Change Scenario Kyoga Annual PET 2050 2000 1950 ar 1900 yerep 1850 m m 1800 1750 1700 1650 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave SSEA III ­ Final Report K-35 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.10b - Tanganyika Region Annual PET for Climate Change Scenario Tanganyika Annual PET 1900 1850 1800 ar 1750 yerep 1700 m m 1650 1600 1550 1500 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave Figure 6.10c - Nyasa Region Annual PET for Climate Change Scenario Nyasa Annual PET 2000 1950 1900 1850 ar yerep 1800 1750 m m 1700 1650 1600 1550 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave SSEA III ­ Final Report K-36 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.11a - Kyoga Region Annual Runoff for Climate Change Scenarios Kyoga Annual Runoff 400 350 300 ar 250 yerep 200 m m 150 100 50 0 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave Figure 6.11b - Tanganyika Region Annual Runoff for Climate Change Scenarios Tanganyika Annual Runoff 500 450 400 350 ar 300 yerep 250 m 200 m 150 100 50 0 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave SSEA III ­ Final Report K-37 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.11c - Nyasa Region Annual Runoff for Climate Change Scenarios Nyasa Annual Runoff 700 600 500 ar yerep 400 m 300 m 200 100 0 BASE 2050A1B- 2050A1B- 2050A1B- 2050A1FI- 2100A1B- 2100A1B- 2100A1B- 2100A1FI- Ave wet dry Ave Ave wet dry Ave 6.10 Monthly Results for Model Average Scenarios For 2050 and 2100 for the A1B and A1FI average model scenarios, three monthly seasonal scenario values were provided. These seasonal values were applied to the monthly base values and the model results at the monthly level, and provide insight into seasonal changes in runoff. The results for each region are provided below in Figures 6.12a, b, and c. SSEA III ­ Final Report K-38 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.12a - Kyoga Region Monthly Runoff Results Kyoga Monthly Runoff 50 45 40 35 30 mm 25 20 15 10 5 0 ary y ril t uar Ap May June July ber ber Janu Febr March Augus ptem tober Oc cember Se Novem De 61-90-BASE-- 2050A1B-Model Average-- 2050A1B-wet-- 2050A1B-dry-- 2050A1FI-Model Average-- 2100A1B-Model Average-- 2100A1B-wet-- 2100A1B-dry-- 2100A1FI-Model Average-- Figure 6.12b - Tanganyika Region Monthly Runoff Results Tanganyika Monthly Runoff 100 90 80 70 60 mm 50 40 30 20 10 0 January y ril y t uar rch Ap Ma June July ber tober ber Febr Ma Augus em Sept Oc Novem cember De 61-90-BASE-- 2050A1B-Model Average-- 2050A1B-wet-- 2050A1B-dry-- 2050A1FI-Model Average-- 2100A1B-Model Average-- 2100A1B-wet-- 2100A1B-dry-- 2100A1FI-Model Average-- SSEA III ­ Final Report K-39 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.12c - Nyasa Region Monthly Runoff Results Nyasa Monthly Runoff 180 160 140 120 100 mm 80 60 40 20 0 ary uary rch April y t Ma June July ber ber Janu tober Febr Ma Augus ptem Oc Se Novem December 61-90-BASE-- 2050A1B-Model Average-- 2050A1B-wet-- 2050A1B-dry-- 2050A1FI-Model Average-- 2100A1B-Model Average-- 2100A1B-wet-- 2100A1B-dry-- 2100A1FI-Model Average-- 6.11 Climate Change Impact on Regional Reservoir Storage Yield Analysis of runoff impacts provides insight into potential climate change impacts on natural hydrologic systems. However, in many cases, the concern is about the impact on existing water resources infrastructure. The following is a broad-brush analysis of the impacts of climate change on the storage-yield relationships of a "virtual" reservoir in each of the runoff regions. A storage-yield curve shows the amount of water storage necessary to provide, or yield, a "reliable" amount of water in each time period. The storage requirement is a function of the variability of the runoff. Natural runoff is highly variable, so storage is built to mediate the variability and to retain the runoff until it is needed. Logically, the minimum steady flow that can be delivered is the minimum flow of the river in the time period being considered. The maximum steady flow that can be delivered by a reservoir is the average runoff flowing into the reservoir, although in reality, losses such as evaporation, bank storage, and seepage make this theoretical maximum difficult to achieve even when adequate storage is built. In order to achieve a yield close to the average runoff, the storage must be large enough to be able to contain the largest flood flow and must be able to keep releasing water through the longest and deepest drought. Generally, storage-yield curves exhibit diminishing returns to scale, as shown in the sample curve in Figure 6.13, created by using data from Lake Nasser in Egypt (Wiberg and Strzepek, 2005). SSEA III ­ Final Report K-40 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.13 - Typical Shape of the Storage-Yield Curve for Lake Nasser 90 80 70 ) 3 m 60 9 01( 50 deliY40 30 20 10 0 0 50 100 150 200 Storage (109 m3) A common technique for calculating storage-yield curves is the sequent peak algorithm (Thomas and Fiering, 1963). Equation 7 is the equation for the sequent peak algorithm. if positive St = 0Rt - Qt + St -1 (7) otherwise Here, S is the storage, R the release, and Q the inflow. The subscript "t" represents the current time period. Equation 7 is applied for every time period and the maximum St over all time periods the storage is required for the series of inflows applied. The sequent-peak algorithm was applied to the 30-year monthly time series generated by WATBAL for the base and the climate change scenarios for 2050 and 2100. By examining the curves in Figures 6.14 to 6.16 below, one can see how potential climate change will impact the yield of a given reservoir capacity or the required reservoir capacity to maintain a given firm yield. The storage-yield analysis suggests that for all regions and for all scenarios except the A1B model average the storage-yield curve maintains the same shape but moves up or down related to the ratios of the annual runoff. This is consistent with a constant annual climate change scenario or for very little seasonal change in runoff. SSEA III ­ Final Report K-41 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.14a - 2050 Kyoga Region Storage-Yield Curves Kyoga 2050 Storage Yield Results 10.00 9.00 8.00 7.00 earY/ 6.00 MC 5.00 M d eliY 4.00 3.00 2.00 1.00 0.00 0.00 5.00 10.00 15.00 20.00 25.00 Reservoir Storage MCM BASE A1B AVE A1B WET A1B DRY A1F1 AVE Figure 6.14b - 2100 Kyoga Region Storage-Yield Curves Kyoga 2100 Storage Yield Results 14.00 12.00 10.00 ra Ye/ 8.00 MC M dle 6.00 Yi 4.00 2.00 0.00 0.00 5.00 10.00 15.00 20.00 25.00 Reservoir Storage MCM BASE A1B AVE A1B WET A1B DRY A1F1 AVE SSEA III ­ Final Report K-42 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.15a - 2050 Tanganyika Region Storage-Yield Curves Tankanyika 2050 Storage Yield Results 14.00 12.00 10.00 earY/ 8.00 MC M d 6.00 eliY 4.00 2.00 0.00 0.00 5.00 10.00 15.00 20.00 25.00 Reservoir Storage MCM BASE A1B AVE A1B WET A1B DRY A1F1 AVE Figure 6.15b - 2100 Tanganyika Region Storage-Yield Curves Tankanyika 2100 Storage Yield Results 16.00 14.00 12.00 ra Ye/ 10.00 MC 8.00 M dle 6.00 Yi 4.00 2.00 0.00 0.00 5.00 10.00 15.00 20.00 25.00 Reservoir Storage MCM BASE A1B AVE A1B WET A1B DRY A1F1 AVE SSEA III ­ Final Report K-43 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Figure 6.16a - 2050 Nyasa Region Storage-Yield Curves Nyasa 2050 Storage Yield Results 16.00 14.00 12.00 earY/ 10.00 MC 8.00 M d eliY 6.00 4.00 2.00 0.00 0.00 5.00 10.00 15.00 20.00 25.00 Reservoir Storage MCM BASE A1B AVE A1B WET A1B DRY A1F1 AVE Figure 6.16b - 2100 Nyasa Region Storage-Yield Curves Nyasa 2100 Storage Yield Results 25.00 20.00 ra Ye/ 15.00 MC M dle 10.00 Yi 5.00 0.00 0.00 5.00 10.00 15.00 20.00 25.00 Reservoir Storage MCM BASE A1B AVE A1B WET A1B DRY A1F1 AVE SSEA III ­ Final Report K-44 017334-003-00 Appendix K - Climate Change and Impacts of Runoff However for the A1B model average scenarios, the storage-yield curves shape changes due to increases in variability in the monthly runoff. (The A1B model average scenario is the only scenario that considered seasonal changes in climate.) Reservoir storage is less effective in providing firm yield at lower storage levels. This is due to changes in seasonal runoff, so even for some increases in annual runoff, reservoir storage in less effective. To illustrate this, Figure 6.15a shows the storage-yield curves for the Tanganyika Region. The base scenario has a maximum yield of 9 MCM, while under the A1B model average scenario the maximum yield is 11 MCM. This is the case when a reservoir with a large storage capacity is assumed. Notice that the A1B yield-curve is below the base curve up the storage level of 6.58 MCM and yield of 8.5 MCM and above the base after this point. This means that if reservoir storage in the region is 5 MCM current climate would provide for an annual firm yield of 8 MCM. Under the A1B model average scenario that same storage would provide for an annual firm yield of 6 MCM. This is a 25% decrease of firm yield even though there is a 19% increase in annual runoff. The reason behind the differences in the curves is that under the A1B model average scenario there are significant changes in the seasonal distribution of precipitation and PET, which results in more variation in monthly stream flow. This is the case for the Tanganyika Region, where the monthly runoff standard deviation for the A1B model average scenario is 25% greater than current climate and the coefficient of variation is 5% greater than the base. These increases in variation change the shape of the storage-yield curve and in this case reduce reservoir effectiveness at lower storage levels. 6.12 Summary The analysis of potential impacts of climate change on runoff in the three sub-regions in the Nile Equatorial Lakes Region shows that all three exhibit an asymmetric, non-linear relationships between precipitation and runoff. All the regions have a runoff multiplier of up to 3 times the precipitation change at +50% (e.g., a 25% increase in precipitation would lead to an approximate 75% increase in runoff) and 1.5 times the precipitation change at -50%. All three regions exhibit approximately linear relationship between temperature and runoff. The regions have different slopes for the linear relationships, with northern Kyoga 2% per degree C, central Tanganyika 3% per degree C, and southern Nyasa 4% per degree C. This is related to potential evapotranspiration and the range of temperatures each region received monthly. The analysis of the climate change scenarios summarized in Table 6.4 contains the main message of this analysis. The model average climate change scenario for 2050 results in significant increases in runoff for the Kyoga and Tanganyika regions for both A1B and A1FI ­ 23 and 42% respectively. For 2100 there is a larger increase in runoff for the Kyoga and Tanganyika regions for both A1B and A1FI ­ 55 and 107% respectively. For the Nyasa region, the model average changes in 2050 and 2100 result in no change in runoff for both A1B and A1FI ­ 1 and 0% respectively. These findings are driven primarily by the climate change scenarios, but also from the responsiveness of hydroclimatic system of each region. An important finding from the storage-yield analysis is that for all regions and all scenarios except A1B model average, the storage-yield curve shape does not change but is shifted up and down in relationship to the change in mean annual runoff. However, under the A1B scenario, the only scenario in which seasonal changes in climate differ, the storage-yield curve changes its shape so that a portion is below the base curve and a subsequent portion is above the base curve. This means that for reservoirs with relatively small storage, firm yield would be less than base climate even in cases where the average annual yield increases. For reservoirs with relatively large storage, yield could increase. SSEA III ­ Final Report K-45 017334-003-00 Appendix K - Climate Change and Impacts of Runoff This last result suggests that an increase in climate variability with no change in annual runoff would decrease reservoir performance. This can be offset where runoff increases. If there is no change in variability, yield would rise with increasing runoff and decrease with decreasing runoff. The result suggests that larger reservoir capacity can better cope with increased variability or increased runoff, but not decreased runoff. While this climate change analysis is informative at a broad regional scale, any hydropower project and especially systems with significant reservoir storage should be examined in detail with localized and downscale climate change scenarios developed for the watersheds. SSEA III ­ Final Report K-46 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 7 POTENTIAL IMPACT ON RUNOFF AND GENERATION CAPABILITY The previous two sections have provided the results of the climate change analyses, in terms of: · Predictions of temperature and precipitation changes, as a function of emission or economic development assumptions; · Estimates of resulting changes to net water yield, expressed in terms of annual averages, monthly average values, and reservoir yield. These analyses have targeted three geographic areas: · Lake Victoria/Lake Kyoga and the Victoria Nile ­ including the Bujagali and Karuma hydro sites; · Lake Tanganyika/Lake Kivu and Rwanda/Burundi ­ including the Ruzizi III and Rusumo sites; · Lake Nyasa and the adjacent Ruhudji and Rumakali river basins. Certain general and specific conclusions can be drawn in terms of potential climate change impacts on hydro generation that should be considered in a risk analysis to confirm the robustness of the portfolio selection process. 7.1 General conclusions The general conclusions that may be drawn from the analyses described in Section 5 and 6 above include the following: · The predictions of temperature and precipitation changes are consistent with other modelling results in that temperature is expected to increase with greenhouse gas emission increases; · An increase in precipitation is the expected result from an increase in temperature; · An increase in temperature will also result in increased evaporation and evapotranspiration losses; · Changes will be more significant in year 2100 than in 2050, due to the forecast higher emission levels, and consequent changes to temperature; · Changes will be more significant for the high emission scenario A1F1, than for the median emission scenario A1B, again because of the expected link between emission levels and temperature. (Note wet and dry scenarios were not tested for the A1F1 emission scenario); · Net runoff will increase with increase in greenhouse gas emission levels; · Increased emission levels (due to year or development scenario) will result in increased seasonal variability in runoff, as flood periods will provide most of the increased runoff, with dry periods being only marginally affected in terms of volume; · Increased variability in runoff is most evident in the southern Tanzania region. It is relatively modest in the northern and central west regions; · All annual runoff predictions (development scenario and wet/average/dry conditions) for the northern (Uganda-Victoria Nile) and central west (Rwanda-Burundi-West Tanzania) areas show increases in runoff. For the southern Tanzania area reduced SSEA III ­ Final Report K-47 017334-003-00 Appendix K - Climate Change and Impacts of Runoff annual run off would result only under dry condition scenarios, however this would apply anyway without climate change impacts; · If storage yield is taken into account, the minimum flows increase by less than for the average minimum (driest) month. 7.2 Specific Results Table 7-1 provides a summary of predicted runoff changes for each of the hydro options included in the reference indicative generation plan for the A1B median and A1F1 high emission scenarios, based on average model results. These results show that for all cases, average runoff, and thus generation, would increase, based on average model results. This however does not take into account the possibility of increased flood discharges not used for power. However in turn one must recognize that a final optimization study for any given project, as part of the final design of the project, predicated on increased but more variable runoff, might justify higher capacity installations that would offset or eliminate this factor. The only potential negative impact, as related to future generation is the indication that minimum flows for the southern Tanzania projects (Ruhudji and Rumakali) could be reduced, based on average model results. However it has to be remembered that for this region, relatively little runoff volume occurs in the dry months August to November. Furthermore reference to Table 6.4 suggests that the prediction from the "dry" model (the model that forecasts the least increase in precipitation) for southern Tanzania would be significantly reduced net runoff. 7.3 Supplementary Analyses The modeling provided in this study of climate change potential impacts has been based on the IPCC Third Assessment Report model output. NCAR have now completed analyses based on the IPCC Fourth Assessment Report climate model projections (This report is due for issue in 2007). Probability distributions based on the world median emission scenario A1B for the period 2080-2100, for a grouping of all 18 models show increased median precipitation values for all three regions, with the probabilities on precipitation increases being at least: · Lake Victoria/Lake Kyoga and the Victoria Nile ­ including the Bujagali and Karuma hydro sites - 80%, with 17 models out of 18 predicting increased precipitation; · Lake Tanganyika/Lake Kivu and Rwanda/Burundi ­ including the Ruzizi III and Rusumo sites ­ 70%, with 15 of the models predicting an increase in precipitation; · Lake Nyasa and the adjacent Ruhudji and Rumakali river basins ­ 70%, with 16 models predicting an increase in annual precipitation. The derived median precipitation increases from these latest analyses suggest lower precipitation increases in the northern and west central areas than were developed in the SSEA study. SSEA III ­ Final Report K-48 017334-003-00 Appendix K - Climate Change and Impacts of Runoff 50 % probability % Region SSEA average annual % precipitation increase precipitation increase ­ latest NCAR analyses North (Nile ­ Lake Victoria) 13.8 11.9 West central ­ R/B/WT 13.8 7.3 Southern Tanzania 3.8 10.1 7.4 Risk Analyses The purpose of these analyses was to determine plausible changes to historic runoff for the new hydro options that were included in the reference indicative plan for the region, that would be indicated from current climate change modelling. These potential changes could then be used to determine if the project selection and scheduling procedure would be valid if these changes would be accepted as the basis for planning studies. In considering whether to undertake any risk analyses, in the context of the results and conclusions that have been presented above, one should note the following. The immediate concern should be the validity of project selection for the first part of the plan period, as this could affect decisions being taken on the basis of studies already completed. Under this grouping one may include Bujagali, Rusumo and Ruzizi. These sites are in the northern and west central regions, for which the potential for runoff reduction, for any combination of emission scenario or model (average or dry) criterion, appears to be minimal (with all results showing runoff increases). The study results do not provide any basis for selecting a runoff reduction to be used in a risk analyses. The longer term part of the plan includes Karuma in the northern region, and Ruhudji and Rumakali in the southern region. The results for the northern region are very positive in terms of long term runoff trends, and thus there is no basis for assuming any negative impact for a risk analysis. For the Tanzanian projects there appears to be some potential for average annual runoff reduction, however only assuming validity from the results of the "dry" model. Clearly if one was to adopt the "dry sequence" scenario for a risk analysis, sensitivity tests with average runoff reduced to 23 to 42 % of the base or historic runoff (as shown in Table 6.4), then these projects would not be selected for the plan, and would be replaced by thermal (next stage of Mchuchuma and imported coal) if Tanzanian replacement generation is assumed, or less socially/environmentally acceptable hydro if this generation would be provided from other hydro options in the region. One option could be to determine the least cost, and best ranked alternatives for Rumakali and Ruhudji, however this would require significantly less plausible assumptions with regard to the price of coal, and/or acceptability of less desirable hydro from outside of the southern Tanzania region. It is therefore proposed that the results of this climate change risk assessment be defined as follows: · There are few clearly identified hydrological risks to the hydro options included in the indicative plan, and overall for the Northern and Central West regions there is a high probability of increases in runoff, and thus generation, than presently identified from historic flow data. For the southern region there is a high likelihood of changes in SSEA III ­ Final Report K-49 017334-003-00 Appendix K - Climate Change and Impacts of Runoff seasonality of runoff, resulting in lower effectiveness for flow regulation in any smaller reservoir; · Any further planning studies and assessment of new hydro options in southern Tanzania should address this risk in more detail, as is suggested in Section 6.12 above; · Results show that for all regions flood flows may increase significantly, thus designs for flood discharge during construction and over a permanent spillway should take this potential into account. Project costs would also be affected; · Similarly the identified trend towards larger floods, suggests that project planning and environmental assessments for multipurpose specifically take into account this hydrologic risk in assessing project benefits from flood control. SSEA III ­ Final Report K-50 017334-003-00 Appendix K - Climate Change and Impacts of Runoff Table 7-1 - Impact of Climate Change on Runoff for Preferred Hydro Options SSEA III - Climate Change K-51 017334-003-00 APPENDIX L DEVELOPMENT OF PORTFOLIOS SSEA III - Final Report 017334-001-00 Appendix L - Development of Portfolios TABLE OF CONTENTS PAGE 1 Introduction 1 2 Candidate New Power Options Load ­ Resource Balance 1 3 Development Strategies 2 3.1 Main Portfolios Examined 10 3.2 Sensitivity to load growth 11 3.3 Sensitivity analyses 12 4 Option Selection and Ordering 12 4.1 Socio-Economic and Risk Factors 12 4.2 Earliest On-Power 13 4.3 Generation Cost 13 4.4 Option Size 13 5 Independent Approach, Primarily National Options and Base Load Growth Scenario ­ Portfolio 1Aa 17 6 Portfolios Based on the Medium Load Growth Scenario 18 6.1 Regional Approach, Best Evaluated Options and Medium Load Growth Scenario ­ Portfolio 2Bb 18 6.2 Regional Approach, Technological Diversification and Medium Load Growth Scenario ­ Portfolio 2Cb 22 6.3 Regional Approach, Geographical Diversification and Medium Load Growth Scenario ­ Portfolio 2Db 24 7 Modified Plans to Meet the High Load Growth Scenario 27 7.1 Technical Diversification, Based on High Load Growth Scenario - Portfolio 2Cc 27 7.2 Geographical Diversification, Based on High Load Growth Scenario ­ Portfolio 2Dc 30 8 Plan Using all Resources to Meet Transformation Load Growth Scenario ­ Portfolio 2d 32 9 Sensitivity Tests 34 9.1 Regional Approach, Technical Diversification, Including Options with Insufficient Level of Preparation and Medium Load Growth Scenario ­ Portfolio 2Cb(S1) 34 9.2 Regional Approach, Technical Diversification, Including Imports From Outside the Region and Medium Load Growth Scenario ­ Portfolio 2Cb(S2) 35 9.3 Regional Approach, Technological Diversification, Excluding any Consideration of Environmental, Social and Risk Issues and Medium Load Growth Scenario ­ Portfolio 2Cb(S3) 37 SSEA III - Final Report L-i 017334-001-00 Appendix L - Development of Portfolios 1 Introduction This appendix provides a description of the development of the portfolios that are presented in Chapter 13 of the main report. The alternative strategies on which the portfolios are based are outlined, and then the selection and ordering of options for each is described. The concept of the development of portfolios of new generation options, or in power planning terminology, alternative generation plans, was introduced to provide a basis for comparison of logical sequences of new generation, taking into account socio-environmental acceptability, minimum lead times to on-power and cost effectiveness. The alternative portfolios were developed to respect certain strategies such as technical or geographical diversification, as well as to determine the cost impacts associated with relaxing certain of the plan development criteria. In all cases options assessed as having minimum social or environmental risk were selected preferentially, except where this infringed on the strategy criterion. The portfolios corresponding to alternative development strategies were developed to cover the period 2005 to 2020, and to respond to alternative load growth scenarios. 2 Candidate New Power Options Load ­ Resource Balance The list of new power options that were evaluated in the MCA process and their segregation into "best evaluated" and "other" groups is shown in Table L-1. Other options, that are not shown in Table L-1 that have been considered in the development of portfolios are: · Possible import of 300 MW via Zambia; · Use of low speed diesels using Bunker C, where no other options exist (for the high load growth scenario). As is noted in Chapter 6 of the main report, there are other options such as biomass, demand side management and off grid generation that have not been included in the candidate list of new power options. It is important to relate the available new generation options in the region with the forecast demands for new generation. In this respect the load growth scenarios resulting from the needs analysis shown in Chapter 5 of the main report provide the following total new power requirements for the region from the end of 2004 to the end of 2020: Base load growth scenario 1,639 MW Medium load growth scenario 2,853 MW High load growth scenario 4,140 MW Transformation load growth scenario 10,516 MW A comparison of load and available resources is shown in summary form in Table L-2. This covers the period 2005 to 2020. Resources are limited to the specific power development options that have been identified in previous studies, as are listed in Chapter 7, as well as existing generation. Power development options are limited to those that have been retained after the screening; thus this load resources balance does not take account of the results of the comparative analyses carried out in Chapter 9. No generic power development options are included at this stage. SSEA III - Final Report L-1 017334-001-00 Appendix L - Development of Portfolios This shows that even for the period up to 2020 there are insufficient indigenous resources (hydro, wind or thermal using local fuels) to meet the medium load growth scenario, and that all of the known resources, including options that are not included in the best evaluated options group, would be required to meet the high load growth scenario. Total identified new generation resources (excluding thermal using imported fuels) are: Best evaluated 2,549 MW Other options 992 MW Total 3,361 MW Consequently only portfolios designed to satisfy the base load growth scenario could be done using only new options that are presently considered as "best evaluated". The above totals exclude possible gas generation using imported LNG or coal fired thermal using imported coal from Richards Bay. 3 Development Strategies In order to properly assess the power development options for the region, two major approaches were considered: independent development by each country and a regional cooperation approach in which the six countries plan for a joint development of resources. Within the second approach, three strategies were considered: 1. Maximize the use of the most attractive resources available within the region. This strategy leads to heavy reliance on hydroelectric options with the attendant risk of power shortages due to drought conditions; 2. Use of attractive resources while enhancing technological diversification. This strategy reduces reliance on hydroelectric facilities but increases the cost of power and involves the use of resources that are less attractive from environmental and social points of view; 3. Use of attractive resources while enhancing geographical diversification. This strategy ensures that each country, on the long term is not overly dependent upon its neighbours, but at increased financial, environmental and social cost. A portfolio of development options1 was prepared to illustrate the impact of the independent development approach and for each of the strategies under the regional cooperation approach. For the independent development approach, the base load growth scenario was used. For the regional cooperation approach, three forecasts were used and applied as appropriate to the three strategies: the medium growth, the high growth and the transformation growth scenarios. 1Defined as groups of power development options installed over time so as to meet the forecast load with a defined level of reserve. SSEA III - Final Report L-2 017334-001-00 Appendix L - Development of Portfolios Table L-1 - Results of comparative analysis Best Evaluated Options Hydro Bujagali 250 MW (5 units) Kabu 16 20 MW Kakono 40 MW Karuma 200 MW Mutonga 60 MW Rusumo 62 MW Ruzizi III 82 MW Ruhudji 358 MW Rumakali 222 MW Thermal and Geothermal Combined Cycle 180 MW (2 x 60 MW GT + 1 x 60 MW steam cycle, Songo gas) Gas Turbine 60 MW (Songo gas) Geothermal power development options ­ including o Olkaria II 35 MW o Longonot 70 MW o Suswa 70 MW o Menengai 140 MW o Non-specified 140 MW Kivu gas engines 120 MW (4 x 30 MW groups of engines) Mombasa LNG 180 MW (assumed as CC 3 x 60 MW- imported fuel) Other Technologies Wind (Generic) 30 MW (or 60 MW ­ Two sites) Other Options Hydro SSEA III - Final Report L-3 017334-001-00 Appendix L - Development of Portfolios Table L-2 - Load Resource Balance SSEA III - Final Report L-4 017334-001-00 Appendix L - Development of Portfolios Table L-2 - Load Resource Balance (Cont'd) SSEA III - Final Report L-5 017334-001-00 Appendix L - Development of Portfolios Table L-2 - Load Resource Balance (Cont'd) SSEA III - Final Report L-6 017334-001-00 Appendix L - Development of Portfolios Table L-2 - Load Resource Balance (Cont'd) SSEA III - Final Report L-7 017334-001-00 Appendix L - Development of Portfolios Table L-2 - Load Resource Balance (Cont'd) SSEA III - Final Report L-8 017334-001-00 Appendix L - Development of Portfolios In addition, three sensitivity tests were applied to the strategy of enhanced technological diversification: · The impact of including options that have not yet been adequately studied; · The impact of power imports at a defined unit cost of power; and · The impact of considering only financial cost in the determination of the order of installation of options. These are summarized in Table L-3: Table L-3 - Nomenclature Used in Portfolio Development Power Development 1. Independent 2. Regional Cooperation Approaches Strategies to Develop A) Primarily B) Best C) Technological D) Geographic Power Option National Options Evaluated Diversification Diversification Portfolios Options a) Base (Growth in demand of 3.7% to 4.0%), one portfolio examined Portfolio 1Aa b) Medium (Growth in demand of 5.6% to 6.3%); three portfolios examined Load Growth Portfolio 2Bb Portfolio 2Cb Portfolio 2Db Scenarios c) High (Growth in demand of 6.8% to 8.1%; two portfolios examined Portfolio 2Cc Portfolio 2Dc d) Transformation (Growth in demand of 5.1% to 15.0%; one portfolio examined Portfolio 2d* Limited level of readiness (S1) Portfolio 2Cb(S1) Sensitivity Allowing import options (S2) Analyses Portfolio 2Cb(S2) No comparative analysis; only screening of options (S3) Portfolio 2Cb(S3) * Note: as the transformation scenario would require all the identified power options in the region it is not appropriate to give the portfolio an identifier for a specific strategy. Each of the above portfolios is described below. SSEA III - Final Report L-9 017334-001-00 Appendix L - Development of Portfolios 3.1 Main Portfolios Examined Power development approach: Independent Strategy to develop power option portfolios: Primarily national options Load growth scenario: Base Portfolio: 1Aa In order to better define the benefits from regional cooperation and the consequent implementation of larger, lower cost options, it is necessary to provide an assessment of the social and environmental consequences from failure to implement a regional integrated power supply system. This reference strategy implies that regional projects will not go ahead, and that development throughout the region will be limited to national expansion plans, probably with limited access to financing. It follows from this assumption that the load growth scenario would be lower than under the situation of regional integration. Thus only one portfolio is examined and that uses the base load growth scenario. A portfolio of new generation was developed for each of Kenya, Tanzania, Uganda, and the combined systems of Burundi, Eastern DRC and Rwanda, to respond to the low load forecast for each country. Power development approach: Regional Cooperation Strategy to develop power option portfolios: Best evaluated options Load growth scenario: Medium Portfolio: 2Bb This strategy minimizes the environmental and social impacts on power development in the region. Thus, under this strategy, all of the "best evaluated" options would be used first, followed by any additional options required to meet the load forecast with the selected level of reliability. The results of applying this strategy would be a certain imbalance in both technical diversification, with over dependence on hydro with consequent increased hydrological risk, and geographic diversification, which would require a high level of regional integration in the relatively short term. However the total system cost for this strategy provides a basis for comparison with the other strategies, to define what cost premiums if any would be associated with applying different planning criteria and constraints. Power development approach: Regional Cooperation Strategy to develop power option portfolios: Technological Diversification Load growth scenario: Medium Portfolio: 2Cb For this strategy, the criterion used to define the portfolio was that a balance is to be maintained between hydroelectric power development options and thermal options. Based on the availability of power development options by type, this constraint is defined numerically as having a target of 30% to 50% of the new power development options being hydro options. This implies that some of the best-evaluated options will be replaced by some of the other options. In this context it has to be noted that new indigenous generation options in Uganda are primarily hydroelectric, while they are mostly thermal in Kenya. In addition, any major SSEA III - Final Report L-10 017334-001-00 Appendix L - Development of Portfolios investment in coal or gas fired thermal plant would have to be on the coast in Kenya or Tanzania. For practical purposes the selection of power development options was carried out using a target in 2020 of having the proportion of new hydroelectric power development options being between 33 and 50% of the total new generation. To the extent practical this objective was applied during the 2005-2020 sequence. Power development approach: Regional Cooperation Strategy to develop power option portfolios: Geographic Diversification Load growth scenario: Medium Portfolio: 2Db For this strategy, the criterion used to define the portfolio was that it needed to provide as much security of supply to each country as could be reasonably possible given the availability of resources even at the expense of using options with some environmental, social or risk concerns. For practical purposes, the selection of power development options was carried out using a target in 2020 of having the proportion of new power development options in each country similar to the share of the load in 2020 of each country. Thus, if 20% of the regional load in 2020 were in Uganda, the target installations of new power development options in Uganda from 2005 to 2020 would also be 20%. This target could not always be achieved because of the scarcity of attractive resources in some of the countries. In addition, this target was applied to the period as a whole only and not year-by-year. 3.2 Sensitivity to load growth Power development approach: Regional Cooperation Load growth scenario: High Strategy to develop power option Strategy to develop power option portfolios: portfolios: Technological Diversification Geographic Diversification Portfolio: 2Cc Portfolio: 2Dc Because all of the "Best-evaluated" options would be used up under the medium load growth scenario, it would be redundant to derive a portfolio for the strategy of using best evaluated options under the high load growth scenario. Thus only Strategies technological and geographic diversification are considered under the high load growth scenario. Power development approach: Regional Cooperation Load growth scenario: Transformation Strategy to develop power option portfolios: Not Applicable Portfolio: 2d Because all of the identified resources in the region would need to be used (plus additional, as yet unidentified resources), to meet the load implied by the transformation scenario, it would be redundant to derive portfolios for the individual strategies being examined. Thus, SSEA III - Final Report L-11 017334-001-00 Appendix L - Development of Portfolios only one portfolio of development is considered under the transformation load growth scenario. 3.3 Other Sensitivity Analyses Many power development options have been dropped from the analysis because of lack of sufficient data to permit them to be analyzed on a consistent basis with other, more thoroughly studied options. This runs the risk that an option that would be attractive if studied further may have been discarded from the analysis. To assess the possible impact of this having occurred, a first sensitivity analysis was carried out using the condition that the screening criterion for level of readiness of study was ignored (thus all options only at the reconnaissance level and that met the other criteria are considered). A second sensitivity test was carried out in which the impact of imports of power from outside the region was considered. A third sensitivity analysis looks at the impact of taking account of the environmental, socio- economic and risk issues. In this sensitivity, the options were selected based on the results of the screening carried out in Chapter 7 but were NOT subjected to the comparative analysis based on environmental, social and risk aspects. Power development approach: Regional Cooperation Load growth scenario: Medium Strategy to develop power option portfolios: Technological Diversification Sensitivity to a limited Sensitivity to allowing Sensitivity to eliminating level of readiness imports the comparative analysis of options Portfolio: 2Cb(S1) Portfolio: 2Cb(S2) Portfolio: 2Cb(S3) As these are sensitivity analyses, it is expected that the impact would be the same regardless of which development strategy or which load growth scenario is selected. For this reason, only the medium load growth scenario applied to the technological diversification strategy is examined. 4 Option Selection and Ordering The portfolios are built up from a candidate list that reflects the core strategy for the portfolio. However there are three key criteria that affect option selection and ordering: · Results from the comparative analyses (to assess social, environmental and risk factors ­ Chapter 9); · Earliest on power date (Chapter 6); · Generation cost (estimated cost of firm energy is used as an indicator ­ Chapter 7); · Option size. 4.1 Social, Environmental and Risk Factors The comparative analysis of social, environmental and risk factors provided in Chapter 9 of the main report separated the new power options into two groups or classes ­ "best evaluated" and "other options" (Table L-1 above). For all portfolios the best evaluated SSEA III - Final Report L-12 017334-001-00 Appendix L - Development of Portfolios options were taken up first, within any constraints imposed in the strategy design (e.g. technological diversification) 4.2 Earliest On-Power The earliest on power dates shown in Table L-4 overleaf were based on either: · The minimum lead times provided in the EAPMP for EAC options, or the estimated minimum lead times that would result from the criteria shown in Chapter 6 (the standardized estimate). Where the EAPMP value differed from the standardized estimate, the EAPMP value has been selected. In the case of significant differences (longer minimum lead times suggested in the EAPMP), these are usually associated with options that involved complex development issues, such as development in a national park. · Standardized estimates shown in Table L-4 have been used for all options outside of the EAC. On power dates were obtained by adding the lead time to January 2006. Thus estimated on- power dates are in January of the year. 4.3 Generation Cost With availability established, based on earliest on-power dates, the cost of generation becomes the key indictor. For this purpose the cost of firm energy was used. 4.4 Option Size Option size was also a factor in option selection. The build up of the portfolios attempted to approximately match supply with demand (plus reserve). Thus in some cases a large option such as Ruhudji (358 MW) was delayed by 1-2 years in favour of a smaller but slightly less cost effective option. The ordering and availability of new power options which passed the screening analysis are shown in Table L-5. It may be noted that this table includes a series of options with insufficient level of preparation, because these were considered in one of the sensitivity tests. SSEA III - Final Report L-13 017334-001-00 Appendix L - Development of Portfolios Table L-4 - NELSAP Region ­ Combined List of Hydro Options ­ Earliest On-Power Dates Name Installed Average Firm Energy Cost per Status Standard EAPMP Selected On-power Total Cost Capacity Energy Energy unit cost kW lead time - lead time - date $million (MW) (GWh) (GWH) c/kWh $/kW years years Babeba I 122.40 50 351 351 3.89 2448 DRC reconnaissance 7 7 2013 Bangamisa 123.47 48 420 420 3.28 2572 DRC reconnaissance 7 7 2013 Budana 12.72 13 70 70 2.08 979 DRC reconnaissance 7 7 2013 Bujagai 5 30.54 50 222 14 1.62 611 Uganda feasibility 5 3 7 2013 Bujagali 1-4 495.33 200 1703 1390 3.25 2477 Uganda feas/design 7 6 6 2012 Bujagali total 1-5 525.87 250 1925 1404 3.06 2103 Uganda fesibility 7 7 2013 Busanga 323.95 224 1304 1304 2.81 1446 DRC reconnaissance 10 10 2016 Ewaso Ngiro 492.55 220 609 448 9.04 2239 Kenya design 7 7 7 2013 Igamba Falls (Stage 2)* 15.44 8 65 56 2.67 1930 Tanzania prefeasibility 6 6 2012 Igamba Falls 980 m 544.80 80 494 464 12.17 6810 Tanzania reconnaissance 9 9 2015 Igamba Falls FSL 865 m 41.74 11 87 87 5.32 3661 Tanzania reconnaissance 7 7 2013 Jiji 03 48.82 16 40 33 13.57 3149 Burundi prefeasibility 6 6 2012 Kabu 16 44.35 20 112 67 4.43 2218 Burundi feasibility 6 6 2012 Kaganuzi A 61.37 34 98 98 7.04 1805 Burundi reconnaissance 7 7 2013 Kaganuzi Complex 162.11 39 184 171 9.76 4136 Burundi feasibility 6 6 2012 Kakono (High) 85.80 53 300 126 3.22 1619 Tanzania prefeasibility 6 6 2012 Kamanyola 517.79 390 1880 1880 3.12 1328 DRC reconnaissance 10 10 2016 Karuma 544.44 200 1747 1619 3.47 2722 Uganda feasibility 8 8 8 2014 Kiliba 39.06 15 65 65 6.70 2604 DRC reconnaissance 7 7 2013 Kishanda 260.67 207 1087 500 2.72 1259 Tanzania prefeasibility 9 9 2015 Kitete 200.52 21 153 153 14.43 9549 DRC reconnaissance 7 7 2013 Kiymbi (Bengamisa II) 52.06 43 377 377 1.57 1211 DRC reconnaissance 7 7 2013 Low Grand Falls 455.18 140 715 324 7.07 3251 Kenya feasibility 7 9 9 2015 Luiche 89.55 15 100 69 9.89 5853 Tanzania reconnaissance 7 7 2013 Magwagwa 382.99 120 668 244 6.37 3192 Kenya feasibility 7 7 2013 Mandera 50.10 21 149 109 3.76 2386 Tanzania feasibility 6 6 2012 Masigira 190.24 118 695 528 3.08 1612 Tanzania prefeasibility 8 7 7 2013 Masindi - 2 1088.16 360 2302 1798 5.26 3023 Uganda prefeasibility 9 14 14 2020 Masindi -1 1347.14 360 3016 2615 4.95 3742 Uganda prefeasibility 9 14 14 2020 Mpanda 51.48 10 40 40 14.23 4950 Burundi feasibiility 6 6 2012 Mpanga 232.44 144 1028 863 2.55 1614 Tanzania prefeasibility 8 8 8 2014 Mugomba 87.63 40 160 160 6.13 2191 DRC reconnaissance 7 7 2013 Muhuma 71.69 25 100 100 7.98 2868 DRC reconnaissance 7 7 2013 Mule 34 38.17 17 54 39 7.90 2314 Burundi prefeasibility 6 6 2012 Mutonga 229.44 60 328 293 7.76 3824 Kenya feasibility 6 7 7 2013 Mwana ngoye 403.65 46 336 336 13.23 8775 DRC reconnaissance 7 7 2013 Nyabarongo 111.92 28 142 80 8.73 4026 Rwanda feasibility 6 6 2012 Nzilo II 111.98 33 720 720 1.73 3393 DRC reconnaissance 7 7 2013 Panzi 136.72 36 175 175 8.66 3798 DRC reconnaissance 7 7 2013 Piana Mwanga 40.49 38 193 193 2.40 1065 DRC reconnaissance 7 7 2013 Portes d´enfer 346.35 36 263 263 14.50 9621 DRC reconnaissance 7 7 2013 Ruhudji 486.84 358 1930 1476 2.86 1360 Tanzania feasibility 8 8 8 2014 Rumakali 450.63 222 1141 1170 4.43 2030 Tanzania feasibiility 8 10 10 2016 Rusumo Falls (Full) 113.52 62 403 308 3.16 1846 Tan/Rw feasibility 6 6 2012 Ruzizi 318.64 270 1300 1300 2.79 1180 DRC reconnaissance 10 10 2016 Ruzizi III 105.17 82 418 418 2.86 1283 Rw/DRC prefeasibility 8 8 2014 Semliki 95.59 28 120 120 8.85 3414 DRC reconnaissance 7 7 2013 Siguvyaye 420.06 90 510 486 9.11 4667 Burundi feas/design 7 7 2013 Sisi 405.93 174 883 883 5.14 2333 DRC reconnaissance 10 10 2016 Songwe 407.60 330 1352 1352 3.43 1235 Tan/Mal prefeasibility 9 9 2015 Upper Kinansi 98.13 0 124 11 8.67 Tanzania prefeasibility 7 6 7 2013 Wagenia I 411.46 50 400 400 11.33 8229 DRC reconnaissance 7 7 2013 Wanie Rukula 1457.76 688 6000 6000 2.72 2119 DRC reconnaissance 10 10 2016 SSEA III - Final Report L-14 017334-001-00 Appendix L - Development of Portfolios Table L-5 - NELSAP region ­ Integrated Ranking of Screened Options with Earliest On-Power Dates Name Country Installed Energy Generation Cost Earliest Total Cost Capacity AV FIRM Average Firm installat-ion 2008 2009 2010 2011 2012 2013 2014 2015 $ million (MW) (GWh) (GWH) c/kWh c/kWh $/kW date Kiymbi/Bendera II DRC 43 377 377 1.57 1.57 1211 2013 43 Budana DRC 13 70 70 2.08 2.08 979 2013 13 Piana Mwanga DRC 38 193 193 2.40 2.40 1065 2013 38 Ruzizi III Rwanda-DRC 105.17 82 418 418 2.86 2.86 1283 2014 82 Mpanga Tanzania 232.44 144 1028 863 2.55 3.03 1614 2014 144 Bangamisa DRC 48 420 420 3.28 3.28 2572 2013 48 Songwe Tanz/Malawi 407.60 330 1352 1352 3.43 3.43 1235 2015 330 Ruhudji Tanzania 486.84 358 1930 1476 2.86 3.74 1360 2014 358 Karuma Uganda 544.44 200 1747 1619 3.47 3.74 2722 2014 200 GT 60 MW- gas - generic x 4 units Tanzania 240 1682 1682 3.84 3.84 591 2008 240 Babeba I DRC 50 351 351 3.89 3.89 2448 2013 50 Masigira Tanzania 190.24 118 695 528 3.08 4.06 1612 2013 118 Rusumo Falls (Full) Tanzania W-Rwanda 113.52 62 403 308 3.16 4.14 1846 2012 62 Bujagali total Uganda 525.87 250 1925 1390 3.06 4.24 2103 2012 200 50 Rumakali Tanzania 450.63 222 1141 1170 4.43 4.32 2030 2016 Longonot Geothermal Kenya 70 491 491 5.05 5.05 2352 2010 70 Suswa Geothermal Kenya 70 491 491 5.05 5.05 2352 2012 70 Menengai Geothermal Kenya 140 981 981 5.05 5.05 2352 2015 140 CC 60 MW - gas /steam cycle x 2 units Tanzania 120 841 841 5.13 5.13 1532 2008 120 Sisi 3 Rwanda-DRC 174 883 883 5.14 5.14 2333 2013 174 Igamba Falls FSL 865 m Tanzania W 11 87 87 5.32 5.32 3661 2013 11 Olkaria ext - Geothermal Kenya 35 245 245 5.62 5.62 2645 2009 35 Kivu methane engines 30 MW x 4 units Rwanda/DRC 120 841 841 6.11 6.11 2505 2007 120 Mugomba DRC 40 160 160 6.13 6.13 2191 2013 40 Mchuchuma - Coal steam 4 x 100 MW Tanzania 400 2803 2803 6.50 6.50 1909 2012 400 Kiliba DRC 15 65 65 6.70 6.70 2604 2013 15 Mombasa - Coal steam-2 units Kenya 300 2102 2102 6.88 6.88 1678 2012 300 Mombasa - Gas/LNG steam (4$/GJ) -2units Kenya 300 2102 2102 7.39 7.39 895 2015 300 Kabu 16 Burundi 44.35 20 112 67 4.43 7.40 2218 2012 20 Kakono (High) Tanzania W. 85.80 53 300 126 3.22 7.67 1619 2012 53 Muhuma DRC 25 100 100 7.98 7.98 2868 2013 25 Wind energy conversion systems generic 30 63 63 8.33 8.33 Panzi Rwanda-DRC 36 175 175 8.66 8.66 3798 2013 36 GT 60 MW- gas - generic x 2 units Kenya 120 841 841 3.84 3.84 591 2008 120 Mutonga Kenya 229.44 60 328 293 7.76 8.68 3824 2012 60 Semliki DRC 28 120 120 8.85 8.85 3414 2013 28 Upper Kinansi (storage) Tanzania 98.13 0 124 11 8.67 N/A 2014 0 Not sufficiently prepared - considered in plan 2 BP only thermal units costs at CF 75% Not "best evaluated" Imports and interconnections not shown Projects on the Ruzizi river have been developed under sgreements between DRC-Rwanda-Burundi SSEA III - Final Report L-15 017334-001-00 Appendix L - Development of Portfolios 5 Independent Approach, Primarily National Options and Base Load Growth Scenario ­ Portfolio 1Aa In order to identify potential environmental and social impacts of the three strategies reflecting integrated development, it was necessary to develop a representative portfolio, for each country, for the period to the year 2020 under the independent development approach. The portfolio reflecting this reference strategy was developed under the following rules or criteria: · Load growth in each country and collectively for the region would be expected to be lower than for the NELSAP plan based on medium load growth scenario, because of electricity shortages (resulting in suppressed demand), and more expensive electricity (use of smaller less economic options). For the purpose of developing a power development portfolio, the low load growth scenario described in Chapter 5 were used. · Transmission interconnections were assumed to be limited to present interchange capability. Thus potential transfers would be limited to those presently taking place between Uganda and Kenya, and for the sharing of the Ruzizi 1 and 2 generation. · Rwanda, Eastern DRC and Burundi were treated as a single load to reflect the relatively small size of these loads and the existing generation sharing between Rwanda and Eastern DRC. It was assumed that West Tanzania would remain separate from the main Tanzania grid. One third of the generation from Rusumo would be provided to West Tanzania. · No power development options in excess of 150 MW (for any single stage of development) were considered. It has to be recognized that any such option would have a total capital cost in the order of $300 million US. It is assumed for this strategy that investment conditions would not be adequate for larger options. This approximates the larger sizes of plant that have been commissioned in the past in the three larger load areas. · Power development options would be scheduled to meet national loads only. Table L-6 presents the portfolios for each of the sub-regions considered. Some of the features of the portfolios are: · In Kenya, all the known geothermal resources would be used, then medium speed diesels using fuel oil would be needed; · In Uganda, medium speed diesel units would be used until Bujagali could be commissioned; · In Tanzania the natural gas that is available offshore would be used in gas turbines as required; · For Burundi, Eastern DRC and Rwanda most of the additions would be medium speed diesels, some fuelled with fuel oil and others with methane from Lake Kivu. In addition, one hydro plant in Eastern DRC would be built: Kisala Ivugu. It is also assumed that Rusumo Falls would be built, even though it is a regional option. The rationale for this is that commitments have already been made for this option and it would be illogical to ignore this. Ruzizi III is also included. SSEA III - Final Report L-17 017334-001-00 Appendix L - Development of Portfolios 6 Portfolios Based on the Medium Load Growth Scenario 6.1 Regional Approach, Best Evaluated Options and Medium Load Growth Scenario ­ Portfolio 2Bb This portfolio illustrated in Table L-7 respects the preference for scheduling best evaluated options, however does not seek to achieve technological or geographic diversification. All options selected are "best evaluated" except as noted. The program to the end of 2008 is common to all portfolios. The options available in 2009 are the last two Tanzania GTs fired by Songo Songo gas. Addition of these units raises the Tanzania gas generation to 320 MW (2 x 40 MW + 4 x 60 MW). A further 2 x 60 MW will be added (2009 and 2010) with the addition of the 2 x 60 MW steam cycle units for the combined cycle plants, for a total of 440 MW of gas fired generation. These options also carry some social / environmental risk. This scheduling agrees with the EAPMP recommended plan. For 2010 the least cost available options are Longonot geothermal in Kenya, Kivu gas engines, and the last 60 MW steam cycle unit for upgrading to a further 180 MW combined cycle unit in Tanzania. Consequently the additions are Longonot geothermal (70 MW), Unit No. 2 at Kivu, and a 60 MW combined cycle steam unit. Total capacity remains high however this does not fully replace existing oil fired generation. In 2011 there are no new generation options, consequently the demand increase is met by adding Unit 3 at Kivu, and a 60 MW oil fired GT in Kenya. In 2012 the least cost unused generation options are Bujagali (1-4) and Rusumo. It is assumed that the 5th unit at Bujagali would be added 1-2 years later. The next "best evaluated" option available for 2012 in terms of cost would be Suswa geothermal. In 2013 the Masigira hydro option could be available, however as it is not best evaluated, it is not selected. The next best option is the Suswa geothermal 70 MW plant. Further generation to meet the demand would come from Kabu 16 (20 MW) and Kakono (53 MW), both of which have an earliest on-power date of 2012. By 2014 Ruzizi III (82 MW), which is the least cost "best evaluated" available option and the large Ruhudji (358 MW) and Karuma (200 MW) "best evaluated" hydro options could be available. However the demand can be met by adding Ruzizi III, and a further 60 MW oil fired GT (Kenya). The Bujagali 5th unit would also be added. In 2015 the Ruhudji (358 MW) hydro option in Tanzania, as the least cost available option, would be scheduled to meet the load increase. In 2016 the Karuma (200 MW) hydro option in Uganda, as the least cost available option, would be scheduled to meet the load increase. SSEA III - Final Report L-18 017334-001-00 Appendix L - Development of Portfolios Table L-6 - Sub-Regional Portfolios Kenya Uganda Tanzania Burundi, DRC, Rwanda Year Name Type/Fuel Capacity Name Type/Fuel Capacity Name Type/Fuel CapacityName Type/Fuel Capacity 2005 Existing 1120 Existing 417 Existing 700 Existing 167 2006 Diesel Fuel Oil 20 2007 Diesel Fuel Oil 20 Diesel Methane 30 2008 Olkaria 2 Geothermal 35 Diesel 20 Diesel Methane 30 2009 Longonot Geothermal 70 Diesel 20 Gas Turbine Natural Gas 60 Kisala Ivugu Hydro 13 Gas Turbine Natural Gas 60 20 2010 Diesel 2011 Gas Turbine Natural Gas 60 2012 Gas Turbine Natural Gas 60 Rusumo 2/3 Hydro 41 2013 Suswa Geothermal 70 Bujagali Hydro 200* Diesel Methane 30 2014 Gas Turbine Natural Gas 60 Diesel Methane 30 2015 Menengai Geothermal 140 Ruzizi III Hydro 82 2016 2017 Diesel Fuel oil 20 Gas Turbine Natural Gas 60 Diesel Fuel Oil 40 2018 Diesel Fuel oil 40 Diesel Fuel Oil 40 2019 Diesel Fuel oil 40 Gas Turbine Natural Gas 60 Diesel Fuel Oil 60 2020 Diesel Fuel oil 40 Diesel Fuel Oil 60 * Recent information (December 2006) suggests that the option may be developed in one stage only of 5 X 50 MW; in the independent development approach, that amount of capacity is not required for the period of analysis. SSEA III - Final Report L-19 017334-001-00 Appendix L - Development of Portfolios In 2017 the Rumakali (222 MW) hydro option in Tanzania, as the least cost available option, would be scheduled to meet the load increase. By 2018 the only remaining "best evaluated" options in order of cost effectiveness (firm energy unit cost) are Menengai geothermal, the last Kivu engine, Mutonga and wind energy conversion. The load increase is met by Menengai (70 MW), Unit 4 at Kivu and a non- selected or generic 2 x 70 MW geothermal plant. This assumes that further geothermal will be developed in Kenya or Uganda. The EAPMP refers to three further identified sites in Kenya (Ol Banita, Arus and Bogoria) that were not included in the EAC plan. Table L-7 ­ Portfolio 2Bb ­ Expansion Plan ­ Best Evaluated Options Strategy ­ Medium Load Growth Scenario Addition Total Supply Demadn Surplus/Deficit Energy Year Plant/Option Type Fuel Country MW GWH MW GWH MW GWH MW GWH Capacity reserve Firm Firm reserve % % 2004 All existing EAPMP + SSEA + DRC 2421 12129 1878 10642 29 14 2005 Kiira Units 14-15 Hydro Uganda 80 39 2501 12168 GT GT Gas Tanzania 40 280 2541 12448 1976 11244 565 1204 29 11 2006 Kiambere extension Hydro Kenya 20 0 2561 12448 GT GT Gas Tanzania 40 280 2601 12729 Diesel 3 x 10 Diesel No 2 B/R/WT 30 210 2631 12939 2097 11930 534 1009 25 8 2007 GT GT Gas Tanzania 60 420 2691 13359 Diesel 1 x 10 Diesel No 2 Burundi 10 70 2701 13429 2225 12674 476 755 21 6 2008 Sondu Miriu Hydro Kenya 60 292 2761 13721 Olkaria II Geo Kenya 35 491 2796 14212 GT GT Gas Tanzania 60 420 2856 14633 Diesel 1 x 10 Diesel No. 2 Rwanda 10 70 2866 14703 Kivu engine No. 1 Engine Methane R/DRC 30 210 2896 14913 2362 13464 534 1449 23 11 2009 GT GT Gas Tanzania 60 420 2956 15334 GT GT Gas Tanzania 60 420 3016 15754 Combined cycle steam unit CC Gas Tanzania 60 420 3076 16175 Diesel 1 x 10 Diesel No. 2 Tanzania 10 70 3086 16245 2506 14284 580 1961 23 14 2010 Geothermal GEO Kenya 70 491 3156 16735 Kivu engine No. 2 Engine Methane R/DRC 30 210 3186 16946 Combined cycle steam unit CC Gas Tanzania 60 420 3246 17366 2659 15156 587 2210 22 15 2011 Kivu engine No. 3 Engine Methane R/DRC 30 210 3276 17576 GT Diesel No 2 Kenya 60 420 3336 17997 2812 16024 524 1973 19 12 2012 Bujagali 1-4 Hydro Uganda 200 1390 3536 19387 Rusumo Hydro R/DRC 62 308 3598 19695 2974 16947 624 2748 21 16 2013 Geothermal Suswa GEO Kenya 70 491 3668 20185 Kabu 16 Hydro Burundi 20 67 3688 20252 Kakono Hydro Tanzania 53 126 3741 20378 3162 17927 579 2451 18 14 2014 Bujagali Unit 5 Hydro Uganda 50 14 3791 20392 GT Diesel No 2 Kenya 60 420 3851 20813 Ruzizi III Hydro R/DRC 82 418 3933 21231 3348 18970 585 2261 17 12 2015 Ruhudji Hydro Tanzania 358 1476 4291 22707 3544 20079 747 2628 21 13 2016 Karuma Hydro Uganda 200 1619 4491 24326 3752 21254 739 3072 20 14 2017 Rumakali Hydro Tanzania 222 1170 4713 25496 3974 22506 739 2990 19 13 2018 Menengai Geothermal GEO Kenya 140 981 4853 26477 Kivu engine No. 4 Engine Methane R/DRC 30 210 4883 26687 Geothermal 2 x 70 GEO Kenya 140 981 5023 27668 4211 23839 812 3829 19 16 2019 Songwe Hydro Tanzania 330 1352 5353 29020 4462 25256 891 3764 20 15 2020 Mutonga Hydro Kenya 60 293 5413 29313 Wind Wind Kenya 60 126 5473 29439 Mombasa 1 Coal Kenya 150 1051 5623 30490 4731 26770 892 3720 19 14 SSEA 2 TOTAL ADDITIONS 2004-2020 3202 18361 2853 16128 EAPMP TOTAL ADDITIONS 2004-2020 2302 14338 2354 14120 GT burning gas assumed as maximum PF % 80 Combined cycle burning gas max PF % 80 Technology and geographic diversification Evaluation quotient MW % MW %Supply % Load MW % Hydro 1797 56.1% Burundi 40 1.2% 3 Geotherma 455 14.2% DRC 132 4.1% 2 Best evaluated 2722 85 Gas 440 13.7% Kenya 925 28.9% 43 Other 480 15 Coal 150 4.7% Rwanda 152 4.7% 3 3202 100 Fuel 180 5.6% Tanzania 1423 44.4% 29 Methane 120 3.7% Uganda 530 16.6% 20 Wind 60 1.9% Imports 0 0.0% Imports 0 0.0% 3202 100.0% 3202 100.0% In 2019 the Songwe (330 MW) hydro/multipurpose option in Tanzania/Malawi has been scheduled. It should also be noted that the firm energy capability of the Songwe option is not clearly defined. With an annual demand increment of 300 MW, the best evaluated Mutonga and wind energy conversion plants would be inadequate, and thus they are delayed to 2020. SSEA III - Final Report L-21 017334-001-00 Appendix L - Development of Portfolios For 2020 the increase in load, including reserve, is 320 MW. This would be met by the Mutonga (60 MW) hydro plant in Kenya, and an assumed 60 MW (2 projects) of wind generation in Kenya. The only other identified option is to build the first of a series of 150 MW coal fired steam units at Mombasa. In summary this plan would add the following: Group Total MW 2005 to 2008 475 2009-2020 Best evaluated options 2,247 2009-2020 Other options 480 Total additions 3,202 Total hydro additions 2005-2020 56.1% However by ignoring constraints such as technological or geographic diversity, this portfolio results in a significant over installation in Tanzania, due to low cost gas and hydro, and under-installation in Kenya which is thermal dependant. Country % of total region load in % of total new generation 2020 2005-2020 Burundi 3 1 DRC (East) 2 4 Kenya 43 29 Rwanda 3 5 Tanzania 29 44 Uganda 20 17 6.2 Regional Approach, Technological Diversification and Medium Load Growth Scenario ­ Portfolio 2Cb The overall concept of this portfolio illustrated in Table L-8 is to provide a modified plan that would respect a desired technological diversification program, even if this means increasing overall environmental and social impacts as well as system capital and operating costs. In global terms the objective is to use best evaluated options in order of cost effectiveness, as in Portfolio 2Bb, however to make adjustments to ensure that the hydro component remains appreciably below 50%. This is to provide a measure of robustness to counter possible impacts from a long term dry period in the region. For this purpose, a target range for the hydro component has been set at 33 to 50%. The resulting costs of this portfolio indicate the premium or additional cost that would result from imposing a technological diversification constraint, to provide possibly more secure future electricity supplies for the long term. All options selected are "best evaluated" except as noted. In effect the priority criterion is environmental/social acceptability followed by cost but with the strategy criterion providing an overriding cutoff. The program to the end of 2008 is common to all portfolios. SSEA III - Final Report L-22 017334-001-00 Appendix L - Development of Portfolios Table L-8 ­ Portfolio 2Cb ­ Expansion Plan ­ Technological Diversification ­ Medium Load Growth Scenario Addition Total Supply Demand Surplus/Deficit Energy Year Plant/Option Type Fuel Country MW GWH MW GWH MW GWH MW GWH Capacity reserve Firm Firm reserve % % 2004 All existing EAPMP + SSEA + DRC 2421 12129 1878 10642 29 14 2005 Kiira Units 14-15 Hydro Uganda 80 39 2501 12168 GT GT Gas Tanzania 40 280 2541 12448 1976 11244 565 1204 29 11 2006 Kiambere extension Hydro Kenya 20 0 2561 12448 GT GT Gas Tanzania 40 280 2601 12729 Diesel 3 x 10 Diesel No 2 B/R/WT 30 210 2631 12939 2097 11930 534 1009 25 8 2007 GT GT Gas Tanzania 60 420 2691 13359 Diesel 1 x 10 Diesel No 2 Burundi 10 70 2701 13429 2225 12674 476 755 21 6 2008 Sondu Miriu Hydro Kenya 60 292 2761 13721 Olkaria II Geo Kenya 35 491 2796 14212 GT GT Gas Tanzania 60 420 2856 14633 Diesel 1 x 10 Diesel No. 2 Rwanda 10 70 2866 14703 Kivu engine No. 1 Engine Methane R/DRC 30 210 2896 14913 2362 13464 534 1449 23 11 2009 GT GT Gas Tanzania 60 420 2956 15334 GT GT Gas Tanzania 60 420 3016 15754 Combined cycle steam unit CC Gas Tanzania 60 420 3076 16175 Diesel 1 x 10 Diesel No. 2 Tanzania 10 70 3086 16245 2506 14284 580 1961 23 14 2010 Geothermal GEO Kenya 70 491 3156 16735 Kivu engine No. 2 Engine Methane R/DRC 30 210 3186 16946 Combined cycle steam unit CC Gas Tanzania 60 420 3246 17366 2659 15156 587 2210 22 15 2011 Kivu engine No. 3 Engine Methane R/DRC 30 210 3276 17576 GT Diesel No 2 Kenya 60 420 3336 17997 2812 16024 524 1973 19 12 2012 Bujagali 1-4 Hydro Uganda 200 1390 3536 19387 Rusumo Hydro R/DRC 62 308 3598 19695 2974 16947 624 2748 21 16 2013 Geothermal Suswa GEO Kenya 70 491 3668 20185 Kabu 16 Hydro Burundi 20 67 3688 20252 Kakono Hydro Tanzania 53 126 3741 20378 3162 17927 579 2451 18 14 2014 Bujagali Unit 5 Hydro Uganda 50 14 3791 20392 Ruzizi III Hydro R/DRC 82 418 3873 20810 GT Diesel No 2 Kenya 60 420 3933 21231 3348 18970 585 2261 17 12 2015 Ruhudji Hydro Tanzania 358 1476 4291 22707 3544 20079 747 2628 21 13 2016 Menengai Geothermal GEO Kenya 140 981 4431 23688 3752 21254 679 2434 18 11 2017 Kivu engine No. 4 Engine Methane R/DRC 30 210 4461 23898 Geothermal 2 x 70 GEO Kenya 140 981 4601 24879 Karuma Hydro Uganda 200 1619 4801 26498 3974 22506 827 3992 21 18 2018 Wind Wind Kenya 60 126 4861 26624 Mombasa 1 Coal Kenya 150 1051 5011 27675 4211 23839 800 3836 19 16 2019 Mombasa 2 Coal Kenya 150 1051 5161 28727 4462 25256 699 3471 16 14 2020 Rumakali Hydro Tanzania 222 1170 5383 29897 Mchuchuma Coal Coal Tanzania 200 1402 5583 31298 Mombasa 3 Coal Kenya 150 1051 5733 32349 4731 26770 1002 5579 21 21 SSEA 2 TOTAL ADDITIONS 2004-2020 3312 20220 2853 16128 EAPMP TOTAL ADDITIONS 2004-2020 2302 14338 2354 14120 GT burning gas assumed as maximum PF % 80 Combined cycle burning gas max PF % 80 Technology and geographic diversification Evaluation quotient MW % MW %Supply % Load MW % Hydro 1407 42.5% Burundi 40 1.2% 3 Geotherma 455 13.7% DRC 132 4.0% 2 Best evaluated 2662 80 Gas 440 13.3% Kenya 1165 35.2% 43 Other 650 20 Coal 650 19.6% Rwanda 152 4.6% 3 3312 100 Fuel 180 5.4% Tanzania 1293 39.0% 29 Methane 120 3.6% Uganda 530 16.0% 20 Wind 60 1.8% Imports 0 0.0% Imports 0 0.0% 3312 100.0% 3312 100.0% Plant scheduling is the same as for Portfolio 2Bb up to 2015. This is because option selection is based on availability (as a function of earliest on-power date) and lowest generation cost. During the period 2009 to 2015 the hydro proportion of new plant is mostly lower than target, dropping to 19% by 2011, and only increases to 36% in 2012 with the addition of Bujagali and Rusumo. However it should be noted that no other hydro options are available. By 2012, in addition to Bujagali and Rusumo, the relatively more expensive Kabu 16 and Kakono sites could be brought on power, and these are scheduled for 2013, together with the lower cost Suswa geothermal option. By 2014 the proposed Ruzizi III option (82 MW), and the Ruhudji (358 MW) and Karuma (200 MW) options could be commissioned. However as for Portfolio 2Bb the demand in 2014 is met by the Ruzizi option, together with a further 60 MW GT, and the Bujagali unit 5. This avoids over installation, and limits the new hydro component in 2014 to 41%. Following the addition of Ruhidji in 2015, the hydro proportion rises to 53%. SSEA III - Final Report L-23 017334-001-00 Appendix L - Development of Portfolios In 2016 the technological diversification plan departs from the Portfolio 2Bb, by adding the Menengai 140 MW geothermal plant, instead of Karuma hydro, although the Karuma generation is nearly 30% cheaper. Menengai is the least cost remaining available thermal option. However the portfolio up to 2016 only uses "best evaluated" options. In 2017 the demand increase is met by thermal; Kivu engines, a non-selected geothermal plant, and the first two units at Mchuchuma. These are the least cost available thermal options. The proportion of new hydro since 2005 is now reduced to 41%. Additions in 2019 and 2020 are approximately 50% hydro, with the addition of Karuma 200 MW in 2019, and Rumakali 222 MW in 2020, and the addition of units 3 and 4 at Mchuchuma in 2018, and two 150 MW coal fired thermal units at Mombasa in 2020. The alternative to the thermal plants would be the lower cost Songwe option, which carries environmental risks. However this would increase the hydro proportion to above the target. In summary this plan would add the following: Group Total MW 2005 to 2008 475 2009-2020 Best evaluated options 2,187 2009-2020 Other options 650 Total additions 3,312 Total hydro additions 2005-2020 42.5% Although the objective is to target technological diversification, this strategy also results in an improved geographic distribution of new generation, as compared with Portfolio 2Bb. This results from additional thermal generation in Kenya, however which displaces Uganda rather than Tanzania hydro. Country % of total region load % of total new generation in 2020 2005-2020 Burundi 3 1 DRC (East) 2 4 Kenya 43 35 Rwanda 3 5 Tanzania 29 39 Uganda 20 16 6.3 Regional Approach, Geographical Diversification and Medium Load Growth Scenario ­ Portfolio 2Db The overall concept of this portfolio illustrated in Table L-9 is to provide a modified plan that would respect a desired geographical diversification program, even if this means increasing overall environmental and social impacts as well as system capital and operating costs. In global terms the objective is to use best evaluated options in order of cost effectiveness, as in Portfolios 2Bb and 2Cb, however to make adjustments to ensure that the new power additions in each country approximately match the load of that country. SSEA III - Final Report L-24 017334-001-00 Appendix L - Development of Portfolios The resulting costs of this portfolio indicates the premium or additional cost that would result from not integrating and sharing least cost resources on a regional basis. All options selected are "best evaluated" except as noted. The program to the end of 2008 is common to all portfolios. Plant scheduling is the same as for Portfolios 2Bb and 2Cb up to 2009 with additions based on least cost available options. By 2009 the new plant proportion from Tanzania is above the geographic indicator, while Uganda and Kenya are below. Consequently in 2010 the 70 MW Longenot geothermal plant in Kenya is scheduled, followed by the 70 MW Suswa option (note the nominal earliest on-power date for this plant is 2011). Menengai 140 MW geothermal in Kenya is advanced from Portfolio 2Bb to year 2015. Late in the portfolio Rumakali (222 MW), and Mchuchuma (first 200 MW), as proposed in the plan for technological diversification are displaced by Mombasa coal thermal, and Mutonga hydro to improve the load supply balance in Kenya. It may be noted that Mombasa is not in the "best evaluated" category. The installation of 750 MW of coal thermal on the coast would have a negative environmental impact. In summary this plan would add the following: Group Total MW 2005 to 2008 475 2009-2020 Best evaluated options 2,025 2009-2020 Other options 750 Total additions 3,250 Total hydro additions 2005-2020 38.3% By the end of the period (2020) the proportion of new generation from each country, compared with total load would be: Country % of total region load in % of total new generation 2020 2005-2020 Burundi 3 1 DRC (East) 2 4 Kenya 43 37 Rwanda 3 5 Tanzania 29 27 Uganda 20 26 SSEA III - Final Report L-25 017334-001-00 Appendix L - Development of Portfolios Table L-9 ­ Portfolio 2Db ­ Expansion Plan ­ Geographical Diversification ­ Medium Load Growth Scenario SSEA III - Final Report L-26 017334-001-00 Appendix L - Development of Portfolios 7 Modified Portfolios to Meet the High Load Growth Scenario The following two plans were developed to compare option scheduling and systems costs for the two alternative strategies of technological and geographical diversification, based on the high load growth scenario. Option scheduling assumes that options are sufficiently prepared, and load growth trends are established with sufficient lead time that the best available options to meet the load may be selected. The high load growth scenario requires an additional 4200 MW of generation by 2020. Consequently, irrespective of the development strategy, more hydro and/or thermal plants that are not in the "best evaluated" group of options have to be included in the schedule. 7.1 Technical Diversification, Based on High Load Growth Scenario - Portfolio 2Cc The overall concept of this portfolio illustrated in Table L-10 is to provide a plan that would respect a desired technological diversification strategy, even if this means increasing overall environmental and social impacts as well as system capital and operating costs over the least cost plan. As for Portfolio 2Bc, the objective is to use best evaluated options in order of cost effectiveness, however to make adjustments to ensure that the hydro component remains appreciably below 50%. This is to provide a measure of robustness to counter possible impacts from a long term dry period in the region. For this purpose, a target range for the hydro component was set at 33 to 50%. In effect the priority criterion remains environmental/social acceptability followed by cost but the strategy criterion provides an overriding cutoff. Although based on the similar strategy for the medium load growth scenario, this portfolio has to incorporate extensive changes to match the higher loads. Although the plan for the period to the end of 2008 is considered fixed in terms of current commitments and lead times, shortages would result in 2006 and 2007. Additional generation would be required in 2007, for which the only option is assumed to be earlier on-power for three gas turbines in Tanzania using Songo Songo gas, and the combined cycle steam units would have to be commissioned in 2008, in addition to Sondo Miriu and Olkaria II. The only available options for 2009 would be the two oil fired gas turbines in Kenya and advancing the second group of Kivu gas engines. In 2010 the only available options are the next set of Kivu engines and the Longonot geothermal plant. At least 200 MW of additional generation would be required, for which the only options would be low speed diesels and/or imports. Similarly the only options for 2011 are to bring Suswa on line a year earlier than its nominal earliest on-power date, and provide another 200 MW of low speed diesels or imports. With this combination of additions, the hydro proportion in 2010 of new plant additions after 2004 would be 11%, so the strategy target is not a factor in plant selection. In 2012 the Bujagali and Rusumo plants, which are the least cost available options, would be added, and hydro would also meet the 2013 demand increase, however this would have to include the Masigira, which is in the not "best evaluated" group. By 2014 Ruzizi III and Ruhudji would be available. With these additions the new hydro proportion would reach 48%, consequently the next additions have to be non-hydro. Additions in 2015 and 2016 would be non-hydro, however only the Menengai 140 MW geothermal plant and the last set of Kivu engines are available from the "best evaluated" SSEA III - Final Report L-27 017334-001-00 Appendix L - Development of Portfolios group. Karuma would be available in 2016, however is deferred in favour of thermal to respect the strategy criterion. Consequently two units at Mchuchuma are scheduled for 2015 and for 2016. Thus the strategy criterion overrides the preference for use of "best evaluated" options. A non-specified 140 MW geothermal plant and Karuma would be scheduled for 2017, followed by Rumakali and Songwe hydro plants in 2018. The Songwe plant is not best evaluated, however no such plant would be available and it is the least cost available option from the "other" group. Scheduling for 2019 and 2020 would be completed with six 150 MW thermal units at Mombasa, which are not "best evaluated". In summary this plan would add the following: Group Total MW 2005 to 2008 715 2009-2020 Best evaluated options 2,497 2009-2020 Other options 1,748 Total additions 4,960 Total hydro additions 2005-2020 38.6 % With this combination of strategy, and the additional thermal requirements because of the higher demand, the geographical diversification is also reasonable. By the end of the sequence (2020) the proportion of new generation from each country, compared with total load would be: Country % of total region load in % of total new generation 2020 2005-2020 Burundi 4 1 DRC (East) 4 3 Kenya 41 41 Rwanda 4 3 Tanzania 26 39 Uganda 20 11 SSEA III - Final Report L-28 017334-001-00 Appendix L - Development of Portfolios Table L-10 ­ Portfolio 2Cc ­ Technological Diversification, Based on High Load Growth Scenario Addition Total Supply Demand Surplus/Deficit Energy Year Plant/Option Type Fuel Country MW GWH MW GWH MW GWH MW GWH Capacity reserve FIRM FIRM reserve % % 2004 All existing EAPMP + SSEA + DRC 2421 12129 1946 11017 24 10 2005 Kiira Units 14-15 Hydro Uganda 80 39 2501 12168 GT GT Gas Tanzania 40 280 2541 12448 2081 11797 460 651 22 6 2006 Kiambere extension Hydro Kenya 20 0 2561 12448 GT GT Gas Tanzania 40 280 2601 12729 Diesel 3 x 10 Diesel No 2 B/R/WT 30 210 2631 12939 2246 12767 385 172 17 1 2007 GT GT Gas Tanzania 60 420 2691 13359 GT GT Gas Tanzania 60 420 2751 13780 GT GT Gas Tanzania 60 420 2811 14200 GT GT Gas Tanzania 60 420 2871 14621 Diesel 1 x 10 Diesel No 2 Burundi 10 70 2881 14691 2427 13820 454 871 19 6 2008 Sondu Miriu Hydro Kenya 60 292 2941 14983 Olkaria II Geo Kenya 35 491 2976 15474 Combined cycle steam unit CC Gas Tanzania 60 420 3036 15894 Combined cycle steam unit CC Gas Tanzania 60 420 3096 16315 Diesel 1 x 10 Diesel No. 2 Rwanda 10 70 3106 16385 Kivu engine No. 1 Engine Methane R/DRC 30 210 3136 16595 2620 14925 516 1670 20 11 2009 GT Diesel No 2 Kenya 60 420 3196 17016 GT Diesel No 2 Kenya 60 420 3256 17436 Kivu engine No. 2 Engine Methane R/DRC 30 210 3286 17646 Diesel 1 x 10 Diesel No. 2 Tanzania 10 70 3296 17716 2829 16119 467 1597 17 10 2010 Geothermal GEO Kenya 70 491 3366 18207 Kivu engine No. 3 Engine Methane R/DRC 30 210 3396 18417 LSD Diesel No. 6 Kenya 200 1402 3596 19819 3056 17236 540 2583 18 15 2011 LSD Diesel No. 6 Kenya 200 1402 3796 21220 Geothermal Suswa GEO Kenya 70 491 3866 21711 3264 18432 602 3279 18 18 2012 Bujagali 1-4 Hydro Uganda 200 1390 4066 23101 Rusumo Hydro R/DRC 62 308 4128 23409 3488 19770 640 3639 18 18 2013 Kabu 16 Hydro Burundi 20 67 4148 23476 Kakono Hydro Tanzania 53 126 4201 23602 Mutongo Hydro Kenya 60 293 4261 23895 Masigira Hydro Tanzania 118 258 4379 24153 3750 21107 629 3046 17 14 2014 Bujagali Unit 5 Hydro Uganda 50 14 4429 24167 Ruzizi III Hydro R/DRC 82 418 4511 24585 Ruhudji Hydro Tanzania 358 1476 4869 26061 4012 22602 857 3459 21 15 2015 Mchuchuma Coal Coal Tanzania 200 1402 5069 27463 Menengai Geothermal GEO Kenya 140 981 5209 28444 4295 24216 914 4228 21 17 2016 Mchuchuma Coal Coal Tanzania 200 1402 5409 29845 Kivu engine No. 4 Engine Methane R/DRC 30 210 5439 30056 4599 25947 840 4109 18 16 2017 Geothermal 2 x 70 GEO Kenya 140 981 5579 31037 Karuma Hydro Uganda 200 1619 5779 32656 4928 27819 851 4837 17 17 2018 Rumakali Hydro Tanzania 222 1170 6001 33826 Songwe Hydro Tanzania 330 1352 6331 35178 5284 29840 1047 5338 20 18 2019 Mombasa 1 Coal Kenya 150 1051 6481 36229 Mombasa 2 Coal Kenya 150 1051 6631 37280 Mombasa 3 Coal Kenya 150 1051 6781 38331 5669 32024 1112 6307 20 20 2020 Mombasa 4 Coal Kenya 150 1051 6931 39382 Mombasa 5 Coal Kenya 150 1051 7081 40434 Mombasa 6 Coal Kenya 150 1051 7231 41485 6086 34393 1145 7092 19 21 SSEA 2 TOTAL ADDITIONS 2004-2020 4660 28305 4140 23376 EAPMP TOTAL ADDITIONS 2004-2020 2302 14338 2354 14120 GT burning gas assumed as maximum PF % 80 Combined cycle burning gas max PF % 80 Technology and geographic diversification Evaluation quotient MW % MW %Supply % Load MW % Hydro 1915 38.6% Burundi 40 0.8% 4 Geotherma 455 9.2% DRC 132 2.7% 4 Best evaluated 3212 65 Gas 440 8.9% Kenya 2015 40.6% 41 Other 1748 35 Coal 1300 26.2% Rwanda 152 3.1% 4 4960 100 Fuel 580 11.7% Tanzania 1941 39.1% 26 Methane 120 2.4% Uganda 530 10.7% 20 Wind 0 0.0% Imports 150 3.0% Imports 150 3.0% 4960 100.0% 4960 100.0% SSEA III - Final Report L-29 017334-001-00 Appendix L - Development of Portfolios 7.2 Geographical Diversification, Based on High Load Growth Scenario ­ Portfolio 2Dc This portfolio provides an adjustment to the previous strategy plan, in order to closer match the new power additions with country loads, to achieve better geographical diversification. With the high load growth scenario, there are no options to change the geographic distribution of new generation up to the end of 2012, at which time Uganda will be contributing less than its target. During the period 2005-7 new generation is mostly in Tanzania due to the early availability of low cost gas fired gas turbines. In 2013 the best evaluated available options are Kabu 16, Kakono and Mutonga in that order. Further generation would have to be provided by be provided by Masigira, that reasonably matches the load increment, despite its slightly higher cost. In 2014 Ruzizi III and the 5th Bujagali unit would be added, together with Karuma, while the slightly cheaper Ruhudji option to be deferred, to bring the geographic distribution on target for Tanzania and Uganda although below target for Kenya. In 2015 the only available "best evaluated " generation would be Ruhudji (358 MW), Menengai geothermal (140 MW) and the remaining non-specified 140 MW geothermal. Although lower cost, Ruhudji in Tanzania would be deferred in favour of the Kenya geothermal plants. By 2016 Ruhudji could be absorbed, and further generation provided by 200 MW of low speed diesel in Uganda. Rumakali would also be available, however has to be deferred to respect the country targets. Rumakali is scheduled for 2017, followed in 2018 by wind in Kenya, the 4th set of Kivu engines and 200 MW of low speed diesel in Kenya. At this point the Kenya proportion is still below target, and both Tanzania and Uganda are above, so new generation in 2019 and 2020 is provided by Mombasa coal fired thermal (5 x 150 MW), and the Songwe hydro option (330 MW). The result of this strategy is to replace the Mchuchuma plant in Tanzania by diesel in Uganda to maintain geographic diversity. Also Ruhudji would be delayed and Karuma and diesel in Uganda would be used to achieve geographic diversity. By the end of the Portfolio (2020) the proportion of new generation from each country, compared with total load would be: Country % of total region load in % of total new generation 2020 2005-2020 Burundi 4 1 DRC (East) 4 3 Kenya 41 40 Rwanda 4 3 Tanzania 26 33 Uganda 20 20 SSEA III - Final Report L-30 017334-001-00 Appendix L - Development of Portfolios In summary this plan would add the following: Group Total MW 2005 to 2008 715 2009-2020 Best evaluated options 2,407 2009-2020 Other options 1,598 Total additions 4,720 Total hydro additions 2005-2020 50.1% Table L-11 ­ Portfolio 2Dc­ Geographical Diversification, Based on High Load Growth Scenario Addition Total Supply Demand Surplus/Deficit Energy Year Plant Type Fuel Country MW GWH MW GWH MW GWH MW GWH Capacity reserve Firm Firm reserve % % 2004 All existing EAPMP + SSEA + DRC 2421 12129 1946 11017 24 10 2005 Kiira Units 14-15 Hydro Uganda 80 39 2501 12168 GT GT Gas Tanzania 40 280 2541 12448 2081 11797 460 651 22 6 2006 Kiambere extension Hydro Kenya 20 0 2561 12448 GT GT Gas Tanzania 40 280 2601 12729 Diesel 3 x 10 Diesel No 2 B/R/WT 30 210 2631 12939 2246 12767 385 172 17 1 2007 GT GT Gas Tanzania 60 420 2691 13359 GT GT Gas Tanzania 60 420 2751 13780 GT GT Gas Tanzania 60 420 2811 14200 GT GT Gas Tanzania 60 420 2871 14621 Diesel 1 x 10 Diesel No 2 Burundi 10 70 2881 14691 2427 13820 454 871 19 6 2008 Sondu Miriu Hydro Kenya 60 292 2941 14983 Olkaria II Geo Kenya 35 491 2976 15474 Combined cycle steam unit CC Gas Tanzania 60 420 3036 15894 Combined cycle steam unit CC Gas Tanzania 60 420 3096 16315 Diesel 1 x 10 Diesel No. 2 Rwanda 10 70 3106 16385 Kivu engine No. 1 Engine Methane R/DRC 30 210 3136 16595 2620 14925 516 1670 20 11 2009 GT Diesel No 2 Kenya 60 420 3196 17016 GT Diesel No 2 Kenya 60 420 3256 17436 Kivu engine No. 2 Engine Methane R/DRC 30 210 3286 17646 Diesel 1 x 10 Diesel No. 2 Tanzania 10 70 3296 17716 2829 16119 467 1597 17 10 2010 Geothermal GEO Kenya 70 491 3366 18207 Kivu engine No. 3 Engine Methane R/DRC 30 210 3396 18417 LSD Diesel No. 6 Uganda 200 1402 3596 19819 3056 17236 540 2583 18 15 2011 LSD Diesel No. 6 Kenya 200 1402 3796 21220 Geothermal Suswa GEO Kenya 70 491 3866 21711 3264 18432 602 3279 18 18 2012 Bujagali 1-4 Hydro Uganda 200 1390 4066 23101 Rusumo Hydro R/DRC 62 308 4128 23409 3488 19770 640 3639 18 18 2013 Kabu 16 Hydro Burundi 20 67 4148 23476 Kakono Hydro Tanzania 53 126 4201 23602 Mutonga Hydro Kenya 60 293 4261 23895 Masigira Hydro Tanzania 118 258 4379 24153 3750 21107 629 3046 17 14 2014 Bujagali Unit 5 Hydro Uganda 50 14 4429 24167 Ruzizi III Hydro R/DRC 82 418 4511 24585 Karuma Hydro Uganda 200 1619 4711 26204 4012 22602 699 3602 17 16 2015 Menengai Geothermal GEO Kenya 140 981 4851 27185 Geothermal 2 x 70 GEO Kenya 140 981 4991 28166 4295 24216 696 3950 16 16 2016 Ruhudji Hydro Tanzania 358 1476 5349 29642 LSD Diesel No. 6 Uganda 200 1402 5549 31044 4599 25947 950 5097 21 20 2017 Rumakali Hydro Tanzania 222 1170 5771 32214 4928 27819 843 4395 17 16 2018 Kivu engine No. 4 Engine Methane R/DRC 30 210 5801 32424 Wind Wind Kenya 60 126 5861 32550 LSD Diesel No. 6 Kenya 200 1402 6061 33952 5284 29840 777 4112 15 14 2019 Mombasa 1 Coal Kenya 150 1051 6211 35003 Mombasa 2 Coal Kenya 150 1051 6361 36054 Mombasa 3 Coal Kenya 150 1051 6511 37105 5669 32024 842 5081 15 16 2020 Mombasa 4 Coal Kenya 150 1051 6661 38156 Songwe Hydro Tanzania 330 1352 6991 39508 Mombasa 5 Coal Kenya 150 1051 7141 40560 6086 34393 1055 6167 17 18 SSEA 2 TOTAL ADDITIONS 2004-2020 4720 28431 4140 23376 EAPMP TOTAL ADDITIONS 2004-2020 2302 14338 2354 14120 GT burning gas assumed as maximum PF % 80 Combined cycle burning gas max PF % 80 Technology and geographic diversification Evaluation quotient MW % MW %Supply % Load MW % Hydro 1915 40.6% Burundi 40 0.8% 4 Geotherma 455 9.6% DRC 132 2.8% 4 Best evaluated 3122 66 Gas 440 9.3% Kenya 1925 40.8% 41 Other 1598 34 Coal 750 15.9% Rwanda 152 3.2% 4 4720 100 Fuel 980 20.8% Tanzania 1541 32.6% 26 Methane 120 2.5% Uganda 930 19.7% 20 Wind 60 1.3% Imports 0 0.0% Imports 0 0.0% 4720 100.0% 4720 100.0% SSEA III - Final Report L-31 017334-001-00 Appendix L - Development of Portfolios 8 Plan Using all Resources to Meet Transformation Load Growth Scenario ­ Portfolio 2d This portfolio illustrated in Table L-12 is designed to respond to the regional transformation load growth scenario that is described in Section 5.5 of the main report. This scenario provides a very high projected demand by the year 2020, based on acceleration of the regional economies from 2011 onwards. The demand (excluding reserve) in 2020 would be 10,520 MW, requiring the addition of 10,200 MW if the reserve margin of 20% is to be maintained. Since the total generation from "best evaluated" options would be about 3,000 MW, to meet this demand it would be necessary to implement all the "other options" listed in Table L-2 (or Table 8-9 in the main report), as well as a large amount of non-specified generation, nominally represented by coal fired thermal at Mombasa (although LNG fired thermal could equally have been assumed). The ordering of the plants from the "other options" group is based on cost and availability. Given the amount of non-specified generation that would be required to respond to this load scenario, neither the technological or geographic criteria have been taken into account in plant selection. The objective in developing this portfolio is to provide a basis for a very approximate estimate of the total investment requirements for new generation that would be associated with such an economic development scenario. Given the shortage of indigenous generation resources, as compared to the load, no restrictions have been assumed on the selection of plant. Up to the end of 2010 the demands and required / selected new generation are the same as for Portfolio 2Bb. From 2011 onwards with increasing demands the scheduling of new options is accelerated. By 2012 the supply of best evaluated options, available at that date is insufficient, so "other options" including Mchuchuma, Masigira, and the first of a series of coal fired thermal units, are scheduled in 2012 and 2013. In all cases option selection is based on firm energy cost and earliest on power date. By 2015 a further group of "other options" is required. It is assumed these would include Mpanga and Songwe which are the least cost options available at that date, and a further coal fired unit. By 2016 all "best evaluated" options have been taken up. After including Songwe 330 MW multipurpose project, the remaining load growth increase is assumed to be supplied from coal fired steam electric option. For the purpose of this study this generation has been assumed as coal fired plants at Mombasa, using Richards Bay coal. However obviously 6000 MW of generation for the region would not be located at one site, nor with a single fuel type and source. Consequently the Mombasa coal fired generation should be considered as a proxy for a group of non-specified thermal, other hydro and imports. In summary this plan would add the following: Group Total MW 2005 to 2008 475 2009-2020 Best evaluated options 2 547 2009-2020 Other options 6 992 Total additions 10 014 Total hydro additions 2005-2020 20.6% SSEA III - Final Report L-32 017334-001-00 Appendix L - Development of Portfolios Table L-12 ­ Portfolio 2d ­ All Options to Meet Regional Transformation Load Growth Scenario SSEA III - Final Report L-33 017334-001-00 Appendix L - Development of Portfolios 9 Sensitivity Tests 9.1 Regional Approach, Technical Diversification, Including Options with Insufficient Level of Preparation and Medium Load Growth Scenario ­ Portfolio 2Cb(S1) The overall concept of this portfolio illustrated in Table L-13 is to modify the technological diversification portfolio (2Cb) for the medium load forecast, to show the cost impact of relaxing the selection criteria to accept options that have not been sufficiently prepared for comparative evaluation. Most of these options are in the DRC, for which only reconnaissance levels appraisals have been made. It should be noted that none of the "unprepared" options have been subject to the environmental, social and risk assessment that was applied to options that pass the screening. Including these options in this sensitivity analysis does not imply any evaluation of these sites. However it may be noted that these sites are relatively small (less than 50 MW) and three of the sites are rehabilitation of existing hydro developments. However, given the requirement for technological diversification (thus to limit new hydro additions to less than 50% of the total), the impact from accepting options that are not adequately prepared is only to delay options selected for Portfolio 2Cb. Also it may be noted that these options are small (except for Sisi) and none could be available before 2013. The program to the end of 2012 is the same as for Portfolio 2Cb, including Rusumo and Bujagali 1-4. In 2013 it is assumed that the low cost sites from the DRC could be commissioned, including Kiymbi, Budana, Piana Mwanga and Bangamisa for a total of 142 MW. These would be lower cost than Suswa, Kabu 16 and Kakono that were scheduled for 2013 in Strategy 2 BB. In 2014 the options scheduled in Portfolio 2Cb (Ruzizi III, Bujagali unit 5 and a oil fired GT) would be added together with the DRC Babeda 1 option. At this point due to the addition of the DRC hydro plants, the total hydro new plant component would reach 50%, requiring the 2015 load increase to be met by thermal (Suswa and Menengai geothermal), although lower cost generation from Ruhudji or Karuma would be available. The Ruhudji hydro option, as the least cost available option, was scheduled for 2016, to be followed by Mchuchuma coal fired thermal and Kivu engines to meet load increases in 2017 and 2018. In 2019 the Karuma option may be inserted in the plan together with the first Mombasa thermal unit, while maintaining the hydro component less than 50%. Similarly in 2020 the Rumakai hydro option may be added, paired with the second Mombasa thermal unit. The effect of adding the DRC options was to delay Ruhudji and Karuma, and completely displace the Rumakali option from the plan. It may be noted that the only large hydro candidate option from the DRC, development on the Sisi bend on the Ruzizi river, was not included as when available in 2013 and thereafter it was more expensive than other available options. SSEA III - Final Report L-34 017334-001-00 Appendix L - Development of Portfolios In summary this plan would add the following: Group Total MW 2005 to 2008 475 2009-2020 Best evaluated options 1,914 Unprepared options 192 2009-2020 Other options 700 Total additions 3,281 Total hydro additions 2005-2020 46.5% 9.2 Regional Approach, Technical Diversification, Including Imports From Outside the Region and Medium Load Growth Scenario ­ Portfolio 2Cb(S2) The overall concept of this portfolio illustrated in Tale L-14 is to modify the technological diversification portfolio 2Cb for the medium load growth scenario, to show the cost impact of including a significant amount if imports from outside the region. For this purpose three blocks of 100 MW at 80% CF have been assumed, with scheduling assuming availability in 2009 and after, and a price delivered into the grid of 3 cents, thus being less costly than all best evaluated options, except Ruzizi III and Ruhudji (both not available before 2014). The Portfolio 2Cb would initially be modified in 2009, with the addition of the first 100 MW block of imports, which would delay a 60 MW GT to 2010, and would displace a 60 MW combined cycle steam unit, both in Tanzania. The second block of 100 MW would be added in 2010, displacing the second combined cycle steam unit in Tanzania, and delaying the Longonot geothermal plant. The third block of 100 MW would be added in 2011, together with the Longonot geothermal plant and the third Kivu engine group, while displacing the first of the two oil fired GTs for Kenya. From thereon after the schedule would be the same as for Portfolio 2Cb, except that Kakono would not be needed in 2013. The overall impact of the addition of 300 MW of imports to the plan for technical diversification, in terms of plant scheduling, would be to displace two 60 MW steam units for upgrades to combined cycle in Tanzania, the two oil fired GTs in Kenya and the Kakono hydro option in West Tanzania. SSEA III - Final Report L-35 017334-001-00 Appendix L - Development of Portfolios Table L-13 ­ Portfolio 2Cb(S1) ­ Expansion Plan ­ Technological Diversification ­ Including Options without Sufficient Preparation - Medium Load Growth Scenario Addition Total Supply Demand surplu/Deficit Energy Year Plant/Option Type Fuel Country MW GWH MW GWH MW GWH MW GWH Capacity reserve FIRM FIRM reserve % % 2004 All existing EAPMP + SSEA + DRC 2421 12129 1878 10642 29 14 2005 Kiira Units 14-15 Hydro Uganda 80 39 2501 12168 GT GT Gas Tanzania 40 280 2541 12448 1976 11244 565 1204 29 11 2006 Kiambere extension Hydro Kenya 20 0 2561 12448 GT GT Gas Tanzania 40 280 2601 12729 Diesel 3 x 10 Diesel No 2 B/R/WT 30 210 2631 12939 2097 11930 534 1009 25 8 2007 GT GT Gas Tanzania 60 420 2691 13359 Diesel 1 x 10 Diesel No 2 Burundi 10 70 2701 13429 2225 12674 476 755 21 6 2008 Sondu Miriu Hydro Kenya 60 292 2761 13721 Olkaria II Geo Kenya 35 491 2796 14212 GT GT Gas Tanzania 60 420 2856 14633 Diesel 1 x 10 Diesel No. 2 Rwanda 10 70 2866 14703 Kivu engine No. 1 Engine Methane R/DRC 30 210 2896 14913 2362 13464 534 1449 23 11 2009 GT GT Gas Tanzania 60 420 2956 15334 GT GT Gas Tanzania 60 420 3016 15754 Combined cycle steam unit CC Gas Tanzania 60 420 3076 16175 Diesel 1 x 10 Diesel No. 2 Tanzania 10 70 3086 16245 2506 14284 580 1961 23 14 2010 Geothermal GEO Kenya 70 491 3156 16735 Kivu engine No. 2 Engine Methane R/DRC 30 210 3186 16946 Combined cycle steam unit CC Gas Tanzania 60 420 3246 17366 2659 15156 587 2210 22 15 2011 Kivu engine No. 3 Engine Methane R/DRC 30 210 3276 17576 GT Diesel No 2 Kenya 60 420 3336 17997 2812 16024 524 1973 19 12 2012 Bujagali 1-4 Hydro Uganda 200 1390 3536 19387 Rusumo Hydro R/DRC 62 308 3598 19695 2974 16947 624 2748 21 16 2013 Kiymbi Hydro DRC 43 377 3641 20072 Budana Hydro DRC 13 70 3654 20142 Piana Mwanga Hydro DRC 38 193 3692 20335 Bangamisa Hydro DRC 48 420 3740 20755 3162 17927 578 2828 18 16 2014 Bujagali Unit 5 Hydro Uganda 50 14 3790 20769 Ruzizi III Hydro R/DRC 82 418 3872 21187 Babeda 1 Hydro DRC 50 351 3922 21538 GT Diesel No 2 Kenya 60 420 3982 21958 3348 18970 634 2988 19 16 2015 Geothermal Suswa GEO Kenya 70 491 4052 22449 Menengai Geothermal GEO Kenya 140 981 4192 23430 3544 20079 648 3351 18 17 2016 Ruhudji Hydro Tanzania 358 1476 4550 24906 3752 21254 798 3652 21 17 2017 Kivu engine No. 4 Engine Methane R/DRC 30 210 4580 25116 Mchuchuma Coal Coal Tanzania 200 1402 4780 26518 3974 22506 806 4012 20 18 2018 Mchuchuma Coal Coal Tanzania 200 1402 4980 27919 4211 23839 769 4080 18 17 2019 Karuma Hydro Uganda 200 1619 5180 29538 Mombasa 1 Coal Kenya 150 1051 5330 30590 4462 25256 868 5334 19 21 2020 Mombasa 2 Coal Kenya 150 1051 5480 31641 Rumakali Hydro Tanzania 222 1170 5630 32692 4731 26770 899 5922 19 22 SSEA 2 TOTAL ADDITIONS 2004-2020 3281 20682 2853 16128 EAPMP TOTAL ADDITIONS 2004-2020 2302 14338 2354 14120 GT burning gas assumed as maximum PF % 80 Combined cycle burning gas max PF % 80 Technology and geographic diversification Evaluation quotient MW % MW %Supply % Load MW % Hydro 1526 46.5% Burundi 20 0.6% 3 Best evaluated 2389 341 Geotherma 315 9.6% DRC 324 9.9% 2 Unprepared 192 6 Gas 440 13.4% Kenya 815 24.8% 43 Other 700 21 Coal 700 21.3% Rwanda 152 4.6% 3 3281 100 Fuel 180 5.5% Tanzania 1440 43.9% 29 Methane 120 3.7% Uganda 530 16.2% 20 Wind 0 0.0% Imports 0 0.0% Imports 0 0.0% 3281 100.0% 3281 100.0% In summary this plan would add the following: Group Total MW 2005 to 2008 47 2009-2020 Best evaluated options 1 83 Imports 300 2009-2020 Other options 700 Total additions 3 309 Total hydro additions 2005-2020 40.9% SSEA III - Final Report L-36 017334-001-00 Appendix L - Development of Portfolios Table L-14 ­ Portfolio 2Cb(S2) ­ Expansion Plan ­ Technological Diversification with Imports from Outside the Region ­ Medium Load Growth Scenario Addition Total Suplly Demand Surplus/Deficit Energy Year Plant/Option Type Fuel Country MW GWH MW GWH MW GWH MW GWH Capacity reserve FIRM FIRM reserve % % 2004 All existing EAPMP + SSEA + DRC 2421 12129 1878 10642 29 14 2005 Kiira Units 14-15 Hydro Uganda 80 39 2501 12168 GT GT Gas Tanzania 40 280 2541 12448 1976 11244 565 1204 29 11 2006 Kiambere extension Hydro Kenya 20 0 2561 12448 GT GT Gas Tanzania 40 280 2601 12729 Diesel 3 x 10 Diesel No 2 B/R/WT 30 210 2631 12939 2097 11930 534 1009 25 8 2007 GT GT Gas Tanzania 60 420 2691 13359 Diesel 1 x 10 Diesel No 2 Burundi 10 70 2701 13429 2225 12674 476 755 21 6 2008 Sondu Miriu Hydro Kenya 60 292 2761 13721 Olkaria II Geo Kenya 35 491 2796 14212 GT GT Gas Tanzania 60 420 2856 14633 Diesel 1 x 10 Diesel No. 2 Rwanda 10 70 2866 14703 Kivu engine No. 1 Engine Methane R/DRC 30 210 2896 14913 2362 13464 534 1449 23 11 2009 GT GT Gas Tanzania 60 420 2956 15334 Import 1 Import Imports 100 701 3056 16035 Diesel 1 x 10 Diesel No. 2 Tanzania 10 70 3066 16105 2506 14284 560 1821 22 13 2010 Import 2 Import Imports 100 701 3166 16805 Kivu engine No. 2 Engine Methane R/DRC 30 210 3196 17016 GT GT Gas Tanzania 60 420 3256 17436 2659 15156 597 2280 22 15 2011 Kivu engine No. 3 Engine Methane R/DRC 30 210 3286 17646 Import 3 Import Imports 100 701 3386 18347 Geothermal GEO Kenya 70 491 3456 18838 2812 16024 644 2814 23 18 2012 Bujagali 1-4 Hydro Uganda 200 1390 3656 20228 Rusumo Hydro R/DRC 62 308 3718 20536 2974 16947 744 3589 25 21 2013 Geothermal Suswa GEO Kenya 70 491 3788 21026 Kabu 16 Hydro Burundi 20 67 3808 21093 3162 17927 646 3166 20 18 2014 Bujagali Unit 5 Hydro Uganda 50 14 3858 21107 Ruzizi III Hydro R/DRC 82 418 3940 21525 3348 18970 592 2555 18 13 2015 Ruhudji Hydro Tanzania 358 1476 4298 23001 3544 20079 754 2922 21 15 2016 Menengai Geothermal GEO Kenya 140 981 4438 23982 3752 21254 686 2728 18 13 2017 Kivu engine No. 4 Engine Methane R/DRC 30 210 4468 24193 Geothermal 2 x 70 GEO Kenya 140 981 4608 25174 Mchuchuma Coal Coal Tanzania 200 1402 4808 26575 3974 22506 834 4069 21 18 2018 Mchuchuma Coal Coal Tanzania 200 1402 5008 27977 4211 23839 797 4138 19 17 2019 Karuma Hydro Uganda 200 1619 5208 29596 4462 25256 746 4340 17 17 2020 Rumakali Hydro Tanzania 222 1170 5430 30766 Mombasa 1 Coal Kenya 150 1051 5580 31817 Mombasa 2 Coal Kenya 150 1051 5730 32868 4731 26770 999 6098 21 23 SSEA 2 TOTAL ADDITIONS 2004-2020 3309 20739 2853 16128 EAPMP TOTAL ADDITIONS 2004-2020 2302 14338 2354 14120 GT burning gas assumed as maximum PF % 80 Combined cycle burning gas max PF % 80 Technology and geographic diversification Evaluation quotient MW % MW %Supply % Load MW % Hydro 1354 40.9% Burundi 40 1.2% 3 Geothermal 455 13.8% DRC 132 4.0% 2 Best evaluated 2609 79 Gas 320 9.7% Kenya 835 25.2% 43 Other 700 21 Coal 700 21.2% Rwanda 152 4.6% 3 3309 100 Fuel 60 1.8% Tanzania 1320 39.9% 29 Methane 120 3.6% Uganda 530 16.0% 20 300 MW Imports displace 2 x 60 MW CC Wind 0 0.0% steam cycle, 2 x 60 MW oil GTs and Imports 300 9.1% Imports 300 9.1% 3309 100% 3309 100.0% 9.3 Regional Approach, Technological Diversification, Excluding any Consideration of Environmental, Social and Risk Issues and Medium Load Growth Scenario ­ Portfolio 2Cb(S3) The overall concept of this portfolio illustrated in Table L-15 is to modify the technological diversification portfolio (2Cb) for the medium load forecast, to show the cost impact of relaxing the selection criteria to accept options that may incur significant social and /or environmental risk. Given that the final determination of an option's acceptability may include detailed environmental assessment, cumulative impacts (such as a basin study for hydroelectric options), and determination and costing of environmental measures, this study only seeks to identify the approximate cost premium that would be placed on excluding low cost generation that carries a potential risk. However, given the underlying requirement for technological diversification in this strategy, the impact from accepting options that are not best evaluated, is to reorder the selection of hydroelectric options, as low cost hydro with potential impacts would displace /defer previously selected higher cost "best evaluated" options. Also none of these options would be available before 2013. SSEA III - Final Report L-37 017334-001-00 Appendix L - Development of Portfolios The program to the end of 2012 is the same as for Portfolio 2Cb, including Rusumo and Bujagali 1-4. In 2013 the options selected are Masigira Hydro, Suswa geothermal and the fourth engine at Lake Kivu. In 2014 the least cost options are Ruzizi III and Bujagali 5 and these are proposed. In 2015 the options are the Menengai geothermal plant and the Karuma Hydro. In 2016 the installations would be Mpanga, the least cost remaining hydro plant, and a non- specified 140 MW geothermal unit. To maintain the hydro proportion below 50%, the next unit would have to be thermal, and the first two units at Mchuchuma were selected. For 2018 the least cost hydro would be Songwe (330 MW), or Ruhudji (358 MW), in that order, so Songwe was selected. A gas turbine using fuel oil and located in Kenya and the Rumakali hydro options would follow in 2019, and the increment for 2020 would be met by a first coal fired unit at Mombasa (150 MW) and the second two units at Mchuchuma. The resulting total new hydro (after 2005) is 47%. In summary this plan would add the following: Group Total MW 2005 to 2008 475 2009-2020 Best evaluated options 1,696 2009-2020 Other options 1,142 Total additions 3,313 Total hydro additions 2005-2020 47.2% SSEA III - Final Report L-38 017334-001-00 Appendix L - Development of Portfolios Table L-15 ­ Portfolio 2Cb(S3) ­ Expansion Plan ­ Technological Diversification ­ Including Options with Social/Environmental Risks - Medium Load Growth Scenario Addition Total Supply Demand Surplu/deficit Energy Year Plant Type Fuel Country MW GWH MW GWH MW GWH MW GWH Capacity reserve FIRM FIRM reserve % % 2004 All existing EAPMP + SSEA + DRC 2421 12129 1878 10642 29 14 2005 Kiira Units 14-15 Hydro Uganda 80 39 2501 12168 GT GT Gas Tanzania 40 280 2541 12448 1976 11244 565 1204 29 11 2006 Kiambere extension Hydro Kenya 20 0 2561 12448 GT GT Gas Tanzania 40 280 2601 12729 Diesel 3 x 10 Diesel No 2 B/R/WT 30 210 2631 12939 2097 11930 534 1009 25 8 2007 GT GT Gas Tanzania 60 420 2691 13359 Diesel 1 x 10 Diesel No 2 Burundi 10 70 2701 13429 2225 12674 476 755 21 6 2008 Sondu Miriu Hydro Kenya 60 292 2761 13721 Olkaria II Geo Kenya 35 491 2796 14212 GT GT Gas Tanzania 60 420 2856 14633 Diesel 1 x 10 Diesel No. 2 Rwanda 10 70 2866 14703 Kivu engine No. 1 Engine Methane R/DRC 30 210 2896 14913 2362 13464 534 1449 23 11 2009 GT GT Gas Tanzania 60 420 2956 15334 GT GT Gas Tanzania 60 420 3016 15754 Combined cycle steam unit CC Gas Tanzania 60 420 3076 16175 Diesel 1 x 10 Diesel No. 2 Tanzania 10 70 3086 16245 2506 14284 580 1961 23 14 2010 Geothermal Longonot GEO Kenya 70 491 3156 16735 Kivu engine No. 2 Engine Methane R/DRC 30 210 3186 16946 Combined cycle steam unit CC Gas Tanzania 60 420 3246 17366 2659 15156 587 2210 22 15 2011 Kivu engine No. 3 Engine Methane R/DRC 30 210 3276 17576 GT Diesel No 2 Kenya 60 420 3336 17997 2812 16024 524 1973 19 12 2012 Bujagali 1-4 Hydro Uganda 200 1390 3536 19387 Rusumo Hydro R/DRC 62 308 3598 19695 2974 16947 624 2748 21 16 2013 Masigira Hydro Tanzania 118 528 3716 20223 Geothermal Suswa GEO Kenya 70 491 3786 20713 Kivu engine No. 4 Engine Methane R/DRC 30 210 3816 20924 3162 17927 654 2997 21 17 2014 Bujagali Unit 5 Hydro Uganda 50 14 3866 20938 Ruzizi III Hydro R/DRC 82 418 3948 21356 3348 18970 600 2386 18 13 2015 Menengai Geothermal GEO Kenya 140 981 4088 22337 Karuma Hydro Uganda 200 1619 4288 23956 3544 20079 744 3877 21 19 2016 Mpanga Hydro Tanzania 144 863 4432 24819 Geothermal 2 x 70 GEO Kenya 140 981 4572 25800 3752 21254 820 4546 22 21 2017 Mchuchuma Coal Coal Tanzania 200 1402 4772 27201 3974 22506 798 4695 20 21 2018 Songwe Hydro Tanzania 330 1352 5102 28553 4211 23839 891 4714 21 20 2019 GT Diesel No 2 Kenya 60 420 5162 28974 Rumakali Hydro Tanzania 222 1170 5384 30144 4462 25256 922 4888 21 19 2020 Mombasa 1 Coal Kenya 150 1051 5534 31195 Mchuchuma Coal Coal Tanzania 200 1402 5734 32597 4731 26770 1003 5827 21 22 SSEA 2 TOTAL ADDITIONS 2004-2020 3313 20468 2853 16128 EAPMP TOTAL ADDITIONS 2004-2020 2302 14338 2354 14120 GT burning gas assumed as maximum PF % 80 Combined cycle burning gas max PF % 80 Technology and geographic diversification Evaluation quotient MW % MW %Supply % Load MW % Hydro 1568 47.3% Burundi 20 0.6% 3 Geotherma 455 13.7% DRC 132 4.0% 2 Best evaluated 2171 66 Gas 440 13.3% Kenya 805 24.3% 43 Other 1142 34 Coal 550 16.6% Rwanda 152 4.6% 3 3313 100 Fuel 180 5.4% Tanzania 1674 50.5% 29 Methane 120 3.6% Uganda 530 16.0% 20 Wind 0 0.0% Imports 0 0.0% Imports 0 0.0% 3313 100.0% 3313 100.0% SSEA III - Final Report L-39 017334-001-00 APPENDIX M REFERENCES AND SOURCES OF DOCUMENTS Reports .........................................................................................................................1 Legal References ..........................................................................................................7 Maps ...........................................................................................................................11 Miscellaneous..............................................................................................................12 New References (for October 2006 update).................................................................13 References for Climate Change...................................................................................14 SSEA III - Final Report 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS REPORTS - African Development and Economic Consultants Ltd, Republic of Kenya, Kenya Power Company, Ewaso Ngiro (South) Multipurpose Project Environmental Impact Assessment, Stage I Report, Socio-economic issues related to Proposals for Ewaso Ngiro River Developments, December 1991 - Arundati Inamdar & Associates Environmental Consultant, GEM GEN Power Company, Environmental Scoping Study for GEM GEN Hydroelectric Power Project at Ndanu Falls on River Yala, Siaya District, Kenya, Draft Report, March 2002 - Atkins Land Water Management in association with African Development & Economic, Soil and Water Conservation Programme Masinga Dan Catchment Areas, Final Report Volume II, Annexes 1 & 2, June 1984 - BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Kenya Tanzania Uganda, The East African Community, Arusha, Tanzania, November 2003 - BKS Acres, East African Power Master Plan Study, Draft Phase I Report, Appendix H, Kenya Tanzania Uganda, The East African Community, Arusha, Tanzania, November 2003 - BKS Acres, East African Power Master Plan Study, Final Phase II Report, March 2005 - BKS Acres, The East African Power Master Plan Study, Preliminary Task Report - BKS Acres, The East African Power Master Plan Study, System Analysis Report - Burnet Institute, International Rescue Committee, Mortality in the Democratic Republic of Congo: Results from a Nationwide Survey, Conducted April-July 2004 - BUSSEM, Centrale hydroélectrique de Semliki, Études de préfaisabilité, Version provisoire, République démocratique du Congo, Ministère de l'énergie, Électrification du Nord-Kivu, Mars 2005 - Cifarha, Male, Les ressources hydro-électriques du Zaïre, Kinshasa, Février 1994 - Data collection from Experco for the Democratic Republic of Congo - Data collection on environmental and social indicators, Uganda - Données environnementales de l'est de la R.D. Congo, quelques observations et propos par prof. Nyakabwa Mutabana - Données socio-économiques et environnementales de la RDC (est) : province orientale, région Haut-Zaïre, site Babela - Données socio-économiques et environnementales de la RDC (est) : province : Katanga, région Shaba, site Bendera II - Données socio-économiques et environnementales de la RDC (est) : province orientale, région Haut-Zaïre, site Bengamisa - Données socio-économiques et environnementales de la RDC (est) : province : Katanga, région Shaba, site Busanga - Données socio-économiques et environnementales de la RDC (est) : province : Sud- Kivu, région Kivu Nord/Sud, Maniema, site Kamanyola - Données socio-économiques et environnementales de la RDC (est) : province : Maniema, région Kivu Nord/Sud, Maniema, site Mwana Ngoye - Données socio-économiques et environnementales de la RDC (est) : province : Nord-Kivu, région Kivu Nord/Sud, Maniema, site Mugomba SSEA III - Final Report M-1 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS - Données socio-économiques et environnementales de la RDC (est) : province : Katanga, région Shaba, site Nzilo II - Données socio-économiques et environnementales de la RDC (est) : province : Sud- Kivu, région Kivu Nord/Sud, Maniema, site Panzi - Données socio-économiques et environnementales de la RDC (est) : province : Katanga, région Shaba, site Portes d'enfer - Données socio-économiques et environnementales de la RDC (est) : province : Sud- Kivu, région Kivu Nord/Sud, Maniema, site Ruzizi II - Données socio-économiques et environnementales de la RDC (est) : province : Nord-Kivu, région Kivu Nord/Sud, Maniema, site Semliki - Données socio-économiques et environnementales de la RDC (est) : province : Sud- Kivu, région Kivu Nord/Sud, Maniema, site Sisi - Données socio-économiques et environnementales de la RDC (est) : province orientale, région Haut-Zaïre, site Wagenia - Données socio-économiques et environnementales de la RDC (est) : province orientale, région Haut-Zaïre, site Wanie Rukula - Données socio-économiques présentées par Pr Augustin Mutabazi, Province : Katanga - Données socio-économiques présentées par Pr Augustin Mutabazi, Province : Maniema - Données socio-économiques présentées par Pr Augustin Mutabazi, Province : province orientale - Données socio-économiques présentées par Pr Augustin Mutabazi, Province : Nord- Kivu - Données socio-économiques présentées par Pr Augustin Mutabazi, Province : Sud- Kivu - East African Master Plan Study, Geothermal Energy in Uganda, A Status Report, Department of Geological Survey and Mines, Ministry of Energy and Mineral Development, P6015410 - References ID U40, May 2002 - Electricity Regulatory Board, Environmental, Health & Safety Policy for the electric power sub-sector 2005 - ENERGOPROJEKT et École polytechnique de Varsovie en collaboration avec la Section Energétique de l'O.N.R.D., Étude du système électroénergétique de la province du Kivu, Kinshasa 1972, Présidence de la République, Office National de la recherche et du développement - ESG International inc. and WS Atkins, Bujagali Hydropower Project, Executive Summary, Uganda, E464 Volume 1, prepared for AES Nile Power, March 2001 - ESG International inc., WS Atkins Epsom, UK, prepared for AES Nile Power, Richmond, UK, Bujugali Hydropower Project, Executive Summary, Uganda, E464, Volume 1, March 2001 - ESG International inc., WS Atkins Epsom, UK, prepared for AES Nile Power, Richmond, UK, Bujugali Hydropower Project, Environmental Impact Assessment, Facility EIA, Uganda, E464, March 2001 - ESG International inc., WS Atkins Epsom, UK, prepared for AES Nile Power, Richmond, UK, Bujugali Hydropower Project, Appendices, Uganda, E464, March 2001 SSEA III - Final Report M-2 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS - ESG International inc., WS Atkins Epsom, UK, prepared for AES Nile Power, Richmond, UK, Bujugali Hydropower Project, Resettlement and Community Development Action Plan (RCDAP), Uganda, E464, March 2001 - ESG International, Victoria Nile Strategic Impact Assessment, Uganda, prepared for International Finance Corporation (IFC), January 2000 - ESG International inc. and WS Atkins, Bujagali Project Hydropower Facility, Environmental Impact Assessment, Main Report, Prepared for AES Nile Power, March 2001 - Exploitation du méthane du lac Kivu, Le Lac Kivu, Source de méthane, étude fondamentale, risques naturels, Projet de station pilote, Data Environnement, Juin 2003 - Extracts from GIBB report on Environmental Audits of Power Stations in Kenya, 2002 - Extrait de l'étude de remise à l'état de la centrale de Kiyilbi et des réseaux associés - FEM/PNUE/République du Congo, Avant projet du cadre national de biosécurité, Ministère de l'économie forestière et de l'environnement, Direction générale de l'environnement, Juillet 2004 - Field Studies Unit, Directorate of Corporate Planning & Research, Tanzania Electric Supply Company Limited, Feasibility Study of the Mandera Hydroelectric Power Project, Final Report, Tanesco, December 1995 - GIBB Africa Ltd., Kenya Electricity Generating Company Limited, Environmental Impact Assessment for Olkaria II 3rd Unit Extension Project, Draft Audit Report, June 2004 - International Hydropower Association (IHA), Sustainability Guidelines, Draft, January 2003 - Japan International Cooperation Agency, Republic of Kenya, Kenya Power company Limited, Feasibility Study on Magwagwa Hydroelectric Power Development Project, Final Report, Main Report, October 1991 - Japan International Cooperation Agency, Republic of Kenya, Kenya Power company Limited, Feasibility Study on Magwagwa Hydroelectric Power Development Project, Final Report, Executive Summary, October 1991 - Japan International Cooperation Agency, Republic of Kenya, Kenya Power company Limited, Feasibility Study on Magwagwa Hydroelectric Power Development Project, Final Report, Data Book (2), October 1991 - Japan International Cooperation Agency, Republic of Kenya, Ministry of Energy, Feasibility Study of Mutonga/Grand Falls Hydropower Project, Draft Final Report, Executive Summary for Environmental Assessment, October 1997 - Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP), Opportunities for Power Trade in the Nile Basin, Final Scoping Study, January 2004 - Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP), Opportunities for Power Trade in the Nile Basin, Final Scoping Study, January 2004 - Karuma Hydro Project in Uganda, letters from BKS Acres, Royal Norwegian Embassy, Norpak Power Ltd and Costs, Time Schedule etc. - Kennedy & Donkin Power Limited, Hydropower Development Master Plan Part 1 (Final Report), Uganda Electricity Board, November 1997 SSEA III - Final Report M-3 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS · Volume 1, Executive Summary · Volume 2, Main Report · Volume 3, Drawings · Volume 4, Appendices · Volume 6, Report on the Hydrology of the Nile Below Lake Victoria · Volume 7, Hydrology and Hydropower Potential of Non-Nile Rivers · Volume 8, Environmental Impact Assessment (Stage 1) - Kenya Subsidiary Legislation, 2003, Environmental Impact Assessment (EIA) for a Proposed Wind Farm in South Kinangop, Kenya, for ECOGEN Wind Farms Ltd - Knight Piésold & Partners, Environmental Assessment of Proposals for Ewaso Ngiro River Developments, Environmental Assessment Stage IV Report, Republic of Kenya, Kenya Power Company, April 1993 - Knight Piésold Consulting, Ewaso Ngiro (South) Hydroelectric Project, Tender Stage Design Report, Volume 1 : Main Report, KenGen, July 2001 - Knight Piésold in association with Mott Ewbank Preece, Feasibility Study for Raising of Masinga Dam and Redevelopment of Tana Power Station, Redevelopment of Tana Power Station, Final Report, The Kenya Power Company Limited, September 1997 - Knight Piésold, Consulting Engineers, Republic of Kenya, Kenya Power Company, Ewaso Ngiro (South) Multipurpose Project, Environmental Impact Assessment Stage II Report, Hydrological Impacts of proposals for Ewaso Ngiro River Developments, September 1992 - Knight Piésold, Merz and McLellan, Bujugali Hydropower Project, Feasibility Study, Volume 1, Main Report, AES Nile Power, July 1998 - Lahmeyer International, Analysis and Projection of Rwanda's Electricity Demand, Final Report, May 2004 - Lahmeyer International, Electrogaz, Analysis and Projection of the Electricity Demand - Male Cifarha, Perspectives d'électrification des centres de l'est du Zaïre, Kinshasa, mai 1995 - Ministry of Energy and Minerals/Tanesco, Institute of Resource Assessment University of Dar es Salaam, Songo Songo Gas Development and Power Generation Project - 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(NERA) and Gibb Eastern Africa, Review of Electricity Tariff Policy in Kenya, Final Report, Prepared for Electricity Regulatory Board of Kenya, October 4, 2002 - Nations Unies Commission Économique pour l'Afrique, MULPOC-GISENYI, Étude d'interconnexion des réseaux électriques dans les pays membres de la communauté économique des pays des grands lacs (CEPGL) et de l'organisation du bassin de la rivière Kagera (OBK), ECA/GSY/MUL/CIE/III/25, Addis Abeba, Novembre 1995 SSEA III - Final Report M-4 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS - NELSAP-CU, Nile Basin Initiative, Nile Equatorial Lakes Subsidiary Action Program (NELSAP), Strategy for Scaling Up NELSAP Investments Projects, Endorsed by NEL-COM, 16 March, 2005 - Nippon KOEI Co. Ltd. Consulting engineers, compiled by RPS International, Economic Planning & Development Consultants, Sondu-Miriu Hydroelectric Project, Environmental Impact Assessment, Executive Summary, September 1993 - Nippon KOEI Co. Ltd. Consulting Engineers, Republic of Kenya, Kenya Power Company Limited, Detailed Design and Preparation of Tender Documents for Sondu/Miriu Hydropower Project, Environmental Impact Assessment, Data Book (5), July 1991 - Nippon KOEI Co. Ltd., Pasco International inc., Japan International Cooperation Agency (JICA), Tana and Athi Rivers Development Authority (TARDA), Feasibility Study on Mutonga/Grand Falls Hydropower Project, Progress Report (1), Volume 2: Environmental Assessment Report, February 1995 - Nippon KOEI Co. Ltd., Pasco International inc., Japan International Cooperation Agency (JICA), Tana and Athi Rivers Development Authority (TARDA), Feasibility Study on Mutonga/Grand Falls Hydropower Project, Initial Environmental Assessment, August 1994 - NORAD/Norplan A/S, Rufiji Basin Development Authority, Lower Rufiji Valley, Integration Study, Part II, Development Programmes and Physical Impacts, Main Report, Volume 1, June 1983 - Norconsult/Norad, Rufiji Hydropower Master Plan, Annex: Environmental Impacts and Multipurpose Benefits, Rufiji Basin Development Authority (Rubada), The United Republic of Tanzania, November 1984 - Norconsult/Norad, Rufiji Hydropower Master Plan, Executive Summary, Rufiji Basin Development Authority (Rubada), The United Republic of Tanzania, November 1984 - Norconsult, Small Scale Hydropower Developments in the Rukwa and Kigoma Regions of Tanzania, Draft Feasibility Study Report, Malagarasi Hydropower Project- Kigoma, Volume 1, Main Text, Tanesco, Tanzania Electric Supply Company Limited, March 1983 - 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Final Report M-5 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS - Projet de centrale hydroélectrique sur le Nepoko Haut-Congo, 1993 et fiche technique de l'aménagement de la centrale de Nepoko - RISØ National Laboratory, Wind Measurements and Wind Power Feasibility at Selected Sites in Tanzania 2000-2003, Final Report, Ministry of Foreign Affairs, Denmark, December 2003 - Rufiji Basin Development Authority, Basin Potential - Hydropower, Stieglers Gorge - S.E.E.E. - O.C.C.R.-Inter G, République Française, Ministère de la coopération et du développement, Études inventaires des sites hydrauliques en vue de leur équipement avec des mini ou microcentrales hydro-électriques au Zaïre - Scott Wilson Piésold in association with Acres International, Fieldstone Private Capital Group, Norton Rose, OPPPI, Zambia-Tanzania Power Transmission Line Interconnector Project, Zambia-Tanzania Interconnector Review and Tanzania Internal Transmission System Reinforcement, Draft Report, November 2003 - 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Final Report M-6 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS - Tana and Athi Rivers Development Authority, Masinga Reservoir Capacity and Sedimentation Report - Technical Annex 4: Economic Analysis Summary (TANESCO) - Tesaker, E., The Stiegler's Gorge Study - 25 years later, Hydro Africa 2003 - The Kenya Power & Lighting Co. 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Décret no 03/26 du 16 septembre 2003 portant organisation et fonctionnement des cabinets des Vice-Présidents de la République - Décret no 03/27 du 16 septembre 2003 fixant les attributions des Ministères SSEA III - Final Report M-7 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS - Arrêté Interministériel no 0021 du 29 octobre 1993, portant application de la Réglementation sur les Servitudes - Ordonnance no 78-196 du 5 mai 1978 portant statuts d'une Entreprise publique dénommée Société Nationale d'Électricité, en abrégé « S .N.E.L. » - Loi no 78-002 du 6 janvier 1978 portant dispositions générales applicables aux entreprises publiques telle que modifiée et complétée à ce jour (Textes coordonnés et mis à jour au 1er mai 1991) - Avant-projet de décret-loi portant Code de l'Eau ­ Juillet 2000 - Décret du 2 juin 1928 : les conditions générales du transport et de distribution de l'énergie électrique - Arrêté Royal du 9 octobre 1956 portant règlement général et cahier des charges générales fixant les principes applicables aux concessions de distribution publique de l'énergie électrique (autres) - 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Évaluation de l'impact environnemental et social du PMURR (Programme Multisectoriel d'urgence de réhabilitation et de reconstruction), Vol. 1, SOFRECO, 21 June 2004 (WB Report E1014) - Democratic Republic of Congo ­ Economic and Public Sector Work ­ Reforming Public Enterprises Through Improved Governance, March 10, 2004 (WB Report No: 28048-ZR) - Project Appraisal Document on Private Sector Development and Competitiveness in the Democratic Republic of Congo, July 2, 2003 (Report No: 25707 ZR) - Jurist Legal News and Research at http://jurist.law.pitt.edu/world/congo.htm SSEA III - Final Report M-8 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS Kenya References - Draft Sessional Paper on Energy, May 2004 - Electric Power (Electric Supply Lines) Rules 2004 - Electric Power (Licensing) Rules 2004 - Electric Power (Metering and Consumer Installations) Rules 2004 - Electric Power Act, No 11 of 1997 - Energy Bill 2004 (Draft Electric Power Act - Final Draft ­ 20th July 2004) - Energy Bill 2004 - Memorandum of Objects and Reasons - Environmental (Impact Assessment and Audit) Regulations, 2003 - Environmental Management and Coordination Act, 1999 - ERB - Environmental, Health & Safety Policy 2004 ­ June 2004 - ERB - Retail Electricity Tariffs Review Policy; 2004 ­ Zero Draft, Sept. 2004 - Foreign Investment Protection Act (CAP 518) - KPLC Network ­ Map (Opens with AUTOCARD Software) - Land Control Act, Chap. 302 (Rev. 1989) - Land Planning Act, Chap. 303 (Rev. 1970) - Least Cost Power Development Plan Update - 2005 ­ 2025 Draft 1 - Local Government Act, Chap. 265 (Rev. 1998) - Power Market Design and Pre-Privatisation Study Draft Final Report - A Final Report for the Restructuring Task Force, Prepared by NERA in association with Deloitte Touche Tohmatsu, Decon & Rachier Advocates, July 2003 London - Public Procurement and Disposal Bill, 2005 - Public Health Act, Chap. 242 (Rev. 1986) - Water Act, 2002 - Jurist Legal News and Research, at http://jurist.law.pitt.edu/world/kenya.htm - Project Appraisal Document on a Proposed Credit in the Amount of SDR55.20 Million (USD8O Million Equivalent) to the Republic of Kenya for an Energy Sector Recovery Project, June 10, 2004 (WB Report No: 28314-KE) - Policies and Investment Opportunities in Kenya ­ Department of Industry, November 2000 - Investment Opportunities in Kenya ­ Ministry of Trade and Industry, May 2000 - Environmental Legislation and Domestication of International Environmental Law in Kenya, Anne Angwenyi, Principal Legal Officer, National Environment Management Authority (NEMA) Kenya ­ A paper presented at the SISEI (Système de Circulation d'Information et de Suivi de l'Environnement sur Internet en Afrique) Programme sub-regional legal workshop held in Nairobi, 13th-17th December 2004 ­ Can be found at http://www.nema.go.ke/environmental_legislation_and.htm - And at http://www.sisei.net/IMG/pdf/Kenya-env-laws-expose.pdf SSEA III - Final Report M-9 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS Rwanda References - Law No 14/98 of 18/12/1998 establishing the Rwanda Investment Promotion Agency - Republic of Rwanda, Ministry of Infrastructure, National Human Settlement Policy in Rwanda, July 2004 - Republic of Rwanda, National Environmental Policy - Rwanda Labour Law: Law No 51/2001 of 30/12/2001 establishing the labour code Tanzania References - Tanzania Investment Act, 1997 - Tanzania Investment Centre, Laws and Regulations Governing Investments in Tanzania - The United Republic of Tanzania, Ministry of Energy and Minerals, The National Energy Policy, February 2003 - The United Republic of Tanzania, Ministry of Water and Livestock Development, National Water Policy, July 2002 Uganda References - Uganda Power Sector Restructuring and Privatization - New Strategy Plan & Implementation Plan, June 1999 - The Electricity Act, 1999. - The Energy Policy for Uganda, September 2002 - Rural Electrification Strategy and Plan, covering the period 2001 to 2010 - The National Environment Management Policy, March 1995 - The National Environment Statute (Statute No 4 of 1995) - The Environmental Impact Assessment Regulations, 1998 - The National Environment (Wetlands, River banks and Lakeshores Management) Regulations, 1999 - Medium Term Competitive Strategy for the Private Sector (2000-2005) - Electricity Regulatory Authority ­ Annual Report 2000/2002 - Electricity Regulatory Authority ­ Strategic Plan 2003-2013 - Electricity Regulatory Authority ­ Business Plan 2003/2005 - International Agreement to Which Uganda is a Signatory - World Fact Book at http://www.cia.gov/cia/publications/factbook/index.html - Jurist Legal News and Research at http://jurist.law.pitt.edu/world/uganda.htm - Investing in Uganda at http://www.wakili.co.ug/new/investment.html - Competing for FDI : inside the operations of four national investment promotion agencies, Vol. 1 of 1 ­ ((WB Report 31916), pp. 47-76 - (FDI : Foreign Direct Investment) SSEA III - Final Report M-10 017334-001-00 APPENDIX M - REFERENCES AND SOURCES OF DOCUMENTS Maps - Map: East Africa 1:50,000 (Uganda) Kyarusozi, Series Y732, Sheet 57/1, Edition 1- U.S.D. - Map: East Africa 1:50,000 (Uganda) Jinja, Series Y732, Sheet 72/1, Edition 3-U.S.D. - Map: East Africa 1:50,000 (Uganda) Kagoma, Series Y732, Sheet 62/3, Edition 3- U.S.D. - Map: East Africa 1:50,000 (Uganda) Akokoro, Series Y732, Sheet 40/4, Edition 1- U.S.D. - Map: East Africa 1:50,000 (Uganda) Masindi Port, Series Y732, Sheet 40/3, Edition 1-U.S.D. - Map: East Africa 1:50,000 (Uganda) Kiryandongo, Series Y732, Sheet 40/1, Edition 2-U.S.D. - Map: East Africa 1:50,000 (Uganda) Ibuje, Series Y732, Sheet 40/2, Edition 1-U.S.D. - Map: East Africa 1:50,000 (Uganda) Atura, Series Y732, Sheet 31/4, Edition 1-U.S.D. - Map: East Africa 1:50,000 (Uganda) Adibu, Series Y732, Sheet 31/1, Edition 1- U.S.D. - Map: East Africa 1:50,000 (Uganda) Wangkwar, Series Y732, Sheet 30/2, Edition 2- U.S.D. - Map: East Africa 1:50,000 (Uganda) Kabalega Falls, Series Y732, Sheet 30/2, Edition 3-U.S.D. - Map: East Africa 1:50,000 (Uganda) Pakwach, Series Y732, Sheet 29/2, Edition 2- U.S.D. - 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