DIREC TIONS IN DE VELOPMENT Energy and Mining Independent Power Projects in Sub-Saharan Africa Lessons from Five Key Countries Anton Eberhard, Katharine Gratwick, Elvira Morella, and Pedro Antmann Independent Power Projects in Sub-Saharan Africa DIREC TIONS IN DE VELOPMENT Energy and Mining Independent Power Projects in Sub-Saharan Africa Lessons from Five Key Countries Anton Eberhard, Katharine Gratwick, Elvira Morella, and Pedro Antmann © 2016 International Bank for Reconstruction and Development / The World Bank 1818 H Street NW, Washington, DC 20433 Telephone: 202-473-1000; Internet: www.worldbank.org Some rights reserved 1 2 3 4 19 18 17 16 This work is a product of the staff of The World Bank with external contributions. The findings, interpreta- tions, and conclusions expressed in this work do not necessarily reflect the views of The World Bank, its Board of Executive Directors, or the governments they represent. 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Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Contents Foreword xvii Acknowledgments xix About the Authors xxi Executive Summary xxiii Abbreviations xlix PART 1 Power Generation in Sub-Saharan Africa 1 Chapter 1 Introduction 3 The Challenges Faced by Sub-Saharan Africa’s Power Sector 3 Importance of Private Sector Participation and the Role of Independent Power Projects 6 Importance of Investment Flows from Development Partners and Emerging Financiers 7 Scope of This Study 8 Methodology 8 Data Limitations 9 Notes 10 References 10 Chapter 2 Investment in Power Generation in Sub-Saharan Africa: An Overview 11 Current Power Generation Systems in Sub-Saharan Africa 11 Power Generation Capacity Additions over the Past 20 Years 11 Independent Power Projects 14 Chinese-Supported Power Generation Projects 18 Who Has Funded What? 18 Notes 28 References 29 Chapter 3 Factors that Support Independent Power Projects and Their Success 31 Introduction 31 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   v   vi Contents Power Sector Reforms and Independent Power Projects 32 The Importance of Independent Regulation 36 The Importance of Planning, Procurement, and Financial Sustainability 38 A Framework for Understanding the Enabling Environment for IPPs 41 The Performance of Five Countries 43 Notes 45 References 45 Chapter 4 Independent Power Projects: An Analysis of Types and Outcomes 47 Introduction 47 Ownership and Financing Structures 48 The Role of Development Finance Institutions 53 Risk and Ways to Mitigate It 53 Technology Options: A Rise in Independent Power Projects Using Solar and Wind Energy 63 Procurement and Contracting Mechanisms 68 Notes 86 References 87 Chapter 5 Conclusions 89 Introduction 89 Five Main Conclusions 90 Part 2 Five Country Case Studies 97 Chapter 6 Case Study 1: Kenya’s Electric Power Promise 99 Introduction 99 Kenya’s Electricity Sector: An Overview 100 Independent Power Projects, Emergency Power Projects, and Publicly Sponsored Power Plants 109 Emerging Renewable Technologies in Kenya 112 Independent Power Plants: Risk Mitigation Mechanisms and Other Contingencies 115 The Public Sector Making Way for the Private Sector, or a Contested Playing Field? 116 Conclusions and Recommendations 117 Annex 6A The Initial 5,000+ MW Program: An Overview of Targets and Timelines 119 Notes 120 References 123 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Contents vii Chapter 7 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 127 Introduction 127 Nigeria’s Electricity Sector: An Overview 128 State Investment in Power Projects in Nigeria 142 Independent Power Project Investments in Nigeria 143 Chinese-Funded Projects 149 A New Role for Renewable Energy 151 Conclusions 152 Notes 155 References 156 Chapter 8 Case Study 3: Investment in Power Generation in South Africa 159 Introduction 159 South Africa’s Electricity Sector: An Overview 160 Eskom 164 Other Electricity Generation Providers in South Africa 171 Public versus IPP Investment, Direct Negotiations versus Competitive Bids, and Thermal versus Renewables 184 Conclusions 186 Notes 189 References 190 Chapter 9 Case Study 4: Power Generation Results Now, Tanzania! 193 Introduction 193 Tanzania’s Electricity Sector: An Overview 194 IPTL and Songas, and the Next Generation of Independent Power Projects 205 Future Projects, Public and Private 212 Conclusions 216 Annex 9A  Cost Comparison, TANESCO and Independent Power Projects 218 Annex 9B  IPTL and Songas Project Costs, Tanzania 219 Annex 9C  ICSID Tribunal, IPTL 220 Annex 9D Production-Sharing Agreement, TPDC and PanAfrican Energy 221 Notes 222 References 226 Chapter 10 Case Study 5: Power Generation Developments in Uganda 227 Introduction 227 The History and Structure of Uganda’s Electricity Sector 228 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 viii Contents Current Attributes and Recent Performance of the Electricity Sector 240 Measuring the Outcomes 256 Notes 261 References 264 Appendix A Total Investments in Electric Power Generation in Sub-Saharan Africa 265 Appendix B Government Investments in Electric Power Generation in Sub-Saharan Africa 271 Appendix C Investments in Electric Power Generation in Sub-Saharan Africa Financed by Official Development Assistance and Development Finance Institutions 273 Appendix D Investments in Electric Power Generation in Sub-Saharan Africa Financed by Chinese Sources 279 Appendix E Independent Power Projects in Sub-Saharan Africa 283 Boxes 1.1 Definition of Independent Power Projects 6 3.1 Legislation to Promote Sector Competition: Examples from Five Countries 37 4.1 Mitigating the Risk of an Independent Power Project: The Case of Azura, Nigeria 57 4.2 Independent Power Projects Using Hydropower, Geothermal, and Biomass 65 4.3 The South African Experiment with Renewable Energy Feed-in Tariffs 66 4.4 Direct Negotiations and Competitive Procurement in Uganda 73 4.5 A Comparison of Competitive Tenders and Direct Negotiations in Kenya and Tanzania 74 4.6 How the Brazilian Energy Auction Works 83 10.1 Major Institutions in Uganda’s Power Sector 229 Figures ES.1 Grid-Connected Generation Capacity: Sub-Saharan Africa, 1990–2013 xxv ES.2 Investments in Power Generation, Five-Year Moving Average: Sub-Saharan Africa (Excluding South Africa), 1994–2013 xxvi ES.3 Independent Power Projects, by Year of Financial Close: Sub-Saharan Africa (Excluding South Africa), 1994–2014 xxvii Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Contents ix ES.4 Total Investment by IPPs and by Development Finance Institutions: Sub-Saharan Africa (Excluding South Africa), 1994–2014 xxvii ES.5 Electricity Sector Structures: Sub-Saharan Africa, 2014 xxix 1.1 Percentage of Firms Relying on Generators: Selected Countries in Sub-Saharan Africa, Various Years 4 1.2 Average Availability of Generation Plants Run by Eskom: South Africa, 2000–15 5 1.3 Projected Electricity Demand: Sub-Saharan Africa, 2015–40 5 2.1 Power Generation Sources: Sub-Saharan Africa, 2013 12 2.2 Grid-Connected Generation Capacity: Sub-Saharan Africa, 1990–2013 13 2.3 Independent Power Projects, by Year of Financial Close: Sub-Saharan Africa (Excluding South Africa), 1994–2014 15 2.4 Countries with the Most Independent Power Project Capacity: Sub-Saharan Africa (Excluding South Africa), 1994–2014 15 2.5 Number of Independent Power Projects: Sub-Saharan Africa (Excluding South Africa), 1994–2014 16 2.6 Number of Independent Power Projects in Various Size Categories to Have Reached Financial Close: Sub-Saharan Africa (Excluding South Africa), as of 2014 16 2.7 Independent Power Project Capacity, by Technology: Sub-Saharan Africa (Excluding South Africa), 1994–2014 17 2.8 Comparison of Chinese-Funded Power Projects and IPPs, by Total Number: Sub-Saharan Africa (with and without South Africa), 1994–2014 19 2.9 Comparison of Chinese-Funded Power Projects and IPPs, by Generation Capacity: Sub-Saharan Africa, 1994–2014 19 2.10 Chinese-Supported Power Project Capacity, by Technology: Sub-Saharan Africa, 2001–14 20 2.11 Investments in Power Generation, Five-Year Moving Average: Sub-Saharan Africa (Excluding South Africa), 1994–2013 21 2.12 Total Investment by IPPs and by Development Finance Institutions: Sub-Saharan Africa (Excluding South Africa), 1994–2014 24 2.13 Investment in Independent Power Projects, by Country: Sub-Saharan Africa, 1994–2014 24 2.14 Official Development Assistance, Development Finance Institutions (Excluding IPP Investments), and Arab Investment in Power Generation, Five-Year Moving Average: Sub-Saharan Africa (Excluding South Africa), 1994–2013 27 3.1 Electricity Sector Structures: Sub-Saharan Africa, 2014 33 4.1 Competitive Tenders versus Directly Negotiated Projects, Sub-Saharan Africa (Excluding South Africa), 1994–2014 70 4.2 Average Bid Prices for Independent Power Projects Using Renewable Energy, South Africa 81 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 x Contents 6.1 Overview of Kenya’s Electricity Sector 102 6.2 Electricity Production, by Firm/Organization Type: Kenya, 2013–14 106 6.3 Electricity Production of Six Independent Power Projects: Kenya, 2013–14 106 7.1 Transitional Electricity Market Structure, Nigeria 134 7.2 Energy Produced, by Technology: Nigeria, 2013 Averages 136 7.3 Installed Capacity, by Project Type: Nigeria, 2013 Averages 137 7.4 Energy Produced, by Project Type: Nigeria, 2013 Averages 137 7.5 Performance of Electricity Sector: Nigeria, January 2012–October 2013 139 7.6 Average Monthly Capacity Factors of Open-Cycle Gas Turbines: Nigeria, January 2012–October 2013 140 7.7 Average Monthly Capacity Factors of Combined-Cycle Gas Turbines: Nigeria, January 2012–October 2013 140 7.8 Capacity Factors of Various Technologies and Owners: Nigeria, FY2012/13 141 7.9 Timeline of Power Sector Reform Interventions and Generation Investments: Nigeria, 1998–2015 143 8.1 Structure of South Africa’s Electricity Market 162 8.2 Eskom’s Electricity Generation Mix: South Africa, 2014 167 8.3 Eskom’s Installed Generation Capacity over Time: South Africa, 1990–2014 167 8.4 Eskom’s Average Prices and Annual Increases: South Africa, 1970–2014 168 8.5 Proportion of Eskom’s Electricity Generated by OCGTs: South Africa, FY2013/14 169 8.6 Proportion of Primary Energy Costs Attributed to OCGTs: South Africa, FY2013/14 170 8.7 Average Availability of Generation Plants Run by Eskom: South Africa, 2000–15 170 8.8 Eskom’s Energy Purchases from Other Generators: South Africa, FY2013/14 172 8.9 Average Nominal Bid Prices in South Africa’s REIPPPP 180 8.10 Capacity Factors for Wind and Solar PV: South Africa, 2014 182 8.11 Share of Debt Financing in REIPPPP, Rounds 1–3: South Africa, 2011–14 182 8.12 Share of Initial Debt Providers in REIPPPP, Rounds 1–3: South Africa, 2011–14 183 8.13 Major Debt Providers in REIPPPP, Rounds 1–3, by Number of Projects per Lender: South Africa, 2011–14 183 9.1 Overview of Tanzania’s Electricity Sector, 2014 197 9.2 Share of Grid-Generated Electricity Production, by Type of Producer: Tanzania, 2013 202 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Contents xi 9.3 Emergency Power Plants’ Contributions to Generation: Tanzania, 2013 204 9.4 Emergency Power Plants’ Shares of Total Costs: Tanzania, 2013 205 10.1 Structure of Uganda’s Power Sector 228 10.2 Umeme Energy Losses: Uganda, 2005–14 233 10.3 Umeme Collection Rates: Uganda, 2005–14 234 10.4 Umeme Customers: Uganda, 2005–14 234 10.5 Umeme Investment: Uganda, 2005–13 235 10.6 Total Capacity, by Technology: Uganda, 2004–13 241 10.7 Sources of Electricity Sold to UETCL: Uganda, 2005–13 242 10.8 Ownership and Funding, by Share of Installed Capacity: Uganda, 2014 243 10.9 Sources of Funding, by Estimated Share of Installed Capacity: Uganda, 2020 243 Map 8.1 Eskom’s Power Stations 161 Tables ES.1 Total Investment in Completed Power Generation Plants: Sub-Saharan Africa (Excluding South Africa), 1990–2013 xxv ES.2 Largest Chinese-Funded Projects in Sub-Saharan Africa, by Investment and Capacity, 2001–14 xxviii ES.3 Factors Contributing to Successful Independent Power Project Investments, Sub-Saharan Africa xxxii 2.1 Significant Installed Power Generation Capacity and Gross Domestic Product: Sub-Saharan Africa, 2013 12 2.2 Significant Power Generation Capacity Additions: Sub-Saharan Africa, 2000–13 13 2.3 Renewable Energy Investments: South Africa, 2012–14 18 2.4 Total Investment in Completed Power Generation Plants: Sub-Saharan Africa (Excluding South Africa), 1990–2013 21 2.5 Long-Term Sovereign Credit Ratings: Sub-Saharan Africa, January 2014 23 2.6 Largest Independent Power Projects, by Investment Total and Capacity: Sub-Saharan Africa (Excluding South Africa), 1994–2014 25 2.7 Largest Chinese-Funded Projects in Sub-Saharan Africa, by Investment and Capacity, 2001–14 26 2.8 Largest Power Projects Funded by Official Development Assistance, Arab Sources, or Development Finance Institutions, by Capacity and Funding Source: Sub-Saharan Africa, 1994–2013 27 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xii Contents 2.9 Largest Power Projects Funded by Official Development Assistance, Arab Sources, or Development Finance Institutions, by Investment and Capacity: Sub-Saharan Africa, 1994–2013 28 3.1 Sub-Saharan African Countries with Independent Electricity/Utility Regulators, by Year Established 36 3.2 Factors Contributing to Successful Independent Power Project Investments, Sub-Saharan Africa 42 3.3 Summary of Power Sector Features in Case Study Countries, Sub-Saharan Africa 44 4.1 Independent Power Projects in Five Selected Countries, Sub-Saharan Africa, 1994–2014 48 4.2 Independent Power Project Sponsors and Debt Holders in Case Study Countries (Excluding South Africa), Sub-Saharan Africa 49 4.3 Sub-Saharan African Countries with Feed-in Tariffs, Grid-Connected, as of 2014 66 4.4 Criteria for the Evaluation of Global Energy Transfer Feed-in Tariffs, Uganda 68 4.5 Comparison of Procurement Methods Used for Independent Power Projects, Sub-Saharan Africa 69 4.6 Summary of IPP Projects and Procurement Methods in Case Study Countries: Sub-Saharan Africa, 1990–2014 71 4.7 Sample of Competitive Tenders in Selected Countries, Sub-Saharan Africa 75 4.8 Cost Comparison of Directly Negotiated and Internationally Competitive Bid Projects, by Technology, 1994–2014 76 4.9 Cost Comparison of Medium-Speed Diesel/Heavy Fuel Oil Generators, 2013–15 76 4.10 Results of South Africa’s Efforts to Procure Renewable Energy Independent Power Projects, by Bidding Round 79 6.1 KenGen’s Installed Generation Capacity: Kenya, as of April 2015 104 6.2 Independent Power Projects, Installed Generation Capacity: Kenya, as of April 2015 105 6.3 Total Production, by Technology/Fuel: Kenya, 2013 and 2014 107 6.4 Actual and Targeted Availability of Public and Private Diesel Plants: Kenya, April 2015 107 6.5 Actual and Targeted Availability of Public and Private Geothermal Plants: Kenya, April 2015 108 6.6 Electricity Prices of Public and Private Diesel Plants: Kenya, June 2015 109 6.7 Prices among Public and Private Geothermal Plants: Kenya, June 2015 109 6A.1 Cumulative Installed Capacity, 5,000+ MW Program, Kenya 120 7.1 Nigeria: An Overview 128 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Contents xiii 7.2 Successor Power Generation Companies to the National Electric Power Authority, Later Privatized, Nigeria 130 7.3 Key Institutions and Their Functions in the Power Sector, Nigeria 131 7.4 Evolution of the Power Market, Nigeria 133 7.5 Residual State-Owned Plants, Nigeria 138 7.6 Successor Power Generation Companies, Now Privatized, Nigeria 138 7.7 Independent Power Projects, Nigeria 138 7.8 National Integrated Power Projects, Nigeria 139 7.9 Overview of AES Barge, an Independent Power Project, Nigeria 144 7.10 Overview of Okpai, an Independent Power Project, Nigeria 146 7.11 Overview of Afam VI, an Independent Power Project, Nigeria 146 7.12 Overview of Aba, an Integrated Power Project, Nigeria 147 7.13 Overview of Azura-Edo, an Independent Power Project, Nigeria 148 7.14 Overview of Olorunsogo I Power Plant, Nigeria 150 7.15 Overview of Omotosho I and II Power Plants, Nigeria 150 7.16 Overview of Zungeru Hydropower Plant, Nigeria 151 7.17 Renewable Energy Targets for 2025, Nigeria 152 8.1 South Africa: An Overview 160 8.2 South Africa’s Integrated Resource Plan, 2010–30 165 8.3 Eskom’s Electricity Generation Capacity: South Africa, 2014 166 8.4 Eskom’s Recent Generation Capacity Additions: South Africa, 2006–13 168 8.5 Eskom’s Energy Purchases from Other Generators: South Africa, FY2013/14 171 8.6 Medium-Term Power Purchase Programme Prices: South Africa, 2009–18 175 8.7 Economic Development Thresholds and Targets for Wind Projects in South Africa’s REIPPPP 178 8.8 Results of REIPPPP Rounds 1–3: South Africa, 2011–14 181 8.9 Procurement of OCGTs: A Comparison of Eskom’s Plants and IPPs, South Africa 185 8.10 Wind Farm Procurement, South Africa 186 9.1 Onshore and Offshore Gas Discoveries and Developments: Tanzania, 1974–2014 199 9.2 Grid-Connected Capacity: Tanzania, as of 2014 200 9.3 Shares/Costs of Capacity and Generation, by Type of Producer: Tanzania, 2013 202 9.4 Comparison of Costs, by Type of Producer: Tanzania, 2013 203 9.5 Costs of Generation, by Emergency Power Plant: Tanzania, 2013 204 9.6 Generation Projects Planned in the Near Term, Tanzania 213 9A.1 TANESCO’s Own-Generation Costs: Tanzania, 2013 218 9B.1 IPTL Project Costs, Tanzania 219 9B.2 Songas Project Costs, Tanzania 219 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xiv Contents 9D.1 PSAs between the TPDC and PanAfrican Energy Tanzania Limited 221 10.1 REFiT Overview: Uganda, as of January 2015 238 10.2 Overview of Available Tax Incentives for Power Generation Investments, Uganda 239 10.3 Risk Mitigation and Investment Incentives for Thermal and RET Projects, Uganda 240 10.4 Uganda’s Power Plants 242 10.5 Electricity Costs for All Operational Generation Assets, Uganda 244 10.6 Overview of Bujagali HPP—Implementation, Financing, and Cost: Uganda 249 10.7 GETFiT Evaluation Criteria, Uganda 250 10.8 Overview of Approved GETFiT Projects, Uganda 252 10.9 Karuma HPP Project Data, Uganda 254 10.10 Isimba HPP Project Data, Uganda 254 10.11 Ayago HPP Project Data, Uganda 255 10.12 Summary of Procurement Models Used since the Sector Reform of 1999/2000, Uganda 256 A.1 Total Annual Investments in Electric Power Generation, by Country or Territory: Sub-Saharan Africa, 1990–2014 266 A.2 Total Annual Investments in Electric Power Generation, by Source of Funding: Sub-Saharan Africa, 1990–2013 269 A.3 Total Annual Investments in Electric Power Generation, by Source of Funding: Sub-Saharan Africa (Excluding South Africa), 1990–2013 270 B.1 Government Investments in Electric Power Generation, by Country or Territory: Sub-Saharan Africa, Cumulative 1990–2013 271 C.1 Official Development Assistance and Development Finance Institution Investments in Electric Power Generation, by Country and Project: Sub-Saharan Africa, 1990–2012 273 D.1 Investments Funded by Chinese Sources, by Country and Project: Sub-Saharan Africa, 1990–2014 280 E.1 IPP Investments in Angola, by Project 283 E.2 IPP Investments in Cabo Verde, by Project 284 E.3 IPP Investments in Cameroon, by Project 285 E.4 IPP Investments in Côte d’Ivoire, by Project 286 E.5 IPP Investments in The Gambia, by Project 288 E.6 IPP Investments in Ghana, by Project 289 E.7A IPP Investments in Kenya, by Project 291 E.7B IPP Investments in Kenya, by Project 294 E.7C IPP Investments in Kenya, by Project 297 E.8 IPP Investments in Madagascar, by Project 299 E.9 IPP Investments in Mauritius, by Project 300 E.10 IPP Investments in Nigeria, by Project 302 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Contents xv E.11 IPP Investments in Rwanda, by Project 304 E.12 IPP Investments in Senegal, by Project 305 E.13 IPP Investments in Sierra Leone, by Project 307 E.14 IPP Investments in Tanzania, by Project 308 E.15 IPP Investments in Togo, by Project 310 E.16A IPP Investments in Uganda, by Project 311 E.16B IPP Investments in Uganda, by Project 313 E.16C IPP Investments in Uganda, by Project 314 E.16D IPP Investments in Uganda, by Project 315 E.17 IPP Investments in Zambia, by Project 316 E.18 IPP Investments in South Africa, by Project 317 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Foreword Access to electricity is fundamental to development and a key driver for Sub-Saharan Africa’s economic growth. However, a majority of countries in the ­ subcontinent are still experiencing power shortages, and two out of three ­ households, or close to 600 million people, have no electricity at all. Without electricity, health clinics struggle to provide basic services, children are unable to get a proper education, and businesses cannot grow and thrive in today’s global economy. If we do not address the underlying reasons preventing Africans from achieving wider access to reliable and affordable electricity, economic growth on the continent will slow, keeping millions trapped in poverty. Among the many development challenges facing Sub-Saharan Africa is the urgent need to increase power generation capacity. The financing requirements of the power sector far exceed most countries’ already stretched public finances. Therefore, greater volumes of private investment will be critical to scale up generation capacity and thereby expand and improve electricity supply. ­ While public and utility financing has traditionally been the largest source of investment in power generation, independent power projects (IPPs) are now growing rapidly. They presently constitute the primary vehicle for private invest- ment in the African power sector and most likely will continue to do so for the foreseeable future. Currently, 126 IPPs are present in 18 countries of Sub-Saharan Africa. Together, they account for more than 13 percent of the subcontinent’s total installed generation capacity—25 percent if South Africa is excluded. This is a notable share of total generation, given that most IPP investment has occurred in just the past few years. However, IPP investments could be much larger and less concentrated. South Africa alone accounts for 62 percent of IPP capacity; most of the remaining projects are located in a handful of countries. Many more African countries could and should benefit from such investments. Although African governments strive to foster private sector participation, increased private investment will not materialize just because the need is great. Investments will flow where rewards demonstrably outweigh risks, while governments will demand investments that serve the public interest and support ­ poverty reduction and growth targets. Investment and development imperatives are often difficult to balance. The objective of this study is to evaluate the experience of IPPs and to identify Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   xvii   xviii Foreword lessons that can help African countries attract more and better private investment. At the core of this analysis is a reflection on whether IPPs have ­ ­ benefited Sub-­Saharan Africa and how such transactions might be improved. The analysis is based primarily on in-depth case studies carried out in five countries—Kenya, Nigeria, South Africa, Tanzania, and Uganda—that have the most extensive experience with IPPs. An unprecedented body of data has been collected and analyzed. This report highlights not only the challenges that policy makers are facing but also the underlying factors that contributed to healthy investment climates. Ultimately, the report is intended to offer references, options, and tools that may help African countries achieve scaled-up and sustainable power sector invest- ment for the benefit of their people and their economies as a whole. Makhtar Diop Vice President, Africa Region World Bank Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Acknowledgments This study was authored by a team comprising Anton Eberhard, Katharine Gratwick, Elvira Morella, and Pedro Antmann. Laban Kariuki, Rene Meyer, and Marek Raciborski contributed to the country case studies. Anshul Rana provided expert research assistance in investment data. Luiz Augusto Barroso and Priscila Lino provided insights into the Brazilian auction experience. Substantive inputs were received from Clara Alvarez and Dan Vardi. The work was carried out under the guidance of Lucio Monari, Meike van Ginneken, and Jamal Saghir. This study draws from existing reports authored by Anton Eberhard and Katharine Gratwick and is the culmination of inquiry and analysis carried out over the course of several years by them as well as by researchers at the World Bank. The team has engaged with many individuals and owes each one a great debt of gratitude for contributing to the collective understanding of investment in electricity generation in Africa. Numerous public stakeholders and private investors working in the case study countries, including in public utilities, regula- tors, and independent power projects (IPPs), provided invaluable insights. The team is grateful to colleagues in the Global Energy and Extractives Practice, who contributed information, careful review, and recommendations concerning the five case study countries. Specifically, the team benefited from discussions with Raihan Elahi, Erik Fernstrom, Joseph Kapika, Laurencia Karimi Njagi, Paivi Koljonen, Nataliya Kulichenko, Zayra Romo, Robert Schlotterer, Sajjad Shah, Vlado Vucetic, and Mustafa Zakir Hussain. The team is also deeply grateful to colleagues from the country-specific teams that reviewed and vali- dated the case studies. The team wishes to thank peer reviewers Richard Damania, Vivien Foster, Ada Karina Izaguirre, Peter Johansen, Ranjit Lamech, Luiz T. A. Maurer, Raghuveer Sharma, and Sameer Shukla, who provided valuable comments and constructive insights at various stages of this work. The team is also grateful to Steven Kennedy for his editorial assistance. This work could not have been possible without financial support from the Africa Renewable Energy and Access Program, which is gratefully acknowledged. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   xix   About the Authors Anton Eberhard is a professor at the University of Cape Town’s Graduate School of Business in South Africa. In his research and teaching, he focuses on the restructuring and regulation of the electricity sector, investment challenges, and links to sustainable development. He has worked in the energy sector for more than 30 years and was the founding director of the Energy and Development Research Centre. He is also a foundation member of the Academy of Science of South Africa, chair of the Deputy-President’s Advisory Panel on the Electricity Sector, and a member of the Ministerial Advisory Council on Energy. Previously, he served for seven years on the Board of the National Electricity Regulator of South Africa. The more than 100 peer-reviewed publications to his credit include two recent books, Power-Sector Reform and Regulation in Africa and Africa’s Power Infrastructure: Investment, Integration, Efficiency. He works exten- sively across Sub-Saharan Africa and has undertaken numerous assignments for governments, utilities, regulatory authorities, donor and multilateral agencies, and private sector companies. Katharine Gratwick is a former senior researcher at the Management Programme in Infrastructure Reform and Regulation in Cape Town, South Africa. She pres- ently works as an independent energy consultant, based in Houston, Texas. Her area of research is largely independent power projects across Sub-Saharan Africa. She has also worked with multilateral and bilateral institutions on electricity access, as well as with the private sector on a wide range of subjects, including liquefied natural gas. Elvira Morella is a senior energy specialist in the Global Energy and Extractives Practice at the World Bank, where she leads energy sector investment operations and major analytical work in the Sub-Saharan region. Her focus includes energy markets and institutions, power sector reforms, regional integration, and power trade. She has also served as infrastructure economist in operations and analytical assignments in the water and urban sectors in several regions, including Sub- Saharan Africa, the Middle East and North Africa, and East Asia and Pacific. Prior to joining the World Bank, she worked as a technical expert in the Development Cooperation Department of the Italian Ministry of Foreign Affairs, advising on Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   xxi   xxii About the Authors major environmental and cultural heritage preservation assistance programs in the Arab Republic of Egypt and the Syrian Arab Republic. Pedro Antmann is a lead energy specialist at the World Bank, working in the areas of institutional restructuring, regulation, tariffs, and management of utili- ties, including incorporation of information technology (IT) applications. Since September 2008, he has served as a member of more than 50 project teams in the six regions in which the Bank develops operations. From 1979 to 1995, he worked for Uruguay’s state-owned vertically integrated electricity company (UTE) in the areas of thermal power generation (operating existing plants and planning and commissioning new ones), transmission, international power exchanges, distribution, and retail. From 1995 to 1997, he served in Uruguay’s Ministry of Industry, Energy, and Mines, initially as director of the National Board of Energy and later as deputy minister of industry, energy, and mines, in charge of energy. From 1998 to 2000, he was associated with the French water and sani- tation company Suez Lyonnaise des Eaux as international manager, in charge of operations of an affiliate company serving 3 million customers in Buenos Aires, Argentina. More recently (2000–08), he served as partner and senior consultant in Mercados Energy Markets International, a consultancy company specialized in institutional restructuring, regulation, and management of the energy sector. There, he conducted projects in more than 40 countries in the fields of design and implementation of new regulatory frameworks, tariff setting for network industries, management of utilities (including incorporation of IT applications), rural electrification, and benchmarking studies for electricity companies. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary Introduction The track record of Sub-Saharan Africa’s power sector is dismal. Two out of three households in Sub-Saharan Africa, close to 600 million people, have no electric- ity connection. Most countries in the region have pitifully low access rates, including rural areas that are the world’s most underserved. In some countries, less than 5 percent of the rural population has access to electricity. Chronic power shortages are a primary reason. The region simply does not generate enough electricity. The Republic of Korea alone generates as much elec- tricity as all of Sub-Saharan Africa. Across the region, per capita installed genera- tion capacity is barely one-tenth that of Latin America. The need for large investments in power generation capacity is obvious, espe- cially in the face of robust economic growth on the continent, which has been the key driver of electricity demand over the last decade. The International Energy Agency predicts that the demand for electricity in Sub-Saharan Africa will increase at a compound average annual growth rate of 4.6 percent, and by 2030 it will be more than double the current electricity production. The World Bank estimated in 2011 that Sub-Saharan Africa needed to add approximately 8 gigawatts (GW) of new generation capacity each year through 2015 (Eberhard and others 2011). But, in fact, over the last decade an average of only 1–2 GW has been added annually. The cost of addressing the needs of Sub-Saharan Africa’s power sector has been estimated at US$40.8 billion a year, which is equivalent to 6.35 per- cent of Africa’s gross domestic product (GDP). The existing funding is far below what is needed. This large funding gap cannot be bridged by the pub- lic sector alone. Private participation is critical. Historically, most private sector financing has been channeled through independent power projects (IPPs). IPPs are defined as power projects that mainly are privately devel- oped, constructed, operated, and owned; have a significant proportion of private finance; and have long-term power purchase agreements (PPAs) with a utility or another off-taker. Like any other private investment, IPPs will not materialize in the absence of a suitable enabling environment. The primary objective of this study is to evaluate Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   xxiii   xxiv Executive Summary the experience of IPPs and see what is necessary to maximize their contribution to mitigating Sub-Saharan Africa’s electric power woes. Investment in Power Generation in Sub-Saharan Africa: An Overview Current Power Generation Systems in Sub-Saharan Africa In 2012, the 48 countries of Sub-Saharan Africa had a total grid-connected power generation capacity of only 83 GW. South Africa accounts for over half of this total. The remaining Sub-Saharan African countries have a combined capac- ity of only 36 GW, and just 13 of these countries have power systems larger than 1 GW. Twenty-seven countries have grid-connected power systems smaller than 500 megawatts (MW), and 14 have systems smaller than 100 MW. Across Sub-Saharan Africa (excluding South Africa, which uses mostly coal), hydropower contributes just over half the capacity. Fossil fuels, primarily natural gas and diesel or heavy fuel oil, along with some coal, make up almost all the remainder. Renewables such as biomass, geothermal, wind, and solar add about 1 percentage point. Power Generation Capacity Additions and Investment over the Past 20 Years Between 1990 and 2013, only 24.85 GW of new generation capacity was added across Sub-Saharan Africa, of which South Africa accounted for 9.2 GW figure ES.1). In the first decade of this period, 1990 to 2000, the countries of (­ Sub-Saharan Africa other than South Africa added only 1.84 GW, and some even lost capacity. Between 2000 and 2013, investments picked up in these countries with an additional 13.8 GW installed. However, 94 percent of this increase occurred in only 15 countries, leaving dozens that added hardly any capacity at all. And as in the decade between 1990 and 2000, some actually lost capacity. Civil strife and lack of adequate system maintenance were the prevalent causes. Between 1990 and 2013, investments in new power generation capacity totaled approximately $45.6 billion ($31.3 billion, excluding South Africa), or far below what is required to meet Africa’s growth and development aspirations (table ES.1). Although public utilities have historically been the major sources of funding for new power generation capacity, that trend is changing. Most African governments are unable to fund their power needs, and most utilities do not have investment-grade ratings and so cannot raise sufficient debt at affordable rates. Official development assistance (ODA) and development finance institutions (DFIs) have only partially filled the funding gap. ODA and concessional funding has fluctuated considerably over the past two decades and has recently been overshadowed by IPP and Chinese-supported investment. Indeed, private invest- ments in IPPs and Chinese funding are now the fastest-growing sources of finance for Africa’s power sector (figure ES.2). Independent Power Projects IPPs in Sub-Saharan Africa date to 1994. Representing a minority of total genera- tion capacity, IPPs have mainly complemented incumbent state-owned utilities. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xxv Figure ES.1  Grid-Connected Generation Capacity: Sub-Saharan Africa, 1990–2013 85 50 80 45 75 40 Gigawatts Gigawatts 70 35 65 30 60 55 25 50 20 90 12 92 94 96 98 00 02 04 06 08 10 19 20 19 19 19 19 20 20 20 20 20 20 SSA (left axis) SSA excl. SA (right axis) Source: Authors’ compilation of data from U.S. EIA 2014. Note: SA = South Africa; SSA = Sub-Saharan Africa. Table ES.1  Total Investment in Completed Power Generation Plants: Sub-Saharan Africa (Excluding South Africa), 1990–2013 Type of investment Debt and equity (US$, millions) MW added % of total MW % of total investment Government and utilities 15,883.87 8,663.26 43.66 50.67 IPPs 6,950.12 4,760.60 23.99 22.17 China 5,009.80 3,263.73 16.45 15.98 ODA, DFI, and Arab funds 3,506.48 3,156.15 15.91 11.18 Total 31,350.27 19,843.73 100.00 100.00 Source: Compiled by the authors, based on various primary and secondary sources. For more information, see table 2.4 in chapter 2. Note: DFI = development finance institution; IPP = independent power project; MW = megawatt; ODA = official development assistance. Nevertheless, IPPs are an important source of new investment in the power sector in a number of African countries. ­ IPPs are now present in 18 Sub-Saharan countries—all with varying degrees of sector reform and private participation. Currently, 59 projects (greater than 5 MW) are in countries other than South Africa, totaling $11.1 million in invest- ments and 6.8 GW of installed generation capacity. Including South Africa adds 67 more IPPs, bringing the total to 126, with an overall installed capacity of 11 GW and investments of $25.6 billion. IPPs in Sub-Saharan Africa range in size from a few megawatts to around 600 MW. The overwhelming majority of IPP capacity (82 percent) is thermal; only 18 percent is fueled by renewables. However, there is important growth in Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xxvi Executive Summary Figure ES.2  Investments in Power Generation, Five-Year Moving Average: Sub-Saharan Africa (Excluding South Africa), 1994–2013 2,000 Investment (US$, millions) 1,500 1,000 500 0 94 96 98 00 02 04 06 08 10 12 19 19 19 20 20 20 20 20 20 20 DFIs (multilateral) Arab (private and public) ODA (OECD) Chinese flows Sum of IPP investments Source: Compiled by the authors, based on various primary and secondary sources. Note: Ghana’s Kpone IPP and Nigeria’s Azura investments in 2014 and 2015, respectively, which together total $900 million, will result in a continued upward tick in IPP investments. DFI = development finance institution; IPP = independent power project; ODA = official development assistance; OECD = Organisation for Economic Co-operation and Development. renewables. For example, three wind projects reached financial close between 2010 and 2014, and seven small hydropower projects are on the horizon. South Africa procured 3.9 GW in private power between 2012 and 2014, all of which is renewable. As shown in figure ES.3, there have been three major IPP investment spikes: 1999–2002, 2008, and 2011–2014. The first two spikes were due to the financial close of a small number of comparatively large projects. In 2011, IPP investments began taking off. Excluding South Africa, total IPP invest- ment for projects in Sub-Saharan Africa between 1990 and 2013 was $8.7 billion, whereas in 2014 alone another $2.3 billion was added. Previously, IPP investments in South Africa had lagged those in other Sub-Saharan coun- tries, but between 2012 and 2014 that country closed $14 billion in renew- able energy IPPs. Although the conditions were varied in the countries where IPPs and other private participation took root, certain themes were common. With the exception of South Africa and Mauritius, none of the Sub-Saharan African countries with IPPs had an investment-grade rating. The possibility of a traditional project-financed IPP deal in this climate was limited. DFIs that invest in the private sector have made a significant contribution to fund- ing IPPs (figure ES.4). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xxvii Figure ES.3  Independent Power Projects, by Year of Financial Close: Sub-Saharan Africa (Excluding South Africa), 1994–2014 1,000 900 800 700 600 Megawatts 500 400 300 200 100 0 01 11 99 02 03 09 10 12 13 94 98 08 96 04 05 06 14 97 07 20 20 19 20 20 20 20 20 20 19 19 20 19 20 20 20 20 19 20 Source: Compiled by the authors, based on utility data, primary sources, and the Private Participation in Infrastructure (PPI) database. Note: No projects reached financial close in 1995 or 2000. Figure ES.4  Total Investment by IPPs and by Development Finance Institutions: Sub-Saharan Africa (Excluding South Africa), 1994–2014 1,200 1,000 Investment (US$, millions) 800 600 400 200 0 96 94 98 00 02 04 06 08 10 12 14 19 19 19 20 20 20 20 20 20 20 20 IPP investment without SA DFI investment in IPP without SA Source: Compiled by the authors, based on various primary and secondary sources. Note: DFI = development finance institution; IPP = independent power project; SA = South Africa. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xxviii Executive Summary Table ES.2  Largest Chinese-Funded Projects in Sub-Saharan Africa, by Investment and Capacity, 2001–14 Investment Capacity Project Country (US$, millions) (MW) Karuma Hydropower Project Uganda 1,688 600 Zungeru Hydropower Project Nigeria 1,293 700 Morupule B Power Station Botswana 970 600 Omotosho Power Plant II (NIPP) Nigeria 660 513 Memve’ele Hydropower Project Cameroon 637 201 Bui Hydropower Project Ghana 621 400 Soubré Hydropower Project Côte d’lvoire 571 270 Source: Compiled by the authors, based on various primary and secondary source data. Note: MW = megawatt; NIPP = national integrated power project. Chinese-Funded Power Generation Projects In addition to IPPs, significant increases in generation capacity have stemmed from Chinese-funded projects. Chinese-funded generation projects can be found in 19 countries in Sub-Saharan Africa. Eight of these countries have IPPs as well as Chinese-funded projects. Between 1990 and 2014, there were 34 such projects in Sub-Saharan Africa, totaling 7.5 GW. Chinese-funded projects far exceed IPPs in terms of total mega- watts, especially for the years 2010–14, with an average size of 226 MW, in contrast to the IPP average of 98 MW. As of 2014, Chinese-funded projects exceeded IPPs in total megawatts and in total dollars invested. The majority of Chinese-funded projects are large hydropower projects (table ES.2), for which Chinese engineering, procurement, and construction contractors have become renowned worldwide. The typical project structure involves a contractor plus a financing contract. The majority of these projects received funding from the China ExIm Bank (responsible for soft loans and export credit) on behalf of the Chinese government. Additional finance has been provided by other banks owned in whole or part by the Chinese government. Factors that Support Independent Power Projects and Their Success Power Sector Reforms and Independent Power Projects In recent decades, in response to the poor financial and technical performance of their power sectors, developing countries were encouraged to unbundle their electricity utilities, vertically and horizontally, to introduce competition, to create independent regulators, and to make space for private sector participation. As of 2014, however, 21 of the 48 Sub-Saharan countries still had state-owned and vertically integrated utilities with no private sector participation (figure ES.5, model 1). The second-largest group of countries also had vertically integrated state-owned utilities but, in addition, had introduced IPPs. A much smaller group of countries had unbundled power generation from transmission and distribu- tion, and also incorporated IPPs. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xxix Figure ES.5  Electricity Sector Structures: Sub-Saharan Africa, 2014 1. 2. 3. 4. Benin G Gabon G G G G Botswana Guinea Burkina Faso Guinea-Bissau Namibia Burundi T Liberia T T T T CAR, Chad Malawi, Mali Congo, DRC Mauritania, Niger D Djibouti, Eritrea D Somalia D D Mozambique Ethiopia D Equatorial Guinea Swaziland 5. 6. 7. G G G The Gambia IPPs G IPPs G Madagascar Mauritius T Rwanda South Africa T T Angola Senegal Sudan Cabo Verde Sierra Leone Cameroon D Tanzania Dn D Côte d’Ivoire Togo D 8. 9. 10. IPPs G IPPs G IPPs G T Ghana T Nigeria T T Uganda D D Kenya Zimbabwe D Dn D Zambia Source: Compiled by the authors, based on various primary and secondary source data. Note: Includes vertical integration or unbundling of generation (G), transmission (T), and distribution (D) and presence of IPPs. While there are 48 Sub-Saharan African countries, the Comoros, Lesotho, São Tomé and Príncipe, and the Seychelles are excluded from this figure. Thus the three island states are not included, along with Lesotho, where the national utility, Lesotho Electricity Company (LEC), has only T&D assets. A separate generation plant, the Muela Hydroelectric Station (72 MW), is owned and operated by the Lesotho Highlands Development Authority (owned by the government of Lesotho). These countries otherwise form part of the overall analysis. It should be noted that Kenya also has an unbundled transmission company, the Kenya Electricity Transmission Company Limited (KETRACO), which is responsible for new transmission assets. Furthermore, Uganda has one large, privatized distribution utility supplied from the transmission grid and some regional distribution companies not connected to the main transmission grid. Finally, some of the countries listed in model 1 can, in principle, allow private investments, but as of yet do not have IPPs. CAR = Central African Republic; Congo = Republic of Congo; DRC = Democratic Republic of Congo; IPP = independent power project; MW = megawatt; T&D = transmission and distribution. The model that has emerged from these reform efforts is a hybrid market in which public and private investment coexist. The characteristics of such power markets need to be recognized explicitly, as they present an array of challenges. IPP investments have arisen in a variety of power market structures, indicating that no particular reform is the key. Nonetheless, unbundling, independent regu- lation, privatization, and competition are all significant where they improve overall sector governance, strengthen the enabling environment, and reduce the risk perceived by prospective investors. Key elements in supporting IPPs include planning the expansion of least-cost generation, streamlining procurement and contracting processes, and ensuring the financial health of off-taker utilities. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xxx Executive Summary An important lesson is provided by the second wave of power sector reforms that occurred in regions such as Latin America. Most Latin American countries had undergone a process of unbundling, privatization, and the establishment of wholesale spot markets. Even so, it became clear that long-term contracts with financially viable off-takers were critical to generate secure and reliable financial flows to pay for large investments. A second wave of reforms shifted emphasis to long-term generation and transmission expansion. Of particular importance were efforts to improve the technical and financial performance of electricity distribution. The Importance of Independent Regulation By definition, IPPs are investment transactions regulated by the underlying con- tracts. Regulations at the sector level, although they do not directly influence the details of these contracts, are important in defining the rules of the game and ultimately shaping the enabling environment for IPPs. The establishment of independent regulators has been the most widespread power sector reform element in Sub-Saharan Africa. As of 2014, more than half of all Sub-Saharan African countries had established such agencies, and the coun- tries with the most IPPs all have electricity regulators. The mere presence of such an agency, however, is not sufficient. The quality of regulation is critical. Transparent, fair, and accountable regulators that produce credible and predict- able regulatory decisions are necessary for creating the certainty around market access, tariffs, and revenues that encourages investment. Ideally, an independent regulator should enforce best practices in investment transactions and notably competitive procurement. In Sub-Saharan Africa, the presence of a regulator is not necessarily associated with more competitive pro- curement practices, and regulators have not always ensured that captive electric- ity consumers benefit from the pass-through of competitive generation prices. The independence of regulators may be compromised by overreaching and competing government agencies. In many countries, the independence and pro- fessional capacity of regulators need to be strengthened so that they can discour- age directly negotiated generation contracts and instead enforce the rules for the competitive procurement of IPPs. Generation Planning, Procurement, Contracting, and Financial Sustainability A range of generation planning arrangements is in place across the region. Although there is no optimal solution, some key lessons can be observed. If the planning function remains with the national utility, strong political leadership is crucial to ensure that the utility works to achieve national goals. Alternatively, the planning function may be transferred to an unbundled, independent trans- mission or system operator. If this transfer is to be successful, the planning function needs to be properly resourced. The majority of Sub-Saharan African ­ countries have an inadequate planning capacity and end up contracting out this function to consultants. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xxxi Electricity plans need to be translated into timely procurement and well- delineated investment opportunities for the private and public sectors. Unfortunately, few African countries have an explicit connection between plan- ning and procurement. More important, competitive bidding is not the norm. A disproportionate number of IPPs are developed based on unsolicited proposals and through direct negotiation. IPP contracts typically extend from 15 to 30 years. This is both a strength and a weakness. Predictable revenue streams allow equity risk capital to be rewarded, and sponsors can also service debt with long tenors. Conversely, in an environ- ment of power market reform, both parties can encounter problems with fixed long-term take-or-pay contracts if the various conditions under which the con- tracts are agreed upon change. Because of the complexities involved, governments and national utilities need to marshal specialized expertise on a par with that of the private sponsors to negotiate robust and competitive IPP contracts. Governments have to allocate clear contracting responsibility to either the national utility or a government agency. If the national utility is to be responsible, then it is also critical that a ring-fenced contracting function be established, separate from the utilities’ own generation or new build function. The best location may be an independent sys- tem operator that also takes responsibility for planning, which may then be integrated with the procurement function. In this case, the system operator assumes responsibility for both the system’s short-term balance and the long- term security of supply. At the crux of the investment conundrum is the financial viability of the off- taker. High transmission and distribution (T&D) losses, tariffs below cost recov- ery levels, and poor billing and collections severely affect the financial standing of utilities. Average distribution losses in Sub-Saharan Africa are high, and aver- age collection rates are not high enough. Combined, this inefficiency is equiva- lent to 50 percent of turnover on average. Governance reforms can critically improve the performance of state-owned utilities. Most utilities in Sub-Saharan Africa meet only about half of the criteria for good governance. Operational practices targeting technical and commercial efficiency can critically improve the financial standing of a utility in a short period of time. Because of concerns about the financial health of the off-taker, robust PPAs in a strong currency and bolstered by guarantees have become a requirement for new investors seeking to safeguard payment streams. A Framework for Understanding the Enabling Environment for IPPs The elements that contribute to sustainable IPP investments have been identi- fied (table ES.3). Host country governments have an immediate influence over some of the elements. These include policy, regulation, planning, and competi- tive procurement. Overall economic conditions and the legal framework are clearly relevant, as are policies that encourage private investment in general and in the power sector in particular. Stable macroeconomic policies, investment protection, respect for contracts, capital repatriation, tax incentives, and further Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xxxii Executive Summary Table ES.3  Factors Contributing to Successful Independent Power Project Investments, Sub-Saharan Africa Factor Details Country level Stable country context Stable macroeconomic policies Legal system allows contracts to be enforced, laws to be upheld, arbitration Good repayment record and investment-grade rating Previous experience with private investment Clear policy framework Framework enshrined in legislation Framework that clearly specifies market structure and roles and terms for private and public sector investments (generally for a single-buyer model, since wholesale competition is not yet seen in the African context) Reform-minded “champions” to lead and implement framework with a long-term view Transparent, consistent, and fair Transparent and predictable licensing and tariff framework regulation Cost-reflective tariffs Competitive procurement of new generation capacity required by regulator Coherent power sector planning Power planning roles and functions clarified and allocated Planning function skilled, resourced, and empowered Fair allocation of new build opportunities between utility and IPPs Built-in contingencies to avoid emergency power plants or blackouts Competitive bidding practices Planning linked to timely initiation of competitive tenders/auctions Competitive procurement process adequately resourced and fair and transparent Project level Favorable equity partners Local capital/partner contribution where possible Risk appetite for project Experience with developing country project risk Involvement of a DFI partner (and/or host country government) Reasonable, fair ROE Development-minded firms Favorable debt arrangements Competitive financing Local capital/markets that mitigate foreign exchange risk Risk premium demanded by financiers, or capped by off-taker, matches country/ project risk Some flexibility in terms and conditions (possible refinancing) Creditworthy off-taker Adequate managerial capacity Efficient operational practices Low technical losses Commercially sound metering, billing, and collections Sound customer service Secure and adequate revenue Robust PPA (stipulates capacity and payment as well as dispatch, fuel metering, stream interconnection, insurance, force majeure, transfer, termination, change-of-law provisions, refinancing arrangements, dispute resolution, and so on) Security arrangements where necessary (escrow accounts, letters of credit, standby debt facilities, hedging and other derivative instruments, committed public budget and/or taxes/levies, targeted subsidies and output-based aid, hard currency contracts, indexation in contracts) table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xxxiii Table ES.3  Factors Contributing to Successful Independent Power Project Investments, Sub-Saharan Africa (continued) Factor Details Credit enhancements and Sovereign guarantees other risk management and Political risk insurance (PRI) mitigation measures Partial risk guarantees (PRGs) International arbitration Positive technical performance Efficient technical performance high (including availability) Sponsors who anticipate potential conflicts (especially related to O&M and budgeting) and mitigate them Strategic management and Sponsors who work to create a good image in the country through political relationship building relationships, development funds, effective communications, and strategic management of their contracts, particularly in the face of exogenous shocks and other stresses Source: Adapted from Eberhard and Gratwick 2011. Note: DFI = development finance institution; IPP = independent power project; O&M = operations and maintenance; PPA = power purchase agreement; ROE = return on equity. IPP investment opportunities will attract more capital at lower cost. Transparent, consistent, and fair regulatory oversight, with a commitment to cost-reflective tariffs, provides more price and revenue certainty, boosting the creditworthi- ness of off-takers and thus requiring less risk mitigation. Power planning and timely initiation of competitive tenders or auctions for new capacity are also important. The balance of issues is within the project purview. At the project level, debt and equity finance has to be appropriately structured and serviced through rev- enue guaranteed in a robust PPA and backed with the required credit enhance- ment and security arrangements, including guarantees, insurance, and other risk mitigation instruments. Independent Power Projects: An Analysis of Types and Outcomes Many different forms of IPPs fall under the broad definition used in this study. They differ in their ownership and financing structures, in technology choices and risk profiles, in how they are procured and contracted, and in risk mitigation mechanisms. The analysis summarized here (as well as the main conclusions in chapter 5) is based primarily on case studies of five countries: Kenya, Nigeria, South Africa, Tanzania, and Uganda. Among the case study countries, South Africa has embarked on the most ambitious renewable energy IPP program, which will soon be followed by thermal IPPs. Nigeria is undergoing the most extensive power sector reforms on the continent. Although other countries may not be able to replicate the experiences of these two major economies, many lessons from them can be adapted and applied. Tanzania and Kenya provide a fascinating opportunity to contrast the experiences and outcomes of solicited versus unsolicited bids. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xxxiv Executive Summary Tanzania is also about to start more ambitious reforms and will expand its gas-to-power investments, while Kenya is encouraging a diversified set of ­ power investments, including in renewable energy. Uganda has overhauled its electricity supply industry and has numerous small IPPs and the largest hydro- power IPP in Sub-Saharan Africa. Ownership, Financing Structures, and Development Finance Institutions There has been a wide variety of African IPP sponsors and debt providers. State institutions have invested in some IPPs, but private sponsors are prominent, including private African partners, European entities such as Globeleq, Aldwych, and Wartsila, and numerous European bilateral DFIs. A smaller number of spon- sors are from North America, Asia, and the Middle East. A few multilateral agen- cies also hold some equity. In addition to equity investments, DFIs are prominent in the debt financing of IPPs. The African reality is one in which most IPPs carry substantial risks. Without DFI financing, key projects would not have reached financial close and commercial operation. DFIs have also reduced the chances of investments and contracts unraveling—in part because of rigorous due diligence practices, but also because of the pressure governments or multilateral institutions might bring to bear around honoring investment contracts. Risk Mitigation In addition to the customary risks, IPPs in the region are faced with risks that must be mitigated to make the investment viable. These are political risk—events resulting from adverse actions by the host government or from politically moti- vated violence; regulatory risk—any change in law or regulation that may have a negative impact on a project; and credit/payment risk—deficiencies in the credit quality and the payment capacity of the off-taker. Mitigating these and other risks is crucial to attracting private investment to the Sub-Saharan African power sector. Various measures are available, but each context poses different challenges and requires tailored solutions. In large projects in which the public sector plays a counterpart role, private investors routinely require international arbitration to resolve disputes. In particu- lar, clauses addressing instances of a “change in law” or in sector regulations are commonly embedded in PPAs. When considering an investment in a new coun- try, private sector investors often reach out to the DFI community to seek financ- ing and other types of support for IPPs. Where off-takers are not creditworthy or perceived as such, sovereign ­guarantees are the most common instrument to mitigate off-taker risks. In such cases, structural measures can also be designed to ring-fence revenues accruing to off-taker utilities and ensure that there is enough cash flow to honor payment obligations under the PPA. Another option to be considered is to transfer collec- tion for a set of large, profitable customers from the utility to an escrow account managed by the IPP. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xxxv Although host governments can provide sovereign guarantees or arrange other risk mitigation measures, their capability to deliver on IPP commitments may remain in doubt. In that case, further risk mitigation instruments that transfer risks to third parties are in order. The most commonly used instruments are mul- tilateral development bank guarantees, most often from the World Bank (but also more recently from the African Development Bank), and insurance products, in particular political risk insurance. World Bank guarantees are designed to provide credit enhancement and direct risk mitigation. They are flexible in nature and adaptable to the specific requirements of each project and to market circumstances. Project-based World Bank guarantees may be loan guarantees, which mitigate the risks faced by commercial lenders with respect to debt service payment defaults, or pay- ment guarantees, which mitigate the risks faced by private projects or foreign public entities with respect to payment default on government obligations not related to loans. Insurance products may be provided by multilateral and bilateral agencies, export credit agencies, or private insurers. Guarantees and insurance are comple- mentary products. Large and complex projects often involve both instruments. The Sub-Saharan African experience clearly points to the fact that risk mitiga- tion has been critical in attracting private investments to IPPs located in challeng- ing markets and in keeping projects intact. (A few notable examples are presented in this study.) Going forward, risk mitigation promises to remain critical in attracting private financing to projects. Nevertheless, as IPP markets mature in Sub-Saharan Africa, it is possible that the use of risk mitigation arrangements will diminish. It is important to note that in no projects have guarantees of any sort been invoked, including in those projects whose contracts ultimately unraveled. Technology Options: A Rise in Independent Power Projects Using Solar and Wind Energy The last decade has witnessed a revolution in renewable energy technologies such as wind and solar energy, especially in the past five years as costs have fallen and efficiencies improved. The same has generally not occurred in fuel-to-power plants. Accordingly, for IPPs in the Sub-Saharan Africa power sector, grid-­ connected renewable energy is gaining traction. The most dramatic example has been South Africa’s recent large Renewable Energy Independent Power Project Procurement Programme (REIPPPP). Grid- connected wind and solar renewable energy in South Africa is now among the cheapest in the world. Outside South Africa, the wind story has been centered around a few projects in Kenya, which are marginally more expensive than Kenya’s private geothermal capacity but beat any of the country’s existing ther- mal plants on price. Because both solar- and wind-based generation entail higher up-front costs and different risk profiles than those of traditional technologies, countries interested in renewables have experimented with methods to incentivize private investment. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xxxvi Executive Summary Until recently, the most widely adopted procurement strategy for attracting renewable energy IPPs involved feed-in tariffs (FiTs), which have primarily been promoted by European bilateral aid programs. FiTs are beginning to face criticism, however, because prices have not come down as fast as those associated with competitive tenders. In Africa, the experience with this instrument has been dis- appointing, and relatively few projects have materialized. However, two solar projects have been developed in Uganda under the global energy transfer feed-in tariff (GETFiT) program. This program was designed as a temporary facility to stimulate the small-scale renewable energy market, initially through a premium payment but also through firming up the contractual ­ framework, providing investors with confidence, and extending institutional assistance to the host government. By early 2015, GETFiT had confirmed support for 15 projects with a total of 128 MW capacity. Although the results ­ achieved to date in Uganda are less impressive than those in South Africa, these projects are still cheaper than the imported fuel-to-power alternative in Uganda. Competitive Bidding versus Direct Negotiation Excluding South Africa, direct negotiations outnumber competitive tenders across the Sub-Saharan Africa IPP pool and represent the majority of megawatts procured. Most often, direct negotiation originates in unsolicited proposals from interested investors. Historically, there has been no move toward or away from competitive tenders or directly negotiated projects; instead, there has been con- sistent engagement with both—again excluding South Africa. Every one of the five study countries procured its first IPP by direct negotia- tion. In Kenya, Nigeria, and Tanzania, serious power shortages motivated the first IPP procurements. At the time, these countries had negligible experience with competitive procurement, and there was a general perception that direct nego- tiation would allow a quick fix. Most of these projects did come online rapidly, but later problems could be ascribed to their fast-track nature. Subsequent private power projects in the five study countries have not fol- lowed a clear pattern. Both Kenya and Tanzania next used competitive procure- ment, as it was made a precondition for access to multilateral funding streams and guarantees. In these two countries, the initial negotiated IPPs were viewed as costly experiments. Meanwhile, Nigeria, South Africa, and Uganda continued to use direct negotiations to procure private power, despite the costs. Most recently, competitive tenders have finally emerged in South Africa and Uganda, and nego- tiated projects have returned in Kenya and Tanzania. Overall, the level of competition in Sub-Saharan Africa has been disappointing. Nonetheless, the results are improving. Competitive tenders are most likely to bring about their intended benefits where they attract an adequate number of investors. With the exception of South Africa, no IPP tender in Africa has attracted more than a small handful of bidders, but there has been an increase over time. Despite the relatively low number of bidders, the experience of the case study countries demonstrates that competitive procurement of IPPs provides clear price advantages. Some types of thermal generation are consistently less costly Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xxxvii when competitively bid, although procurement of other thermal types appears to be comparable using either method. Wind projects, especially recently in South Africa, clearly show the advantage of competitive tenders over direct negotiation. Competitively bid solar projects in South Africa and Uganda are also more com- petitive than directly negotiated similar projects in Nigeria and Rwanda. Despite the obvious benefits associated with competition, three arguments against competitive procurement are frequently made: (1) competitive tenders are more complex and expensive; (2) there is insufficient private investment interest to justify competitive tenders; and (3) the first developer or sponsor who con- ceives the project may be unwilling to compete via a tender because of proprietary data, technology, or the initial investment. These arguments are used mainly by private developers, but the first and second have also been used by public stake- holders to justify using direct negotiation rather than competitive bidding. In reality, the record shows that while direct negotiations may appear to be simpler and cheaper at the outset, in practice they are often lengthy, and govern- ments may be ill equipped to assess the value of unsolicited offers. Also, it is possible to run competitive bids efficiently and in short time frames. Although it is true that many tenders have attracted only a couple of bids, the solution is not direct negotiations—a public tender process opens any bid up to more scru- tiny. A project can be made more attractive to investors by bundling it with other ­ projects. Finally, several technical strategies are available to deal with investors who are reluctant to lose up-front capital or proprietary information via a competitive bid. Competitive tenders are therefore preferable and countries should strive to use them. This does not mean that countries should never be involved in direct negotiations with unsolicited offers. In some instances, there could be few other options. Also, unsolicited proposals may lead to good deals, as long as countries are able to fully assess the value of the project, direct negotiations are run trans- parently, and countries have an adequate transaction capacity to negotiate rea- sonable PPAs. Transparency is even more important in the case of direct negotiations, as a means of minimizing the risk of controversy or corruption. Also, having in place a sound generation expansion plan is critical for assessing whether the project is the best option in terms of cost and technology choice. Therefore, countries need to invest in planning capacity, obtain transaction advisory support, and strive for transparency in their procurement practices. Conclusions Independent power projects make a significant contribution to meeting Africa’s power needs. There is no doubt that IPPs are worth the effort. But it is not only the quantum of private investment in IPPs that is relevant; equally important are investment outcomes and, especially, the price and reliability of the elec- tricity produced. The challenge ahead is for African countries to create the conditions to attract more and better IPPs and thus help overcome the conti- nent’s power deficit. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xxxviii Executive Summary Competition still poses a conundrum in Africa, which is why this study pays particular attention to unpacking the trade-offs attached to competitive procure- ment. When procured competitively, IPPs have generally delivered power at lower costs than directly negotiated projects, and their contracts have held up better. Despite this, unsolicited and directly negotiated deals have been the norm across Sub-Saharan Africa, accounting for over 70 percent of all IPP megawatts procured. After 20 years of reform efforts in Africa, nowhere on the continent is full wholesale or retail competition to be found in power sectors. Countries that have attracted the most finance have a wide range of sector policies, structures, and regulatory arrangements. In 13 such destinations for IPP investments, vertically integrated, state-owned utilities predominate. The presence of a regulator is also not definitive in attracting investment. Although the countries with the most IPPs all have formally independent regulators, some countries with regulatory agencies do not have any IPPs. There seems to be no clear relation among reforms, degree of competition, and the success of countries to attract IPPs. Thus it is reasonable to ask what are the merits of competition in this context, and what are the key reform ele- ments that can help African countries most advantageously attract IPPs? Responses to these questions may be condensed into five main conclusions: • Systematic and dynamic power sector planning is crucial to identifying the generation projects that best meet a country’s power needs and define the potential space for IPPs. Sound planning means that countries are able to project future electricity demand correctly, decide on best supply (or demand ­ management) options, and anticipate how long it would take to procure, finance, and build the required generation capacity. Planning tools must be updated regularly and new building opportunities allocated based on clear criteria. Finally, there must be an explicit link between planning and the timely initiation of the generation procurement process. • Competitive procurement of IPPs helps ensure that projects are implemented transparently and at the lowest cost. Two decades of experience in power pro- curement in Sub-Saharan Africa have amply demonstrated that a lack of com- petition in procuring new generation capacity has extensive drawbacks, ranging from immediate effects on project outcomes (higher prices, unraveling con- tracts, and so on) to more general effects on the overall governance of the electricity sector and its investment climate. IPP investment in Africa will rely on long-term contracts with off-takers where electricity demand is growing at medium or high rates. Where long-term contracts for new power are competi- tively bid rather than directly negotiated, there is a potential for reduced prices. Also, competitive procurement can stimulate the development of potentially bankable projects, especially renewable energy. African governments have not done enough to offer competitive tenders or auctions with clear ground rules; standardized, long-term contracts with IPPs; and reliable timelines. In the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xxxix absence of these, project developers and funders have offered unsolicited bids. Designing and running competitive tenders are not trivial tasks. But if a core government team is authorized to do the work and sufficient resources are allocated for this purpose, then experienced transaction advisers can be hired to help. And the benefits of lower prices invariably justify the initial cost of running these tenders. • Direct negotiations and unsolicited offers are not ruled out. Indeed, sometimes they are unavoidable, but governments that engage in unsolicited proposals or directly negotiated deals must develop the capacity to properly assess the cost- competitiveness of these projects and the technical and financial capabilities of the project developers—thereby negotiating cost-competitive contracts. In addition, unsolicited bids may be opened to more scrutiny by instituting a public tender. • The financial viability of utilities is a critical factor in attracting IPP invest- ments. IPP contracts should be undertaken with financially viable off-takers, whether they be utilities or large customers. Most IPPs are project-financed, and their bankability rests on secure revenue flows. Although credit enhance- ment and security measures can mitigate risk, a financially strong off-taker provides a sustainable basis for securing long-term contracts with IPPs. A sus- tained effort to better the performance of utilities must be at the center of countries’ reform agendas and also be consistently supported by development partners through financial and technical assistance. • Reforms, especially those improving the investment climate, remain impor- tant. Although IPP investment trends do not appear to be correlated with spe- cific power sector institutional arrangements, the importance of reforms geared toward promoting a sound investment climate should not be discounted. Unraveling potential conflicts of interest between incumbent state-owned generators and IPPs, through unbundling generation from transmission, is in principle positive for private investment, as is more transparent contracting among state generators, IPPs, and independent transmission companies and system operators. Having a regulator in place is especially important, but the mere existence of a regulatory agency is not enough. The quality of regulation capacity is nonnegotiable: the regulator must be independent and endowed with competent—and sufficient—human resources. In conclusion, investment in Africa’s power sector IPPs is growing, but not fast enough. The region does not have sufficient power. All sources of investment need to be encouraged. For IPPs to flourish, the countries of Sub-Saharan Africa need dynamic, least-cost planning, linked to the timely initiation of the competi- tive procurement of new generation capacity. This must be accompanied by building an effective regulatory capacity that encourages the distribution utilities that purchase power to improve their performance and prospects for financial Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xl Executive Summary sustainability—and to widen access to electricity. Such efforts promise to pro- mote economic and social development across the region. Five Case Studies 1. Kenya’s Electric Power Promise Kenya is among the countries in Sub-Saharan Africa with the most extensive experience in IPPs. Its first IPPs date back to 1996, and since then the country has closed 11 projects for a total of approximately 1,065 MW and $2.4 billion in investment. Although these numbers are small from a global standpoint, IPPs will soon represent more than one-third of Kenya’s total installed generation capacity. Despite this momentum, the actual process of procuring new power through IPPs has remained complex, and there are many opportunities for improvement. The present situation should be viewed in the context of Kenya’s reform efforts. Since the first reforms of the mid-1990s, there have been numerous changes in Kenya’s electric power sector. An independent regulator was created in 1997. The Kenya Power and Lighting Company (KPLC, known as Kenya Power), which had served as an integrated utility since 1954, was unbundled. The KPLC began to focus exclusively on the transmission and distribution of electric- ity, while the Kenya Electricity Generating Company (KenGen) took over all public power generation activities. A second reform wave starting in 2004 saw the establishment of the Geothermal Development Company (GDC) to under- take an assessment of Kenya’s geothermal resources, the creation of a new regula- tory body, the Energy Regulatory Commission (ERC), and partial privatization of KenGen. In 2008, Kenya’s “2030 Vision” set a new generation target of 23,000 MW by 2030, as well as other lofty goals. In 2013, an ambitious capacity expansion program was launched with the goal of bringing 5,000 MW online within 40 months. After spawning two large public projects that stalled, this program was scaled back. Meanwhile, the ERC affirmed that IPPs would be given an opportunity to compete alongside KenGen, and a competitive market is a stated legislative goal. However, even with 11 current IPPs in Kenya, KenGen and the KPLC remain the dominant players in the country’s power sector. There is no evidence that their roles in Kenya’s hybrid market structure will be scaled back. In recent projects, public and private procurements were said to be comple- mentary, not competitive. To mobilize adequate funding for capacity expansion, those projects thought likely to attract private sector funding were offered to IPPs, all via international competitive bidding. Procurement, with the KPLC at the helm, has widely been considered to be positive, specifically in running effec- tive competitive bids for thermal capacity. There was considerable competition for the three latest diesel generators, showing how much the sector has evolved since the late 1990s. Alongside this evolution, problems persist in planning and procurement. Unlike many countries in Sub-Saharan Africa, Kenya has reasonably good mecha- nisms for the often-neglected process of planning for least-cost generation and Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xli transmission capacity. Unfortunately, since 2010 demand estimates from the government have been unrealistically high. Linked to this, a number of genera- tion projects have been procured through direct negotiations and without a thorough technical and financial analysis to determine whether the proposed plants meet least-cost planning standards. Because of the variety of projects, Kenya offers an interesting opportunity to compare directly the performance of state-owned power plants with IPPs using similar technologies. Plant availability is arguably the best performance indicator. IPP diesel projects have outperformed their public sector equivalents. Although the data on plant availability demonstrate the technical superiority of IPPs, electricity price data favor KenGen. The comparison, however, is affected by differences in capital costs. The two KenGen diesel plants are more price competitive than most IPP diesel plants. However, one particular IPP diesel plant is the cheapest of all; it has a heat-recovery system, which improves efficiency, and it is located close to its fuel source. Among geothermal plants, most of the publicly owned KenGen plants are relatively more competitive. In summary, for two decades private and public power projects in Kenya have been developed in parallel. Private developers have been critical in mobilizing funding to meet the nation’s demand for electricity, and they have complemented publicly owned projects. Kenya’s power-planning pro- cess has been dynamic, and there has been a strong track record of interna- tional competitive bidding. However, more recently the planning process has not always been based on solid independent technical analysis. Overall, Kenya has demonstrated the clear advantages of competitive bidding for thermal plants, and also the cost advantages of renewable energy, particularly geothermal power. After two decades of experience, the key remains the careful implementation of IPPs, from planning to competitive procurement to effective contracting. 2. Independent Power Projects and Power Sector Reform in Nigeria Nigeria represents a fascinating case of accelerating investment in new power capacity in an electricity sector undergoing radical reform. Although Nigeria has the largest population and economy on the African continent, 46 percent of its citizens live below the poverty line and less than 50 percent have access to ­ electricity. The demand for electricity far outweighs available capacity, which is less than 5 GW for a population of about 170 million. Making matters worse, the actual generation output in Nigeria is far below installed capacity. Nigeria’s out- put rate per capita is among the lowest in the world, owing to poor operation and maintenance, aging generation and transmission infrastructure, fuel supply constraints, and vandalism. Nonetheless, since 2001 Nigeria has embarked on the most ambitious electricity sector reform effort of any country in Africa. As part of the reform process, Nigeria has unbundled the generation, transmission, and distribution subsectors; privatized power generation stations and distribution utilities; appointed a private management contractor to manage the transmission Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xlii Executive Summary company; and established a bulk trader. Other than South Africa, Nigeria also boasts the largest investment in IPPs in Sub-Saharan Africa. Several generations of IPP transactions correlate with distinct phases of the sector reform process. Today, however, a new power market is being established, and a fourth generation of classic, project-financed IPPs is emerging. IPP con- tracts have had to be designed and negotiated afresh in the new market conditions, and appropriate credit enhancement and security measures have had ­ to be put in place to mitigate payment and termination risks. The challenges and risks of reform in Nigeria have been formidable. Each step has prompted new issues that have required further interventions. Nigeria has not waited for all steps to be clearly defined and agreed upon before moving. Instead, the “Nigerian way” has been to catalyze strong momentum for reform that becomes difficult to reverse and that forces political decisions and interven- tions along the way. It is not clear whether the “Nigerian way” will sustain the reforms. Election-related pressure to reduce tariffs did not help, and financial sustainability has yet to be demonstrated. Nigeria has seen recent investments in power generation capacity. The largest source of new generation to date has been publicly funded projects that are being privatized, but historically there also have been significant investments in IPPs, and recently a large IPP investment closed. Indeed, excluding South Africa, Nigeria has more privately funded megawatts than any other country in Sub- Saharan Africa. Also noteworthy in Nigeria has been the entry of Asian power investors in the form of the Republic of Korea’s KEPCO (Korea Electric Power Corporation) and the Chinese engineering, procurement, and construction con- tractors. However, even these investments are not sufficient to meet Nigeria’s power needs. Interestingly, the first wave of IPP investments preceded power sector reforms. And the most recent IPP power purchase contracts were signed during a period of financial uncertainty. Incomplete reforms and financial shortfalls in the sector have thus not blocked IPP investments. However, not many countries would have been able to divert massive financial allocations (in Nigeria’s case, from oil revenues) to keeping electricity companies afloat. Without serious efforts to achieve financial sustainability in the industry, private investments will be at risk. Nigeria does not yet have a benchmark for international competitive bids versus directly negotiated projects. However, the government regulator has man- dated competitive tenders by a rule published in 2014. It is hoped that the con- tracting authority (the electricity bulk trader) will commence international competitive tenders in the near future. Nigeria also does not yet have any grid-connected renewable energy projects (other than hydropower), but some solar photovoltaic projects in the pipeline are being negotiated by the bulk trader. Preparatory work is being undertaken for competitive bids for renewable energy. In a few years’ time, it will be worthwhile to compare these price outcomes with those of directly negotiated projects. It is also hoped that capacity will be built for effective generation planning and that the system operator will issue regular demand and supply forecasts that will Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xliii trigger initiatives to procure new capacity. Regular and dynamic generation expansion plans—linked directly to competitive procurement and effective con- tracting—are needed. What are the lessons for other African countries? Clearly, the extensive power sector reforms in Nigeria have not been a panacea. Few other African countries have sought to completely unbundle and privatize their entire electricity sector, and not one has set up a wholesale electricity trader. Nonetheless, Nigeria has demonstrated that it is possible to attract IPPs in a challenging investment cli- mate. There, IPPs have been built more quickly than publicly funded projects, and data also show that the performances of IPPs have been superior to those of state-owned generation plants, although the more reliable gas supplies of IPPs probably contribute to the difference. The poor financial performance of Nigeria’s distribution companies and the insecurity of gas supplies have added risk to new IPP investments—risks that have had to be mitigated through extensive credit enhancement and security measures. Other African countries with risky investment climates can learn from what has been required in Nigeria, but it is hoped that the extent and cost of these risk mitigation instruments will fall over time as the financial sustain- ability of the sector improves. And herein is a key lesson: ultimately, IPP invest- ments rely on secure revenue flows from customers and distribution companies. There is no way to avoid the fundamental challenge of improving the technical and commercial performance of electricity distribution utilities. Indeed, the future success of Nigeria’s power sector reforms and investment program depends on it. 3. Investment in Power Generation in South Africa South Africa is a latecomer to introducing private investment and IPPs into its electricity sector. Two areas have been the focus of reform efforts in South Africa’s power sector over the last two decades: (1) restructuring the fragmented electricity distribution industry, and (2) unbundling the national electricity util- ity, Eskom, to facilitate private investments in electricity generation. However, on neither front has there been much progress. And yet, although past attempts to introduce IPPs were halfhearted and unsuccessful, today this situation has changed dramatically in the area of renewables. Most notably, South Africa now occupies a central position in the global debate on which are the most effective policy instruments to accelerate and sustain private investments in renewable energy. The government’s current pro- gram, REIPPPP, has successfully channeled substantial private sector expertise and investments into grid-connected renewable energy at competitive prices. To date, 92 projects have been awarded to the private sector, and the first projects are already online. Private sector investments of more than $19 billion have been committed for projects that total 6,327 MW of renewable energy. Over only four years, 2011–15, the prices of renewable energy dropped during four bidding phases, with average solar photovoltaic tariffs decreasing by 71 percent and wind dropping by 48 percent. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xliv Executive Summary Until recently, South Africa was Africa’s largest economy. Its electricity gen- eration amounts to more than half of the installed capacity in all of Sub-Saharan Africa. South Africa’s electricity supply industry is dominated by its state-owned and vertically integrated utility, Eskom. With a capacity of approximately 42 GW, Eskom generates approximately 96 percent of the country’s electricity. Eskom also owns and controls the high-voltage national transmission grid and supplies approximately half of the electricity generated directly to customers. The other half is distributed through 179 municipalities. South Africa has a well-defined, rigid electricity planning and procurement system. Until 2006, Eskom assumed sole responsibility for electricity planning and procuring new generation capacity. Legislation changed this situation, how- ever, giving responsibility to the minister of energy to produce regular Integrated Resource Plans that guide electricity generation investments. In practice, Eskom’s staff continues to produce the Integrated Resource Plans, but they do so now under the guidance and approval of the energy ministry. Initially, Eskom was charged with procuring IPPs, but, facing an obvious conflict of interest with its own generation ambitions, it failed to contract adequate amounts of privately produced power. The ministry began assuming responsibility for IPPs, but it realized early on that it did not have the capacity to run large, sophis- ticated power procurement programs (PPPs). It therefore welcomed the assistance of experienced PPP advisers in the National Treasury and, along with an army of local and international transaction advisers, designed and ran what is now widely recognized and applauded as a world-class, albeit ad hoc, procurement group. South Africa’s experience suggests several key lessons for successful renewable energy programs in other emerging markets. For example, it is evident that pri- vate sponsors and financiers are more than willing to invest in renewable energy if the procurement process is well designed and transparent, transactions have reasonable levels of profitability, and key risks are mitigated by the government. Renewable energy costs are falling, and technologies such as wind turbine elec- tric generation are becoming competitive with fossil fuel generation. Furthermore, renewable energy procurement programs have the potential to leverage local social and economic development. The REIPPPP also highlights the need for effective program champions with the credibility to convincingly interact with senior government officials, effectively explain the program to stakeholders, and communicate and negotiate with the private sector. Other interesting lessons from South Africa are related to public versus pri- vate projects. In the case of renewable energy, competitive tenders and private sector developers produced better price outcomes and shorter construction times than the national utility, which had had no prior experience with renew- able energy. South Africa’s experience also demonstrates that much greater competition is possible among renewable energy providers—93 bids were received in the third round—than thermal power plants. The smaller project sizes, diversified and distributed renewable energy resources, and a highly com- petitive international market of project developers, equipment suppliers, and finance sources facilitate competition. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xlv Furthermore, South Africa’s experience highlights that significant investments in new electricity generation capacity are possible in a power sector that has undergone only limited reforms. Although an independent regulator has been established and IPPs are permitted, the vertically integrated and state-owned Eskom has retained a dominant market position. However, the current power crisis in South Africa suggests that further reform is required. Unbundling gen- eration and leaving Eskom with system and market operation, transmission, and perhaps also distribution could focus scarce management skills, improve efficien- cies, and create a level playing field between public and private investments in generation. Planning, procurement, and contracting functions could be embed- ded in a ­nonconflicted Eskom. These are the key concerns in any sector reform restructuring. Ultimately, successful power sector reforms are not about own- or ­ ership or wholesale or retail competition as much as they are about the effective- ness of planning, procuring, and contracting new investments. 4. Power Generation Results Now, Tanzania! Tanzania has a vast array of conventional and renewable energy resources, includ- ing recently discovered significant offshore gas reserves. And yet the country struggles to generate sufficient power to fuel growth and development. It has only 1,583 MW in installed generation, and imported fuel is a critical piece of its electric power generation. Network failures undermine what little power is produced. As a result, approximately 46 percent of the nation’s total power ­ ­ consumption is from off-grid self-generation. The government’s current plan to address these problems has set admirable and ambitious goals of achieving 10,000 MW of generation capacity by 2025, doubling access rates, increasing efficiency, boosting transparency and financial integrity, and privatizing generation and distribution assets. But viewed in light of the recent past, it is uncertain whether the government has the requisite capacity to deliver on these objectives. It has repeatedly committed to reforms, but has been slow to implement them and has wavered in its commitment to integrate private power sustainably and systematically. Notwithstanding ambitious reforms envisioned for the electricity sector, its present structure con- ­ tinues to be characterized by the prominence of nontransparent deals and by a poor-performing, vertically integrated, state-owned utility, the Tanzania Electric Supply Company (TANESCO, whose attempts to contract IPPs are sporadic and not always successful). Several specific projects illustrate Tanzania’s difficulties. The potential of recently discovered gas reserves to change the landscape of Tanzania’s electric power production has not yet been fulfilled. The absence of relevant planning and timely implementation (including the development of pipeline and gas pro- cessing infrastructure) along with a weak investment climate have prevented Tanzania from exploiting its gas potential. Delays in expanding the gas supply have already resulted in costly contingency plans such as emergency power proj- ects (EPPs), which in turn have bankrupted TANESCO. These EPPs, along with one ill-fated thermal IPP, Independent Power Tanzania Ltd. (IPTL), account for Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xlvi Executive Summary an inordinate portion of costs relative to actual production, due in large part to imported fuel charges. The lessons from Tanzania’s experience with IPTL, detailed in this study, could not be more explicit. When power is not planned, procured, and con- tracted transparently and consistently, the implications are potentially grave, far- reaching, and ongoing. Rather than being considered a planning and procurement mishap, however, IPTL is often used to emphasize the drawbacks of private sec- tor participation. Meanwhile, Songas, a more successful Tanzanian IPP, has not been widely recognized as an example of how competitive procurement and private sector involvement can work together to harness more power. Instead, Songas has been charged with having advanced private interests at the expense of the state, including obtaining key assets such as pipeline infrastructure that are in the strategic interests of the country. The wind story in Tanzania provides evidence that the lessons of the IPTL debacle have not been internalized by key stakeholders. Various factions still compete within state agencies, based on vested interests, and transparency remains compromised, despite efforts to empower the national regulator. The issues at stake go beyond the question of private versus public sector involvement, however. The lack of competitive procurement and transparent contracting has resulted in costly deals and disputed contracts, with large drains on time and resources lost. The national regulator has been given the mandate to reject unsolicited proposals that are not within the Power Sector Master Plan and are not financially viable. However, negotiated deals persist, and noncompetitive procurement remains the preferred method at the governing level. Incoherent planning and interagency disagreements have compounded the problem and impeded the timely procurement of ­ generation. As a result, the country has been forced to depend on EPPs and expensive oil-fired generation over the last several years. It is hoped that a secure gas supply will be established, putting an end to Tanzania’s costly dependence on imported fuel. Private power has, largely through Songas, helped benchmark the state-owned utility, raised the bar, and provided critical new generation. Other projects, such as IPTL and the EPPs, have proven to be costly experiments, primarily because of planning and pro- curement failures. Tanzania deserves a new decade of private and public project successes. 5. Power Generation Developments in Uganda Uganda occupies a unique space in the history of power sector reform and investment in Africa. It was the first country to unbundle generation, transmis- sion, and distribution into separate utilities and to offer separate, private conces- sions for power generation and distribution. Critics said that Uganda’s power system was too small to reap the possible benefits that might flow from competi- tion in generation and more focused management of transmission and distribu- tion. The years that immediately followed the reforms seemed to bear out the critics’ views: the private distribution operator struggled to reduce losses, and Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Executive Summary xlvii there were delays in investments in large new hydropower capacity, resulting in costly dependence on short-term thermal power. Despite ongoing challenges, Uganda’s power sector reforms are now bearing fruit. The performance of the distribution utility has improved. Losses are down, and collections, investment, and connections are up, although access rates remain low. After a torturous start, Uganda concluded the largest private hydro- power investment in Africa built by an IPP, Bujagali. Simultaneously, it has attracted a raft of smaller IPP investments, including innovative competitive bids for small hydropower, biomass, and solar projects solicited under the GETFiT program. After South Africa, Uganda has the largest number of IPPs in Sub- Saharan Africa and the only other competitively bid, grid-connected solar pho- tovoltaic program. Uganda’s experience in IPP development is among the most interesting in Africa. By 2012, it had implemented 11 IPP projects across a diverse set of gen- eration technologies and project capacities. Between 2015 and 2018 it is expected that up to 20 small-scale (1–20 MW) projects will be added to this portfolio through the government’s cooperation with the German Development Bank on the GETFiT Uganda program. And with an estimated total investment volume of $860 million and a capacity of 250 MW, Bujagali ranks among the largest privately financed hydroelectric power projects in Sub-Saharan Africa. Alongside these IPP successes, Uganda has now embarked on two large Chinese-funded hydropower projects. While locally IPPs are seen to be poten- tially expensive, complex, and time-consuming, investors rank Uganda as one of the top destinations for private sector investment in renewable energy technologies. In general, it can be said that the Ugandan government has been successful in achieving its development goals for the power generation sector. With close to 1,000 MW under implementation or in later feasibility stages, the capacity under development has multiplied within a short time frame of three years. Uganda has also managed to develop a mix of public projects financed by Chinese sources and privately financed small-scale IPP projects—a mix that is unique in Sub- Saharan Africa. Large hydropower projects accounted for 74 percent of Uganda’s power capacity in 2013, followed by thermal plants (12 percent). Bagasse and small hydropower projects supplied roughly equal shares of the remainder. Electricity production in 2013 was split more or less evenly between IPPs (1.492 GWh) and public projects (1.291 GWh), with a small share of thermal capacity, currently operated as emergency or standby capacity. IPP production increased dramatically with the commissioning of the Bujagali hydropower plant in 2012, which reduced the need for emergency power generation. The Ugandan government intends to follow a two-pronged policy for pro- curing generation capacity in the years to come. For large-scale projects, inter- national competitive bidding seems to have been abandoned in favor of direct awards to international—effectively Chinese—contractors. At the small to medium end of the scale, targeted policies aim to further encourage foreign investment in IPP projects involving all types of generation. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 xlviii Executive Summary References Eberhard, A., and K. Gratwick. 2011. “IPPs in Sub-Saharan Africa: Determinants of Success.” Energy Policy 39: 5541–49. Eberhard, A., O. Rosnes, M. Shkaratan, and H. Vennemo. 2011. Africa’s Power Infrastructure: Investment, Integration, Efficiency. Washington, DC: World Bank. U.S. EIA (U.S. Energy Information Administration). 2014. “International Energy Statistics.” http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid=2&aid=12. Accessed January 2014–August 2015. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Abbreviations ADFD Abu Dhabi Fund for Development AFD Agence Française de Développement AfDB African Development Bank AFESD Arab Fund for Economic and Social Development AFUDC allowance for funds used during construction AFUR African Forum for Utility Regulators AGFA Associated Gas Framework Agreement AGIP Azienda Generale Italiana Petroli AICD Africa Infrastructure Country Diagnostic AIIF African Infrastructure Investment Fund ANEEL Brazilian Electricity Regulatory Agency ATI African Trade Insurance Agency BADEA Arab Bank for Economic Development in Africa BNDES Brazilian Development Bank BNEF Bloomberg New Energy Finance BOAD West African Development Bank BOO build-own-operate BOOT build-own-operate-transfer BOT build-operate-transfer BPE Bureau of Public Enterprises BRICS Brazil, Russian Federation, India, China, and South Africa BRN Big Results Now BWSC Danish engineering company (owned by Mitsui) CAPEX capital expenditure CAR Central African Republic CBAO Banking Company of West Africa CBN Central Bank of Nigeria CCGT combined-cycle gas turbine CDC Commonwealth Development Corporation Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   xlix   l Abbreviations CEC Copperbelt Energy Corporation CEO chief executive officer CGC China Geo-Engineering Corporation CGGC China Gezhouba Group Company CIDA Canadian International Development Agency CIPREL Compagnie Ivoirienne de Production d’Électricité CMEC China Machinery Engineering Corporation COD commercial operation date CPI consumer price index CSP concentrated solar power CTL Centrale Thermique de Lomé DA direct agreement DAC Development Assistance Committee (of the OECD) DARESCO Dar es Salaam and District Electric Supply Company DBSA Development Bank of Southern Africa DEG German Investment and Development Corporation DFI development finance institution DfID U.K. Department for International Development DisCo distribution company DN direct negotiation DoE Department of Energy DPC dynamic production cost DPE Department of Public Enterprises DPO I-II Development Policy Operation Credits I and II DSCR debt service coverage ratio EADB East African Development Bank EAIF Emerging Africa Infrastructure Fund EAPP Eastern Africa Power Pool ECA Excess Crude Account ECG Electricity Company of Ghana EDI Electricity Distribution Industry EIA/U.S. EIA U.S. Energy Information Administration EIB European Investment Bank EKF Eksport Kredit Fonden (Danish export credit agency) EoI expression of interest EPC engineering, procurement, and construction EPE Brazilian Energy Research Agency EPP emergency power plant EPSRA Electric Power Sector Reform Act Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Abbreviations li ERA Ugandan Electricity Regulatory Authority ERB Electricity Regulatory Board ERC Energy Regulatory Commission ERR economic rate of return ESAP environmental and social action plan ESIA environmental and social impact assessment ETG Export Trading Group EWURA Tanzanian Energy and Water Utilities Regulatory Authority FDI foreign direct investment FEC Firm Energy Certificate FIRR financial internal rate of return FiT feed-in tariff FMO Netherlands Development Finance Company FY fiscal year GDC Geothermal Development Company GDP gross domestic product GenCo generation company GETFiT global energy transfer feed-in tariff GIIP gas initially in place GoT Government of Tanzania GoU Government of Uganda GSA government support agreement GW gigawatt GWh gigawatt-hour HFO heavy fuel oil HPP hydropower plant IA implementation agreement IBRD International Bank for Reconstruction and Development (of the World Bank Group) ICB international competitive bid ICBC Industrial and Commercial Bank of China ICSID International Centre for Settlement of Investment Disputes IDA International Development Association (of the World Bank Group) IDC Industrial Development Corporation IEA International Energy Agency IFC International Finance Corporation (of the World Bank Group) IFU Danish Investment Fund for Developing Countries IGG Inspectorate General of Government Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 lii Abbreviations IMF International Monetary Fund IOC international oil company IPP independent power project IPS Industrial Promotion Services Industrial Promotion Services-Aga Khan Fund for Economic IPS-AKFED Development IPTL Independent Power Tanzania Ltd. IRENA International Renewable Energy Agency IRP Integrated Resource Plan IsDB Islamic Development Bank ISMO independent system and market operator ISO independent system operator JIBAR Johannesburg Interbank Agreed Rate JICA Japan International Cooperation Agency KenGen Kenya Electricity Generating Company KEPCO Korea Electric Power Corporation KETRACO Kenya Electricity Transmission Company KfW Kreditanstalt für Wiederaufbau (German development bank) KILAMCO Kilwa Ammonia and Urea Company km kilometer km2 square kilometer KNEB Kenya Nuclear Electricity Board KPDC Kribi Power Development Company KPLC Kenya Power and Lighting Company K Sh Kenya shilling kV kilovolt kW kilowatt kWh kilowatt-hour LC letter of credit LCOE levelized cost of energy LCPDP Least Cost Power Development Plan LEC Lesotho Electricity Company LNG liquefied natural gas LRF livelihood restoration framework LRMC long-run marginal cost LTWP Lake Turkana Wind Project m3/s cubic meters per second MBLIPP Multisite Baseload Independent Power Project Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Abbreviations liii MDB multilateral development bank MEGS Mediterranean Electric Generating Services MEM Ministry of Energy and Minerals MEMD Ministry of Energy and Mineral Development MEP Mtwara Energy Project MFI multilateral finance institution MHI Manitoba Hydro International MIGA Multilateral Investment Guarantee Agency (of the World Bank Group) MMBtu million British thermal units MME Minister of Mines and Energy mmscf million standard cubic feet mmscfd million standard cubic feet per day MoE Ministry of Energy MoEP Ministry of Energy and Petroleum MoU memorandum of understanding MSD medium-speed diesel MTPPP Medium-Term Power Purchase Programme MW megawatt MWh megawatt-hour MYTO Multi-Year Tariff Order NBET Nigerian Bulk Electricity Trading NCP National Council on Privatisation NDC National Development Corporation NELMCO Nigeria Electricity Liability Management Company NEMS Nigerian Electricity Market Stabilization NEPA National Electric Power Authority NERC Nigerian Electricity Regulatory Commission NERSA National Energy Regulator of South Africa NIPP national integrated power project NNGIP National Natural Gas Infrastructure Project NNPC Nigerian National Petroleum Corporation NORAD Norwegian Agency for Development Cooperation Norfund Norwegian Investment Fund for Developing Countries NPV net present value O&M operations and maintenance OCGT open-cycle gas turbine ODA official development assistance Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 liv Abbreviations OECD Organisation for Economic Co-operation and Development OFID OPEC Fund for International Development OPEC Organization of the Petroleum Exporting Countries OPIC Overseas Private Investment Corporation PACP Presidential Action Committee on Power PAP Pan Africa Power Tanzania Ltd. PAT PanAfrican Energy Tanzania Ltd. PCG partial credit guarantee PHCN Power Holding Company of Nigeria PLF plant load factor PNCP Pilot National Cogeneration Programme PPA power purchase agreement PPDA Public Procurement and Disposal of Public Assets Act PPI Private Participation in Infrastructure PPP power procurement program; public-private partnership; ­ purchasing power parity PRG partial risk guarantee PRI political risk insurance PSA production-sharing agreement PSIP Power Sector Investment Plan PTA Preferential Trade Area Bank PTFP Presidential Task Force on Power PURA Petroleum Upstream Regulatory Authority PV photovoltaic QPEA Quantum Power East Africa R South African rand RAP Resettlement Action Plan Rc rand cent REA Kenya Rural Electrification Authority; Tanzania Rural Energy Agency; Uganda Rural Electrification Agency RED regional electricity distribution company REEEP Renewable Energy and Energy Efficiency Partnership REFiT renewable energy feed-in tariff REIPPPP Renewable Energy Independent Power Project Procurement Programme REP Rural Electrification Programme RET renewable energy technology RfP request for proposals RfQ request for qualification Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Abbreviations lv RMB Rand Merchant Bank ROE return on equity S&P Standard & Poor’s SAEMS South Asia Energy Management Systems SBLC standby letter of credit SCB-HK Standard Chartered Bank, Hong Kong SENELEC Société Nationale d’Électricité du Sénégal SHP small hydropower plant Sida Swedish International Development Cooperation Agency SOE state-owned enterprise SPE Society of Petroleum Engineers SPP small power project SPV special-purpose vehicle SSA Sub-Saharan Africa STPPP Short-Term Power Purchase Programme T&D transmission and distribution TANESCO Tanzania Electric Supply Company Tcf trillion cubic feet TCN Transmission Company of Nigeria TDFL Tanzania Development Finance Company Limited TDV Tanzania’s Development Vision TEM Transitional Electricity Market TPC Tanganyika Planting Company TPDC Tanzania Petroleum Development Corporation UAE United Arab Emirates UEB Uganda Electricity Board UEDCL Uganda Electricity Distribution Company Ltd. UEGCL Uganda Electricity Generation Company Ltd. UETCL Uganda Electricity Transmission Company Ltd. USc U.S. cent VAT value added tax VRA Volta River Authority WB World Bank WBG World Bank Group WEPS Wholesale Electricity Pricing System YFP Yinka Folawiyo Power All dollar amounts are U.S. dollars unless otherwise indicated. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 PA R T 1 Power Generation in Sub-Saharan Africa Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   1   C h apter 1 Introduction The Challenges Faced by Sub-Saharan Africa’s Power Sector All too often the dismal statistics and track record of Sub-Saharan Africa’s power sector are cited. Two out of three households in Sub-Saharan Africa, close to 600 million people, have no electricity connection at all. Electrification rates are high- est in South Africa (around 88 percent), followed by Nigeria, Côte d’Ivoire, Senegal, Cameroon, Gabon, Ghana, and Botswana (all above 50 percent). But most Sub-Saharan African countries have pitifully low access rates. Rural areas remain the most underserved in the world: in some countries, less than 5 percent of the rural population has access to electricity. Although electricity consumption levels in Sub-Saharan Africa have accelerated over the past decade, they are, on average (and excluding South Africa), less than 2 percent of the average level seen in the Organisation for Economic Co-operation and Development (OECD) countries (U.S. EIA 2014; IEA 2014b). Chronic power shortages combined with inadequate transmission and distri- bution networks are primary causes of low electricity access and consumption. Many countries simply do not have enough electricity to distribute to potential consumers. The region’s entire installed capacity, at a little over 80 gigawatts (GW), is equivalent to that of the Republic of Korea; excluding South Africa, this total is less than 40 GW. Nigeria, with more than three times South Africa’s population, has only 15 percent of its installed generation capacity. Meanwhile, across Sub-Saharan Africa, per capita installed generation capacity is barely one- tenth that of Latin America. The World Bank’s Africa Infrastructure Country Diagnostic (AICD) quanti- fied the extent to which existing power systems are unable to adequately meet suppressed demand, generate sufficient electricity for economic growth, and increase new connections to boost access to electricity (Eberhard and others 2011). Using 2005 as a baseline, the Bank estimated that Sub-Saharan Africa needed to add approximately 8 GW of new generation capacity each year through to 2015 to meet suppressed demand, keep pace with projected eco- nomic growth, and support the rollout of further electrification in line with Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   3   4 Introduction poverty reduction targets, compared with the 1–2 GW added on average annually in the past decade (Eberhard and others 2011: 58). ­ The majority of countries in Sub-Saharan Africa have experienced power shortages over the past few years, resulting in load shedding and frequent inter- ruptions to service. The economic costs of power outages, including the costs of running backup generators and of forgone production, typically range between 1 and 4 percent of gross domestic product (GDP) (Foster and Briceño-Garmendia 2010). It is estimated that infrastructure problems and, notably, deficient power generation and transmission infrastructure account for 30–60 percent of overall drains on firm productivity—well ahead of red tape, corruption, and other factors (Escribano, Guasch, and Pena 2008). The region’s high reliance on backup gen- erators, shown in figure 1.1, is an indication of the inadequacy and unreliability of grid-supplied power. Poor electricity supply is generally the result of inadequate investment in new power generation capacity; the deteriorating performance of existing power plants may also play a part. South Africa’s recent power outages, for example, have been exacerbated by plant breakdowns at its national utility, Eskom, and a resulting decline in available power (figure 1.2). In the case of state-owned utilities, maintenance and operations have often been poor, and tariffs and collections have been insufficient to support the refur- bishment of equipment or new investments. Even though many countries permit private sector participation in generation, shortcomings in planning and procure- ment have been common, and international competitive tenders for new capac- ity have been few and far between. Figure 1.1  Percentage of Firms Relying on Generators: Selected Countries in Sub-Saharan Africa, Various Years 90 80 70 60 Percent 50 40 30 20 10 0 ) ) 3) 3) ) 4) ) 9) 3) ) 9) ) 1) 9) ny 13) ) 3) 10 09 09 14 10 11 14 01 01 01 nz (200 01 00 01 00 01 20 20 20 20 20 20 0 20 (2 (2 (2 (2 (2 (2 (2 2 (2 ( De ad ( s( l( a( ( a( ( la . a ria e da on ic ia n ia ia ep ga iu on an an bo bl go op ib an ge Ch an o rit .R ne Ke pu w Gh m Le er Ga An hi au Ug Ni m ts Se Na m Re Et Ta ra Bo M Ca er n Si ca o, ng fri lA Co ra nt Ce % firms with generators % electricity from backup generators Source: World Bank 2014. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Introduction 5 Figure 1.2  Average Availability of Generation Plants Run by Eskom: South Africa, 2000–15 100 95 90 85 Percent 80 75 70 65 60 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 Source: Eskom annual reports. Note: Unit capacity factor is defined as the amount of electricity generated by a power unit or power station throughout a specified time period, divided by the maximum amount of electricity that the plant could have generated during that period—that is, the installed capacity multiplied by the number of hours in that period, expressed as a percentage. Figure 1.3  Projected Electricity Demand: Sub-Saharan Africa, 2015–40 1,500 Terawatt-hours 1,000 500 0 2015 2020 2025 2030 2035 2040 Source: IEA 2014a. Looking ahead, Africa will need to ramp up its power generation capacity. Expanding electricity supply is even more important in the face of economic growth on the continent, which has been the key driver of electricity demand in the past decade. The International Energy Agency (IEA 2014a) predicts that electricity demand in Sub-Saharan Africa will increase at a compound average annual growth rate of 4.6 percent, and by 2030 will be more than double its current electricity production (figure 1.3). The need for large investments in expanding power generation capacity is self-evident. The cost of addressing Sub-Saharan Africa’s power sector needs has been estimated at $40.8 billion a year, equivalent to 6.35 percent of Africa’s GDP. Approximately two-thirds of this is needed for capital investment ($27.9 billion a year); the remainder is for operations and maintenance (O&M). Of capital Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 6 Introduction expenditure, about $14.4 billion is required for new power generation each year, and the remainder for refurbishments and networks (Eberhard and others 2011: 60). Existing investment is far below what is needed. Importance of Private Sector Participation and the Role of Independent Power Projects The large funding gap that holds back investments in new power projects in Africa cannot be bridged by the public sector alone. Private participation is ­ critical. Historically, most of such private sector financing has been channeled through independent power projects (IPPs), intended as nonutility generators that sell power to public utilities, end consumers, or wholesale power traders. Box 1.1 presents the definition of IPPs used in this study and their various types. IPPs are not uniform. Although the typical IPP structure is understood as a privately sponsored project with nonrecourse or limited recourse project ­ financing, some IPPs in Sub-Saharan Africa do not follow this exact model. Instead, the government may hold some portion of equity and/or debt, bringing IPPs closer to a model of a public-private partnership (PPP) than that of a tradi- tionally conceived IPP. Examples of even more pronounced departures from what might be expected include the Itezhi-Tezhi hydropower plant (HPP) in Box 1.1  Definition of Independent Power Projects In this book the definition of independent power projects (IPPs) is slightly broader than that of traditional private power projects that rely on nonrecourse or limited recourse project finance. Some of the projects categorized as IPPs in this study are financed by corporations; others are supported in part by public funding. For the purposes of this study, IPPs are defined as power projects that are, in the main, pri- vately developed, constructed, operated, and owned; have a significant proportion of private finance; and have long-term power purchase agreements with a utility or another off-taker. Within this overall definition, various IPP typologies may be identified, based on: • Ownership and financing structures. Private or corporate-financed projects, or joint venture companies with minority public funding, and different debt/equity ratios. • Technology. Thermal or renewable energy projects, using different technologies and sources, including diesel, heavy fuel oil, geothermal, hydropower, solar, wind, and biomass. • Procurement modalities. Projects that have been competitively procured or are unsolicited or directly negotiated. • Financial and risk mitigation structures. Projects that benefit from different risk mitigation, credit enhancement, and security arrangements. Emergency power, in the form of temporary lease agreements, is excluded from these categories. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Introduction 7 Zambia, 50 percent of which is owned by the state-run utility, ZESCO; and the second wave of IPPs in Nigeria (that is, IPPs that were developed on the balance sheet of their sponsors), in which the Nigerian National Petroleum Corporation has a 60 percent ownership stake. State-run companies—the Tanzania Electric Supply Company (TANESCO), Tanzania Petroleum Development Corporation (TPDC), and Tanzania Development Finance Company Limited (TDFL)—all hold equity in Songas, Tanzania’s flagship gas-to-electricity project. And there are other variations on the traditional IPP model. For example, instead of receiving commercial project financing, numerous IPPs have been the beneficiaries of funding by development finance institutions (DFIs), some with concessionary rates and relatively long debt tenors. African countries strive to attract investments in the generation sector and in many cases IPPs are an important new source of funding. Increased private investment will not materialize simply because large financing gaps are present. Investments will flow only where the return on capital meets the necessary threshold, and where risks are adequately mitigated. Governments, meanwhile, would like investments to serve the public interest by achieving poverty reduc- tion and growth targets. Where public and private interests are well balanced, contracts are less likely to unravel and projects are more likely to have a positive impact across the board. The primary objective of this study is to evaluate the experience of IPPs in Sub-Saharan Africa and explore how they might be improved. Lessons from past experiences and a review of best practices from the region and from around the world can greatly help countries attract more and better IPPs. Importance of Investment Flows from Development Partners and Emerging Financiers Maximizing partnerships with donors and development partners is also para- mount to scaling up investments in new generation capacity in Africa. The financial landscape of energy sector investments has changed consider- ably in recent years. Capital flows from new financiers (that is, outside the OECD)—such as China, India, and several Arab states—have reached unprece- dented levels in the past few years. Chinese-funded investments in generation account for a major part of these external flows. Investments funded by non- OECD financiers are largely part of bilateral assistance, distinct from traditional development assistance and falling instead within a new, broader category of south-to-south cooperation among developing nations (Foster and others 2009). Chinese official economic assistance to the region is typically in the form of loans from the China ExIm Bank, one of the largest export credit agencies worldwide. More recently, the China Development Bank—China’s major domestic develop- ment bank—has been expanding its portfolio overseas and has funded infrastructure investments in Africa. Infrastructure assets funded through these ­ channels remain publicly owned for the most part, and African governments or their utilities continue to be responsible for their operation and management. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 8 Introduction As African countries strive to anchor investments from traditional and ­ontraditional financiers over the long term, a better understanding of the n emerging trends in the financial landscape will help them make informed choices and effectively leverage investments and financial assistance. Scope of This Study Following this brief introduction, chapter 2 provides an overview of investment in power generation, with a focus on the current power generation systems of Sub-Saharan Africa, including public and private additions of the past 20 years. Thereafter focus shifts to specific funding sources, including official development assistance (ODA), new financiers, governments, and private investors. Chapter 3 assesses the enabling environment for IPP investments, including power sector reforms and the critical issues of generation expansion planning, procurement and contracting processes, and the creditworthiness of off-taker utilities, which together may explain why some countries are more successful than others in attracting IPP investments. In chapter 4, the spotlight turns to IPPs, among the most conspicuous of reform elements, and possibly the engine of the real scale-up of generation systems in Sub-Saharan Africa. Various types of IPPs—which may differ in their ­ ownership and financing structures, technologies, risk mitigation measures, and procurement and contracting mechanisms—are presented. In particular, the study examines and compares competitively bid versus directly negotiated IPPs. The analysis first investigates the power sector characteristics (sector legislation, poli- cies and regulations, generation expansion plans, and supply emergencies) and political economy incentives that drive governments, in certain circumstances, to select direct negotiation rather than use an open bidding process and competitive selection. The analysis assesses and compares the outcomes of the two models, specifically in terms of the cost of power supply. Chapter 5 concludes with a series of key messages that may be used to help countries take advantage of private capital and competition in procuring new power generation investments. Methodology IPPs included in this study are all greenfield, grid-connected installations of 5 megawatts (MW) or greater that have reached financial close, are under construction, or are in operation.1 A significant amount of data on power projects ­ has been collected and analyzed for this study. Sources include a series of World Bank databases, including the Private Participation in Infrastructure (PPI) database, data from the Energy Information Administration (EIA), and databases ­ prepared by AidData and the OECD, among others. In addition, the authors have conducted primary and secondary source research, particularly for IPPs and Chinese-funded projects. Detailed explanations of the data used, as well as associated limitations, are provided in footnotes in each relevant section. ­ Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Introduction 9 Apart from the already noted data sources, the analysis and conclusions in chapter 4 are based primarily on original, in-depth case studies carried out in five countries, namely Kenya, Nigeria, South Africa, Tanzania, and Uganda. Country case studies are also included as separate chapters in this book. The five case study countries were selected because they present the largest and most diversified experience with IPPs over the longest time period. Each country has developed four or more IPPs, a fact that facilitates an assessment of enabling policies and regulatory frameworks, planning and procurement ­ practices, and lessons learned. All five countries have been host to IPPs with different tech- nology bases, which allows for a relatively in-depth evaluation of cost and reliability. Also, their mix of bid structures helps assess the value differences and ­ trade-offs attached to competitive procurement. The aim of this book is to extract a few key lessons from these core countries that may be generally applied to the scaling up of investment in power genera- tion in Africa and, perhaps, in other developing regions. Data Limitations Although an unprecedented body of data and case histories has been collected and analyzed, data limitations remain. Information concerning the composition of investments by funding source; the terms of IPP contracts (which remain mostly confidential); and the size, composition, and types of investment from emerging financiers (notably China) had to be gathered from various sources and triangulated.2 For Chinese data specifically, the authors used AidData and the World Bank’s existing analysis on power investments financed by Chinese sources as a starting point. Additional secondary source research was conducted, and then actual projects were verified with stakeholders in each of the study countries. As nearly every Chinese-funded generation project is directly negoti- ated with the government of a given African country, there are limited public data available. The analysis of the Brazilian energy auction and contracting system presented in chapter 4 is intended to provide evidence of policies and practices underpin- ning competitive power markets, with a look at how they affect cost and techni- cal efficiency. One may argue that Brazil’s context is not comparable to Africa, whose power sectors are generally at an incipient stage of development. This is true. But the Brazilian analysis only seeks to highlight some basic principles that should inspire policy decisions: notably, robust planning, competition in the pro- curement of new generation, coherent sector oversight, and an unremitting emphasis on improving the performance of the utilities that are the ultimate off-takers. Such principles are valid at any latitude. The focus of this report is on power generation, as opposed to the transmis- sion and distribution (T&D) of electricity. While inadequate T&D is clearly a constraint on any effort to widen service access, countries must have suffi- cient generation capacity to be able to serve new customers, improve welfare, and accelerate economic development. Also, a detailed discussion of the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 10 Introduction ­ nvironmental externalities attached to specific IPP technologies—which pose e growing ­ concern—lies outside the purview of this report. Finally, South Africa’s size and prominence in the generation of Sub-Saharan Africa’s electric power is noteworthy. The authors have opted to include South Africa even though it dramatically shifts some of the numbers. Efforts have been made to present Sub-Saharan African tallies with and without South Africa. Notes 1. While the primary criterion for including IPPs in our data is financial close, in select cases, projects may be mentioned that are on the verge of financial close, for example, the renewable energy feed-in tariffs in Uganda, for which financial close was antici- pated in 2015. As of 2015, not all awarded projects had reached financial close or had started construction and some had been canceled through failure to fulfill conditions precedent. Also mentioned is Window 4 of South Africa’s Renewable Energy Independent Power Project Procurement Programme. These projects do not, however, form the core of the project analysis. 2. As noted in chapter 2, amid a lack of available data, government and utility megawatts and investments have largely been derived by (1) subtracting the megawatt totals of IPPs, Chinese-funded investment, official development assistance, and investment from multilateral finance institutions and development finance institutions, and then (2) using the Energy Information Administration’s corresponding data on “megawatts installed by technology” to determine residual megawatts per technology, and finally (3) ascribing a value, based on average costs per technology in Sub-Saharan Africa. Wherever possible, efforts have been made to verify the megawatts and the technol- ogy with known projects undertaken by the government. References Eberhard, A., O. Rosnes, M. Shkaratan, and H. Vennemo. 2011. Africa’s Power Infrastructure: Investment, Integration, Efficiency. Washington, DC: World Bank. Escribano, A., J. L. Guasch, and J. Pena, eds. 2008. “Impact of Infrastructure Constraints on Firm Productivity in Africa.” AICD Working Paper 9, Africa Country Infrastructure Diagnostic, World Bank, Washington, DC. Foster, V., and C. Briceño-Garmendia, eds. 2010. Africa’s Infrastructure: A Time for Transformation. Washington, DC: Agence Française de Développement and World Bank. Foster, V., W. Butterfield, C. Chen, and N. Pushak. 2009. Building Bridges: China’s Growing Role as Infrastructure Financier for Sub-Saharan Africa. Washington, DC: World Bank. IEA (International Energy Agency). 2014a. Africa Energy Outlook. Paris: IEA. ———. 2014b. Key World Energy Statistics 2013. Paris: IEA. U.S. EIA (U.S. Energy Information Administration). 2014. “International Energy Statistics.” http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid=2&aid=12. Accessed January 2014–August 2015. World Bank. 2014. “World Bank Enterprise Surveys.” http://www.enterprisesurveys.org/. Accessed July–August 2015. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 C h apter 2 Investment in Power Generation in Sub-Saharan Africa: An Overview Current Power Generation Systems in Sub-Saharan Africa In 2013, the 48 countries of Sub-Saharan Africa had a total grid-connected power generation capacity of 83 gigawatts (GW). South Africa accounts for just over half of this total, using mostly coal, and thus radically changes the power landscape. (Unless explicitly stated, subsequent references to Sub-Saharan Africa exclude South Africa.) The remaining countries combined have only 36 GW, produced from a wider array of resources (as described below). Just 13 countries have power systems larger than 1 GW, and they account for more than 80 percent of the power capacity in Sub-Saharan Africa (see table 2.1). Twenty-seven Sub-Saharan African countries have grid-connected power systems smaller than 500 megawatts (MW), and 14 smaller than 100 MW. ­ Across Sub-Saharan Africa, hydropower contributes the most capacity (51 percent), followed by fossil fuels (24 percent natural gas, 18 percent diesel/ heavy fuel oil [HFO]), coal (5 percent), and other renewables (1 percent) such as biomass, geothermal, wind, and solar (figure 2.1). Installed capacity in Sub-Saharan Africa is 44 MW per million people, compared with 192 MW in India, 590 MW in Latin America, and 815 MW in ­ China (U.S. EIA 2014; IEA 2011). Power Generation Capacity Additions over the Past 20 Years Power investments between 1990 and 2013 were far below requirements; only 15.63 GW net was added across Sub-Saharan Africa.1 Investments were particu- larly paltry from 1990 to 2000, when only 1.84 GW of new capacity was installed. In this period, a number of countries actually saw their systems contract, which may be attributed in part to civil wars and lack of system ­ maintenance—most notably in the Democratic Republic of Congo and Côte ­ d’Ivoire, but also in countries such as Angola, the Central African Republic, Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   11   12 Investment in Power Generation in Sub-Saharan Africa: An Overview Table 2.1  Significant Installed Power Generation Capacity and Gross Domestic Product: Sub-Saharan Africa, 2013 Country Capacity (MW) GDP (PPP) 2013 (current int’l $, billions) Nigeria 7,044 972.65 Sudan 3,038 153.09 Ghana 2,812 103.65 Congo, Dem. Rep. 2,444 50.47 Mozambique 2,382 28.40 Ethiopia 2,094 129.86 Zambia 1,985 57.07 Zimbabwe 1,970 25.92 Kenya 1,766 124.02 Tanzania 1,659 117.66 Côte d’Ivoire 1,521 65.55 Angola 1,509 166.11 Cameroon 1,238 69.98 Sources: Data on capacity are compiled by the authors from various sources; data on GDP are from the World Bank’s World Development Indicators. Note: GDP = gross domestic product; MW = megawatt; PPP = purchasing power parity. Figure 2.1  Power Generation Sources: Sub-Saharan Africa, 2013 percent Other Coal, renewables, 5 1 Diesel/HFO, 18 Hydro, 51 Natural gas, 24 Source: Authors’ compilation of data from U.S. EIA 2014. Note: HFO = heavy fuel oil. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 13 Ghana, Liberia, Nigeria, Sierra Leone, Somalia, and Zimbabwe. Since 2000, investments have picked up and an additional 13.8 GW has been installed in the region, excluding South Africa (figure 2.2). Fourteen countries (table 2.2) account for around 94 percent of capacity addi- tions between 2000 and 2013. Figure 2.2  Grid-Connected Generation Capacity: Sub-Saharan Africa, 1990–2013 85 50 80 45 75 40 Gigawatts Gigawatts 70 35 65 30 60 25 55 50 20 90 12 92 94 96 98 00 02 04 06 08 10 19 20 19 19 19 19 20 20 20 20 20 20 SSA (left axis) SSA excl. SA (right axis) Source: Authors’ compilation of data from U.S. EIA 2014. Note: SA = South Africa; SSA = Sub-Saharan Africa. Table 2.2  Significant Power Generation Capacity Additions: Sub-Saharan Africa, 2000–13 Country Megawatts added Sudan and South Sudan 2,218 Ghana 1,648 Ethiopia 1,576 Nigeria 1,156 Angola 923 Tanzania 797 Botswana 761 Kenya 718 Uganda 599 Côte d’Ivoire 537 Congo, Rep. (Brazzaville) 507 Cameroon 442 Senegal 377 Sources: U.S. EIA 2014, utility annual reports, and consultations with World Bank country staff. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 14 Investment in Power Generation in Sub-Saharan Africa: An Overview The remaining 6 percent of capacity—that is, around 879 MW—was distrib- uted across 34 countries. A number of countries added hardly any capacity in this period (and some actually lost capacity), including Burundi, the Central African Republic, the Democratic Republic of Congo, Lesotho, Liberia, Mozambique, and Niger, where again civil strife and a lack of adequate system maintenance were prevalent. Independent Power Projects Independent power projects (IPPs) in Sub-Saharan Africa date to 1994, when investors first made inroads into Côte d’Ivoire, followed by Kenya (1996), and Mauritius (1997). Senegal, Tanzania, and Ghana were also among the early destina- tions for private capital in 1997–99. With few exceptions, these initial deals, for (domestic) gas and (imported) diesel-fueled projects, were directly negotiated with state-owned utilities. In nearly all instances, investment climates were poor, particu- larly when compared with those of other developing regions, with insolvent utilities the norm. Deals were sealed with various investment risk mitigation mechanisms. In some instances, generous power purchase agreements (PPAs) were coupled with government guarantees and escrow accounts. In the two decades since IPPs first emerged, considerable changes have taken place, but there are remnants of the conditions and procurement approaches that first shaped private power projects. Since their inception, IPPs have spread across Sub-Saharan Africa and are now present in 17 countries (excluding South Africa)—all with varying degrees of sector reform and private participation. Currently, there are 59 projects (greater than 5 MW) in Sub-Saharan Africa (excluding South Africa), totaling $11.12 million in investments and 6.8 GW of installed generation capacity.2 South Africa adds 67 IPPs, bringing the total to 126 IPPs, with an overall installed capacity of 11.01 GW and investments of $25.6 billion.3 Figures 2.3 through 2.7 provide perspectives on the location and capacity of IPPs in Sub-Saharan Africa (excluding South Africa). IPPs are conspicuous across these diverse contexts, with notable concentra- tions in South Africa, Nigeria, Kenya, Côte d’Ivoire, Ghana, Uganda, and Tanzania. Five of these countries form the basis for this book’s case studies. IPPs represent a minority of total generation capacity and have mainly ­ complemented incumbent state-owned utilities. Nevertheless, IPPs represent an important source of new investment in the power sector in a number of African countries. For instance, in Togo, Centrale Thermique de Lomé (CTL), the country’s first IPP, raised installed capacity by approximately 67 percent (from 149 MW to 249 MW); meanwhile, Bujagali increased Uganda’s installed capacity by about 30 percent (250 MW) when it came online in 2012. Of the present pool of 59 IPPs that have reached financial close, Kenya and Uganda have the highest number.4 If Uganda closes another 10 projects as expected, it will contribute a total of 21 projects to this sum. It is noteworthy that three-quarters of the projects in these two countries have closed within the past three years. Thus, more than 50 percent of the total IPP pool, in terms of Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 15 Figure 2.3  Independent Power Projects, by Year of Financial Close: Sub-Saharan Africa (Excluding South Africa), 1994–2014 1,000 900 800 700 600 Megawatts 500 400 300 200 100 0 01 11 99 02 03 09 10 12 13 94 98 08 96 04 05 06 14 97 07 20 20 19 20 20 20 20 20 20 19 19 20 19 20 20 20 20 19 20 Source: Compiled by the authors, based on utility data, primary sources, and the Private Participation in Infrastructure (PPI) database. Note: No projects reached financial close in 1995 or 2000. Figure 2.4  Countries with the Most Independent Power Project Capacity: Sub-Saharan Africa (Excluding South Africa), 1994–2014 1,600 1,400 1,200 1,000 Megawatts 800 600 400 200 0 da a n ia da re a a ia go s l iu bi an ny ga oo an r oi ge an an To rit m Ke Gh ne Iv er nz Rw Ug Ni Za au d‘ m Se Ta M Ca te Cô Source: Compiled by the authors, based on utility data, primary sources, and the Private Participation in Infrastructure (PPI) database. Note: Not included in this graph are smaller capacity additions in the following countries: Madagascar (15 MW), Sierra Leone (15 MW), The Gambia (25 MW), Cabo Verde (26 MW), and Angola (46 MW), which contribute a sizable amount to the overall installed capacity of these countries. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 16 Investment in Power Generation in Sub-Saharan Africa: An Overview Figure 2.5  Number of Independent Power Projects: Sub-Saharan Africa (Excluding South Africa), 1994–2014 Kenya Uganda Mauritius Senegal Tanzania Ghana Nigeria Zambia Cameroon Angola Côte d’Ivoire Sierra Leone Togo Cabo Verde Rwanda Madagascar Gambia, The 0 2 4 6 8 10 12 No. of projects Source: Compiled by the authors, based on utility data, primary sources, and the Private Participation in Infrastructure (PPI) database. Figure 2.6  Number of Independent Power Projects in Various Size Categories to Have Reached Financial Close: Sub-Saharan Africa (Excluding South Africa), as of 2014 18 16 14 12 No. of projects 10 8 6 4 2 0 <20 MW 20–50 MW 51–100 MW 101–200 MW 201–300 MW >301 MW Source: Compiled by the authors, based on utility data, primary sources, and the Private Participation in Infrastructure (PPI) database. Note: MW = megawatts. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 17 Figure 2.7  Independent Power Project Capacity (% of MW), by Technology: Sub-Saharan Africa (Excluding South Africa), 1994–2014 percent Methane gas, Hydro, small 2 (<20 MW), Geothermal, 2 1 Coal, Biomass, 3 0 Waste/bagasse, 3 Hydro, large, 5 Wind, onshore, 6 HFO + MSD/HFO, OCGT + CCGT, 17 61 Source: Compiled by the authors, based on utility data, primary sources, and the Private Participation in Infrastructure (PPI) database. Note: Not featured here are solar and biomass, each representing less than 1 percent of the total. CCGT = combined-cycle gas turbine; HFO = heavy fuel oil; MSD = medium-speed diesel; MW = megawatts; OCGT = open-cycle gas turbine. number of projects, is concentrated in two countries and is relatively new. The balance developed slowly over the two decades since the first large-scale IPP reached financial close in 1994 in Côte d’Ivoire. IPPs in Sub-Saharan Africa range in size from a few megawatts to around 600 MW. There are a handful of projects larger than 300 MW (mostly in Nigeria), and a dozen projects sized 100–300 MW. Two-thirds of the IPPs are smaller than 100 MW; these are more or less evenly distributed across three size categories, of less than 20 MW, 21–50 MW, and 51–100 MW. The majority of IPP capacity is thermal. Open- and combined-cycle gas tur- bines (OCGT, CCGT) are the most dominant, though there is considerable diversity within technologies (figure 2.7) and important growth to be noted in renewables. For example, three different wind projects in Kenya and Cabo Verde reached financial close between 2010 and 2014. Similarly, there have been several new small hydropower projects (< 20 MW), most prominent in Uganda, though also seen in Madagascar and Angola over the past decade. South Africa procured 3.9 GW in private power between 2012 and 2014, all of which is renewable.5 As shown in table 2.3, wind represents the greatest portion of this new capacity, followed by solar (photovoltaic [PV] and concentrated solar power [CSP]).6 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 18 Investment in Power Generation in Sub-Saharan Africa: An Overview Table 2.3  Renewable Energy Investments: South Africa, 2012–14 Wind PV CSP Hydro Biomass Biogas Landfill Total Capacity (MW) 1,984 1,484 400 14 16 0 18 3,915 Projects awarded 32 23 5 2 1 0 1 64 Investment (US$, millions) 4,683 5,085 3,806 79 108 0 29 13,790 Source: Eberhard, Kolker, and Leigland 2014. Note: CSP = concentrated solar power; MW = megawatt; PV = photovoltaic. Chinese-Supported Power Generation Projects Another area of significant capacity additions in Sub-Saharan Africa may be linked to Chinese-funded generation assets. Of these, 6.3 GW7 reached financial close between 1990 and 2013; another 1.2 GW was expected to either reach financial close or be under construction in 2014, for a total of 34 projects.8 Figures 2.8–2.10 compare Chinese-funded power projects against IPPs, including and excluding South Africa. While there is currently more operational IPP capacity than completed Chinese-funded capacity, the picture is changing. In terms of total megawatts to have reached financial close, for the five years from 2010 to 2014, Chinese- backed investments exceeded those in IPPs. Chinese-funded projects have an average size of 226 MW, in contrast to IPPs’ average of 114 MW. Three-quarters of Chinese-funded projects are larger than 100 MW, and a third equal to or larger than 300 MW. Chinese-funded projects do not follow an expected pattern. There appears to be no correlation between Chinese-backed investment in generation and the resource wealth of the countries where investments are made. Chinese-funded generation projects exist in the following 19 countries: Botswana, Cameroon, the Central African Republic, the Democratic Republic of Congo, the Republic of Congo, Côte d’Ivoire, Equatorial Guinea, Ethiopia, Gabon, Ghana, Guinea, Liberia, Mali, Nigeria, Sudan, Togo, Uganda, Zambia, and Zimbabwe. Some of these are resource-rich countries, and some are not. Eight have IPPs, again signal- ing no apparent pattern. Excluding macroeconomic considerations that may help determine investment, the one notable characteristic is the preponderance of a particular technology: the large hydropower projects9 (that compose 4.9 GW, or approximately 63 percent, of total Chinese-funded capacity), for which Chinese engineering, procurement, and construction (EPC) contractors have become renowned worldwide. Who Has Funded What? How were these power investments financed? What proportion was funded by host governments or their utilities through debt, what by official develop- ment assistance (ODA)10 and concessionary loans from development finance institutions (DFIs), and what by private IPPs? And what are the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 19 Figure 2.8  Comparison of Chinese-Funded Power Projects and IPPs, by Total Number: Sub-Saharan Africa (with and without South Africa), 1994–2014 40 35 30 25 No. of projects 20 15 10 5 0 94 96 97 98 99 01 02 03 04 05 06 07 08 09 10 11 12 13 14 19 19 19 19 19 20 20 20 20 20 20 20 20 20 20 20 20 20 20 SA IPP IPP Chinese funded Source: Compiled by the authors, based on various primary and secondary sources. Note: No IPPs recorded for 1995 or 2000, which explains the absence of those years in the figure. IPP = independent power project; SA = South Africa. Figure 2.9  Comparison of Chinese-Funded Power Projects and IPPs, by Generation Capacity: Sub-Saharan Africa, 1994–2014 4,000 3,500 3,000 2,500 Megawatts 2,000 1,500 1,000 500 0 94 96 97 98 99 01 02 03 04 05 06 07 08 09 10 11 12 13 14 19 19 19 19 19 20 20 20 20 20 20 20 20 20 20 20 20 20 20 SA IPP IPP Chinese funded Source: Compiled by the authors, based on various primary and secondary sources. Note: No IPPs recorded for 1995 or 2000, which explains the absence of those years in the figure. The total for 2014 includes projects that were under construction and had not yet reached financial close. IPP = independent power project; SA = South Africa. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 20 Investment in Power Generation in Sub-Saharan Africa: An Overview Figure 2.10  Chinese-Supported Power Project Capacity (% of MW), by Technology: Sub-Saharan Africa, 2001–14 percent Wind, onshore, 201 MW, 3 Hydro, small Coal, 900 MW, (<20 MW), 12 43.6 MW, 0 OCGT + CCGT, 1,672 MW, HFO + MSD/HFO, 22 10 MW, 0 Hydro, large, 4,864.1 MW, 63 Source: Compiled by the authors, based on various primary and secondary sources. Note: CCGT = combined-cycle gas turbine; HFO = heavy fuel oil; MSD = medium-speed diesel; MW = megawatt; OCGT = open-cycle gas turbine. trends in new financing sources, such as China? These are the questions that will be answered in this section. The Financing Landscape since 1990 Between 1990 and 2013, approximately $45.6 billion (nominal) was invested in electric power generation in Sub-Saharan Africa. Excluding South Africa, this figure falls to $31.3 billion, far below what is required to meet Africa’s growth and development aspirations. Table 2.4 depicts the major types of investment and the associated megawatts added over the period. Over the past 25 years, governments and utilities have been the largest funders of the sector. Some such investment has come from national treasuries, some through utility-retained earnings, and the remaining from bond issues or loans from commercial banks. In recent years, however, the financing picture has changed, with larger amounts coming from IPPs11 and China. Figure 2.11 illus- trates the shift, in the years 1994–2013, toward IPPs (private debt and equity plus private sector DFI finance) and Chinese funding, while funding from ODA (here distinguished as OECD [Organisation for Economic Co-operation and Development] and bilateral funding), concessional DFIs (multilateral), and Arab donors (also predominantly concessional) has remained relatively flat. Among new financiers, China is dominant, India has made modest investments, and Brazilian and Russian involvement is still relatively miniscule. As all investment is Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 21 Table 2.4  Total Investment in Completed Power Generation Plants: Sub-Saharan Africa (Excluding South Africa), 1990–2013 Type of investment Debt and equity (US$, millions) MW added % of total MW % of total investment Government and utilities 15,883.87 8,663.26 43.66 50.67 IPPs 6,950.12 4,760.60 23.99 22.17 China 5,009.80 3,263.73 16.45 15.98 ODA, DFI, and Arab funds 3,506.48 3,156.15 15.91 11.18 Total 31,350.27 19,843.73 100.00 100.00 Source: Compiled by the authors, based on various primary and secondary sources. Note: Total megawatts installed are based on data from the U.S. EIA and the World Bank. IPP and China megawatt and investment totals are based on extensive primary and secondary source data (including the PPI database, AidData, and direct correspondence with country and project contacts). ODA (including concessionary DFI/MFI and Arab funding) has been sourced by AidData (for which the OECD data are a reference point) and cross-checked with secondary sources. The authors have also actively engaged with researchers at both AidData, the OECD, and those involved in the AICD. Data for India-funded capacity and investment in Sub-Saharan Africa have been obtained directly from the ExIm Bank of India. Finally, government and utility capacity and investments have largely been derived—amid a lack of available data—by (1) subtracting the aforementioned MW totals (of IPP, China investment, and ODA/MFI/DFI) and then (2) using EIA’s corresponding “MW installed by technology” data to determine residual megawatts per technology, and finally (3) ascribing a value, based on average costs per technology in Sub-Saharan Africa. Wherever possible, efforts have been made to verify the megawatts and the technology with the known projects undertaken by the government. The data exclude projects that have reached financial close but do not have a COD. Hence numbers will differ from those quoted elsewhere in the text for IPPs and Chinese-funded projects, especially in recent years, which have seen a significant increase in the number of projects that have reached financial close. The total megawatts added exceed the figure of net megawatts previously quoted in the text, as about 3,800 MW of capacity has been retired over the period. AICD = Africa Infrastructure Country Diagnostic; COD = commercial operation date; DFI = development finance institution; EIA = U.S. Energy Information Administration; IPP = independent power project; MFI = multilateral finance institution; MW = megawatt; ODA = official development assistance; OECD = Organisation for Economic Co-operation and Development; PPI = Private Participation in Infrastructure. Figure 2.11  Investments in Power Generation, Five-Year Moving Average: Sub-Saharan Africa (Excluding South Africa), 1994–2013 2,000 1,800 1,600 Investment (US$, millions) 1,400 1,200 1,000 800 600 400 200 0 00 96 98 02 04 06 08 10 12 94 20 19 19 20 20 20 20 20 20 19 DFIs (multilateral) Arab (private and public) ODA (OECD) Chinese flows Sum of IPP investments Source: Compiled by the authors, based on various primary and secondary sources. Note: Ghana’s Kpone IPP and Nigeria’s Azura investments in 2014 and 2015, respectively, which together total $900 million, will result in a continued upward tick in IPP investments. DFI = development finance institution; IPP = independent power project; ODA = official development assistance; OECD = Organisation for Economic Co-operation and Development. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 22 Investment in Power Generation in Sub-Saharan Africa: An Overview spread, in practice, across project construction periods, figure 2.11, with five-year rolling averages, provides a more realistic picture of funding disbursements.12 The balance of this chapter will focus on the growth and composition of IPPs and Chinese-funded investments. Financing Independent Power Projects The first IPP investment took place in 1994 in Côte d’Ivoire. Shortly thereafter, Ghana, Kenya, Nigeria, Senegal, Tanzania, and Uganda, among others, opened their doors to private sector participation in generation. Investors were not attracted by the general investment climate, as would otherwise be the case, or the adoption of key power sector reforms. Instead, the countries where IPPs and other private participation took root were those where competitive procurements were initiated or directly negotiated deals were possible, and where security and credit enhance- ment mechanisms created the opportunity to achieve required rates of return. There have been three major IPP investment spikes, in the period 1999–2001, the year 2007, and then again from 2011 until 2014. Foreign investment flows into Africa’s power sector slowed after the collapse of Enron (and the withdrawal of other U.S. firms) and again in 2008 after the global financial crisis. Each invest- ment spike is associated with the financial close of a small number of compara- tively large projects. For instance, 1999 saw the financial close of the first 288 MW on the Azito OCGT project in Côte d’Ivoire, as well as the first phase (220 MW) of the Takoradi II OCGT in Ghana. Financial close was also reached on OrPower4 (geothermal) and Tsavo (diesel) in Kenya during this year. The 2007 spike is associated with even fewer projects and may be attributed mainly to the close of Uganda’s 250 MW Bujagali project, which still represents Sub- Saharan Africa’s largest private hydropower installation, at $860 million.13 From 2011, investments began taking off. The years since (2011–14) consti- tute the largest and most sustained investment cycle to date, representing 14 projects (excluding South Africa), $4.9 billion in investment, and an addi- tional 2.1 GW in capacity. Within this upsurge are several expansions and thus the continuation of specific projects: for example, the 36 MW expansion of OrPower4, the 110 MW expansion of Takoradi II, the 111 MW expansion of Côte d’Ivoire’s Compagnie Ivoirienne de Production d’Électricité (CIPREL)— Sub-Saharan Africa’s first IPP—as well as the 146 MW expansion of Azito. These are joined by a swath of new projects that include three diesel-fired plants in Kenya, which introduced unprecedented competition in Kenya and secured par- tial risk guarantees (PRGs) from the World Bank; the 125 MW Sendou coal project in Senegal, which tapped domestic coal reserves; and the 350 MW Kpone gas-to-power plant in Ghana. The upward trend in IPP investments in Sub- Saharan Africa since 2011 is even more pronounced if South Africa is included. In 2015, this figure rose still further with the financial close of the 459 MW Azura Nigerian IPP, which harnesses domestic natural gas. With the exception of South Africa and Mauritius, none of the Sub-Saharan African countries with IPPs has an investment-grade rating. Table 2.5 provides a comprehensive list of all sovereign credit ratings in Sub-Saharan Africa. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 23 Table 2.5  Long-Term Sovereign Credit Ratings: Sub-Saharan Africa, January 2014 Country Moody’s Fitch S&P IPPs present Botswana A2 A− No Investment grade in SSA, only South Africa Baa1 BBB BBB Yes four countries, two of which Mauritius Baa1 Yes (bolded) have IPPs: South Africa Namibia Baa3 BBB− No and Mauritius Angola Ba3 BB− BB− Yes Gabon BB− BB− No Nigeria Ba3 BB− BB− Yes Lesotho BB− No Senegal B1 B+ Yes Kenya B1 B+ B+ Yes Cabo Verde B+ B+ Yes Sixteen countries have received a speculative grade rating, 10 of Zambia B1 B+ B+ Yes which (bolded) have IPPs; the Ghana B1 B+ B Yes majority occurred after countries Mozambique B B+ No received sovereign ratings Uganda B B+ Yes Cameroon B B Yes Rwanda B B Yes Seychelles B No Burkina Faso B No Benin B No Source: Adapted from Mecagni and others 2014: 20–21. Note: IPP = independent power project; S&P = Standard & Poor’s; SSA = Sub-Saharan Africa. Of the 10 countries with IPPs that have received a speculative rating (Angola, Cabo Verde, Cameroon, Ghana, Kenya, Nigeria, Rwanda, Senegal, Uganda, Zambia), six of these ratings (Angola, Kenya, Nigeria, Rwanda, Senegal, and Uganda) were received after the first IPP deals were signed.14 For instance, Kenya’s investment climate was defined, at the time, by its aid embargo in the mid-1990s. Tanzania is also worth mentioning in this context. Throughout the 1990s, all export credit agencies were off cover in Tanzania and no foreign com- mercial banks were willing to lend. The possibility of a traditional project- financed IPP deal in this climate was limited. Nevertheless, as has already been noted, IPP projects were developed in challenging investment climates. With less than favorable investment conditions, DFIs that invest in the private sector—such as the International Finance Corporation (IFC), the Netherlands Development Finance Company (FMO), the German Investment and Development Corporation (DEG), Proparco, and the Norwegian Investment Fund for Developing Countries (Norfund)—have made a significant contribu- tion to funding IPPs, as shown in figure 2.12. A breakdown of IPP investment by country is provided in figure 2.13. The greatest investments have gone to Nigeria, Kenya, and Uganda for more than a decade, and in the case of Kenya for nearly two decades. Later chapters in this book will analyze why there has been an uptick in pri- vate investment in power in recent years and why certain countries have been Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 24 Investment in Power Generation in Sub-Saharan Africa: An Overview Figure 2.12  Total Investment by IPPs and by Development Finance Institutions: Sub-Saharan Africa (Excluding South Africa), 1994–2014 1,200 1,000 Investment (US$, millions) 800 600 400 200 0 94 96 98 00 02 04 06 08 10 12 14 19 19 19 20 20 20 20 20 20 20 20 IPP investment without SA DFI investment in IPP without SA Source: Compiled by the authors, based on various primary and secondary sources. Note: DFI = development finance institution; IPP = independent power project; SA = South Africa. Figure 2.13  Investment in Independent Power Projects, by Country: Sub-Saharan Africa, 1994–2014 2,500 2,000 Investment (US$, millions) 1,500 1,000 500 0 da M nia go s te nda Ni a ad one ra he de Za n ria bo la Ug a Rw ia Se e r Ta al Ca ritiu ny ca an r oo Ca go b oi g an Si ia, T ge To Ga Ver a m as Ke ne Gh a Le lv er nz An au ag d´ m b m er Cô M Source: Compiled by the authors, based on various primary and secondary source data. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 25 Table 2.6  Largest Independent Power Projects, by Investment Total and Capacity: Sub-Saharan Africa (Excluding South Africa), 1994–2014 Project Country Investment (US$, millions) Capacity (MW) Kpone IPP Ghana 900 350 Lake Turkana Wind Power Kenya 861 300 Bujagali Hydro Project Uganda 860 250 Afam Nigeria 540 630 Okpai Nigeria 462 480 Aba Integrated Nigeria 460 141 Takoradi II Ghana 440 330 Azito Côte d’Ivoire 430 434 Source: Compiled by the authors, based on various primary and secondary source data. Note: IPP = independent power project; MW = megawatt. more successful than others in attracting IPP investments. Total IPP investment in 1990–2013 (as recorded in table 2.4) stood at $6.95 billion, based on mega- watts installed; this number swells to $8.7 billion if all projects that reached financial close between 1990 and 2013 are included. In 2014 alone, another $2.3 billion was added, for a total of $11.12 billion, representing a significant upsurge and reflecting several of the financial closes.15 Previously, IPP investments in South Africa lagged those in other Sub-Saharan countries, but between 2012 and 2014 the country closed $14 billion in renew- able energy IPPs—more than double the total in the rest of Sub-Saharan Africa over the past two decades. South Africa also boasts the largest such single invest- ment: the Kaxu Solar One, with 100 MW CSP, at approximately $976 million. The largest projects in terms of total investment in Sub-Saharan Africa, exclud- ing South Africa, are listed in table 2.6. A complete list of IPP projects in Sub-Saharan Africa is included in appendix E. ­ The Relatively New and Growing Trend of Chinese Funding In addition to IPPs, the generation sector has seen substantial investments from China since 2001, with their growth accelerating in recent years. As of 2014, based on financial close, Chinese-funded projects exceeded IPPs in total dollars invested (approximately $13.4 billion, compared to $11.5 billion). The majority of these projects received funding from the China ExIm Bank, responsible for soft loans and export credit, on the part of the Chinese govern- ment. Additional finance has been provided by the Industrial and Commerce Bank of China and China Development Bank, with the latter providing primarily commercial loans. In addition to these three, both the China Construction Bank and Bank of China are involved in energy sector investments. The ExIm and the China Development Bank remain state owned. Of the other entities named, the government owns two-thirds, and one-third is publicly traded. The China-Africa Development Fund is an additional, more recent, source of concessionary finance. The typical project structure involves an EPC plus a financing contract, which means EPCs will have a preliminary support letter or letter of interest Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 26 Investment in Power Generation in Sub-Saharan Africa: An Overview Table 2.7  Largest Chinese-Funded Projects in Sub-Saharan Africa, by Investment and Capacity, 2001–14 Investment Capacity Project Country (US$, millions) (MW) Karuma Hydropower Project Uganda 1,688 600 Zungeru Hydropower Project Nigeria 1,293 700 Morupule B Power Station Botswana 970 600 Omotosho Power Plant II (NIPP) Nigeria 660 513 Memve’ele Hydropower Project Cameroon 637 201 Bui Hydropower Project Ghana 621 400 Soubré Hydropower Project Côte d’lvoire 571 270 Source: Compiled by the authors, based on various primary and secondary source data. Note: MW = megawatt; NIPP = national integrated power project. from the “cooperation banks.” There is competition among Chinese EPCs, and the selected EPC will start work—generally with its own funds—prior to the disbursement of the bank loan, provided that the bank passes its evaluation of the project loan. The majority of loans (80 percent) are entered into between Sub-Saharan African governments and the said cooperation banks. The balance, 20 percent, is given directly to Chinese special-purpose vehicles (SPVs) or EPCs for projects. Table 2.7 showcases the largest Chinese-funded projects, based on investment costs. A comprehensive list of Chinese-supported power projects in Sub-Saharan Africa appears in appendix D. Official Development Assistance and Concessional Funding Trends There has been considerable fluctuation in ODA and concessional funding figures in the past two decades; however, this has been overshadowed by IPP and ­ Chinese-supported investment, as previously noted. Figure 2.14 shows these developments, once again disaggregating ODA (OECD/bilateral), concessional DFI (multilateral), and largely concessional Arab funding. A decline in ODA in the early 2000s and after 2008 exacerbated the dip in private investment in these years. Concessional DFIs (multilateral, and excluding the funding of IPPs) contrib- uted approximately $1.9 billion, excluding South Africa, followed by Arab funds at $1.2 billion and ODA (OECD/bilateral) at $747 million. Recent loans to Eskom in South Africa from the World Bank (International Bank for Reconstruction and Development, IBRD) and African Development Bank (AfDB), at $1.54 billion and $1.14 billion, respectively, exceed total concession- ary DFI flows to the rest of Sub-Saharan Africa over the past two decades. ODA and concessional funding is found in approximately 30 projects. The largest single project funded by Arab flows, the Merowe Dam (Sudan), explains the spike from 2004. The Gilgel Gibe I and II hydroelectric plants Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 27 (Ethiopia) received a combination of multilateral, bilateral, and government aid (tables 2.8 and 2.9). In summary, while public utilities have historically been the major sources of funding for new power generation capacity, that trend is changing. Most African governments are unable to fund their power needs, and most utilities do not have investment-grade ratings and are unable to raise sufficient debt at affordable rates. ODA and DFIs have only partially filled the funding gap. The fastest- growing sources of finance are from China and the private sector. Figure 2.14  Official Development Assistance, Development Finance Institutions (Excluding IPP Investments), and Arab Investment in Power Generation, Five-Year Moving Average: Sub-Saharan Africa (Excluding South Africa), 1994–2013 250 200 Investment (US$, millions) 150 100 50 0 11 13 03 09 10 12 94 98 99 00 01 02 04 08 96 06 95 97 05 07 20 20 20 20 20 20 20 19 19 19 20 20 20 20 19 20 19 19 20 20 DFIs (multilateral) ODA (OECD) Arab (private and public) Source: Compiled by the authors, based on various primary and secondary source data. Note: DFI = development finance institution; IPP = independent power project; ODA = official development assistance; OECD = Organisation for Economic Co-operation and Development. Table 2.8  Largest Power Projects Funded by Official Development Assistance, Arab Sources, or Development Finance Institutions, by Capacity and Funding Source: Sub-Saharan Africa, 1994–2013 Project Country Capacity (MW) Funding sources Medupi Power Station South Africa 4,800 WB, AfDB Merowe Dam Sudan 1,250 Arab funds, AFESD Expansion of Roseires Dam Sudan 700–900 Arab funds, AFESD Morupule B Power Station Botswana 600 AfDB, WB Gilgel Gibe II Ethiopia 420 Italy, EIB, WB Source: Compiled by the authors, based on various primary and secondary source data. Note: AfDB = African Development Bank; AFESD = Arab Fund for Economic and Social Development; EIB = European Investment Bank; MW = megawatt; WB = World Bank. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 28 Investment in Power Generation in Sub-Saharan Africa: An Overview Table 2.9  Largest Power Projects Funded by Official Development Assistance, Arab Sources, or Development Finance Institutions, by Investment and Capacity: Sub-Saharan Africa, 1994–2013 DFI/ODA/Arab investment Capacity Project Country (US$, millions) (MW) Medupi Power Station (coal) South Africa 2,677 4,800 Merowe Dam Sudan 1,413 1,250 Gilgel Gibe II Ethiopia 590 420 Expansion of Roseires Dam Sudan 441 700–900 Takoradi Thermal Power Plant Ghana 301 300 Source: Compiled by the authors, based on various primary and secondary source data. Note: DFI = development finance institution; MW = megawatts; ODA = official development assistance. Notes 1. That is, after taking into account capacity that was removed from the system. This total (24.85 GW) is based primarily on data from the U.S. Energy Information Administration (EIA), with minor adaptations, and supplemented with 2013 World Bank data. While the EIA data are not perfect and the authors have noted a number of anomalies, they nevertheless provide a reasonable view of overall trends, and, including annual installed global data, compose one of the most comprehensive data- bases available. Furthermore, although the EIA provides a picture of overall capacity, it does not indicate whether these projects are utility owned and operated, or whether they are independent power projects. Neither does it differentiate between traditional projects financed by the members of the Organisation for Economic Co-operation and Development or those that have been supported by new sources of financing such as China. The authors have therefore complemented these data with detailed project- level data on independent power projects and Chinese-financed projects. 2. This figure is based on the date of financial close and not the commercial operation date; it includes all projects that reached financial close in 2014. 3. By 2015, South Africa had contracted 92 renewable energy IPPs totaling 6,327 MW and US$19 billion in investment, although the 26 projects of round 4 had still to reach financial close. 4. Projects included in this tally are all grid-connected IPPs with a capacity of 5 MW and greater. A complete list is provided in appendix A. Although Zimbabwe has three hydropower IPPs, these projects are all under 5 MW and are therefore excluded here. 5. A further 2,189 MW was awarded in 2015. 6. Between April and June 2015, South Africa announced the award of an additional 26 projects totaling 2,205 MW. 7. Many of the deals concluded in recent years were for hydroelectric plants that, as of 2014, had not yet reached their commercial operation date (COD). Hence, there is a discrepancy with the data in table 2.4, which includes only megawatts that are operational. 8. Unlike IPPs, which follow a strict sequence of financial close and then construction, Chinese-funded generation assets may commence construction before financial close, due to financing arrangements with “cooperation banks” as described in the next section. 9. Large hydropower is defined here as >50 MW. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investment in Power Generation in Sub-Saharan Africa: An Overview 29 10. For the purpose of this study, ODA is defined as flows to countries and territories on the OECD (Organisation for Economic Co-operation and Development) Development Assistance Committee’s list of ODA recipients (available at http://www.oecd.org​ dac​ /­ /stats/daclist.htm) and to multilateral development institutions that are provided by official agencies, including state and local governments, or by their executive agencies; that aim to promote the economic development and welfare of developing countries; and that are concessional in character and have a grant element of at least 25 percent (calculated at a rate of discount of 10 percent) (http://www.oecd.org/investment​ /­stats/officialdevelopmentassistancedefinitionandcoverage​.htm). 11. Investment in IPPs includes private equity and loans from commercial banks, as well as flows from DFIs oriented toward the private sector, such as the International Finance Corporation, the Netherlands Development Finance Company (FMO), the German Investment and Development Corporation (DEG), Proparco, the Norwegian Investment Fund for Developing Countries (Norfund), and exim banks, among others. DFIs’ commercially priced investments in IPPs are included in the IPP total. ­ Concessionary grants and loans from DFIs and multilateral finance institutions are included in the ODA total. 12. Data on the financing of IPPs and Chinese-funded projects are most often available at the time of financial close. ODA data include funding commitments made in specific years (which could be graphed conveniently alongside IPP and Chinese funding data); however, these funding commitments do not have the same degree of certainty as financial close figures and there is often a large discrepancy between ODA commit- ments and disbursements. Therefore, this report relies on disbursements. ODA project disbursements were frontloaded to the first date to be consistent with IPP and Chinese data. Because most government and utility data are derived (as described in the text), and the EIA total installed megawatt figures correspond to COD and not to the finan- cial close dates used for IPPs and Chinese-funded investments, or the ODA disburse- ment dates, it is difficult to form an accurate picture of government and utility funding year by year. These funding sources have therefore been excluded from figure 2.11. 13. Although Bujagali still represents the largest private hydropower installation, taking into consideration all renewables, Bujagali has been surpassed by the 300 MW Lake Turkana project in Kenya at $861 million. 14. Angola, Nigeria, and Zambia, despite having a noninvestment speculative grade, have all issued bonds since 2011 (Mecagni and others 2014: 8–10). 15. As noted previously, the discrepancy in figures is further exacerbated by the fact that table 2.4 records only megawatts installed. References Eberhard, A., J. Kolker, and James Leigland. 2014. South Africa’s Renewable Energy IPP Procurement Program: Success Factors and Lessons. Washington, DC: World Bank. IEA (International Energy Agency). 2011. Key World Energy Statistics 2011. Paris: IEA. Mecagni, Mauro, Cheikh A. Gueye, Jorge Ivan C. Kriljenko, Masafumi Yabara, Yibin Mu, and Sebastian Weber. 2014. Issuing International Sovereign Bonds: Opportunities and Challenges for Sub-Saharan Africa. Washington, DC: International Monetary Fund. U.S. EIA (U.S. Energy Information Administration). 2014. “International Energy Statistics.” http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid=2&aid=12. Accessed January 2014–August 2015. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 C h apter 3 Factors that Support Independent Power Projects and Their Success Introduction How do we account for the power investment trends outlined in the previous chapter? Why have some countries been more successful than others in attract- ing private investment? What are the key elements of the enabling environ- ment for independent power projects (IPPs)? To what extent does the structure of a power sector affect the levels and rate of investment in new power genera- tion capacity? What are the other key factors that can facilitate investment in new capacity? This chapter explores the enabling environment for IPPs. First it examines the 20-year experience of power sector reforms on the African continent. Despite an ambition to unbundle and privatize the electricity industry and introduce competition, a very different reality persists. In most African coun- tries, the state still controls the power sector, often through the presence of a dominant national utility. Meanwhile, massive needs for new investment, especially in power generation, greatly exceed the funding capacity of gov- ernments or national utilities and mean that private sector participation is imperative. Within this context, IPPs have arisen in a number of countries, and in power sectors with various levels of unbundling and sector reforms. While this track record suggests that traditional reforms are not an absolute precondition for attracting IPPs, reforms that improve overall sector governance, strengthen the enabling environment, improve financial sustainability, reduce perceived risks by prospective investors, and improve competition will facilitate and accelerate investment. Elements that appear to be particularly important in supporting IPPs include least-cost power expansion planning, effective procurement and contracting pro- cesses, and ensuring the financial health of off-taker utilities. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   31   32 Factors that Support Independent Power Projects and Their Success Power Sector Reforms and Independent Power Projects Reforms and Emerging Power Sector Market Structures in Sub-Saharan Africa Following earlier reforms in the power sectors of industrial countries and emerg- ing markets, developing countries were encouraged to unbundle their electricity utilities and to introduce competition and private sector participation. Reforms were pursued to address poor financial and technical performance. Reform efforts also sought to introduce a space for private participation, as the public sector was no longer able to provide the requisite funds for system expansion (Jamasb 2002: 1–2; Gratwick and Eberhard 2008b). At the outset, it was advised that the state-owned utility be transformed into a separate legal entity, through corporatization. Thereafter, this new entity, which was distinct from any government ministry and had all the associated company rights and obligations (including governance, labor, and budgetary management), was to undergo “commercialization.” Such reforms were intended to address the root cause of many of the troubles faced by developing-country utilities and move them toward cost-recovery in pricing and improvements in metering, bill- ing, and collections. Concurrently, the passage of the requisite energy legislation was to provide a legal mandate for restructuring, as well as the legal framework to allow private and foreign participation (including ownership) in the sector. Provision was also made for an independent regulator to introduce efficiency, cost-reflectivity, transparency, and fairness in the management of the sector, encourage appropriate investment, and protect consumers. Further reform steps included unbundling, privatization, and competition— although it was not always apparent whether these were appropriate for specific countries. Vertical unbundling of the incumbent utility was proposed to separate the potentially competitive generation businesses from the natural monopoly of transmission and distribution (T&D) components. The horizontal unbundling of generation was meant to create competition by facilitating power trade through a power exchange, spot market, or bilateral contracts. Private investment was encouraged, in the form of IPPs with long-term contracts, and through full dives- titure and the privatization of assets. Over the course of the past two decades, power utilities in Africa were corpo- ratized and steps were taken toward greater commercialization. Numerous coun- tries passed energy laws providing for third-party access to grids and new regulatory institutions; many others also adopted IPPs. However, the reform measures stop here, with little achieved in terms of full unbundling (vertical or horizontal), privatization, and the introduction of wholesale and retail competi- tion (Gratwick and Eberhard 2008a: 315–16).1 While Nigeria appears to be moving toward wholesale competition, having unbundled and privatized its utility and established a bulk electricity trader, the latter is still not operational. Other countries, such as Ghana, are considering moving to wholesale competition, but full implementation may be far off. The stated intentions of a number of African countries—including South Africa, Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Factors that Support Independent Power Projects and Their Success 33 Tanzania,2 Zambia, and Zimbabwe—to introduce market competition have not materialized. As of 2014, of the 48 Sub-Saharan countries, 21 had state-owned and v ­ ertically integrated utilities (that is, with generation, transmission, and distribution com- bined) with no private sector participation (figure 3.1, model 1).3 The ­second-largest group of countries (model 6) also had vertically integrated state-owned u ­ tilities but, in addition, had introduced IPPs. A much smaller group of countries had unbun- dled power generation from T&D, and also incorporated IPPs (models 7–10).4 The unbundling of generation from T&D was initially understood as a key reform element, and one that arguably should even precede the introduction Figure 3.1  Electricity Sector Structures: Sub-Saharan Africa, 2014 1. 2. 3. 4. Benin G Gabon G G G G Botswana Guinea Burkina Faso Guinea-Bissau Namibia Burundi T Liberia T T T T CAR, Chad Malawi, Mali Congo, DRC Mauritania, Niger D Djibouti, Eritrea D Somalia D D Mozambique Ethiopia D Equatorial Guinea Swaziland 5. 6. 7. G G G IPPs G The Gambia G IPPs Madagascar Mauritius T T Rwanda South Africa T Angola Senegal Sudan Cabo Verde Sierra Leone Cameroon D Tanzania Dn D Côte d’Ivoire Togo D 8. 9. 10. IPPs G IPPs G IPPs G T Ghana T Nigeria T T Uganda D D Kenya Zimbabwe D Dn D Zambia Source: Compiled by the authors, based on various primary and secondary source data. Note: Includes vertical integration or unbundling of generation (G), transmission (T), and distribution (D) and presence of IPPs. While there are 48 Sub-Saharan African countries, the Comoros, Lesotho, São Tomé and Príncipe, and the Seychelles are excluded from figure 3.1. Thus the three island states are not included, along with Lesotho, where the national utility, Lesotho Electricity Company (LEC), has only T&D assets. A separate generation plant, the Muela Hydroelectric Station (72 MW), is owned and operated by the Lesotho Highlands Development Authority (owned by the government of Lesotho). These countries otherwise form part of the overall analysis. It should be noted that Kenya also has an unbundled transmission company, the Kenya Electricity Transmission Company Limited (KETRACO), which is responsible for new transmission assets. Furthermore, Uganda has one large, privatized distribution utility supplied from the transmission grid and some regional distribution companies not connected to the main transmission grid. Finally, some of the countries listed in model 1 can, in principle, allow private investments, but as of yet do not have IPPs. CAR = Central African Republic; Congo = Republic of Congo; DRC = Democratic Republic of Congo; IPP = independent power project; MW = megawatt; T&D = transmission and distribution. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 34 Factors that Support Independent Power Projects and Their Success of IPPs to ensure fairness in the contracting and dispatching of IPPs (versus the off-taker utility’s own generation). This sequencing, however, is not fully reflected in the power sector structures on the ground. The majority of IPPs are in countries with vertically integrated utilities. In only six countries—namely, Ghana, Kenya, Nigeria, Uganda, Zambia,5 and Zimbabwe—do the unbundling of utility generation and the introduction of IPPs go hand in hand. Sudan has unbundled generation, but has no IPPs. Other countries, such as Ethiopia, Ghana, Namibia, Nigeria, South Africa, and Uganda, have ­ separate distribution companies, but this level of unbundling is of less importance in cre- ating equal opportunities for state utilities and IPPs, unless distributors are pro- curing generation capacity directly. Do Power Market Structures Matter in Attracting Independent Power Projects? Despite an ambition to unbundle and privatize the electricity industry and intro- duce competition, outcomes have not been as far-reaching as the plans set down on paper. As seen in the power sectors of many Sub-Saharan African countries, the incumbent state-owned utility often remains intact and dominant, even as IPPs are invited into the market. In many cases, the incumbent state-owned utility may at a later stage also invest in new generation capacity. Thus, the model that has emerged is fundamentally a hybrid market, where public and private invest- ment coexist. The characteristics of such power markets need to be recognized explicitly, as they present an array of new and unanticipated challenges related to generation planning and in particular to allocating new investment opportuni- ties, ensuring timely initiation of competitive bidding processes, establishing institutional capacity to contract effectively, and ensuring fair and transparent power dispatch arrangements. Implementation of either wholesale or retail competition has also been very ­ nfrastructure, limited. Such competition requires sophisticated legal and financial i which is often inadequate in many developing countries. Even with the infra- structure in place, the market may not send the signals needed for the requisite investment. It is possible that almost half of the reform measures typically prescribed are not necessarily relevant to the conditions on the ground in most develop- ing countries. In addition, as the previous section shows, there is no clear cor- relation between the degree of unbundling and the presence of private investment in the form of IPPs, although it seems logical that where the national utility is still investing in new generation capacity, its unbundling would have the effect of leveling the playing field for new IPPs. The next sec- tion will also highlight that IPPs are not necessarily correlated to the presence of an independent regulator. In sum, the analysis shows that IPP investments have arisen in a variety of power market structures, characterized by various degrees of reform. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Factors that Support Independent Power Projects and Their Success 35 This does not mean the traditional elements of power sector reform—such as unbundling, independent regulation, privatization, and competition—are unimportant or irrelevant. As has been observed, reforms remain important as long as they improve sector governance and the enabling environment for IPPs. They also serve to boost a country’s credibility—or reduce the risk perceived by power sector investors. This is a key positive externality that can ­ ultimately lead to more sustainable contract arrangements. There will also be instances where private participation can improve utility performance. Where there are real conflicts between state-owned generation and the pro- curement of IPPs, unbundling generation from the transmission company and system operator or market operator might make sense. And competition for the market remains critical. The power sectors in African countries face two enduring challenges. First is to accelerate investment in generation capacity to power economic development. Second is to improve the performance of utilities so that they are creditworthy purchasers of power from IPPs and can also deliver electricity services on a sus- tainable basis. In response to these challenges, focus on planning, procurement, and contracting practices for new generation investment must be renewed and, simultaneously, improvements need to be made to the performance of distribu- tion utilities. An important lesson is provided by the second wave of power sector reforms to occur in regions such as Latin America (see chapter 4). There, the traditional reform model was tweaked to attract adequate investment in new power generation capacity, especially in capital-intensive technologies such as large hydroelectricity and also in new, renewable technologies such as wind energy. Most Latin American countries had undergone a process of u ­ nbundling, privatization, and the establishment of wholesale spot markets. Even so, it became clear that long-term contracts with financially viable off-takers were critical to generate secure and reliable financial flows to pay for large invest- ments. A second wave of reforms—as enacted in Brazil, Chile, Colombia, Panama, and Peru—shifted emphasis from prescriptions regarding unbun- dling, privatization, and the creation of wholesale markets (competition in the market), to the establishment of dynamic plans for long-term generation and transmission expansion. This was linked to the timely initiation of com- petition for the market—through the auction of long-term power contracts backed by creditworthy off-takers. Of particular importance were efforts to improve the technical and financial performance of electricity distribution: unless a utility operates efficiently, and sufficient revenue is being collected to pay for operations and investment (including contracts for power), sector reforms cannot meet their objectives. Africa has not progressed as far as Latin America and other regions in the privatization and establishment of wholesale electricity markets; nevertheless, it can learn from Latin America’s second wave of reforms, in particular the prac- tices and tools used to attract sources of new investment in power generation capacity—and to foster competition among them. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 36 Factors that Support Independent Power Projects and Their Success The Importance of Independent Regulation By definition, IPPs are investment transactions regulated by the underlying contracts, most notably the power purchase agreement (PPA). Regulations at the ­ sector level, although they do not directly influence the details of these contracts, are important in defining the rules of the game and ultimately shaping the enabling environment for IPPs. Regulators approve PPAs and issue licenses to new power projects. The most widespread power sector reform element in Sub-Saharan Africa has been the establishment of independent energy/utility regulators. As of 2014, 27 countries, or more than 50 percent of all Sub-Saharan African countries, had established such agencies (table 3.1). The countries with the most IPPs—for example, Uganda, Kenya, Senegal, Nigeria, Tanzania, Ghana, Cameroon, and Côte d’Ivoire—all have electricity regulators (table 3.1). The presence of such an agency is not a sufficient condi- tion for attracting IPPs, however, as seen by the countries with a regulator but no IPP. The quality of regulation, meanwhile, is critical. If regulatory governance is transparent, fair, and accountable, and if regulatory decisions are credible and predictable, there is greater certainty around market access, and tariffs and rev- enues—with potentially positive outcomes for the host country and investors alike. The corollary is that inexperienced regulators with insufficient capacity may make arbitrary decisions that might serve to increase regulatory risk and deter investment. An independent regulator brings with it oversight capacity and could poten- tially enforce the competitive procurement of IPPs. This is largely recognized as a best practice, as will be discussed at length in the next chapter. In nearly all of Table 3.1  Sub-Saharan African Countries with Independent Electricity/Utility Regulators, by Year Established Year regulator established Country 1994 South Africa 1997 Zambia 1998 Cameroon, Côte d’Ivoire, Senegal 1999 Niger, Uganda 2000 Ghana, Mali, Namibia, Togo 2001 The Gambia, Mauritania, Rwanda, Tanzania 2003 Zimbabwe 2004 Lesotho, Mozambique 2005 Nigeria 2006 Kenya 2007 Angola, Malawi, Swaziland 2010 Burkina Faso, Gabon 2011 Sudan 2014 Ethiopia Sources: Based on authors’ data, African Forum for Utility Regulators, and IRENA 2012. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Factors that Support Independent Power Projects and Their Success 37 the five case study countries, competition has been enshrined in legislation and/or regulations, with the regulator at the helm (box 3.1). Much of the relevant leg- islation, however, has come into effect only recently after considerable planning and procurement mishaps, and is not foolproof. For example, Kenya, Tanzania, Uganda, and Nigeria have seen directly negotiated projects even after the advent of the regulator. Overall, the presence of a regulator is not necessarily associated with more competitive procurement practices, and regulators have not always ensured that captive electricity consumers benefit from the pass-through of competitive gen- eration prices. Also, the independence of regulators may be compromised by overreaching and competing government agencies. In many countries, the inde- pendence and professional capacity of regulators need to be strengthened so that they can discourage directly negotiated generation contracts and instead enforce the rules for the competitive procurement of IPPs. Box 3.1  Legislation to Promote Sector Competition: Examples from Five Countries In Kenya, through the 2006 Energy Act, the regulator is charged with ensuring the implemen- tation and the observance of the principle of fair competition in the energy sector, in coordina- tion with other statutory authorities (Clause 5). As stated in the 2013 Public Procurement and Disposal Act, the procuring entity shall open tendering (29 [1]). In Nigeria, the regulator mandated competitive tenders through its Regulations for the Procurement of Generation Capacity, published in 2014. In South Africa, Section 217 of the Constitution requires that when an organ of state pro- cures goods and services it must do so in accordance with the principles of fairness, equitabil- ity, transparency, competitiveness, and cost-effectiveness. This constitutional requirement is echoed in section 51(1)(a) of the Public Finance Management Act of 1999. In Tanzania, the Electricity Act gives the Energy and Water Utilities Regulatory Authority (EWURA), the Tanzanian regulator, powers to approve the initiation of procurement of power projects. These powers have been further defined under “The Electricity (Initiation of Power Procurement) Rules,” with the overarching goal to discourage the development of unsolicited proposals that fall outside the Power System Master Plan and are not financially viable for the state (EWURA, per com, 2014; Electricity Act [CAP 131]). The rules came into effect as of January 1, 2015, and will impact on projects presently under negotiation, but not existing IPPs (that is, Songas and Independent Power Tanzania Ltd., IPTL). In Uganda, the relevant guidelines are less explicit, though the regulator is vested with managing the process. For any independently promoted projects across all generation types, the Electricity Regulatory Authority (ERA) can receive unsolicited bids (Section 30 of the Electricity Act 1999) or implement competitive bidding processes for concessions pursuant to Section 33 of the Electricity Act (1999). For all unsolicited bids, ERA is the focal entity and guides and monitors the planning and implementation of projects. Source: Compiled by the authors, based on various primary and secondary source data. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 38 Factors that Support Independent Power Projects and Their Success The Importance of Planning, Procurement, and Financial Sustainability Generation Planning in Hybrid Power Markets The most comprehensive planning tools are the Least Cost Power Development Plan (LCPDP) or, more broadly, the Integrated Resource Plan (IRP), which includes both generation and transmission planning, and identifies the supply- and demand-side investments needed to meet projected electricity demand at the least total cost (that is, the net present value [NPV] of investments, operat- ing costs, and costs of unsupplied energy) over a certain period (typically 15–20 years), while also meeting associated policy objectives such as environmental sustainability. In the past, the incumbent state-owned power utility generally assumed responsibility for generation expansion planning. In many cases, these utilities ran into financial difficulties; investment costs were high, and tariffs were insuf- ficient to fund the required new investment. Today, the majority of utilities in Africa are underinvesting: they simply do not have sufficient financial resources. As noted, growing pressure for power sector reforms has encouraged the entry of IPPs and new private investment that supplements the utilities’ efforts. However, in these hybrid markets it is often unclear who is responsible for generation expansion planning. There is a range of generation planning arrangements across Sub-Saharan African countries. While there is no one optimal solution, some key lessons may be observed. If the planning function remains with the national utility, strong political leadership is crucial to ensure that the incumbent utility works with the state to achieve national goals and objectives. Alternatively, the planning function may be transferred to another institution—within the government, the regulator, or a new independent planning body—or attached to an unbundled, independent transmission and/or system operator. If this transfer is to be successful, the planning function needs to be properly resourced in terms of people, software, and institutional capacity. The majority of Sub- Saharan African countries have inadequate capacity and end up contracting out this function to consultants. Master plans for least-cost generation expansion are produced but are often not implemented. Tanzania is a case in point—it has a master plan but this is not fully used in practice. Meanwhile, the country still experiences power shortages, as do many other countries in the region. Although the institutional location of power sector planning is important, equally important is the nature of that planning. Planning needs to be up to date and flexible to ensure security of supply, a least-cost mix of generation plants, and the right combination of exports and imports. South Africa’s electricity plan (the IRP 2010–30) is widely recognized as being out of date, with optimistic demand projections and incorrect cost assumptions. Nevertheless, the plan has continued to be used as a basis for power procurement and investment decisions, with the risk that too much capacity of the wrong kind might be procured. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Factors that Support Independent Power Projects and Their Success 39 Effective planning also involves broad stakeholder participation. Kenya, for example, has adopted a planning approach that involves a wide range of stake- holders through the membership of a planning committee chaired by the energy sector regulator. Broad buy-in to the planning process ensures that stakeholders properly understand the challenges and costs of developing new sources of power, and creates investor interest. Generation Procurement ­ ell-delineated Electricity plans need to be translated into timely procurement and w investment opportunities for the private and public sectors. Unfortunately, few African countries have an explicit connection between planning and procurement. South Africa is one of the few countries that do have such a connection. The Electricity Regulation Act, and subsidiary new generation regulations, empower the minister of energy to determine not only how much new power generation capacity is needed, but also what type should be built, and when, and by what party. Yet South Africa, like most other Sub-Saharan African countries, lacks clearly stated criteria for the allocation of investment opportunities between state-owned enterprises (SOEs) and IPPs. In Ghana, IPP investments have been negotiated with the Volta River Authority (VRA), the Electricity Company of Ghana (ECG), and the Ministry of Energy, with all three entities entering sepa- rate purchase agreements with potential IPPs. Each entity has followed different processes, with little regard for national procurement procedures. A key feature of power generation procurement in Africa is the low recourse to competitive bidding, despite the fact that this is frequently enshrined into legislation. A disproportionate share of IPPs in Africa is developed based on unso- licited proposals and through direct negotiation. The causes behind this phenom- enon and the various advantages, disadvantages, and outcomes of unsolicited and directly negotiated projects versus competitive bidding will be extensively inves- tigated in chapter 4. Weak linkages between planning and procurement, inade- quate or incomplete regulations, and the absence of a procurement authority, as outlined earlier, all contribute to the problem and will be further discussed. It should be noted that even where good regulations and practices exist, without enforcement there is little hope that procurement will be run efficiently. When countries—often finding themselves short of power—opt for direct negotiation and/or are confronted with numerous unsolicited proposals from power developers, more attention needs to be devoted to ensuring that they achieve value for money. For example, Kenya Power once had robust processes for testing the merits of unsolicited proposals, using a range of analytical techniques. Its methods included “open book” processes, prespecifying a capital ­ structure for the project and expected returns on debt and equity, and comparing the resulting prices to other pricing benchmarks—such as feed-in tariffs (FiTs) and the prices resulting from competitive procurements. The energy regulator also undertook a separate review of value for money. Importantly, these processes consider the combined impact of project prices and risks. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 40 Factors that Support Independent Power Projects and Their Success Meanwhile, FiTs have emerged as an alternative procurement mechanism in a number of Sub-Saharan African countries, including Angola, Ghana, Kenya, Nigeria, Rwanda, Senegal, Tanzania, and Uganda. FiTs have mostly been used for the procurement of grid-connected renewable energy. Standard power purchase tariffs are published by the regulator and have the advantage of offering investors simplicity and price certainty. However, regulators may set FiTs too high, and the potential advantages of lower prices from competitive tenders might be missed. Generation Contracting In most cases, IPP contracts extend over a long period of time; the typical contract is for 15 to 30 years. This large time frame is considered both a strength and a weakness. Predictable revenue streams allow equity risk capital to be rewarded, and sponsors can also service debt with long tenors. Conversely, in an environment of power market reform, both parties can encounter problems with fixed long-term take-or-pay contracts if the various conditions under which the contracts are agreed upon change. While all con- tracts between IPPs and utility off-takers described in this book have been in the form of long-term PPAs, the legal and regulatory frameworks surrounding the making of these contracts differ, resulting in diverse outcomes across the region’s power sectors. Governance frameworks, which shape the degree of predictability and risk in the sector, ultimately impact on investment and development outcomes. Governments and national utilities require a great deal of specialized expertise to negotiate robust and competitive contracts. Private sponsors often hire the best legal, financial, and technical transaction advisers; governments rarely do so. To plug this gap, governments need to allocate clear responsibility to either the national utility or a government agency. If the national utility is to be responsible, then it is also critical that a ring-fenced contracting function be established, sepa- rate from the utilities’ own generation or new build function. The best location may be an independent system operator that also takes responsibility for plan- ning and may then be integrated with the procurement function. In this case, the system operator assumes responsibility for both the system’s short-term balance and the long-term security of supply. Creditworthiness of Off-Takers At the crux of the investment conundrum is the financial viability of the off- taker. High T&D losses, tariffs below cost-recovery levels, and poor billing and collections are key issues that can severely affect the financial standing of utilities. Average distribution losses in Sub-Saharan Africa are 23 percent compared with the commonly used norm of 10 percent or less in developed countries. Moreover, average collection rates are only 88.4 percent compared with the best practice of 100 percent. Combining the costs of distribution losses and uncollected revenue and expressing them as a percentage of utility turnover provides a measure of a utility’s inefficiency. In Africa, this inefficiency is equivalent, on average, to 50 percent of turnover (Eberhard and others 2011: 134). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Factors that Support Independent Power Projects and Their Success 41 At the sector level, governance reforms can critically improve the ­performance of state-owned utilities. Governance may be assessed using various criteria, including ownership and shareholder quality, managerial and board autonomy, accounting standards, performance monitoring, outsourcing to the private sector, exposure to labor markets, and the discipline of capital markets. Most utilities in Sub-Saharan Africa meet only about half of the criteria for good governance (Eberhard and others 2011: 137). At the operational level, practices targeting technical and commercial effi- ciency can critically improve the financial standing of a utility in a short period of time. To reduce losses and protect revenues, utilities must take better control of technical losses, enhance service delivery, and improve billing and collection. Such actions are especially important as a utility approaches an IPP transaction. If the utility is financially fragile and is not collecting enough revenues, then the payment of power generators could be threatened. Robust PPAs have therefore become a requirement for new investors seeking to safeguard payment streams (that is, regardless of the financial health of the off-taker). PPAs denominated in U.S. dollars or euros, bolstered by credit enhancements and security measures, have been necessary to seal the deal for the majority of IPPs in Sub-Saharan Africa over the past two decades. While most arrangements have been honored, there is evidence that contracts have unraveled when terms were considered untenable by country stakeholders, as seen in the case of Tanzania’s IPTL (Independent Power Tanzania Ltd.) and Nigeria’s AES Barge, both of which went to arbitration. Thus, even robust PPAs and security arrangements are not ironclad, and issues must be anticipated from the outset during the procurement process. A Framework for Understanding the Enabling Environment for IPPs After documenting and analyzing IPPs in Sub-Saharan Africa over a decade, researchers have compiled a list of the elements seen to contribute to sus- tainable IPP investments (table 3.2). Some of the elements may be grouped into areas over which the host-country government has immediate influence, and include issues such as policy, regulation, planning, and competitive procurement. The balance of issues may be considered as being within the ­ project purview. The list outlined here is not exhaustive, but provides a sketch of best practices for developing IPPs in Sub-Saharan Africa (Eberhard and Gratwick 2011). At the country level, the overall economic conditions and legal framework are clearly relevant, as are policies that encourage private investment in general and in the power sector in particular. Stable macroeconomic policies, investment protection, respect for contracts, capital repatriation, tax incentives, and further IPP investment opportunities will attract more capital at lower cost. Transparent, consistent, and fair regulatory oversight, with a commitment to cost-reflective tariffs, provides more price and revenue certainty, boosting the creditworthiness of off-takers and thus requiring less risk mitigation. And we have already Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 42 Factors that Support Independent Power Projects and Their Success Table 3.2  Factors Contributing to Successful Independent Power Project Investments, Sub-Saharan Africa Factor Details Country level Stable country context Stable macroeconomic policies Legal system allows contracts to be enforced, laws to be upheld, arbitration Good repayment record and investment-grade rating Previous experience with private investment Clear policy framework Framework enshrined in legislation Framework clearly specifies market structure and roles and terms for private and public sector investments (generally for a single-buyer model, since wholesale competition is not yet seen in the African context) Reform-minded “champions” to lead and implement framework with a long-term view Transparent, consistent, and fair Transparent and predictable licensing and tariff framework regulation Cost-reflective tariffs Consumers protected Coherent power sector planning Power-planning roles and functions clarified and allocated Planning function skilled, resourced, and empowered Fair allocation of new build opportunities between utility and IPPs Built-in contingencies to avoid emergency power plants or blackouts Competitive bidding practices Planning linked to timely initiation of competitive tenders/auctions Competitive procurement process adequately resourced and fair/transparent Project level Favorable equity partners Local capital/partner contribution, where possible Risk appetite for project Experience with developing-country project risk Involvement of a DFI partner (and/or host country government) Reasonable, fair ROE Development-minded firms Favorable debt arrangements Competitive financing Local capital/markets mitigate foreign-exchange risk Risk premium demanded by financiers or capped by off-taker matches country/ project risk Some flexibility in terms and conditions (possible refinancing) Creditworthy off-taker Adequate managerial capacity Efficient operational practices Low technical losses Commercially sound metering, billing, and collections Sound customer service Secure and adequate revenue Robust PPA (stipulates capacity and payment as well as dispatch, fuel metering, stream interconnection, insurance, force majeure, transfer, termination, change-of-law provisions, refinancing arrangements, dispute resolution, and so on) Security arrangements where necessary (escrow accounts, letters of credit, standby debt facilities, hedging and other derivative instruments, committed public budget and/or taxes/levies, targeted subsidies and output-based aid, hard currency contracts, indexation in contracts) table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Factors that Support Independent Power Projects and Their Success 43 Table 3.2  Factors Contributing to Successful Independent Power Project Investments, Sub-Saharan Africa (continued) Factor Details Credit enhancements and other Sovereign guarantees risk management and Political risk insurance (PRI) mitigation measures Partial risk guarantees (PRGs) International arbitration Positive technical performance Efficient technical performance high (including availability) Sponsors anticipate potential conflicts (especially related to O&M and budgeting) and mitigate them Strategic management and Sponsors work to create a good image in the country through political relationships, relationship building development funds, effective communications, and strategically managing their contracts, particularly in the face of exogenous shocks and other stresses Source: Adapted from Eberhard and Gratwick 2011. Note: DFI = development finance institution; IPP = independent power project; O&M = operations and maintenance; PPA = power purchase agreement; ROE = return on equity. m ­ entioned the benefits of power planning and timely initiation of competitive tenders or auctions for new capacity. At the project level, debt and equity finance has to be appropriately struc- tured and serviced through revenue guaranteed in a robust PPA and backed with required credit enhancement and security arrangements, including guarantees, insurance, and other risk mitigation instruments. The Performance of Five Countries Table 3.3 summarizes the features of the power sectors of the five case study countries, with a focus on those elements relevant to supporting IPPs. Of the five countries, South Africa clearly has the best investment climate, a policy for expanding renewable energy, a power plan linked to a series of com- petitive tenders, and a set of standardized contracts backed by a sovereign guar- antee. The country has an independent regulator, although its decisions have not always been consistent. It could be argued that utility tariffs do not fully reflect costs; nevertheless, the regulator has mandated the full pass-through of IPP costs. The consequence has been a highly successful IPP program where more mega- watts and investment have been contracted in four years than in the previous two decades across the rest of Sub-Saharan Africa. Remarkably, this has been achieved within an electricity sector that is dominated by a large state-owned vertically integrated utility that relies mostly on coal and once was not receptive to IPPs. Kenya has an investment climate that is better than that of neighboring Tanzania and Uganda, as well as Nigeria, and has been able to attract private investment at a lower cost than these countries. Its electricity sector has been Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 44 Factors that Support Independent Power Projects and Their Success Table 3.3  Summary of Power Sector Features in Case Study Countries, Sub-Saharan Africa Unbundled Privatized Wholesale Independent Least Cost Power Predominant Country utility utility competition regulator Development Plan (LCPDP) procurement practices South No No No Yes Integrated Resource Plan for Competitive Africa 2010–2030 out of date Kenya Yes No No Yes LCPDP based on stakeholder Competitive consultations Tanzania No No No Yes Electricity Supply Industry Mostly direct Reform Strategy and negotiations (some Roadmap, 2014–2025; previous tenders with LCPDP, 2013 limited competition) Uganda Yes Partiala No Yes 2011 Power Sector Direct negotiations until Investment Plan not advent of GETFiT updated (hybrid feed-in tariff with competitive tenders) Nigeria Yes Partiala Transitional Yes System operator is Direct negotiations market mandated to prepare a power master plan but has not been updating it Source: Compiled by the authors, based on various primary and secondary source data. Note: GETFiT = global energy transfer feed-in tariff. a. Uganda’s main distribution utility is concessioned to a private company, as is the previous state generation utility. Transmission remains public. There are also some small private regional concessions not connected to the main transmission grid. In Nigeria, the distribution companies have been privatized, as have many of the generation companies, but the transmission utility remains publicly owned, albeit under a private management contract. unbundled, it has an independent regulator, and it once had a clear power-­ planning process and a competent procurement capability in the Kenya Power and Lighting Company (KPLC), the T&D company. The regulator has helped move tariffs to cost-reflective levels, and the KPLC has been reasonably cred- itworthy. The consequence is a series of competitive procurements with steadily better price outcomes. Tanzania on the other hand has a weaker investment climate, some ambiva- lence around private sector investment, a vertically integrated state-owned utility with technical and financial performance challenges, and poor planning and procurement practice—despite a regulator that seeks to encourage more trans- parent and competitive procurement. Tanzania has relied more on unsolicited bids and direct negotiations than on competitive tenders. As a result, some IPPs here stand out for their high prices and c­ ontroversial contracts. Uganda’s recent success has relied less on its overall investment climate and more on a clear power sector structure and a recent competitive tendering pro- gram for small renewable energy power plants. With its power sector unbundled, IPPs contract directly with the transmission company, free of conflicts with state- owned generation, and the privately concessioned distribution company is increasingly more effective in reducing losses and improving its financial viability. The dedicated global energy transfer feed-in tariff (GETFiT) intervention analyzed at length in the next chapter) has provided transaction advice and (­ support for running competitive tenders coupled with standardized contracts. ­ It remains to be seen whether this initiative can be sustained in the future. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Factors that Support Independent Power Projects and Their Success 45 Nigeria’s investment climate is challenging; its previous success with IPPs had less to do with a clear policy framework and more with strong political will at the highest levels. A protracted and torturous power sector reform process— including full unbundling, privatization, and, eventually, competition—has, in the short term, probably made it harder to secure investments in new IPPs. It is hoped that, eventually, the reform process will improve the financial viability of the sector, and Nigerian Bulk Electricity Trading (NBET) will become a depend- able and attractive off-taker for IPPs. This analysis of the case study countries reveals no single or consistent ele- ment that guarantees IPP investment. Planning and competitive procurement practices are important; creditworthiness of off-taker utilities is also critical, but policy makers should not lose sight of the broader investment, policy, and regula- tory climate. Notes 1. The one minor exception is the Southern African Power Pool, where nominal cross- border trades are made either through bilateral contracts or through a day-ahead market. Such trades, however, constitute a fraction of the total electricity produced in the region. 2. In Tanzania, however, the goal of full-scale privatization by 2024 exists on paper but may not be possible to achieve in practice. 3. These countries tend to have smaller systems, of 280 MW on average. If the Democratic Republic of Congo is excluded, this average falls to 170 MW. 4. The exceptions are Sudan and Ethiopia, but IPPs will soon be present there, too. 5. Zambia’s national utility, ZESCO Ltd., remains vertically integrated, but a separate and private transmission company, Copperbelt Energy Corporation, is also investing in IPPs. References Eberhard, A., and K. Gratwick. 2011. “IPPs in Sub-Saharan Africa: Determinants of Success.” Energy Policy 39: 5541–49. Eberhard, A., O. Rosnes, M. Shkaratan, and H. Vennemo. 2011. Africa’s Power Infrastructure: Investment, Integration, Efficiency. Washington, DC: World Bank. Gratwick, K., and A. Eberhard. 2008a. “An Analysis of Independent Power Projects in Africa: Understanding Development and Investment Outcomes.” Development Policy Review 26 (3): 309–38. ———. 2008b. “Demise of the Standard Model of Power Sector Reform and the Emergence of Hybrid Power Markets.” Energy Policy 36: 3948–60. IRENA (International Renewable Energy Agency). 2012. “Hydropower.” Renewable Energy Technologies: Cost Analysis Series 1 (3/5). IRENA, Bonn. Jamasb, T. 2002. “Reform and Regulation of the Electricity Sectors in Developing Countries.” DAE Working Paper WP 0226, Department of Applied Economics, University of Cambridge. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 C h apter 4 Independent Power Projects: An Analysis of Types and Outcomes Introduction Previous chapters have indicated the important and growing contribution of independent power projects (IPPs) to Africa’s power generation mix. Again, for the purposes of this study, IPPs are defined as power projects that are, in the main, privately developed, constructed, operated, and owned; have a significant proportion of private finance; and have long-term power purchase agreements (PPAs) with a utility or another off-taker. Within this broad definition there are many variants: IPPs differ in their ownership and financing structures, in technol- ogy choices and risk profiles, in how they are procured and contracted, and in risk mitigation mechanisms. Most IPPs are wholly privately owned, though several involve public coinvestment. Most IPPs are developed within special-purpose vehicles (SPVs) ­ and rely on nonrecourse, project funding. A few are financed off the balance sheets of large corporations. Debt and equity structures differ. The first IPPs in Sub-Saharan Africa were thermal (diesel, heavy fuel oil [HFO], or gas), but some hydroelectric IPPs exist. These are joined, in growing numbers, by new renewable energy technologies such as wind and solar. The ­ various project types have different risk mitigation measures—related, in part, to technology and fuel choices, but also, crucially, to the creditworthiness of off-takers and investors’ assessments of payment risks. IPPs may result from direct negotiations between IPP developers and govern- ments or utility off-takers, or may be procured through international competitive bids (ICBs), with very different investment and price outcomes. This chapter presents an analysis of the different types of IPPs. First, owner- ship and financing structures are discussed, with the role of development finance institutions (DFIs) highlighted; next, the range of risk mitigation measures associ- ated with different IPPs is outlined; then the growth in solar and wind IPPs is noted; and finally the different procurement and contracting mechanisms for IPPs are considered. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   47   48 Independent Power Projects: An Analysis of Types and Outcomes Table 4.1  Independent Power Projects in Five Selected Countries, Sub-Saharan Africa, 1994–2014 Country No. of projects Capacity (GW) Total investment (US$, millions) Kenya 11 1.07 2,328 Nigeria 4 1.52 1,702 South Africa 67 4.31 14,435 Tanzania 4 0.43 598 Uganda 11 0.45 1,274 Total 97 7.77 20,337 Source: Compiled by the authors, based on various primary and secondary source data. Note: GW = gigawatt. A large part of the analysis focuses on assessing and comparing competitively procured versus directly negotiated projects. A lack of competition in the pro- curement and contracting of IPPs is a common feature of African power sectors, and this chapter tries to unpack the reasons behind such a phenomenon, and the associated implications. The analysis in this chapter is based primarily on the in-depth case studies car- ried out in Kenya, Nigeria, South Africa, Tanzania, and Uganda, included as sepa- rate chapters. Altogether, these countries account for 97 out of the 126 existing IPPs, with a cumulative capacity of 7.8 gigawatts (GW) (equal to approximately 70 ­percent of the total IPP capacity) and $20.3 billion of investments (equal to 80 percent of the total IPP investment in Sub-Saharan Africa) (table 4.1). Among the case study countries, South Africa has embarked on the most ambitious renewable energy IPP program, which will soon be followed by thermal IPPs. Nigeria is undergoing the most extensive power sector reforms on ­ the continent. While other countries might not be able to replicate the experi- ences of these two major economies, there are many lessons that can be adapted and applied. Kenya and Tanzania provide a fascinating opportunity to contrast the experiences and outcomes of solicited versus unsolicited bids. Tanzania is also about to start more ambitious reforms and will expand its gas-to-power investments, while Kenya is encouraging a diversified set of power investments, ­ including renewable energy. Uganda has overhauled its electricity supply industry and has numerous small IPPs and the largest hydropower IPP in Sub-​ ­ Saharan Africa. Ownership and Financing Structures There has been a wide variety of African IPP sponsors and debt providers, though a few have backed multiple projects. Table 4.2 highlights specific IPPs from the case study countries (excluding South Africa). While state institutions have invested in some IPPs—for example, the Nigerian National Petroleum Corporation (Okpai and Afam) and the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 49 Table 4.2  Independent Power Project Sponsors and Debt Holders in Case Study Countries (Excluding South Africa), Sub-Saharan Africa Contract change Project Equity partners (country, % of equity held) Procurement Y = yes/N = no Equity turnover (no.)a Kenya Westmont Equity: Westmont (Malaysia, 100%); sought to DN Not extended — sell plant since 2004; ultimately towed back to Malaysia Debt: equity financed Iberafrica Equity: Union Fenosa (Spain, 80%), Kenya Power DN Y 0 Pension Fund (Kenya, 20%) since 1997 Debt: Union Fenosa ($12.7 million in direct loans and guaranteed $20 million); Kenya Power Pension Fund ($9.4 million in direct loans and guaranteed $5 million through local Kenyan bank) OrPower4 Equity: Ormat (USA, 100%) since 1998 ICB Y 0 Debt: equity financed until 2009, European DFIs $105 million loan in 2009, then OPIC loan of $310 million drawn down in 2012–13 Tsavo Equity: Cinergy (USA) and IPS (Int’l) jointly ICB N 1 owned 49.9%; Cinergy sold to Duke Energy (USA) in 2005, CDC/Globeleq (UK, 30%), Wartsila (Finland, 15%), and IFC (Int’l, 5%) retain remaining shares since 2000 Debt: IFC own account ($16.5 million), IFC syndicated ($23.5 million), CDC own account ($13 million), DEG own account (€11 million), DEG syndicated (€2 million) Rabai Equity: Aldwych International (Netherlands, ICB N 0 34.5%), BWSC (Danish, but owned by Mitsui of Japan, 25.5%), FMO (Netherlands, 20%), IFU (Danish bilateral lender, 20%) Debt: FMO ($126 million), Proparco and EAIF (25% each), DEG (15%), European Financing Partners (10%) Mumias Equity: Mumias Sugar Company Limited DN N 0 (100%/Kenya) Debt: not available Thika Equity: Melec PowerGen (part of Matelec ICB N 0 Group) (90%/Lebanon) Debt: AfDB (€28 million), IFC (€28 million), Absa Capital (€28 million) Triumph Equity: Broad Holding (Kenya), Interpel ICB N 0 Investments (Kenya), Tecaflex (Kenya), Southern Inter-trade (Kenya) table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 50 Independent Power Projects: An Analysis of Types and Outcomes Table 4.2  Independent Power Project Sponsors and Debt Holders in Case Study Countries (Excluding South Africa), Sub-Saharan Africa (continued) Contract change Project Equity partners (country, % of equity held) Procurement Y = yes/N = no Equity turnover (no.)a Triumph Debt: Industrial and Commercial Bank of (cont.) China (ICBC) ($80 million), and Kenya’s CFC Stanbic Bank ($28 million) (of which Standard Bank is the parent, in which ICBC has a 20% stake) Gulf Equity: consortium of local investors, namely ICB N 0 Gulf Energy Ltd. and Noora Power Ltd. Debt: $76 million in long-term debt financing (IFC A Loan, and commercial lending through IFC B Loan and OPEC Fund for International Development) Kinangop Equity: Aeolus Kenya, AIIF2, majority owner REFiT N 0 (South Africa/Mauritius), Norfund (Norway) Debt: Kenyan CFC Stanbic project stalled Turkana Equity: KP&P Africa BV (Netherlands) with DN N 0 Aldwych International (Netherlands) Debt (foreign and local): AfDB, EIB, the Standard Bank of South Africa, Nedbank, FMO, Proparco, East African Development Bank (EADB), PTA Bank, EKF, Triodos, and DEG. The project’s debt raising for the generation project was led by the AfDB, as mandated lead arranger, with the Standard Bank of South Africa and Nedbank as coarrangers Nigeria AES Barge Equity: Enron (USA, 100%) sold to AES (95%) DN Y 1 and YFP (Nigeria, 5%) in 2000 Debt: $120 million loan (foreign and local): RMB (South Africa), FMO, African Export- Import Bank, Diamond Bank Nigeria, Fortis Bank, KfW, United Bank for Africa, African Merchant Bank Okpai Equity: Nigerian National Petroleum DN Y 0 Corporation (Nigeria, 60%), Nigerian Agip Oil Company (Italy, 20%), and Phillips Oil Company (USA, 20%) maintained equity since 2001 Debt: 100% equity financed Afam VI Equity: Nigerian National Petroleum DN N 0 Corporation (Nigeria, 55%), Shell (UK/ Netherlands, 30%), Elf (Total) (France, 10%), Agip (Italy, 5%) Debt: 100% equity financed table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 51 Table 4.2  Independent Power Project Sponsors and Debt Holders in Case Study Countries (Excluding South Africa), Sub-Saharan Africa (continued) Contract change Project Equity partners (country, % of equity held) Procurement Y = yes/N = no Equity turnover (no.)a Aba Equity: Geometric DN N 0 Integrated Debt: senior debt: Diamond Bank (Nigeria) and Stanbic IBTC Bank (Nigeria); subordinated debt: EIB and EAIF Tanzania IPTL Equity: Mechmar (Malaysia, 70%), VIP DN Y 1 (Tanzania, 30% in kind); sold to Pan Africa Power Tanzania Ltd. (PAP) in 2013 (disputed) Debt: Bank Bumiputra and Sime Bank (Singapore); Standard Chartered Bank, Hong Kong (SCB-HK) bought debt, valued at $125 million, for $74 million (in 2005) Songas Equity: TransCanada sold majority shares to ICB Y 2 AES (USA) in 1999 and AES sold majority shares to Globeleq (UK) in 2003. All preferred equity shares were converted into “Loan Notes” in June 2009, only common shares remain Debt: IDA ($120 million), EIB ($50 million), assumed loans of $69.2 million from initial TANESCO plant Mtwara Equity: Artumas Group Inc. (Canada, 100%), ICB Y 2 sold shares to Wentworth Group, which in turn sold to TANESCO in 2012 Debt: 100% financed with balance sheet of shareholders Symbion Equity: built by Richmond, sold to Dowans, DN Y 2 then to Symbion Debt: equity financed Ugandab Bujagali Equity: Sithe Global (USA, 58%), IPS-AKFED ICB N 0 (32%), Government of Uganda (10%) Debt: IFC, EIB, Proparco, KfW, AfDB, FMO, DEG, Standard Chartered, Absa Namanve Equity: Jacobsen (Norway, 100%) ICB N 0 Debt: Norwegian commercial bank and local Ugandan bank, and supported by the Norwegian Agency for Development Cooperation (NORAD) Bugoye Equity: TrønderEnergi, Norfund (Norway) DN N 0 Debt: EAIF/FMO table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 52 Independent Power Projects: An Analysis of Types and Outcomes Table 4.2  Independent Power Project Sponsors and Debt Holders in Case Study Countries (Excluding South Africa), Sub-Saharan Africa (continued) Contract change Project Equity partners (country, % of equity held) Procurement Y = yes/N = no Equity turnover (no.)a Mpanga Equity: South Asia Energy Management DN N 0 Systems (SAEMS) (USA, 100%) Debt: EAIF, FMO, DEG Tororo Equity: Electro-Maxx (Uganda, 100%) DN N 0 Debt: funded by local Ugandan banks Ishasha Equity: Eco Power Ltd. (Sri Lanka, 100%) DN N 0 Debt: Sri Lankan commercial banks Buseruka Equity: Hydromax Limited (Uganda, 100%) DN N 0 Debt: African Preferential Trade Area Bank (PTA), AfDB Source: Compiled by the authors, based on various primary and secondary source data. Note: Absa = South African commercial bank; AfDB = African Development Bank; AIIF = African Infrastructure Investment Fund; BWSC = Danish engineering company now owned by Mitsui; CDC = Commonwealth Development Corporation; DEG = German Investment and Development Corporation; DFI = development finance institution; DN = direct negotiation; EAIF = Emerging Africa Infrastructure Fund; EIB = European Investment Bank; EKF = Eksport Kredit Fonden (Danish export credit agency); FMO = Netherlands Development Finance Company; GETFiT = global energy transfer feed-in tariff; ICB = international competitive bid; IDA = International Development Association; IFC = International Finance Corporation; IFU = Danish Investment Fund for Developing Countries; IPS = Industrial Promotion Services; IPS-AKFED = Industrial Promotion Services Aga Khan Fund for Economic Development; IPTL = Independent Power Tanzania Ltd.; KfW = Kreditanstalt für Wiederaufbau; KP&P = company registered in the Netherlands to develop the Lake Turkana Wind Project; KPLC = Kenya Power and Lighting Company; OPEC = Organization of the Petroleum Exporting Countries; OPIC = Overseas Private Investment Corporation; REFiT = renewable energy feed-in tariff; RMB = Rand Merchant Bank; TANESCO = Tanzania Electric Supply Company; YFP = Yinka Folawiyo Power. a. Shareholders—particularly those with technical expertise—are often prohibited (by lenders) from selling until after commercial operation. b. The balance of four Ugandan IPPs (Kilembe Mines aka Mubuku I, Kakira, Kinyara, and Kasese Cobalt aka Mubuku III) not included in the table were developed to source electricity to the mining/sugar industries and have evacuated excess power to the national grid. Also not included are the eight GETFiTs and two solar ICBs for which financial close was imminent but not yet complete as of 3Q2015. government of Uganda (Bujagali), as well as the Kenya Power Pension Fund (Iberafrica)—private sponsors are prominent. Private African partners are present in numerous projects and recently have even taken majority or full equity, as in the case of Aba Integrated (Nigeria), Gulf and Triumph (Kenya), and Tororo and Buseruka (Uganda). Following this, the most conspicuous equity sponsor, Globeleq, hails from Europe, and there are 15 other European entities, such as Aldwych and Wartsila, as well as numerous European bilat- eral DFIs, such as the Norwegian Investment Fund for Developing Countries (Norfund), the Netherlands Development Finance Company (FMO), and the Danish Investment Fund for Developing Countries (IFU). North American sponsors (primarily from the United States) are significantly fewer, at only seven, followed by South Asia (one), Southeast Asia (one), and the Middle East (one). Equity is also held by multilateral agencies, namely, the International Finance Corporation (IFC) and new infrastructure funds: for example, the African Infrastructure Investment Fund (AIIF) managed by a South African life insurer. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 53 The Role of Development Finance Institutions In addition to equity investments, DFIs are prominent in the debt financing of IPPs. Their presence has not waned and, arguably, is as integral now as it was 20 years ago—if not more. The sample in table 4.2 indicates a minimum of 42 debt holders on the part of multilateral and bilateral funding agencies for the 26 projects specified in the case study countries. FMO and the IFC are among the most prominent, joined by the African Development Bank (AfDB), the German Investment and Development Corporation (DEG), the European Investment Bank (EIB), the Overseas Private Investment Corporation (OPIC), and Proparco. One may argue that DFIs possibly crowd out private investment. Indeed, earlier IPPs were predominantly financed by DFIs rather than commercial banks. However, the African reality is one where most IPPs carry substantial risks. Without DFI financing, key projects would not have reached financial close and commercial operation. Nonetheless, African commercial banks are not to be ­ discounted; they took on notable debt in Kenya, Nigeria, South Africa, and Uganda. And recent IPPs, such as Lake Turkana and the Azura IPP, have involved positive cooperation between DFIs and commercial banks. DFIs have also reduced the chances of investments and contracts unraveling—in part because of rigorous due diligence practices, but also because of the pressure governments or multilateral institutions might bring to bear around honoring investment con- tracts. Only eight of the projects listed in table 4.2 have seen substantial contract changes (that is, the parameters of the original deal were renegotiated after the PPA was signed). Such changes vary, from a scaling back of the original project size (Nigeria’s AES Barge) to a reduction in capacity charges (Independent Power Tanzania Ltd. [IPTL], AES Barge, OrPower, Iberafrica, Songas1) to a reconfiguration of the project in its entirety (Mtwara and Symbion2). Further changes have included the rolling back or elimination of certain security arrange- ments (for example, Songas’s escrow fund) to reduce the financial liability of the state-owned utility. It should be noted that changes occurred in what might be termed the first wave of IPPs in Sub-Saharan Africa—which might signal that there has been a learning process of sorts. DFIs also contribute to the long-term sustainability of IPP investments, by offering guarantees and insurance (described in the next section). It is of interest that the majority (some two-thirds) of World Bank Group (WBG) guarantees have been provided to projects that were competitively bid. The relative pros and cons of international competitive tenders versus unsolicited bids are dis- cussed in the last section of this chapter. Risk and Ways to Mitigate It Owing to the difficult investment environment typical of Sub-Saharan African countries, a key requirement to attract private investment to the power sector is the availability of risk mitigation instruments. Most Sub-Saharan African Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 54 Independent Power Projects: An Analysis of Types and Outcomes countries are either unrated or have a credit rating below investment grade; their track record of implementing projects with private sector investors is limited or nonexistent, and their power sectors are in most cases evolving (that is, at an early stage of development or undergoing a reform process). From the perspec- tive of private investors and financiers, these circumstances create uncertainty regarding the future stability of any investment. Such uncertainty translates into high-risk perceptions and high costs of financing—or an inability to raise financ- ing altogether. The following section explores the types of risks that can affect IPPs, especially in Sub-Saharan Africa, and the menu of risk mitigation measures and their effectiveness. Risks Associated with Investments in Independent Power Projects Some types of risk are customary for IPPs, regardless of location, such as contrac- tual risk, construction risk, natural force majeure, and so on. These are cov- ered or mitigated through structural arrangements typical of project financing (for example, reserve accounts, liquidated damages) or through comprehensive ­ commercial insurance packages appropriate for the industry. When investing in Africa, IPPs are faced with an additional set of risks that must be mitigated to make the investment sufficiently attractive or, in some instances, viable. These risks can be classified in the following categories: • Political risk refers to events resulting from adverse actions by the host govern- ment (for example, expropriation, repudiation of contract, arbitrary cancella- tion of permits or licenses, restrictions on the conversion and/or transfer of currencies, and so on) or from politically motivated violence (war, civil strife, coups, terrorism) that can disrupt the construction or the operation of a project, whether temporarily or permanently. ­ • Regulatory risk refers to any change in law or regulation that may have a nega- tive impact on a project, including changes that apply specifically to a project (for example, a change in the tariff agreed by contract) or to the sector in general (for example, structural policy changes). Regulatory risk is perceived as particularly high in countries where the regulatory framework is still evolving, and where there are relatively few precedents for how the legal system handles conflicts resulting from changes in laws. • Credit/payment risk refers to the credit quality and the payment capacity project of the off-taker. From an investor’s perspective, the profitability of a ­ hangs upon the ability to collect revenues from the off-taker. As previously alluded to, the low creditworthiness of off-takers is the key challenge to IPP investments in Sub-Saharan Africa. Here, the typical utility’s limited financial capacity, substantial financial obligation, and fairly limited commercial flexibility (a limited customer base and highly regulated activ- ­ ities) all pose credit/payment risks that can make or break a project. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 55 Mitigating these risks is therefore critical to make a project bankable and to guarantee fair and sustained returns to investors once the project is under implementation. A Menu of Risk Mitigation Measures There are various measures that can be taken to mitigate the risks. Each country’s context poses different challenges—as revealed by assessing the experience of previous IPPs—and requires well-tailored solutions. A review of various measures is presented below. International Arbitration In the case of large-size projects where the public sector plays a counterpart role, private investors routinely require international arbitration to resolve disputes. In particular, clauses regarding arbitration in instances of a “change in law” or in sec- tor regulations are commonly embedded into PPAs. Involvement of Development Finance Institutions When considering an investment in a new country, private sector investors often reach out to the DFI community to seek financing and other types of support for IPPs. This is because, as discussed earlier in this chapter, the DFIs’ beneficial role spans well beyond providing financing. Their involvement serves to mitigate risk, especially political risk. DFIs can dissuade governments from making ­ill-considered changes and point out the potential consequences and spillover effects of the withdrawal of development assistance and finance, especially on the part of large multilateral agencies. The degree of DFI involvement varies across countries and regions. Some DFIs such as the IFC and AfDB are present basically everywhere in Sub-Saharan Africa. Others are focused in particular regions (such as the West African Development Bank and the Islamic Development Bank in West Africa) or in countries with whom they have traditionally close ties (such as Proparco in francophone Africa). Sovereign Guarantees Sovereign guarantees are the most common instrument to mitigate off-taker risks where off-takers are not creditworthy or not perceived as such. This is the case when their financial standing is weak or they rely heavily on government subsidies, or in contexts where there is no long or solid track record of private sector investment in the power sector. In these circumstances, the private sec- tor may ask the government to back the off-taker’s obligations under the PPA. As countries build a track record of successful IPPs, they can slowly reduce the issuance of these guarantees or limit them only to cover specific risks (as opposed to covering the full PPA). Structural Measures Structural measures can be designed to ring-fence revenues accruing to off-taker utilities and ensure that there is enough cash flow to honor payment obligations Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 56 Independent Power Projects: An Analysis of Types and Outcomes under the PPA. In Côte d’Ivoire, for example, a sectorwide mechanism has been put in place to collect all power sector revenues, which are then allocated on a priority basis to cover IPP payments. This measure has worked very well in the country and has allowed it to successfully develop some of the largest IPPs in Sub-Saharan Africa (Azito and CIPREL). A similar, smaller-scale option consists of transferring the bill collection for a set of large customers from the utility to an escrow account managed by the IPP. These “delegated customers” typically represent a profitable customer segment, ensuring a stable stream of revenues to the utility. The problem with this arrange- ment is the lack of replicability: once the best customers are delegated to the first IPP, it becomes difficult to identify enough customers suitable for delegation to any IPPs that follow. A sectorwide cash flow channel, meanwhile, is an arrange- ment that can accommodate future projects. Although host governments can provide sovereign guarantees or arrange any of the risk mitigation measures presented earlier, their financial capability to deliver on IPP commitments may remain in doubt, or the legal underpinning of such commitments may be uncertain. In this context, equity investors and financiers must put in place further risk mitigation instruments that transfer risks to third parties. The most commonly used instruments are (1) multilateral development bank (MDB) guarantees and (2) insurance products, in particular ­ political risk insurance (PRI). While most MDBs offer guarantees, the guarantees provided by the World Bank—specifically the International Bank for Reconstruction and Development (IBRD) and the International Development Association (IDA)—have been the most widely used in the Sub-Saharan African region. World Bank Guarantees World Bank guarantees are designed to provide credit enhancement and direct risk mitigation. They are flexible in nature and adaptable to the specific require- ments of each project and to market circumstances. Customarily, the World Bank guarantees are issued for the benefit of private investors (project companies or lenders) to guarantee timely payment of obligations due by government-owned entities under key project contracts, such as payments due under PPAs signed by government-owned utilities with privately owned project companies. World Bank guarantees are of two main types: (1) project based and (2) policy based. Project-based guarantees are applied in the context of specific investment projects where governments wish to attract equity and/or debt by the private ­ sector. They are the instruments best suited and typically used to support IPPs in Sub-Saharan Africa. Project-based guarantees (formerly called partial risk guarantees, PRGs) include the following subcategories: • Loan guarantees mitigate the risks faced by commercial lenders with respect to debt service payment defaults caused directly or indirectly by a government Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 57 failure to meet specific payment and/or performance obligations arising from contracts, laws, or regulations. Debt service payment defaults may relate to: –– Commercial loans taken by private projects, which rely on contracts with the government for their cash flows and may be affected by certain factors such as a change in tariff levels named in an implementation agreement between the government and a project. –– Commercial loans taken directly by the government. • Payment guarantees are intended to mitigate the risk faced by private projects or foreign public entities with respect to payment default on government obligations not related to loans. Such obligations include scheduled or unscheduled predetermined payments arising from contracts, laws, or regula- tions (for example, monthly payments under a PPA); and termination payments due under a government support agreement (GSA) as a result of a ­ change in law. A notable and recent example of the suite of risk mitigation instruments offered by the World Bank is provided by the Azura project in Nigeria (see box 4.1). Box 4.1  Mitigating the Risk of an Independent Power Project: The Case of Azura, Nigeria Azura, which reached financial close in 2015 after considerable delays, has been a ­ path-​ breaking independent power project (IPP) in Nigeria: it is the first project-financed power ­ generation project to have been developed since that country’s power sector reforms began. ­ Investment costs—at $895 million for a 450 megawatt (MW) open-cycle gas turbine (OCGT)— are high and reflect perceptions of risk. The counterparty of the power purchase agreement (PPA) is a newly created Nigerian Bulk Electricity Trading (NBET), with insufficient liquidity and dependent on revenue flows from newly privatized distribution companies that are still expe- riencing high losses and insufficient collections. Development costs have been high. Each con- tract has had to be negotiated from scratch. Because Azura was the first IPP to be established in Nigeria for several years, there were no ready-made templates for it to follow, and capacity had to be built among the various stakeholders. The project sponsor is a relatively small, cash- poor, ­ first-generation developer that had to leverage equity partners and a large number of debt providers, each of which wanted to limit its exposure. The International Finance Corporation (IFC) was a colead arranger of the development finance institution (DFI) compo- nent of the debt, and the World Bank employed its full range of risk mitigation instruments to make the project bankable. The Multilateral Investment Guarantee Agency (MIGA) provided a full equity guarantee as well as a partial risk debt guarantee. The International Bank for Reconstruction and Development (IBRD) provided for project-based guarantees (formerly partial risk guarantees, PRGs), including both payment and loan guarantees. (The payment guarantee backstops box continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 58 Independent Power Projects: An Analysis of Types and Outcomes Box 4.1  Mitigating the Risk of an Independent Power Project: The Case of Azura, Nigeria (continued) payment obligations by the NBET.) Specifically, the guarantee ensures security under the PPA in the form of a letter of credit (LC) issued by a commercial bank in favor of the IPP. The LC can be drawn in the event the NBET or the government of Nigeria fails to make timely payments to the IPP. Following the drawing up of the LC, the NBET would be obligated to make a repayment to the LC bank (under the reimbursement and credit agreement), failing which the LC bank would have recourse to the IBRD PRG under the guarantee agreement, which in turn would trigger the obligation of the federal government of Nigeria under the indemnity agreement. The loan guarantee provides direct support to commercial lenders in the event of a debt payment default caused by the NBET’s failure to make undisputed payments under the PPA, or the government of Nigeria under a termination of the PPA. There is also an LC for gas supply. Given the complexity and cost of the Azura deal, questions have been asked as to whether project-financed IPPs are worthwhile in risky environments. The counterargument is that Azura has shown the way and that subsequent IPPs will be much easier. In a sense, the devel- opment and risk mitigation costs of Azura could be seen to be spread across a large pool of IPPs currently under development. More important, as the power market evolves and more private investments flow into it, future IPPs are expected to be less costly to develop and to require less risk mitigation. Source: Compiled by the authors, based on various primary and secondary source data. African Development Bank Guarantees The AfDB also offers guarantee instruments. These were introduced in 2004 for middle-income countries, and later (in 2011) extended to low-income countries. AfDB guarantees are of two kinds: (1) partial credit guarantees (PCGs) and (2) partial risk guarantees (PRGs). PCGs cover a portion of scheduled repayments of private loans or bonds against all risks. Their application spans project finance (including IPPs), financial intermediation, and policy-based finance. Specifically, project finance PCGs are normally used to help extend loan/bond maturity and ease access to capital mar- kets for public and private investments alike. They can be applied to cover the principle for the bullet maturity of corporate bonds, or, later, the maturity prin- ciple payments of amortizing syndicated loans. PRGs insulate private lenders against well-defined political risks related to the failure of a government or a government-related entity to honor specified com- mitments. Such risks could include political force majeure, currency inconvert- ibility, regulatory risks (adverse changes in law), and various forms of breach of contract. Insurance Products Insurance products may be provided by multilateral and bilateral agencies, export credit agencies, or private insurers. The providers most common in Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 59 Sub-Saharan Africa are the Multilateral Investment Guarantee Agency (MIGA), the OPIC, and the African Trade Insurance Agency (ATI). Political risk insurance (PRI) typically provides insurance to private equity investors and/or to lenders against traditional political risks (as specified in the coverage), resulting in a default by a sovereign or a corporate entity to honor its obligations. Guarantees and insurance are complementary products. As such, it is not uncommon for a project to benefit from both instruments, a practice that is favored in large and complex projects. The Impact of Risk Mitigation How does risk mitigation intersect with projects’ bankability and sustainability? To what extent have the instruments described been effective in attracting lenders? And to what degree have such mechanisms helped keep projects intact ­ or led to a swift resolution, in the face of external pressures? The Sub-Saharan African experience clearly points to the fact that risk mitiga- tion has been critical in attracting private investments to strategic IPPs located in challenging markets. A few notable examples follow. Kribi Gas Power Project, Cameroon Developed by the Kribi Power Development Company (KPDC), this project con- sists of a new 216 megawatt (MW) natural-gas-fired power plant and an associated 100-kilometer (km) transmission line. The total project cost was $350 million, financed with a 75:25 debt-to-equity ratio. One of the major challenges was to secure long-term loans in the local currency. Until 2011, most of the infrastructure financing in Cameroon was done on a corporate basis through equity and foreign- currency-denominated loans from DFIs. The only exception was the Dibamba thermal power plant, which was financed on a project finance basis with private equity and loans from DFIs denominated in foreign currency. Local and interna- tional commercial banks provided only short-term corporate financing. The government of Cameroon wanted local banks to participate in the financ- ing of Kribi. Its objective was twofold: (1) to introduce a local-currency component into the financing package to mitigate foreign-exchange risk (which ­ is passed through to the tariff), and (2) to develop the capacity of the local lend- ing market in long-term project finance. While local lenders had liquidity and strong interest in participating in the financing of private projects, they suffered from structural and regulatory con- straints that limited maximum maturities of the loan to seven years—insufficient for long-term infrastructure financing needs. Moreover, the fact that the govern- ment and associated entities lacked a track record in private project financing left local lenders with a high degree of uncertainty (that is, perceived risk). Thus, the challenge was to create a financial structure that might attract local lenders with relatively little experience in project finance, and overcome the regulatory restrictions on the tenor of local lending. As a response to these constraints, the government, local banks, and the IDA joined efforts to design a local loan with an innovative structure. The seven-year Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 60 Independent Power Projects: An Analysis of Types and Outcomes maturity constraint was turned into a 14-year amortization profile through a “put option” in favor of the local lenders under which, at the end of seven years, local lenders might exercise the option and sell their participation to the government at a price defined in the local loan purchase agreement. In this case, the government would hold the local loan until the KPDC or the government itself found new commercial lenders to take it up. If local lenders did not exercise their put option, the loan would be extended for a second seven-year term. The government’s obli- gation to purchase it was secured by an $82 million World Bank guarantee. Kribi’s financing structure provided a novel way of addressing problems com- mon to large infrastructure projects in low-income countries: currency mismatch, short loan tenor, regulatory constraints, and government creditworthiness. The World Bank’s involvement enabled Cameroon’s first long-term, ­ local-currency loan for infrastructure and thus contributed to building capacity within local banks and bolstering the development of both the financial and infrastructure sectors. In addi- tion, the local component of the financing package reduced ­ foreign-exchange risks. Recent Thermal Independent Power Projects, Kenya In 2011, three IPPs—namely, Thika Power Ltd. (87 MW), Triumph Power Ltd. (82 MW), and Gulf Power Ltd. (80 MW)—were identified as strategic to meet- ing Kenya’s urgent power generation needs. The Kenya Power and Lighting Company (KPLC), Kenya’s government-owned utility, selected private sponsors through a competitive tender process and signed 20-year PPAs with each of the three IPPs. However, these projects were tendered at a time when financial mar- kets were still suffering the impact of the 2008 global financial crisis and project financiers remained risk averse. Moreover, the financial situation of the KPLC started deteriorating, driven in part by an ambitious network expansion plan. To make things worse, Kenya’s political stability was perceived as fragile after the civil unrest that followed the 2007 presidential elections, and there were con- cerns over the upcoming 2013 presidential elections. During the project tender process, it became clear to the KPLC that it would not be able to attract investors unless it offered significant credit enhancement such as sovereign guarantees. The government of Kenya, however, was con- strained in its ability to provide sovereign guarantees due to its limited fiscal space and a tight debt ceiling agreed on with the International Monetary Fund (IMF). The KPLC, in turn, found it difficult to continue offering the security packages that it had provided under the PPAs with previous IPPs. Those security packages had become financially onerous as they required full cash collateral, thus impacting the KPLC’s ability to direct resources for its operating needs and its investment program. As a response, the Kenyan government, the KPLC, and the World Bank opted for exploring credit-enhancement options that might encourage the required private financing, while minimizing the contingent liabilities for the government and the financial cost for the KPLC. After a market-sounding exercise, a credit-enhancement package consisting of IDA guarantees (to back- stop ongoing payment obligations of the KPLC under the PPAs) and MIGA Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 61 insurance (to cover termination payments) was put together for these projects. In addition, the IFC provided support through long-term debt financing for two of the IPPs. The IDA guarantees were structured around two goals. First, to ensure timely payments of energy, capacity, and fuel charges and assure investors that the proj- ects’ cash flow would be protected against any payment default by the KPLC or government interference. Second, to ensure that in the event of a KPLC payment default, remedial actions would be taken during a 12-month period so that the liquidity protection could be reinstated and remain in place for 15 years, which was the tenor of the underlying financing. Both goals were accomplished with the use of standby letters of credit (SBLCs) backstopped by IDA guarantees. Commercial banks issued the SBLCs to project companies on behalf of the KPLC as a payment security for ongoing KPLC payment obligations under the PPAs. The SBLCs allowed project companies to withdraw funds in the event that the KPLC failed to make a timely payment under the PPAs. In that case, the KPLC or the gov- ernment was obliged to repay to the SBLC bank the amount drawn within 12 months. If it failed to do so, the World Bank would pay under the IDA guarantee. The MIGA provided insurance to equity investors and commercial lenders to cover the termination payment obligations of the KPLC (as a result of a breach of contract, as stipulated under the PPA) and the government (as a result of breach of contract, under the government letter of support). The MIGA insur- ance also covered transfer restrictions. The WBG’s support ensured the mobilization of private financing for needed additional generation capacity that otherwise would not have been achieved. The crucial value of the IDA guarantee was to enable the bankability of the IPPs. All three IPPs attracted long-term commercial financing, becoming the first proj- ects to do so in Kenya. The IFC and other DFIs played a critical role in providing debt financing. These IPPs have become benchmarks for long-term financing in Kenya—and Africa. Tobene Power Project, Senegal This is a 96 MW power plant developed by Tobene Power SA, whose main shareholder is the Matelec Group of Lebanon. The total project cost was a127 million, financed on a 75:25 debt-to-equity basis. Tobene is currently under construction; once completed it will deliver power to SENELEC, the national utility and single off-taker, under a 20-year PPA. As a reaction to the nation’s power crisis, in 2010 the government of Senegal carried out a sector diagnostic that highlighted an increasing gap between fast- growing demand and insufficient, costly, and unreliable supply of electricity. The diagnostic also underscored SENELEC’s persistent financial difficulties, charac- terized by a significant operating deficit and high indebtedness. In response, the government developed a 2011–15 electricity emergency plan, outlining an over- all policy framework and strategy to put the sector on a more sustainable footing Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 62 Independent Power Projects: An Analysis of Types and Outcomes and build SENELEC’s financial and operational sustainability over the long run. The Tobene Power Project was identified as a key IPP under the plan. Although Senegal was among the first countries in Sub-Saharan Africa to introduce private participation in the power sector, in the late 1990s, the track record of its IPPs was mixed. This is mainly a consequence of SENELEC’s poor payment track record, as well as a number of technical issues that reduced electricity output from these plants, including the variable quality of fuel deliv- ­ ered by SAR (a state-owned refinery) and grid instability. Therefore, investors were reluctant to proceed with developing Tobene unless risk mitigation was provided. As a response, the government of Senegal, together with the World Bank, agreed to offer an IDA guarantee backstopping the payment obligations of SENELEC and the government, under the PPA and under the government guarantee, respectively. The IDA guarantee of $40 million covers ongoing pay- ­ ment obligations as well as a portion of termination payments resulting from a breach of contract by the government or SENELEC. In addition to the IDA guarantee, the project also benefited from long-term debt financing and an equity contribution through the IFC and IFC InfraVentures. The remainder of the debt financing was provided by other DFIs, such as FMO, the Emerging Africa Infrastructure Fund (EAIF), and the West African Development Bank (BOAD). The IDA guarantee was considered key to attracting private capital for Tobene as well as long-term debt financing, which would have not been available otherwise. Commissioning of Tobene is expected in 2016. Once in place, the project will make a critical contribution to reducing power shortages and diversifying the energy mix away from expensive emergency diesel generation. ­ It is also a hallmark of the government’s interest in increasing private sector participation. Going forward, risk mitigation promises to remain critical in attracting private financing to projects. The question of off-takers’ creditworthiness alone offers justification for resorting to security arrangements and credit enhancements, whether the risk is real or only perceived by prospective investors. For instance, in Kenya, despite the sheer number of IPPs and the proven track record of pay- ment via the KPLC, investors still claim that the KPLC “is not an investment grade company” (Aldwych International, personal communication with authors, 2010). Contrast this situation with that of other middle-income countries, such as those in Latin America, where the PRG and other credit enhancements and security arrangements are virtually absent. There, power markets are in ­ operation, including long-term bilateral contracts, and local lenders are generally comfort- able with local developers and regulation. Nevertheless, as IPP markets mature in Sub-Saharan Africa, it is possible that the use of risk mitigation arrangements will diminish. In Nigeria, for example, the IPPs that follow Azura are unlikely to utilize as wide an array of ­ credit-enhancement instruments. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 63 As risks are reduced, greater private investment should be encouraged, and DFIs should focus on projects that commercial banks cannot finance. Finally, it is important to note that in no projects have guarantees of any sort been invoked, including in those projects whose contracts ultimately unraveled (namely, AES Barge, IPTL, OrPower4, or Takoradi II). Recourse to international arbitration has been made only in the case of IPTL in Tanzania, where it shaved $30 million off the investment cost. Technology Options: A Rise in Independent Power Projects Using Solar and Wind Energy The past decade has witnessed a revolution in renewable energy technologies such as wind and solar energy. They have grown especially in the past five years, with costs falling and efficiencies improving remarkably. The levelized cost of onshore wind per megawatt-hour has now reached a level that is competitive with combined-cycle gas turbine (CCGT) and coal-fired generation, without taking into ­ account the environmental and social costs of carbon. While not yet as competitive as wind, solar photovoltaic (PV) has seen among the greatest cost reductions. Geothermal energy has also proved to be cost competitive. Renewable power capacity, excluding large hydropower, represented 44 ­ percent of all new global capacity in 2013, amounting to $192 billion in investment (FS-UNEP 2014). A similar trend has not, however, been observed in fuel-to-power plants, although there are notable developments in the gas sector, with implications for natural-gas-fired plants. This has serious ramifications for power development in Sub-Saharan Africa and particularly for IPPs: with falling costs, grid-connected renewable energy (particularly solar and wind) is gaining traction and represents significant new investment. Wind and Solar Energy Price Trends in Sub-Saharan Africa How do wind and solar energy IPPs score in the five case study countries and, by contrast, how do fuel-to-power IPPs measure up in terms of actual price outcomes?3 The most dramatic outcomes of wind and solar energy IPPs have been in South Africa’s Renewable Energy Independent Power Project Procurement Programme (REIPPPP), discussed in more detail later in this chapter, where between 2012 and 2015, 92 new projects were contracted, amounting to 6,327 MW of capacity (including small quantities of hydropower, biomass, and biogas) and more than $19 billion in private investment, with impressive price outcomes. Grid-connected wind and solar renewable energy in South Africa is now among the cheapest in the world: solar PV prices are as low as U.S. cents (USc) 6.4/kilowatt-hour (kWh) and wind as low as USc 4.7/kWh.4 These out- comes will not, however, be easy to replicate in other African countries, which have smaller markets with less competition; more risky investment climates; thinner domestic capital markets; and less-experienced local financial, legal, and advisory service industries. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 64 Independent Power Projects: An Analysis of Types and Outcomes Two solar projects have been developed in Uganda under the global energy transfer feed-in tariff (GETFiT) program (presented in detail later in this chapter) with less impressive results (USc 16.4/kWh), due to a much smaller ­ market size, less competition, and more broadly, a higher-risk environment. Nonetheless, the technology is gaining ground and is still cheaper than the imported fuel-to-power alternative in Uganda. The directly negotiated solar PV deals in Rwanda and Nigeria—at over USc 20/kWh—are more expensive than the competitively bid projects. Outside South Africa, the wind story has been focused on Kenya: first in its directly negotiated Lake Turkana 300 MW project, and then in the more recent renewable energy feed-in tariff (REFiT)–procured Kinangop IPP (60 MW), at USc 10.39/kWh5 and USc 12/kWh,6 respectively, which are marginally more expensive than Kenya’s private geothermal capacity but outdo any of the country’s existing thermal plants, as previously noted. IPP wind developments ­ have also taken shape in Cabo Verde, through a 25 MW installation that has helped offset high-price thermal imports. Outcomes of other renewable energy IPPs are presented in box 4.2. Sub-Saharan African Experience with Feed-in Tariffs As frontier technologies, solar and wind-based generation entails higher up-front costs and different risk profiles than traditional, and especially thermal, technolo- gies. Countries interested in these and other renewables have experimented with methods to incentivize private investment in them. Until recently, the most widely adopted procurement strategy for attracting renewable energy IPPs involved feed-in tariffs (FiTs) (at least in terms of policy and regulations). Six Sub-Saharan African countries have FiTs for small hydropower, solar, wind, geothermal, and biomass/waste (table 4.3). FiTs have primarily been promoted by European bilateral aid programs, ­ premised on the assumption that renewable energy costs are higher than those of other options, and renewable energy projects need premiums to attract invest- ment (Davies and Allen 2014). Meanwhile, FiTs are beginning to face criticism in their markets of origin because prices have not come down as fast as competi- tive tenders. In Africa, the experience with this instrument has been disappointing, and relatively few projects have materialized. In Kenya, specific interventions to accelerate renewables with a FiT policy date to 2008. The first iteration of this policy did not attract investors, and tariffs were subsequently reviewed in January 2010 and decreased (BNEF and others 2014). In Uganda, FiTs have been retooled and have finally taken off under the GETFiT program, as described below. The two-year South African experiment with FiTs, which was terminated with no contracts signed, is highlighted in box 4.3. Uganda GETFiT Tender Design REFiTs in Uganda did not manage to attract any renewable energy invest- ments before 2013. In 2013, the Kreditanstalt für Wiederaufbau (KfW, German Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 65 Box 4.2  Independent Power Projects Using Hydropower, Geothermal, and Biomass Large hydropower independent power projects (IPPs) have emerged, albeit only in the form of Bujagali in Uganda (250 megawatts, MW) and, more recently, Itezhi in Zambia (120 MW). Bujagali, at U.S. cents (USc) 10/kilowatt-hour (kWh), has helped offset higher-price thermal installations (USc 24–27/kWh), and contributed 45 percent of total generation in 2013. This technology is now largely being developed in the form of publicly owned projects with Chinese-backed funding, and with Chinese engineering, procurement, and construction (EPC), which have distinguished themselves as market leaders worldwide. This follows global trends: 14 of the 19 projects with the greatest hydropower capacity worldwide are wholly state owned (FS-UNEP 2014: 41). In contrast, small hydropower IPPs (<20 MW) have seen an upsurge in activity, particu- larly in Uganda. Each of the small hydropower IPPs (at around USc 9/kWh) are superior price - wise to the thermal alternative (heavy fuel oil, HFO), which relies on imported fuel. Prior to the global energy transfer feed-in tariff (GETFiT) program, Uganda had procured six small hydropower IPPs; GETFiT, with an initially anticipated close of more projects in 2015, pushes that tally closer to 14. On the geothermal front, private investments in Kenya date to 1999, when OrPower won the first tender. At USc 9/kWh, the IPP geothermal plant is slightly more expensive than state- run geothermal plants (USc 7/kWh) and superior to all fuel-to-power alternatives available in the country (in the range of USc 20–33/kWh). Geothermal is expanding rapidly in Kenya, both via public and private procurement. Biomass IPPs are well established in Mauritius, which has a fleet of bagasse cogeneration plants that collectively account for 110 MW of installed capacity, dating from 1997. South Africa, Kenya, Uganda, and, most recently, Angola, have also added bagasse to their electric power supply; Kenya’s Mumias IPP plant, at USc 5/kWh, is more competitive than geothermal and is outcompeting any fuel-to-power alternative, as noted. Source: Compiled by the authors, based on various primary and secondary source data. development bank) assisted the Uganda regulator, the Electricity Regulatory Authority (ERA), in developing the GETFiT to incentivize new investments that might plug the difference between supply and demand before two large new hydropower projects, Isimba and Karuma, came online. The primary GETFiT mechanism is a grant-based premium payment at the REFiT levels to close the gap with the levelized cost of energy (LCOE) for eligible technologies, namely small hydropower, biomass, bagasse, and solar PV. The per-kilowatt-hour-based GETFiT subsidy is calculated over the 20-year lifetime of ­ the PPA, but is designed as a performance-based payment to the developer over the first five years of operation to enhance the project’s debt service profile. An important and valuable part of the program has been the development of a full set of legal documents including standardized (and investor-approved) Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 66 Independent Power Projects: An Analysis of Types and Outcomes Table 4.3  Sub-Saharan African Countries with Feed-in Tariffs, Grid-Connected, as of 2014 USc/kilowatt-hour Country Small hydro FiT Solar FiT Wind FiT Geothermal FiT Biomass FiT Biogas FiT Ghana 17.74a 21.21b 18.35c — — 10.36 Kenya 8.25 12 11 8.8 10 10 Nigeria 17.33d 49.92 18.07 — 20.19 — Rwanda 6.7–16.6 — — — — — South Africa (2011) 8.4 29 11.8 — 13.3 10.5 Uganda 8.5e 11 12.4 7.7 10.3 11.5 Sources: Based on BNEF and others 2014; NERSA 2011. South African FiTs are no longer applicable. Note: FiT = feed-in tariff; kWh = kilowatt-hour; MYTO-2 = Multi-Year Tariff Order 2; USc = U.S. cent; — = not available. a. Ghanaian small hydropower, assuming average 2014 exchange rate of $1= Ghanaian cedi 3.0367. All tariff rates are as of October 1, 2014 (BNEF and others 2014). b. Ghanaian solar photovoltaic (PV) with grid stability; solar PV without grid stability is USc 19.21 (BNEF and others 2014). c. With grid stability system; wind without grid stability indicated at USc 16.93 (BNEF and others 2014). d. Based on MYTO-2 2014 FiT prices. e. Maximum tariffs available at auctions for hydro, bagasse (USc 9.5/kWh), biomass, biogas, geothermal, landfill (USc 8.9/kWh), and wind (solar is under a separate regime). Box 4.3  The South African Experiment with Renewable Energy Feed-in Tariffs In South Africa, a renewable energy feed-in tariff (REFiT) policy was approved in 2009 by the National Energy Regulator of South Africa (NERSA). Tariffs were designed to cover generation costs plus a real after-tax return on equity of 17  percent, to be fully indexed for inflation (NERSA 2009). Initial published feed-in tariffs (FiTs) were generally regarded as generous by developers—U.S. cents (USc) 15.6 per kilowatt-hour (kWh) for wind, USc 26/kWh for concen- trated solar power (CSP, troughs with 6 hours’ storage), and USc 49/kWh for photovoltaic (PV).a But the procurement and licensing process remained uncertain. The legality of FiTs within South Africa’s public procurement framework was unclear, as was Eskom’s (the national electricity utility) intention to fully support the REFiT program by allowing the timely finaliza- tion of power purchase agreements (PPAs) and interconnection agreements. In March 2011, the NERSA introduced a new level of uncertainty with a surprise release of a consultation paper calling for lower FiTs, arguing that a number of parameters—such as exchange rates and the cost of debt—had changed. The new tariffs were 25 percent lower for wind, 13 percent lower for CSP, and 41 percent lower for PV. Moreover, the capital component of the tariffs would no longer be fully indexed for inflation. Importantly, in its revised financial assumptions, the NERSA did not change the required real return for equity investors, set at 17 percent (NERSA 2011). More policy and regulatory uncertainty was to come. Already concerned that the NERSA’s FiTs were still too high, the Department of Energy (DoE) and National Treasury commissioned a legal opinion that concluded that FiTs amounted to noncompetitive procurement and were therefore prohibited by the government’s public finance and procurement regulations. The DoE and National Treasury then took the lead in a reconsideration of the government’s approach. The fundamental goal of achieving large-scale renewable energy projects with pri- vate developers and financiers remained the same. However, the structure of the transactions, box continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 67 Box 4.3  The South African Experiment with Renewable Energy Feed-in Tariffs (continued) including the FiTs, was to change significantly. A series of informal consultations were held with developers, lawyers, and financial institutions throughout the first half of 2011. These meetings proved to be extremely important in allaying market concerns resulting from the earlier REFiT process and providing informal feedback from the private sector on design, legal, and technology issues. In August 2011, the DoE announced that a competitive bidding process for renew- able  energy would be launched (the Renewable Energy Independent Power Project Procurement Programme, REIPPPP). Subsequently, the NERSA officially terminated the REFiTs. Not a single megawatt of power had been signed in the two years since the launch of the REFiT program; a practical procurement process was never implemented, and the required contracts were never negotiated or signed. The abandonment of FiTs, ­ meanwhile, was met with dismay by a number of renewable energy project developers that had secured sites and initiated resource measurements and environmental impact assess- ments. But, it was these early developers who would later benefit from the first round of competitive bidding under the REIPPPP. Source: Compiled by the authors, based on various primary and secondary source data. a. These values are calculated at the exchange rate of the time, R (rand) 8 = $1. PPAs, implementation agreements, and direct agreements (securing lender takeover rights). World Bank PRGs are available to successful projects to address off-taker and termination risks. Support is also provided for lender due diligence. Furthermore, GETFiT assists the government of Uganda in further streamlining essential procedures for project implementation, such as the permit and licensing process as well as the operationalization of tax and custom ­ exemptions provided to IPPs. Three competitive tenders were run for small hydropower and biomass (1–20 MW), based on the quality rather than the price of projects. Projects had to meet minimum qualitative benchmarks (table 4.4). Prices were determined by the REFiT plus the premium payment. Project developers proposed their own sites and had to undertake full feasibility and interconnection studies; they had to secure permits and prepare environmental and social impact assessments (ESIAs) in compliance with the IFC’s performance standards, including a Resettlement Action Plan (RAP), wherever applicable. An additional competi- tive tender was run for solar PV projects with a maximum size of 5 MW. The GETFiT facility also funded a secretariat, supported by an implementa- tion consultant, which ran the tenders and assessed bids, with ultimate approval from an investment committee. By early 2015, GETFiT had confirmed support for a total of 15 projects with an accumulated 128 MW capacity. Forty-one applications were received over three bid rounds.7 In January 2015, the third and last request for proposals under the “classic” GETFiT setup was issued. When the GETFiT Investment Committee was convened for the last time in June 2015, a further six projects were approved. But amid funding constraints, Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 68 Independent Power Projects: An Analysis of Types and Outcomes Table 4.4  Criteria for the Evaluation of Global Energy Transfer Feed-in Tariffs, Uganda “Classic” GETFiT (small hydro, biomass, bagasse) GETFiT solar facility Financial and economic performance Economic performance Minimum FIRR, DSCR, sensitivity ERR DPC, ERR, contribution to energy balance Project maturity and location and grid stability Environmental and social performance Environmental and social performance Quality and IFC compliance of ESIA/ESAP Quality and IFC compliance RAP/LRF Technical and organizational performance Technical and organizational performance Feasibility of proposed site Quality of technical documentation Quality of technical documentation Project implementation timeline/expected COD Project implementation timeline Price proposed per kilowatt-hour (70% of total score) Maturity of project and financial package Risk analysis Source: Compiled by the authors, based on various primary and secondary source data. Note: COD = commercial operation date; DPC = dynamic production cost; DSCR = debt service coverage ratio; ERR = economic rate of return; ESAP = environmental and social action plan; ESIA = environmental and social impact assessment; FIRR = financial internal rate of return; GETFiT = global energy transfer feed-in tariff; IFC = International Finance Corporation; LRF = livelihood restoration framework; RAP = Resettlement Action Plan. just three additional small hydropower projects, totaling 25 MW, were accepted. An additional tender was run for solar PV, which attracted 24 expressions of interest; 9 were short-listed and 7 bids submitted. In the end, two project devel- opers were awarded two 5 MW projects each. GETFiT was designed as a temporary facility, likely to be phased out. The idea was to stimulate the small-scale renewable energy market, initially through a premium payment but, importantly, also through firming up the contractual framework and providing confidence to investors. It remains to be seen whether further regular competitive tenders will be conducted after the withdrawal of donor support. Procurement and Contracting Mechanisms Within the context of procuring IPPs, we define competition as competition for the market, that is, competitive tenders or auctions for long-term contracts contrast, between new IPPs and off-takers, typically the national or local utility. In ­ directly negotiated deals are awarded without an open bidding process, and most often originate in unsolicited proposals from interested investors. The majority of IPPs developed in Africa (80 of the 126 for which data are avail- able) have been competitively procured (table 4.5). But without South Africa (which accounts for 67 projects), the numbers change dramatically: only 16 com- petitive tenders versus 34 directly negotiated projects. Not only do direct negotia- tions outnumber competitive tenders across the Sub-Saharan Africa pool, excluding South Africa, but they also represent the majority of the megawatts procured. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Table 4.5  Comparison of Procurement Methods Used for Independent Power Projects, Sub-Saharan Africa C C C DN DN DN REFiT a REFiT a REFiT a No. of US$, No. of US$, No. of US$, Total Total US$, Total MWb projects (%) millions (%) MW (%) projects (%) millions (%) MW (%) projects (%) millions (%) MW (%) numberb (%) millionsb (%) (%) All IPPs 80 (68%) 17,008.52 5,580 37 7,840.06 5,115.3 1 (1%) 150 (1%) 60 (1%) 118 (100%) 24,999 10,755.3 (68%) (52%) (31%) (31%) (48%) (100%) (100%) SSA IPP 16 (31%) 2,997 1,665 34 7,417 4,730 1 (2%) 150 (1%) 60 (1%) 51 (100%) 10,564 6,455 (excl. SA) (28%) (26%) (67%) (70%) (73%) (100%) (100%) SA IPP 64 (96%) 14,012 3,915 3 423 385 0 (0%) 0 (0%) 0 (0%) 67 (100%) 14,435 4,300 (97%) (91%) (4%) (3%) (9%) (100%) (100%) Source: Based on authors’ calculations. Note: C = competitive tender; DN = direct negotiation; IPP = independent power project; MW = megawatt; REFiT = renewable energy feed-in tariff; SA = South Africa; SSA = Sub-Saharan Africa. a. This refers to the Kinangop greenfield wind project (60 MW) and does not include Uganda REFiTs and solar, which had initially been expected to reach financial close in 2015. b. This project tally and associated megawatt and investment totals exclude 305 MW from five projects in Mauritius (293 MW), one IPP in The Gambia (25 MW), one IPP in Cabo Verde (25 MW), and one IPP in Madagascar (15 MW), for which procurement information was outstanding in 2015. In terms of methodology, it should be noted that if projects are initially procured via an international competitive bid (ICB), then any expansions (and associated investment and megawatts), unless otherwise specified, are also counted as an ICB, regardless of whether there was additional competition. The same applies to those projects procured via direct negotiation. 69 70 Independent Power Projects: An Analysis of Types and Outcomes Figure 4.1  Competitive Tenders versus Directly Negotiated Projects, Sub-Saharan Africa (Excluding South Africa), 1994–2014 1,000 900 800 700 600 Megawatts 500 400 300 200 100 0 11 01 02 03 13 10 12 08 09 94 99 04 14 96 05 06 07 97 20 20 20 20 20 20 20 20 20 19 19 20 20 19 20 20 20 19 DN MW ICB MW Source: Based on authors’ calculations. Note: No IPPs recorded for 1995 or 2000, which explains the absence of those years in the figure. DN = direct negotiation; ICB = international competitive bid; IPP = independent power project; MW = megawatt. To what extent have trends moved toward or away from one procurement method? Figure 4.1 shows a cycle that mimics the larger investment cycle, as first highlighted in chapter 2. There is neither a move toward or away from either competitive tenders or directly negotiated projects, but a consistent engagement with both—again excluding South Africa, where ICBs are the dominant procure- ment method. Following South Africa, Kenya has had the most success in conducting inter- national competitive tenders, with six such procurements for 11 IPPs (table 4.6). Successful bid processes tend to make subsequent tenders easier and more pre- dictable, which in turn potentially lead to more bids and more competition. Why Countries Sometimes Pursue Direct Negotiations over Competitive Tenders Based on the specific experience of the five case study countries, the analysis here investigates circumstances that drive governments to choose directly negotiated IPP contracts rather than competitive selection based on an open bidding process. Conspicuously, every one of the five study countries procured its first IPP via a direct negotiation. Kenya was the first in 1996, followed by Tanzania in 1997; Uganda and Nigeria would follow in 1999 and 2001, respectively. South Africa came last, in 2005—initially for a mere 7 MW but later for a larger open-cycle gas turbine (OCGT) plant when a competitive tender failed.8 Uganda had a slower transition to private power, first integrating excess power from multiple captive plants (Mubuku I, III) involved in mining operations.9 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 71 Table 4.6  Summary of IPP Projects and Procurement Methods in Case Study Countries: Sub-Saharan Africa, 1990–2014 Total investment Country No. of projects Capacity (MW) (US$, millions) Kenya 11 1,065.5 2,361.4 DN (1996x2, 2008, 2014) 4 480.5 1,133.4 C (1999x2, 2008, 2012, 2013) 6 525.0 1,077.9 REFiT (2013) 1 60.0 150.0 Nigeria 4 1,521.0 1,702.0 DN (2001, 2002, 2008, 2013) 4 1,521.0 1,702.0 South Africa 67 4,307.3 14,434.6 DN (2005, 2006, 2010) 3 385.0 422.6 C (2012, 2013, 2014) 64 3,922.3 14,012.0 Tanzania 4 427.0 598.4 DN (1997, 2006) 2 220.0 250.4 C (2001, 2005) 2 207.0 348.0 Uganda 11 451.3 1,274.4 DN (1975, 1999, 2003, 2008, 2009, 2012) 9 151.3 340.4 C (2007, 2008) 2 300.0 934.0 Grand total 97 7,772.1 20,370.8 Source: Compiled by the authors based on various primary and secondary source data. Note: Excludes Uganda’s REFiT and South Africa’s Renewable Energy Independent Power Project Procurement Programme (REIPPPP) round 4, for which financial close was initially anticipated in 2015. C = competitive tender; DN = direct negotiation; MW = megawatts; REFiT = renewable energy feed-in tariff. In Kenya, Tanzania, and Nigeria, serious power shortages motivated these first IPP procurements. These countries’ experiences with competitive procure- ment were negligible at the time, and there was a general perception that direct negotiation would allow quick fixes. Interestingly, in both Kenya and Tanzania competitive tenders were already under way for other installations, but were passed by for stopgap measures. In the case of one Tanzanian project (IPTL), the time between financial close and procurement spanned five years amid the arbitration of a project dispute; thus, direct negotiation was not a quick fix in the least. Other than this project, most of these fast-track projects did come online rapidly. But the contract changes or challenges they met at a later date could easily be ascribed to their fast-track nature. Take, for instance, AES Barge in Nigeria: the initial plant size increased from 90 MW to 270 MW and the project also saw a change in fuel, from liquid fuel to natural gas—both of which had the effect of reducing the capacity charge. It took five years of arbitration to resolve a disagreement over the payment due for deficient availability, among other issues, and a tax exemption certificate was withheld by the government for the duration of the project. In the case of Westmont in Kenya, tariffs met with public disapproval, along with allegations of corruption, but there was no outright contract change. Westmont would not, however, negotiate a second contract after its initial seven-year contract expired Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 72 Independent Power Projects: An Analysis of Types and Outcomes (amid a failure to agree on rates), and the project was terminated—in contrast to Iberafrica (also in Kenya), which voluntarily lowered rates prior to contract renegotiation. While the first IPPs in the five cases were all directly negotiated, subsequent private power projects have not followed a clear pattern. Both Kenya and Tanzania opted for the competitive procurement model, reverting to projects that were already under way and clearly identified in the country’s master plans. Importantly, competitive procurement was made a precondition for access to multilateral funding streams and later guarantees. In these two countries, the first set of IPPs were perceived to be costly experiments, prompting demand for greater accountability and scrutiny in subsequent IPP projects. Nigeria, Uganda, and South Africa, meanwhile, continued to use direct nego- tiations to procure private power, despite the costs observed in earlier such negotiations. This points to potentially deeper issues surrounding how countries perceive the cost of funding and the benefits of various procurement methods, particularly in the face of power cuts as well as initial IPP experiences. Uganda’s experience (presented in box 4.4) provides an illustrative example of how policy makers’ perceptions of competitive procurement may be erroneous. Neither procurement method has, however, been a foregone conclusion. For instance, direct negotiations have subsequently been used in Kenya and Tanzania, albeit intermittently, and competitive tenders have finally emerged in South Africa and Uganda, alongside further procurement by direct negotiation. This reinforces the dynamic highlighted in figure 4.1: a recurring wave of com- petitive tenders and direct negotiations across the pool is also now seen at the country level. Nigeria is the one country among the five with no record of competitive procurement, although once the Transitional Electricity Market (TEM) is fully functional, it intends running competitive tenders as stipulated by the Nigerian Electricity Regulatory Commission (NERC), the electricity regulator. It is important to reiterate here that direct negotiations are often the result of unsolicited bids and frequently occur within the context of power short- ages. This scenario is very common in countries where planning capacity is weak and ­ generation expansions are not effectively programmed and procured in a timely manner. Competitive tenders, in contrast, ideally follow from up- to-date power plans and are initiated with sufficient time to allow for a well- designed procurement process. The risks and often poor outcomes associated with procurement processes delinked from generation expansion plans and based on direct negotiation, in contrast to well-planned and well-run tenders, come to the fore when comparing the experiences of Kenya and Tanzania, as presented in box 4.5. The Scope for Competition in Sub-Saharan Africa Competitive tenders are intended to bring about more affordable, higher-quality power through a transparent bidding process. This is more likely the case when tenders attract an adequate number of investors. In the ideal scenario, one project Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 73 Box 4.4  Direct Negotiations and Competitive Procurement in Uganda In Uganda, competitive tenders for large-scale independent power projects (IPPs) are per- ceived by some in government as costly and time consuming and, hence, not in line with the ultimate goals of a reliable power system and reduced generation prices. The government of Uganda believes that, in the end, public projects involve less expenditure because they involve fewer transaction costs between lenders. Also, it is assumed that private investors come with higher expectations of returns—framed by some government officials as the “hidden cost” or “premium” of private financing. Such perceptions are understandably—but, nevertheless, erroneously—shaped by the comparison of the fully depreciated, government-owned Nalubaale and Kiira, and the privately sponsored Bujagali hydroelectric plants. Whereas the former projects sell electricity to the utility at an estimated U.S. cents (USc) 1.2 per kilowatt-hour (kWh), Bujagali-generated electricity is bought at roughly USc 10 or more. For the Karuma and Isimba hydropower projects, both under construction and both financed in part by Chinese funding, the government publicly communicates an expected tar- iff range of USc 4–6/kWh. Development partners as well as the private sector have questioned these numbers and, indeed, a closer look at current cost estimates and the financing condi- tions under discussion do not necessarily verify the government’s expectations. With $3.44  ­million/megawatt (MW), the Bujagali hydropower plant (HPP) ranks among the most expensive projects of this scale in the world (overview in IRENA [2012]). The Karuma HPP, mean- while, has competitive cost levels, at an estimated $2.34 million/MW. Nonetheless, the Isimba HPP, at $3 million/MW, is not significantly cheaper than the Bujagali HPP on a per unit level. Amid the frequent cost overruns of large hydropower projects, the effective margin of pub- lic over private projects could decrease more. The other main argument in favor of a direct award is its comparatively shorter implemen- tation timeline. The public perception is that the full procurement cycle for Bujagali took more than 12 years. In contrast, the implementation of the similar-sized Kiira hydropower proj- ect in the early 2000s is recorded—and wrongly so—as having been completed without com- plications and delays. With an estimated six years from the award to the expected commissioning of the Karuma and Isimba hydropower projects, a competitive procurement process following all (international) legalities and formalities cannot compete. It could, how- ever, be argued that competition was not the reason for any failure associated with Bujagali, but rather the institutional arrangements of its implementation, especially the exclusion of external experts in the procurement process and decision-making bodies. Furthermore, the first failed attempt to implement Bujagali was the result of a flawed direct award process, which in the end had to be aborted after the detection of corruption. Source: Compiled by the authors, based on various primary and secondary source data. receives a dozen bids and the fierce competition drives down prices and, ­ optimally, pushes up quality. With the notable exception of South Africa, no tender in Africa has attracted a dozen bidders over the course of the two-decade experience with IPPs. As seen in table 4.7, tenders in the five case study countries have generally attracted two Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 74 Independent Power Projects: An Analysis of Types and Outcomes Box 4.5  A Comparison of Competitive Tenders and Direct Negotiations in Kenya and Tanzania Kenya has run a series of successful competitive procurements for new thermal power. In the most recent round, in 2010, the Kenya Power and Lighting Company (KPLC) began a competi- tive procurement for three diesel generators of approximately 80 megawatts (MW) each, cul- minating in Thika (87 MW), Triumph (83 MW), and Gulf (80 MW). For Thika alone, 9 bids were received (after 17 firms drew tender documents). Local sponsors are noted in two of the three projects, and partial risk guarantees (PRGs) helped shore up competitive financing. The three projects are deemed success stories in terms of the ultimate cost and reliability of power. Kenya had a dynamic power-planning process, chaired by the regulator, the Energy Regulatory Commission, but involving all relevant stakeholders. New build opportunities were allocated to either the national power generation company, KenGen, or to private indepen- dent power projects, which were procured via competitive tenders run by the KPLC. Separated from KenGen, and housing the system operator, the KPLC does not face any generation invest- ment conflicts and is able to procure new power in a fair, transparent, and competitive fashion. The KPLC built up considerable internal procurement and contracting capabilities and was able to run timely and effective procurement processes. But more recently, the landscape for new build opportunities has been somewhat clouded by the involvement of the government’s Geothermal Development Company and direct negotiations for wind projects. The power- planning system today relies on optimistic demand assumptions, and unfortunately no longer offers a clear link to the timely initiation of competitive tenders by a central procurement unit. Tanzania’s record stands in contrast to Kenya’s. It produces irregular power master plans that never translate into timely competitive tenders. Instead, the Ministry of Energy and Minerals is inundated with unsolicited proposals formalized into memorandums of under- standing with project developers, some without an established track record. The ministry has struggled to assess the value of these projects and procurement has been often delayed. An example is the Richmond (now Symbion) project. Agreement was struck, in a nontrans- parent manner, with Richmond, a special-purpose vehicle formed in 2006 to provide 100 MW of emergency power. The contract was stipulated for two years starting in September 2006 (20 MW) followed by the balance (80 MW) by February 2007, which was safeguarded by a govern- ment guarantee. The first 20 MW (of the 100 MW) was brought online in October 2006, and fueled with natural gas supplied by Songo Songo. This occurred only after the government advanced Richmond funds, as neither the parent company (which it turns out was a publisher with no prior experience in power supply) nor the subsidiary (operating from a residential address in Houston) had money to lift the generators. Dowans Holdings, based in the United Arab Emirates (UAE), subsequently bought the plant and took over the ­ contract, and saw the addition of 60 MW capacity, albeit only by August 2007—six months later than expected. When the plant finally came online it was not fully functioning and by the time all issues had been resolved Tanzania was no longer in need of the power, yet was legally contracted to pur- chase it or pay penalties. The Richmond/Dowans fallout led to the resignation of Prime Minister Edward Lowassa and two ministers in 2008 amid associated corruption allegations. Source: Compiled by the authors, based on various primary and secondary source data. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 75 Table 4.7  Sample of Competitive Tenders in Selected Countries, Sub-Saharan Africa Year Project No. of bids Country 1999 Azito 3 Côte d’Ivoire 1999 Kipevu II/Tsavo 3 Kenya 1999 OrPower4 2 Kenya 2001 Songas—Songo Songo Gas-to-Power Project 2 Tanzania 2005 Saint-Louis-Dagana-Podor Rural Electrification 2 Senegal 2007 Bujagali Hydro Project 3 Uganda 2008 Namanve Power Plant 3 Uganda 2008 Rabai Power Plant 4 Kenya 2012 Thika Thermal Power Project 9 Kenya 2015 GETFiT PV (Tororo North/South and Soroti I/II) 7 (for 2 projects each) Uganda Source: Compiled by the authors, based on various primary and secondary source data. Note: GETFiT = global energy transfer feed-in tariff; PV = photovoltaic. to three bidders, surely not enough to ensure strong competition. However, the results have slowly improved since 1999 and there is notable development in the case of Kenya. The Advantages of Competition: Better Transparency and Price Outcomes The obvious advantage of competition is that it affords greater transparency in the procurement process and therefore helps ensure that new generation capac- ity is procured fairly and at the least cost. Direct negotiation restricts options and the possibility to strike the best deal. All too often, unsolicited bids result in nontransparent memoranda of under- standing (MoUs) and contracts, sometimes linked to allegations of corruption. In contrast, published requests for qualification (RfQs), requests for proposals (RfPs), and evaluation and award processes provide transparency and certainty in the market and potentially generate a pipeline of investors. Transparency and market interest are further enhanced if competitive tenders are linked to regu- larly updated generation expansion plans. The experience of the case study countries demonstrates that the competitive procurement of IPPs provides clear price advantages, despite the relatively low number of bidders in many of these tenders. As seen in table 4.8, competitively bid OCGTs and CCGTs are consistently less costly than directly negotiated capacity using the same technologies. Procurements of medium-speed diesel (MSD)/HFO power engines by competi- tive tender and direct negotiations appear to be largely comparable, whereas wind shows the advantage of competitive tenders (based on South Africa’s round 3 REIPPPP data) over both REFiT and direct negotiation. Table 4.9 provides a series of price comparisons, based on data from case study countries.10 Looking at the projects listed in table 4.9, the MSD/HFO procured via competitive bidding appears to be less expensive (as measured by USc/kWh) ­ than that procured through direct negotiation, setting aside exogenous factors Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 76 Independent Power Projects: An Analysis of Types and Outcomes Table 4.8  Cost Comparison of Directly Negotiated and Internationally Competitive Bid Projects, by Technology, 1994–2014 US$/kilowatt-hour Technology/procurement Directly negotiated Competitive tender REFiT OCGT 977 833 n.a. CCGT 1,145 1,038 n.a. MSD/HFO 1,526 1,534 n.a. Onshore wind 2,870 2,180 2,500 Source: Based on the authors’ calculations. Note: Biomass, coal, geothermal, methane, and solar PV are excluded from this comparison as there was only one procurement type, that is, either direct negotiation or competitive tender, not both. Hydropower has also been excluded as costs are site specific (hydrology and geology). The data on competitive tenders for wind are from Window 3 of the REIPPPP. Some projects from the database have also been excluded because they include gas or fuel infrastructure costs and, at the time of writing, separate power plant costs were not available for comparative purposes. CCGT = combined-cycle gas turbine; HFO = heavy fuel oil; kW = kilowatt; MSD = medium-speed diesel; OCGT = open-cycle gas turbine; PV = photovoltaic; REFiT = renewable energy feed-in tariff; REIPPPP = Renewable Energy Independent Power Project Procurement Programme; n.a. = not applicable. Table 4.9  Cost Comparison of Medium-Speed Diesel/Heavy Fuel Oil Generators, 2013–15 USc/kilowatt-hour MSD/HFO-country (year of financial close), project name Competitive tender Directly negotiated MSD/HFO-Tanzania (1997), IPTL n.a. 31 MSD/HFO-Uganda (2009), Tororo n.a. 27.09 MSD/HFO-Uganda (2008), Namanve 24.08 n.a. MSD/HFO-Kenya (1996), Iberafrica n.a. 25 MSD/HFO-Kenya (1999), Tsavo 22 n.a. MSD/HFO-Kenya (2008), Rabai 14 n.a. MSD/HFO-Kenya (2012), Thika 22 n.a. MSD/HFO-Kenya (2014), Gulf 22 n.a. Source: Compiled by the authors, based on various primary and secondary source data. Note: There are important qualifiers, related to specific technology and location, that explain some of the cost discrepancies. Take, for instance, the case of Kenya: Rabai, the least costly IPP listed in this table, has a heat-recovery system, which improves efficiencies, and is located close to the port of Mombasa (and its fuel source). The heat-recovery system explains part of the difference in cost with the Tsavo IPP, also located in Mombasa. The Thika Power and Gulf IPP have heat-recovery systems as well, but these plants are located up-country near Nairobi and have an additional fuel cost for transportation to and from Mombasa (about 500 kilometers away). Iberafrica, located in Nairobi, which also has an additional fuel transportation cost, is similar in technology to Tsavo. HFO = heavy fuel oil; IPP = independent power project; IPTL = Independent Power Tanzania Ltd.; MSD = medium-speed diesel; USc = U.S. cent; n.a. = not applicable. such as transmission constraints and dispatch regimes that impact on capacity factors and hence price. Price outcomes for solar and wind energy11 projects can be compared more reliably, since they are self-dispatched and have fixed tariffs. The next section presents the experience of South Africa, where competitively bid wind projects have far lower price outcomes than the directly negotiated Lake Turkana project in Kenya, despite its vastly superior wind resources. Competitively bid solar PV projects in South Africa and Uganda are also more competitive than the directly negotiated projects in Rwanda and Nigeria. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 77 The Impressive Results of Competitively Bid Wind and Solar Projects in South Africa South Africa provides a striking example of the superior outcomes associated with the competitive procurement of wind and solar projects, which have deliv- ered prices comparable to the very sophisticated auction system developed in more mature power markets, such as Brazil (whose experience is presented in the next section). Following the abandonment of the REFiT program in 2011, South Africa moved to competitive tenders for grid-connected renewable energy with the REIPPPP. An IPP office was set up by the National Treasury in cooperation with the Department of Energy (DoE), and the first RfP was launched in August 2011. The REIPPPP envisioned the procurement of 3,625 MW of power over a maximum of five tender rounds. Another 100 MW was reserved for small proj- ects below 5 MW that were procured in a separate program for small IPPs. Caps were set on the total capacity to be procured for individual technologies— the largest allocations were for wind and PV, with smaller amounts for concen- trated solar, biomass, biogas, landfill gas, and hydropower. The rationale for these caps was to limit the supply to be bid out and therefore increase the level of competition among the various technologies and potential bidders. The tenders for different technologies were held simultaneously. Interested parties could bid for more than one project and more than one technology. Projects had to be larger than 1 MW; the upper limit set on bids differed by technology—for example, 75 MW for a PV project, 100 MW for a concentrated solar power (CSP) project, and 140 MW for a wind project. Caps were also set on the price for each technology (at levels not dissimilar to the National Energy Regulator of South Africa’s [NERSA’s] 2009 REFiTs). Bids were due within three months of the release of the RfP, and financial close was to take place within six months after the announcement of preferred bidders. Twenty-year PPAs, denominated in South African rand (R), were to be signed by the IPPs and Eskom, the off-taker. IPPs and the DoE were to sign implementa- tion agreements (IAs), which included a sovereign guarantee of payment to the IPPs, by requiring the DoE to make good on these payments in the event of an Eskom default. The IAs also placed obligations on the IPP to deliver economic development targets. Direct agreements (DAs) provided step-in rights for lend- ers in the event of default. The PPA, IA, and DA were nonnegotiable contracts and were developed after an extensive review of global best practices and con- sultations with numerous public and private sector actors. Despite some bidder reservations regarding a lack of flexibility to negotiate the terms of the various agreements, the overall thoroughness and quality of the standard documents seemed to satisfy most of the bidders participating in the three rounds. Bids were required to contain information on the project structure; legal qualifications; and land, environmental, financial, technical, and economic devel- opment qualifications. Bidders had to submit bank letters indicating that financing was locked in—a highly unusual practice outsourcing due diligence to ­ Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 78 Independent Power Projects: An Analysis of Types and Outcomes the banks. Effectively, this meant that lenders took on a higher share of project development risk, in an arrangement that addressed the biggest problem with auctions—the “low-balling” that results in deals not closing. The developers were expected to identify the sites and pay for early development costs at their own risk. Bid bonds or guarantees had to be posted, equivalent to R 100,000 ($12,500) per megawatt of nameplate capacity of the proposed facilities, and the amount was doubled once preferred bidder status was announced. The guaran- tees were to be released once the projects came online or if the bidder was unsuccessful after the RfP evaluation stage. Approximately 130 local and international advisers were used by the DoE’s IPP office to develop the RfP and evaluate the bids in the first round, at a total cost of approximately $10 million. Many of these advisers had been involved in the initial design process. The bid evaluation involved a two-step process. First, bidders had to satisfy certain minimum threshold requirements in six areas: environment, land, commercial and legal, economic development, financial, and technical. For example, the environmental review examined approvals while the land review looked at tenure, lease registration, and proof of land-use applications. Commercial considerations included the project structure and the bidders’ acceptance of the PPA. The financial review included standard templates used for data collection that were linked to a financial model used by the evaluators. Technical specifications were set for each of the technologies. For example, wind developers were required to provide 12 months of wind data for the designated site and an independently verified generation forecast. The economic development r ­ equirements, in particular, were complex and gener- ated some confusion among bidders. Bids that satisfied the threshold requirements then proceeded to the second step of evaluation, where bid prices counted for 70 percent of the total score, with the remaining 30 percent given to a composite score covering job creation, local content, ownership, management control, preferential procurement, enter- prise development, and socioeconomic development. The 70/30 split was new in public procurement and decreased the weight of price considerations over eco- nomic development considerations compared with the usual 90/10 split man- dated by the government. Bidders were asked to provide two prices: one fully indexed for inflation and the other partially indexed, with the bidders initially allowed to determine the proportion that would be indexed. In subsequent rounds, floors and caps were instituted for the proportion that could be indexed. The detailed results of the first four rounds are shown in table 4.10. In the first round, 53 bids for 2,128 MW of power-generating capacity were received. Ultimately 28 preferred bidders were selected, awarding 1,425 MW for a total investment of nearly $6 billion. Successful bidders realized that not enough projects were ready to meet the bid qualification criteria, and that all qualifying bids were thus likely to be awarded contracts. Bid prices in the first round were thus close to the price caps set in the tender documents. Major Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 79 Table 4.10  Results of South Africa’s Efforts to Procure Renewable Energy Independent Power Projects, by Bidding Round Bidding round Wind PV CSP Hydro Biomass Biogas Landfill Total Round 1 Capacity offered (MW) 1,850 1,450 200 75 12.5 12.5 25 3,625 Capacity awarded (MW) 648.5 626.8 150 0 0 0 0 1,425.3 Projects awarded 8 18 2 0 0 0 0 28 Average tariff (Rc/kWh) 114 276 269 n.a. n.a. n.a. n.a. n.a. Average tariff (USc/kWh) R 8/$ 14.3 34.5 33.6 n.a. n.a. n.a. n.a. n.a. Total investment (R, millions) 13,312 23,115 11,365 0 0 0 0 47,792 Total investment (US$, millions) R 8/$ 1,664 2,889 1,421 0 0 0 0 5,974 Round 2 Capacity offered (MW) 650 450 50 75 12.5 12.5 25 1,275 Capacity awarded (MW) 558.9 417.12 50 14.4 0 0 0 1,040.42 Projects awarded 7 9 1 2 0 0 0 19 Average tariff (Rc/kWh) 90 165 251 103 n.a. n.a. n.a. n.a. Average tariff (USc/kWh) R 7.94/$ 11.3 20.8 31.6 13 n.a. n.a. n.a. n.a. Total investment (R, millions) 10,897 12,048 4,483 631 0 0 0 28,059 Total investment (US$, millions) R 7.94/$ 1,372 1,517 565 79 0 0 0 3,533 Round 3 Capacity offered (MW) 654 401 200 121 60 12 25 1,473 Capacity awarded (MW) 787 435 200 0 16.5 0 18 1,456.5 Projects awarded 7 6 2 0 1 0 1 17 Average tariff (Rc/kWh) 74 99 164 n.a. 140 n.a. 94 n.a. Average tariff (USc/kWh) R 9.86/$ 7.5 10 16.6 n.a. 14.2 n.a. 9.5 n.a. Total investment (R, millions) 16,969 8,145 17,949 0 1,061 0 288 44,412 Total investment (US$, millions) R 9.86/$ 1,721 826 1,820 0 108 0 29 4,504 Round 3.5 Capacity offered (MW) n.a. n.a. 200 n.a. n.a. n.a. n.a. 200 Capacity awarded (MW) n.a. n.a. 200 n.a. n.a. n.a. n.a. 200 Projects awarded n.a. n.a. 2 n.a. n.a. n.a. n.a. 2 Average tariff (Rc/kWh) n.a. n.a. 153 n.a. n.a. n.a. n.a. 153 Average tariff (USc/kWh) R 10.52/$ n.a. n.a. 14.5 n.a. n.a. n.a. n.a. 14.5 Total investment (R, millions) n.a. n.a. 18,319 n.a. n.a. n.a. n.a. 18,319 Total investment (US$, millions) R 10.52/$ n.a. n.a. 1,742 n.a. n.a. n.a. n.a. 1,742 Round 4 (a) Capacity offered (MW) 590 400 0 60 40 0 15 1,105 Capacity awarded (MW) 676.4 415 0 4.7 25 0 0 1,121.1 Projects awarded 5 6 0 1 1 0 0 13 Average tariff (Rc/kWh) 61.9 78.6 n.a. 111.7 145 n.a. n.a. n.a. Average tariff (USc/kWh) R 12/$ 5.2 6.6 n.a. 9.3 12.1 n.a. n.a. n.a. Total investment (R, millions) 13,466 8,504 0 245 1,195 0 0 23,410 Total investment (US$, millions) R 12/$ 1,122 708.7 0 20.4 99.6 0 0 1,950.7 table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 80 Independent Power Projects: An Analysis of Types and Outcomes Table 4.10  Results of South Africa’s Efforts to Procure Renewable Energy Independent Power Projects, by Bidding Round (continued) Bidding round Wind PV CSP Hydro Biomass Biogas Landfill Total Round 4 (b)a Capacity offered (MW) n.a. n.a. n.a. n.a. n.a. n.a. n.a. 0 Capacity awarded (MW) 686.4 397.9 0 0 0 0 0 1,084.3 Projects awarded 7 6 0 0 0 0 0 13 Average tariff (Rc/kWh) 71.6 85.1 n.a. n.a. n.a. n.a. n.a. n.a. Average tariff (USc/kWh) R 12.5/$ 5.7 6.8 n.a. n.a. n.a. n.a. n.a. n.a. Total investment (R, millions) 15,329 8,363 0 0 0 0 0 23,692 Total investment (US$, millions) R 12.5/$ 1,226.3 669 0 0 0 0 0 1,895.3 TOTALS Capacity offered (MW) n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. Capacity awarded (MW) 3,357.2 2,291.82 600 107.7 41.5 0 18 6,327.62 Projects awarded 44 35 7 3 2 0 1 92 Total investment (R, millions) 69,973 60,175 33,797 876 2,256 0 288 167,365 Total investment (US$, millions) R 12.5/$ 7,105.3 6,609.7 5,548 99.4 207.6 0 29 19,599 Source: Compiled by the authors based on DoE presentations and data provided by the DoE IPP Unit. Note: R/US$ conversions are relevant for the date on which contracts were signed in each bid window. These data are representative at the time of bidding. Contracted capacity and investment amounts changed slightly at the time of financial close. CSP = concentrated solar power; DoE = Department of Energy; IPP = independent power project; kWh = kilowatt-hour; MW = megawatt; PV = photovoltaic; R = rand; Rc = rand cent; USc = U.S. cent; n.a. = not applicable. a. Round 4b was an additional award. Due to numerous low-priced bids in round 4, after the initial award of preferred bidders (now referred to as 4a), it was decided to double the award (referred to as 4b). There was no official prior allocation for 4b—simply an additional award based on the next cheapest projects bid in the original round 4. contractual agreements were signed on November 5, 2012; most projects reached full financial close shortly thereafter. Construction on all of these proj- ects has since commenced, and the first project came online in November 2013. A second round of bidding was announced in November 2011. The total amount of power to be acquired was reduced, and other changes were made to tighten the procurement process and increase competition. Seventy-nine bids for 3,233 MW were received in March 2012, and 19 bids were ultimately selected. Prices were more competitive, and bidders also offered better local content terms. IAs, PPAs, and DAs were signed for all 19 projects in May 2013. A third round of bidding commenced in May 2013, and again, the total capac- ity offered was restricted. In August 2013, 93 bids were received, totaling 6,023 MW. Seventeen preferred bidders were notified in October 2013, totaling 1,456 MW. Prices fell further in round three. Local content again increased, and financial close was expected in July 2014, but has been delayed a number of times because of uncertainties around Eskom transmission connections. A fourth round of bidding commenced in August 2014; 13 preferred bidders were announced in April 2015, totaling 1,121 MW. Prices were so low that an extended allocation was made in June 2015 for an additional 13 projects totaling 1,084 MW. As it can be clearly seen, bid prices fell across rounds (figure 4.2). In particular, in round 4 the price for solar PV was less than a fifth of the price in round 1. The price for onshore wind decreased to a third of what it had been. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 81 Figure 4.2  Average Bid Prices for Independent Power Projects Using Renewable Energy, South Africa 300 Rand cents/kilowatt-hour (nominal) 250 200 150 100 50 0 Round 1 Round 2 Round 3 Round 4 Solar PV Onshore wind Source: Compiled by the authors, based on various primary and secondary source data. Note: PV = photovoltaic. Increased competition was no doubt the main driver of the fall in prices in rounds two and three. But there were other factors as well. International prices for renewable energy equipment have declined over the past few years amid a glut in manufacturing capacity as well as ongoing innovation and economies of scale. The REIPPPP was well positioned to capitalize on these global factors. Transaction costs were also lower in subsequent rounds, as many of the project sponsors and lenders became familiar with the REIPPPP tender specifications and process. As renewable energy prices are reaching grid parity, it is possible for other African countries to explore what they might learn from the South African REIPPPP through lowering transaction costs and designing competitive tenders appropriate to local markets. Competitive Procurement Elsewhere in the World: The Brazilian Model When considering effective mechanisms for procuring new generation capac- ity, it is useful to explore the experience of other regions and countries. Brazil is a case in point. Brazil’s auction-based power market is among the most sophisticated and efficient in the world. How did Brazil come to use the auc- tion mechanism and how does it work in practice? Prompted by a deep finan- cial and operational crisis in its power sector, Brazil commenced reforms in 1998. A competitive wholesale market was created with a spot market as well as independent institutions responsible for sector regulation and monitoring and market administration. Importantly, the reforms also targeted improve- ments in the technical and financial performance of utilities. In this early reform period, however, investors did not always receive the right signals for the long-term expansion of generation capacity in line with increasing demand. With a significant share of capital-intensive hydropower in the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 82 Independent Power Projects: An Analysis of Types and Outcomes generation mix, Brazil was forced to fall back to energy rationing during dry periods, especially in 2001–02. The energy crisis triggered a second wave of reforms that began in 2004. These focused on delivering adequate power sup- ply and on the centralized planning of power expansion. Competitive tenders or auctions were used to build and operate new generation and transmission facilities. Also, to provide more ­revenue certainty and to attract long-term financing for new power capacity, long-term bilateral contracts between the new IPPs or transmission companies and financially viable distribution com- panies (DisCos) were made mandatory. As of today, although the state-owned company, Eletrobras, remains one of the most important players in generation and transmission, private sector participation is extensive, not only in distribu- tion but also in most new generation and transmission additions. Customers supplied by distribution companies account for 70 percent of total electricity consumption. Each distribution company has to estimate the growth in demand from its regulated customers, and these demand projections are aggre- gated to determine required supply capacity in centrally organized auctions. Distribution companies cannot negotiate contracts bilaterally with suppliers outside these auctions. There are separate auctions for new energy (new gen- eration investments) and existing energy (renewal of contracts from existing generators) to ensure the security of supply. A detailed analysis of the auction process is presented in box 4.6. Multiple auctions have been held each year, with impressive capacity and price outcomes. Sixty-five gigawatts of new capacity have been contracted (40 percent hydropower, 33 percent renewable energy, and 27 percent ther- mal) and wind prices are now as low as USc 5/kWh. PPAs include capacity factors of the plant that have to be guaranteed by the IPP, and penalties in case actual production is lower than the guaranteed value. This analysis of the Brazilian energy auction and contracting system demonstrates the significance of the second wave of power sector reforms that have swept across Latin America (and some other emerging economies), aimed at incentivizing and facilitating new investment in power generation. Africa’s power sector reforms have not progressed as far. Understandably, the level of sophistication reached in Latin America does not fit the reality of most African countries, constrained as they are by structural issues such as weak public sector capacity, vulnerable economies, and weak investment climates. Nonetheless, what is important about Brazil’s experience is not the type or degree of reforms put in place, but rather the key principles underpinning reforms: openness and transparency in the planning of power expansion, transparency and predictability in the com- petitive procurement of generation capacity, and robust oversight by the min- istry and the sector regulator. It is important to note that the reforms first commenced with efforts to improve the operational and financial sustainability of electricity distributors. These distributors then had to take responsibility for securing adequate power through a centrally managed, fully competitive procurement process. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 83 Box 4.6 How the Brazilian Energy Auction Works Auctions are run annually and are designed according to project lead times, contract dura- tion,  technology type, and adjustments. In addition, there are sporadic auctions that are ­ project specific or for reserve energy. The Brazilian Electricity Regulatory Agency (ANEEL) pub- lishes draft contracts and more detailed requirements. Developers then submit technical details of their projects to the Brazilian Energy Research Agency (EPE)—reporting to the Ministry of Energy and Mines (MME), which announces the projects qualified to participate in the auction. All existing, new, and reserve energy auctions have followed a hybrid design, divided into two phases: a “descending price clock auction,” followed by a final “pay as bid” round through sealed bids. Prior to the auction, the MME decides two important undisclosed parameters: the “total demand,” representing the maximum energy amount that will be contracted, provided that there is sufficient supply; and the “demand parameter,” which is used to force a minimum level of competition. For example, if the demand parameter is equal to 1.5, this means that the auc- tion’s supply must be at least 50 percent higher than the auction demand—and, therefore, if supply is insufficient, the demanded quantity will be automatically adjusted downward. In the first step of the descending clock phase, the bidders confirm the quantity of elec- tricity (in gigawatt-hours per year) they are willing to commit at the auction’s ceiling price (disclosed in advance and specific to each technology). This quantity cannot be revised in later rounds, even as the offered price decreases. In addition, at this point, the single “total demand,” previously defined by the MME, is allocated to various technologies in proportion to the supply confirmed for each technology, unless the MME has specified a ceiling for a specific technology (in which case the lowest-cost technology on offer makes up the differ- ence). Having thus defined the demand for each technology, and the quantity offered by each of the bidders, the auction continues with the subsequent rounds of the descending clock phase. Multiple rounds take place, in which the auctioneer announces the new price level and bidders confirm whether they wish to continue in the auction (with the full quan- tity initially offered) or not. This phase is terminated when the overall supply becomes smaller than the auction’s demand plus a certain adjustment factor (“demand parameter”) unknown by the bidders. The bidders that remain in the auction proceed to a sealed-bid auction. Bidders are still not allowed to revise the initial quantities offered and they cannot offer a price higher than the ceiling price at which the descending clock phase was termi- nated. What the bidders know for sure is that the supply is greater than the demand, which incentivizes them to further lower their bids in the sealed-bid phase. Experience has shown that this second phase can result in price reductions of up to 15 percent, although less than 5 percent has been more common. The bids are then selected in an ascending order until demand is matched or surpassed. The contracts are priced as bid. Most are standard take-or-pay energy contracts in which the buyer pays a fixed amount per megawatt-hour for the energy contracted, and the seller must deliver the contracted energy, clearing the difference between the energy produced box continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 84 Independent Power Projects: An Analysis of Types and Outcomes Box 4.6  How the Brazilian Energy Auction Works (continued) and contracted in the spot market. In some availability contracts, however, distribution companies pay a fixed amount for available capacity in addition to the variable operating ­ costs and short-term market transactions. Contract values are escalated annually according to defined indexes. Winning bidders sign direct contracts with distribution companies in proportion to their forecasted demand and then conclude financing agreements with banks (principally with the Brazilian Development Bank, BNDES, which offers concessionary finance for auction winners). The mandatory bilateral contracts between new generators and financially viable distribu- tion companies introduced in 2004 have two basic rules: • Every load in the system must be 100  percent covered by a supply contract. This means  that each kilowatt-hour consumed in the system, regardless of whether it comes  from free consumers or from regulated consumers, must be supported by an energy ­contract. The distribution utilities are responsible for contracting energy for their regulated consumers, while each free consumer is responsible for contracting its own consumption. • Every energy contract must be backed up by Firm Energy Certificates (FECs), which are calculated by the MME using probabilistic production-costing models. These certificates ­ represent a generator’s expected capacity to produce energy in a sustainable fashion, ­ following a predefined supply reliability criterion. After signing the power purchase agreements, the project developers are required to deposit a completion bond of 5 percent of the estimated investment cost of their project. If delays exceed one year, ANEEL has the right to terminate the contract and to keep the financial guarantee. To date, no penalties have been applied, although delays with the permits for ­ power transmission and environmental safeguards have occurred for a number of projects. The distribution companies also have to sign a guarantee contract with the energy seller and the bank, mitigating the credit risk. Distribution companies’ bank accounts are required to hold at least 1.5 times the average monthly payments to energy sellers. Federal laws prohibit defaulting distribution companies from adjusting their consumer tariffs; such companies also risk losing their concessions. Source: Compiled by the authors from two notes on power sector reforms and energy auctions in Brazil, one by Antmann (2012), and another by Lino and others (2015). Summary: Competitive Tenders versus Directly Negotiated, Unsolicited Offers The analysis in this chapter has shown that there are benefits to competitive bid- ding in terms of transparency and lower price. Competition is also associated with good practices, such as transparent tendering and contracting procedures or standard contracts with fair risk allocation, which increase predictability and therefore lower perceived risks by prospective investors. As demonstrated by the South African REIPPPP and the Uganda GetFiT program, multiple bid rounds enable the progressive improvement of documentation and contracts; they build Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 85 investor confidence and a pipeline of bankable projects, which can more easily reach financial close and commissioning. Despite the obvious benefits associated with competition, there are a number of common arguments against competitive procurement. First, competitive ten- ders are considered more complex and expensive than their directly negotiated counterparts. Second, competitive tenders take too long, especially if emergency power is required. Third, there is often insufficient private interest to justify competitive tenders. Fourth, the first developer or sponsor who conceives the project may be unwilling to compete via a tender due to proprietary data, ­ technology, and/or initial investment. These arguments are used mainly by pri- vate developers, but the first and second have been used by public stakeholders as well to justify unsolicited proposals. Yet, there are viable responses to each argument raised. Competitive tenders/auctions are more complex and costly. A typical argument against competitive procurement is that tenders/auctions entail ­ potentially higher transaction costs. These can be of different kinds and invari- ably affect governments and bidders. Governments may need to invest in expen- sive transaction advisers to prepare good-quality tender documentation and contracts, and to run the tenders or auctions. Preparing bids may prove onerous to bidders: bid bonds have to be lodged, and complying with environmental, legal, technical, and financial requirements may be expensive. Also, bidders incur these costs with no certainty that they will be awarded the contract. While direct negotiations may appear to be simpler and cheaper at the outset, in prac- tice they are often lengthy, and governments may be ill-equipped to assess the value of unsolicited offers. Contracts are not standardized; developers propose PPAs and IAs, which skew risks unfairly to the off-taker or government. Controversy, even corruption, can bedevil these negotiations, which are often not transparent. Poorly formulated and uncompetitive unsolicited bids may unravel, meaning that projects end up taking longer than they would have through a competitive tender. South Africa’s REIPPPP and some of Kenya’s better-run tenders show that it is possible to run competitive bids efficiently and in short time frames. In these cases, the lower price outcomes of competitive tenders (with multiple bid rounds resulting in even more competitive prices) far outweigh higher transaction costs. Competitive tenders take too long to address an immediate power e ­ mergency. Unsolicited deals have been advocated in the face of supply emergencies. Nonetheless, such a justification should not be taken for granted. A common emergency solution is a thermal plant (reciprocating engines, gas turbines) run- ning on diesel/HFO, a standard greenfield project that can be awarded through a fast-track competitive process. Latin American countries faced with recurring power shortages made the explicit decision to ban directly negotiated deals as part of the second wave of reforms in that region. Meanwhile, it is possible to expedite solicited bids by tightening timelines and approval processes. Case stud- ies also show that directly negotiated projects have been more prone to renego- tiation and contract disputes, meaning that they were not faster. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 86 Independent Power Projects: An Analysis of Types and Outcomes Where investor interest is sparse, competitive tenders are not feasible. This argument holds some weight in Africa, where, as described earlier, many tenders have attracted only a couple of bids. The solution is not, however, to turn to direct negotiations. Instead, there are two viable alternatives. One is to institute a public tender that opens an unsolicited bid up to more scrutiny (even if there is only one bidder, there is always the public process to guide and oversee the bid). The sec- ond is to reconceive the project, and possibly increase its scope by bundling it with other projects, thereby making it more attractive to investors (Hodges 2003). There are proprietary data, technologies, or original investments in place. Several strategies are proposed to deal with investors who are reluctant to lose up-front capital or proprietary information via a competitive bid. Three such examples are the bonus system, Swiss challenge, and best and final offer. In the first option, “an advantage to the original project proponent in the form of a premium used in the bidding procedure” (generally 5–10 percent) is given to the original sponsor’s bid in an open tender (Hodges and Dellacha 2007: 7). In the Swiss challenge, by contrast, the original sponsor may countermatch the best offer and obtain the contract. Finally, the “best and final offer” approach permits the original sponsor to compete in a final tender round, but without giving it preference (Hodges and Dellacha 2007: 7). Thus competitive tenders are preferable and countries should strive to use competition. This does not mean that they should never be involved in direct negotiations or unsolicited offers. In some instances there could be few other options. Competition may be hard in contexts characterized by small-size power systems, or in fragile states with poor investment climates. Also, unsolicited proposals may lead to good deals, as long as countries are able to fully assess the value of the project, direct negotiation is run transpar- ently, and countries have adequate transaction capacity to negotiate reasonable PPAs. Transparency is even more important in the case of direct negotiations, as a means to minimize the risk of controversy or corruption. Also, having in place a sound generation expansion plan is critical to assess whether the project is the best option in terms of cost and technology choice. Therefore, countries that pursue direct negotiation need to invest in planning capacity, obtain transaction advisory support, and strive for transparency in their procurement practices. Notes 1. In the case of Songas, the reduction in capacity charges was facilitated by the buying down of the allowance for funds used during construction, which had ballooned dur- ing delays in construction. Mtwara has been sold back to the state/Tanzania Electric Supply Company 2. (TANESCO) and is no longer an IPP. Symbion, originally an emergency power plant, has been redefined as an IPP, though its PPA negotiations are still under way. 3. All USc/kWh prices cited are for 2013. 4. Prices fully indexed with inflation. South African rand (R)/$ exchange deteriorated from 8 to 12 over the period. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects: An Analysis of Types and Outcomes 87 5. Lake Turkana has an initial tariff of 7.52/kWh euro cents (ac) for up to 1,684 gigawatt-hours (GWh) and ac 3.76/kWh for any additional power. Only 14 percent ­ of the price is indexed to inflation. The Lake Turkana tariff assumes a higher capacity factor than that used in the calculation of the Kenya wind energy feed-in tariff (FiT). 6. Kinangop (developed by Aeolus Wind) is at the 12c FiT (that is, USc 12/kWh up to 223.5 GWh, and USc 6/kWh for any additional power produced and no indexation to inflation). By the third quarter of 2015, this project had been halted amid conflicts with local communities. 7. Round 1 (15), round 2 (8), round 3 (18). Pursuant to the GETFiT policy, rejected projects can apply again. Overall, more than 30 projects applied. 8. This is not true of all countries in the Sub-Saharan African pool, for example, Senegal ran a competitive tender for its first IPP, which reached financial close in 1997, and has since continued to procure via competitive tender. In the majority of Sub-Saharan African countries, however, direct negotiations were conducted for the first IPP. Dates cited here are generally indicative of the year of financial close. 9. In 1999, Kasese Cobalt (Mubuku III) started feeding excess capacity (of approxi- mately 9 MW) into the grid. Prior to that, Mubuku I, associated with a mining project, had been evacuating electricity (approximately 5 MW) to the grid from the 1970s, when mining operations ceased. Kakira cogeneration would be the next to feed excess power, in 2003, with the first dedicated IPP emerging in 2008. 10. OCGTs and CCGTs are excluded from these price comparisons. The CCGT Songas in Tanzania, procured via international competitive bids (ICBs), is known to be priced at USc 5/kWh; however, comparable prices are not available for Nigeria’s directly negotiated CCGT (Afam and Okpai), only the Multi-Year Tariff Order 2 (MYTO-2) prices of USc 6.47/kWh for successor gas and USc 7.28/kWh for new gas (for 2013). Similarly, comparable USc/kWh data are not available for AES Barge and Aba Integrated. Small hydropower are excluded from the analysis here because their prices in large part depend on hydrological and geological conditions. As a reference, though, the average cost of the 2013 ICB-bid small hydropower project in South Africa (Window 3) is USc 13/kWh (for 2013). For small hydropower in Uganda, three directly negotiated projects (in 2008 and 2009) yielded USc 12.9/ kWh, 8.3/kWh, and 13.5/kWh, respectively. REFiT small hydropower, also in Uganda, with a financial close initially anticipated in 2015, ranged from USc 8.5/ kWh to USc 10.1/kWh. 11. Based on the authors’ data, Cabo Verde, Ethiopia, Kenya, and South Africa are the only countries in Sub-Saharan Africa with grid-connected wind installations. Ethiopia’s wind is publicly financed, including via Chinese-backed funding and therefore is not part of this analysis. References Antmann, P. 2012. “Reform of the Electricity Sector in Latin American Countries: Main Characteristics and Emerging Lessons.” Unpublished paper, World Bank, Washington, DC. BNEF (Bloomberg New Energy Finance) and others. 2014. “Climatescope.” http://global​ -climatescope.org/en/policies/#/policy/4125. Accessed April 27, 2015. Davies, L., and K. Allen. 2014. “Feed-in Tariffs in Turmoil.” West Virginia Law Review 116. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 88 Independent Power Projects: An Analysis of Types and Outcomes FS-UNEP (Frankfurt School-United Nations Environment Programme)/BNEF. 2014. Global Trends in Renewable Energy Investment 2014. Frankfurt am Main: UNEP Collaborating Centre Frankfurt School of Finance and Management. Hodges, J. 2003. “Unsolicited Proposals: The Issues for Private Infrastructure Projects.” Viewpoint, World Bank, Washington, DC. Hodges, J., and G. Dellacha. 2007. “Unsolicited Infrastructure Proposals: How Some Countries Introduce Competition and Transparency.” Working Paper No. 1, PPIAF/ World Bank, Washington, DC. IRENA (International Renewable Energy Agency). 2012. “Hydropower.” Renewable Energy Technologies: Cost Analysis Series 1 (3/5). Lino, P., L. Barrosso, A. Anisie, J. Pedro, and G. Rocha. 2015. “Case Study: Brazil Auctions.” Unpublished note, World Bank, Washington, DC. NERSA (National Energy Regulator of South Africa). 2009. “Consultation Paper: Review of Renewable Energy Feed-in Tariffs.” National Energy Regulator of South Africa, Pretoria, July. ———. 2011. “Consultation Paper: Review of Renewable Energy Feed-In Tariffs.” National Energy Regulator of South Africa, Pretoria, March. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 C h apter 5 Conclusions Introduction Independent power projects (IPPs) certainly make an important contribution to Africa’s power needs. By enabling increasing levels of access to electricity, they promise to support economic and social growth across the continent. While public and utility financing have traditionally been the largest sources of expanded power generation capacity, IPPs, together with Chinese-funded projects, are now the fastest growing. IPPs account for about 25 percent of investment and additional generation capacity in Sub-Saharan Africa (excluding South Africa). This is a notable share given the relatively short period during which IPPs have been in operation; how- ever, private investment might be much higher. The challenge ahead is for African countries to create the conditions to attract more IPPs and thus help overcome the continent’s power deficit. Excluding South Africa, the major source of IPP additions have been open- and combined-cycle gas turbines (OCGTs and CCGTs), representing nearly two- thirds of IPP capacity in Sub-Saharan Africa. Second to this are IPPs involving medium-speed diesel (MSD) and heavy fuel oil (HFO), which have relied on high-price oil imports to generate power. Meanwhile, the number of IPPs relying on renewable energy sources, notably wind and solar energy, has increased mani- fold. These are becoming increasingly more attractive than traditional thermal sources of power, and promise to help diversify countries’ energy mix and reduce the cost of power supply. In fewer than four years, South Africa has contracted more than 6 gigawatts (GW) of grid-connected wind, solar photovoltaic (PV), and concentrated solar power (CSP), and renewable energy is now supplied to the grid at prices below the average cost of supply of the national utility, Eskom. There is no doubt that IPPs were worth the effort. But it is not only the quantum of private investment in IPPs that is relevant; equally important are investment outcomes and, markedly, the price and reliability of electricity produced. When procured competitively, IPPs have generally delivered power at lower costs than directly negotiated projects, and their contracts have held better. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   89   90 Conclusions The analysis presented in the preceding chapters shows that competitively bid project costs are lower for gas and wind turbines than directly negotiated ­ projects. And tariffs from competitively bid diesel or HFO generators, and solar PV, are cheaper than directly negotiated contracts. Despite these successful examples, unsolicited and directly negotiated deals have prevailed across Sub-Saharan Africa, accounting for more than 70 percent of all IPP megawatts procured. Competition still poses a conundrum in Africa, which is why this study pays particular attention to unpacking the trade-offs attached to competitive procurement. Much of the analysis has also focused on power sector reforms and business models—which are intertwined with procurement and contracting mechanisms— and the way they influence the investment climate. After 20 years of reform efforts in Africa, nowhere on the continent is full wholesale or retail competition to be found in power sectors. Countries that have attracted the most finance have a wide range of sector policies, structures, and regulatory arrangements. In 13 such destinations for IPP investments, vertically integrated state-owned utilities predominate. The presence of a regulator is also not definitive in attracting investment. While the countries with the most IPPs all have formally independent regulators, some countries with regulatory agencies do not have any IPPs. Thus, what are the merits of competition? What are the key reform elements that can help African countries attract IPPs? What are the instruments that can help them strike the best deals? Five Main Conclusions Responses to these questions may be condensed into five main conclusions, as follows. Systematic and dynamic power sector planning is crucial to identify generation projects that best meet a country’s power needs and define the potential space for IPPs. The analysis has shown that much more important than unbundling or privatization are the more prosaic issues of dynamic power planning and related procurement and contracting processes. Sound planning means that countries are able to correctly project future electricity demand, decide on best supply (or demand management) options, and anticipate how long it would take to procure, finance, and build the required generation capacity. Planning tools, such as the Least Cost Power Development Plan (LCPDP) or the Integrated Resource Plan (IRP), need to be updated regularly to reflect changing demand patterns and cost data. Planning arrangements may vary, with the planning function entrusted to the government, the regulator, a new indepen- dent planning body, or attached to an independent system operator. In several countries in Africa this function remains within the national utility, in which case Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Conclusions 91 the government may exercise political leadership to ensure that the incumbent utility works in the national interest. Whatever the arrangements are, it is critical that the responsible agency be resourced with adequate capacity. Planning capac- ity also entails clear criteria for allocating new build opportunities either to state- owned utilities (if they are present) or to IPPs. Finally, there must be an explicit link between planning and the timely initiation of generation procurement processes. Unfortunately, far too many generation expansion master plans are not kept up to date, and even fewer are linked explicitly to the timely initiation of com- petitive procurement processes. These are the areas where technical assistance needs to be directed. Responsibility for planning needs to be allocated, and ade- quate resources devoted to building planning capacity and models. A key message is that power planning cannot be neglected. Competitive procurement of IPPs helps ensure that projects are implemented transparently and at the lowest cost. A common argument raised against competitive tenders or auctions is that they are complicated, take time to set up, are expensive to run, and have high trans- action costs for the governments that have to hire expensive transaction advis- ers, and the private companies that have to spend heavily to prepare compliant bids. Unsolicited, directly negotiated contracts, it is argued, can be concluded quickly and cheaply. However, 20 years of experience in power procurement in Africa has amply demonstrated that a lack of competition in procuring new generation capacity has extensive drawbacks, ranging from the immediate effects on project outcomes—higher prices, unraveling contracts, and so on—to more general effects on the overall governance of the electricity sector and its investment climate. The lessons from Tanzania’s experience with Independent Power Tanzania Ltd. (IPTL) could not be more explicit: when power is not planned, procured, and contracted transparently and consistently, the implica- tions are potentially grave, far-reaching, and ongoing. The assumption that direct negotiation can facilitate a rapid response in the face of supply emergencies is also erroneous. Energy solutions that entail stan- dard thermal projects can be awarded through a fast-track competitive process. There are a number of countries where competitive tenders have been run for thermal plants in short time frames and with good outcomes. Kenya is an example. There is no reason why more countries could not benefit from com- petitive tenders for these standard technologies. More important, in practice, direct negotiations may be lengthy. In many cases, governments faced with multiple IPP proposals from private developers, some with poor financial track records, do not have the capacity to assess the value of the projects and lack critical transaction skills to structure reasonable power purchase agreements (PPAs). Contracts are not standardized and risks are often unfairly skewed to the off-taker or government. Nontransparent negotiations may be subject to contro- versy or even corruption. The experience of the five case study countries includes notable examples of directly negotiated deals that either took too long Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 92 Conclusions or unraveled at the end. Even if an open tender is potentially more time inten- sive, any time “lost” is generally made up in the life of the project, in contrast to projects that are directly negotiated and are subject to more renegotiations and contract disputes. In sum, competitive bidding is associated with greater trans- parency and lower costs. In addition, standard contracts result in a fair allocation of risks. And projects are more likely to move to financial close, construction, and commercial operation. These benefits are most apparent in wind and solar auctions. They are also evident in competitive bids run for gas, diesel, and HFO generators. More competitive tenders should be run in a greater number of countries, both for standard thermal technologies as well as for other technolo- gies and contexts where competition is possible. IPP investments in Africa will rely on long-term contracts with off-takers (most often utilities, as seen around the world) where electricity demand is grow- ing at medium or high rates. In the future, off-takers may also be large customers. If the long-term contracts for new power are competitively bid rather than directly negotiated, then there is the potential for reduced prices. A further benefit of competitive tenders or auctions is that they can stimulate the development of a pipeline of potentially bankable projects, especially in renewable energy. A frequent lament in Africa is that there are not enough bank- able projects. Much of the emphasis is put on project development facilities and technical assistance to develop these projects. But more effort should be put into developing competitive tenders or auctions. If these are well designed, and held at regular intervals, then—as the South African Renewable Energy Independent Power Project Procurement Programme (REIPPPP) and the Uganda global energy transfer feed-in tariff (GETFiT) experiences show—investors will be will- ing to bid for and develop projects. Quite simply, African governments have not done enough to offer competitive tenders or auctions with clear ground rules; standardized, long-term contracts with IPPs; effective risk mitigation; and reliable timelines. In the absence of these, project developers and funders have offered unsolicited bids. But this can change, and many would argue that it should. Designing and running competitive tenders are not trivial tasks. But if a core government team is authorized to do the work and sufficient resources are allo- cated for this purpose, then experienced transaction advisers can be hired to help. And the benefits of lower prices invariably justify the initial cost of running these tenders. Once again, the South African, Kenyan, and Ugandan examples are revealing: each invested substantially in transaction advice and building capacity to design and implement competitive tenders. In South Africa’s case, the National Treasury made a substantial financial allocation so that the Department of Energy (DoE)-IPP unit could hire top-rate transaction advisers. Successful proj- ects in South Africa are required to pay a project development fee (1 percent of project cost), which goes into a DoE fund to pay for future tenders. Uganda had the support of a development finance institution (DFI) in designing effective GETFiT tenders. And Kenya learned, over successive tender rounds, how to build capacity to design and run effective tenders. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Conclusions 93 Competitive tenders for new power need to be initiated in a timely manner. It can take a year or more to run a competitive tender, and longer to reach finan- cial close, and even longer to construct the plant. Hence, there need to be clear plans for when power is needed and a realistic timeline for its procurement. There are examples of generation expansion plans explicitly linked to timely and competitive procurement, which in turn has yielded impressive investment and price outcomes. In South Africa, for one, there is a formal link between the promulgation of plans for the electricity sector and the allocation of megawatts for competitive auctions through ministerial “determinations.” Such a system has resulted in the initiation of a series of highly successful competitive auctions for grid-connected renewable energy, with price outcomes that are comparable to those achieved in the most mature power markets internationally. In this regard, Sub-Saharan Africa also has much to learn from the second wave of power sector reforms across Latin America, notably Brazil. Here the goal has been on planning and competition for long-term contracts that facilitate capital-intensive investments, backed by financially viable distribution utilities and appropriate risk mitigation, rather than relying on competitive wholesale spot markets. Also, all power purchased by distribution companies to meet their demand must be procured following competitive arrangements monitored by the sector regulator. Direct negotiations with unsolicited offers are not ruled out; sometimes they are unavoidable, but countries need to strive for greater transparency and more competitive prices. If a country still opts for an unsolicited bid, it should at least have in place effective systems and capabilities to evaluate projects and negotiate favorable contracts. A coherent generation expansion plan is a critical element, as it pro- vides a benchmark against which to screen proposed projects and their technical parameters. Transaction capacity is equally important. Governments that engage in unsolicited proposals or directly negotiated deals have very limited capacity to properly assess the cost-competitiveness of these projects and the technical and competitive financial capabilities of the project developers—and thus negotiate cost-­ contracts. As alluded to earlier, if governments are to consider unsolicited propos- als, they need to contract experienced transaction advisers and, over time, build sufficient capacity to evaluate projects and to negotiate fair contracts with cost- effective outcomes and the appropriate allocation and mitigation of risks. Open-book approaches are often adopted in these direct negotiations, with project developers sharing their financial models with governments, including projected rates of return on investment. However, there is invariably an asymme- try of information, and governments struggle to properly assess projected costs. Of course, unsolicited bids may be opened to more scrutiny by instituting a public tender (even if there is only one bidder, the public process may be used to guide and oversee the bid). Sponsors of unsolicited projects often argue that this would be unfair because of the costs they have incurred Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 94 Conclusions developing their projects. Several strategies are proposed to deal with investors who are reluctant to lose up-front capital or proprietary information via a competitive bid. Three such examples are the bonus system, Swiss challenge, and the best and final offer—all of which serve to compensate or privilege in varying degrees the original proposal while simultaneously managing a com- petitive and transparent process. The financial viability of utilities is a critical factor in attracting IPP investments. IPP contracts need to be with financially viable off-takers, whether they be utilities or large customers. Again, this is an obvious point, but it needs to be restated. Most IPPs are project financed and their bankability rests on secure rev- enue flows. While credit enhancement and security measures can mitigate risk, a financially strong off-taker provides a sustainable basis for securing long-term contracts with IPPs. In most African countries, state-owned utilities are the off-takers and ­ counterparties for IPP contracts—and may remain so for the foreseeable future. The hard work still needs to be done to improve the technical and financial performance of utilities that purchase IPP power and distribute it to mostly captive customers. There is no silver bullet to accomplish this; rather, it requires a suite of strategies and interventions aimed at improved corporate governance, performance and management contracts, billing and collections, loss reductions, and so on. A sustained effort to better the performance of utilities must be at the center of countries’ reform agenda and also be consistently supported by development partners through financial and technical assistance. Reforms, especially those improving the investment climate, remain important. Although IPP investment trends do not appear to be correlated with specific power sector institutional arrangements, the importance of reforms geared toward promoting a sound investment climate should not be discounted. Most electricity laws in African countries now explicitly make provision for private sector participation. Unraveling potential conflicts of interest between incumbent state-owned generators and IPPs, through unbundling generation from transmission, is in principle positive for private investment, as is more trans- parent contracting among state generators, IPPs, and independent transmission companies and system operators. Having a regulator in place is especially important, for two reasons. First, as part of its oversight role, the regulator can enforce competitive procurement and ensure that power purchase costs (including those from PPAs with IPPs), which are passed on to captive customers by distribution utilities, are actually least cost. Second, much of the investment climate hinges upon effective regulation. The financial sustainability of utilities and key aspects of their performance are enhanced by sound economic regulation that is transparent, credible, and consistent. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Conclusions 95 It should be emphasized that the mere existence of a regulatory agency does not determine investment and development outcomes. The potential advantages of greater transparency and certainty in establishing revenue requirements and setting tariffs can be outweighed if regulators have insufficient capacity and make arbitrary decisions. The quality of regulation capacity is nonnegotiable: the regu- lator must be independent and endowed with competent—and sufficient— human resources. In conclusion, investment in African IPPs is growing, but not fast enough. Africa does not have sufficient power. All sources of investment need to be encouraged. For IPPs to flourish, Africa needs dynamic, least-cost planning, linked to the timely initiation of the competitive procurement of new generation capacity. This must be accompanied by the building of effective regulatory capacity that encourages the distribution utilities that purchase power to improve their performance and prospects for financial sustainability—and to widen access to electricity. Such efforts promise to promote economic and social development across the continent. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 P art 2 Five Country Case Studies Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   97   C h apter 6 Case Study 1: Kenya’s Electric Power Promise Introduction Kenya is among the countries in Sub-Saharan Africa with the most extensive experience in independent power projects (IPPs). Its first IPPs date back to 1996, and since then the country has closed a total of 11 projects for a total of approxi- mately 1,065 megawatts (MW) and $2.4 billion in investment.1 While from a global standpoint these numbers are small, IPPs will soon represent more than one-third of Kenya’s total installed generation capacity. Most of the plants pro- cured over the past two decades use medium-speed diesel/heavy fuel oil (MSD/ HFO); some are geothermal and wind plants. And more IPPs are on the way: for example, in September 2014, a 900–1,000 MW coal plant was awarded to a consortium led by the Kenyan companies Gulf Energy and Centum Investment Company (MoEP 2014a; African Energy 2015).2 Despite this momentum, the actual process of procuring new geothermal and wind power has become more muddled and complex with a series of procurements conducted by the publicly owned Geothermal Development Company (GDC) and directly negotiated wind projects. What can be learned from Kenya’s IPP experience, particularly in terms of planning, procurement, and contracting? How do Kenya’s IPPs mea- sure up to their public counterparts, and what areas might require further improvement? In the first section of this case study, a history of the sector’s development is provided, followed by a description of its current structure, planning processes, and capacity. Prices and performance data are also presented. In subsequent sec- tions, the analysis focuses on how current capacity was procured and financed (from both public and private sources), as well as on future plans. Finally, conclu- sions are offered related to fundamental issues that have contributed to and detracted from power generation development in Kenya. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   99   100 Case Study 1: Kenya’s Electric Power Promise Kenya’s Electricity Sector: An Overview Past Sector Reforms The structure of Kenya’s electricity supply may be traced back to reforms that swept the industry in the mid-1990s. As the country emerged from an aid embargo, one of the main objectives of these reforms was to attract much-needed private sector investment to complement limited public sector funding.3 In a policy paper on economic reforms (Government of Kenya 1996), the government stated an intention to separate the regulatory and commercial ­ functions of the sector, facilitate restructuring, and promote private sector invest- ment. Consequently, the Electric Power Act of 1997 was passed. The govern- ment’s primary function, through the Ministry of Energy and Petroleum (MoEP), became policy formation, and its regulatory authority was devolved to a newly established Electricity Regulatory Board (ERB) that became functional in 1998. At the industry level, rationalization and unbundling redefined the scope of the Kenya Power and Lighting Company (KPLC, popularly known as Kenya Power),4 which had served as an integrated utility since 1954.5 Thus, from 1997 the KPLC began to focus exclusively on the transmission and distribution (T&D) of elec- tricity, while the Kenya Electricity Generating Company (KenGen) took over all public power generation activities. In its 2003 strategy document on economic recovery, the government expressed its dissatisfaction with the performance of the sector (Government of Kenya 2003), conceding that electricity in Kenya remained unreliable and expensive despite the reforms of the mid-1990s on. To remedy this, the strategy recommended measures to deepen reforms in the power sector. These were sub- sequently detailed in the national energy policy of 2004 (Government of Kenya 2004), which included an action plan for the period 2004–07 that set out the government’s commitment to: • Establish a rural electrification authority. • Facilitate the development of a competitive market structure for the genera- tion, distribution, and supply of electricity. • Establish the GDC to undertake an assessment of Kenya’s geothermal resources, including steam-field appraisal and development. • Enact new legislation to, among other things, dissolve the ERB and create a new energy sector regulator—the Energy Regulatory Commission (ERC).6 • Accelerate the increase in the rural electrification rate by 10 percent a year. • Partially privatize KenGen through an initial public offering of 30 percent of its equity through the Nairobi Stock Exchange.7 Most of these measures were implemented in the time frame identified, includ- ing the listing of KenGen on the Nairobi Stock Exchange in 2006. Exceptions were the development of a fully competitive market structure and the ambitious rural electrification target. In 2008, the Kenya Electricity Transmission Company Limited (KETRACO) was established to facilitate concessionary and donor funding in the network. The KPLC retained responsibility for operating the grid. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 101 Further reform efforts and strategic targets followed. In 2008, Kenya’s 2030 Vision (encompassing social and economic goals) set a new generation target of 23,000 MW by 2030. Rural electrification efforts would bring electricity to every home in Kenya (Ongwae 2012), with interim targets set for 2013 and 2022 (these have since been moved out to 2017 and beyond). In 2010, the govern- ment began work on a nuclear power project that has since been formalized through the Kenya Nuclear Electricity Board (KNEB), an institution within the MoEP. The initial aim was to generate 1,000 MW of nuclear energy by 2023 (Energy Monitor Worldwide 2014; Government of Kenya 2014: 46), but little progress has been made. In September 2013, the “5,000+ MW” capacity and expansion program was launched with the goal of bringing 5,000 MW online within 40 months.8 The program was heralded by the government of Kenya as the means to “trans- form Kenya, by providing adequate [generation] capacity at a comparative rate” (MoEP 2013a).9 Meanwhile at the generation level, the ERC affirmed that “electricity genera- tion in Kenya is liberalized,” with IPPs given an opportunity to enter the sec- tor and compete alongside the state incumbent, KenGen (ERC 2014a). A competitive market structure is a stated goal; the proposed National Energy and Petroleum Policy and Energy Bill 2015 suggests further reforms to legal and institutional frameworks to facilitate a competitive wholesale market structure in the country. (The extent of the proposed reforms will be probed in subsequent sections.) Even with 11 IPPs present in the industry,10 KenGen and the KPLC (both state-owned entities with significant private shareholding) remain the dominant players. There is no evidence of attempts to scale back or redefine their roles in what might be termed a hybrid market structure. Figure 6.1 is an overview of the industry’s current structure. The spaces defined as “generation” and “transmission and distribution” are still actively evolv- ing. Also noteworthy is the anticipated growth of imports and exports. Power Sector Practices While detailed long-term planning is often neglected amid the urgency of power sector reform across Sub-Saharan Africa, Kenya has reasonably good mechanisms in place for the planning of least-cost generation and transmis- sion capacity. The 2006 Energy Act states that one of the ERC’s objectives is to “prepare indicative national energy plans” (Clause 5 [g]) (Government of Kenya 2006: 22)—plans that were previously a regulatory function of the MoEP. To fulfill this new mandate, and building on the experience of the ministry, the ERC estab- lished the Least Cost Power Development Planning Committee in 2009, with representatives from the ERC (which chairs and provides the secretariat); the KPLC11; KenGen; KETRACO; the GDC; the MoEP; the Ministry of State for Planning, National Development and Vision 2030; the Rural Electrification Authority (REA); and the Kenya National Bureau of Statistics. Bringing these stakeholders together should enable the ERC to leverage the diverse skills and Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 102 Case Study 1: Kenya’s Electric Power Promise Figure 6.1  Overview of Kenya’s Electricity Sector Ministry of Energy and Petroleum (MoEP) Energy Tribunal Energy Regulatory (ET) Commission (ERC) Generation Geothermal Development Company (GDC) Kenya Electricity Generating Company (KenGen) Independent power Imports/exportsa projects (IPPs) Kenya Power and Lighting Company (KPLC) Rural Electrification Authority (REA) Transmission and distribution Kenya Electricity Transmission Company (KETRACO) Consumers Sources: MoEP 2013a; Kapika and Eberhard 2013. a. Imports and exports are as follows: Kenya buys/sells power from/to Uganda at 132 kilovolts (kV). Kenya also has cross-border trade with Tanzania and Ethiopia at 33 kV. It buys power from Tanzania at Lunga Lunga and sells to the country at Namanga, and buys power from Ethiopia at Moyale. New cross-border trade includes the following significant developments: a new 500 high-voltage direct current (HVDC) line between Ethiopia and Kenya with a power purchase agreement (PPA) signed for Kenyan imports of 400 megawatts (MW), from July 2018. A further PPA has been signed by Kenya, Rwanda, and Uganda, with Kenya exporting to Rwanda approximately 30 MW, via Uganda, starting in July 2015 (African Energy 2015). resources (including data) required for robust planning and provide a platform for building consensus, thus ensuring the credibility of the Least Cost Power Development Plan (LCPDP)—see Ministry of Energy of Kenya 2010. Plans are best based on solid, independent technical analysis (of, for example, the relationship between the gross domestic product [GDP], growth, and elec- tricity demand; sectors that drive GDP growth; existing investments in infra- structure that might absorb incremental capacity; and the technical integration of technologies). In the past five years (from 2010), the demand estimates used Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 103 have been directed by the government, and have tended to be unrealistically high. Linked to this, a number of generation projects have been procured through direct negotiations, and without a thorough technical and financial analysis to determine whether the proposed plants meet least-cost planning standards. The 2011–31 LCPDP was modified to support the 5,000+ MW program, launched in 2013 by the MoEP (see annex 6A for details), and to champion the development of indigenous resources, including geothermal power, wind power, coal, and, potentially, gas.12 Integral to the new generation program was the promise that tariffs would drop by almost half (ERC 2014b).13 Nearly two years from its inception, the 5,000+ MW program has been radically scaled back. Plans for a liquefied natural gas (LNG) project have been shelved, and a coal project postponed well beyond any 40-month time horizon. Large LNG and coal power projects were the cornerstone of the program; together, these two devel- opments represented the majority (3,000 MW) of the new capacity to come online, while most of the balance is associated with preexisting projects. Industry experts had long warned that massive capacity additions pose high risks to an energy sector’s sustainability unless matched by demand.14 The ideal supply profile in the critical dry season should be 15–20 percent more than the peak demand; thus, the inclusion of massive coal and LNG projects has the potential to distort Kenya’s electric generation supply landscape. The rollout and subsequent scaling back of the 5,000+ MW program sheds light on how planning and procurement are handled in the nation, as well as the role that the private sector has played and will continue to play. The LCPDP does not identify any explicit criteria for the allocation of new build opportunities, a common challenge in hybrid markets. When KenGen is unable to finance new investments, the private sector is invited to participate. Typically, bids for IPPs are requested by the KPLC, and winners selected via a competitive process, although in some cases (such as for the emergency thermal generators required in 2000 and 2011, and tenders for large LNG and coal plants in 2014) procurement has been handled by the government directly or through its appointed agent, KenGen. The government, through the Ministry of Energy (MoE), may also con- sider unsolicited bids. Installed Generation Capacity As of April 2015, Kenya’s total installed capacity stood at 2,159 MW.15 Of this total, KenGen’s installed capacity amounted to 72 percent; IPPs made up the major- ity of the balance. Table 6.1 highlights KenGen’s total capacity as of April 2015. The recent shift to a mix of publicly financed energy supply has increased reliance on geothermal energy and encouraged the emergence of wind energy. Geothermal energy increased from 12 percent of KenGen’s total installed capac- ity in 2006 to 32 percent as of April 2015. The share of installed wind capacity, though relatively small (at 1.6 percent), has increased substantially from its base and is expected to increase further after additions at Meru. The share of tradi- tional thermal gas and diesel has become less significant (at 15 percent) as it is displaced by geothermal. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 104 Case Study 1: Kenya’s Electric Power Promise Table 6.1  KenGen’s Installed Generation Capacity: Kenya, as of April 2015 Technology % of capacity Project Capacity (MW) PPA (years) CODa Major hydros 48.93 Various 765.5 20 2008 Medium hydro 1.28 Sang’oro 20 20 2012 Small hydro 0.75 Various 11.7 15 2009 Isolated thermal 0.35 Lamu 2 15 2009 Garissa 3.4 15 2009 Small wind 0.35 Ngong old 0.35 15 2009 Ngong I Phase I 5.1 15 2009 Wind 1.30 Ngong I Phase II 20.4 20 2015 Geothermal 32.40 Olkaria I (Units 1, 2, and 3) 45 4 2013 Olkaria II 105 20 2008 Olkaria IV 140 25 2014 Olkaria I (Units 4 and 5) 140 25 2014 Well head 37 2.5 15 2012 Well head 43 2 15 2012 Well head 1 20 15 2012 Well head 2 20 15 2012 Well head 3 30 15 2012 Eburru 2.44 20 2012 Thermal/diesel 11.19 Kipevu Diesel Power I 60 15 2008 Kipevu Diesel Power III 115 20 2011 Thermal/gas 3.45 Embakasi Gas Turbines 54 3 2013 Total 100.00 1,564.39 Source: Based on data received from the Kenya Power and Lighting Company, 2015. Note: KenGen = Kenya Electricity Generating Company; MW = megawatt; PPA = power purchase agreement. a. COD refers to the commercial operation date of the latest PPAs, as some plants, especially hydropower, have been redeveloped, and Olkaria I (Unit 1) has been in operation since 1981. IPPs together account for approximately 26 percent of the installed capacity in Kenya (or 565 MW)—see table 6.2.16 Most capacity is supplied by diesel gen- erators (78 percent), followed by a geothermal installation (OrPower4, 18 per- cent) and a cogeneration installation (5 percent). The percentage of IPP capacity has grown considerably since 2005, when IPPs accounted for only 12 percent of installed capacity. Sponsors have been diverse, as will be discussed in the follow- ing sections, and technology types are increasingly varied. Total installed generation capacity also includes emergency power projects (EPPs), which today account for only 30 MW (2015) or less than 1 percent of the total. Dependence on EPPs has fluctuated considerably over the past decade; their peak was in 2008 and 2009, when EPP installed capacity amounted to 11 percent of the total. Power Sector Performance How have KenGen and IPPs measured up in terms of the actual electricity pro- duced and its availability, price, and capacity factors? What does a comparison of public and privately procured plants reveal? Can it offer lessons for future pro- curement processes? Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 105 Table 6.2  Independent Power Projects, Installed Generation Capacity: Kenya, as of April 2015 Technology % of capacity Project Capacity (MW) PPA (years) COD MSD/HFO 9.99 Iberafrica Power Company 56.346 7 + 15 2004a (plant 1) MSD/HFO 9.30 Iberafrica Power Company 52.5 25 2009 (plant 2) MSD/HFO 13.11 Tsavo Power Company Ltd. 74 20 2001 MSD/HFO 15.67 Rabai Power 88.4 20 2010 MSD/HFO 15.42 Thika Power (Melec) 87 20 2014 MSD/HFO 14.18 Gulf Power 80 20 2014 Geothermal 17.72 OrPower4 Inc. 48 20 2009 Geothermal OrPower4 Inc. 36 20 2013 Geothermal OrPower4 Inc. 16 20 2014 Cogeneration 4.61 Mumias Sugar Company Ltd. 26 10 2010 Total 100.00 564.246 Source: Based on data received from the Kenya Power and Lighting Company, May/June 2015. Note: Triumph Power, an 83 MW MSD, was expected to reach COD by 2Q2015. Excluded from this table are the small independent hydropower plants Imenti Tea Factory and Gikira, which amount to 0.75 MW and 0.514 MW, respectively. COD = commercial operation date; MSD/HFO = medium-speed diesel/heavy fuel oil; MW = megawatt; PPA = power purchase agreement. a. Fifteen-year PPA starting in 2004. Electric Power Production In the period July 2013–June 2014, the latest for which complete data are available, KenGen produced 5,931 gigawatt-hours (GWh) of electricity, or 67 percent of the total (of which approximately 67 percent was KenGen hydropower installations, and the balance was largely geothermal, accounting for 19 percent). This was followed by IPPs at 31 percent, EPPs at 1 percent, and a total of 1 percent contributed by imports and the government’s Rural Electrification Programme (REP), as illustrated in figure 6.2. This represents a change from 2012–13, when KenGen’s portion amounted to 74 percent and IPPs to only 22 percent. Thika Power has come online and production has been ramped up at Rabai as well. Assessing IPPs individually reveals an important piece of evidence. Iberafrica, with the second-largest installed capacity, is providing only 20 percent of genera- tion (a significant drop from previous years). Instead, OrPower4 is contributing the largest piece of the production pie, followed by Rabai. Tsavo’s portion is relatively small due to merit-order dispatch and transmission constraints. An ­ expansion of the Mombasa-Nairobi electricity transmission line has been delayed, limiting the further evacuation of power, which has had an impact on many plants (Obiero 2015), though not on the Nairobi-based Iberafrica IPP. (See figure 6.3 for the contribution of the various IPPs.) At the end of 2014, a significant development occurred: for the first time in Kenya’s history, geothermal production (public and private combined) sur- passed hydropower (see table 6.3), with important ramifications for supply going forward. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 106 Case Study 1: Kenya’s Electric Power Promise Figure 6.2  Electricity Production, by Firm/Organization Type: Kenya, 2013–14 percent EPPs, 94 GWh, Imports and REP, 117 GWh, 1 1 IPPs, 2,697 GWh, 31 KenGen, 5,931 GWh, 67 Source: Authors’ compilation, based on KPLC 2014. Note: EPP = emergency power plant; GWh = gigawatt-hour; IPP = independent power project; KenGen = Kenya Electricity Generating Company; REP = Rural Electrification Programme. Figure 6.3  Electricity Production of Six Independent Power Projects: Kenya, 2013–14 percent Mumias, 57 GWh, 2 Tsavo, 152 GWh, 6 OrPower, 4,851 GWh, 32 Thika, 454 GWh, 17 lberafrica, 550 GWh, 20 Rabai, 633 GWh, 23 Source: Authors’ compilation, based on KPLC 2014. Note: GWh = gigawatt-hour. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 107 Table 6.3  Total Production, by Technology/Fuel: Kenya, 2013 and 2014 percent Technology/fuel 2013 2014 Biomass 0 0 Wind 0 >0<1 Thermal 37 10 Hydro 46 38 Geothermal 14 51 Source: Based on data received from KenGen (Kenya Electricity Generating Company), June 2015. Availability Kenya offers an interesting opportunity to directly compare the performance of the state-owned power plant with that of IPPs using similar technology. Plant availability is arguably the best indicator of that performance (see table 6.4 for a comparison of the actual and targeted availability of private and public plants using similar technology). With the exception of Kipevu I, all diesel projects, public and IPP alike, have met their availability target; however, IPPs with diesel projects have outper- formed their public sector equivalents. The same may be said of geothermal plants (see table 6.5), although the technology is not comparable: KenGen plants are flash while OrPower4 uses binary technology (expected to offer bet- ter availability). KenGen’s Olkaria I (Units 1, 2, and 3) was available only 68.3 percent of the time in 2014—far below its target and the performance of its private sec- tor counterparts. This low share may in part be due to age: Olkaria I’s units are 30–33 years old (dating from 1981–85). Also, it should be noted that KenGen plants must follow public procurement procedures; delayed payment processes do not allow fast access to critical parts in the event of an emergency, an issue that may affect overall performance. Table 6.4  Actual and Targeted Availability of Public and Private Diesel Plants: Kenya, April 2015 percent Plant Ownership Actual availability Targeted availability Tsavo Power Company Ltd. IPP 97.21 85.00 Thika Power (Melec) IPP 95.72 85.00 Kipevu Diesel Power III KenGen 94.58 85.00 Iberafrica Power Company (plant 2) IPP 93.92 85.00 Gulf Power IPP 93.60 85.00 Rabai Power IPP 91.65 85.00 Iberafrica Power Company (plant 1) IPP 87.95 85.00 Kipevu Diesel Power I KenGen 66.95 85.00 Source: Based on data received from the Kenya Power and Lighting Company, May/June 2015. Note: IPP = independent power project; KenGen = Kenya Electricity Generating Company. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 108 Case Study 1: Kenya’s Electric Power Promise Table 6.5  Actual and Targeted Availability of Public and Private Geothermal Plants: Kenya, April 2015 percent Project Ownership Actual availability Targeted availability OrPower4 (16 MW) IPP 99.79 96.00 OrPower4 (48 MW) IPP 99.17 96.00 OrPower4 (36 MW) IPP 97.82 96.00 Olkaria IV KenGen 96.45 94.00 Olkaria I (Units 4 and 5) KenGen 95.15 94.00 Olkaria II KenGen 84.30 94.00 Source: Based on data received from the Kenya Power and Lighting Company, May/June 2015. Note: OrPower4 represents only one project, of which different units are recorded in the table. IPP = independent power project; KenGen = Kenya Electricity Generating Company; MW = megawatts. Electricity Prices While data on plant availability demonstrate the technical superiority of IPPs over KenGen, electricity prices offer a more nuanced picture. It should be noted at the outset that a direct comparison between KenGen and IPPs is not possible, since they pay different costs for their capital. While KenGen has raised private capital via bond issues, it has also accessed loans from development finance insti- tutions (DFIs). See table 6.6 for a comparison of KenGen and IPP (and EPP) diesel plants; the values listed represent the sum of energy, fuel, capacity charge, and forex adjustment. The two KenGen plants are largely more competitive than IPPs; however, Rabai IPP distinguishes itself as the cheapest of all. Apart from the cost of capi- tal, there are important additional qualifiers related to specific technologies and location that explain some of the cost discrepancies. Rabai has a heat- recovery system, which improves efficiency and is located close to the port of Mombasa (and the plant’s fuel source). But this system explains part of the cost difference when Rabai is compared with the Tsavo IPP and KenGen’s Kipevu I and Kipevu III plants, also located in Mombasa. Thika Power and Gulf IPP have heat-recovery systems as well, but these plants are located up-­ country, near Nairobi, and must pay the additional fuel cost for transportation from Mombasa (about 500 kilometers, km). Iberafrica, located in Nairobi, must also pay an additional cost, and has technology similar to that of KenGen’s plants and the Tsavo IPP. Among geothermal plants, most of the publicly owned KenGen plants are relatively more competitive; Olkaria II is a notable exception, having proved more costly than OrPower4 (table 6.7). In sum, though KenGen remains the dominant producer, IPPs contribute an important share: 30 percent of production in 2013–14. Meanwhile, supply (from private and public sources alike) is changing amid increased reliance on geother- mal power. The technical performance of IPPs, as gauged by actual and target plant availability, appears to be superior to that of publicly owned plants (for both diesel and geothermal). An HFO IPP—Rabai—is cheaper than the KenGen Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 109 Table 6.6  Electricity Prices of Public and Private Diesel Plants: Kenya, June 2015 Project Technology Location Ownership Price (K Sh/kWh) Price (US$/kWhb) Iberafrica Power Company (plant 1) MSD/HFO Nairobi IPP 22.82 0.25 Iberafrica Power Company (plant 2) MSD/HFO Nairobi IPP 22.61 0.25 Temporary power plants (Aggreko) MSD/HFO Various EPP 20.99 0.23 Gulf Power MSD/HFOa Near Nairobi IPP 20.43 0.22 Thika Power (Melec) MSD/HFOa Near Nairobi IPP 19.86 0.22 Tsavo Power Company Ltd. MSD/HFO Mombasa IPP 19.84 0.22 Kipevu Diesel Power I MSD/HFO Mombasa KenGen 17.70 0.19 Kipevu Diesel Power III MSD/HFO Mombasa KenGen 15.86 0.17 Rabai Power MSD/HFOa Mombasa IPP 12.74 0.14 Source: Based on data received from the Kenya Power and Lighting Company, May/June 2015. Note: EPP = emergency power project; HFO = heavy fuel oil; IPP = independent power project; KenGen = Kenya Electricity Generating Company; K Sh = Kenya shilling; kWh = kilowatt-hour; MSD = medium-speed diesel. a. Gulf, Thika, and Rabai have heat-recovery systems and thus greater efficiency rates. b. Assuming the average conversion rate in April 2015 of $1 = K Sh 91.57. Table 6.7  Prices among Public and Private Geothermal Plants: Kenya, June 2015 Project Ownership Price (K Sh/kWh) Price (USc/kWh) Olkaria II KenGen 12.97 0.14 OrPower4 IPP 8.99 0.10 Olkaria IV KenGen 6.14 0.07 Olkaria I (Units 4 and 5) KenGen 5.91 0.06 Olkaria I (Units 1, 2, and 3) KenGen 3.09 0.03 Source: Based on data received from the Kenya Power and Lighting Company, May/June 2015. Note: IPP = independent power project; KenGen = Kenya Electricity Generating Company; K Sh = Kenya shilling; kWh = kilowatt-hour; USc = U.S. cent. plants at the same site. Meanwhile, the costs of KenGen geothermal plants appear to be more competitive than those of IPPs, but the comparison is ham- pered by differences in funding sources, technologies, locations, and the avail- ability of spare parts. Independent Power Projects, Emergency Power Projects, and Publicly Sponsored Power Plants Private participation in generation is not new to Kenya; what is new, how- ever, is the anticipated scale. Until recently, private power played a subsidiary role (as of 2013–14, after almost two decades of development, IPPs accounted for 26 percent of installed generation and 31 percent of produc- tion). But it is expected to play the lead. Of the near-term capacity envi- sioned in the 5,000+ MW program, the majority (70 percent) would be through the private sector (with KenGen and GDC developing the balance, or 30 percent).17 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 110 Case Study 1: Kenya’s Electric Power Promise In this context, it is instructive to review how private and public plants have been procured in parallel over the past two decades, and how this might inform the next series of procurements.18 First Wave: The Stopgap Independent Power Projects, c. 1996 The first wave of privately financed power, dating to 1996,19 involved the pro- curement of two diesel IPPs: Westmont (46 MW) was sponsored by a Malaysian firm, and Iberafrica (44 MW) represented a partnership between Union Fenosa (Spain, 80 percent) and the KPLC Pension Fund (Kenya, 20 percent). While no international competitive bidding was conducted, there was competitive ­ bidding from a restricted list of bidders drawn from a longer list of bidders that had shown interest in the Kipevu II project, discussed shortly. With a tenure of seven years, longer than that of most EPPs, these first two IPPs were considered stopgap measures addressing drought and the delayed construction of projects envisioned in the LCPDP—and an ensuing power crisis. Westmont would not renew its contract in 2004 after it failed to agree on tariff levels. Iberafrica, mean- while, renewed its contract (albeit on more favorable terms to country stakehold- ers) and increased capacity (first by 12 MW, then an additional 52 MW) to reach 108.5 MW in 2015. Second Wave and a KenGen Comparison, c. 1997–99 Prior to the stopgap IPPs, all power projects had been implemented by the public sector through the concessionary funding of bilateral and multilateral funding agencies, including the World Bank (International Development Association, IDA). Amid a move to reform and liberalize the sector, and a corresponding lack of funding, the private sector was invited to develop genera- ­ tion projects. In 1996, the KPLC resumed a procurement process (initiated in 1995, prior to the stopgap IPPs), following an international competitive bid (ICB), for two projects—Olkaria III and Kipevu II—which came to be known as OrPower4 (varying MW20/geothermal) and Tsavo (74 MW/diesel), respec- tively. OrPower4 was exclusively developed by Ormat (Israel/USA, 100 per- cent), while Tsavo represented a consortium of investors: Duke Energy and Industrial Promotion Services (IPS) (jointly 49.9 percent), Commonwealth Development Corporation (CDC)/Globeleq (United Kingdom, 30 percent), Wartsila (Finland, 15 percent), and the International Finance Corporation (IFC, 5 percent). Although both projects were procured via ICB, it is noteworthy that only three bids were received for the Tsavo plant and two for what would become OrPower4.21 During this same period (1997–99), KenGen would also develop Kipevu I (a 75 MW diesel-fired plan). Despite tightening purse strings and a shift toward privately funded generation, funding was secured from the Japan International Cooperation Agency (JICA, then the Japan Bank for International Cooperation [JBIC]) for this project. An ICB for engineering, procurement, and construction (EPC) was conducted for KenGen’s Kipevu I, as for OrPower4 and Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 111 Tsavo—the standard for all public and private plants, unless procured through feed-in tariffs (FiTs) (discussed in chapter 4) or under other conditions pre- scribed by procurement laws. The Development of Emergency Power Projects, c. 2000–10 In the years that followed, amid worsening hydrological conditions, the MoEP directly arranged EPPs. There was limited competitive bidding: that is, bids were invited from a short list of known international EPP providers. Ultimately, con- tracts with three international EPPs (Aggreko, Cummins, and Deutz) for a com- bined 105 MW would be sealed for rental capacity between 2000 and 2001. In 2006, Aggreko would be called upon, again, to provide 80 MW, and in 2007, its contract would be extended and increased to 100 MW, and then 150 MW. By 2009, Aggreko had 290 MW of emergency power. By mid-2010, however, the requirement was reduced (to only 60 MW), with a plan to retire all such emer- gency power by November. The reemergence of drought in the latter part of 2010 prompted a reconsideration of that plan, and the installation of 60 MW at Muhoroni. In 2012, there were 120 MW of EPPs; this has since been reduced to a mere 30 MW (KPLC 2006: 68; 2007: 98; 2008: 104; 2009: 100; 2010: 104; 2011: 115; 2012). A Brief Hiatus and Complementary Developments, c. 2004–09 Although no new IPP procurements were conducted for nearly a decade, additional capacity, as alluded to earlier, would be added for Iberafrica and OrPower. Iberafrica renegotiated the terms of its tariff and a second power purchase agreement (PPA) starting in 2004. The next IPP, conducted via an ICB in 2007, would be Rabai (90 MW diesel). Only four bids were received, although more than for Tsavo and OrPower4. Following the award, legal challenges led to an eight-month delay;22 further challenges involved the changing political climate in Kenya in 2008 (and associated postelection ­ violence) as well as the meltdown of global financial markets. Still, the proj- ect closed in 2008 and came onstream in 2009. Project equity stakeholders included Aldwych (United Kingdom, 34.5 percent), Burmeister & Wain (Danish, but owned by Mitsui of Japan, 25.5 percent), the Netherlands Development Finance Company (FMO) (Netherlands, 20 percent), and the Danish Investment Fund for Developing Countries (IFU) (Danish bilateral lender, 20 percent). During this period, KenGen also made advances on Olkaria II, a geothermal installation. In 2003–04, the first 70 MW came online, followed by the balance in 2009, resulting in a total of 105 MW.23 This complemented KenGen’s existing geothermal capacity (Olkaria I, 3 × 15 MW units, which had been phased in over the 1980s). At the same time, KenGen was tasked with the Kipevu III extension of 120 MW (diesel), which came online in 2011. This too followed an ICB for its EPC. In each of these instances, public and private procurements were considered to be complementary, not competitive. Decisions were made by the government Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 112 Case Study 1: Kenya’s Electric Power Promise in consultation with the KPLC, the World Bank, and other sector donors. To mobilize adequate funding for capacity expansion, those projects considered likely to attract private sector funding were offered to IPPs, all via ICB, excluding the first round of stopgap IPPs. Procurement, with the KPLC at the helm, has widely been considered to be positive, specifically with regard to running effec- tive competitive bids for thermal capacity. A Renewed Push from the Private Sector, c. 2010 Finally, in 2010, the KPLC began a series of procurements. The first related to three diesel generators (Kitengela I, Kitengela II, and Nairobi, today commonly known as Triumph,24 Gulf,25 and Thika26) of approximately 80 MW each via an ICB. A total of 31 expressions of interest were received, followed by 23 prequali- fying bids, for all three plants. Subsequently five bids were received for Kitengela I, five for Kitengela II, and then two for Nairobi, which was retendered.27 The second procurement related to a 52 MW extension at OrPower4. There was considerable competition for the three diesel generators. This shows how much the sector has evolved since the late 1990s, when the first ICBs resulted in Tsavo and OrPower4. It is also noteworthy that, for OrPower4, the initial pro- curement (of 13 MW) was done using ICB; however, since the late 1990s, the plant has added a further 97 MW in capacity (in three different phases), none of them with a competitive bid process. OrPower4 pricing has become a benchmark for private geothermal in Kenya and across Sub-Saharan Africa, but there has been no direct private competition to this benchmark since 1997. Emerging Renewable Technologies in Kenya Although Kenya has a history of small public geothermal investments and IPPs dating to the 1980s and late 1990s, respectively, there has been limited public and private renewable activity besides publicly funded hydropower. Kenya’s nascent wind and new geothermal activity marks a departure from earlier trends, and is the focus of the following section. Feed-in Tariffs and Support for Renewables Specific interventions to accelerate renewables in Kenya date to 2008, with the FiT policy. The first iteration of this policy did not attract investors, and tariffs were subsequently reviewed in January 2010 (Climatescope 2014). A second FiT regime was introduced in 2012. The parameters were as follows: wind p ­ rojects’ capacity was to reach 50 MW, and an earlier applicable tariff of USc 12/kilowatt- hour (kWh), fixed over the term of the PPA, was capped at the weighted average long-run marginal cost of generation. The current tariff is U.S. cents (USc) ­ 11/kWh, 12 ­ percent of which is scalable according to the U.S. dollar consumer price index (CPI). A number of renewable projects have been approved, namely, the Kinangop Wind Farm (60 MW), Kipeto Wind (100 MW), Kwale Sugar Mill (18 MW), and several small projects in the range of 0.5 to 2.0 MW.28 It is impor- tant to note that these projects do not involve a specific payment security Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 113 instrument, such as a letter of credit from the KPLC. They do, however, have a letter of project support from the government, which, while not a ­ guarantee, ­carries weight. Kinangop, Kenya’s first FiT project, developed by Aeolus Wind Kenya and now funded primarily by the African Infrastructure Investment Fund 2 (AIIF2), Norfund, and Stanbic, reached financial close in 2013. During the development stage, Aeolus reached agreements with l ­andowners, but in the ensuing months, more landowners in the area made additional claims. In February 2015, there was a series of protests, and an altercation between the community and police resulted in one civilian death. The Kenyan government made attempts to resolve the issues involved; in the meantime, the EPC contractor, which had been restricted from the site, exercised its right to declare force majeure. As of the third quarter of 2015, the project had been halted. Donors and financiers such as Power Africa, the World Bank, Agence Française de Développement (AFD), the African Development Bank (AfDB), the Kreditanstalt für Wiederaufbau (KfW, German development bank), and the European Investment Bank (EIB), among others, are increasingly providing sup- port and advisory services to help such projects reach financial close. Looking at the broader electricity landscape, however, an increase in wind capacity may make poor economic sense for Kenya. While less costly than imported thermal power, wind may substantially increase the price of electricity to users (displacing low-cost geothermal and hydropower-generated energy, for variable power at approximately USc 10–12/kWh), and potentially increase grid instability. Finally, it is important to note that while Kenya’s development partners have programs targeting the promotion of renewables through private sector participa- tion, Kenya itself offers no special incentives for renewables, other than the FiTs. As has been noted, coal and, until recently, LNG formed the bulk of proposed new capacity. The government’s focus has been, first and foremost, to increase the supply of reliable and competitive power, primarily through indigenous resources. Renewables—most notably geothermal and (soon) wind power, and to a lesser extent solar power—are part of the equation but do not enjoy favored status. Directly Negotiated Renewable Projects Departing from the well-defined procurement process for thermal IPPs—with the KPLC at the helm and the REFiT process outlined earlier—in 2011, a PPA was negotiated with the Lake Turkana Wind Project (LTWP). The LTWP was not part of the LCPDP of 2009. Instead, the project was initiated as an unsolicited bid directly with the government of Kenya at a time when the government was actively promoting renewable energy, but before it formulated the FiT policy and the later Public Private Partnership Act. Importantly, the ERC was not involved at the time of project initiation. Given the absence of a valid comparator—that is, a private wind project procured via an ICB—it is difficult to assess the LTWP’s outcomes and cost-effectiveness. The next large wind project, Kinangop Wind Farm, is a FiT, not an ICB. The tariff negotiated for the LTWP under the PPA has a base rate of ic 7.52/kWh for up to 1,684 GWh and ic 3.76/kWh for Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 114 Case Study 1: Kenya’s Electric Power Promise any additional power, with 14 percent of the base tariff scalable, and linked to the euro area CPI. This appears to be competitive with the present FiT wind tariff of USc 11/kWh. However, the capacity factor assumed for the LTWP is significantly higher than that for the FiTs, which makes the comparison less accurate.29 Regardless, both Turkana and Kenya FiTs are expensive when com- pared with recent competitively bid wind FiTs, including the South African Renewable Energy Independent Power Project Procurement Programme (REIPPPP), at USc 4.7/kWh. Geothermal Development Following the unbundling of the KPLC in 1997, KenGen assumed ownership of Kenya’s public generation facilities. Thirty percent of the entity would go on to be privatized following the power sector reform strategy, as outlined earlier. Among the next significant developments was the creation of the GDC in 2008 (operational in 2009). The GDC, a 100 percent government-owned entity, was given all mining rights for geothermal steam in the country with the exception of those held by KenGen and Ormat (at Olkaria), as well as those that had already been concessioned by the government (Longonot, Akiira, and Suswa).30 The company was expected to handle the most risky part of geothermal activity (namely, exploration, appraisal, and production drilling) and thereby remove much risk from project development. It was also expected that the GDC would then sell steam to IPPs and KenGen.31 The GDC and geothermal activities in Kenya have been supported by a diverse array of multilateral, bilateral, and regional development partners, most notably the IDA, EIB, AFD, AfDB, and JICA.32 The GDC should be increasingly funded by revenue generated from steam sales to IPPs and KenGen. However, this hinges upon the success of the geothermal power projects fueled by steam from the GDC, as well as a steam-pricing strategy that is attractive to investors. As the GDC undertakes risky geothermal exploration on behalf of the govern- ment, some form of subsidy may continue to be required depending on the nature and extent of the exploration activities. Despite a multimillion-dollar investment in the GDC and pressure to meet the power supply targets associated with Kenya’s 5,000+ MW program (by pro- viding steam to IPPs and KenGen), since its inception the company has been able to source only limited steam. Between 2010 and 2014, three expressions of inter- est (EoIs) were invited for 400 MW (revised to 800 MW, phase II at Menengai) and 800 MW (at Bogoria-Silali), as well as for 300 MW at Suswa. In 2014, the GDC finally managed to award three contracts of 35 MW each, for a total of 105 MW, at the Menengai field. It is important to note the large gap between what was originally invited by the GDC—namely, 1,900 MW of geothermal activity (between 2010 and 2014)—and the 105 MW that is expected to reach financial close. While the initial capacity targets may have been inflated, other issues specifically related to the GDC and its business model may have hampered the procurement pro- cess as well. First, the availability of the requisite steam supply was uncertain. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 115 Second, no government guarantee or support was initially extended for the proj- ects, which may have detracted from their viability since the GDC itself has no equity. All the funds the GDC invested have come from the government of Kenya and the soft loans of development partners.33 The 105 MW Menengai project has since received the backing of the AfDB, which provided $12.7 ­ million in partial risk guarantees (PRGs). This should help secure financial backing for three projects sponsored, respectively, by the Sosian Menengai Geothermal Power Ltd., Quantum Power East Africa (QPEA) GT Menengai Ltd., and OrPower (22 Ltd.) (AfDB 2014; Ormat 2014). QPEA GT and Sosian are Kenyan firms and their indicative price is USc 8.5/kWh (inclusive of the steam price of USc 3.0/kWh). The GDC remains unable to stand on its own. Meanwhile, steps forward are still being made. The first target of new capacity additions set under the 5,000+ MW program (see annex 6A)—namely, 176 MW by October 2014—has been met, albeit not by the GDC. By end-2014, KenGen had connected the entire 280 MW from Olkaria I and IV to the national grid, which led geothermal to surpass hydropower as a source of electricity. Plans are now taking shape for an additional 350 MW by 2017 (Herbling 2014; KenGen 2014a). While the GDC drilled some wells on behalf of the govern- ment, it is not expected to be active in the 280 MW project in Olkaria going forward. The GDC and KenGen are, however, required by the MoEP to enter into an agreement under which the GDC will receive royalties for steam from KenGen (USc 3/kWh). Although the GDC and KenGen may not compete at Olkaria, the clear designation and development of projects, along with appropriate safeguards, has ­ yet to be established. One experienced stakeholder commented, “at present, I think all real new geothermal developments will probably be done by KenGen depending on their credit capacity. [There is little] room for IPPs. The business conditions that allowed the successful development of OrPower4, do not exist presently in Kenya” (March 20, 2015). Independent Power Plants: Risk Mitigation Mechanisms and Other Contingencies Of the stopgap IPPs, Westmont and Iberafrica, the first involved an escrow account and the second an advance payment cash deposit.34 Thereafter, in the initial phase of IPP development (1997–98), the KPLC was required to provide two-tier payment securities in the form of a standby letter of credit (SBLC) and escrow accounts (ring-fencing part of the coastal area receivables as a payment guarantee). This double security was requested because of Kenya’s poor credit rating and the KPLC’s weak balance sheet35 (a weakness exacerbated by the severe drought of 1999–2001). The ERB’s (now the ERC’s) failure to take reme- dial action on the KPLC’s retail tariffs (vs. KenGen’s bulk tariff) caused the company to incur financial losses over four consecutive fiscal years. The two-tier payment security arrangement was not applied in subsequent IPP projects for the following reasons: (1) the KPLC’s return from the sunk Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 116 Case Study 1: Kenya’s Electric Power Promise escrow fund was not optimized; (2) the KPLC incurred the additional costs of a double security; and (3) there were additional administrative costs, including for staff dedicated to ring-fencing the revenues and ensuring that the billing system could collect captive receivables. Subsequently, for the three medium-speed diesel generators procured from 2010, the KPLC provided an IDA-backed ­ PRG with a government letter of support for an off-taker termination default. According to stakeholders consulted at Thika Power: “I think [the World Bank] role was essential—these projects [referring to all 3 diesel generators] would have taken ages to close without a PRG” (personal communication, May 7, 2014). In the case of the LTWP, a PRG of i20 million was extended by the AfDB for the timely completion of the transmission line. This also covered the off-taker risk of the nonpayment of monthly invoices, and the risk of the PPA’s termination (AfDB 2013). Meanwhile, a payment security for the LTWP was to be provided via an escrow account, raised via a tariff increase starting in 2013. For Menengai Phase I (3 × 35 MW geothermal projects), initially the only security was a government letter of support in the case of termination due to default by the KPLC/GDC. The idea of not providing liquid security was to remove the contingent liability of the SBLC. In fact, the KPLC intended to use the available SBLC capacity to support distribution expansion projects. Also, the Kenyan IPP market was believed to be sufficiently mature. However, given the GDC’s financial fragility, this security proved to be insufficient. Since, the project has necessitated the backing of the AfDB, in the form of a PRG covering the KPLC payment default as well as a default stemming from the failure of the GDC to supply enough steam. Going forward, PRGs appear to be the most likely form of risk mitigation. There are no guarantees for FiTs, and this may be an area for further improve- ment. Most prospective investors (excluding FiTs) appear to be satisfied with the KPLC’s track record of timely payments of IPP invoices, and the KPLC has never defaulted. There is, however, concern about how the KPLC’s creditworthiness will be affected by the large surplus capacity that may result from the recently signed PPAs, including some under construction (which made up part of the 5,000+ MW program), as well as what may happen as a wholesale market takes shape. In some of the PPAs presently under negotiation, the KPLC has intro- duced a clause moving the market risk from the KPLC to the government (through a letter of support) and another stating that, should there be a whole- sale market, the parties can consult with a view to opting out of the PPA in a mutually acceptable manner. The Public Sector Making Way for the Private Sector, or a Contested Playing Field? In the Power Sector Medium Term Plan (2014–18), it was estimated that KenGen would have a total of 800 MW in geothermal capacity by December 2018, thereby tripling its capacity (ERC 2014c). This could potentially squeeze Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 117 out private investment from the sector, particularly if KenGen projects are sup- ported by concessionary finance. Plans for new wind installations, including a feasibility study for a 150 MW wind farm, Marsabit Wind, and the 50 MW Isiolo are also under way (KenGen 2014b).36 Additionally, local coal deposits are being explored and assessed. KenGen identified the 600 MW Kilifi project for comple- tion in 2016, though momentum on this project has slowed and it is presently still in exploratory drilling. Furthermore, despite murmurs that the country’s (large) hydropower poten- tial has been exhausted, the government has indicated that it will continue to develop its hydropower resources—it “estimate[s] that the undeveloped hydro- electric power potential of economic significance is 1,449 MW out of which 1,249 MW is for projects of above 30 MW” (MoEP 2014b: 46).37 Between 2011 and 2014, KenGen noted 53 MW in new hydropower capacity, though this included the upgrading of existing capacity. Among ongoing and new proj- ects, hydropower facilities are notably absent. However, the MoEP has indi- cated its intent to finance prefeasibility studies for the identification of potential hydropower sites, and 290 MW of new (multipurpose) hydropower projects have been identified as public-private partnerships (PPPs) by the Ministry of Environment, Water, and Natural Resources. Overall, there are great prospects for increasing private participation in the generation sector. Nonetheless, publicly funded generation is not about to stop any time soon. KenGen does not show any sign of slowing its activities and remains, without question, the dominant player in the generation sector. As highlighted at the outset of this case study, instead of lack of power, there is a concern about surplus power in Kenya. IPPs, which are required contractually to retain at least three months’ equivalent of fuel supplies to avoid stockouts, have been laden with stock, which has become an increasing liability amid falling oil prices. IPPs have petitioned the regulator to review relevant policies and prices, given the changing circumstances (Situma 2015). Conclusions and Recommendations For two decades private and public power projects in Kenya have been devel- oped in parallel. Private developers have been critical in mobilizing funding to meet the nation’s demand for electricity, and have complemented publicly owned projects. Kenya’s power-planning process has been dynamic. The LCPDPs have been periodically updated in collaboration with international consultants under the direction of the regulator and involving all relevant stakeholders. Although the first (stopgap) IPPs were procured through limited competition, there has since been a strong track record of international competitive bidding. From the late 1990s, new build opportunities have been allocated to either the national power generation company, KenGen, or to private IPPs, and procured via ICBs run by the national transmission/distribution company, the KPLC. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 118 Case Study 1: Kenya’s Electric Power Promise Separated from KenGen, and housing the system operator, the KPLC does not face any generation investment conflicts and can procure new power in a fair, transparent, and competitive fashion. The KPLC has built up considerable internal procurement and contracting capabilities and has been able to run timely and effective procurement processes. While the first ICBs that cemented deals with Tsavo and OrPower4 attracted only limited competition (three and two bidders, respectively), ICBs conducted for the three recent diesel generators resulted in nine bidders for the Thika plant alone. There are well-recognized links between the transparency of procurement processes, price outcomes, and the sustainability of projects. Prices have generally declined since the first IPPs were procured, which signals the merits of private power and increased competition. Thermal IPPs demonstrate superior technical performance relative to KenGen’s plants with similar technologies. Pricewise, KenGen’s projects appear to be more competitive, though the least expensive thermal is an IPP. A direct comparison between public projects (KenGen’s plants) and private projects (IPPs) is clouded by the fact that their respective costs of capital have been different. While KenGen has raised private capital via bond issues, it has also benefitted from concessionary funds. Location and specific technology types also influence any comparison. More recently, the planning process has not always been based on solid inde- pendent technical analysis; the government’s demand estimates have tended to be unrealistically high. Also, a number of generation projects have been procured without following a competitive process, and without a thorough technical and financial analysis to determine if the plants’ integration and system requirements are in line with least-cost planning standards. In particular, the landscape for new build opportunities has been affected by the involvement of the GDC, which has been only minimally successful in attracting investment, and whose model remains unsustainable. Further complications have arisen due to noncompeti- tively bid wind projects, which have proven to be much more expensive than comparable projects that involved competitive bidding, notably in South Africa. Meanwhile, KenGen has asserted itself as the dominant player in geothermal activity and is on track to continue as such, possibly squeezing out private invest- ment. Based on these findings, the following recommendations are offered: • Overly ambitious demand assumptions that have been directed by the govern- ment should be tempered, and the planning process allowed to follow its due course involving the relevant, empowered agencies. • The current generation plan might be revised to reset activities on the basis of well-grounded macroeconomic and technical assumptions, including the issue of proper assessments of system integration challenges for wind and solar capacity. • To ensure coherent planning, procurement, and contracting, it is necessary to continue building relevant capacity in key institutions, including the MoEP, PPP Unit, ERC, and GDC. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 119 • KenGen could offer greater disclosure of its capacity charges, reflecting the cost of capital, so that a more accurate comparison of electricity prices may be analyzed and made public. • If the GDC is to operate effectively in the market as a provider of steam to IPPs, then the GDC should be capitalized and/or a guarantee program should be put in place to reduce any uncertainty surrounding this dispatch by addressing the current imbalance of supply and demand. • Provided that there is a viable steam provider, adequate space should be allo- cated to the IPPs and KenGen to minimize the crowding out of the private sector. • The FiT regime should be revisited with private and public stakeholders alike to determine whether it is the best way to engage renewable development or whether international competitive bidding processes, following South Africa’s example, ultimately make more sense. • The creditworthiness of the off-taker (KPLC) is critical for the successful ­ procurement of IPPs and other power capacity; efforts to improve it should continue. • Given the outcomes of the recent renewable projects awarded without competition, Kenya should potentially explore ICBs for future solar projects, ­ particularly in remote areas. • Finally, addressing transmission constraints and integration issues to ensure that all the power generated is actually delivered remains an area in need of improvement. In summary, Kenya has demonstrated the clear advantages of competitive ­ bidding for thermal plants, and also the cost advantages of renewable energy, particularly geothermal power. After two decades of experience, the key remains in the careful implementation of IPPs, from planning to competitive procure- ment to effective contracting. Annex 6A The Initial 5,000+ MW Program: An Overview of Targets and Timelines According to industry experts, massive capacity additions do not make sense unless they are matched by demand. The ideal supply profile should be 15–20 percent more than demand. The inclusion of massive coal and liquefied natural gas (LNG) projects has the potential to distort planning decisions. The projects noted in table 6A.1 involve an ambitious interim LNG project with potential imports from Qatar (Senelwa 2014). The tender for the LNG project was not, however, awarded because none of the bidders agreed to the timelines required in the request for proposal. The project has since been shelved, also partly due to the discovery of natural gas in Wajir (in northeastern Kenya). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 120 Case Study 1: Kenya’s Electric Power Promise Table 6A.1  Cumulative Installed Capacity, 5,000+ MW Program, Kenya No. of months from start of project 0a 6 12 18 24 30 36 40 Technology Cumulative installed capacity (MW) Hydro 770 794 794 794 794 794 794 794 Thermal 622 709 782 782 782 432 432 432 Geothermal 241 331 507 697 747 952 1,102 1,887 Wind 5 5 5 25 85 385 635 635 Coal 0 0 0 0 0 960 960 1,920 LNG 0 0 0 0 700 1,050 1,050 1,050 Cogeneration 26 26 26 44 44 44 44 44 Retired plants n.a. 90 n.a. n.a. n.a. 350 n.a. n.a. Cumulative total 1,664 1,775 2,114 2,342 3,152 4,617 5,017 6,762 Generation tariff (USc/kWh) 11.3 10.14 9.93 8.74 8.07 7.38 7.58 7.41 Industrial/commercial tariff (USc/kWh) 14.14 12.77 12.49 11.03 10.08 9.03 9.32 9.00 Domestic tariff progression 19.78 18.30 17.73 15.85 13.46 11.14 11.19 10.43 Source: Authors’ compilation based on MoEP 2014a: 69. Note: kWh = kilowatt-hour; LNG = liquefied natural gas; MW = megawatt; USc = U.S. cent; n.a. = not applicable. a. Time 0 = from September 2013. Notes 1. These data are current through the end of 2014; megawatt and dollar figures are based on the date of financial close and not commercial operation. 2. Although initially conceived as part of the “5,000+ MW” program discussed in the next section, it is anticipated that this coal project will take considerably longer than the 40 months identified. 3. Unless otherwise stated, this section and the next are based in part on Power-Sector Reform and Regulation in Africa (Kapika and Eberhard 2013: 22–23, 26, 37, 42–43). The author is collaborating with Anton Eberhard, and has been given permission to draw heavily on relevant material. 4. KPLC was rebranded as “Kenya Power” in 2011; however, for the purposes of this report it is referred to as KPLC throughout. 5. The KPLC’s predecessor was the East African Power and Lighting Co., incorporated as a public limited liability company under the Companies Act in 1922. It was a merger between the Nairobi Electric Power and Lighting Syndicate and the Mombasa Electric Light and Power Company Limited, the second of which was directly con- nected by way of technology acquisition to electric power developments in Zanzibar that date to 1881 (KPLC 2011: 2). 6. Energy Act No. 12 of 2006 subsequently established the Energy Tribunal in Kenya, to hear and determine appeals brought against the decisions of the ERC. The tribunal published the Energy Tribunal (Procedure) Rules 2008, on September 26, 2008. 7. Between 1960 and 1975, the government bought KPLC shares totaling 32,853,268 that represented 40.4 percent of the voting shares of the company. Under a capital restructuring in 2011 the government of Kenya shareholding increased to 50.1 percent. The KPLC has been listed on the Nairobi Stock Exchange since 1972. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 121 8. While “5,000+ MW” and the Obama administration’s “Power Africa Program” in Kenya were independently conceived, they are aligned in their goals and to some extent in their timelines as well (http://www.usaid.gov/powerafrica/partners/african​ -governments/kenya). 9. See annex 6A for a detailed timetable and associated capacity targets for the 5,000+ MW program. 10. Westmont independent power project (IPP), also known as the Mombasa Barge- Mounted Power Project, would bring this total to 12; however, it came into service in 1997 and had only a 7-year contract. Unlike Iberafrica, which also came into service in the same year and had a short-term contract, Westmont did not succeed in renew- ing its contract due to failure to agree on a lower tariff. Several more IPPs are presently under construction, namely Triumph and Kinangop, though Kinangop was halted as of the third quarter of 2015 (this is discussed in more detail later in this chapter). Gulf Energy—counted in the total—reached its commercial operation date in December 2014. Triumph was expected to complete installation, testing, and commissioning by the third quarter of 2015. In addition, construction has started on Lake Turkana. 11. The KPLC staff work in subteams (one for generation and one for transmission). As an organization, the KPLC has no lead role. 12. The development of domestic resources supports Kenya’s Vision 2030 infrastructure program, which seeks to make the country more attractive to investors by, among other things, improving domestic energy supply: http://www.vision2030.go.ke/index​ .php/vision. The targets of the 5,000+ MW program also support those of Vision 2030. 13. The prices for commercial/industrial customers, exclusive of taxes and levies, were expected to drop from U.S. cents (USc) 14.14 to USc 9, and for domestic customers, from USc 19.78 to USc 10.45 (ERC 2014b). 14. Even the demand estimates of the 2011 Least Cost Power Development Plan were considered to be high by most industry stakeholders. 15. This figure includes 22 MW that is off-grid and owned by the government of Kenya (Rural Electrification Programme, REP), which accounts for 1 percent of total installed capacity. Also included in this figure are emergency power projects. KenGen also owns off-grid stations—Garissa and Lamu—with a total installed capacity of 5.4 MW. 16. This includes less than 1 MW of small hydropower projects, but does not include 30 MW of installed emergency power projects or exports and imports. 17. According to the MoEP Investment Prospectus (2013–16, section 5), the developers of the 5,164 MW projects initially were categorized as IPPs/Sida (Swedish International Development Cooperation Agency) partnerships (PPPs). IPPs were to contribute 4,724 MW (91.5 percent) and KenGen, 440 MW (8.5 percent) (MoEP 2013b, section 5). This, however, was revised and presently stands at a 70/30 split between IPPs and KenGen/Geothermal Development Company. Importantly, it was previously estimated that the 5,000+ MW would be carried out for K Sh 850 billion, of which the private sector would contribute K Sh 800 billion ($9.4 billion). However, “Actual costs are proving to be much higher than previously estimated, due mainly to higher costs for getting transmission lines rights-of-way and resettlement and corporate social responsi- bility program costs for power generation projects” (personal communication, March 3, 2015). It should be noted that the actual position of public and IPP projects awarded and under implementation will continue to change, including actual realized ratios. Some information for this case study was collected directly from private and public sector stakeholders who requested anonymity, including, at times, regarding their Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 122 Case Study 1: Kenya’s Electric Power Promise organization affiliation. Efforts are made to identify the date when information was collected by way of personal communication. 18. KenGen’s large hydropower projects—namely, Gitaru (225 MW hydro with a commer- cial operation date of 1999) and Sondu-Miriu (60 MW hydropower with a commercial operation date of 2007)—are, however, excluded from this analysis, as there is no private sector correlate. 19. Westmont and Iberafrica reached financial close in 1996 and came online in the ­following year. 20. The initial bid document specified a capacity of 28 MW–100 MW, which was later refined to 64 MW and again modified to 48 MW. Today the project stands at 110 MW after expansion. 21. One of the two bids, by CalEnergy, was, however, noncompliant, as it was conditional on the bidder developing Olkaria II (which had been earmarked for KenGen) together with Olkaria III. 22. The fact that there was an appeal by a losing bidder for the Rabai project should not, however, be viewed as negative. Although it potentially delays the overall project implementation, it is part and parcel of the international competitive bidding process, and points potentially to the robustness of the process itself. Procurement appeals have been witnessed in almost all plants competitively procured after the enactment of the Public Procurement and Disposal Act in 2005—including, most recently, the three diesel generators, dating to 2010, and the latest coal plant. 23. Also in 2009, a cogenerator, Mumias Sugar Company, increased its supply to the KPLC from 3 MW to 26 MW. 24. A partnership among four Kenyan firms: Broad Holding, Interpel Investments, Tecaflex, and Southern Inter-trade. 25. A consortium of Kenyan investors, namely Gulf Energy Ltd. and Noora Power Ltd. 26. Melec PowerGen (90 percent/Lebanon). 27. Nine bids were received (after 17 firms withdrew tender documents). 28. Prunus Wind (50 MW) is also in the process of being approved. 29. The capacity factor used in capping payments for deemed generated energy is as follows: Lake Turkana Wind Project (LTWP), 55 percent; Kinangop, 39 percent; and ­ Kipeto, 49 percent. Meanwhile, the capacity factor for which energy is paid for at a discounted price (50 percent) is as follows: LTWP, 64 percent; Kinangop, 42 percent; and Kipeto, 62 percent. 30. Kenya’s Ministry of Energy awarded three concessions, but the first lost its concession (Suswa, 300 MW, due to noncompliance) and nothing has been done by the other two concessionaires. The Suswa concession was later given to the GDC. 31. The intention is for the GDC to sell steam to IPPs and KenGen, which in turn con- duct the conversion to energy. To date the GDC has not been involved in power conversion projects. In the future, the GDC may be involved in geothermal projects’ development models—for example, Sida PPPs in which the GDC undertakes resource-related activities, while other partners undertake energy conversion. 32. In 2013, the GDC received an $18 million grant from the Japan International Cooperation Agency to “support a comprehensive capacity strengthening programme for geothermal development in Kenya” (JICA 2013: 16). 33. Also cited by stakeholders were “politics,” namely intraorganizational disputes between the chairman and the managing director of the GDC (personal communica- tion, June 2 and 6, 2014). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 123 34. Iberafrica presently has no payment security. 35. Tsavo received both a standby letter of credit (SBLC) and an escrow account; ­ however, OrPower4 received only an SBLC (though the escrow account was also stipulated in OrPower4’s agreement with the KPLC). With the KPLC’s financial situation deteriorating during and after the drought, security measures were left to ­ wait, and OrPower4 would eventually proceed, via a phased development approach, without any further escrow account (Eberhard and Gratwick 2007: 31–32). 36. There are two potential wind projects at Isiolo: 50 MW to be developed by KenGen and 40 MW to be developed by Blue Sea (http://www.bluesea-energy.com/bluesea​ %20energy%20portfolio.html). 37. Furthermore, “the total estimated potential of small, mini, micro and pico hydro sys- tems is 3,000 MW of which about 30 MW has been developed” (MoEP 2014a: 48). In terms of a strategy to develop hydropower, five policies were identified, including one to “provide incentives for public private partnerships in small hydros” (MoEP 2014b: 49). References AfDB (African Development Bank). 2013. http://www.afdb.org/en/projects-and​ operations/project-portfolio/project/p-ke-fa0-006/. Accessed May 16, 2015. -­ ———. 2014. “AfDB Eases Investor Risk in Large African Geothermal Project.” Press Release, African Development Bank, October 22. http://www.afdb.org/en/news-and​ -events/article/afdb-eases-investor-risk-in-large-african-geothermal-project-13652/. Accessed January 20, 2015. African Energy. 2015. “Kenya: Rwanda to Import 30 MW from Kenya in 2015.” Issue 291, December 18. Climatescope. 2014. “Kenya Feed-in Tariffs.” http://global-climatescope.org/en/policies/#​ policy/3426. Accessed February 20, 2015. /­ Eberhard, A., and K. Gratwick. 2007. “Take 4: The Contribution and Evolution of Independent Power Projects in Kenya.” MIR Working Paper, Management Programme for Infrastructure Reform and Regulation, Cape Town. http://www.gsb.uct.ac.za/files​ /Kenya_10_10_2007_23512.pdf. Accessed January 29, 2015. Energy Monitor Worldwide. 2014. “Kenya to Get Help from Foreign Countries to Develop Nuclear Power.” September 4. ERC (Energy Regulatory Commission). 2014a. “Electric Supply Industry in Kenya.” http://www.erc.go.ke/index.php?option=com_content&view=article&id=107&Ite mid=620. Accessed January 13, 2015. ———. 2014b. “Investor Power Plan Portal Seeks Consumption Data from Investors.” http://www.erc.go.ke/index.php?option=com_content&view=article&id=203:kenya​ -s-electricity-sector-seeks-input-from-industrialists-in-national-energy-planning&catid​ =98:latest-news&Itemid=579. Accessed January 8, 2015. ———. 2014c. “Power Sector Medium Term Plan (2014–2018).” http://erc.go.ke/images​ docs/Power_Sector_Medium_Term_Plan_2014-2018.pdf. Accessed June 29, 2015. /­ Government of Kenya. 1996. “Economic Reforms for 1996–1998: The Policy Framework Paper.” Government of Kenya, Nairobi. ———. 2003. “Kenya: Economic Recovery Strategy for Wealth and Employment Creation 2003–2007.” Government of Kenya, Nairobi. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 124 Case Study 1: Kenya’s Electric Power Promise ———. 2004. “Sessional Paper No. 4 of 2004 on Energy.” Government of Kenya, Nairobi. ———. 2006. Energy Act. Nairobi: Government of Kenya. http://www.eisourcebook.org​ cms/Kenya%20Energy%20Act,2006.pdf. Accessed January 29, 2015. /­ .go​ ———. 2014. Energy Bill. Nairobi: Government of Kenya, October 11. http://www.erc​ .ke/images/docs/Energy_Bill_2014_11102014.pdf. Accessed January 22, 2015. Herbling, D. 2014. “KenGen Targets 560 MW of More Geothermal Power.” Business Daily, December 16. http://www.businessdailyafrica.com/Corporate-News/KenGen​-­targets -560MW-of-more-geothermal-power/-/539550/2559182/-/jndc4mz/-/index.html. Accessed January 21, 2014. JICA (Japanese International Cooperation Agency). 2013. Annual Report, Kenya. http:// www.jica.go.jp/kenya/english/office/others/c8h0vm000001pzr0-att/report2013.pdf. Accessed January 5, 2015. Kapika, J., and A. Eberhard. 2013. Power-Sector Reform and Regulation in Africa: Lessons from Kenya, Tanzania, Uganda, Zambia, Namibia and Ghana. Cape Town: Human Sciences Research Council Press. KenGen. 2014a. “KenGen Finally Connects Olkaria 280 MW to the Grid.” Press Release, December 10. http://www.kengen.co.ke/index.php?page=press&subpage=releases. Accessed January 21, 2015. ———. 2014b. “Ongoing Projects.” http://www.kengen.co.ke/index.php?page=business& subpage=current. Accessed January 21, 2015. KPLC (Kenya Power and Lighting Company Ltd.). 2006. Annual Report and Financial Statements 2005/2006. KPLC: Nairobi. http://www.kplc.co.ke/fileadmin/user_upload​ /Reports/annualrep2006.pdf. Accessed February 9, 2015. ———. 2007. Annual Report and Financial Statements 2006/2007. KPLC: Nairobi. http:// www.kplc.co.ke/fileadmin/user_upload/Reports/annualrep2007.pdf. Accessed February 9, 2015. ———. 2008. Annual Report and Financial Statements 2007/2008. KPLC: Nairobi. http:// www.kplc.co.ke/fileadmin/user_upload/Reports/annualrep2008.pdf. Accessed February 9, 2015. ———. 2009. Annual Report and Financial Statements 2008/2009. KPLC: Nairobi. http:// www.kplc.co.ke/fileadmin/user_upload/Reports/annualrep2009.pdf. Accessed February 9, 2015. ———. 2010. Annual Report and Financial Statements 2009/2010. KPLC: Nairobi. http:// www.kplc.co.ke/fileadmin/user_upload/1Report_Pages.pdf. Accessed February 9, 2015. ———. 2011. Annual Report and Financial Statements 2010/2011. KPLC: Nairobi. http:// www.kenyapower.co.ke/AR/Annual%2520Report%25202010%2520-%25202011​ .pdf. Accessed January 16, 2015. ———. 2012. Annual Report and Financial Statements 2011/2012. KPLC: Nairobi. http:// www.kenyapower.co.ke/tender_docs/ANNUAL%20REPORT%20AND%20 FINANCIAL%20STATEMENTS%202011-12%20EMAIL.pdf. Accessed January 16, 2015. ———. 2013. Annual Report and Financial Statements 2012/2013. KPLC: Nairobi. http:// www.kenyapower.co.ke/AR2013/KENYA%20POWER%20ANNUAL%20 REPORT%2020122013%20FA%20127,128.pdf. Accessed January 16, 2015. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 1: Kenya’s Electric Power Promise 125 ———. 2014. Annual Report and Financial Statements 2013/2014. KPLC: Nairobi. http:// kplc.co.ke/img/full/4rNGlk21KXmA_KENYA%20POWER%20ANNUAL%20 REPORT%20FA.pdf. Ministry of Energy of Kenya. 2010. Least Cost Power Development Plan. Nairobi: Government of Kenya. MoEP (Ministry of Energy and Petroleum). 2013a. “Energy Day.” http://www.imf.org​ external/np/seminars/eng/2013/kenya/pdf/chirchir.pdf. Accessed January 8, 2015. /­ ———. 2013b. “5000 + MW by 2016, Power to Transform Kenya, Investment Prospectus (2013–2016).” http://admin.theiguides.org/Media/Documents/Kenya_Energy​ Prospectus.pdf. Accessed February 9, 2015. _­ ———. 2014a. “Draft National Energy and Petroleum Policy.” http://www.erc.go.ke​ /­images/docs/Draft_National_Energy_and_Petroleum_Policy-111014.pdf. Accessed January 22, 2015. ———. 2014b. “Ministry Projects.” http://www.energy.go.ke/Projects.html. Accessed January 22, 2015. Obiero, E. 2015. “Work on Nairobi-Mombasa Electricity Transmission Line to End in August 2015.” The African Resources Post, February 17. http://afrespost.com/2015​ /­work-on-nairobi-mombasa-electricity-transmission-line-to-end-in-august-2015. Accessed March 25, 2015. Ongwae, E. 2012. “Authority Plans to Light Every Home by 2020.” Daily Nation, August 31. http://www.reelforge.com/reelmedia/files/pdf/2012/08/31/DNT​ _20120831​_V8ABEHNQZ369.pdf. Accessed January 13, 2015. Ormat. 2014. “Ormat Signs 25-Year PPA and Steam Supply Agreement for the 35 MW Menengai Geothermal Project in Kenya.” Press Release, Ormat, November 3. http:// www.ormat.com/news/latest-items/ormat-signs-25-year-ppa-and-steam-supply​ -agreement-35-mw-menengai-geothermal-proje. Accessed January 20, 2015. Senelwa, K. 2014. “Construction of Mombasa LNG Plant to Start in August.” Business Daily, June 30. http://www.businessdailyafrica.com/Construction-of-Mombasa​ -LNG-plant-to-start-in-August/-/539546/2366726/-/1w5i1cz/-/index.html. Accessed January 12, 2015. Situma, E. 2015. “Diesel Power Generators Stuck with Expensive Stocks.” Business Daily, January 13. http://www.businessdailyafrica.com/Diesel-power-generators-stuck-with​ -costly-stocks/-/539546/2585626/-/15t72qez/-/index.html. Accessed January 29, 2015. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 C h apter 7 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Introduction While Nigeria has the largest population and economy on the African continent, 46 percent of its citizens live below the poverty line and less than 50 percent have access to electricity. The demand for electricity far outweighs available capacity, which is less than 5 gigawatts (GW) for a population of about 170 ­ million (table 7.1). (Compare this with South Africa, which has an installed capacity of 43 megawatts [MW] for a population one-third the size of Nigeria’s.) The actual generation output rate in Nigeria, meanwhile, is far below installed capacity. In fact Nigeria’s output rate per capita is among the lowest in the world, owing to poor operation and maintenance, aging generation and transmission infrastructure, fuel supply constraints, and vandalism. Nonetheless, Nigeria has embarked on the most ambitious electricity sector reform effort of any country in Africa. Reforms were initiated in 2001 with the publication of a new power policy. The objectives of the reforms were to improve efficiency, attract private participation, and strengthen power sector performance so as to enable economic and social development. To this end, policy makers set a goal of achieving 40 GW of capacity by 2020—a goal that now seems out of reach. As part of the reform process, Nigeria unbundled the generation, transmission, and distribution subsectors; privatized power generation stations and distribution utilities; appointed a private management contractor to manage the transmission company; and established a bulk trader. Barring South Africa, the country also boasts the largest investment in independent power projects (IPPs) in Sub- Saharan Africa. Since 1998, five large IPPs have been developed. Several generations of IPP transactions may be attached to distinct phases of the sector reform process. The first generation of IPPs emerged before the reforms began in earnest and included Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   127   128 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Table 7.1  Nigeria: An Overview Population 173.6 million (2013) Generation capacity (installed) 7,485 MW GDP $521.8 billion (2013) Generation capacity (available)a 4,978 MW Income level Lower middle income Electricity intensity (consumption per capita) 149 kWh/capita Area 923,768 km² Primary electricity source Natural gas Sources: World Bank 2014; PTFP 2015. Note: GDP = gross domestic product; km2 = square kilometer; kWh = kilowatt-hour; MW = megawatt. a. In practice, available capacity is sometimes even lower than this due to gas, hydropower, and transmission constraints. a project-financed plant. A second generation of IPPs was developed after President Olusegun Obasanjo took office in 1999 and the new power sector policy was published in subsequent years. Two stopgap projects emerged during this period, financed by international oil companies (IOCs) and with equity contributions from the Nigerian National Petroleum Corporation. After a hiatus of a number of years, and the rejuvenation of the reform process under President Goodluck Jonathan, who took office in 2010, a third generation of IPPs was developed including a predominantly Nigerian-financed IPP that intends to serve a local grid with mainly industrial demand. Today, a new power market is being established, and a fourth generation of classic, project-financed IPPs is emerging. IPP contracts have had to be designed and negotiated afresh in the new market conditions, and appropriate credit enhancement and security measures put in place to mitigate payment and termination risks. Nigeria thus represents a fascinating case study of accelerating investment in new power capacity, in an electricity sector undergoing radical reform. Will the next generation of IPPs be successful and lead to further investment in much- needed power generation capacity? Will risks be mitigated? Will sector reforms foster financial sustainability? Will greater competition be possible in the future? These are some of the questions that will be answered in this case study. Nigeria’s Electricity Sector: An Overview The significant shortfall in Nigeria’s generation capacity has resulted in fre- quent blackouts and a reliance on private generators. It is estimated that more than 30 percent of electricity is supplied by inefficient and expensive private generators (EIA 2013). By 2014, the highest peak generation recorded was 4,517 MW, while suppressed demand was estimated at 12,800 MW (Federal Ministry of Power 2014). Prior to sector reforms, the state-owned National Electric Power Authority (NEPA), established in 1972, had the sole responsibility for generation, transmis- sion, distribution, and retail activities in the country and operated as a vertically integrated monopoly. Lack of investment and ineffective management resulted in consistently poor performance over several decades (Ikeonu 2006). In 1990 only 37 percent of installed capacity was operational, and transmis- sion and distribution (T&D) losses averaged 38 percent. By the late 1990s it Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 129 became apparent that the utility could not meet the power needs of the country; and the new civilian government under President Obasanjo began the gradual process of restructuring the sector (Adegbulugbe and others 2007). Power Sector Reform Early Reform Initiatives (The Obasanjo Era) The National Electric Power Policy of 2001 called for the transformation of the control, electricity supply industry through fundamental changes in its ownership, ­ and regulation. The policy identified principles for restructuring the sector and deregulating the market to attract private sector participation (Ikeonu 2006). Evolving from this policy, the Electric Power Sector Reform Act (EPSRA) was passed in 2005, and still serves as the legal basis and regulatory framework for the reform of the industry. The act provides for: • The creation of the Power Holding Company of Nigeria (PHCN) to take over NEPA’s assets and liabilities • The unbundling of the PHCN through the establishment of several companies to take over the assets, liabilities, functions, and staff of the holding company • The establishment of the Nigerian Electricity Regulatory Commission (NERC) • The development of a competitive electricity market • The basis for determining tariffs, customer rights and obligations, and other related matters. Following the enactment of the EPSRA, the NEPA was unbundled, vertically and horizontally, into 6 generation companies, 11 distribution companies, and a single transmission company (Transmission Company of Nigeria, TCN) under the PHCN holding company, which was tasked with preparing the successor companies for independent commercial operation and eventual privatization (Okoro and Chikuni 2007)—see table 7.2. The Reinvigoration of Reforms (Jonathan Era) By 2010, important steps in the reform process had been implemented, including the establishment of a regulator (NERC) and the unbundling of the PHCN, but progress was slow on the divestiture of the successor companies and the development of a competitive electricity market. Not one generation or distribution company had been sold to private investors in the five years since the EPSRA was signed into law. In 2007 the Korean firm KEPCO (Korea Electric Power Corporation) offered to purchase 51 percent of Egbin Power for $280 million. However, this deal was delayed by unresolved labor issues and the lack of a credible power purchase agree- ment (PPA) or agreements on pricing and the gas supply (allAfrica 2013). A Presidential Action Committee on Power (PACP) was set up, headed by President Jonathan, to accelerate progress toward reform objectives by (1) removing obstacles to private sector involvement, (2) clarifying the govern- ment’s strategy on divestiture, and (3) reforming the fuel-to-power market. These policy objectives were reaffirmed and elaborated in the Roadmap for Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 130 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Table 7.2  Successor Power Generation Companies to the National Electric Power Authority, Later Privatized, Nigeria Generation company Electricity distribution company Afam Power Abuja Geregu I Benin Sapele Power Eko Ughelli Power Enugu Kainji/Jebba Hydro Power Ibadan Shiroro Hydro Power Ikeja Jos Kaduna Kano Port Harcourt Yola Source: Compiled by the authors from various primary and secondary sources. Note: Some reports might list different successor generation companies; strictly, they are defined under the Electric Power Sector Reform Act (EPSRA) as the companies created by the National Council on Privatisation (NCP) in November 2005 as part of the initial unbundling, which is not the same as those ultimately listed for privatization. Thus, the list here does not include Egbin, which was sold separately. Omotosho and Olorunsogo were also handled separately and are now owned by the Chinese engineering, procurement, and construction (EPC) companies that built them. The construction of Geregu I was completed after the initial unbundling and therefore is not strictly a successor company, though it was privatized with the others. Each successor generation company represents a single generation facility with the exception of Kainji Hydro Power, which includes both the Kainji and Jebba hydropower plants. Power Sector Reform, published in August 2010, which set out a large number of detailed targets and milestones. The road map outlined a strategy to remove obstacles to private sector involvement by establishing a cost-reflective tariff regime, establishing a bulk power purchaser backed by credit enhancements, settling labor disputes, and strengthening the regulator and licensing regime. The divestiture strategy out- lined in the road map called for the sale of distribution companies and the ther- mal generation companies (via a sale of a minimum of 51 percent), the concession of hydropower generation companies, and the placement of the TCN under a private management contract. In September 2012, the PACP was reconstituted to oversee the implementa- tion of the federal government’s agenda for power sector reform and to ensure that the reform momentum was sustained (table 7.3). A Presidential Task Force on Power (PTFP) was also established to carry out administrative work for the PACP and to monitor and facilitate the achievement of the road map’s targets. In practice, however, these targets have proven to be highly ambitious, and the PTFP has lacked executive authority. The more influential implementers of the reform process have been individual institutions such as the Bureau of Public Enterprises (BPE), which has driven the privatization program, and the NERC, which has developed market rules and tariff regulations. Privatization In December 2010, 11 distribution companies and 6 generation companies1 were ready for privatization. The BPE led the process, requesting expressions of Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 131 Table 7.3  Key Institutions and Their Functions in the Power Sector, Nigeria Key institution Functions Ministry of Power Sector policy formulation Guided by the National Electric Power Policy, the Electric Power Sector Reform Act, and the Roadmap for Power Sector Reform Nigerian Electricity Regulatory Commission (NERC) Regulation and monitoring of the sector by: • Promoting competition and private sector involvement • Licensing and regulating entities engaged in generation, transmission, system operations, distribution, and the trading of electricity • Setting tariffs and technical standards Bureau of Public Enterprises (BPE) Responsible for the privatization of federal government assets Transmission Company of Transmission Responsible for investment in and the operation Nigeria (TCN) service provider of the transmission grid System operator Oversees dispatch and grid control, including • System planning • Dispatch and generation forecasting • Demand forecasting Market operator Administers the electricity market Manages market billing and settlement statements Nigerian Bulk Electricity Trading (NBET) Purchaser of electricity from generators via PPAs Manages the sale of electricity to distributors and eligible customers Publicly owned and backed by sovereign guarantees Presidential Action Committee on Power (PACP) Oversees power sector reforms Approves reform road map Presidential Task Force on Power (PTFP) Implementing agency for the PACP Coordinates various agencies involved in removing private sector obstacles Source: Compiled by the authors from various primary and secondary sources. Note: PPAs = power purchase agreements. interest and conducting international road shows for the privatization of the suc- cessor companies. The bureau subsequently released a request for proposals, in response to which 25 bids for the 6 generation companies and 54 bids for the 11 distribution companies were received. Preferred bidders were announced in October 2012, following a rigorous technical and financial evaluation. Transaction and industry documents were signed in February 2013, alongside an initial pay- ment of 25 percent. Bidders then had until August 21, 2013, to pay the remain- ing 75 percent for the companies (BPE 2013). Egbin Power had concluded its privatization transaction in 2013; a joint ven- ture between KEPCO and the Sahara Power Group agreed to acquire an addi- tional 19 percent equity stake over their original 2007 offer, bringing their total shareholding to 70 percent, for a total acquisition cost of $407 million. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 132 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Five of the generation companies and 10 of the distribution companies were sold for a total value of approximately $3 billion, with much of the proceeds used to pay off previous PHCN employees. Ownership was handed over in November 2013. The Afam generation plant and the Kaduna Electricity Distribution Company deals took longer but have since also been concluded. The federal government retained 40 percent ownership stakes in the distribu- tion companies and 49 percent in the Geregu I successor generation company; the remaining thermal successor generation companies were fully privatized. The two hydropower companies—Kainji and Shiroro—were concessioned, with the state retaining ultimate ownership of assets. In addition to the sale of the successor generation companies, two other state- owned plants were sold via debt equity swaps with the Chinese contractors who built them: Omotosho Phase I (March 2013) and Olorunsogo Phase I (March 2014) (This Day Live 2013b). The local partner for the privatized assets was the engineering, procurement, and construction (EPC) contractor SEPCO-Pacific. Conceived in 2004, 10 national integrated power projects (NIPPs) were ­ initiated to increase the generation capacity of the country, including associated T&D projects. The projects involved gas-fired power plants with supporting transmission and gas delivery infrastructure; their combined capacity was close to 5,000 MW. These projects were initially funded and owned by the state through the three tiers of government (federal, state, and local) and were managed by the Niger Delta Power Holding Company (2013). Following many delays, the 10 projects were either complete or near completion as of late 2015. However, gas supply constraints remained an issue and only some were fully operational. In line with the government’s privatization program, the 10 NIPP facilities were also earmarked for divestiture. The plants are being privatized through the sale of 80 percent of the state’s equity in them, with 20 percent remaining with the Niger Delta Power Holding Company. Preferred bidders have been selected for the 10 facilities, and though the handover of the plants was originally sched- uled for June 2014, these transactions had not yet been concluded in late 2015. Pending litigation and amid uncertainty surrounding gas supply, some of the plants remain incomplete; how to operate a Transitional Electricity Market (TEM) remains a question (Daily Independent 2014). Market Evolution and Financial Sustainability The market rules envisage that the competitive electricity market will evolve through four stages: (1) pretransition, (2) transition, (3) medium term, and (4) long term (table 7.4). The market rules also define procurement procedures for new power. The NERC’s Regulations for the Procurement of Generation Capacity, published development. in 2014, simplify these procedures for the early stages of market ­ The regulations cover new capacity procured by the bulk trader or distribu- tion companies. Prior to the regulations, all IPPs that had been issued licenses involved unsolicited, directly negotiated proposals. The objective of the regu- lations is to establish a systematic, transparent, and competitive process to Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 133 Table 7.4  Evolution of the Power Market, Nigeria Market stage Market characteristics Pretransition Unbundling and privatization of the PHCN Establishment of the NELMCO and bulk trader Preparation of market rules and governing documentation Transition Successor companies commence functionsa Bulk trader commences trading with generators and distributors—TEM No centrally administered balancing mechanism for the market Medium term Bulk trader no longer enters into PPAs Commence novation of PPA rights to other licensees Distributors may enter into bilateral contract for purchase and sale of energyb Full wholesale competition (spot market) Centrally administered balancing mechanism for the market Long term Capacity sufficient to meet demand Retail competition (consumers have choice of provider) Source: Compiled by the authors from various primary and secondary sources. Note: NELMCO = Nigeria Electricity Liability Management Company (a publicly owned company that assumes the liabilities of the PHCN); PHCN = Power Holding Company of Nigeria; PPA = power purchase agreement; TEM = Transitional Electricity Market. a. Successor companies actually commenced functions in the pretransitional stage. b. Distribution companies can enter into bilateral contracts during the TEM, in defined circumstances. procure new capacity at the least cost to the consumer. The system operator is required to publish a five-year demand forecast and an annual generation report. If the report indicates that contracting for new capacity is required within 12 months, the buyer (a creditworthy distribution company or the Nigerian Bulk Electricity Trading Plc [NBET]) may begin procurement pro- cedures in line with the regulations and with approval from the NERC (NERC 2014). The market rules govern contracting through the transitional and medium- term stages of the market. For the vesting contracts to be activated, the TEM should have been in place at the time the successor companies were privatized. However, many of the conditions required for declaring the TEM—such as metering—were not met in full, and there were still concerns around financial sustainability. So, instead, a set of interim rules was issued by the NERC, first in December 2013 (effective from November 1, 2013) and extended to April 2014. After many delays the TEM was finally declared in February 2015. The bulk trader, NBET, is intended to act as the credible off-taker and aggregator to guar- antee liquidity in the market (figure 7.1). Electricity is bought from successor generation companies and from NIPPs and IPPs—through PPAs—and then sold on to distribution companies and eligible customers. In the future, the bulk trader need not be the only off-taker of power; any creditworthy distribution company or eligible customer will be able to negotiate a PPA directly with a generation company or IPP. The bulk trader is required to be in place only until the distribu- tion companies have established creditworthiness, and until the accounting, managerial, and governance systems have developed enough to handle a more sophisticated market of multiple buyers and sellers (PACP 2010). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 134 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Figure 7.1  Transitional Electricity Market Structure, Nigeria E xisting E xisting E xisting GenCo1 GenCo2 GenCo3 New IPPs GenCo4 GenCo5 GenCo6 IPPs IPPs IPPs POWER PURCHASE AGREEMENTS Additional PPAs capacity BULK TRADER PPAs Eligible customers VESTING CONTRACTS DisCo 1 DisCo 2 DisCo 3 DisCo 4 DisCo 5 DisCo 6 DisCo 7 DisCo 8 DisCo 9 DisCo 10 DisCo 11 Note: DisCo = distribution company; GenCo = generation company; IPP = independent power project; PPA = power purchase agreement. Despite delays and considerable challenges, privatization has taken root in Nigeria. It is remarkable that private investors actually reached financial close without the TEM and the security arrangements (partial risk guarantees, PRGs) to be provided by the World Bank. Investors probably take some comfort from the fact that the reforms are being supported at the highest political level. Besides, investors are keen to position themselves in a market that has enormous growth potential, following the successful experience of Nigeria’s liberalization of the telecommunication industry. Despite this impressive progress in sector reform, some serious challenges remain. Revenue collection from customers is still inadequate to cover the costs of power delivery. Insufficient revenue is flowing from customers—through distri- bution companies—to generators, gas suppliers, and investors. The Central Bank of Nigeria (CBN) devised a financial rescue package in the form of the Nigerian Electricity Market Stabilization (NEMS) facility to inject liquidity into the sector and address legacy debts. These amounts are repaid through an understanding that the NERC-approved tariffs would include a premium over a 10-year period to fund these debts. The NERC revised tariffs through the second Multi-Year Tariff Order (MYTO-2.1).2 However, in March 2015 the NERC arbitrarily removed assumptions of distribution companies’ collection losses. This in effect reduced the approved tariffs, thus threatening the financial viability of the sector again. A number of distribution companies gave notice of force majeure. Subsequently, the new administration under President Muhammadu Buhari was forced to inter- vene, and brokered an agreement with the NERC to reconsider its tariff ruling. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 135 Another area of concern has been the viability and reliability of gas supply to power generators; increasing the gas supply is critical to increasing the delivery of power to distribution companies and customers. A decision was made in late 2014 to increase the regulated supply price of gas to $2.50/million standard cubic feet (mmscf  )3 plus pipeline transport costs of $0.80/mmscf (however, as of late 2015, the new price had still not been implemented). Also, in the period leading up to the March 2015 elections there were numerous incidents of van- dalism and the sabotage of gas pipelines. Another key challenge is insufficient investment to facilitate the full evacua- tion of power from the new NIPPs and existing generation companies. There are also transmission constraints on transporting available power throughout the country. And distribution companies have barely begun the job of improving metering, billing, collections, loss reductions, and service quality. These combined factors may turn public opinion against the reform process. Another concern is the organizational fragility of the TCN. The original con- tract with the Canada-based Manitoba Hydro International (MHI), appointed as management contractor, ended in July 2015 and was then extended for a year. However, there is still no credible succession plan. Without a cooperative and well-designed succession plan, the TCN is on the road to institutional collapse— with dire consequences for the entire power sector. Amid such unresolved issues, particularly surrounding the financial sustain- ability of the sector, it is very difficult for new IPPs to enter the power market. While the pioneering Azura IPP may soon be followed by an ExxonMobil IPP, more than 50 IPP projects wait in the wings—many of them frustrated by gas constraints and an electricity sector in flux. Nevertheless, as the NBET becomes operational, capacity is being built to negotiate and contract with IPPs. The NBET serves as the “principal buyer” and thus offers a clear access point for future investors. As contracts are concluded with pioneer IPPs, the road map for subsequent investments will be clearer and easier. The NBET model might not be easily replicated in other African countries— the transaction costs of establishing a separate, dedicated institution in small power markets is probably too high—but it does point to the importance of, at minimum, creating a capable central wholesale electricity purchasing function that can serve as a transparent and creditworthy counterpart for PPA contracts with IPPs. This function could be established within national transmission com- panies, but it would be important to ring-fence these market operations from transmission and system operations, as well as from power generation. Functional capability to contract IPPs is important for attracting new private investment and is an area that needs more attention in the future. Installed Generation Capacity Historically, Nigeria’s electricity sector has operated far below its installed capacity; utilization rates have averaged below 40 percent for over three decades. Aging infrastructure, poor maintenance, vandalism, and gas sup- ply constraints have all negatively affected the performance of the sector. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 136 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Figure 7.2  Energy Produced, by Technology: Nigeria, 2013 Averages percent Hydro, 21 OCGT, 35 Steam (Gas), 21 CCGT, 23 Source: Compiled by the authors from system operator data. Note: CCGT = combined-cycle gas turbine; OCGT = open-cycle gas turbine. Presently, the installed capacity of Nigeria is estimated to be under 7.5 GW, of which less than 5 GW is available.4 There are 23 grid-connected and operational power plants in Nigeria. Given the country’s abundance of natural gas, the generation fleet is largely gas fired; three hydropower plants provide the balance (figure 7.2). In January 2014, the TCN estimated that 2,994 MW of capacity was lost due to gas supply con- straints. Furthermore, 80 percent of gas power plants are reported to be regularly deprived of gas (Punch 2014). Power plants can be divided into four categories based on their ownership: (1) IPPs, (2) successor generation companies (including successor companies and plants privatized before the October 2013 sale), (3) NIPPs (built with public money but undergoing privatization), and (4) residual state-owned plants5 (not part of PHCN) (see figures 7.3 and 7.4 and tables 7.5–7.8). Power Sector Performance The performance of the generation fleet was analyzed from January 2012 through October 2013, using data from the system operator. Over the reference period, theoretically available capacity averaged around 5,200 MW; the actual energy sent out had an average peak of only about 3,500 MW (figure 7.5). The average monthly capacity factors6 of IPPs, successor generation companies, and NIPP plants are shown in figures 7.6 and 7.7 for open- and combined-cycle Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 137 Figure 7.3  Installed Capacity, by Project Type: Nigeria, 2013 Averages percent IPP, 20 Residual Successor state-owned, GenCos, 3 54 NIPP, 24 Source: Compiled by the authors from system operator data. Note: GenCos = generation companies; IPP = independent power project; NIPP = national integrated power project. Figure 7.4  Energy Produced, by Project Type: Nigeria, 2013 Averages percent IPP, 24 Residual state-owned, Successor 2 GenCos, 55 NIPP, 18 Source: Compiled by the authors from system operator data. Note: GenCos = generation companies; IPP = independent power project; NIPP = national integrated power project. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 138 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Table 7.5  Residual State-Owned Plants, Nigeria Installed Plant cost Plant Fuel capacity (MW) COD Location Ownership (US$, millions) Omoku Gas–OCGT 150 2005 Omoku, Rivers State Rivers State 132 Trans Amadi Gas–OCGT 136 2002 Port Harcourt, Rivers State Rivers State 34 Ibom Power Gas–OCGT 190 2009 Akwa Ibom State Ibom State n.a. Rivers IPP (Eleme) Gas–OCGT 95 2005 Eleme, Rivers State Rivers State n.a. Source: Compiled by the authors, based on various primary and secondary source data. Note: COD = commercial operation date; IPP = independent power project; MW = megawatt; OCGT = open-cycle gas turbine; n.a. = not applicable. Table 7.6  Successor Power Generation Companies, Now Privatized, Nigeria Installed Available capacity capacitya Plant Fuel (MW) (MW) COD Location Ownership Jebba Hydro 578 450 1985 Jebba, Niger State Mainstream Energy Kainji Hydro 760 580 1968 Kainji, Niger State Solutions (concession) Shiroro Hydro 600 450 1989 Shiroro, Niger State North-South Power Ltd. (concession) Geregu I Gas–CCGT 414 138 2007 Geregu, Kogi State Amperion Power Ughelli (Delta) Gas–OCGT 900 340 1975/1978/2008 Ughelli, Delta State Transcorp/Woodrock Afam IV/V Gas–OCGT 776 75 1982/2002 Afam, Rivers State Still to be divested— preferred bid: Taleveras Group Sapele Gas–steam 1,020 90 1978 Sapele, Delta State CMEC/Eurafric Energy Ltd. Omotosho I Gas–OCGT 335 42 2005 Omotosho, Ondo State CMEC Olorunsogo I Gas–OCGT 335 168 2007 Olorunsogo, Ogun State SEPCO-Pacific Partners Egbin Gas–steam 1,320 880 1986 Egbin, Lagos State KEPCO Source: Compiled by the authors, based on various primary and secondary source data. Note: CCGT = combined-cycle gas turbine; CMEC = China Machinery Engineering Corporation; COD = commercial operation date; KEPCO = Korea Electric Power Corporation; MW = megawatt; OCGT = open-cycle gas turbine. a. Available as of September 2013. Table 7.7  Independent Power Projects, Nigeria Installed Plant cost Plant Fuel capacity (MW) COD Location Ownership (US$, millions) AES Barge Ltd. Gas–OCGT 270 2001 Egbin, Lagos State AES 240 Afam VI (Shell) Gas–CCGT 650 2008 Afam, Rivers State Shell 540 Okpai (Agip) Gas–CCGT 480 2005 Okpai, Delta State Agip 462 Aba Integrated Power Gas–OCGT 140 2013 Aba, Abia State Geometric Power 250 Project (Geometric) Source: Compiled by the authors, based on various primary and secondary source data. Note: CCGT = combined-cycle gas turbine; COD = commercial operation date; MW = megawatt; OCGT = open-cycle gas turbine. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 139 Table 7.8  National Integrated Power Projects, Nigeria Installed Deal value Plant Fuel capacity (MW) Location Preferred bidder (US$, millions) Alaoji Gas–CCGT 1,131 Alaoji, Abia State AITEO Consortium 902 Benin (Ihovbar) Gas–OCGT 508 Ihovbor, Edo State EMA Consortium 580 Calabar Gas–OCGT 634 Calabar, Cross River State EMA Consortium 625 Egbema Gas–OCGT 381 Egbema, Imo State Dozzy Integrated 415 Power Ltd. Gbarain Gas–OCGT 254 Gbarain, Bayelsa State KDI Energy Resources 340 Geregu II Gas–OCGT 506 Geregu, Kogi State Yellowstone Electric 613 Power Ltd. Ogorode (Sapele II) Gas–OCGT 508 Sapele, Delta State Daniel Power 531 Olorunsogo II Gas–CCGT 754 Olorunsogo, Ogun State ENL Consortium 751 Omoku II Gas–OCGT 265 Omoku, Rivers State Shynobe International 319 Ltd. Omotosho II Gas–OCGT 513 Omotosho, Ondo State Omotosho Electric 660 Power Source: Compiled by the authors, based on various primary and secondary source data. Note: CCGT = combined-cycle gas turbine; MW = megawatt; OCGT = open-cycle gas turbine. Figure 7.5  Performance of Electricity Sector: Nigeria, January 2012–October 2013 7,000 6,000 5,000 Megawatts 4,000 3,000 2,000 1,000 0 12 12 Ap 012 M 012 Ju 012 Ju 12 Au 012 pt 2 Oc 012 No 012 De 012 Ja 012 Fe 013 M 013 Ap 013 M 013 Ju 013 Ju 13 Au 013 pt 3 Oc 013 13 Se 01 Se 201 20 20 20 20 20 .2 2 2 l. 2 2 .2 2 2 2 2 2 .2 2 2 l. 2 .2 n. b. r. ay n. g. t. v. c. n. b. r. ay n. g. t. ar ar Ja Fe M Available capacity Actual energy sent out Source: Compiled by the authors from system operator data. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 140 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Figure 7.6  Average Monthly Capacity Factors of Open-Cycle Gas Turbines: Nigeria, January 2012–October 2013 100 90 80 70 60 Percent 50 40 30 20 10 0 12 12 Ap 012 M 012 Ju 012 Ju 12 Au 012 pt 2 Oc 012 No 012 De 012 Ja 012 Fe 013 M 013 Ap 013 M 013 Ju 013 Ju 13 Au 013 pt 3 Oc 013 13 Se 01 Se 201 20 20 20 20 20 .2 2 2 l. 2 2 .2 2 2 2 2 2 .2 2 2 l. 2 .2 n. b. r. ay n. g. t. v. c. n. b. r. ay n. g. t. ar ar Ja Fe M IPP GenCo NIPP Source: Compiled by the authors from system operator data. Note: Open-cycle gas turbine (OCGT) sample: IPP—AES; GenCos—Afam IV/V, Delta, Olorunsogo I, Omotosho I; NIPPs—Omotosho II, Sapele II. GenCo = generation company; IPP = independent power project; NIPP = national integrated power project. Figure 7.7  Average Monthly Capacity Factors of Combined-Cycle Gas Turbines: Nigeria, January 2012–October 2013 100 90 80 70 60 Percent 50 40 30 20 10 0 Fe 012 M 012 Ap 012 M 012 Ju 012 Ju 12 Au 012 pt 2 Oc 012 No 012 De 012 Ja 012 Fe 013 M 013 Ap 013 M 013 Ju 013 Ju 13 Au 013 pt 3 Oc 013 13 Se 01 Se 201 20 20 20 2 2 .2 2 2 l. 2 2 .2 2 2 2 2 2 .2 2 2 l. 2 .2 n. b. r. ay n. g. t. v. c. n. b. r. ay n. g. t. ar ar Ja IPP GenCo NIPP Source: Compiled by the authors from system operator data. Note: Combined-cycle gas turbine (CCGT) sample: IPP—Afam VI, Okpai; GenCos—Geregu I; NIPP—Olorunsogo II. GenCo = generation company; IPP = independent power project; NIPP = national integrated power project. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 141 Figure 7.8  Capacity Factors of Various Technologies and Owners: Nigeria, FY2012/13 100 90 80 70 60 Percent 50 40 30 20 10 0 m GT GT GT GT GT GT te OC OC OC CC CC CC ys ls P o PP P o PP IP nC ta IP nC NI NI To Ge Ge Source: Compiled by the authors from system operator data. Note: CCGT = combined-cycle gas turbine; GenCo = generation company; IPP = independent power project; NIPP = national integrated power project; OCGT = open-cycle gas turbine. gas turbines (OCGTs and CCGTs). Only plants that were operational for the majority of the reference period were included. Privately owned OCGT and CCGT plants in Nigeria are operated much closer to their available capacity than the state-owned generation companies and NIPP plants. IPPs also seem to have more consistent capacity factors than pub- licly owned plants. The average capacity factors are summarized in figure 7.8, which includes the total system’s average capacity factor. The NIPP plants are newer plants, and the lower capacity factors experienced over the period are likely attributable to gas supply constraints. It should also be noted that the publicly financed NIPPs took up to 10 years to build and complete, much longer than the IPPs. Electricity Pricing A principal driver of Nigeria’s power sector reforms is the need for cost-reflective tariffs. Prior to the reforms, electricity was considered a public welfare service to be provided by the government, and was therefore heavily subsidized. A uniform pricing structure was used, and tariffs remained fixed for years despite rising energy costs. Between 2002 and 2008, the tariff averaged around naira (N) 4.50–  N6.00/kilowatt-hour (kWh) (U.S. cents [USc] 3–4/kWh), and the PHCN operated with monthly deficits of close to N2 billion ($12.1 million)—see Bello 2013. These tariffs restricted the ability of the utility to invest in new infrastruc- ture and discouraged the entry of private IPPs. The EPSRA (2005) describes the objectives of tariff regulations for the indus- try and places responsibility for the setting and reviewing of electricity prices Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 142 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria with the NERC. As described in the act, electricity prices and tariff methodolo- gies shall: business • Allow a licensee that operates efficiently to recover the full costs of its ­ activities, including a reasonable return on the capital invested in the business. • Provide incentives for the continued improvement of the technical and economic efficiency with which the services are provided. ­ • Provide incentives for the continued improvement of quality of services. • Give consumers economically efficient signals regarding the costs that their consumption imposes on the licensee’s business. • Avoid undue discrimination between consumers and consumer categories. • Phase out or substantially reduce cross-subsidies. The NERC employs the MYTO methodology for determining tariffs. The MYTO provides a 15-year price path for the industry with minor7 tariff reviews every two years and major8 reviews every five years (NERC 2012). Introduced in 2008, the MYTO-1 was based on an efficient new-entrant model; the long-run marginal cost (LRMC9) method was used to determine the unit price of an effi- cient plant. Tariffs for the first five years ranged from N9/kWh to N11.50/kWh (USc 5–7/kWh), and the gap between the required tariff and what customers were billed was gradually removed; only the poorest customers now receive a subsidy (Bello 2013). The MYTO-2 (for the period up to 2017) came into effect on May 31, 2012, and included more flexibility in wholesale generation pricing and considered new fuel types such as coal and renewables. In addition, market data (industry costs and so on) for the development of tariffs and regulatory financial models are now obtained directly from market participants as opposed to regulator estimates (Bello 2013). Following a loss verification exercise, the NERC published an amended MYTO in early 2015 that disallowed collection losses. Exchange rate, inflation, generation, and gas price adjustments were also made. Tariff increases for some residential customers were frozen. The arbitrary reduction of tariffs by the NERC contradicted terms in the privatization agreements and threatened the financial viability of the sector. Following elections, and the advent of the new administration, in mid-2015 the NERC agreed to reconsider its previous decision and move toward cost-reflective tariffs. State Investment in Power Projects in Nigeria The 10 NIPPs—totaling 5,000 MW—compose the largest publicly financed power program in Sub-Saharan Africa, outside South Africa. The program was initiated during the Obasanjo presidency with an allocation of $2.5 billion in 2005 from the Excess Crude Account (ECA, owned by all three tiers of govern- ment and used to collect oil revenues above a defined benchmark price). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 143 Following a change in government in 2007, funding for the NIPPs was suspended for 2.5 years while the new Jonathan administration queried funding, legal, and political issues surrounding the program. The release of a further $5.4 billion was then approved as a power emergency fund to complete the projects and fund transmission and gas infrastructure (PTFP 2013). Ten years after the initiation of this program, several power stations are still not fully commissioned. The poor construction and completion record of the NIPPs stands in stark contrast to the IPPs described below. The privatization of the NIPPs has also not gone as well as the sale of the suc- cessor generation and distribution companies. It has been delayed in part by gas and transmission constraints and the lack of sovereign guarantees for payment and political risks. The government expects to generate about $3.2 billion from the sale of the NIPP plants, with at least half of the proceeds being earmarked for investment in transmission. Independent Power Project Investments in Nigeria IPPs in Nigeria have developed over a period of 15 years and in very different policy, legislative, regulatory, and market contexts; accordingly, they have been structured and financed in various ways. Figure 7.9 shows the timing of IPP invest- ments in relation to key reform interventions. As previously indicated, there have been four generations of IPPs. The first-generation AES IPP was initiated in the pre-reform period. Then two IOC stopgap IPPs—Okpai and Afam V—were Figure 7.9  Timeline of Power Sector Reform Interventions and Generation Investments: Nigeria, 1998–2015 NEPA converted to PHCN and sector unbundling starts Roadmap for Power Sector Reform National Electricity Electricity Regulatory Presidential Decree NEPA Commission Action Amendment National established Committee PACP Successor Transitional Act Private sector Electric on Power reconstituted GenCos Electricity participation Power Electric Power (PACP) and PTFP and DisCos Market permitted Policy Sector Reform Act established formed privatized declared 1998 2001 2005 2010 2012 2013 2015 Pre- Obasanjo era (1999–2007) Jonathan era (2010–15) reform 1999 2001 2005 2015 AES IPP Okpai Agip IPP NIPPs 2001 2008 2015 Afam V Shell IPP Aba Integrated IPP Azura IPP Note: DisCos = distribution companies; GenCos = generation companies; IPP = independent power project; NEPA = National Electric Power Authority; NIPP = national integrated power project; PHCN = Power Holding Company of Nigeria; PTFP = Presidential Task Force on Power. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 144 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria developed with generous, but not-to-be repeated, tax incentives as President Obasango kick-started power sector reforms. President Jonathan later reinvigo- rated power sector reforms with the development of a Roadmap for Power Sector Reform and the inauguration of the PACP and the PTFP. The Aba Integrated IPP was developed during this period. It has been something of an anomaly, as it is not connected to the national grid and seeks to serve mainly industrial, local demand. Finally, with the TEM and NBET being established, a new set of classic, project- financed IPPs were developed, with Azura the first of the new batch. Since power sector reforms opened up the market, there has been consider- able interest from the private sector; the NERC received over 100 applications for generation licenses. However, as alluded to earlier, gas supply remains a major limiting factor, and the NERC has declared that only generators with a secured gas supply will be considered for a license (Business Day 2014). The NERC Regulations for Embedded Generation (2012) make provision for embedded generators of below 20 MW to operate without central dispatch. This might open space for more regional and local IPPs to enter the market. AES Barge Ltd. The AES Barge project was the first IPP deal in Nigeria, dating back to 1999 (table 7.9). Amid an emergency power situation, and following the 1998 passage of a law10 allowing private sector participation, negotiations for a two-part project began. The plans were for a 90 MW diesel barge-mounted plant and a 560 MW Table 7.9  Overview of AES Barge, an Independent Power Project, Nigeria Plant AES Barge Contract details 13.25-year PPA (build-own-operate) Location Egbin, Lagos State U.S. dollar denominated Capacity 270 MW Flat capacity charge (OECD CPI indexed) $19.35/kW/month (November 2006) No energy charge Ownership 95% AES Limited (U.S.) Financing $120 million loan 5% Yinka Folawiyo Power Limited (Nigeria) Foreign and local debt (Rand Merchant Bank [RMB], FMO, African Export-Import Bank, Diamond Bank Nigeria, Fortis Bank, KfW, United Bank for Africa, African Merchant Bank) Technology Open-cycle gas turbines (9 × 30 MW) Security Sovereign guarantee—$60 million letter of credit (Ministry of Finance) OPIC political risk insurance Value $240 million ($888/kW) Fuel contract No separate fuel supply contract COD June 2001 NEPA (now PHCN) provides fuel purchased directly from Nigeria Gas Company Sources: Eberhard and Gratwick 2012; Adegbulugbe and others 2007. Note: COD = commercial operation date; CPI = consumer price index; FMO = Netherlands Development Finance Company; KfW = Kreditanstalt für Wiederaufbau; kW = kilowatt; MW = megawatt; NEPA = National Electric Power Authority; OECD = Organisation for Economic Co-operation and Development; OPIC = Overseas Private Investment Corporation; PHCN = Power Holding Company of Nigeria; PPA = power purchase agreement. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 145 permanent gas-fired plant with a common PPA. The deal was directly negotiated within a few months between the U.S.-based Enron, the Lagos state government, the NEPA, and the Ministry of Power and Steel (Eberhard and Gratwick 2012). Strong objections to the project and mounting public pressure resulted in the deal being modified. The objections included the lack of a transparent and com- petitive process, excessive contract termination payments, a lack of penalties for poor performance, and excessive capacity charges. The project design was modi- fied by increasing the barge-mounted plant to 270 MW and changing the fuel type from diesel to natural gas. Plans for a 560 MW permanent plant were shelved, and the new deal was concluded six months later, in 2000 (Eberhard and Gratwick 2012). Prior to filing for bankruptcy, the majority shareholder, Enron, sold its stake in the plant to AES Limited (95 percent over two sales) and Yinka Folawiyo Power Limited (5 percent), which had been the local adviser to Enron since project inception. Enron did not complete construction, and the EPC contract was handed over to the AES. The plant began operation in 2001. In the absence of a reform policy and law, initial risk allocation was skewed in favor of the private developer. Certain terms in the contract, such as the availability deficiency payment terms and tax exemp- tion certificate, have since been renegotiated. Furthermore, there have been fuel supply constraints on the plant’s operations relating to unrest in the Niger Delta region. Supply constraints and uncompetitive operating costs have meant that the plant has been essentially mothballed for some years. Okpai (Agip) The next IPP deal also came as a result of severe electricity supply shortages. Okpai (table 7.10) resulted from a policy, launched in 2001, that aimed to con- tain the problem of gas being wasted through flaring from oil fields in Nigeria. In 2001, during the Obasango presidency, the NEPA invited prequalified bidders (namely IOCs) to bid for a two-phase 480 MW gas plant (300 MW OCGT with conversion to 480 MW CCGT). This deal included the required gas infrastruc- ture and was to be structured on a build-own-operate (BOO) basis (Eberhard and Gratwick 2012). The application of the Associated Gas Framework Agreement (AGFA) to these investments allowed IOCs to offset the costs under the joint venture oil and gas activities and depreciate the assets rapidly. These were undoubtedly the most attractive incentives offered to private power gen- eration investments on the continent. A consortium led by Agip Oil won the bid to build the plant, and the PPA was signed in 2001. While it involved less back-and-forth than the preceding IPP deal, the project was subject to dramatic cost escalations (from $300 million to $462 million) between contracting, signing, and the start of commercial opera- tions in 2005. The escalations were mainly due to acts of vandalism and an underestimation of the required gas infrastructure. They prompted a dispute among the parties involved; until this was settled (out of court), payments were not made to the IPP (Eberhard and Gratwick 2012). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 146 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Table 7.10  Overview of Okpai, an Independent Power Project, Nigeria Plant Okpai IPP Contract details 20-year PPA (build-own-operate) Location Okpai, Delta State U.S. dollar denominated Capacity 450 MW Capacity charge: $13.00/kW/month (2006) Energy charge: 2.2 USc/kWh (2006) Ownership 60% NNPC Financing 100% equity financed 20% Agip Oil Company (Italy) 60% NNPC 20% Phillips Oil Company (U.S.) 20% Agip 20% Phillips Technology Combined-cycle gas turbine Security PPA backed by oil revenue of NNPC Value $462 million (includes gas Fuel contract Agip to provide fuel infrastructure) COD 2005 EPC Alstom Sources: Eberhard and Gratwick 2012; Adegbulugbe and others 2007. Note: COD = commercial operation date; EPC = engineering, procurement, and construction; IPP = independent power project; kW = kilowatt; kWh = kilowatt-hour; MW = megawatts; NNPC = Nigerian National Petroleum Corporation; PPA = power purchase agreement. Okpai and Afam VI (described below), were entirely equity financed, with the Nigerian National Petroleum Corporation (NNPC) taking a majority share and the oil companies the balance. Generous depreciation allowances made these projects attractive for investors. Thus, these were not classic IPPs relying on non- recourse project finance. Afam VI (Shell) As with the Okpai IPP, the NEPA invited several IOCs to bid for the two-part Afam project. The project included the refurbishment of Afam V and the procurement of the new Afam VI plant (table 7.11). A consortium led by ­ Shell Petroleum Development Company won the bid in 2001; the plant began operations in 2008. Table 7.11  Overview of Afam VI, an Independent Power Project, Nigeria Plant Afam Phase VI Contract details 20-year PPA Location Afam, Rivers State Afam V (acquire-own-operate) Capacity 630 MW Afam VI (build-own-operate) U.S. dollar denominated PPA Ownership 55% NNPC Financing 100% equity financed 30% Shell (UK/Netherlands) 55% NNPC 10% Elf/Total (France) 30% Shell 5% Agip Oil Company (Italy) 10% Elf 5% Agip Technology Combined-cycle gas turbine (3 × 148 MW Security Letter of credit (Ministry of Finance) gas turbine) (1 × 230 MW steam turbine) Value $540 million Fuel contract Shell provides gas supply COD 2008 EPC Daewoo E&C Source: Eberhard and Gratwick 2012. Note: COD = commercial operation date; EPC = engineering, procurement, and construction; MW = megawatt; NNPC = Nigerian National Petroleum Corporation; PPA = power purchase agreement. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 147 Arrangements were similar to that of the Okpai IPP, and involved a U.S.- dollar-denominated PPA and full equity financing. The main difference between the arrangements was that the PPA in the Afam VI deal was backed by a letter of credit (LC) from the Ministry of Finance and not by the oil revenues of the NNPC. A LC was sufficient security for the deal. Other international petroleum companies with a presence in Nigeria—such as Total, Exxon, and Chevron—did not participate in these IPP opportunities, although Chevron is now looking at a new IPP development to monetize domes- tic gas (as international liquefied natural gas [LNG] prices fall). Other IOCs could follow, although they are unlikely to benefit from the generous tax incen- tives that were offered under the AGFA. Aba, an Integrated Power Project The Aba project (table 7.12) is an integrated generation and distribution project that was directly negotiated with the city of Aba in Abia State and was spear- headed by the former minister of power, Barth Nnaji, who chairs the lead ­ sponsor, Geometric Power. A 141 MW OCGT plant and a distribution network were developed in the Aba and Ariaria business district under a 15-year lease between Geometric and the Enugu Distribution Company (LeBoeuf, Lamb, Greene, & MacRae 2006). The project is ring-fenced and does not feed into the national grid operated by the TCN. Construction began in 2008. The project was to be commissioned in October 2013, but the plant is not yet operational because of issues with the gas pipeline and disputes regarding the licensed area. Stretching 27 kilometers (km) from the plant to Shell’s Imo River facility, the gas pipeline was completed in September 2013; however, inconsistencies in design between Geometric Power and Shell caused a setback (Africa Oil and Gas Report 2014). An even more serious issue Table 7.12  Overview of Aba, an Integrated Power Project, Nigeria Plant Aba Integrated Power Project Contract details PPAs with Aba distribution company (same parent Location Aba, Abia State company) and directly with Aba industrial customers Capacity 141 MW Ownership Geometric Power Ltd. (Nigeria) Financing Debt-equity mix Senior debt: Diamond Bank (Nigeria) and Stanbic IBTC Bank (Nigeria) Subordinated debt: IFC, EIB, and Emerging Africa Infrastructure Fund Technology Open-cycle gas turbine Security n.a. Value $460 million (including gas and Fuel contract Fuel supply agreement with Shell T&D infrastructure) COD Currently being refinanced EPC General Electric Source: LeBoeuf, Lamb, Greene, & MacRae 2006. Note: COD = commercial operation date; EIB = European Investment Bank; EPC = engineering, procurement, and construction; IFC = International Finance Corporation; IPP = independent power project; MW = megawatts; PPA = power purchase agreement; T&D = transmission and distribution; n.a. = not applicable. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 148 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria is a dispute with the local distribution company regarding the licensed area. The project is intended to serve primarily industrial clients, which is a demand cluster that no distributor is willing to give up; hence, tensions over the service area are ongoing. Aba claims to have a license from the NERC, but the new privatized distribution company claims to have a concession for the area and disputes Aba’s claim on industrial customers. The Aba project, initially corporate financed, was refinanced during construc- tion. As the commercial operation date (COD) was delayed, debt built up; the banks have since taken over. While this embedded generation model has poten- tial advantages, the project delays also reveal how distribution companies may resist IPPs cherry-picking larger customers. Azura-Edo (Entering Construction) Azura has been a path-breaking IPP development in Nigeria and is the first project-financed power generation project since reforms began (table 7.13). Investment costs—at $895 million for a 459 MW OCGT—are high and reflect perceptions of risk. The counterparty of the PPA is the newly created NBET, which has insufficient liquidity and is dependent on revenue flows from newly privatized distribution companies that are still experiencing high losses and insufficient collections. Development costs have been high. Each contract has had to be negotiated from scratch. With Azura being the first IPP in several years, there was no ready-made template to follow, and capacity had to be built among Table 7.13  Overview of Azura-Edo, an Independent Power Project, Nigeria Plant Azura-Edo IPP Contract details 20-year PPA with NBET Location Benin City, Edo State Capacity 459 MW Ownership Azura-Edo Ltd. (Mauritius) (97.5%) Financing $180 million equity (20%) and Edo State Government (2.5%) $715 million debt 15 debt providers, including DFIs, for example, IFC, FMO, and commercial banks Main equity sponsors: Azura-Edo Ltd., 97.5%, comprising APHL, 50% (Amaya Capital 80%, American Capital 20%); AIM, 30%; ARM, 6%; Aldwych, 14%; and Edo State, 2.5% Technology Siemens open-cycle gas turbine Security Credit Enhancement PRG (IBRD) Partial Risk Guarantee, Debt (IBRD) Political risk insurance (MIGA) Value $895 million Fuel contract 15-year fuel supply agreement with Seplat with a gas supply LC Financial close 2015 EPC Siemens and Julius Berger Nigeria Source: Compiled by the authors from various primary and secondary sources. Note: DFI = development finance institution; EPC = engineering, procurement, and construction; FMO = Netherlands Development Finance Company; IBRD = International Bank for Reconstruction and Development; IFC = International Finance Corporation; IPP = independent power project; LC = letter of credit; MIGA = Multilateral Investment Guarantee Agency; MW = megawatt; NBET = Nigerian Bulk Electricity Trading; PPA = power purchase agreement; PRG = partial risk guarantee. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 149 the various stakeholders. The project sponsor is a relatively small, cash-poor, first-generation developer that had to leverage equity partners and a large ­ ­ number of debt providers, each of which wanted to limit its exposure. The International Finance Corporation (IFC) was a co-lead arranger of the develop- ment finance institution (DFI) component of the debt, and the World Bank employed its full range of risk mitigation instruments to make the project bankable. The Multilateral Investment Guarantee Agency (MIGA) provided a full equity guarantee as well as a partial risk debt guarantee. The International Bank for Reconstruction and Development (IBRD) provided a credit enhancement guarantee to the NBET and commercial debt mobilization guarantees. Specifically, the IBRD PRG backstops payment obligations by the NBET, which provides security under the PPA in the form of an LC issued by a commercial bank in favor of the IPP. The LC can be drawn in the event the NBET or the government of Nigeria fails to make timely payments to the IPP. Following the drawing up of the LC, the NBET would be obligated to make a repayment to the LC bank (under the reimbursement and credit agreement), failing which the LC bank would have recourse to the IBRD PRG under the Guarantee Agreement. This in turn would trigger the obligation of the federal government of Nigeria under the indemnity agreement. The commercial debt PRG provides direct support to commercial lenders in the event of a debt payment default caused by the NBET’s failure to make undis- puted payments under the PPA, or the government’s payments under a termina- tion of the PPA. There is also an LC for gas supply. The Azura-Edo IPP deal reached a significant milestone in 2014 with the sign- ing of key project documents and the finalization of debt arrangements; however, financial close was delayed until 2015 by the government’s reluctance to provide appropriate security. Given the complexity and cost of the Azura deal, questions have been raised as to whether project-financed IPPs are worthwhile in risky environments. The counterargument is that Azura has shown the way, and that subsequent IPPs will be much easier. In a sense, the development and risk mitigation costs of Azura could be seen as spread across a large pool of IPPs currently under development. Future IPPs will be less costly to develop; hopefully, they will also require less risk mitigation. Chinese-Funded Projects China is one of the fastest-growing sources of funding for power projects in Africa. This section examines the three Chinese-funded deals that have reached completion in Nigeria. Olorunsogo I Phase I of the Olorunsogo plant was completed in 2007 (table 7.14). It was built by the Chinese EPC contractor SEPCO-Pacific Partners. The original agreement Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 150 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Table 7.14  Overview of Olorunsogo I Power Plant, Nigeria Plant Olorunsogo I (Papalanto) Location Olorunsogo, Ogun State Capacity 335 MW EPC SEPCO-Pacific Partners Technology OCGT Value $360 million COD 2007 Source: Compiled by the authors from various primary and secondary sources. Note: COD = commercial operation date; EPC = engineering, procurement, and construction; MW = megawatt; OCGT = open-cycle gas turbine. was to have the PHCN provide 35 percent of the funding for the project, with the balance to be provided by SEPCO through vendor financing. Proceeds from the sale of electricity would then be used to repay the vendor finance and interest. The Export-Import Bank of China provided a loan of $115 million with a 6 percent interest rate, 6-year grace period, and 12-year maturity period (Premium Times 2014; AidData 2012a). Owing to delays in completion, a shortage of gas, and a lack of funds, the PHCN defaulted on its payments to SEPCO. The Debt Management Office took over the debt and, in line with the government’s privatization efforts, the plant was ceded to SEPCO through a debt-equity swap in March 2014 (Premium Times 2014). Since its completion, the plant has been operating far below its capacity. SEPCO had identified severe gas shortages and poorly trained PHCN staff as the principal reasons for the poor performance (Business News 2011). Omotosho I and II The Omotosho I deal was structured the same way as Olorunsogo (table 7.15). The PHCN was supposed to fund 35 percent of the plant, with the EPC contrac- tor (China Machinery Engineering Corporation, CMEC) funding the remaining Table 7.15  Overview of Omotosho I and II Power Plants, Nigeria Plant Omotosho I Plant Omotosho II (NIPP) Location Omotosho, Ondo State Location Omotosho, Ondo State Capacity 335 MW Capacity 500 MW EPC China Machinery Engineering EPC CMEC Corporation (CMEC) Technology OCGT Technology OCGT Value $361 million Value — COD 2008 COD 2012 Source: AidData 2012b. Note: COD = commercial operation date; EPC = engineering, procurement, and construction; MW = megawatt; NIPP = national integrated power project; OCGT = open-cycle gas turbine; — = not available. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 151 65 percent. The Export-Import Bank of China also provided a loan of $115 ­million (AidData 2012b). As with Olorunsogo, the government could not meet its payment obligations; by September 2012, the PHCN had accrued $104 million in unpaid debt to CMEC. The PHCN ceded control of the plant to CMEC through a debt-equity swap in March 2013 (Punch 2013). Phase II of Omotosho (part of the NIPP fleet) was also awarded to CMEC, but was not funded through the Export-Import Bank of China following the previous payment defaults by the government. Zungeru Hydropower Project In September 2013, the Nigerian government signed a deal with two Chinese firms (China National Electric Engineering Company and Sinohydro) to build the 700 MW Zungeru hydropower plant (table 7.16). The government approved funding for 25 percent of the project, with the Export-Import Bank of China funding 75 percent with low-interest loans. The project is the largest power proj- ect in Africa to be funded with government concessional loans (This Day Live 2013a). Table 7.16  Overview of Zungeru Hydropower Plant, Nigeria Plant Zungeru Location Zungeru, Niger State Capacity 700 MW EPC CNEEC-Sinohydro Consortium Technology Hydropower Value $1,293 million COD 2017 (expected) Source: Compiled by the authors from various primary and secondary sources. Note: CNEEC = China National Electric Engineering Company; COD = commercial operation date; EPC = engineering, procurement, and construction; MW = megawatts. Another Chinese-funded project in the pipeline is the Mambilla 3,050 MW hydropower plant in Taraba State, worth $3.2 billion. Negotiations began in 2006 with a consortium made up of the China Gezhouba Group Company Limited and China Geo-Engineering Corporation (CGGC/CGC), which were awarded the EPC contract for the project. The contract was then unilaterally cancelled by the Nigerian government and awarded to Sinohydro under contro- versial circumstances. CGGC/CGC disputed the cancellation, and negotiations have stalled for several years (This Day Live 2014). A New Role for Renewable Energy The development of renewable energy would potentially be very beneficial to Nigeria; it would help diversify the country’s energy mix away from thermal sources, reduce the carbon footprint of power generation, and boost the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 152 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria Table 7.17  Renewable Energy Targets for 2025, Nigeria Energy type Target (MW) Small hydro 2,000 Solar PV 500 Wind 40 Biomass 400 Source: Compiled by the authors, based on various primary and secondary source data. Note: PV = photovoltaic. reliability of supply. However, renewable energy has not gained acceptance and there are currently no grid-connected plants other than the three large hydropower plants. A Renewable Energy Master Plan was released in 2006 (and updated in 2011). This identified the considerable potential for renewable energy—a market estimated to be worth $7.5 billion. The plan includes capacity targets and an overall goal of 23 percent of electric- ity supplied from renewables by 2025 (table 7.17) and 36 percent by 2030. Furthermore, the plan implements a set of incentives to support renewable energy development: in the short term, a moratorium on import duties for renewable energy technology, and in the longer term, further tax credits, capital incentives, and preferential loan opportunities (REEEP 2014). The latest MYTO also included a set of feed-in tariffs (FiTs) for renewable energy. A number of unsolicited applications for licenses from the NERC and PPA contracts from the NBET involve renewable energy technologies, in particular solar photovoltaic (PV). Following its Procurement Regulations, the NERC has provided the NBET with a list of projects in the pipeline for which specific exemptions would be granted from the requirement to run competitive tenders for new generation capacity. Accordingly, the NBET is in direct negotiations with a number of these projects. The NBET is also doing preparatory work to run competitive tenders in the future. Conclusions Nigeria is in the middle of the most ambitious power sector reform process in Africa. It has unbundled generation and distribution utilities, and separated them from the TCN. It has privatized all of its distribution companies and most of its generating companies. The publicly owned NIPP generation plants are in the process of being sold. It has established a TEM with contracts between distribu- tion companies and the bulk trader (NBET) and between generators and the NBET. And it has an independent electricity regulator. No other African country has journeyed as far as Nigeria in power sector reforms. None has fully unbundled and privatized and embarked on a contract market that will eventually lead to wholesale competition. (Uganda comes the closest: it also unbundled generation, transmission, and distribution, but it has awarded private concessions rather than selling assets and does not envisage wholesale competition.) Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 153 Nigeria’s reform path has been far from smooth. It has taken time to trans- late into reality the restructuring vision and model embodied in the National Electric Power Policy (2001), the EPSRA (2005), and the Roadmap for Power Sector Reform (2010, 2012). But against all odds, Nigeria has made progress, aided by a clear road map and high-level support from the president and the PACP and PTFP. Individual institutions have also played their role in driving the reform forward: the BPE, for example, has driven the privatization pro- cess, albeit with assistance from transaction advisers and the Nigeria Infrastructure Advisory Facility, funded by the Department for International Development (DfID), which continues to provide extensive professional sup- port across the sector. The challenges and risks have been formidable. It is remarkable that genera- tion and distribution assets were sold without the activation of the TEM and without sufficient revenue flowing from customers (through distribution compa- nies) to the market operator—and on to generation companies and gas suppliers. Each new step along the reform path has prompted new issues that have required further interventions. Nigeria has not waited for all steps to be clearly defined and agreed upon before moving. Rather, the “Nigerian way” has been to catalyze a strong momentum for reform that becomes difficult to reverse and that forces political decisions and interventions along the way. The journey has not been without obstacles. It was not clear whether the purchasers of assets would be able to make final payments (they did). Unions raised their voice before the assets were handed over. Concerns about unresolved conditions and financial sustainability delayed the activation of the TEM for more than a year after the target launch date (but it has since been launched). And poor billing and revenue collection, liquidity constraints, and mounting debt threatened the financial viability of the sector (but a bold intervention by the CBN helped keep the privatized companies afloat, and contracts are being ­ activated). It is not clear if the “Nigerian way” will sustain the reforms. Election- related pressure to reduce tariffs did not help, and financial sustainability has yet to be demonstrated; also, it remains to be seen whether the momentum for reform will be maintained after the 2015 elections. Despite reform efforts, meanwhile, Nigeria has not been able to attract suf- ficient investment in power generation capacity. The largest source of new generation to date has been public funding for the NIPPs, which are now in the process of being privatized. There have also been significant amounts of invest- ment in IPPs. Indeed, excluding South Africa, Nigeria has more privately funded megawatts than any other country of Sub-Saharan Africa. These are not all traditional project-financed IPPs: two are funded by IOCs. Data presented earlier show that the performance of IPPs has been superior to state-owned generation plants; IPPs’ more reliable gas supply probably contributes to the difference. Interestingly, the first wave of IPP investments preceded power sector reform. And the most recent IPP power purchase contracts were signed during a period of financial uncertainty. Incomplete reform and financial shortfalls in the sector Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 154 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria have not blocked IPP investments. However, not many countries would have been able to divert massive financial allocations (in Nigeria’s case, from oil rev- enues) to keeping electricity companies afloat. Without serious efforts to achieve financial sustainability in the industry, private investments will be at risk. IPPs have entered the sector either through limited bids (for example, the IOCs) or as a result of directly negotiated contracts; price outcomes have not been optimal. Details of PPAs have not been made available, and hence it is dif- ficult to make definitive conclusions around comparative prices. It should be noted, however, that the directly negotiated Enron/AES Barge has been the most controversial project and the contract had to be renegotiated. It looks likely that IOCs are once again interested in IPP investments in Nigeria, mainly to monetize domestic gas resources. ExxonMobil’s project is well advanced, and may be followed by others. Nigeria will need to make sure that it is able to negotiate more competitively priced PPAs than in the previous era of IPPs. The directly negotiated Azura project also looks expensive. However, Azura has been a trailblazer in negotiating the current terrain for IPPs. None of the previous IPPs, negotiated and contracted in a different era, offered a model that could be emulated. The project developers for Azura had to craft contracts from scratch and had to build understanding among a new generation of government, regulatory, and bulk trader officials on the risk mitigation requirements for ­ project finance. A large proportion of Azura’s costs went into these efforts, which will hopefully be beneficial for subsequent IPPs, even those that might be ­competitively bid. Nigeria does not yet have a benchmark for international competitive bids (ICBs) versus directly negotiated projects. However, the NERC has mandated competitive tenders through its Regulations for the Procurement of Generation Capacity, published in 2014. It is hoped that the NBET will commence interna- tional competitive tenders in the near future. It is also hoped that capacity will be built for effective generation planning, and that the system operator will issue regular demand and supply forecasts that will trigger initiatives to procure new capacity. The lack of such forecasts has been a weakness of the Nigerian power sector. Regular and dynamic generation expansion plans—linked directly to competitive procurement and effective ­contracting—are needed. Also noteworthy in Nigeria has been the entry of Asian power investors—in the form of Korea’s KEPCO and also the Chinese EPC contractors, which later took over ownership in debt-equity swaps. Chinese-funded investment in power is on the rise across the continent. Traditional government-to-government loan deals are being supplemented by Chinese participation in special-purpose proj- ect vehicles (SPVs) and in joint ventures. And Chinese EPCs are starting to take equity positions in projects. More work needs to be done to unpack the terms and outcomes of these projects. Nigeria does not yet have any grid-connected renewable energy projects (other than hydropower), but there are a number of solar PV projects in the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 155 pipeline that are being negotiated by the bulk trader, NBET. Initial indications are that these prices might be higher than in other African countries, in part because of the lower solar resources, but also, no doubt, because of country and sector risk. Preparatory work is being done for competitive bids for renewable energy. In a few years’ time it will be worthwhile to compare their price outcomes with those of directly negotiated projects. Some of these projects are also being con- sidered for support by the World Bank PRGs. Considerable challenges remain, and the financial sustainability of the sector is still uncertain. Not all contracts are in force. It remains to be seen whether Nigeria’s power sector reforms will accelerate investment so that the country’s huge power needs might be met. What are the lessons for other African countries? Clearly, the extensive power sector reforms in Nigeria have not been a panacea. Few other African countries have sought to completely unbundle and privatize their entire electricity sector, and none have set up a wholesale electricity trader. Nevertheless, Nigeria has dem- ­ limate. Here, onstrated that it is possible to attract IPPs in a challenging investment c IPPs have not only been built more quickly than publicly funded projects but have resulted in superior performance. The poor financial performance of Nigeria’s dis- tribution companies, and the insecurity of gas supplies, has added risk to new IPP investments—risks that have had to be mitigated through extensive credit enhance- ment and security measures. Other African countries with risky investment cli- mates can learn from what was required in Nigeria, but, hopefully, the extent and cost of these risk mitigation instruments might fall over time as the financial sus- tainability of the sector improves. And here lies a key lesson: ultimately, IPP invest- ments rely on secure revenue flows from customers and distribution companies. There is no way to avoid the fundamental challenge of improving the technical and commercial performance of electricity distribution utilities. Indeed, the future suc- cess of Nigeria’s power sector reforms and investment program depends on it. Notes 1. These included five of the original unbundled generation companies with the addition of Geregu I, commissioned in 2007. The Egbin negotiation was handled separately. 2. MYTO-2 for the period up to 2017, as presented later in the text. 3. Million standard cubic feet (oil industry). 4. The highest recorded peak generated was 4,517 MW on December 23, 2012, although this may have since been superseded. 5. These plants are often referred to as IPPs as the federal government does not own them. However, they are still publicly owned by the states in which they operate. 6. The U.S. Energy Information Administration’s definition is “the ratio of the electrical energy produced by a generating unit for the period of time considered to the electri- cal energy that could have been produced at continuous full power operation during the same period.” 7. Taking into account inflation, gas prices, foreign exchange (FOREX) rates, and actual daily generation capacity. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 156 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 8. A comprehensive review of all assumptions in the MYTO model. 9. The LRMC calculates the full life-cycle cost of the most efficient new generator, considering the current costs of the plant and equipment, return on capital, operation, ­ maintenance, fuel, and so on. 10. Electricity (Amendment) Decree 1998 and the NEPA (Amendment) Act 1998. References Adegbulugbe, A. O., A. S. Momodu, A. Adenikinju, J. F. Akinbami, and P. O. Onuvae. 2007. “Balancing the Acts in the Power Sector: The Unfolding Story of Nigeria Independent Power Projects.” 27th USAEE/IAEE North America Conference, September 16–19, 2007. Africa Oil and Gas Report. 2014. “Commissioning Hitches Delay Gas Supply to Geometric Power Plant.” http://africaoilgasreport.com/2014/05/gas-monetization​​ /­commissioning-hitches-delay-gas-supply-to-geometric-power-plant/. AidData. 2012a. “Construction of Papalanto Power Gas Turbine Power Plant.” http:// china.aiddata.org/projects/173. /27948. ———. 2012b. “Omotosho Power Plant Phase I.” http://china.aiddata.org/projects​ allAfrica. 2013. “Nigeria: BPE Offers Egbin Power Plant to KEPCO.” April 3, 2013. http:// allafrica.com/stories/201304030622.html. Bello, S. L. 2013. “Evaluating the Methodology of Setting Electricity Prices in Nigeria.” IAEE Energy Forum 4th Quarter, 2013. http://www.iaee.org/en/publications​ /­fullnewsletter.aspx?id=28. BPE (Bureau of Public Enterprises). 2013. “Power Privatisation Objectives Prospects and Challenges.” Lagos Business School, September 11. http://www.lbs.edu.ng​ /­LBSBreakfastClub/Power%20Privatisation%20Objectives%20Prospects%20and%20 Challenges.pdf. Business Day. 2014. “Gas Challenge Harming IPPs in Nigeria.” Business Day Online, June 11, 2014. http://businessdayonline.com/2014/06/gas-challenge-harming​ -­ipps-in-nigeria/#.VFiCfpPoy_E. Business News. 2011. “Low Megawatts Generation at Papalanto Is Not Our Fault— Chinese Firm.” http://businessnews.com.ng/2011/08/31/low-megawatts-generation​ -at-papalanto-is-not-our-fault-chinese-firm/. Daily Independent. 2014. “Nigeria: BPE Blames Gas Supply Problems for Delay in NIPPs’ Sale.” September 24. http://allafrica.com/stories/201409251011.html. Eberhard, A., and K. Gratwick. 2012. “Light Inside: The Experience of Independent Power Projects in Nigeria.” Infrastructure Consortium for Africa Working Paper, Tunis. EIA (U.S. Energy Information Administration). 2013. “Nigeria Country Overview.” http:// www.eia.gov/countries/cab.cfm?fips=ni. Federal Ministry of Power. 2014. http://www.power.gov.ng/. Ikeonu, I. 2006. “The Nigerian Electric Power Sector Reform: Establishing an Effective Licensing Framework as a Tool for Attracting Investment.” February. http://www.ip3​ .org/ip3_site/the-nigerian-electric-power-sector-reform-establishing-an​ -­effective​ -licensing-framework-as-a-tool-for-attracting-investment.html?print=1&tmpl​ ­=component​#sthash.8Ri12U98.dpuf. LeBoeuf, Lamb, Greene, & MacRae. 2006. “First IPP in Nigeria.” http://www.icafrica.org​ /­fileadmin/documents/First_IPP_in_Nigeria_v1.PPT. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 2: Independent Power Projects and Power Sector Reform in Nigeria 157 NERC (Nigerian Electricity Regulatory Commission). 2012. “Multi-Year Tariff Order 2.” http://www.nercng.org/index.php/myto-2. ———. 2014. “Regulation for the Procurement of Generation Capacity.” NERC, Abuja. Niger Delta Power Holding Company. 2013. “National Integrated Power Project.” http:// ndphc.net/?page_id=3331. Okoro, O. L., and E. Chikuni. 2007. “Power Sector Reforms in Nigeria: Opportunities and Challenges.” Journal of Energy of South Africa 18 (3): 52–57. PACP (Presidential Action Committee on Power). 2010. Roadmap for Power Sector Reform. Lagos: The Presidency of the Federal Government of Nigeria. Premium Times. 2014. “Nigerian Government Hands Over Olorunsogo Power Plant to SEPCO.” https://www.premiumtimesng.com/business/156303-nigerian-government​ -hands-olorunsogo-power-plant-sepco.html. PTFP (Presidential Task Force on Power). 2013. “Accelerating Delivery of Projects.” http:// nigeriapowerreform.org/index.php?option=com_content&view=article&id=430​ :accelerating​-delivery-of-projects-a-period-of-harvest-for-nipp&catid=36:sector-news​ &Itemid=336. ———. 2015. 2014 Year in Review. Abuja, Nigeria: PTFP. Punch. 2013. “FG to Sell Omotosho Power Plant for $82 m.” http://www.punchng.com​ /­business/business-economy/fg-offers-omotosho-power-plant-to-cmec-pacific/. ———. 2014. “Power: Nigeria Loses 2,994 MW to Gas Shortage, Faults.” http://www​ .punchng.com/business/business-economy/power-nigeria-loses-2994mw​ -to-gas-shortage-faults/. REEEP (Renewable Energy and Energy Efficiency Partnership). 2014. “Nigeria.” http:// www.reegle.info/policy-and-regulatory-overviews/ng. This Day Live. 2013a. “Nigeria, China Sign $1.293bn Zungeru Power Plant Deal.” http:// www.thisdaylive.com/articles/nigeria-china-sign-1-293bn-zungeru-power​ -plant-deal/160195/. ———. 2013b. “Shell Shuts Down 624 MW Afam VI Power Plant.” http://www​ .­thisdaylive.com/articles/shell-shuts-down-624mw-afam-vi-power-plant/153576/. ———. 2014. “FG, China to Discuss $3.2bn Mambilla Contract Imbroglio.” http://www​ .thisdaylive.com/articles/fg-china-to-discuss-3-2bn-mambilla-contract​-imbroglio​ /177824/. World Bank. 2014. “World Development Indicators 2014.” Washington, DC. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 C h apter 8 Case Study 3: Investment in Power Generation in South Africa Introduction South Africa is a latecomer in introducing private investment and independent power projects (IPPs) into its electricity sector. For nearly a century, its national electricity utility, Eskom, dominated the power market. Various attempts to introduce IPPs were halfhearted and unsuccessful. However, this has changed during the past four years. South Africa now occupies a central position in the global debate about how best to accelerate and sustain private investment in renewable energy. In 2009, the government began exploring feed-in tariffs (FiTs) for renewable energy, but these were rejected in favor of competitive tenders. The result- ing program, known as the Renewable Energy Independent Power Project Procurement Programme (REIPPPP), has successfully channeled substantial ­ private sector expertise and investments into grid-connected renewable energy in South Africa at competitive prices. To date, 92 projects have been awarded to the private sector, and the first projects are already online. Private sector investments of more than $19 billion have been committed for projects that total 6,327 megawatt (MW) of renewable energy. Prices of renewable energy dropped during the four bidding phases, with average solar photovoltaic (PV) tariffs decreasing by 71 percent and wind dropping by 48 percent in nominal terms. Most impressively, these achievements occurred during a four-year period, from 2011 to 2015. Additionally, there have been notable improvements in eco- nomic development that have primarily benefitted rural communities. Important lessons can be learned from this process for both South Africa and other emerging markets contemplating investments in renewable energy and other power sources. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   159   160 Case Study 3: Investment in Power Generation in South Africa Table 8.1  South Africa: An Overview Population 52.98 million (2013) Generation capacity 45 GW Gross domestic product $350.6 billion (2013) Electricity production 256,100 GWh Income level Upper middle income Electricity intensity 4,694 kWh per capita Area 1,219,912 km² (consumption per capita) Primary electricity source Coal (90%) Sources: World Bank, Energy Information Administration, and Eskom. Note: GW = gigawatt; GWh = gigawatt-hour; km2 = square kilometer; kWh = kilowatt-hour. South Africa’s Electricity Sector: An Overview Until recently, South Africa was Africa’s largest economy.1 Its electricity genera- tion amounts to more than half of the 80 gigawatts (GW) of installed capacity in Sub-Saharan Africa. Table 8.1 and map 8.1 list further information about South Africa’s population and electricity supply. Structure of South Africa’s Electricity Supply Industry South Africa’s electricity supply industry is dominated by the state-owned and vertically integrated utility, Eskom (figure 8.1). With a capacity of approximately 42 GW, Eskom generates approximately 96 percent of South Africa’s electricity. Private generators contribute approximately 3 percent of national output, and municipalities contribute an additional 1 percent. South Africa is largely self-sufficient in electricity production. Although Eskom imports some power from nearby regions, notably Mozambique, it sells electricity to neighboring countries, including Botswana, Lesotho, Mozambique, Namibia, Swaziland, Zambia, and Zimbabwe. Eskom owns and controls the high-voltage national transmission grid and supplies approximately half of the electricity generated directly to customers. ­ The other half is distributed through 179 municipalities. They buy bulk supplies of electricity from Eskom, although some generate small amounts to sell within their own areas of jurisdiction. Twelve of the largest municipalities account for approximately 80 percent of the electricity distributed by all of South Africa’s municipalities. The electricity sector is overseen by the Department of Energy (DoE, for- merly the Department of Minerals and Energy), and Eskom is governed by a shareholder compact with the Department of Public Enterprises (DPE). The National Energy Regulator of South Africa (NERSA) is responsible for regulating the electricity sector through approving tariffs and licensing electricity genera- tors, transmitters, distributors, and traders. Power Sector Reform in South Africa Two areas have been the focus of reform efforts in South Africa’s power sector during the past two decades: restructuring the fragmented electricity distribution industry, and unbundling Eskom to facilitate private investments in electricity generation. Neither has seen much progress. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 161 Map 8.1  Eskom’s Power Stations Source: Eskom. Electricity Distribution Reform South Africa’s constitution grants local governments the right and responsibil- ity to reticulate electricity; however, by the 1990s the power sector was prov- ing to be increasingly inefficient. In 1992, discussions about reforming the electricity distribution industry began at an electricity conference hosted by the African National Congress. In the years following this conference, a number Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 162 Case Study 3: Investment in Power Generation in South Africa Figure 8.1  Structure of South Africa’s Electricity Market National Energy Department of Department of Regulator of Public Enterprises Energy South Africa Eskom IPP1 IPP2 IPPn generation Eskom transmission Eskom distribution Municipal Municipal Municipal distributor1 distributor2 distributor179 Customers Note: IPP = independent power project. of stakeholder forums were established, including the National Electrification Forum, followed by the Electricity Working Group and later the Electricity Restructuring Inter-Departmental Committee. This work culminated in the PricewaterhouseCoopers Restructuring Blueprint Report and a number of cabinet decisions to reorganize the numerous municipal distributors and Eskom’s ­ distribution regions into six adequately resourced regional electricity distribution companies (REDs). In 2004, the government established Electricity Distribution Industry (EDI) Holdings Ltd. to implement these mergers. But despite years of talk, studies, and cabinet decisions, very little progress was made toward establishing the REDs. In the end, the government accepted that a constitutional amendment was unlikely, and thus in 2010 the cabinet decided to abandon the RED model and disband EDI Holdings. Restructuring Eskom In the mid-1990s, the government adopted a program of self-imposed structural adjustment. Following a period of attention to macroeconomic reforms, Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 163 the emphasis moved to microeconomic reforms, including a new focus on improved efficiencies and governance in government-owned entities. In 2000, the DPE published “Policy Framework: An Accelerated Agenda towards the Restructuring of State Owned Enterprises.” The Eskom Conversion Act of 2001 followed. Consequently, Eskom became a state-owned public corporation subject to the Companies Act. Eskom, along with other state-owned enterprises, had to pay taxes and dividends and was subject to a shareholder performance contract. The cabinet also approved a white paper on energy policy, released in December 1998, with the objective of achieving improvements in social equity, economic competitiveness, and environmental sustainability. The paper ­ emphasized the importance of allowing customers to choose their electricity supplier; introducing competition into the industry, especially in the generation sector; unbundling Eskom; permitting open, nondiscriminatory access to the transmission system; encouraging private sector participation; and establishing an independent regulator. Although an electricity regulator (NERSA) was estab- lished, few of these other proposals were implemented. After 2000, consultants were hired to design a power market for South Africa not dissimilar to Nord Pool in Scandinavia, which has a day-ahead power exchange, a bilateral contract market, and financial hedging instruments. But in 2004, worried about looming power shortages, South Africa’s government aban- doned these reforms as well and again placed the responsibility for new invest- ments in power on Eskom. A decade later, more modest reform proposals surfaced in the Independent System and Market Operator (ISMO) Bill, which was approved by the cabinet and passed by the Parliament of South Africa’s Energy Committee in March 2013. The objective of the bill was to remove potential conflicts of interest in Eskom as a buyer and seller of electricity. The bill called for the establishment of a publicly owned system operator (separate from Eskom) that would be respon- sible for system operations and purchasing electricity from the utility and pri- vately owned generators. Under the bill the transmission network would remain an asset of Eskom. However, the ISMO bill has been repeatedly delayed in the parliament, and it is unclear when or whether it will be reintroduced. Power Sector Planning, Allocation, Procurement, and Contracting South Africa has a well-defined, although quite rigid and dirigiste, electricity ­ planning and procurement system. Until 2006, Eskom assumed sole responsibil- ity for electricity planning and procuring new generation capacity. The Electricity Regulation Act (No. 4 of 2006) changed this by giving responsibility to the minister of energy to produce regular Integrated Resource Plans (IRPs) that ­ guide electricity generation investments. In practice, Eskom’s staff still produce the IRPs, but they do so now under the guidance and approval of the minister of energy. Pursuant to the Electricity Regulation Act, the minister of energy published the Electricity Regulations on New Generation Capacity in 2009 and revised them in 2011. The regulations apply only to the public procurement of power. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 164 Case Study 3: Investment in Power Generation in South Africa Section 4(1) of the regulations states that the minister of energy, after consulting with the regulator, shall develop an IRP and publish it in the Government Gazette. In addition, in consultation with the regulator, the minister of energy may make various determinations about new generation capacity, including whether it is necessary, what types should be procured, how much is needed, and who the buyer should be. The minister can require that it be procured through a tender- ing process that is fair, equitable, transparent, competitive, and cost-effective, and it can determine whether new capacity should be provided by Eskom, another state entity, or private power projects (Electricity Regulation Act, Sec. 46 [1], 2006; Electricity Regulations on New Generation Capacity, 2011). The public procurement principles of “fair, equitable, transparent, competitive, and cost- effective” are embedded in Section 217 of South Africa’s constitution and are repeated in the Public Finance Management Act (No. 1 of 1999). The regulations also stipulate that power purchase agreements (PPAs) should reflect current costs and provide value for money. Applicants for generation licenses have to provide evidence of compliance with the IRP or reasons for any deviations. The regulator can license only generation capacity that is envisaged in the plan and for which the minister ­ has issued a “determination,” although the minster is empowered to grant exemptions from the plan when they are justifiable (Electricity Regulation Act, Sec. 11, 2006). The IRP 2010–30 was gazetted in 2011 and is summarized in table 8.2. The first determination under these regulations on new generation capacity was gazetted by the minister of energy in 2011 and was for 3,725 MW of grid- connected renewable energy. A further ministerial determination was made in 2012 for 2,500 MW of power from coal, 2,652 MW from gas, 2,609 MW from hydropower, 800 MW from cogeneration, and an additional 3,200 MW from renewable energy. The IRP was updated in 2013 to include lower demand fore- casts, more gas, and less nuclear power; however, the updated plan has not yet been officially adopted. In 2015, the minister of energy determined that an addi- tional 6,300 MW of renewable energy should be procured. These ministerial determinations have initiated a quiet revolution in South Africa’s power sector. In each case, the minister has stipulated that new capacity should be provided by IPPs rather than Eskom. Competitive tenders have been issued for renewable energy (described ahead) and coal, and subsequent tenders are planned for cogeneration and gas. Eskom Installed Capacity Eskom’s baseload generation capacity comprises several large coal-fired power stations situated in the northeast of the country and a single nuclear power sta- tion on the west coast. Diesel-fired gas turbines and pumped-storage schemes supply Eskom’s peaking capacity. A breakdown of its generation capacity is shown in table 8.3 and figure 8.2. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Table 8.2  South Africa’s Integrated Resource Plan, 2010–30 New build options Committed Non-IRP Coal (PF, FBC, Other imports, Import DoE renewables own build) Nuclear hydro Gas–CCGT Peak–OCGT  Wind CSP Solar PV Coal Other Peaker Wind  non-IRP Cogeneration Year MW MW MW MW MW MW MW MW MW MW MW MW MW MW 2010 0 0 0 0 0 0 0 0 380 260 0 0 0 0 2011 0 0 0 0 0 0 0 0 679 130 0 0 0 0 2012 0 0 0 0 0 0 0 300 303 0 0 400 100 0 2013 0 0 0 0 0 0 0 300 823 333 1,020 400 25 0 2014 500 0 0 0 0 400 0 300 722 999 0 0 100 0 2015 500 0 0 0 0 400 0 300 1,444 0 0 0 100 200 2016 0 0 0 0 0 400 100 300 722 0 0 0 0 200 2017 0 0 0 0 0 400 100 300 2,168 0 0 0 0 200 2018 0 0 0 0 0 400 100 300 723 0 0 0 0 200 2019 250 0 0 237 0 400 100 300 1,446 0 0 0 0 0 2020 250 0 0 237 0 400 100 300 723 0 0 0 0 0 2021 250 0 0 237 0 400 100 300 0 0 0 0 0 0 2022 250 0 1,143 0 805 400 100 300 0 0 0 0 0 0 2023 250 1,600 1,183 0 805 400 100 300 0 0 0 0 0 0 2024 250 1,600 283 0 0 800 100 300 0 0 0 0 0 0 2025 250 1,600 0 0 805 1,600 100 1,000 0 0 0 0 0 0 2026 1,000 1,600 0 0 0 400 0 500 0 0 0 0 0 0 2027 250 0 0 0 0 1,600 0 500 0 0 0 0 0 0 2028 1,000 1,600 0 474 690 0 0 500 0 0 0 0 0 0 2029 250 1,600 0 237 805 0 0 1,000 0 0 0 0 0 0 2030 1,000 0 0 948 0 0 0 1,000 0 0 0 0 0 0 Total 6,250 9,600 2,609 2,370 3,910 8,400 1,000 8,400 10,133 1,722 1,020 800 325 800 Source: DoE 2011. Note: CCGT = combined-cycle gas turbine; CSP = concentrated solar power; DoE = Department of Energy; FBC = fluidized bed combustor; IRP = Integrated Resource Plan; MW = megawatt; OCGT = open-cycle gas turbine; PF = pulverized coal-fired boiler; PV = photovoltaic. 165 166 Case Study 3: Investment in Power Generation in South Africa Table 8.3  Eskom’s Electricity Generation Capacity: South Africa, 2014 Technology and plant Location Capacity (MW) Coal Arnot Middelburg, Mpumalanga 2,232 Camden Ermelo, Mpumalanga 1,481 Duvha Witbank, Mpumalanga 3,450 Grootvlei Balfour, Mpumalanga 1,120 Hendrina Hendrina, Mpumalanga 1,798 Kendal Witbank, Mpumalanga 3,840 Komati Middelburg, Mpumalanga 904 Kriel Kriel, Mpumalanga 2,850 Lethabo Sasolburg, Free State 3,558 Majuba Volksrust, Mpumalanga 3,843 Matimba Ellisras, Limpopo 3,690 Matla Kriel, Mpumalanga 3,450 Tutuka Standerton, Mpumalanga 3,510 Nuclear Koeberg Melkbosstrand, Western Cape 1,860 Conventional hydro Gariep Norvalspont, Free State 360 Vanderkloof Petrusville, Northern Cape 240 Pumped storage Drakensberg Bergville, KwaZulu Natal 1,000 Palmiet Grabouw, Western Cape 400 Diesel-fired gas turbines Acacia Cape Town, Western Cape 171 Ankerlig Atlantis, Western Cape 1,327 Gourikwa Mossel Bay, Western Cape 740 Port Rex East London, Eastern Cape 171 Eskom total nominal capacity 41,995 Source: Eskom 2014. Capacity Additions Much of Eskom’s current generation capacity was built in the 1970s and 1980s in a massive investment program that ultimately resulted in overcapacity and the subsequent mothballing of three of its older power stations. After 2001, when a competitive market was being designed, the government prohibited Eskom from building any new capacity in the hope of attracting private investments in generation. However, the new power market was never implemented, and no ­ procurement or contracting mechanisms were put in place for IPPs. By 2004, the government was concerned that power reserve margins were diminishing, and the responsibility for investing in new capacity was again placed on Eskom. Eskom began by refurbishing the three mothballed power stations, followed by investing in new diesel-fired open-cycle gas turbines (OCGTs) and later new Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 167 Figure 8.2  Eskom’s Electricity Generation Mix: South Africa, 2014 percent Pumped Hydro, storage, 2 Wind, Nuclear, 3 0 Diesel, 5 5 Coal, 85 Source: Constructed from Eskom 2014. Figure 8.3  Eskom’s Installed Generation Capacity over Time: South Africa, 1990–2014 46 44 42 40 Gigawatts 38 36 34 32 30 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 19 19 19 19 19 19 19 19 19 19 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 Source: Eskom’s annual reports. coal-fired stations. However, despite these efforts, demand exceeded supply, and nationwide power cuts commenced in 2008 and are now a regular occurrence. Eskom’s installed generation capacity over time and recent additions are shown in figure 8.3 and table 8.4, respectively. Eskom is embarking on a capital expansion program that costs an estimated $35 billion and will include the addition of two 4,800 MW coal-powered plants Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 168 Case Study 3: Investment in Power Generation in South Africa Table 8.4  Eskom’s Recent Generation Capacity Additions: South Africa, 2006–13 megawatts Plant Technology 2006 2007 2008 2009 2010 2011 2012 2013 Camdena Coal 190 740 320 190 n.a. n.a. n.a. n.a. Grootvleia Coal n.a. n.a. 190 190 380 190 140 n.a. Komatia Coal n.a. n.a. n.a. 170 n.a. 125 300 200 Ankerlig OCGT n.a. 440 150 735 n.a. n.a. n.a. n.a. Gourikwa OCGT n.a. 145 300 300 n.a. n.a. n.a. n.a. Total 190 1,325 960 1,585 380 315 440 200 Source: Eskom’s annual reports. Note: OCGT = open-cycle gas turbine; n.a. = not applicable (no capacity additions). a. Returned to service. (Medupi and Kusile), a 1,332 MW pumped-storage scheme (Ingula), and two 100 MW renewable energy plants (Eskom 2014). However, at present these projects are late and over budget. Construction on the coal-powered plants started in 2007–08 and should have been completed by 2014. Instead, the first unit came online only in 2015, and the two power stations will be completed in 2021 at the earliest. Eskom Costs, Prices, and Funding Eskom’s prices are regulated by NERSA in multiyear price determinations (MYPDs) based on a rate-of-return methodology. Historically, the major cost driver for Eskom has been capital expenditures on new electricity generation capacity. Figure 8.4 demonstrates how prices escalated sharply in the 1970s and 1980s, when most of Eskom’s current electricity generation fleet was built, and Figure 8.4  Eskom’s Average Prices (Rc/kWh) and Annual Increases (%): South Africa, 1970–2014 70 60 50 Rc/kWh and % 40 30 20 10 0 70 72 74 76 78 80 82 84 86 88 90 92 94 96 98 00 02 04 06 08 10 12 14 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 20 20 20 20 20 20 20 20 Percent Nominal price Real price Source: Authors’ compilation, based on Eskom’s annual reports and consumer price indexes. Note: kWh = kilowatt-hour; Rc = rand cent. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 169 again in recent years as Eskom builds new power stations. Current average Eskom electricity prices are between U.S. cents (USc) 6/kilowatt-hour (kWh) and USc 7/kWh. The marginal cost of its new coal-powered stations will be much higher than this, likely close to USc 10/kWh. The budgets for Medupi, Kusile, and Ingula have more than doubled, and the interest accruing during construction is escalating amid ongoing construction delays. Eskom’s initial estimate for Medupi in October 2007, when construction began, was South African rand (R) 78.6 billion, including the interest expected during construction. By July, Eskom had revised its estimate to R105 billion, excluding interest during construction, which could amount to an additional R 35 billion. If flue gas desulphurization is added, the total cost could exceed R 150 billion. Until the first units from Medupi start supplying energy to the grid, reserve margins will remain tight. To provide regular electricity to its customers, Eskom must run its costly peaking plants at much greater load factors than budgeted. The total outlay for the OCGT stations for fiscal year (FY) 2013/14 was R 10.6 billion (2012/13: R 5.0 billion), significantly over the original budget (Eskom 2014). These breakdowns are shown in figure 8.5 and figure 8.6. Eskom’s coal costs have been rising. Historically these were low because most of Eskom’s coal was supplied by tied mines on long-term, cost-plus contracts. However, some of the original contracts have ended, or will do so soon, and Eskom is increasingly exposed to short-term contracts at higher prices. Average coal costs are currently approximately R 350/ton ($30/ton). Eskom’s performance has been deteriorating amid increased plant outages. The precipitous decline in average power station capacity factors in recent years Figure 8.5  Proportion of Eskom’s Electricity Generated by OCGTs: South Africa, FY2013/14 percent OCGT, 2 Non-OCGT, 98 Source: Constructed from Eskom 2014. Note: FY = fiscal year; OCGT = open-cycle gas turbine. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 170 Case Study 3: Investment in Power Generation in South Africa Figure 8.6  Proportion of Primary Energy Costs Attributed to OCGTs: South Africa, FY2013/14 percent OCGT, 20 Non-OCGT, 80 Source: Constructed from Eskom 2014. Note: FY = fiscal year; OCGT = open-cycle gas turbine. Figure 8.7  Average Availability of Generation Plants Run by Eskom: South Africa, 2000–15 100 95 90 85 Percent 80 75 70 65 60 00 01 02 03 04 06 08 09 10 11 12 13 14 15 05 07 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 Source: Eskom’s annual reports. Note: Unit capacity factor is defined as the amount of electricity generated by a power unit or power station throughout a specified time period, divided by the maximum amount of electricity that the plant could have generated during that period—that is, the installed capacity multiplied by the number of hours in that period, expressed as a percentage. is noticeable in figure 8.7. The years of insufficient spending on maintenance are now beginning to take their toll. For most of its history, Eskom has raised debt from private capital markets to fund its capital expenditure programs. It received government support for the first time in 2008 with a subordinated loan of R 10 billion, followed by R 30 billion in 2009 and R 20 billion in 2010. These loans were converted to Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 171 equity in 2015. Nevertheless, Eskom’s balance sheet does not look promising. Eskom applied for annual tariff increases of 16 percent, but NERSA’s MYPD3 awarded only 8 percent increases annually from 2013/14 to 2017/18. The regu- lator accepted additional costs through an adjustment to the regulatory clearing account that resulted in an additional 5 percent increase in 2014/15, but it declined an additional application from Eskom in May 2015 for a selective reopening of some cost items. The government promised an additional injection of R 23 billion in 2015, raised from asset sales, but Moody’s and Standard & Poor’s (S&P) downgraded Eskom’s credit rating to junk status. As part of the funding for Medupi, Eskom, with the support of the govern- ment, sought a $3.75 billion loan from the World Bank. This was the World Bank’s first financial support to South Africa since the end of apartheid. Part of the loan will also fund Eskom’s first wind farm, the 100 MW Sere Wind Farm, as well as a proposed 100 MW concentrated solar power (CSP) plant (World Bank 2012). The loan was approved in 2010. Eskom’s financial situation is deteriorating sharply. It is facing a liquidity squeeze as its costs rise and sales volume stagnates. And the cost and difficulty of raising sufficient debt financing is challenging. Other Electricity Generation Providers in South Africa Prior to 2011, South Africa had very limited success in procuring independent electricity generation. Several negotiations with international and local IPPs stalled, and Eskom’s procurement programs were abandoned or secured only marginal amounts of power. This included projects under the Short-Term Power Purchase Programme (STPPP), the Medium-Term Power Purchase Programme (MTPPP), the Wholesale Electricity Pricing System (WEPS), and municipal baseload contracts. These proportions are shown in table 8.5 and figure 8.8. Privatization South Africa’s first attempt to invite private participation in the electricity sector was the privatization of the Kelvin 600 MW coal-powered plant in 2001 by the City of Johannesburg. The U.S.-based AES acquired a 95 percent majority share Table 8.5  Eskom’s Energy Purchases from Other Generators: South Africa, FY2013/14 Source Energy (GWh) Cost (Rc/kWh) MTPPP 1,478 82 STPPP 931 88 WEPS 139 52 Municipal baseload 873 88 Source: Eskom 2014. Note: FY = fiscal year; GWh = gigawatt-hour; kWh = kilowatt-hour; MTPPP = Medium-Term Power Purchase Programme; Rc = rand cent; STPPP = Short-Term Power Purchase Programme; WEPS = Wholesale Electricity Pricing System. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 172 Case Study 3: Investment in Power Generation in South Africa Figure 8.8  Eskom’s Energy Purchases from Other Generators: South Africa, FY2013/14 percent Non-Eskom producers, 2 Eskom production, 98 Source: Eskom 2014. Note: FY = fiscal year. in the plant only to slip into financial difficulties following the collapse of Enron, forcing it to sell its share to Globeleq in 2002 (Business Report 2002). Globeleq retained majority ownership of Kelvin until 2006, when it was also forced to sell the plant, citing technical issues; it stated that the plant could not be brought back to its full capacity, making it financially unviable. Globeleq relinquished the asset to Nedbank and Investec, which had originally financed the deal (Benjamin 2006). In 2007, a consortium of investors concluded agreements to purchase a 95 percent stake in the plant from Nedbank and Investec. Included in the con- sortium was an infrastructure fund managed by Old Mutual, Macquarie, Kagiso Trust, J&J Infrastructure Holdings, and Aldwych Kelvin Operations (Proprietary) Ltd. (the wholly owned South African subsidiary of Aldwych International, Ltd., which currently has a management services agreement with Kelvin Power [Proprietary] Ltd.). The Kelvin power station has reportedly been operating at 25 percent of its capacity for several years, and is undergoing continuous refurbishment efforts to increase its capacity.2 Another privatization attempt was the partial privatization of the Kusile coal-powered plant, which is still under construction. In an effort to raise much- ­ needed capital, Eskom considered selling a 30–49 percent stake. However, no privatization deal was struck. Eskom’s former chief executive officer (CEO) Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 173 Brian Dames stated, “the return requirement by private investors was a lot higher than what Eskom is prepared to accept as a return” (Donnelly 2012). International Deals Eskom has been involved in negotiations with several international power ­ projects, but with little result. Two of the larger projects are the Mmamabula coal-powered plant (Botswana) and the Mphanda Nkuwa hydropower project (Mozambique) (Eskom 2009). Both depend on an Eskom PPA to secure their financial viability. The 1,200 MW Mmamabula Energy Project is an integrated coal mine and power plant project proposal from Botswana. Negotiations between Eskom and the project developer, CIC Energy Corporation, were for a 75 percent fixed off- take agreement (Eskom 2010). CIC offered power at rand cent (Rc) 72/kWh, indexed at below inflation. At the time, Eskom found it too expensive, but it is now below the cost of Medupi and Kusile, Eskom’s new mega power plants cur- rently being built. The 1,500 MW Mphanda Nkuwa hydropower project (downriver from the Cahora Bassa hydropower scheme on the Zambesi River) has also shown little progress. Negotiations have been under way since 2008, yet no PPAs have been signed. There have reportedly been some technical and political concerns regard- ing the agreements. Eskom wants to minimize financial risk and takes no respon- sibility for the transmission failures of the Mozambican grid. It demands that it purchase power at the border, not at the point of generation, and using rand- denominated PPAs. Other international projects in which Eskom has had limited active engage- ment include the Kudu gas field (Namibia), the Benga and Moatize coal-­ powered projects (Mozambique), and the Kariba North Bank hydropower extension (Zambia). Since the project’s inception around 2006, developers of the 800 MW Kudu gas field have tried on several occasions, with little success, to get Eskom to com- mit to a long-term off-take agreement. The Zambian private utility CEC Africa has now taken an equity stake in the project with an interest in concluding power purchases for the southern African region. Eskom originally declined an offer to purchase a stake in the 600 MW Moatize coal-powered project situated in Mozambique but then expressed ­ interest in entering into a PPA (Bloomberg Business Week 2006). The first phase (300 MW) of the project was approved in March 2014, with 250 MW to be supplied to the attached coal mine and the balance sold to Mozambique’s grid. However, there is no indication that Eskom is still involved in the project. One international project that is starting to show progress is the Inga hydro- power scheme in the Democratic Republic of Congo. The project has the poten- tial to supply up to 44 GW of electricity to the continent when it is complete, but it has been in the pipeline for more than 40 years. The next stage, Inga 3, will supply 4,800 MW. The Grand Inga Treaty between the Democratic Republic of Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 174 Case Study 3: Investment in Power Generation in South Africa Congo and South Africa was signed in October 2013 and ratified by the cabinet in August 2014, but the treaty has been submitted to parliament. Under the agreement, Eskom is contractually committed to purchase 2,500 MW from Inga 3, provide 15 percent of the equity to build the plant, and build the transmission network to the border of the Democratic Republic of Congo. ­ Furthermore, Eskom will buy at least 33 percent of all future capacity additions of the Inga project. The Aggreko 110 MW natural gas plant based on the border of South Africa and Mozambique is one small example of a successful international negotiation, albeit a temporary one. Commissioned in 2012, the plant is the world’s first international, interim IPP. It will be replaced by a longer-term, 120 MW plant being constructed by Gigawatt Global. Sasol and EDM have also developed the 170 MW Centrale Termica Ressano Garcia in the same area. The plant has been in operation since March 2015, and it sells its output to EDM, which then sells part of it to various regional off-takers. EDM/Sasol are also developing the 400 MW Temane project, which could sell the majority of its output to Eskom. Non-Eskom Thermal Power in South Africa Three procurement programs that were initiated by Eskom between 2007 and 2009 had industry players optimistic that the generation market was slowly open- ing up. However, by 2009, despite considerable market interest, the Eskom-led programs had all been scrapped. During the same period, the DoE commenced procurement for an IPP to produce peaking power. There have been considerable delays, but the contract has been awarded and construction is under way. Cogeneration and Short- and Medium-Term Contracts Initiated by Eskom, the Pilot National Cogeneration Programme (PNCP), the MTPPP, and the Multisite Baseload Independent Power Project Programme (MBLIPP) all showed promise, but then they were all ultimately scrapped with little or no capacity procured. Initiated in 2007, the PNCP sought to procure 900 MW of cogeneration capacity. Following the publication of a request for proposals (RfP), 125 bids were received that totaled 4,900 MW of potential capacity. Bids that met the mini- mum requirements were evaluated against a ceiling price. The price was equal to Eskom’s avoided cost of generation (adjusted for the time and location of the plant). The maximum length of the PPA on offer was 15 years (Eskom 2007). There had been considerable private sector interest in the program, yet devel- opers were also critical. Many found that the PPA was too burdensome and placed undue risk on the generator. By its nature, cogeneration technology relies on fuel from an unpredictable industrial process, and without a fuel pass-through mechanism, bidders are exposed to fuel-supply risk (DoE 2009). Furthermore bidders struggled to beat the unrealistically low ceiling price set by Eskom (Viljoen 2008). Ultimately, no PPAs were signed, and the program was deemed a failure. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 175 The MTPPP was initiated in 2008 in response to developers that wished to participate in the PNCP but did not qualify. The program was aimed at project sponsors with the ability to supply electricity to the grid by 2012. An RfP was published in March 2008. Projects under the program were required to be between 5 MW and 1,000 MW and could involve any technology that included new build, incremental capacity additions, or the refurbishment of existing plants. The total capacity allowed under the program was 3,000 MW, and successful bids would be awarded a PPA with a maximum length of 10 years, ending in December 2018 (Viljoen 2008). An improvement to the PNCP was the price band outlined in the RfP, shown in table 8.6. This allowed bidders to gauge their chance of being awarded a PPA (de Beer and Magubane 2009). Bids received that were below the ceiling price would automatically be awarded a PPA on a first-received, first-accepted basis. Bids that fell between the ceiling price and the maximum price would be evaluated against other bids (Eskom 2008). Still, bidders again criticized the PPA on offer. Many argued that the prices did not reflect the costs to be expected near the end of the PPA term. Additionally, the short length of the PPA placed serious constraints on projects’ ability to raise and pay back debt (de Beer and Magubane 2009). Decisions about preferred bidders were delayed for several years. In February 2011, Eskom announced the procurement of six projects totaling 373 MW under the program, a far cry from the 3,000 MW target. The exact makeup of the 373 MW of capacity has not been made public, but PPAs were signed with Sasol, IPSA, Tangent Mining, and SAPPI (Engineering News 2011). The PPA signed with Sasol was for 200 MW of OCGT capacity at its Secunda synthetic fuel plant. The project was an expansion of its current gas-fired plant, and it began operation in July 2010 after 21 months of construction (Engineering News 2010). The PPAs signed under the MTPPP lapsed in early 2014, but have subse- quently been renewed. For FY2013/14, Eskom purchased 1,478 gigawatt-hours (GWh) from IPPs under the MTPPP at an average cost of Rc 82/kWh (Eskom 2014). Initiated in April 2008, the MBLIPP aimed to secure up to 4,500 MW of capac- ity from plants with a maximum size of 200 MW. IPPs were expected to come online between 2012 and 2017 and have a PPA length of up to 40 years (de Bruyn 2009). Following a request for qualification, 23 local and international bidders Table 8.6  Medium-Term Power Purchase Programme Prices: South Africa, 2009–18 Rc/kilowatt-hour (2008) Price parameter 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Ceiling price 65 65 65 65 65 60 50 40 35 35 Maximum price 105 105 105 105 105 85 75 60 40 35 Source: Eskom 2014. Note: Rc = rand cent. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 176 Case Study 3: Investment in Power Generation in South Africa were identified, the majority of which were coal-powered plants (Kohler 2009). However, without explanation, the program was suspended along with the other two (PNCP and MTPPP) in 2009. The Peaker Project, Department of Energy The Peaker Project involved an international competitive bid (ICB) under the auspices of the DoE. The project followed a 2004 cabinet decision that 2,000 MW of peaking capacity was to be procured, half by the then–Department of Minerals and Energy and half by Eskom (Pickering 2011). Two out of the five prequalified developers submitted bids for the DoE’s Peaker Project in April 2007, and the contract was awarded to an AES-led consortium. The DoE had expressly excluded the project from the require- ments of the Electricity Regulations on New Generation Capacity. The proj- ect would not need to be subject to a value-for-money assessment; nor was a feasibility assessment required to ascertain whether Eskom or the private sector should build the plant (Donnelly 2011). However, negotiations between the DoE and AES broke down in 2008, with neither party claiming fault (Pickering 2011). The DoE pursued the project despite criticisms that it was unnecessary because, in the meantime, Eskom’s Ankerlig and Gourikwa OCGT plants had been expanded to provide more than 2,000 MW of ­peaking capacity. Almost a decade after the 2004 cabinet decision, a deal was eventually signed in June 2013. The DoE entered into 15-year PPAs with a consortium led by GDF Suez to deliver electricity from two plants: one in the Eastern Cape (Dedisa) and one in KwaZulu Natal (Avon), of 335 MW and 670 MW, respectively. The combined investment value of the project is a780 million (Engineering News 2013b). (GDF Suez had been the only other party, besides AES, to bid on the project back in 2007.) The commercial operation date (COD) is expected to fall in FY2015/16. Renewable Energy Independent Power Project Procurement Programme In 2009, the government began exploring FiTs for renewable energy, but these were later rejected in favor of competitive tenders. The initial announcement of the program was through a ministerial determination in August 2011 calling for the procurement of 3,625 MW of renewable energy capacity. Another min- isterial determination in 2012 added an additional 3,200 MW of capacity to be allocated between 2017 and 2020. On August 3, 2011, an RfP was issued, and the next month a compulsory bidder’s conference was held to address questions about bid requirements, ­ documentation, PPAs, and so on. Approximately 300 organizations attended this ­ conference. The REIPPPP envisioned the procurement of 3,625 MW of power throughout the course of a maximum of five tender rounds. Another 100 MW was reserved for small projects (below 5 MW) that were to be procured in a separate IPP program focused on small projects. Caps were set on the total capac- ity to be procured for individual technologies. The largest allocations were for Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 177 wind and PV, with smaller amounts for CSP, biomass, biogas, landfill gas, and hydropower. The rationale for these caps was to limit the supply to be bid out and therefore increase the level of competition among the different technologies and potential bidders. The tenders for different technologies were held simultaneously. Interested parties could bid for more than one project and more than one technology. Projects needed to be larger than 1 MW, and an upper limit was set on bids for different technologies—for example, 75 MW for a PV project, 100 MW for a CSP project, and 140 MW for a wind project. Caps were also set on the price for each technology. Bids were due within three months of the release of the RfP, and the financial close was to take place within six months after announcing the preferred bidders. The bid evaluation involved a two-step process. In the first, bidders needed to satisfy certain minimum threshold requirements in six areas: environment, land, commercial and legal, economic development, financial, and technical. For example, wind developers were required to provide 12 months of wind data for the designated site and an independently verified generation forecast. Project developers were responsible for identifying appropriate sites and for paying for measurement and early development costs at their own risk. The economic development requirements in particular were complex, incor- porating 17 sets of minimum thresholds and targets (table 8.7). For wind proj- ects, for example, at least 12 percent of the company shares had to be held by black South Africans and another 3 percent by local communities. At least 1 percent of project revenues had to go to socioeconomic contributions. The minimum threshold for local content was set at 25 percent, with an encouraged target of 45 percent. Bidders that satisfied the threshold requirements then proceeded to the sec- ond step of evaluation, in which bid prices counted toward 70 percent, and the remaining 30 percent weighting was given to composite scores on job creation, local content, preferential procurement, enterprise development, and socioeco- nomic development. Bidders were asked to provide two prices—one fully indexed for inflation and the other partially indexed—and the bidder was allowed to determine the proportion that would be indexed. The RfP included a standard PPA, an implementation agreement (IA), and direct agreements (DAs). The PPA was to be signed by the IPP and Eskom, the off-taker. The PPAs specified that transactions should be denominated in South African rand and that contracts would have 20-year tenures from the COD. The IAs were to be signed by the IPPs and the DoE, and effectively provided a sover- eign guarantee of payment to the IPPs by being required to make good on these payments in the event of an Eskom default. The IA also placed obligations on the IPP to deliver economic development targets. The DAs provided step-in rights for lenders in the event of default. The PPA, IA, and DA were nonnegotiable con- tracts that were developed after an extensive review of global best practices and consultations with numerous actors in the public and private sectors. Despite some bidder reservations regarding the lack of flexibility to negotiate the terms of Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 178 Case Study 3: Investment in Power Generation in South Africa Table 8.7  Economic Development Thresholds and Targets for Wind Projects in South Africa’s REIPPPP percent Factor and criteria Threshold Target Employees South Africa–based employees who are citizens 50 80 South Africa–based employees who are black citizens 30 50 Skilled employees who are black citizens 18 30 South Africa–based employees who are citizens from local communities 12 20 Local content Value of local content spending 25 45 Ownership Shareholding by black people in the project company 12 30 Shareholding by black people in the contractor responsible for construction 8 20 Shareholding by black people in the operations contractor 8 20 Shareholding by local communities in the project company 3 5 Management control Black top management n.a. 40 Preferential procurement Broad-based black economic empowerment procurement spending n.a. 60 Procurement from small enterprises n.a. 10 Procurement from women-owned vendors n.a. 5 Enterprise development Enterprise development contributions n.a. 0.6 Adjusted enterprise development contributions n.a. 0.6 Socioeconomic development Socioeconomic development contributions 1.0 1.5 Adjusted socioeconomic development contributions 1.0 1.5 Sources: Department of Energy, REIPPPP bid documents, and press releases (http://www.ipp-renewables.co.za). Note: REIPPPP = Renewable Energy Independent Power Project Procurement Programme; n.a. = not applicable (no threshold set). the various agreements, the overall thoroughness and quality of the standard documents seemed to satisfy most of the bidders participating in the three rounds. Bidders had to submit bank letters indicating that financing had been secured—this was highly unusual and basically a way to outsource due diligence to the banks. Effectively, this meant that lenders took on a higher share of the project development risk, and this arrangement dealt with the biggest problem with auctions: the low-balling that results in deals not closing. The developers were expected to identify the sites and pay for early devel- opment costs at their own risk. A registration fee of R 15,000 ($1,875) was due at the outset of the program. Bid bonds or guarantees had to be posted that were equal to R 100,000 ($12,500) per megawatt of the nameplate capacity of the proposed facilities, and the amount was doubled when the ­ Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 179 preferred bidder status was announced.3 The guarantees were to be released when the projects came online or if the bidder was unsuccessful after the RfP evaluation stage. In August 2011, an initial RfP was issued. By November 2011, 53 bids for 2,128 MW of generating capacity were received. Ultimately, 28 preferred bidders were selected, offering 1,416 MW, for a total investment of nearly $6 billion. Successful bidders realized that not enough projects were ready to meet the bid qualification criteria and that all qualifying bids were thus likely to be awarded contracts. Bid prices in the first round were thus close to the price caps set in the tender documents. Major contractual agreements were signed on November 5, 2012, and most projects reached full financial close shortly thereafter. Construction on all of these projects has commenced, and the first project came online in November 2013. A second round of bidding was announced in November 2011. The total amount of power to be acquired was reduced, and other changes were made to tighten the procurement process and increase competition. Seventy-nine bids for 3,233 MW were received in March 2012, and 19 bids were ulti- mately selected. Prices were more competitive, and bidders also offered bet- ter local content terms. PPA, IAs, and DAs were signed for all 19 projects in May 2013. A third round of bidding commenced in May 2013, and again the total capac- ity offered was restricted. In August 2013, 93 bids were received that totaled 6,023 MW. Seventeen preferred bidders were notified in October 2013, totaling 1,456 MW. Prices fell further in round 3. Local content again increased, and although some projects were delayed because of uncertainties around Eskom transmission connections, all reached financial close. In December 2014, an additional 200 MW of CSP projects were awarded. A fourth round of bidding commenced in August 2014, and preferred bidders were to be announced in November 2014. An award was eventually announced in April 2015 for 13 projects that totaled 1,121 MW. Prices were so low that an additional allocation was made in June 2015 for an additional 13 projects that totalled 1,084 MW. To date, 92 projects have been awarded to the private sector, and the first projects are already online. Private sector investments totaling more than $19 billion have been committed, and these projects total 6,327 MW of renew- able power. Prices dropped during the four bidding phases, with average PV tariffs decreasing by 71 percent and wind dropping by 48 percent in nominal terms. Most impressively, these achievements occurred during a four-year period, from 2011 to 2015 (figure 8.9). Grid-connected renewable energy prices are now among the cheapest in the world, with average solar PV prices in round 4 at USc 6.4/kWh and the cheapest wind bid at USc 4.7/kWh. Finally, there have been notable improvements in economic development commitments that have primarily benefitted rural communities. Real returns to equity in round 1 were close to the 17 percent (in local cur- rency) that was envisaged when determining the original FiTs. Equity returns Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 180 Case Study 3: Investment in Power Generation in South Africa Figure 8.9  Average Nominal Bid Prices in South Africa’s REIPPPP 300 250 200 Rc/kilowatt-hour 150 100 50 0 Round 1 Round 2 Round 3 Round 4 Solar PV Onshore wind Source: Department of Energy REIPPPP office. Note: PV = photovoltaic; Rc = rand cent; REIPPPP = Renewable Energy Independent Power Project Procurement Programme. dipped slightly in round 2 for wind and probably more substantially for PV. Dollar returns in the range of 12–13 percent were reported. Returns fell further in round 3, especially for some of the corporate-funded projects (table 8.8). Increased competition was no doubt the main driver for the price fall after the first round, but there were other factors as well. International prices for renew- able energy equipment have declined during the past few years because of a glut in manufacturing capacity as well as ongoing innovations and economies of scale. The REIPPPP was well positioned to capitalize on these global factors. Transaction costs were also lower in subsequent rounds because many of the project sponsors and lenders became familiar with the REIPPPP tender specifications and requirements. Figure 8.10 indicates the performance of the wind and solar PV plants that have been connected to the grid. Fifty-six of the 64 projects in rounds 1–3 have been project financed. One project in round 1 (Touwsrivier Solar Energy Facility) issued a corporate bond valued at R 1 billion, and a small hydropower project (Stortemelk) was initially corporate financed, but it is now being refinanced through debt. Six projects out of 17 in round 3 were corporate financed, all by the Italian utility Enel (which had been unsuccessful in previous rounds). Reports indicate that returns on equity for the corporate-funded projects in round 3 were low. This trend toward corporate financing in the REIPPPP may or may not continue, but it is likely that more international utilities will be interested in entering South Africa’s renewable energy market, especially European utilities that are strug- gling to grow shares in their home markets. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 181 Table 8.8  Results of REIPPPP Rounds 1–3: South Africa, 2011–14 Bidding round Wind PV CSP Hydro Biomass Biogas Landfill Total Round 1 Capacity offered (MW) 1,850 1,450 200 75 12.5 12.5 25 3,625 Capacity awarded (MW) 648.5 626.8 150 0 0 0 0 1,425.3 Projects awarded 8 18 2 0 0 0 0 28 Average tariff (Rc/kWh) 114 276 269 n.a. n.a. n.a. n.a. n.a. Average tariff (USc/kWh) R 8/$ 14.3 34.5 33.6 n.a. n.a. n.a. n.a. n.a. Total investment (R, millions) 13,312 23,115 11,365 0 0 0 0 47,792 Total investment (US$, millions) 1,664 2,889 1,421 0 0 0 0 5,974 R 8/$ Round 2 Capacity offered (MW) 650 450 50 75 12.5 12.5 25 1,275 Capacity awarded (MW) 558.9 417.12 50 14.4 0 0 0 1,040.42 Projects awarded 7 9 1 2 0 0 0 19 Average tariff (Rc/kWh) 90 165 251 103 n.a. n.a. n.a. n.a. Average tariff (USc/kWh) R 7.94/$ 11.3 20.8 31.6 13 n.a. n.a. n.a. n.a. Total investment (R, millions) 10,897 12,048 4,483 631 0 0 0 28,059 Total investment (US$, millions) 1,372 1,517 565 79 0 0 0 3,533 R 7.94/$ Round 3 Capacity offered (MW) 654 401 200 121 60 12 25 1,473 Capacity awarded (MW) 787 435 200 0 16.5 0 18 1,456.5 Projects awarded 7 6 2 0 1 0 1 17 Average tariff (Rc/kWh) 74 99 164 n.a. 140 n.a. 94 n.a. Average tariff (USc/kWh) R 9.86/$ 7.5 10 16.6 n.a. 14.2 n.a. 9.5 n.a. Total investment (R, millions) 16,969 8,145 17,949 0 1,061 0 288 44,412 Total investment (US$, millions) 1,721 826 1,820 0 108 0 29 4,504 R 9.86/$ Totals Capacity awarded (MW) 1,984 1,484 400 14 16 0 18 3,915 Projects awarded 32 23 5 2 1 0 1 64 Total investment (R, millions) 40,590 42,130 33,797 631 1,061 0 288 118,497 Total investment (US$, millions) 4,683 5,085 3,806 79 108 0 29 13,790 Source: Eberhard, Kolker, and Leigland 2014. Note: CSP = concentrated solar power; kWh = kilowatt-hour; MW = megawatt; PV = photovoltaic; REIPPPP = Renewable Energy Independent Power Project Procurement Programme; R = rand; Rc = rand cent; USc = U.S. cent; n.a. = not applicable. On average, across the three rounds, approximately two-thirds of funding was in the form of debt, with the highest proportion in round 2 and the lowest in round 3. A further quarter was funded from pure equity and shareholder loans, with the remaining coming from corporate finance. The majority, 64 percent, of debt funding was from commercial banks (R 57 billion), with the balance from development finance institutions (DFIs) (R 27.8 billion) and pension and insur- ance funds (R 4.7 billion). Eighty-six percent of the debt was raised from within South Africa (figure 8.11).4 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 182 Case Study 3: Investment in Power Generation in South Africa Figure 8.10  Capacity Factors for Wind and Solar PV: South Africa, 2014 50 40 30 Percent 20 10 0 May June July Aug. Sept. Oct. Solar PV Wind Source: Eskom System Operator. Note: PV = photovoltaic. Figure 8.11  Share of Debt Financing in REIPPPP, Rounds 1–3: South Africa, 2011–14 percent International, 14 DFIs, Commercial 31 lenders, 64 Life funds, South African, 5 86 Source: Authors’ calculations based on Department of Energy IPP Office data. Note: DFI = development finance institution; REIPPPP = Renewable Energy Independent Power Project Procurement Programme. South Africa’s five large commercial banks—Standard, Nedbank, Absa, Rand Merchant Bank (RMB), and Investec—have dominated REIPPPP lending. Their relative share of commercial and overall debt financing is shown in figures 8.12 and 8.13. Nedbank has been involved in the most projects (23), followed by Standard (17), Absa (14), RMB/First Rand (11), and Investec (4). These banks have all played lead debt-arranging roles, although not for all deals, and they have participated in a number of projects as cosenior lenders or as providers of subor- dinated ­mezzanine debt. Debt tenors are approximately 15 to17 years (from COD), and spreads on the Johannesburg Interbank Agreed Rate (JIBAR) are between 310 and 400 points (risk premium: 250; liquidity: 120; and statuary costs: 30 points). Nedbank and Absa were involved in the majority of projects in round 3. Some project sponsors have complained that there has not been enough Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 183 Figure 8.12  Share of Initial Debt Providers in REIPPPP, Rounds 1–3: South Africa, 2011–14 20 15 Rand, billions 10 5 0 sa SA ec st k B C F l C rd ua an RM EK Re ID IF Ab st DB da ut db ve an M Ne In St d Ol Round 1 Round 2 Round 3 Source: Authors’ calculations from the time of financial close, based on Department of Energy IPP Office data. Some debt has been subsequently syndicated to other banks or funds. Note: The “rest” category includes OPIC, AfDB, Liberty Group, ACWA, EIB, Sanlam, FMO, Proparco, and Sumitomo. Absa = South African commercial bank; AfDB = African Development Bank; DBSA = Development Bank of Southern Africa; EIB = European Investment Bank; EKF = Eksport Kredit Fonden (Danish export credit agency); FMO = Netherlands Development Finance Company; IDC = Industrial Development Corporation; IFC = International Finance Corporation; OPIC = Overseas Private Investment Corporation; REIPPPP = Renewable Energy Independent Power Project Procurement Programme; RMB = Rand Merchant Bank. Figure 8.13  Major Debt Providers in REIPPPP, Rounds 1–3, by Number of Projects per Lender: South Africa, 2011–14 25 20 No. of projects per lender 15 10 5 0 p am SA sa rd ec k C C B l F ua ou an EK RM ID IF Ab da st DB nl ut db Gr ve an Sa M Ne In ty St d er Ol Lib Source: Authors’ calculations based on Department of Energy IPP Office data. Note: Absa = South African commercial bank; DBSA = Development Bank of Southern Africa; EKF = Eksport Kredit Fonden (Danish export credit agency); IDC = Industrial Development Corporation; IFC = International Finance Corporation; REIPPPP = Renewable Energy Independent Power Project Procurement Programme; RMB = Rand Merchant Bank. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 184 Case Study 3: Investment in Power Generation in South Africa competition among the banks, and premiums have not fallen as much as expected as banks became more familiar and comfortable with the REIPPPP process. Remaining local debt funding came from the Industrial Development Corporation (IDC) and the Development Bank of Southern Africa (DBSA). The IDC participated in 20 deals, and the DBSA participated in 16 deals, mostly in arranging vendor financing for black economic empowerment and community participation. Another feature of local financing has been the involvement of insurance and pension funds, such as Old Mutual, Sanlam, and Liberty. Old Mutual also partici- pated through its Ideas Fund as well as its majority-owned specialist investment fund, Future Growth, and indirectly through African Clean Energy Developments, which is a joint venture between African Infrastructure Investment Managers (in turn a joint venture between Macquarie African and Old Mutual) and AFPOC (a Mauritian-registered company). It is expected that commercial banks will sell down more of their debt to these secondary capital markets and position them- selves for ongoing debt exposure in future REIPPPP rounds. International DFIs include the International Finance Corporation (IFC) and EKF (Eksport Kredit Fonden—the Danish export credit agency), with three projects each; and the Netherlands Development Finance Company (FMO), African Development Bank (AfDB), European Investment Bank (EIB), and Overseas Private Investment Corporation (OPIC), with one project each. Public versus IPP Investment, Direct Negotiations versus Competitive Bids, and Thermal versus Renewables Most of Eskom’s power stations are coal fired, and there are not yet any coal IPPs. However, as mentioned earlier, two diesel-fired OCGT peaking plants are being built by an IPP and may be compared to Eskom’s own direct procurement of a similar plant. In addition, the REIPPPP resulted in a number of wind farms, and Eskom is about to build its first. Diesel-Fired Open-Cycle Gas Turbines The Eskom-owned Ankerlig and Gourikwa diesel-fired OCGT plants were pro- cured by the utility in two phases between 2007 and 2009. Siemens was identi- fied as the main contractor to install 14 gas turbines (Ankerlig: 9 × 150 MW; Gourikwa: 5 × 150 MW) at the two sites. The contract awarded by Eskom was for only the engineering, procurement, and construction (EPC) of the plant at a total cost of R 7.7 billion for 2,072 MW of capacity—that is, a specific invest- ment cost of R 3,716/kW (approximately $465/kW). This does not include the owner’s costs, which could add an additional 30 percent—that is, approximately R 4,830/kW ($600/kW at the exchange rate of the time); see table 8.9. The two OCGT plants (Avon and Dedisa) under the DoE’s Peaker Project were initially procured through an ICB and then through direct negotiations for a turnkey solution that included the project management and operation s ­ervices throughout the lifetime of the project. The successful bidder entered into an IA Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 185 Table 8.9  Procurement of OCGTs: A Comparison of Eskom’s Plants and IPPs, South Africa Project information Ankerlig and Gourikwa DoE Peaker Project Sponsor Eskom GDF-Suez Consortium Capacity Ankerlig: 1,332 MW Avon: 670 MW Gourikwa: 740 MW Dedisa: 335 MW Total: 2,072 MW Total: 1,005 MW Cost Phase 1: R 3.5 billion Total: R 9.7 billion (2013) Phase 2: R 4.2 billion Total: R 7.7 billion (2009) Specific investment cost R 3,716/kW R 9,652/kW Time to COD 18 months Dedisa: 24 months; Avon: 30 months Commissioned Phase 1: June 2007 Avon: 2016 (expected) Phase 2: May 2009 Dedisa: 2016 (expected) Procurement Tender for EPC only International competitive bid and then direct negotiation Source: Compiled by the authors, based on various primary and secondary source data. Note: COD = commercial operation date; DoE = Department of Energy; EPC = engineering, procurement, and construction; IPP = independent power project; kW = kilowatt; MW = megawatt; OCGT = open-cycle gas turbine; R = rand. with the DoE and a 15-year PPA with Eskom. The project-financed deal took seven years to conclude, and it was the first thermal IPP project in South Africa (Absa 2013). Specific investment costs amounted to R 9,652/kW ($965/kW at the ruling exchange rate)—50 percent more than the cost of Eskom’s OCGTs. The PPAs of these diesel-fired OCGTs have not been made public. Although, technically, the Peaker Project was a competitive bid program, competition in the market was limited. Only two prequalified developers sub- mitted bids, but one was disqualified, leaving AES to win the bid by default. When negotiations with AES broke down, the deal was awarded to the only other (disqualified) bidder, raising doubt about the competitiveness of the deal. This was South Africa’s first IPP, and the DoE had much to learn about running an effective procurement program. Although all the data are not available, it can be safely concluded that Eskom’s procurement of the OCGTs was both more cost-effective and quicker than the DOE’s procurement of a similar plant. Renewable Energy: Wind Part of the World Bank loan made to Eskom in 2010 included funding for the 100 MW Sere Wind Farm, which thus had to be in line with the World Bank’s procurement guidelines. An ICB was held for the EPC contract, which was awarded to Siemens, with a total value of R 1.8 billion (World Bank 2013). This included a five-year operations-and-maintenance agreement. Projects under the REIPPPP are procured through a competitive bid for a 20-year PPA with Eskom as the off-taker. Competition has been fierce, with prices falling rapidly during the first four rounds. According to Eskom, the Sere Wind Farm is expected to produce electricity at a cost of Rc 77/kWh (Blaine 2014). It is not clear whether this figure includes development and owner costs. This tariff is favorable to the REIPPPP rounds 1 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 186 Case Study 3: Investment in Power Generation in South Africa Table 8.10  Wind Farm Procurement, South Africa Project information Sere Wind Farm Dorper Wind Farm Red Cap-Gibson Bay Sponsor Eskom Sumitomo (majority shareholder) Enel (majority shareholder) Rainmaker (developer) Red Cap (developer) Capacity 100 MW 100 MW 110 MW Cost Project value: R 2.4 billion Project value: R 2.2 billion Project value: R 2.25 billion Overnight cost: $2,516/kW Overnight cost: $2,182/kW Tariff: Rc 77/kWh Round 1 average: Rc 114/kWh Tariff: Rc 66/kWh Commissioned Late 2014 July 2014 Early 2017 (expected) Procurement International competitive bid for EPC Round 1 REIPPPP preferred Round 3 REIPPPP preferred bidder bidder Financing World Bank loan 32.4% 70% debt financed Corporate finance AFD 36.7% Nedbank, Absa, Sumitomo AfDB 26.8% Mitsui Banking Corp Operation Five-year operations-and-maintenance 20-year PPA 20-year PPA contract with Siemens Source: Compiled by the authors, based on various primary and secondary source data. Note: Absa = South African commercial bank; AFD = Agence Française de Développement; AfDB = African Development Bank; EPC = engineering, procurement, and construction; kW = kilowatt; kWh = kilowatt-hour; MW = megawatt; PPA = power purchase agreement; R = rand; Rc = rand cent; REIPPPP = Renewable Energy Independent Power Project Procurement Programme. and 2, in which wind farm prices averaged Rc 114/kWh and Rc 90/kWh, ­ respectively. However, round 3 delivered prices as low as Rc 66/kWh, and the cheapest wind project in round 4 was Rc 56/kWh (or USc 4.7/kWh). This is an interesting outcome, because the World Bank loan to Eskom has an interest rate that is cheaper than the debt raised by the IPPs. Table 8.10 indicates that Eskom’s specific investment costs are higher than the REIPPPP’s, and that the utility has not been able to realize the competitive gains made by the IPPs. Eskom has also been slow in getting its wind project off the ground and reach- ing a COD; REIPPPP projects with exactly the same EPC contractors were built in much smaller time frames. It is also interesting to note the differences in the socioeconomic benefits of the Eskom project compared with the privately funded projects. Projects under the REIPPPP are required to have socioeconomic development interventions equal to between 1.0 percent and 1.5 percent of total project revenue and entrust between 2.5 percent and 5.0 percent of the total shareholding of a proj- ect to local communities. In addition, points are awarded for skill development, enterprise development, and local content. By contrast, Eskom’s wind farm appears to have no further socioeconomic benefits beyond job creation and local content. Conclusions South Africa has been a latecomer to IPP procurements in Africa, but in the past 4 years the country has added more projects and investments than did all the other countries of Sub-Saharan Africa in the previous 20 years. Initially, the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 187 national utility, Eskom, was charged with the responsibility to procure IPPs, but, facing an obvious conflict of interest with its own generation ambitions, it failed to contract adequate amounts of privately produced power. Even the FiT regime failed to deliver any projects, with Eskom continually raising issues around draft PPAs, associated contracts, and regulatory agreements. The DoE started assuming responsibility for IPPs, but it realized early on that it did not have the capacity to run large, sophisticated power procurement pro- grams. Its first procurement effort—the OCGT peaking plants—was a stop-start affair, with complicated negotiations, little competition, lengthy delays, and, in the end, expensive power. Fortuitously, the DoE welcomed the assistance of experienced PPP advisers in the National Treasury and, along with an army of local and international transac- tion advisers, designed and ran what is now widely recognized and applauded as a world-class procurement of grid-connected renewable energy IPPs. The REIPPPP’s success was facilitated by the largely ad hoc institutional status of the DoE’s IPP unit, which allowed an approach that emphasized problem solving, rather than an enforcement of administrative arrangements, and did not undermine quality or transparency. The DoE’s IPP management team and the team leader had extensive experience, expertise, and credibility with both public and private sector stakeholders. This team was also able to overcome some of the mistrust regarding private business that sometimes restricts the public-private dialogue in South Africa and to secure resources to implement a quality program. These resources were used to appoint experienced advisers who were able to transfer international best practices to the South African context. Despite these successes, the ad hoc status of the DoE’s IPP unit poses some risks. For this pro- curement process to be sustainable, these capabilities will need to be imple- mented in a formal institution, preferably an independent one. The REIPPPP offered a quick way to roll out new generating capacity, and the size and structure of the bidding process meant that there would be multiple bid winners, an important incentive for the private sector to participate. The REIPPPP also represented opportunities for developers to make reasonable prof- its because the tariff caps in round 1 were close to the previously published FiTs. As competition increased in subsequent bid rounds, tariffs dropped sharply. The rolling series of bidding with substantial capacity allocations also helped build confidence in the program. Furthermore, the requirement that bids be fully underwritten with debt, as well as equity, effectively eliminated the tendency of competitive tenders to incentivize underbidding to win contracts.5 Although some of the program’s economic development requirements have been contro- versial, they did generate critical political support for the REIPPPP. There were also some design shortcomings, and the size and readiness of the local renewable energy market were initially overestimated. This resulted in lim- ited competition in round 1, with bids close to the price caps that were specified in the tender. Some REIPPPP critics also argued that the program’s significant up-front administrative requirements and high bid costs have contributed to higher prices than in other countries, such as Brazil, and serve as a bias against Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 188 Case Study 3: Investment in Power Generation in South Africa small- and medium-scale entrepreneurs. Although the latter critique may have some merit, it should be noted that bid costs were nevertheless tiny compared to overall project values. In terms of important market factors impacting the program, the global slow- down in renewable energy markets in the Organisation for Economic Co-operation and Development (OECD) meant that the REIPPPP was able to attract consid- erable attention from the international private sector. The REIPPPP also bene- fited South Africa’s sophisticated capital market, which offered long-term project finance. The array of sophisticated advisory services was also critical to the design and management of the REIPPPP. South Africa’s experience suggests several key lessons for successful renewable energy programs in other emerging markets. For example, it is evident that pri- vate sponsors and financiers are more than willing to invest in renewable energy if the procurement process is well designed and transparent, transactions have reasonable levels of profitability, and key risks are mitigated by the government. Renewable energy costs are falling, and technologies such as wind turbine elec- tric generation are becoming competitive with fossil-fuel generation. Furthermore, renewable energy procurement programs have the potential to leverage local social and economic development. The REIPPPP also highlights the need for effective program champions with the credibility to convincingly interact with senior government officials, effectively explain the program to stakeholders, and communicate and negotiate with the private sector. Finally, whether a FiT or competitive tender is chosen, private sector project developers need a clear pro- curement framework within which to invest. Other interesting lessons from South Africa relate to public versus private procurement. In the case of renewable energy, competitive tenders and private sector developers produced better price outcomes (from round 3) and shorter construction times than the national utility, which had had no prior experience with renewable energy. However, the opposite outcome was achieved with ther- mal OCGTs: Eskom and its EPC contractors constructed a plant in a shorter period of time and at lower investment costs than the DoE-procured IPP. The latter was DoE’s first procurement and was far from ideal, with limited competi- tion, and eventually it had to resort to direct negotiations. It is almost certain that better outcomes could have been achieved through more competition. South Africa’s experience also demonstrates that much greater competition is possible among renewable energy providers—93 bids were received in the third round—than thermal power plants. The smaller project sizes, diversified and distributed renewable energy resources, and a highly competitive interna- tional market of project developers, equipment suppliers, and finance sources facilitate competition. It is on these lessons that further thermal IPP procurements in South Africa will be built. It remains to be seen how competitive the coal baseload IPP bids will be. It is already certain, however, that bids will be below both the imposed price cap of approximately USc 7/kWh and the final costs of Eskom’s new Medupi and Kusile plants. Bids for cogeneration plants were launched in 2015 Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 3: Investment in Power Generation in South Africa 189 along with a request for information for gas power projects that will lead to an RfP in 2016. But there will be new challenges. It can no longer be assumed that the national utility, Eskom, will remain creditworthy. And as South Africa’s fiscal situation tightens, there will be less room to offer sovereign guarantees, which will increase contingent liabilities for the National Treasury to unacceptable levels. Finally, South Africa’s experience demonstrates that significant investments in new electricity generation capacity are possible in a power sector that has under- gone limited reforms. Although an independent regulator has been established and IPPs are permitted, the vertically integrated and state-owned Eskom has retained a dominant market position. Initially it discouraged the entry of IPPs, but the DoE managed to establish a separate procurement office and, with trans- action advisers, an effective capability to run international competitive tenders. Nevertheless, current arrangements are far from perfect and could easily be undermined. The powers given to the Minister of Energy to produce electricity generation expansion plans, and to translate the plans into timely procurement decisions (through ministerial determinations), have not been well used and have also restricted the regulator, which may license new generation investments only in line with these directives. Gazetted plans are out of date, demand forecasts have proven to be too optimistic, and the projected costs of various supply options are incorrect. More flexible, dynamic, and indicative plans and more space for private innovation around new generation supply investments would probably better ensure sufficient electricity supply in the future. South Africa’s damaging power cuts are symptomatic of the failure of the current system. Eskom has not been able to supply enough power, and sufficient IPP capacity has not been procured on time. The current institutional arrangements for IPP procurement are ad hoc and vulnerable to politically capricious decisions. The current power crisis in South Africa suggests that further reform is required. Unbundling generation and ­ leaving Eskom with system and market operation, transmission, and perhaps also distribution could focus scarce management skills, improve efficiencies, and cre- ate a level playing field between public and private investments in generation. Planning, procurement, and contracting functions could be embedded in a non- conflicted Eskom. These are the key concerns in any sector reform or restructur- ing. Ultimately, successful power sector reforms are not about ownership or wholesale or retail competition as much as they are about the effectiveness of planning, procuring, and contracting new investments. Notes 1. Nigeria recently rebased its gross domestic product, which now measures larger than South Africa’s. 2. The first unit was commissioned in 1957. 3. An exchange rate of R 8/$ was used in the buildup to the Renewable Energy Independent Power Project Procurement Programme and for round 1 when the first agreements were signed. For Rounds 2 and 3, the exchange rate at the time of signing agreements was used to calculate project prices and investment values. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 190 Case Study 3: Investment in Power Generation in South Africa 4. The Development Bank of Southern Africa, located in Johannesburg, has been classi- fied as local in this analysis. 5. This requirement was relaxed in bid round 4. 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Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 C h apter 9 Case Study 4: Power Generation Results Now, Tanzania! Introduction Tanzania has a vast array of conventional and renewable energy resources, and yet the country struggles to generate sufficient power to fuel growth and development. It has only 1,583 megawatts (MW) in installed generation, and imported fuel is a critical piece of its electric power generation. Network failures undermine what little power is produced. As a result, approximately 46 percent of the nation’s total power consumption is from off-grid self-generation (averaging $0.35/kilowatt-hours, kWh) (NKRA Energy 2013: ­ 12, 166).1 What has prevented Tanzania from harnessing its domestic resources in an economically efficient way, and what may be done differently going for- ward? There appear to be three key elements that directly affect Tanzania’s electricity supply industry and generation procurement. The first is a lack of coherent and up-to-date planning; the second is related to the planning and contracting nexus, including the allocation of public and private generation projects. The third element is a lack of sustained commitment to private sector investment and competitive bidding practices. The gas sector also suffers from many of the same issues, with direct implications for power production. The first section of this case study provides a history of how the sector developed, followed by a description of the current structure and capacity. Prices and plant performance are also presented. In subsequent sections, the analysis focuses on how capacity has been procured and financed (in both public and independent power projects, IPPs), as well as future plans. Finally, the case study offers conclusions related to fundamental elements that have contributed to and detracted from power generation development in Tanzania. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   193   194 Case Study 4: Power Generation Results Now, Tanzania! Tanzania’s Electricity Sector: An Overview A History of Power Sector Reforms Electricity in Tanzania dates back to 1908, when colonial authorities (in what was then known as Tanganyika) installed electric power to run railway work- shops in Dar es Salaam.2 In the early 1930s, the colonial government decided to withdraw from the supply of electricity services. Thus, the Dar es Salaam and District Electric Supply Company (DARESCO) and the Tanganyika Electric Supply Company were established. Both utilities grew, and when Tanzania gained independence in 1961, the second of the two companies was exporting power to Mombasa in Kenya. After independence, the government sought to acquire both electric utilities, and a prolonged nationalization process took place (1964–75). During that time, the two utilities merged to form the Tanzania Electric Supply Company (TANESCO), which performed adequately in the 1960s and 1970s. In the 1980s, electric supply and distribution began to deterio- rate and has remained poor since. Repeated attempts at reform started in the early 1990s. In 1992, a National Energy Policy was formulated that opened the sector to private participation, including a provision to encourage private electricity generation and distribution in areas where TANESCO had not established a public power supply system. The next year, bids were invited for the country’s first IPPs. Following this push, in 1997, TANESCO was earmarked for privatization. Under pressure from both the World Bank and the International Monetary Fund (IMF), these efforts inten- sified from 1999, and included a 100 percent increase in nominal tariffs. By 2001, with electricity costs relatively high, the quality and reliability of supply still poor, and the financial standing of the state utility persistently weak, attention focused on TANESCO’s management. In the same year, the govern- ment of Tanzania reconstituted TANESCO’s board and initiated a management contract that was set up to last two years, starting in 2002, but ended up spanning four years. The objective of the contract was to achieve TANESCO’s commercial turnaround with a view to privatizing the utility. When the contract was extended in 2004, its scope was widened to include improvements in technical performance. Meanwhile, in 2003 the National Energy Policy was updated; revi- sions were built on the 1992 policy and further emphasis placed on introducing competition into the sector, ensuring open access to the grid, prioritizing regional cooperation and integration, and developing indigenous resources and renew- ables for power supply. While TANESCO’s balance sheet improved under the management contract, specifically because of better collection, the quality and reliability of supply and the rate of new electricity connections did not increase materially, mainly because of underinvestment (Ghanadan and Eberhard 2007: 23). Then, in 2005, an incoming administration reversed plans and de-listed TANESCO from priva- tization, in direct opposition to an underlying objective of the management contract. In 2006, the government announced that the management contract would not be extended, a decision that met with wide public approval. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 195 Two years later, in 2008, an Electricity Act was passed, updating the 1957 Electricity Ordinance Amendment that had until then governed the sector. With respect to the structure of the electricity industry, Clause 4(1) of the act states: The Minister shall provide supervis[ion] and oversight in the electricity supply industry and shall in that respect ... take all measures necessary to reorganise and restructure the electricity supply industry with a view to attracting private sector and other participation, in such parts of the industry, [in] phases or time frames as he deems proper. After nearly two decades of reforms characterized by a fluctuating commit- ment to private sector participation, the Electricity Act of 2008 appeared to signal a renewal of the government’s commitment to reform the sector, albeit in part at the insistence of the donor community (as had been the case for the dura- tion of the reforms). In 2011–12, however, actual practices on the ground departed from this policy commitment, with the nontransparent procurement and installation of multiple emergency power plants (EPPs) and a push for four state-owned power projects. While privately owned, the EPPs worked contrary to the goals of competition and reform, as detailed below. The “Big Results Now” (BRN) initiative (which came into effect in 2013) is rooted in the 2008 Electricity Act, which reaffirms the goal of unbundling and privatizing the sector. According to BRN, the mandate of the present planning framework, under Tanzania’s Development Vision (TDV) 2025, is to transform Tanzania’s future electricity landscape.3 By 2025, Tanzania is expected to have installed 10,000 MW, more than six times the present capacity, which would represent a radical departure from past supply shortages (MEM 2014: i).4 In 2014, PricewaterhouseCoopers provided strategic advice related to the unbundling of TANESCO, advice that harkened back to the era of the manage- ment contract. The sector has long suffered from TANESCO’s poor financial position, which was severely aggravated by the EPPs. As made evident in the most recent publicly available financial statement (from 2013), TANESCO’s financial situation is dire: Without qualifying my opinion, I draw attention to users of the financial statements to Note 3 which indicates that during the year the Company incurred a net loss of Shs. 467,704 million (2012: Shs 177,399 million) and at the reporting date, the Company had accumulated losses amounting to Shs 1,450,380 million (2012: Shs 982,678 million). These conditions together with other matters disclosed in Note 3 indicate the existence of uncertainty on the smooth operation of the company (United Republic of Tanzania Audit Office 2013: 27).5 Strategic interventions, some supported by the World Bank’s Development Policy Operation Credits I and II (DPO I-II), have aimed to address and amelio- rate TANESCO’s financial situation, with another under preparation. However, private stakeholders are concerned as arrears continue to increase and TANESCO remains far from being financially viable. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 196 Case Study 4: Power Generation Results Now, Tanzania! Other challenges for the sector include the lack of transparency, as discussed in the context of two high-profile cases (Independent Power Tanzania Ltd. [IPTL] and Richmond/Dowans) later in this case study, and what private inves- tors have repeatedly described as the favoring of publicly funded projects over private investment. All new long-term projects in recent years have been or are going to be built and owned by TANESCO (despite, it should be emphasized, TANESCO’s precarious financial situation) rather than the private sector. This unwritten policy has been formalized (through letters from the energy regulator to the energy minister), and going forward all private projects will be undertaken as public-private partnerships (PPPs). Furthermore, despite regulatory statutes that encourage a competitive approach, noncompetitive arrangements are the preferred method of doing business with the private sector. What factors explain the country’s shifts toward and away from private invest- ment and reform measures, and the disconnection between adopted policy and actual practices on the ground? Part of this disconnect may be attributed to the fact that the numerous state actors involved are not united in their policy posi- tions and approaches, and various factions have at times worked against one another. Finally, it is worth noting that while feed-in tariffs (FiTs) are under discussion, there are presently no specific incentives for large-scale renewable projects. The Sector’s Structure and Institutions Notwithstanding the ambitious reforms envisioned for the electricity sector, its present structure continues to be characterized by a poor performing, verti- cally integrated, state-owned utility (whose attempts to contract IPPs are spo- radic and not always successful), and the prominence of nontransparent deals (figure 9.1). This is an important factor in evaluating the efficacy of planning, procure- ment, and financing, particularly of private power, and future investments in generation. The present structure also has implications for Tanzania’s gas devel- opment, which is integral to electric power. The government, through the Ministry of Energy and Minerals (MEM), is responsible for formulating energy policy. A statute dictates that the regulation of the sector be conducted by an independent regulatory agency, the Energy and Water Utilities Regulatory Authority (EWURA). As is increasingly the case across Africa, an autonomous body, the Rural Energy Agency (REA), has been charged with scaling up rural electrification. However, as will be discussed in more detail, EWURA has not always been emboldened to carry out the regula- tion that is its mandate. At the industry level, all the defining features of a hybrid electricity market are visible. TANESCO dominates the sector, while IPPs (Songas6 and IPTL) pro- vide additional generation capacity, together with Mwenga hydropower, Tanganyika Planting Company (TPC), Tanwat, and Ngombeni through small power projects (SPPs).7 The Mtwara Energy Project (MEP), formerly a remote rural gas-to-electricity generation and distribution concession, reverted back to Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 197 Figure 9.1  Overview of Tanzania’s Electricity Sector, 2014 Ministry of Energy and Minerals (MEM) Energy and Water Utilities Regulatory Authority (EWURA) Rural Energy Agency (REA) Industry Special power Emergency power projects/plants plants (EPPs) Independent power Generation and distribution projects (IPPs) concession (Symbion, (Mwenga hydro, TPC, Tanwat, Ngombeni) Aggreko) (Songas, IPTL) (Mtwara Energy Project) TANESCO Consumers Note: IPTL = Independent Power Tanzania Ltd.; TANESCO = Tanzania Electric Supply Company; TPC = Tanganyika Planting Company. TANESCO’s control in 2012 after two years of operation, due to a mismatch between operating costs and revenue (TANESCO, personal communication, January 14, 2015). Power Sector Processes While the MEM is responsible for planning, TANESCO and EWURA have advi- sory and support roles. This has largely been an ad hoc arrangement to address performance issues within the MEM and across the planning process (TANESCO, personal communication, January 14, 2015). It presents a number of challenges, including the fact that TANESCO takes part in sector planning while simultane- ously retaining an interest in building its own new power stations. The planning process is characterized by politics rather than impartial and sound (near- and long-term) decisions based on outside data sources. Although it is expected to continue for the foreseeable future, the Electricity Act of 2008 allocated the Power System Master Plan to an independent system operator (ISO). As of the first quarter of 2015, the ISO had not been established, though the most recent Reform Strategy and Roadmap stipulated that this should be done between July 2014 and June 2015 (MEM 2014: 42). Noteworthy in this context is that in the Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 198 Case Study 4: Power Generation Results Now, Tanzania! past 10 years, the MEM has seen five permanent secretaries, five ministers, and several different deputy ministers—a turnover that has had serious ramifications for the planning and associated execution and coordination processes. Historically, the planning function was largely outsourced to TANESCO and consultants. A number of master plans and strategies have been produced over the years, but they have quickly obsolesced, and it would appear that they have not directly informed procurement decisions. The present Power Sector Master Plan (2012) was bolstered by BRN (2013), which has not introduced any new projects but has altered the priorities and the schedules of several others (MEM 2013: 11; NKRA Energy 2013: 458). While TANESCO has built some genera- tion capacity, as described below, this has been funded by the government; the utility has no resources to finance its own future projects. Meanwhile, numerous prospective IPP developers have entered into memo- randa of understanding (MoUs) with the MEM in the past, but the ministry has limited capacity to assess value for money or undertake the negotiations neces- sary to bring these to fruition. As a result, very few projects have materialized, as will be highlighted in the forthcoming discussion of IPPs. Those that have been negotiated have been slow to come to commissioning. Furthermore, there has been limited application of international competitive tendering. Other planning mishaps are highlighted by the engagement of EPPs, as described as follows: The fact that the EPP was formulated in a highly charged atmosphere of political anger at the on-going power shortages was no reason to disregard normal plan- ning precepts and government procurement requirements. The EPP should have been rooted in careful analysis of unsuppressed demand, should have acknowl- edged the dispersed capacity owned by the private sector, which is appropriately used in times of emergency, and the imminence of the commissioning of genera- tion projects already being implemented (mid-2012).8 The Ministry of Finance should have played a key role in formulating the EPP, requiring the Technical Working Group to carefully weigh up the costs of high levels of capacity increases against the risks of just “getting by” until mid 2012 with a minimalist strategy. (MEM 2011) The Electricity Act gives EWURA the power to approve the initiation of pro- curement of power projects. These powers have been further defined under the Electricity (Initiation of Power Procurement) Rules, with the overarching goal of discouraging unsolicited proposals that fall outside the Power System Master Plan and are not financially viable for the state (Electricity Act [CAP 131]).9 The rules came into effect as of January 1, 2015, and will affect projects presently under negotiation, but not existing IPPs (that is, Songas and IPTL). EWURA is supposed to review all projects in Tanzania, a principle that is enshrined in the Electricity Rules; however, it is not clear that the agency is sufficiently equipped to carry out this task. While the legislation came into effect in January 2015, negotiations over unsolicited proposals carry on. Among these, the Kilwa IPP, a 308 MW gas-fired project that has been highlighted among near-term projects, was introduced by retired public servants and one foreign investor. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 199 Gas: Challenges and Potential The discovery of significant offshore gas to the south is among the most positive developments in Tanzania in recent years (table 9.1). Contingent resources10 are estimated at 29 trillion cubic feet (Tcf), although estimates of more than 50 Tcf have been reported. In the near term, the first priority for Tanzania is to develop two liquefied natural gas (LNG) trains from deep-sea gas, entailing a commitment of 14 Tcf of gas. In the long term, at least two further LNG trains are planned. In parallel, Tanzania is aggressively pursuing a domestic gas-to-power agenda that could result in over 8 Tcf of gas being committed to the domestic market (Santley, Schlotterer, and Eberhard 2014). Supply from this offshore gas, however, depends on the LNG development proceeding. Offshore gas will not flow without an export market as it is too expensive and the volumes too low in the country to justify it. As will be probed shortly, significant gas discoveries have the potential to change the landscape of Tanzania’s electric power production, but this has not yet happened. The absence of relevant planning and timely implementation (including the development of pipeline and gas-processing infrastructure) along with a weak investment climate have prevented Tanzania from exploiting its gas potential. Instead, the country has continued to resort to EPPs. The high costs of engaging and fueling a fleet of EPPs with imports in the past five years (for 2012 alone, EPP costs were estimated to be $320 million) effectively bankrupted TANESCO.11 It should be reiterated in this context that EPPs were all procured through nontransparent deals. Government support for TANESCO in this period was sporadic and insufficient to keep TANESCO liquid. As a result, TANESCO stopped paying the IPPs, EPPs, and some of their fuel suppliers. With funding obtained from donors and commercial lenders, including under DPO I, II, and (anticipated) III, TANESCO is beginning to recover from this financial shock, but until recently owed large arrears to the sector (estimated to be up to $300 million). Table 9.1  Onshore and Offshore Gas Discoveries and Developments: Tanzania, 1974–2014 Field Discovery date GIIP (Tcf) Proven (Tcf) Songo Songo 1974 2.5 0.880 Mnazi Bay 1982 3–5 0.262 Mkuranga 2007 0.2 0.2 Kiliwani 2008 0.07 0.027 Mtwara-Ntorya 2012 0.178 — Deep Sea 2010–14 35.10 (2013) 55.5 (March 31, 2015) — Total 63 Tcf (assuming 5 Tcf Mnazi Bay) Unknown Sources: Ng’wanakilala 2014; Energy and Water Utilities Regulatory Authority (figures received April 22, 2015). Note: GIIP = gas initially in place, not proven reserves; Tcf = trillion cubic feet; — = not available. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 200 Case Study 4: Power Generation Results Now, Tanzania! Installed Generation Capacity As of 2014, Tanzania’s total installed generation capacity was 1,583 MW, including 561 MW of hydropower (35 percent), 527 MW of natural-gas-fired ­ power plants (34 percent), and 495 MW of liquid-fuel power plants (31 percent), of which 53.6 MW is off-grid (table 9.2). Power is also imported from Uganda (10 MW), Zambia (5 MW), and Kenya (1 MW). The current profile is dramati- cally different from that of the recent past. Between 1980 and 2000, the majority of the supply was state-owned hydropower (which is still in operation, distributed across five plants of 8 MW, 11 MW, 68 MW, 80 MW, and 204 MW each). A number of additional observations are noteworthy. First, nearly 57 percent of the grid capacity installed from 2000 (or 643 MW) was privately sponsored; of this, 331 MW was private emergency power. Thus, more than half of all private power was via short-term, nontransparent, emergency contracts. ­ Furthermore, while the relatively new power installations diversified away from Table 9.2  Grid-Connected Capacity: Tanzania, as of 2014 Installed Name Ownership Installed Retire Fuel capacity (MW) Hale TANESCO 1967 2017 Hydro 21 Nyumba ya Mungu TANESCO 1968 2018 Hydro 8 Kidatu TANESCO 1975 2025 Hydro 204 Zuzu diesel TANESCO 1980 2015 Diesel 7.4 Mtera TANESCO 1988 2038 Hydro 80 Tanwat SPP/IPP 1995 2029 Biomass 2 Pangani Falls TANESCO 1995 2045 Hydro 68 Kihansi TANESCO 2000 2050 Hydro 180 Tegeta IPTL IPP unit 2002 2021 HFO 103 Songas 5 IPP unit 2004 2024 NG 38 Songas 1–4 IPP unit 2004 2024 NG 114 Songas 6 IPP unit 2006 2024 NG 37 Tegeta GT TANESCO 2009 2028 NG 45 TPC SPP/IPP 2010 2030 Biomass 17 Ubungo I TANESCO 2008 2026 NG 102 Aggreko Tegeta Aggreko, rental 2011 2014 Gas oil 50 Aggreko Ubungo Aggreko, rental 2011 2015 Gas oil 50 Symbion Ubungo Symbion, rental 2011 2015 converted NG/Jet 126 Mwenga SPP/IPP 2012 2030 Hydro 4 Symbion Arusha Symbion, rental 2012 2014 Diesel 50 Symbion Dodoma Symbion, rental 2012 2014 Diesel 55 Ubungo II TANESCO 2012 2031 NG 105 Nyakato/Mwanza TANESCO 2013 2038 HFO 63 Total 1,529 Sources: MEM 2013: 16; data received from TANESCO (November 14, 2014; January 9, 2015). Note: Off-grid and grid-connected together total 1,583 MW. Grid alone accounts for 1,529 MW. HFO = heavy fuel oil; IPP = independent power project; IPTL = Independent Power Tanzania Ltd.; MW = megawatt; NG = natural gas; SPP = small power project; TANESCO = Tanzania Electric Supply Company; TPC = Tanganyika Planting Company. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 201 hydropower, imported gas oil and heavy fuel oil (HFO) have remained p ­ rominent in the mix, and only TANESCO’s new builds, along with Songas, have utilized domestically produced natural gas. Thus, leaving aside any contracting issues, the new power has been associated with costly imported fuel (electricity prices will be discussed further below). This power landscape is, however, changing. The “Electricity Supply Industry Reform Strategy and Roadmap 2014–15” set the aggressive goal of retiring 205 MW of 331 MW by December 2014 as a means to improving TANESCO’s financial performance. Of this, 155 MW was phased out over the course of 2014. Two units (Symbion Arusha and Symbion Dodoma), amounting to 105 MW in emergency power, were retired in June 2014, and Aggreko Tegeta (50 MW) was subsequently retired end-November 2014, as per contract specifications. The 50 MW of Aggreko Ubungo, slated to be retired by February 2015, was retained amid expectations in 2Q2016 of a dry year in 2016 and a further delay in gas supplies. The last of the EPPs, Symbion Ubungo (126 MW)—which was to be recommissioned, converted to an IPP contract in April 2015, and run on Tanzanian natural gas—has also been delayed, as of 2Q2015 (TANESCO is still negotiating the power purchase agreement [PPA], and gas supplies are delayed as well). As a result, only 50 percent of EPP capacity has been phased out, in contrast to the 100 percent envisaged. Power Sector Performance The performance of the sector is also critical to evaluating both private and pub- lic sector generation. This analysis has implications for the future of BRN and the proposed 10,000 MW and sector unbundling. It should be reiterated at the out- set that while TANESCO is breaking away from its spiral of debt, its financial situation has been dire (with arrears running into the millions of dollars), which has been a significant barrier to attracting new investors through transparent channels. Electricity Produced The actual units generated in 2013 reflect a reliance on older, state-owned plants (installed before 2000) that are still in operation. In 2013, 53 percent of the power was generated by TANESCO (with a further split of 30 percent state- owned hydropower and 24 percent thermal); 46 percent was produced by IPPs (Songas and IPTL) and EPPs, with a balance of 1 percent contributed by imports (figure 9.2). EPPs and IPTL together accounted for nearly 50 percent of all pri- vately generated power; this generation relied on HFO, gas oil, and/or jet fuel. Electricity Prices Table 9.3 lists the costs of bulk supply borne by TANESCO. The average cost per kilowatt-hour is $0.15, which is closely reflected by the present electricity end-user tariff in Tanzania ($0.15–$0.16/kWh on average). ­ If EPPs are removed from table 9.3, the average cost of supply falls to approxi- mately $0.10/kWh, evidence of EPPs’ impact on price. However, such snapshots Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 202 Case Study 4: Power Generation Results Now, Tanzania! Figure 9.2  Share of Grid-Generated Electricity Production, by Type of Producer: Tanzania, 2013 percent Imports, Other, EPPs, 1 0.28 16 IPTL, 7 TANESCO, 53 Songas, 23 Source: Compiled by the authors, based on TANESCO data. Note: Other (0.28 percent) includes the small private producers Tanwat, TPC, and Mufindi. EPP = emergency power plant; IPTL = Independent Power Tanzania Ltd.; TANESCO = Tanzania Electric Supply Company; TPC = Tanganyika Planting Company. Table 9.3  Shares/Costs of Capacity and Generation, by Type of Producer: Tanzania, 2013 % of installed % of Total cost/bulk Producer capacity generation Total kWh supply tariff (US$) $/kWh TANESCO 54.58a 53.36a 3,109,117,152 313,025,914 0.10 Songas 11.69 22.68 1,321,600,000 65,881,760 0.05 IPTL 6.32 7.03 409,463,300 126,933,623 0.31 EPPs 20.09 15.64 911,561,640 364,624,656 0.40 Total/average 92.68 98.72 5,751,742,092 870,452,737 0.15 Source: Authors’ compilation based on 2013 data provided by TANESCO (November 12, 2014) and Songas (February 20, 2015), verified with the Energy and Water Utilities Regulatory Authority (April 20, 2015). Note: TANESCO’s average derived cost excludes the cost of capital. EPP = emergency power plant; IPTL = Independent Power Tanzania Ltd.; kWh = kilowatt-hour; SPP = small power project; TANESCO = Tanzania Electric Supply Company; TPC = Tanganyika Planting Company. a. Off-grid, imports, and SPPs (Tanwat, TPC, and Mwenga) all excluded from these tallies, hence generation does not total 100 percent. The associated off-grid cost is $0.328, albeit representing only 5 percent of the total generation. do not reflect the full reality of the costs involved. In the case of TANESCO, for which a per plant cost is not available, the per unit cost12 listed in table 9.3 is solely a function of TANESCO’s running costs and does not include depreciation or finance costs. Unlike for IPPs (Songas and IPTL), electricity users are not pay- ing for any portion of the capital costs of the TANESCO-owned plant, which are government subsidized. These costs are, however, still incurred and are generally paid by taxpayers. It remains a challenge to determine TANESCO’s actual costs, Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 203 Table 9.4  Comparison of Costs, by Type of Producer: Tanzania, 2013 US$/kilowatt-hour Producer Running/fuel cost Capacity cost Total cost TANESCO 0.10 n.a. n.a. Songas 0.013 0.037 0.05 IPTL 0.22 0.08 0.31 EPPs 0.29 0.11 0.40 Total/average 0.15 Source: Authors’ compilation based on correspondence with TANESCO stakeholders (2014). Note: EPP = emergency power plant; IPTL = Independent Power Tanzania Ltd.; TANESCO = Tanzania Electric Supply Company; n.a. = not applicable. including all capital-related expenditure and financing, and comparing these systematically with those of private plants using similar technology at compara- ble load factors.13 Songas, whose contribution to generation is second to that of TANESCO, has a different price structure. Its per kilowatt-hour all-inclusive charge comes to approximately $0.05. The average variable charge, a function of competitively priced domestic gas, amounts to a fraction of this total cost, namely U.S. cents (USc) 1.2–1.3/kWh; this is significantly better than TANESCO’s running cost (table 9.4). IPTL trails the EPPs in terms of kilowatt-hours contributed, but it resembles Songas in its cost structure as a traditional IPP, and therefore is highlighted here. Capacity charges averaged $0.08/kWh in 2013, almost double Songas’s total cost. Taking into consideration differences in technology, this figure appears to be possibly inflated (causes associated with load factors but also with nontranspar- ent procurement will be further observed in the next section). Of the remaining $0.23/kWh in charges for IPTL, $0.22/kWh is accounted for by the imported fuel variable charge, which is a complete pass-through item. Thus the over- whelming cost of this IPP is for fuel. While the total unit charge for IPTL is six times greater than that of Songas, it is on par with the running costs of TANESCO’s Mwanza 60 MW HFO plant, which was financed by the govern- ment and came online in 2013. The current unit running cost of the Mwanza plant is $0.23/kWh, excluding the repayment of loans and interest, which has yet to be finalized between TANESCO and the government of Tanzania. EPPs, namely Symbion and Aggreko, contributed only 16 percent of the gen- eration pie in 2013; however, their costs exceeded that of TANESCO’s own generation, albeit based purely on TANESCO’s running cost for supplying more than 50 percent of total generation. Although the weighted average for the EPPs is $0.40, this masks significant differences in per unit costs (see table 9.5). As with IPTL, the capacity charge of the EPPs is overshadowed by the variable charge, which is a pass-through and makes up the majority of the total cost (72 ­percent). In certain projects, such as Aggreko Ubungo and Aggreko Tegeta, the fuel amounts to 87 percent of the cost. There are, however, important differences across EPPs. For instance, Symbion Ubungo runs partly on (domestic) gas, Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 204 Case Study 4: Power Generation Results Now, Tanzania! Table 9.5  Costs of Generation, by Emergency Power Plant: Tanzania, 2013 US$/kilowatt-hour EPP Cost Symbion Ubungo 0.19 Aggreko Ubungo 0.39 Aggreko Tegeta 0.40 Symbion Dodoma 0.78 Symbion Arusha 0.80 Weighted average 0.40 Source: Authors’ compilation based on TANESCO data (November 2014). Note: EPP = emergency power plant; TANESCO = Tanzania Electric Supply Company. Figure 9.3  Emergency Power Plants’ Contributions to Generation (GWh): Tanzania, 2013 percent Symbion Arusha, 8 Symbion Dodoma, Symbion 9 Ubungo, 31 Aggreko Ubungo, 26 Aggreko Tegeta, 27 Source: Authors’ compilation, based on TANESCO data (November 2014). Note: GWh = gigawatt-hour; TANESCO = Tanzania Electric Supply Company. accounting for its low unit cost compared with other EPPs; yet, because of ­ insufficient gas, Symbion Ubungo’s capacity factor remains low. Finally, there is a cause-and-effect dilemma involving electricity prices and capacity factors; that is, high electricity prices (as in the case of Symbion Dodoma) contribute to low capac- ity factors, which in turn contribute to higher per unit costs. Figures 9.3 and 9.4 depict the various EPPs’ contributions to generation and total costs, respectively. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 205 Figure 9.4  Emergency Power Plants’ Shares of Total Costs: Tanzania, 2013 percent Symbion Ubungo, 15 Aggreko Tegeta, 26 Symbion Dodoma, 17 Aggreko Ubungo, Symbion 25 Arusha, 17 Source: Authors’ compilation, based on TANESCO data (November 2014). Note: TANESCO = Tanzania Electric Supply Company. In sum, despite incomplete data on costs, it is clear that the system is out of balance: EPPs and IPTL account for an inordinate portion of costs, relative to their actual production. This is due in large part to imported fuel charges. It is anticipated that if the debt incurred by the EPPs were to be paid off, TANESCO would break even (EWURA, personal communication, February 28, 2015). Songas measures up to TANESCO’s plants in relation to capacity factors and excels in terms of lower prices, which signals some positive developments in terms of private power (but here, too, there have been issues, as discussed in the next section). IPTL and Songas, and the Next Generation of Independent Power Projects As noted at the outset, the three key elements that have come to define Tanzania’s generation procurement are a lack of coherent and up-to-date plan- ning; a planning and contracting nexus, including the allocation of public and private generation projects; and a lack of sustained commitment to private sector investment and transparent bidding practices. Each of these areas is highlighted in the IPP experiences discussed below. This section looks first at the evolving role that natural gas has played in the power sector, then at IPP developments dating from the mid-1990s and how Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 206 Case Study 4: Power Generation Results Now, Tanzania! they affected the outcomes of individual projects and the sector as a whole. What lessons have been learned, and what changes have been made—specifically in terms of planning, procurement, and contracting—to ensure that history does not repeat itself? An Early Gas Discovery at Songo Songo and a Gas-to-Electricity Plan In 1974, approximately 2.5 Tcf of gas was discovered at Songo Songo (offshore and on the island itself, about 200 kilometers [km] south of Dar es Salaam).14 The initial plan was to harness gas for fertilizer production. The government of Tanzania partnered with Agrico, a U.S. company, in 1981 to form the Kilwa Ammonia and Urea Company (KILAMCO, with 51 percent of shares held by the government and 49 percent by Agrico).15 By 1989, with little to no progress made, negotiations collapsed. Failure to close the deal is attributed in part to the poor investment climate at the time, which did not adequately support foreign direct investment (FDI). Meanwhile, the idea to use gas for power had long been considered by the MEM, but public funds were insufficient and private investment not forthcoming. The MEM began a more focused evaluation of the gas-to-power option after the Agrico deal fell through. By 1991, it had been determined that gas-based power generation was the next least-cost option to hydropower and quicker to develop than other sources. This idea became a cornerstone of the Power System Master Plan in the same year. Around that time, the government was approached by Ocelot (which today operates under the name PanAfrican Energy Tanzania Limited, PAT),16 a Canadian-based gas company, with a proposal to develop Songo Songo. Among the options discussed were LNG development, a gas pipeline for export to Mombasa, and gas for domestic use. Two different plans were endorsed by con- sultants, but no conclusion was reached at this early stage.17 On the heels of Ocelot’s initial proposals, starting in 1992, the country experienced a major drought. The MEM sought emergency measures to plug its power shortage. In November 1992, the Swedish International Development Cooperation Agency (Sida), Tanzania’s largest bilateral energy donor, pro- vided funds for TANESCO to procure approximately 40 MW of power (two 18 MW ABB GT 10A open-cycle turbines, which ran on jet fuel).18 The turbines were installed at Ubungo. Sida also committed to meeting the oper- ating costs (primarily fuel costs) of the turbines in the first two years, which amounted to about $35 million. It was expected that by the end of 1993, or shortly thereafter, gas from Songo Songo would be available; that is, before the grant for fuel was exhausted, the country could convert to domestic gas to feed the two turbines (despite the fact that the gas infrastructure had still not been contracted). Amid persistent power shortages and mounting pressure to procure fuel for the Ubungo plant, in February and March 1993 the MEM invited 16 companies with experience in gas and power development to bid for the Songo Songo gas-to-electricity project. According to stakeholders at the MEM, competition for ­ Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 207 the project was a prerequisite of the World Bank, which at the time was active in reform proposals in Tanzania’s electricity sector.19 The invitation contained a basic project concept to rehabilitate existing gas wells (which had been drilled in the 1970s), develop a pipeline to Ubungo, convert and supply two existing turbines, and add an additional 60 MW (in the form of two additional units) under a build-own-operate-transfer (BOOT) ­arrangement.20 Firms were allowed to form consortia to ensure both upstream and downstream expertise. Among those companies invited were Enron, British Gas, Amoco, and Ocelot. At the time of the initial invitation, no credit enhancement was provided (that is, no sovereign guarantees and no escrow accounts), despite a widely perceived poor investment climate and an insolvent utility. Furthermore, firms were given only six months to submit bids; a deadline of August 1993 was set by the MEM. Also, the plant size (of 60 MW) was small by international standards. Because of these limitations only 2 out of the 16 invitees submitted bids: OTC, a joint venture between Ocelot Energy Inc. and TransCanada Pipelines (a Canadian firm with expertise in power development), and a joint venture of Enron and Andrade Gutierrez.21 In December 1993, the MEM, TANESCO, and the Tanzania Petroleum Development Corporation (TPDC) met to review proposals, ultimately recommending the OTC bid to the minister of energy. The ­ World Bank was consulted in January and February 1994, and OTC was officially awarded the tender by February 1994. By July 1994, negotiations commenced in Dar es Salaam; the project company Songas (which was composed of Ocelot) held a 25 percent equity stake and TransCanada the balance of the equity. As negotiations were gaining momentum, the country experienced yet another drought, in November 1994. At this time, additional equity partners were under consideration, including the TPDC and TANESCO, which would eventually formalize their stakes in the project by October 1995, together with those listed earlier. In addition, over 20 different contracts were being drafted to satisfy the requirements of the Songo Songo project participants, and financial close had not yet been reached. Rather than wait the six months or more before the project was finalized, the MEM sought to install additional emergency capac- ity at Ubungo. Persistent Power Shortages and the Emergence of IPTL It was at this time that the government began considering, among others, the IPTL project proposal to yield an additional 100 MW. The IPTL project com- pany was formed between the Malaysian firm Mechmar (70 percent) and the Tanzanian firm VIP Engineering Limited (30 percent). According to numerous stakeholders, the IPTL deal grew out of south-south collaboration, which was being heralded at the time as an alternative to the north- south donor-recipient model of the previous decades. Unlike for Songas, there was no formal tender. However, amid persistent power shortages the g ­ overnment sought a fast-track way to increase its non-hydropower generation capacity. A meeting was convened on December 15, 1994, to address this objective; it was Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 208 Case Study 4: Power Generation Results Now, Tanzania! agreed that IPTL could not meet the fast-track power deadline for mid-1995, but that the firm’s proposal might be considered within the context of the country’s long-term power plan. Instead, through a World Bank facility, the government was able to finance two additional turbines of 35 MW each. Combined with the previous turbines, this now made up a total of approximately 106 MW at Ubungo, which met the immediate shortage, and IPTL was deferred. As with the previous turbines, it was expected that they would be converted to burn natural gas at the earliest possible date. IPTL Dispute and Its Implications for Songas Meanwhile, Songo Songo negotiations continued. The Tanzania Development Finance Company Limited (TDFL, sponsored by the European Investment Bank, EIB), International Finance Corporation (IFC), German Investment and Development Corporation (DEG), and the power company Commonwealth Development Corporation (CDC) all joined the project company by February 1996. Further provisions agreed to later in 1996 included an allowance for funds used during construction (AFUDC) and an escrow account. Although Songas was expected to materialize in the near term, during the same period, negotiations reached completion with IPTL. A PPA was signed between the government and IPTL for a 100 MW diesel generator in May 1995, which was expected to be converted to run on natural gas with the completion of the Songo Songo gas-to-electricity project. Standard security arrangements and credit enhancements were sought and obtained; their terms differed from those negotiated by Songas, however, mainly because the MEM never formalized a set of standard IPP terms and conditions, and the projects were negotiated by different stakeholders. The circumstances surrounding the IPTL agreement have been widely debated; several stakeholders allege corruption and point to the fact that since the project was not included in the Power System Master Plan, it would make Songas redundant. Other stakeholders argue that the project emerged from a genuine south-south collaboration with Malaysia, was identified as a viable solu- tion by the government as early as December 1994, and that the parties agreed (legally) to the terms of the PPA.22 The impact of the IPTL agreement was not immediate. Negotiations with Songas were ongoing and the project company continued to make equity disbursements to fund the development of the project (with an impact on the AFUDC) until 1997. In this year, several things happened. First, IPTL reached financial close, with funding committed by two Malaysian banks, and started construction.23 Second, in the latter part of 1997, Tanzania’s hydrological situation reversed due to the weather phenomenon of El Niño. Starting in December, reservoirs began filling and would ultimately overflow (sustaining the country until 2001). Finally, IPTL plant costs amounted to $150 million (with an additional $13 million budgeted for fuel conversion to natural gas, for a total of $163 million). As a result, Tanzania found itself Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 209 overcommitted in terms of capacity; the country needed at the most one plant but certainly not two. With power now in abundance and financial liabilities mounting, TANESCO served a notice of default to IPTL in April 1998, with an intention to terminate the contract. The charge made by the utility was that IPTL substituted medium- speed engines for slow-speed ones, but did not pass on the capital cost savings to the utility. Contrary to earlier cost estimates, the government determined that a plant of similar size, using similar technology, would cost no more than $90 ­ million. Disagreement over the substitution24 and the capacity payment persisted throughout 1998, culminating in a Request for Arbitration on behalf of TANESCO at the International Centre for Settlement of Investment Disputes (ICSID). Meanwhile, IPTL filed a petition with the High Court of Tanzania claiming that commercial operations were to commence in August 1998, and as a result, IPTL was owed capacity charges of $3.6 million for each month from that date. This petition would eventually become part of the ICSID tribunal once it was convened in June 1999. While the tribunal involved several phases, the final award, made in May 2001, upheld the PPA signed in 1995, adjusted the capacity charge to $2.6 ­million per month, and indicated that conversion to natural gas would be as per the original PPA—with the costs of conversion paid by TANESCO (with a bench- mark of $11.6 million set) and work to be carried out by Wartsila.25 During the three-year dispute between IPTL and TANESCO, Songas would be put on hold amid concerns that the utility could not absorb power from two plants. Three critical developments occurred during this period. First, although no additional work was completed by the sponsors, the AFUDC continued to compound at a rate of 22 percent per year. Second, the scope of Songas was scaled down from 151 MW (as per the 1995 negotiations) to 106 MW in light of the expected IPTL capacity. Third, significant changes occurred in the compo- sition of the project sponsors. Both the IFC and DEG pulled out of Songas shortly after the IPTL dispute became known (with the CDC taking over their associated financial obligations of approximately $12 million). Furthermore, by 1999, TransCanada arranged for the sale of its majority share to a U.S.-based power development firm, citing a strategic decision to consolidate its assets in North America. Two years later, Ocelot would do the same, though for a different reason, namely, consolidating its interests in the Songo Songo gas field exclusively (see details on the production-sharing agreement between the TPDC and PAT in annex 9D). Thus, ­ by the time the IPTL arbitration had been concluded and sufficient demand had been ascertained, the AFUDC had increased substantially and the original lead sponsors of Songas had all but transformed (with only the CDC, TPDC, and TDFL maintaining their minority shares in the project). It was under AES that the PPA was completed; financing for Songas was even- tually finalized in October 2001, nearly a decade after Ocelot had first approached the government.26 By 2003, however, with work well under way on the refurbishment of the Songas turbines, AES would sell the majority of its Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 210 Case Study 4: Power Generation Results Now, Tanzania! shares to Globeleq.27 During this sale, the government negotiated with the new lead shareholder to buy down the AFUDC to keep future tariffs sustainable. Initially, the AFUDC was to be wrapped into the capacity charge; however, because of the extensive project delays, by April 2003 the amount had ballooned to $103 million and would have meant a monthly capacity charge of more than $6 million, equivalent to almost 30 percent of TANESCO’s revenues. The buy down of the AFUDC was agreed to by Songas’s new owners and financed by the Ministry of Finance (50 percent), TANESCO (10 percent), and the Songas Escrow facility28 (40 percent), which by 2003 totalled about $50 million. Globeleq did not require an escrow facility as a condition of its purchase, and the facility has not been replenished. Controversy Continues In the years since these events, power has been supplied by both Songas and IPTL, with IPTL power being considerably more expensive. Despite the original plan dating to 1995 and reinforced in the 2001 arbitration, IPTL has still not been converted to run on natural gas.29 One of the impediments to the conver- sion is that while the ICSID tribunal was concluded, legal issues related to proj- ect sponsors stymied further developments. Another plan was for the government to buy back IPTL’s debt; however, this has not materialized. Furthermore, controversy surrounded the sale of IPTL to Pan Africa Power Solutions (PAP) and the subsequent transfer of funds from the Bank of Tanzania (escrow account) to PAP. According to TANESCO, there is no near-term plan to convert IPTL to natural gas. The lessons from Tanzania’s experience with IPTL could not be more explicit. When power is not planned, procured, and contracted transparently and consistently, the implications are potentially grave, far-reaching, and ongoing. ­ Rather than being considered a planning and procurement mishap, however, IPTL is often used to emphasize the drawbacks of private sector participation. Meanwhile, Songas has not been widely recognized as a successful competitive bid or as an example of how the private sector can work strategically to harness more power. Instead, it has been charged with having advanced private interests at the expense of the state, including obtaining key assets such as pipeline infra- structure that are in the strategic interests of the country. Symbion, Following Independent Power Tanzania Ltd. At its inception, the Symbion case seemed to replicate some of the planning, procurement, and contracting issues experienced around IPTL. Originally speci- fied for a two-year contract to plug an immediate power shortage in 2006, Symbion Ubungo (a 126 MW project previously known as Richmond/Dowans) is now slated for a long-term IPP contract; its project duration has already exceeded eight years. Apart from its longevity, it is worth noting the controversy surrounding the project. Agreement was struck, in a nontransparent manner, with Richmond, a special- purpose vehicle (SPV) formed in 2006 to provide 100 MW of emergency power. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 211 The contract was stipulated for two years starting in September 2006 (20 MW) followed by the balance (80 MW) by February 2007, which was safeguarded by a government guarantee. The first 20 MW (of the 100 MW) was, however, brought online in October 2006, and fueled with natural gas supplied by Songo Songo. This occurred only after the government advanced Richmond funds, as neither the parent company (which it turns out is a publisher with no prior experience in power supply) nor the subsidiary (operating from a residential address in Houston) had money to lift the generators. Dowans Holdings, based in the United Arab Emirates (UAE), subsequently bought the plant and took over the contract, and saw the addition of 60 MW capacity, albeit only by August 2007—six months later than expected. When the plant finally came online it was not fully functioning and by the time all issues had been resolved Tanzania was no longer in need of the power, yet it was legally contracted to purchase it or pay penalties. The Richmond/Dowans fallout led to the resignation of then–prime minister Edward Lowassa and two other ministers on charges of alleged associ- ated corruption in 2008. In contrast to the nontransparent arrangements of 2006, the present negotia- tions with Symbion are overseen by EWURA and governed by the Electricity Act (CAP 131) of 2014, and thus different outcomes may be anticipated. The expectation is that the cost structure will change, both with respect to the capac- ity charge and the fuel. The reference point TANESCO provided for the Symbion negotiation is Kilwa, a 308 MW combined-cycle gas turbine (CCGT) presently under negotiation, for which the target total unit cost should not be more than $0.08/kWh. Nonetheless, the Kilwa negotiation is still ongoing. As previously indicated, Kilwa was not competitively bid—project sponsors involved retired public servants and one private foreign investor—and it is not yet recognized as a success relative to other IPPs. Wind East Africa (Singida 100 MW) versus NDC (Singida 50 MW) In 2004, TANESCO, in collaboration with the Danish government, identified stimulating investment and harnessing Tanzania’s wind power as priorities. TANESCO invited any party (through an open, general invitation that does not necessarily fall under the definition of international competitive bidding) to develop wind projects. Five entities came forward, including the precursor to Wind East Africa (Singida, 100 MW), as well as two of the partners that since formed the Singida 50 MW project (namely National Development Corporation [NDC] and Power Pool East Africa Ltd; the third party in the consortium is TANESCO). Initial wind-mapping studies were undertaken by Wind East Africa, though there was little in terms of project development by either the sponsors of Wind East Africa (100 MW) or Singida (50 MW). In 2009, Aldwych International, a U.K.-based private IPP firm with a focus on Africa, joined the Singida 100 MW project. Momentum picked up, including the engagement of the World Bank and the IFC, which today are involved at several levels in the 100 MW project. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 212 Case Study 4: Power Generation Results Now, Tanzania! Despite the involvement of Aldwych, the World Bank, and the IFC, the project stalled. Meanwhile, Singida 50 was identified among near-term PPPs ­ for TANESCO. Delay and hesitation surrounding the wind projects were partly due to the fact that at 11–12 USc/kWh, the cost of power was higher than for power generated with domestic gas (at 6–7 USc/kWh). With more gas expected to come on stream, there was an argument that wind power was not competi- tive. This argument has less traction now, given the delays in gas infrastruc- ture and contracting. Also, wind would prove significantly less expensive than the EPPs of the recent past and IPTL. While both projects are now progressing, the question arises as to why such extreme delays occurred— almost 12 years and counting since Wind East Africa expressed interest. Another key feature of the wind story is the relationship between the two projects, with Wind East Africa viewed to be in competition with Singida. There was no reason for the two projects to be pitted against each other for multiple years; they could have instead been phased in one after the other, or undertaken simultaneously. The wind story provides further evidence that the lessons of the IPTL debacle have not been internalized by key stakeholders. Various factions compete within state agencies, based on vested interests; and transparency remains compromised, despite efforts to embolden the EWURA with regu- latory powers. Future Projects, Public and Private As private developments are beset with challenges related to planning and other issues, how does the public sphere fare, especially with a cash-strapped utility? Is private investment being crowded out? As mentioned earlier, TANESCO maintains a dominant share in genera- tion—53 percent of installed capacity, which is skewed by the dominance of EPPs. If EPPs are excluded, TANESCO’s installed capacity stands at 64 percent, of which 495 MW have been built since 2000. In addition, and as highlighted earlier, in recent years all new long-term power plants have been or will be built and owned by TANESCO, and PPPs have been identified as the way forward. Thus the trend has been to expand, not curtail, state-owned assets, despite repeated calls for privatization. Going forward, four of the seven priority generation projects in the near term (that is, to be completed before or by 2018) are expected to be owned by TANESCO with varying degrees of PPPs and associated funding; these four projects are Kinyerezi I–IV (with Kinyerezi I and II specified for government ­ funding and Kinyerezi III and IV identified for PPP funding, with Chinese ­ partnerships)—see table 9.6. Of the estimated $1.91 billion earmarked for investment in the earlier-noted generation projects, the government is expected to contribute $615 million or approximately 32 percent of the new capacity. Thus while ownership of assets is Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 213 Table 9.6  Generation Projects Planned in the Near Term, Tanzania Capacity Tech/ Investment Ownership Project name (MW) fuel (US$, millions) Funding source TANESCO Kinyerezi I 150 OCGT 183.3 GoT TANESCO Kinyerezi II 240 CCGT 432 GoT TANESCO Kinyerezi III 300 OCGT 389.7 PPP TANESCO Kinyerezi IV 450 CCGT 400 PPP IPP Kilwa Energy 308 CCGT 365 ETG Power, United Arab Emirates IPP Singida 50 Wind 136 National Development Corporation, TANESCO, and Power Pool East Africa Ltd. IPP Wind East Africa 100 Wind 285 Aldwych, IFC, Six Telecoms Source: Authors’ compilation, based on NKRA 2013 and data received from TANESCO (January 9, 2015). Note: 210 MW OCGT cited in NKRA 2013, revised to 308 MW (2015); 210 MW is for OCGT to operate for two years, thereafter expanded to CCGT. CCGT = combined-cycle gas turbine; ETG = Export Trading Group; GoT = Government of Tanzania; IFC = International Finance Corporation; IPP = independent power plant; MW = megawatt; OCGT = open-cycle gas turbine; PPP = public-private partnership; TANESCO = Tanzania Electric Supply Company. dominated by TANESCO in the near term, funding is supplemented notably by the Chinese (as discussed in greater detail below) and IPPs including local IPP sponsors. The tariff for each of these projects has yet to be announced. For Kinyerezi I and II, which are financed directly by the government, the government has to determine whether there will be on-lending or equity shares provided to TANESCO. Kinyerezi III and IV, which are PPPs, are still in negotiations and the tariff remains undecided. It has been indicated that for gas-fired plants the total unit cost should not exceed $0.08/kWh; however, this is highly dependent on gas prices and still does not reflect the critical capital component, which calls into question the true efficacy of the publicly procured plant. It is important to note that as of 2015, Kinyerezi II, III, and IV had encoun- tered delays. The following issues have been cited as impediments: a lack of seri- ous developers, a lack of funding potential, a lack of credit enhancement mechanisms, the viability of the power off-taker (TANESCO), and the availabil- ity of certain types of fuel. There is a direct connection between the near-term projects planned by the government and the phasing out of the EPPs. According to TANESCO officials, “there will be no more EPPs” (TANESCO, personal communication, November 19, 2014). Instead, the use of TANESCO’s hydropower plants, Mwanza 60 HFO, and IPTL will fill the gap before the new TANESCO plants come online. But the EPPs are not being fully retired as predicted, and Symbion is still in flux. Parallel to this expansion, the goal (at least on the books) is to achieve retail competition and the privatization of TANESCO. The year 2024 has been identi- fied for preparing generation and distribution companies for listing and privati- zation. Thus, state ownership will probably continue in the near term (albeit with a larger portion of supplementary funding), but in the longer term a Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 214 Case Study 4: Power Generation Results Now, Tanzania! phasing out of direct public ownership and asset funding is anticipated. Nonetheless, there seems to be a real disconnect between plans and action, and the necessary buy-in to realize the plans. Further Gas Sector and Power Developments: The Government Looks East In the meantime, the availability (or not) of domestic natural gas continues to play a pivotal role in determining outcomes in the power sector. The government sought private participation in the development of the Mnazi field for over six years. However, no viable interest was found, due in part to a low level of proven reserves in the field and a limited investment-enabling environment. Meanwhile the Songo Songo fields were slated for expansion by the private sector to meet the near-term needs of the country’s gas supply, approximately 50 million standard cubic feet per day (mmscfd) of gas to power 250–300 MW (single cycle). A deal was negotiated with PAT, the existing developer, for a gas infrastructure expansion in 2011 (which had a tariff approved by EWURA; a signed engineering, procurement, construction [EPC] contract; and financing arranged). On the cusp of the Songo Songo expansion, Tanzania engaged China to help fund natural gas infrastructure connecting Mnazi Bay and Songo Songo to Dar es Salaam, also known as the National Natural Gas Infrastructure Project (NNGIP). As a result, the government put the Songo Songo expansion on hold and focused on the development of the Mnazi field, which was reconfigured from a private infrastructure project to one led by the public sector. Gas deliveries from Songo Songo were estimated to be able to feed (and had been earmarked for) near-term power generation, even as the government sought longer-term gas supply. This shift, from near-term Songas expansion to the long-term NNGIP, exacerbated a gap that was plugged in part by the continued use of EPPs. Thus, the conse- quences of this policy decision are far-reaching. The NNGIP, which includes a 532 km natural gas pipeline from Mtwara to Dar es Salaam and gas-processing plants, was completed in 2015 and should be sufficient to run all the plants in an ideal scenario. Despite its mega capacity of 784 mmscfd (1,002 mmscfd compressed), the Mtwara-Dar pipeline ini- tially had only about 80 mmscfd of gas entering it from Mnazi Bay for a limited period of time, about enough to run 350–450 MW (that is, slightly ­ more than what the Songo Songo expansion could have provided for near-term ­developments).30 Most of the gas is expected to be consumed by the existing gas turbine plants (including Kinyerezi I, TANESCO’s Jacobsen 120 MW at Ubungo, Siemens gas turbines, and the extended Symbion 40–120 MW, LM6000s and TM2500s). The following questions arise: Is large infrastructure such as the NNGIP needed? Is there enough gas to flow into the pipeline to start with? Most likely not. Tanzania has an impending need for more gas to fuel new projects (Kinyerezi II–IV, Mtwara 400 MW, and so on), but that has proven to be a challenge to date. For example, there is a long-running dispute between PAT and the TPDC at Songo Songo related to cost-recovery and their existing Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 215 production-sharing agreement. TANESCO also owed PAT approximately $60 million as of 2Q2016, which prevented it from undertaking further investment in gas development. In recent months, progress has been made (although not yet finalized) on a new gas contract between the parties, and the plan is to expand production from Songo Songo by approximately 100 mmscfd, which could be sufficient to supply around 400 MW of open- cycle gas turbine (OCGT) capacity or 50 percent more if configured for the combined cycle. It is envisaged that the existing Songo Songo gas infrastructure can accom- modate 70 mmscfd in total (it is currently processing approximately 91 mmscfd but will revert back to its design capacity of 70 mmscfd). Any additional volumes beyond this will utilize the NNGIP. Considering that PAT has not yet com- menced this new drilling, it was anticipated that these volumes would not be in place before 2Q2016. Also, the significant offshore gas discoveries (of up to 55 Tcf of gas initially in place, GIIP) are promising, but unlikely to be delivered onshore and available for power generation before 2022–24.31 Regardless, the offshore gas is spread out along the coast and is unlikely to be landed in Mnazi Bay. A proposed LNG terminal will be built farther north, so the NNGIP pipe- line may not readily serve the offshore gas without further modifications. Thus, there is a real possibility that gas supply in the medium term will be insufficient to justify an investment such as the NNGIP. To compound the problem, it should be noted that EWURA played no part in the NNGIP ­ despite it being the largest energy infrastructure project undertaken in the country to date. The project was carried out on an emergency basis, and EWURA was only asked to approve a tariff when construction was nearly completed. The China ExIm loan facility of $2.2 billion was premised on a cost ­ of $3.00 per million British thermal units (MMBtu); however, ultimately, EWURA approved a tariff of $2.14/MMBtu (for gas processing and transporta- tion), and the shortfall of $0.86 was to be made up by the government. By comparison, Songas’s ­gas-processing and transportation tariff is $0.59/MMBtu.32 Although the pipeline is now almost complete, gas off-take agreements and power plan investments are still to be finalized. This is not a minor point, given the burgeoning gas sector. Parliament has only recently enacted the corresponding Petroleum Upstream, Midstream, and Downstream Act, which mandates a similar vetting process for the gas sector. Legislation was initiated in 2008, but the act was withheld by the Chief Draftsman’s Office, and finally passed on July 5, 2015. The act establishes the Petroleum Upstream Regulatory Authority (PURA), which is to regulate upstream gas and also lay out how competitive bidding is to be carried out. On paper, this looks positive, but the question is whether the laws will be sufficiently enforced to help Tanzania avoid the nontransparent deals of the past. Furthermore, it is anticipated that it will take an additional three years for all subsidiary legisla- tion to be designed, drafted, and enacted. This is more of a concern given the increasing and changing involvement of new financiers, notably China, in the sector. To date, Chinese capital has not been Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 216 Case Study 4: Power Generation Results Now, Tanzania! directly involved in financing power projects in Tanzania. That may soon change. Two of the PPPs identified in the near term and noted earlier, Kinyerezi III and IV, have Chinese equity and debt;33 Chinese companies have also made major gas discoveries. The real question lies in how Chinese-funded projects will be vetted and regulated and whether the Gas Act will afford both the PURA and EWURA the necessary oversight. In the near term, among the greatest concerns is the ongoing imbalance of payments. There are presently two China ExIm loans (one with a grace period of seven years ending in June 2020 and another with a grace period of four years ending in June 2017). Since 2013, the government has been paying interest twice a year (July, January). This could last up until 2017, when midterm gas supplies are expected. For now, Tanzania potentially will have a costly gas storage facility in the form of a pipeline. Finally, industry stakeholders have voiced serious concern about the govern- ment’s lack of consultation, either with the general public or with businesses that will be directly affected by the Petroleum (Upstream, Midstream, and Downstream) Act, and anticipate that this failure to vet the act will impact adversely on invest- ment in the electricity sector. Conclusions BRN has set goals of achieving 10,000 MW of generation capacity by 2025, doubling access rates, increasing efficiency, boosting transparency and financial integrity, and privatizing generation and distribution assets. The plans are admi- rable and ambitious, but viewed in light of the recent past, it is uncertain whether the government has the requisite capacity to deliver on these objectives. It has repeatedly committed to reforms, but been slow to implement them and has wavered in its commitment to integrate private power sustainably and systematically. Generally, the sector has suffered from poor governance. Frequent turnover at the MEM has impeded consistent and robust decision making. Planning has become a political exercise; coordination, which is intricately linked to planning, has been poor; interagency fighting has been common; and communication among ministries, stakeholders, and donors has broken down, as during the nego- tiation of Songas and IPTL. Private power and its benefits are by no means a forgone conclusion in Tanzania. All new projects in recent years have been or are going to be built by TANESCO, regardless of its financial situation, thus crowding out private sector investment. The push to promote public sector projects is not only the result of vested interests, but also of a general bias against private sector participation that has at times informed decision making in Tanzania. The issues at stake go beyond the question of private vs. public sector involvement. A lack of competitive procurement and transparent contracting has ­ resulted in costly deals and disputed contracts, with large drains on time and resources lost. Although Songas and IPTL run on different fuels and are not Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 217 exactly comparable, Songas is clearly the least-cost privately owned supply option in Tanzania; IPTL is the most expensive. IPTL power costs six times more than Songas’s power and just a little less than the EPPs’ power. Beyond technical considerations, it is apparent that such a large price difference between the two is also due to a lack of competition and the disputes that have affected IPTL procurement. Symbion is another powerful example of a deal initially contracted in a nontransparent manner, with costly and disruptive outcomes, which may only now potentially be mitigated by EWURA oversight. EWURA has been given the mandate to reject unsolicited proposals, like IPTL, that are not within the Power Sector Master Plan and are not financially viable. However, negotiated deals persist, and noncompetitive procurement remains the preferred method at the governing level. Incoherent planning, interagency disagreements, vested interests, and non- competitive practices have unraveled contracts and impeded the timely procure- ment of generation. As a result, the country has been forced to depend on EPPs and expensive oil-fired generation over the past several years. The supply of natural gas, which is directly tied to electric power development, looks to be a positive story, though not without uncertainties. Delays in agree- ments with the private sector may mean that plans materialize only from 2022. Delays in expanding the gas supply have already resulted in costly contingency plans such as EPPs, which in turn have bankrupted TANESCO. Should PAT not conclude its second gas supply agreement with the TPDC in a timely manner and offshore gas be delayed, this could impact the rollout of plants adversely. Gas com- ing from Mnazi Bay will provide fuel in the short term, but it is critical that more sources be secured. And although EPPs were to be phased out, one has been retained in the short term to make up for delays in gas arriving in Dar es Salaam. Also, the delay of the Petroleum (Upstream, Midstream, and Downstream) Act, passed in July 2015, left the gas sector with no consistent regulation for seven years. The engagement of Chinese funding ushers in a new wave of development. To address these challenges, private and public stakeholders alike have called for a commitment to improve governance across Tanzania’s gas and power sec- tors in three main focus areas. First is to improve planning and processes to ensure that plans feed through to decision making. Such improvements need to be institutionalized, and the ­ selection of projects be removed from political appointees’ and senior bureau- crats’ hands. A clear, dynamic, and realistic vision for the future structure of the sector is in order. This would include a sustained commitment to addressing the dire financial condition of TANESCO to ensure a solvent off-taker. Second, is to improve the procurement and contract negotiating processes carried out by the relevant government and parastatal stakeholders. Developers have reported that negotiating processes are ineffective and cumbersome, which has often led to extensive delays or potential projects being abandoned. Clear, trans- parent processes and accountability for contracting with IPPs and engaging with any public funds (including that of China ExIm) need to be prioritized. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 218 Case Study 4: Power Generation Results Now, Tanzania! Third, it is necessary for the government to reestablish its commitment to ­ontracting with IPPs. Of late, most new power projects are being built as c TANESCO-owned plants; this puts the government’s commitment to attracting private capital into doubt, despite repeated statements to the contrary. It is to be hoped that a secure gas supply will be established, putting an end to Tanzania’s costly dependence on imported fuel. Private power has, largely through Songas, helped benchmark the state-owned utility, raised the bar, and provided critical new generation. Other projects, such as IPTL and the EPPs, have proven to be costly experiments, primarily due to planning and procure- ment failures. Tanzania deserves a new decade of private and public project ­ successes, which are within reach of a united approach. Annex 9A  Cost Comparison, TANESCO and Independent Power Projects Dividing the total cost in table 9A.1 by the Tanzania Electric Supply Company’s (TANESCO’s) units generated in 2013—namely, 3,109,117,152 kilowatt-hours (kWh)—comes to $0.10/kWh (with an associated off-grid cost of $0.328, albeit representing only 5 percent of the total generation). Thus, TANESCO’s total own-generation grid per unit costs, excluding capital costs, are approximately 60 percent of the average end-user tariff, that is, before adding the requisite transmission and distribution (T&D) costs. For Songas, the average 2013 monthly figure, including both variable and capacity charges, was equivalent to $5.49 million (excluding value added tax [VAT], which is not a cost to TANESCO, and the disputed loan amount).34 Divided by the average monthly generation of 110,133,333 kWh, the per kilowatt-hour all-inclusive charge comes to approximately $0.0498. The average ­ variable charge amounts to a fraction of this total cost, namely U.S. cents (USc) 1.2–1.3/kWh (billed in Tanzania shillings, T Sh).35 Independent Power Tanzania Ltd. (IPTL) trails the emergency power proj- ects (EPPs) in terms of kilowatt-hours contributed, but it resembles Songas in Table 9A.1  TANESCO’s Own-Generation Costs: Tanzania, 2013 TANESCO Cost (US$, millions) Fuel and oil 287.60 Natural gas purchase 59.78 Plant maintenance 6.33 Staff costs 12.15 Other administrative costs 6.04 Minus off-grid –58.85 Total 313.06 Source: Authors’ compilation, based on correspondence with TANESCO stakeholders (2014). Note: TANESCO = Tanzania Electric Supply Company. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 219 its cost structure, as a traditional independent power project (IPP), and therefore is highlighted here. Capacity charges averaged $0.08/kWh in 2013, ­ almost double Songas’s total cost. Of the remaining $0.23 in charges for IPTL, $0.22 is accounted for by the fuel (variable charge); thus the overwhelming cost of IPPs remains the fuel. Annex 9B  IPTL and Songas Project Costs, Tanzania Table 9B.1  IPTL Project Costs, Tanzania IPTL Project cost (US$, millions) Financing Projected total project cost 163.0 Actual total project cost (postarbitration) EPC contract 98.2 70% debt (at 8.5%) 30% equity Construction contingency 4.9 Land 1.0 Insurance 4.1 Advisers (lenders, project) 3.0 Working capital 1.7 Fuel oil reserve 3.2 Interest during construction 4.6 Financing and agency fees 1.9 Miscellaneousa 4.6 Total project costs for diesel 127.2 Conversion to natural gas Estimate of ICSID 11.6 2005 estimation of Wartsila 20.0 TANESCO Total project costs (postconversion) 147.2 Sources: ICSID, MEM, TANESCO. Note: EPC = engineering, procurement, and construction; ICSID = International Centre for Settlement of Investment Disputes; IPTL = Independent Power Tanzania Ltd.; MEM = Ministry of Energy and Minerals; TANESCO = Tanzania Electric Supply Company. a. Miscellaneous includes funds termed “development,”“mobilization,” and “commitment” fees. Table 9B.2  Songas Project Costs, Tanzania Project costs Songas (US$, millions) Financing Initial Songas costs Gas processing and pipeline 100 70% debt (on-lent by 30% equity GoT at 7.1%) Assumed loans for turbines 1–4 45 (106 MW) Work done on wells 25 Overhaul/refurbishment and 35 conversion of turbines 1–4 Balance of plant costsa 61 Total for 106 MW project, delivered 266 July 2004 table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 220 Case Study 4: Power Generation Results Now, Tanzania! Table 9B.2  Songas Project Costs, Tanzania (continued) Project costs Songas (US$, millions) Financing Songas expansion Turbine 5 (35 MW) 7.1 100% equity (Globeleq) Turbine 6 (40 MW) 14 Balance of plant costs for expansion 28.9 Total for 75 MW expansion 50 (revised down to $45 million) Total on which (2005/present) capacity 316 charges calculated Additional Songas costs incurred by GoT Drilling of original wells 100 Sunk cost, GoT (concessionary loans 1970s) AFUDC 103 Treasury (40%), TANESCO (10%), escrow (50%) Escrow account 50 Surcharge on fuel (used to pay down AFUDC), presently now only $2.5 million Liquidity facility of 4 months’ capacity 16.8 Interest on the escrow on 106 MW Total additional costs 220 Does not include escrow since used to pay down AFUDC Total project costs 536 Sources: World Bank Project Appraisal Document (http://www.globalclearinghouse.org/infradev/assets%5C10/documents​ Tanzania%20-%20Songo%20Songo%20PAD%20-%20WB%20(2001).pdf ), Songas personal interviews, TANESCO, MEM. /­ Note: AFUDC = allowance for funds used during construction; CDC = Commonwealth Development Corporation; EIB = European Investment Bank; FMO = Netherlands Development Finance Company; GoT = Government of Tanzania; IDA = International Development Association; IPTL = Independent Power Tanzania Ltd.; MEM = Ministry of Energy and Minerals; MW = megawatt; Sida = Swedish International Development Cooperation Agency; TANESCO = Tanzania Electric Supply Company; TDFL = Tanzania Development Finance Company Limited; TPDC = Tanzania Petroleum Development Corporation. a. Songas equity: total equity for original scope is $60 million—Globeleq ($33.8 million), FMO ($14.6 million), TDFL ($4 million), CDC ($3.6 million), TPDC ($3 million in kind), and TANESCO ($1 million in kind). Songas debt: total debt is $206 million—IDA ($136 million), EIB ($55 million), Sida ($15 million). In reference to the IDA loan, $108 million was sourced from the World Bank Credit 3569-TA. In addition, the old loans from previous credits and grants include $22 million (salvage value) for UGT3 and UGT4 LM600 GE turbines installed at Ubungo in 1995; and $8 million paid out of the Sixth Power Project for the working over of Songo Songo wells in 1996–97. Sida contributed a grant to the government of Tanzania, but the loan to Songas was the equivalent to $15 million (salvage value) for UGT1 and UGT2 ABB GT10A in 1994. Balance of plant costs refers to refurbishment of the plant, building of a warehouse, as well as soft costs, for example, project management, build-up of operation and maintenance, and refinancing of turbines 5 and 6 completed in 2009. Annex 9C  ICSID Tribunal, IPTL The case brought before the tribunal of the International Centre for Settlement of Investment Disputes (ICSID) involved several phases. In the first phase, the Tanzania Electric Supply Company (TANESCO) attempted to rescind the power purchase agreement (PPA) on the basis of technical issues (namely that medium-speed engines were substituted for slow-speed engines). In April 2000, in the midst of first phase proceedings, TANESCO additionally requested the tribunal to hear corruption charges. The request was refused, as no allegations of bribery had been formally pleaded. In May 2000, the tribunal ruled against rescinding the PPA, but stipulated that the capacity payment be lowered to match actual construction costs. Following the initial ruling, in what may be Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 221 termed a second phase, TANESCO made additional efforts to rescind the PPA, this time formally raising bribery charges through an ancillary claim. Sworn state- ments were provided by the permanent secretary of the Ministry of Energy and Minerals (MEM), assistant commissioner for energy (petroleum and gas), and assistant commissioner for energy (electricity). In June, the tribunal ruled that TANESCO could pursue bribery charges, but only within the existing time frame of the final hearing (that is, in one month’s time). The tribunal ordered both parties to produce any documents in relation to the charges. The tribunal did not allow wide-ranging interrogations or include a forum to require parties to answer specific questions on bribery allegations. By July 2000, TANESCO produced some documents to the tribunal but requested an extension of three months as it had not yet completed its brib- ery investigation. The tribunal disallowed any such extension, but proposed that TANESCO withdraw the bribery charges with the option of raising them later in separate ancillary proceedings after completing its investigation, which the utility never pursued. The tribunal ultimately ruled that: (1) alle- gations of bribery had failed based on the information presented, (2) capacity charges should be reduced based on actual and reasonable costs incurred, and (3) there had been no breach in the fuel supply, as alleged by TANESCO. The final award, made in May 2001, upheld the PPA signed in 1995, adjusted the capacity charge to $2.6 million per month, and indicated that conversion to natural gas would be as per the original PPA—with the costs of conversion paid by TANESCO (with a benchmark of $11.6 million set) and work to be carried out by Wartsila. Annex 9D Production-Sharing Agreement, TPDC and PanAfrican Energy Under the production-sharing agreement (PSA) between the Tanzania Petroleum Development Corporation (TPDC) and PanAfrican Energy Tanzania Limited (PAT), profits are shared on production with respect to “additional gas” only. Additional gas is defined as all gas other than that “protected gas” designated for Table 9D.1  PSAs between the TPDC and PanAfrican Energy Tanzania Limited Share of proven section profit gas revenues (%) Average daily sales (mmscfd) TPDC PanAfrican Energy Tanzania Limited 0–20 75 25 >20 ≤ 30 70 30 >30 ≤ 40 65 35 >40 ≤ 50 60 40 >50 45 55 Source: Orca Exploration 2007: 9. Note: mmscfd = million standard cubic feet per day; PSA = production-sharing agreement; TPDC = Tanzania Petroleum Development Corporation. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 222 Case Study 4: Power Generation Results Now, Tanzania! Ubungo turbines I–V (150 megawatts, MW), plus the cement factory for the 20-year power purchase agreement (PPA). Profit sharing for gas in the as-of-yet unproven section of Songo Songo, will, regardless of average daily sales, be divided on the following terms: TPDC, 45 percent; PanAfrican (EastCoast Energy), 55 percent. Notes 1. A considerable amount of information for this case study was collected directly from private and public sector stakeholders who requested anonymity, including, at times, regarding their organizational affiliation. Efforts are made to identify the date when information was collected by way of personal communication. Generation is the primary focus of this case study; it is, however, worth noting that as of 2014, 32 percent of the population had access to electricity (a low rate, but on par with the Sub-Saharan African average of 35 percent, notably the lowest among developing regions in the world) (TANESCO, personal communication, January 15, 2015). The connection rate, meanwhile, is 24 percent for the population (MEM 2014: 2). Under the program “Big Results Now” access rates are projected to double in a decade, along with efficiency, transparency, and financial integrity (MEM 2014: 49). 2. This section is based on “Chapter 2: Tanzania: Learning the Hard Way” (Kapika and Eberhard 2013: 53–58). The author is collaborating with Anton Eberhard, who has given permission to draw freely on relevant material. 3. Tanzania’s BRN plan took its cue from Malaysia (as well as Thailand and Vietnam, whose economic development levels in the 1960s were akin to Tanzania’s now, before implementing similar programs). 4. Further targets are spelled out for access to electricity and the sector’s financial sustainability. 5. Average exchange rate for 2013: $1 = T Sh 1,584.05 (Oanda historical exchange rates, http://www.oanda.com/currency/historical-rates/, accessed December 19, 2014). Thus, the net loss in 2013 was $295 million (up from $112 million in 2012). Meanwhile, accumulated losses as of 2013 stood at $915 million (up from $620 ­ million in 2012). According to the Energy and Water Utilities Regulatory Authority, the audited accounts supersede the Development Policy Operation losses. 6. Songas, which will be described in detail shortly, is part of the Songo Songo gas-to- electricity project, a $316 million project that encompasses the Songas power plant in Dar es Salaam, a natural-gas-processing plant on Songo Songo Island, a 225-kilometer (km) pipeline from the island to Dar es Salaam, and rights to two onshore and three offshore natural gas wells at Songo Songo Island. The gas-processing plant and pipe- lines were built and are owned by Songas Ltd., a local joint venture company which, following a number of transactions, was formed by the power company, the Commonwealth Development Corporation/Globeleq, TANESCO, the Tanzania Petroleum Development Corporation, and the Tanzania Development Finance Co. Ltd. Globeleq has the controlling interest in the project, including the electric power project (which was expanded by the consortium), and the wells are operated by PanAfrican Energy Tanzania Ltd., a local subsidiary of Orca Exploration Group Inc. Construction of the pipeline network was completed in May 2004, and the project started commercial operation in July 2004. The network transports natural gas to Dar es Salaam, where, apart from the Songas power plant, it is used as the principal Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 223 fuel for turbine generators at TANESCO’s Ubungo I and II power plants (102 and 105 MW, respectively), as well as its 45 MW Tegeta plant. Other outlets for the gas include the Twiga Cement Factory (Wazo Hill) and an electrification project that generates electricity for villages along the pipeline route. 7. While TANESCO remains the dominant player, Songas supplies between 20 and 25 percent of grid electricity, as seen in the next section. 8. The Songo Songo gas-to-electricity project was initially supposed to be expanded in 2006–07 but was delayed following disagreements on gas pricing. The main expan- sion—adding new gas-processing trains and pipeline compression—was planned to commence operations in late 2012, but development effectively stopped in 2011. There was a tariff order in April of that year, when the government started developing the National Natural Gas Infrastructure Project, as described in detail later in this chapter. The supply gap was plugged during the term with costly liquid-fueled ­ emergency power plants. 9. The mandate for these regulations was given in Clause 5 of the Electricity Act (2008): “The Authority shall have powers to: (i) award licenses to entities under- taking or seeking to undertake a licensed activity; (ii) approve and enforce tariffs and fees charged by licensees; (iii) approve licensees’ terms and conditions of electricity supply; and (iv) approve initiation of the procurement of new electric- ity supply installations.” 10. According to the resource classification standards employed in the petroleum industry, the term “reserves” refers to those volumes of gas that are commercially ­ recoverable from known accumulations (SPE 2011). While not all announced reserve figures adhere to this strict definition, the commerciality tests for gas reserves nor- mally require the existence of an established market, available infrastructure, and an approved field development plan. The term “proved reserves” refers to those reserves that are reasonably certain to be recovered, and “probable reserves” denotes gas vol- umes that are more likely than not to be recovered. The sum of proved and probable reserves, denoted as 2P reserves, is often considered a “best guess” estimate of ultimate recovery from commercial fields. 11. Based on the average 2012 exchange rate of $1 = T Sh 1,562.41. 12. Annex 9A provides details on how each price was derived by the author. 13. If the capacity charge component of a plant’s tariff is U.S. cents (USc) 4/kilowatt- hour (kWh) at 90 percent plant load factor (PLF), it would be USc 24/kWh at 15 percent PLF; that is, the differences in headline tariff arising from the PLF may be substantial. 14. Songo Songo 1 (SS1) was drilled and funded by the Azienda Generale Italiana Petroli (AGIP), which had a production-sharing agreement with the government of Tanzania; SS2, SS3, and SS4 were drilled by the Tanzania Petroleum Development Corporation (TPDC) using financial and technical assistance from the government of India; the rest of the wells (SS5, SS6, SS7, SS8, SS9) were drilled in the 1980s by the TPDC. 15. The following overview is based in part on “Generating Power and Controversy: Understanding Tanzania’s Independent Power Projects” (Gratwick, Ghanadan, and Eberhard 2006: 39–56), which provides a detailed account of the development of both Songas and Independent Power Tanzania Ltd.’s (IPTL’s) independent power projects (IPPs). 16. Ocelot, the initial investor in the Songo Songo gas-to-electricity project, was replaced by its subsidiary company, Pan Ocean. Pan Ocean sold its shares in the power project Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 224 Case Study 4: Power Generation Results Now, Tanzania! in 2001 to AES, the American power development company, to concentrate exclu- sively on gas development. In 2004, Pan Ocean spun off its interest in Songo Songo to a separate company, EastCoast Energy, which in April 2007 changed its name to Orca Exploration, but operates under the name PanAfrican Energy Tanzania Limited (PAT). 17. Export of gas and electricity from Tanzania to Kenya was recommended by Hardy BBT Limited; the Songo Songo gas development project (gas for domestic use) was recommended by the National Economic Research Associates, based in the United States. 18. The turbines were a conditional grant to the government of Tanzania, but a loan to TANESCO and whoever inherited or bought the units. The book value of these two turbines amounted to $15 million on the transfer date (August 31, 2004). 19. The World Bank involvement at the time included the Power VI Programme, a $200 million loan to help rehabilitate the Tanzanian electric supply industry under which the Kihansi hydropower station of 180 MW would eventually be developed (it was initially planned for 1995 but came online only in 2000). A key provision of this program was that the World Bank had to be informed of any new investments in the power sector greater than $5 million—a less stringent condition than that spelled out in the Songas loan agreement, which required World Bank approval. The rationale behind this policy, which applies generally to the countries eligible for International Development Association assistance, was to ensure coordination with the World Bank, one of the largest lenders to the sector. 20. This electric power component of the project concept would evolve significantly over the decade 1993–2003, from 60 MW to 151 MW. It was then scaled back to 106 MW before eventually increasing to the present 189 MW. The present scope, including gas infrastructure, is outlined in note 6. 21. Enron put up a proposal but did not submit it in July 1993 (due to a court injunction against the firm). Only two proposals were received—one from the joint venture of Ocelot Energy Inc. and TransCanada Pipelines Limited, and the other from Andrade Gutierrez. The latter had experience in only road infrastructure construction and lacked petroleum exploration skills. Thus, during the clarification period (and after Enron was cleared by a court of law), Andrade Gutierrez and Enron formed a joint venture and resubmitted their proposal (in the form of a clarification addendum) in November 1993 before negotiations started. 22. Due to sensitivities, stakeholder names and organizations have been withheld from this reference. See the first endnote in this case study. Apart from the arbitration pro- ceedings, discussed later, in which corruption figured prominently, an investigation was also conducted to document the corruption, but charges were never brought by the government of Tanzania. Certain stakeholders indicated that the failure to bring charges was due to the fact that “too many were implicated”; others said that “the investigation itself was flawed”; and still others noted that it was “in the best interest of the country not to pursue” the investigation. 23. Annex 9B provides information on the total cost for IPTL and the Songo Songo gas- to-power project. 24. IPTL contends that it briefed TANESCO on the substitution well in advance and that it was designed to enhance the maintenance of the plant. 25. Annex 9C provides additional details on the ICSID tribunal. million; 26. As referenced in table 9B.2 in annex 9B of this chapter, Songas’s debt was $206 ­ IDA, $136 million; EIB, $55 million; and Sida, $15 million. In reference to the IDA Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 4: Power Generation Results Now, Tanzania! 225 loan, $108 million was sourced from the World Bank Credit 3569-TA. In addition, old loans from p­ revious credit lines and grants included $22 million (salvage value) for UGT3 and UGT4 LM600 GE turbines installed at Ubungo in 1995; and $8 million paid out of the Sixth Power Project for Songo Songo well work-overs in 1996–97. Sida contributed a grant to the government, which was loaned to Songas, and equiva- lent to $15 million (salvage value) for UGT1 and UGT2 ABB GT10A in 1994. 27. AES’s exit from the project was a product of the global downturn in the private power sector and foreign direct investment in general, caused by the Asian and subsequent scandal—with Latin American financial crises, the aftershocks of 9/11, and the Enron ­ which AES was closely associated by the mere fact that it was an American power company. AES also lost significant amounts of money on its investments in imploding markets in South America. With a plummeting stock price, AES was pressed to sell assets, among them Songas. As referenced in table 9B.2 in annex 9B of this chapter, after the AES sale, equity shares and associated financial commitments (expressed in $ million) in Songas were as follows: Globeleq: $33.8 (56 percent); the Dutch devel- opment bank (FMO): $14.6 (24 percent); TDFL: $4 (7 percent); CDC: $3.6 (6 per- cent); TPDC: $3 (5 percent); and TANESCO: $1 (2 percent). This does not reflect the additional $45 million that Globeleq committed to expand the power plant, which was subsequently refinanced in 2009. 28. Sponsors required an offshore escrow facility to cover 100 percent of target equity contributions ahead of the transfer date (July 31, 2001), as an exit strategy if nation- alization occurred prior to the construction completion date. The amount in the escrow account was to be reduced to 50 percent on the third anniversary of the trans- fer date (August 1, 2007) and zero on the sixth anniversary (October 2010). The escrow was to be raised through a surcharge on fuel. 29. In 2008 this conversion cost was pegged at $20 million. By 2014 there was no cost estimate available and no date set for conversion (TANESCO, personal ­communication, November 2014). 30. While it is anticipated that more reserves may be proven and supplies increased, presently that is not part of the gas contract. ­ 31. The schedule for long-term gas in Mozambique, which is widely regarded as ahead of Tanzania, would suggest that long-term gas for Tanzania is likely to come after 2022. 32. It should be noted that this tariff of $0.59 is levied only on certain third-party gas that is processed and transported by Songas and is not based on the underlying capital base of the gas infrastructure. 33. Singida 50 IPP would also avail Chinese funding via TANESCO’s equity portion. 34. The disputed loan amount, described below, effectively gets absorbed by the govern- ment and serves as a subsidy to TANESCO. TANESCO does not pay the full charge of Songas’s power, which amounted to U.S. cents (USc) 6.79/kilowatt-hour (kWh) in 2013 (and USc 6.28/kWh in 2014). In turn Songas is unable to repay its government loan (which relates to funds on lent from the concessionary World Bank and EIB funds received by the government of Tanzania). Both parties are thus absolved, with the liability remaining with the government. This arrangement has been in place for the past 10 years. 35. Information in this paragraph and the paragraph below it is based on personal communication with TANESCO and Songas through 2014 and 1Q2015, various dates. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 226 Case Study 4: Power Generation Results Now, Tanzania! References Ghanadan, R., and A. Eberhard. 2007. “Electricity Utility Management Contracts in Africa: Lessons and Experience from the TANESCO-NETGroup Solutions Management Contract in Tanzania, 2002–2006.” MIR Working Paper, Management Programme for Infrastructure Reform and Regulation, Cape Town. Gratwick, K., R. Ghanadan, and A. Eberhard. 2006. “Generating Power and Controversy: Understanding Tanzania’s Independent Power Projects.” Journal of Energy in Southern Africa 17 (4). Cape Town: Energy Research Centre. Kapika, J., and A. Eberhard. 2013. Power-Sector Reform and Regulation in Africa: Lessons from Kenya, Tanzania, Uganda, Zambia, Namibia, and Ghana. Cape Town: Human Sciences Research Council Press. MEM (Ministry of Energy and Minerals). 2011. “Joint Energy Sector Review for 2010/2011.” MEM, Dar es Salaam. ———. 2013. “Joint Energy Sector Review (JESR) 2012/13 for Tanzania.” MEM, Dar es Salaam. ———. 2014. “Electricity Supply Industry Reform Strategy and Roadmap 2014–2015.” MEM, Dar es Salaam. Ng’wanakilala, F. 2014. “Tanzania to Pick Winners of Oil, Gas Bids before Year-End.” Reuters, October 17. http://www.reuters.com/article/2014/10/17/tanzania-gas​ -idUSL6N0SC2RS20141017. Accessed April 22, 2015. NKRA Energy (National Key Result Area). 2013. Energy Lab Final Report. Dar es Salaam: NKRA. Orca Exploration. 2007. “Q1 Interim Report.” Orca Exploration, Calgary. Santley, D., R. Schlotterer, and A. Eberhard. 2014. Harnessing African Natural Gas: A New Opportunity for Africa’s Energy Agenda? Washington, DC: World Bank. SPE (Society of Petroleum Engineers). 2011. “Guidelines for Application of the Petroleum Resources Management System.” http://www.spe.org/industry/reserves.php#redirected​ _from=/industry/reserves/. Accessed April 22, 2015. United Republic of Tanzania Audit Office. 2013. Report of the Controller and Auditor General on the Financial Statements of TANESCO for the Year Ended 31 December. Dar es Salaam: United Republic of Tanzania Audit Office. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 C h apter 1 0 Case Study 5: Power Generation Developments in Uganda Introduction Uganda occupies a unique space in the history of power sector reform and investment in Africa. It was the first country to unbundle generation, trans­ mission, and distribution into separate utilities and to offer separate, private concessions for power generation and distribution. Critics said that Uganda’s power system was too small to reap the possible benefits that might flow from competition in generation, and more focused management of transmission and distribution (T&D). The years that immediately followed the reforms seemed to bear out the critics’ views: the private distribution operator struggled to reduce losses, and there were delays in investments in large new hydropower capacity, resulting in costly dependence on short-term thermal power. Despite ongoing challenges, Uganda’s power sector reforms are now bearing fruit. The performance of the distribution utility has improved. Losses are down, and collections, investment, and connections are up, although access rates remain low. After a torturous start, Uganda concluded the largest private hydropower investment in Africa, the Bujagali plant, built by an independent power project (IPP). Simultaneously, it has attracted a raft of smaller IPP investments, including the innovative competitive bids for small hydropower, biomass, and solar projects solicited under the global energy transfer feed-in tariff (GETFiT) program, which was developed jointly by Uganda’s Electricity Regulatory Authority (ERA) and the Kreditanstalt für Wiederaufbau (KfW, German Development Bank). After South Africa, Uganda has the largest number of IPPs in Sub-Saharan Africa and the only other competitively bid grid-connected solar photovoltaic (PV) program. Alongside these IPP successes, Uganda has now embarked on two large Chinese- funded hydropower projects. Private investment in power is still politically contested, and IPPs are seen locally to be potentially expensive, complex, and time-consuming. Uganda thus offers much pertinent experience and many valuable lessons in power sector reform, private sector participation, IPPs, competitive bidding, grid-connected renewable energy, and Chinese-supported projects. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   227   228 Case Study 5: Power Generation Developments in Uganda The History and Structure of Uganda’s Electricity Sector The structure and regulatory setup of Uganda’s electricity sector are among the most advanced in Sub-Saharan Africa.1 The sector as it stands today is the result of an ambitious reform process begun in the late 1990s and completed in ­ mid-2000. The structure of the Uganda electricity sector is shown in figure 10.1. The sector’s main institutions are profiled in box 10.1. History of Power Sector Reform Before the reform, continuous mismanagement and underperformance of the vertically integrated utility, the Uganda Electricity Board (UEB), had resulted in an underfinanced sector, worn-out infrastructure, and poor service.2 The objec- tives of a 1998 strategic plan3 that evolved into the 1999 Electricity Act were fourfold: (1) to improve overall sectoral performance; (2) to enhance both the Figure 10.1  Structure of Uganda’s Power Sector Ministry of Energy and Mineral Development (MEMD) Rural GoU agency Electricity Electrification Disputes Tribunal Agency (REA) • Appointment of board members Body of appeal • Partial funding Electricity Regulatory Authority (ERA) Regulatory oversight Regulatory oversight Regulatory oversight Generation Transmission Distribution Eskom Umeme Ltd. Uganda (UEDCL asset (UEGCL asset UETCL concessionaire) concessionaire) (fully state- owned) Small-scale Small-scale IPP IPP distributors distributors IPP IPP Isolated grid concessionaire Source: Compiled by the authors, based on various primary and secondary source data. Note: GoU = Government of Uganda; IPP = independent power project; UEDCL = Uganda Electricity Distribution Company Ltd.; UEGCL = Uganda Electricity Generation Company Ltd.; UETCL = Uganda Electricity Transmission Company Ltd. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 229 Box 10.1  Major Institutions in Uganda’s Power Sector Ministry of Energy and Mineral Development (MEMD). The MEMD is the focal point for energy policy matters within the Ugandan government. To meet its mandate of overseeing the power  sector, the MEMD aims to create an enabling environment for investment through modern policies and appropriate legislation and standards. For public or emergency power generation projects, the MEMD continues to act as a procurement entity, either in its own right or through the sector’s parastatals. Procurement for the ongoing Karuma and Isimba hydro- power projects is directly handled by the MEMD. In its 2014 Sector Performance Report, the  MEMD includes among its priorities (1) increasing electricity generation capacity and transmission networks, and (2) increasing access to modern energy services through rural electrification and renewable energy development. Electricity Regulatory Authority (ERA). ERA’s main responsibilities include the setting of cost- reflective electricity tariffs, which involves proposing and/or approving tariffs for generation, transmission, distribution, bulk supply, and system operation. ERA also defines and monitors technical standards within the sector and enforces adherence to the National Grid Code. It issues and monitors the licenses required to generate, transmit, and distribute power. ERA also sets and reviews renewable energy feed-in tariff (REFiT) levels for generation projects between 1 and 20 megawatts (MW). In its capacity as a tendering authority under Section 33 of the Electricity Act (1999), ERA has recently conducted the first competitive tender for 20 MW of on-grid solar concessions. Uganda Electricity Generation Company Ltd. (UEGCL). The UEGCL is the holding company for state-owned generation assets. Its two main roles are (1) to supervise and review the per- formance of the concessionaire, Eskom Uganda Ltd., which operates the Kiira and Nalubaale hydropower plants (HPPs), as well as the thermal-power plant at Namanve; and (2) to negoti- ate and administer contracts for engineering, procurement, and construction (EPC) and operation and maintenance (O&M) related to mid-tier public projects such as the recently ­ commenced Muzizi HPP and Nyagak III small hydropower (SHP) projects. Eskom Uganda Ltd. Eskom Uganda Ltd. is a subsidiary of South Africa’s utility giant Eskom Holdings SOC Ltd. In 2003, Eskom Uganda was awarded a 20-year concession for the O&M of the UEGCL’s generation assets in Jinja (Nalubaale, Kiira). Uganda Electricity Transmission Company Ltd. (UETCL). State-owned UETCL owns, operates, and plans Uganda’s medium- and high-voltage transmission infrastructure (>33 kilovolts, kV), procuring necessary equipment and facilities in its own name. It also functions as the system operator, bulk single buyer (and hence signatory of all power purchase agreements, PPAs), and dispatcher for almost all electricity generated in Uganda. (The electricity generated in isolated grids is excluded. Furthermore, the Electricity Act allows for direct sale from generators to small energy cooperatives.) Uganda Electricity Distribution Company Ltd. (UEDCL). The UEDCL, the holding company for  state-owned distribution assets, administers and supervisors the private distribution concession agreement (presently held by Umeme, discussed next). The UEDCL also operates a ­ small number of mini-grids. box continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 230 Case Study 5: Power Generation Developments in Uganda Box 10.1  Major Institutions in Uganda’s Power Sector (continued) Umeme Ltd. Umeme Ltd., the major privately owned electricity distributor in Uganda, won  the 20-year concession for operating the UEDCL’s main distribution network in 2005. Umeme Ltd. purchases electricity at a bulk tariff from the UETCL and sells it as a retailer to  roughly 575,000 customers. Industrial and government customers account for about 70 percent of the utility’s annual revenue. (The Ugandan government has accrued an account deficit of roughly $42 million, which has led Umeme Ltd., in line with the concession agree- ment, to withhold equivalent payments to the UETCL.) Source: Compiled by the authors, based on various primary and secondary source data. economic and environmental sustainability of the sector; (3) to foster energy security; and (4) to open the sector to private investment, especially in genera- tion and distribution. The National Energy Policy of 2002 reinforced these com- prehensive sector reforms and reemphasized the importance of attracting private investment into the Ugandan energy sector. Proposing measures to attract more private capital and international developers into the sector, the National Energy Policy called for using incentives such as loans on concessionary terms, govern- ment guarantees, and “smart subsidies” (grants) for power sector investments. The core reform and restructuring process initiated by the 1999 legislation lasted six years. Between 1999 and 2005, the UEB was unbundled into the ­ generation, transmission, and distribution companies known as the Uganda Electricity Generation Company Ltd. (UEGCL), Uganda Electricity Transmission Company Ltd. (UETCL), and Uganda Electricity Distribution Company Ltd. (UEDCL). The plan enshrined in the legislation also provided for some key early strategies for the expansion of all three subsectors, with varying degrees of private sector participation. The Ugandan government conducted international competi- tive tenders for the operation and maintenance (O&M) of generation plants and for the leasing of distribution assets. The tendering process resulted in the award of concessions to Eskom Uganda Ltd. in 2003 and to Umeme Ltd. in 2005.4 Through these concessions, the government increased the financing base for rehabilitation and incentivized good performance in accordance with private sec- tor benchmarks. The UETCL remained a publicly operated transmission utility but unraveled due to immediate governmental influence and was reorganized with an operationally independent board and a corporate management structure. Despite plans to privatize the UETCL, the government has so far refrained from doing so. Uganda has, meanwhile, maintained the single-buyer model, and the UETCL is still the sole off-taker of all electricity entering the main grid. The reform process was supported by a credit from the International Development Association (IDA) of the World Bank. The credit was extended under a program that promoted divestiture and restructuring of state-owned enterprises (SOEs), greater private sector participation, and strengthening of regulatory frameworks. A supplementary IDA contingent credit of $5.5 million Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 231 was made to support a liquidity facility for Umeme. The World Bank Group’s (WBG’s) Multilateral Investment Guarantee Agency (MIGA) extended insurance coverage for up to $45 million in equity and shareholder loans to cover transfer restrictions, expropriation, war and civil disturbances, and breach of contract. The IDA contingent credit acted as a guarantee, giving Umeme the right to be compensated for losses of revenue stemming from the following potential events: (1) failure by ERA to approve tariff adjustments according to the tariff methodology in the distribution and supply license; (2) nonpayment of power bills by governmental entities; (3) early termination of the concession by Umeme resulting from a breach of the privatization agreements by the national government or its entities during the first 18 months of the concession; (4) early termination of the concession by Umeme for reasons related to the company during the first 18 months (entitling Umeme to return of half its initial invest- ment of $5 million); (5) and refunds by Umeme of the concession fees and security deposits paid by customers of UEDCL before the transfer date; (6) ter- mination of the concession in the event of default or force majeure (including for political reasons) by the UEDCL or the government of Uganda. The IDA contingent credit was the first recorded instance of a development finance institution (DFI) covering regulatory risk. The security package consisted of the following support measures: (1) monthly lease rents, (2) an escrow account, (3) a letter of credit (LC) facility, and (4) an IDA contingent credit to backstop the latter. The LC facility and the IDA contin- gent credit were accessible to Umeme only for the first three events just listed and only after other mitigation measures (from monthly lease rents and the escrow account) were exhausted. Under the distribution concession, the concessionaire was contractually obligated to invest a minimum of $65 million by the end of the fifth year. With ­ that, the company was expected to provide up to 60,000 new connections, reduce total losses from 33 percent to 28 percent, and improve collection rates from 75 percent to 92.5 percent. An amendment to the distribution concession was signed in 2006.5 Umeme made progress in expanding connections and investment, but losses remained stub- bornly high, oscillating with no discernible pattern between 31 and 35 percent. In 2006, seven years after the start of the sector restructuring process, the ­ supply deficit was in the range of 90 to 210 megawatts (MW) (USAID 2013), entailing extensive load shedding. It had been envisaged that the 250 MW Bujagali hydropower plant (HPP) downstream from the existing Nalubaale and Kiira dams would be on-grid by this date. However, allegations of corruption resulted in the collapse of the contracted consortium led by U.S.-based AES Corporation and to the abandonment of the project in 2004. The relaunch of the procurement process in 2005 was then supervised by the WBG and the European Investment Bank (EIB). The plant was completed in 2012. Arguably, this large investment was facilitated by the presence of a private distribution concession, which instilled confidence that, over time, collections and loss-reduction initia- tives would be sustained. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 232 Case Study 5: Power Generation Developments in Uganda In total, the Bujagali HPP procurement preparation and implementation, and the subsequent construction process, took seven years, during which the electric- ity supply shortage had to be mitigated by expensive thermal power. At peak times in 2011–12, Uganda had 200 MW of generation facilities under operation, using heavy fuel oil (HFO) and diesel. Operation of these facilities first drained the UETCL’s capital savings and then affected the single buyer’s liquidity. In addi- tion, the depreciation of the Uganda shilling, which fell 25 percent against the U.S. dollar in 2011 alone, and the depletion of the World Bank’s partial financing of the thermal-based power production costs, led to a severe shortfall of funding in the power sector. Until fiscal year (FY) 2011/12, the government of Uganda paid a cumulative total of $623 million in subsidies to the UETCL, at its peak, roughly 7 percent of the national budget per year.6 In FY2010/11 alone, the Ugandan government paid more than $170 million of direct subsidy to the UETCL, almost equivalent to the government’s annual budget allocations for health (SE4ALL 2012). Furthermore, in 2005, the government also had to com- pensate Umeme Ltd. for not being able to supply the amount of energy specified in the concession agreement, an additional drain on the national budget. Despite these severe and unsustainable circumstances, the government did not permit ERA to increase end-user tariffs to sustainable levels until 2012.7 Electricity tariffs had been increased twice in 2006—by 41 percent and 35 percent, respectively (Dhalla 2011). Since then, the weighted-average tariff had effectively declined by 6.6 percent in Uganda shilling terms and by 23.2 percent in U.S. dollar terms, the latter being significant because most of Uganda’s power sector revenue require- ments were denominated in foreign currency. As a result, the weighted-average retail tariff in 2011 was $0.126/kilowatt-hour (kWh), while a fully cost-reflective tariff would have been about twice that, at $0.251/kWh (Dhalla 2011). In 2012, the government finally took steps to fix an unsustainable sector and remedy the liquidity situation of the UETCL. It supported ERA’s request to increase the end-user tariff by a weighted average of 46 percent, which, together with power produced by the Bujagali HPP after October 2012, reduced the pres- sure on the UETCL’s balance sheet. To stimulate private investment in small-scale renewable energy technologies (RET), which were needed to bridge the anticipated supply gap until major hydropower schemes came online in FY2018/19, ERA conducted a review of feed-in tariffs (FiTs) pertaining to renewable energy in 2012, which led to the adoption of the “Phase 2 REFiT guidelines” and a new attempt to offer cost- reflective RET-specific FiTs for small projects. With these measures implemented, Uganda appeared prepared to expand generation capacity and improve the overall performance of the sector. Yet, it quickly became clear that problems remained in expanding generation capacity, owing mainly to constraints on cost-reflective tariffs for new projects.8 Financing and project development costs remained high. In particular, the vital small-scale power projects remained unviable, even under the revised renewable energy feed-in tariff (REFiT) scheme. Another period of thermal-based power supply and depleting subsidies loomed. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 233 The government responded to this crisis in two ways. First, the procurement of roughly 800 MW of large hydropower capacity was fast-tracked. Financing and construction deals were reached with China’s ExIm Bank and Chinese contractors. Second, for small-scale projects, ERA, in cooperation with KfW, ­ developed and implemented the GETFiT program.9 Through this facility, up to 20 IPPs of various RET generation types totaling 150 MW of generation capacity were targeted for commercial operation between 2015 and 2018. By late 2014, it seemed that the Ugandan energy sector had overcome the most demanding phase of a market transition and was sufficiently prepared for future challenges, in particular with regard to the procurement of generation capacity. The increase in investor interest in Uganda is tangible, and Sub-Saharan African partners and stakeholders closely monitor ERA’s activities. Not surpris- ingly, Bloomberg New Energy Finance ranked the country 10th in a 2013 global survey of the investment climate in 55 emerging economies (and third in Africa, after the significantly larger African economies of South Africa and Kenya).10 Umeme’s performance has improved steadily in recent years, as indicated in figures 10.2–10.5. Umeme now faces new loss-reduction targets—from 23.4 ­percent in 2014 to 14.9 percent in 2018. Umeme listed its shares on the Uganda Securities Exchange through an initial public offering in 2012. More than 6,000 Ugandans bought the firm’s stock, as did African institutional investors, foreign equity funds, and venture capital funds. Funds raised from the stock offering were used to reduce the company’s interest-bearing debt and enabled Umeme to secure additional commercial debt over the next few years to help finance its expansion strategy. Umeme’s shares were cross-listed at the Nairobi Securities Exchange in 2013. The strategic inves- tor Actis, previously known as Globeleq, became a minority shareholder by Figure 10.2  Umeme Energy Losses: Uganda, 2005–14 40 35 30 Percent 25 20 15 05 06 07 08 09 10 11 12 13 14 20 20 20 20 20 20 20 20 20 20 Source: World Bank 2014. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 234 Case Study 5: Power Generation Developments in Uganda Figure 10.3  Umeme Collection Rates: Uganda, 2005–14 100 95 90 85 Percent 80 75 70 65 11 13 14 09 10 12 08 05 06 07 20 20 20 20 20 20 20 20 20 20 Source: World Bank 2014. Figure 10.4  Umeme Customers: Uganda, 2005–14 700 No. of customers (thousands) 600 500 400 300 200 11 09 10 12 13 08 14 05 06 07 20 20 20 20 20 20 20 20 20 20 Source: World Bank 2014. reducing its equity participation to 14 percent in May 2014. By May 2014, the top shareholders of Umeme were Investec Asset Management, Actis, the National Social Security Fund, Farallon Capital, Coronation Funds, Allan Gray Africa Funds, the International Finance Corporation (IFC, WBG), Utilico Emerging Markets, Patrick Bitature, and Everest Capital. However, it has not been all smooth sailing. In 2006, Umeme shareholders were ready to exercise their termination rights due to the power supply crisis. The IDA strongly encouraged both parties to renegotiate the concession and Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 235 Figure 10.5  Umeme Investment: Uganda, 2005–13 70 60 Investment (US$, millions) 50 40 30 20 10 0 05 06 07 08 09 10 11 12 13 20 20 20 20 20 20 20 20 20 Source: World Bank 2014. extended its guarantee in support of the resulting restructuring. The IDA also provided financial support to help Uganda finance emergency power to mitigate supply shortages. In 2008, Umeme and the Ugandan government entered into a dispute concerning the compliance of both parties with contractual obligations. While the government acknowledged that it could have been more supportive of Umeme’s efforts to reduce nontechnical losses, its perception was that Umeme’s management was not doing enough in accelerating efforts in other areas. In response, Umeme brought in a new management team. In early 2009 a new minister of energy and some members of parliament tried to unilaterally terminate Umeme’s concession on grounds of nonperformance. The IDA joined forces with the MIGA and IFC to prepare a report that showed the progress and conditions of Uganda’s distribution network since the onset of the concession. The Ugandan government acknowledged, at the highest level, that despite “mixed” performance in certain areas, Umeme had improved distribution ­ services overall. Subsequently a new minister of energy was appointed. In FY2011/12 a deadlock in negotiations over performance targets for the 2013–18 regulatory period was eventually resolved with the aid of an independent adviser to ERA and support from the WBG (World Bank 2014). However, tariff challenges remain. With an estimated annual increase in demand of 10–12 percent through 2020, and higher beyond, Uganda needs to embark on proactive planning for additional generation capacity. The export of promising oil and gas resources might generate investment funds for power proj- ects in the medium term. However, it remains essential that Uganda continue to pursue the bold course charted during the first decade of this century. Power Sector Planning, Allocation, Procurement, and Contracting The Electricity Act (1999) and pertinent sector documents (such as the 2002 Energy Policy, the 2007 Renewable Energy Policy, and various joint sector reports) Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 236 Case Study 5: Power Generation Developments in Uganda affirm that the government, in particular the Ministry of Energy and Mineral Development (MEMD), holds primary responsibility for the expansion of genera- tion capacity. Although Uganda’s electricity sector has been fully unbundled, all generation, transmission, and distribution assets remain ultimately under state ownership. O&M of the state-owned generation facilities and the main distribu- tion grid, however, have been concessioned to private companies (see figure 10.1). The MEMD’s electricity sector functions, as described in the 2014 Sector Performance Report and the 2007 Renewable Energy Policy, bear striking simi­ larities to Section 11 of the Electricity Act (1999), which outlines the responsi- bilities of ERA, the regulator. ERA understands its role as the promoter of frameworks that stimulate investment and competition and as the “guardian” and facilitator of the least-cost development path for future resource development. In broader terms, ERA aims to increase the quantity, reliability, and diversity of generation (interview with Benon Mutambi, CEO, ERA, April 2015). Beyond the supply side, ERA also claims responsibility for providing cost-efficient and sustainable frameworks to ensure financial resources for further reinforcements and extensions of the T&D grid. The responsibilities for procuring new power generation capacity are effectively split among three actors: the MEMD, UEGCL, and ERA. Yet there is no doubt that the MEMD remains the chief forum for the development of political consensus and for decisions on the implementation of policies governing the broad electricity sector. The MEMD’s Energy Resources Department is responsible for forecasting demand and supply at the national level. It is within the MEMD that policy pro- posals and inputs of sector stakeholders such as the Rural Electrification Agency (REA) and ERA are coordinated and blended into a national policy framework. ERA has, however, exercised its role as the facilitator of private sector devel- opment to set up market mechanisms and competition. This has led to an increase of its leverage and importance in recent years, as evidenced by the 2012 hike in end-user tariffs, which was advocated by ERA to encourage further investments in generation capacity and other sectorial necessities. Furthermore, the introduction of a quarterly automatic adjustment mechanism for end-user tariffs, which was promoted by ERA for years and which effectively floats electricity prices on the basis of macroeconomic parameters (beyond political ­ control), could not have occurred without ERA’s strong standing in the sector. As the sector’s data collection hub, ERA has unrivaled insight into the market subsectors and their respective dynamics. Armed with this knowledge, it is the de facto policy adviser for all other sector stakeholders, including the MEMD, in matters involving data and strategy. Beyond these advisory responsibilities, ERA autonomously originates sector policy in two ways. First, it is the driver behind the development and monitoring of the least-cost generation path as stipulated in the Power Sector Investment Plan (PSIP), even though that path must be officially adopted by the MEMD. Second, it affects sector planning by shaping the future energy mix in the country, specifically by determining and enforcing capacity targets and limits (as seen under the REFiT scheme) and by licensing generation projects based on marginal cost. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 237 Planning and procurement are guided by the Renewable Energy Policy of 2007 and the 2011 PSIP. The latter expands on the sector strategies mandated in the 2010 National Development Plan for the period 2010/11 to 2014/15 (Government of Uganda 2010). It encompasses investment proposals for genera- tion through 2030 and prioritizes projects along the trajectories of supply reli- ability and least costs (discounted) (MEMD 2011). In the PSIP, the MEMD estimated that the total capital investment cost for generation to meet demand through 2030 would be nearly $5.5 billion.11 In the proposed scenario (which has not yet been realized), the government was to provide, in the medium term, equity of more than $1.6 billion. The MEMD has opened the public space for Chinese-funded investments and development as well as attempted to create an attractive environment for private investment and development. The first procurements of generation capacity following the 1999 reforms were the Bujagali HPP and various thermal power projects, all implemented between 2004 and 2010. Bujagali HPP was initially undertaken by the MEMD, which awarded the contract to the AES consortium. The award process was implemented under internal and external pressures resulting from a severe supply deficit, economic woes, and turmoil in the sector in the years following ­ the reforms. The procurement of thermal power was realized by a multitude of players using a variety of procurement arrangements. The MEMD, through the UETCL, awarded the first contract to Aggreko in 2005 after competitive bidding. The second award to Aggreko for the Kiira project in 2005/06 was effectively the result of a direct negotiation process, one accompanied by allegations of secretiveness and mismanagement.12 The 2008 procurement of the Mutundwe project was partially supported by the IDA and implemented by the UETCL on behalf of the MEMD and World Bank. The contract for the Namanve plant, awarded to Jacobsen of Norway in 2008, was the result of a competitive procure- ment process under the Electricity Act, but this time implemented by ERA. The last thermal project followed a classic IPP model: Electro-Maxx’s Tororo project resulted from an unsolicited bid process under Section 32 of the Electricity Act (1999). For IPP-promoted projects across all generation types, ERA can receive unso- licited bids under Section 30 of the Electricity Act (1999) or implement com- petitive bidding for concessions pursuant to Section 33. For all unsolicited bids, ERA is the lead entity and guides and monitors the planning and implementation of projects. For nonstandard tender procedures, such as the recently closed com- petitive bidding for solar generation jointly implemented with KfW and the GETFiT facility,13 ERA can utilize the expertise of external consultants in com- pliance with Section 15 of the 1999 Act. The procurement processes hosted by ERA follow the legislative framework set forth in Sections 30–52 of the act, which deal with the licensing and permitting. For both unsolicited proposals and competitive bids, ERA initiates the procurement and conducts the necessary due diligence for the award of permits and licenses and then monitors the perfor- mance of the IPPs. For all RET-based projects having a capacity of between 1 MW and 20 MW, ERA is also in charge of the REFiT scheme, which offers Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 238 Case Study 5: Power Generation Developments in Uganda predefined, technology-specific off-take prices per kilowatt-hour over the 20-year lifetime of the power purchase agreement (PPA). After some further minor increases,14 the terms of REFiTs are as shown in table 10.1. For the two currently implemented large-scale hydropower projects—Karuma (600 MW) and Isimba (183 MW)—the MEMD took the lead in procurement starting in 2005/06, when Karuma was earmarked for implementation as a pub- licly procured engineering, procurement, and construction (EPC) project.15 The first tenders went out in 2006. However, the process of obtaining financing and a contractor for the project gained decisive momentum only after 2010. In this context, it is noteworthy that the 1999 Act does not foresee any direct role for the Ugandan government in developing generation projects or procuring new capacity. The sector reforms of 1998–99 and the subsequent act stipulated the development of IPPs (through unsolicited bids or competitive bidding for concessions) under the direction of ERA, as well as public EPC procurement through parastatals such as the UEGCL and UETCL. The act contemplated only “persons” as legitimate applicants for a permit to conduct feasibility studies (Section 30) or as holders of a generation license (Section 34). A person is defined as “any individual, firm, company, association, partnership or body or persons, whether incorporated or not.” Whereas this clause, narrowly construed, stipulates only that the MEMD can- not be the holder of a permit or license, it is noteworthy that the ministry is otherwise not mentioned once in the respective section of the act. From this, one may conclude, as other stakeholders affected by the act have done, that the development and procurement of generation capacity are not the role of govern- ment, but exclusively of private actors and incorporated parastatals.16 The emergence of direct procurement by the MEMD has thus been consid- ered “a challenge for the integrity of sector structures.”17 Although both the Table 10.1  REFiT Overview: Uganda, as of January 2015 Renewable energy Cumulative capacity limits (MW) Payment technology Tariff (US$/kWh) O&M (%)a 2013 2014 2015 2016 period (years) Hydro (9 ><= 20 MW) 0.085 7.61 30 90 135 180 20 Hydro (1 ><= 9 MW Linear tariffb 7.24 30 75 105 135 20 Hydro (500 kW ><= 1 MW) 0.115 7.08 1 2 2.5 5.5 20 Bagasse 0.095 22.65 30 70 95 120 20 Biomass 0.103 16.23 5 15 25 45 20 Biogas 0.115 19.23 5 15 25 45 20 Landfill gas 0.089 19.71 0 10 20 40 20 Geothermal 0.077 4.29 10 30 50 75 20 Wind 0.124 6.34 25 75 100 150 20 Solar 0.11 n.a. n.a. n.a. n.a. n.a. 20 Source: Compiled by the authors, based on various primary and secondary source data. Note: kW = kilowatt; kWh = kilowatt-hour; MW = megawatt; O&M = operation and maintenance; REFiT = renewable energy feed-in tariff; USc = US cents; n.a. = not applicable. a. The REFiT scheme also allows for an inflation indexation of the O&M share on an annual basis. b. Linear tariff for small hydro computed as a regressive allocation of costs with increase in plant size, range USc 10.9 (1 MW) to USc 7.9 (Uganda REFiT guidelines, www.era.co.ug). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 239 Karuma and Isimba HPPs will be transferred to the UEGCL ownership after reaching financial close, and thus brought into compliance with the provisions of the act, ERA’s regulation of these projects will remain marginal. The conclusion of financing agreements for the projects implies that tariffs have already been negotiated, which precludes ERA from exercising its mandate and obligations under Section 76 of the act. Furthermore, as the design of the projects has been determined, ERA will have difficulty monitoring and enforcing compliance with technical and quality standards. The UEGCL and, in the past also the UETCL, are the parastatal entities that regularly procure generation capacity for the government, often in cooperation with development partners or international financial institutions and on the basis of concessional official development assistance (ODA) or grant finance. The procurements presently under implementation by the UEGCL are the Muzizi HPP (46 MW) and Nyagak III small hydropower (SHP) project (4.3 MW). The UEGCL is also the governmental body designated to participate in public-­ private partnerships (PPPs). Nyagak III SHP is the first project currently consid- ered a PPP, and its process of identifying a private partner recently closed, despite the fact that the PPP legislation has been pending in parliament since early 2012. Projects realized by the UEGCL are also subject to full regulatory scrutiny by ERA. Incentive Frameworks During the sector crisis of the late 2000s, the government introduced an array of incentives to facilitate investments in the power sector (table 10.2). Beyond the FiT for small-scale RET, the government implemented other measures Table 10.2  Overview of Available Tax Incentives for Power Generation Investments, Uganda Type Details Initial capital Initial allowance on plant and machinery of 50–75 percenta allowances Start-up cost spread over four years (25 percent per year) Initial allowance of 20 percent on hotels, hospitals, and industrial buildings Deductible annual allowances (depreciable assets) of 20–40 percent VAT Exemptions for hydro (full/public and IPPb) Partial exemptions for solar (sole-purpose electromechanical equipment only) Import duty/tax Duty- and tax-free import of plant and machinery Rebate of fuel duties Stamp duty exemption Exemptions from withholding on plant and machinery, scholastic materials, human and animal drugs, and raw materials Ten-year tax holiday Repatriation of profits No limits and no tax on repatriation of profits or dividends Source: Compiled by the authors, based on various primary and secondary source data. Note: IPP = independent power project; VAT = value added tax. a. Revoked in the tax reforms of 2014. Now plant and equipment must qualify under the Income Tax Act for accelerated depreciation, with a maximum annual deductible of 20 percent. b. After the tax reforms of 2014, costs incurred during the feasibility stage are no longer exempted from the value added tax. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 240 Case Study 5: Power Generation Developments in Uganda Table 10.3  Risk Mitigation and Investment Incentives for Thermal and RET Projects, Uganda Risk Thermal RET (2008–12) RET/GETFiT (since 2012) Nonpayment by Governmental/World Bank Governmental guarantees Governmental/World Bank sole off-taker guarantees for UETCL payments for UETCL payments guarantee for UETCL payments resulting in Implementation agreements Implementation Implementation agreements liquidity agreements (some) (standardized) shortage Up-front payment of GETFiT subsidy for supported projects Dispatch Capacity payments Capacity payments (large) Take-or-pay arrangements Take-or-pay arrangements Interconnection support (policy, for small-scale projects development partner grant or concessional finance support for power infrastructure) Fuel, hydrology Fuel cost pass-through to UETCL/ None None by Ugandan government government of Uganda Limited hydrology risk sharing Joint fuel procurement under GETFiT financing arrangement with Ugandan agreements government for some projects Termination, Implementation agreements Implementation Implementation agreements government agreements (some) (standardized) default, Direct agreements between lenders expropriation and Ugandan government World Bank partial risk guarantee Source: Compiled by the authors, based on various primary and secondary source data. Note: GETFiT = global energy transfer feed-in tariff; RET = renewable energy technology; UETCL = Uganda Electricity Transmission Company Ltd. ­pecifically targeting RET and thermal-based power investments, such as take- s or-pay arrangements and capacity deals. Additional supporting measures, such as sovereign guarantees, were introduced, and tax exemptions for general invest- ments were extended to the power generation subsector. In its Sector Performance Report for 2014, the government confirmed its willingness to promote power generation across all available technologies. However, whereas RET development has dedicated policies, the thermal sector has not benefitted from such specific proposals, presumably because it lacks donor funding and support. This has not impeded thermal power development in Uganda in the past. However, the implementation of further projects is not likely to materialize until the timeline for development of Uganda’s petroleum potential becomes clearer (a topic discussed further on). For RET, as previously noted, the government and its entities have developed a more comprehensive policy, accompanied by the risk mitigation instruments and incentive mechanisms detailed in table 10.3. Current Attributes and Recent Performance of the Electricity Sector Installed Generation Capacity Large hydropower projects accounted for 74 percent of Uganda’s power capacity in 2013, followed by thermal plants (12 percent). Bagasse and small HPPs Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 241 Figure 10.6  Total Capacity, by Technology: Uganda, 2004–13 1,000 900 800 700 600 Megawatts 500 400 300 200 100 0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Small hydro 15.5 15.5 15.5 15.5 15.5 28.5 28.5 52.9 52.9 61.9 Bagasse 0 0 0 0 22 22 36.5 36.5 36.5 66.5 Thermal 0 50 50 50 150 150 170 170 150 100 Large hydro 380 380 380 380 380 380 380 380 630 630 Source: Compiled by the authors, based on various primary and secondary source data. supplied roughly equal shares of the remainder (figure 10.6). Details on Uganda’s power plants are shown in table 10.4. Electricity production in 2013 was split more or less evenly between IPPs (1.492 gigawatt-hours, GWh) and public projects (1.239 GWh), with a small share of thermal emergency capacity (figure 10.7). (All conventional thermal capacity in Uganda—the Namanve and Tororo plants—is currently operated as emergency or standby capacity.) IPP production increased dramatically with the commissioning of the Bujagali HPP in 2012, which reduced the need for emergency power generation. Figures 10.8 and 10.9, viewed together, reveal the expected evolution in ownership and funding of Uganda’s generation assets through 2020. The advent of the Bujagali HPP resulted in a roughly even share of power genera- tion between the public utility and IPPs. The share of public projects will grow again (to roughly 75 percent of total installed capacity by 2020) with the completion of the current Chinese-funded hydropower investments, which are discussed further on. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 242 Case Study 5: Power Generation Developments in Uganda Table 10.4  Uganda’s Power Plants Ownership Installed Peak (and (public, MW average) Owner/operation Plant PPP, or IPP) Type (noncaptive) capacity to grid Comment UEGCL/Eskom Nalubaale Public Hydro 180 220 (140) Capacity shown is Uganda for both projects Kiira 200 BEL Ltd. Bujagali IPP Hydro 250 170 Jacobsen Namanve IPP Thermal (diesel/ 50 50 Emergency plants Electro-Maxx Tororo IPP HFO) 50 50 (2013) SAEMS Mpanga IPP Small hydro 18 9 TrønderEnergi Bugoye IPP 13 9 Hydromax Buseruka IPP 9.0 4 Eco Power Ishasha IPP 6.4 3 Mubuku III KCCL IPP 10.5 (7.5) 3 Mubuku I Kilembe Mines IPP 5.4 2 Kakira Sugar Kakira IPP Cogeneration 52 (32) 32 Works (bagasse) Kinyara Sugar Ltd. Kinyara Cogen IPP 14.5 (7.5) 3 West Nile Rural Nyagak I IPP Small hydro 3.4 n.a. Isolated grid Electrification Company Oil Palm Uganda PPP/ Solar/thermal 1.6 n.a. ODA hybrid Total MW 858.4 Source: Compiled by the authors, based on various primary and secondary source data. Note: HFO = heavy fuel oil; IPP = independent power project; KCCL = Kasese Cobalt Company Ltd.; MW = megawatt; ODA = official development assistance (concessional aid); PPP = public-private partnership; SAEMS = South Asia Energy Management Systems; UEGCL = Uganda Electricity Generation Company Ltd.; n.a. = not applicable. Figure 10.7  Sources of Electricity Sold to UETCL: Uganda, 2005–13 1,800 1,600 Megawatts (thousands) 1,400 1,200 1,000 800 600 400 200 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 IPP 22,310 30,021 32,687 88,474 138,377 177,202 260,359 1,272,351 1,492,036 Emergency 140.91 370.08 556.27 217,104.71 896,610.26 1,020,278.08 957,992.91 275,292.78 1.40 Government 1,702,690 1,160,456 1,263,544 1,373,444 1,234,975 1,255,803 1,335,935 1,274,637 1,239,140 Source: Compiled by the authors, based on various primary and secondary source data. Note: In the table, “emergency” indicates thermal plant capacity that is now mostly used for backup power on the grid. It is not a short-term rental plant. The steep drop from 2012 to 2013 reflects the entry into commercial service of the Bujagali hydroelectric IPP, which reduced the need for emergency supplies from thermal plants. IPP = independent power project; UETCL = Uganda Electricity Transmission Company Ltd. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 243 Figure 10.8  Ownership and Funding, by Share of Installed Capacity: Uganda, 2014 percent Government/ utility, 44 IPP, 44 Emergency, 12 Source: Compiled by the authors, based on various primary and secondary source data. Note: IPP = independent power project. Figure 10.9  Sources of Funding, by Estimated Share of Installed Capacity: Uganda, 2020 percent Government/ utility, 24 Chinese, 45 Emergency, 6 IPP, 25 Source: Compiled by the authors, based on various primary and secondary source data. Note: IPP = independent power project. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 244 Case Study 5: Power Generation Developments in Uganda Costs of Generation Generation costs in Uganda are not uniformly or universally transparent, even apart from variable components such as the cost of the HFO and diesel fuel used in thermal plants. All large hydropower assets have capacity payment arrange- ments with the UETCL linked to annual operational targets. The Nalubaale and Kiira projects are fully depreciated, and the unit costs presented in table 10.5 result from the provisions in the concession agreement, pursuant to which Eskom Uganda Ltd. receives a 12 percent return on capital expenditures and an O&M charge, plus its concession fee. For the Bujagali HPP, the agreements are more complex. According to ERA, the final tariff arrangement between BEL Ltd. and the UETCL depends on a final cost audit for the project, which was not yet complete in early 2015. For existing small-scale IPPs, unit costs are higher than for the large hydro- power projects but still much lower than those of thermal plants. Their numbers would appear viable even under the current REFiT regime. However, some fac- tors are not incorporated in the tariffs, as agreed in the PPAs, and need to be incorporated into the real cost of the projects. First, ERA and the UETCL had to agree to extended PPA durations for the Buseruka (40 years) and Bugoye (25 years) SHPs, with high up-front tariffs. The latter project also received sub- stantial grant support through Norwegian development cooperation institutions, which brought the tariff for this $65.7 million project down to the levels pre- sented here. It must further be assumed that some of these sites (Mpanga, Ishasha) represented “low-hanging fruit” among the SHP portfolio in Uganda and hence could be realized at a very competitive cost. It is difficult to compare hydroelectric costs as they are highly dependent on hydrological and geological site conditions. The emergency thermal plants are the highest-cost producers. They are being run less and less often, however, as other, more competitive, generation assets are exploited. Table 10.5  Electricity Costs for All Operational Generation Assets, Uganda PPA duration Specific (years), investment Levelized project Asset owner/ Form of cost (US$/ costa (USc/ finance operator Type ownership kW) kWh, 2013) structure Comment Nalubaale HPP GoU n.a. 1.2 n.a. Guaranteed return on GoU/Eskom concession CAPEX concession fee Uganda O&M costs Capacity availability payment Kiira HPP GoU n.a. 1.2 n.a. Guaranteed return on GoU/Eskom concession CAPEX concession fee Uganda O&M costs Capacity availability payment table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 245 Table 10.5  Electricity Costs for All Operational Generation Assets, Uganda (continued) PPA duration Specific (years), investment Levelized project Asset owner/ Form of cost (US$/ costa (USc/ finance operator Type ownership kW) kWh, 2013) structure Comment Bujagali HPP IPP 3,444 11.0 30 Capacity payment BOOT Stepped tariff Namanve Emergency IPP 1,240 24.1 5.5 (extended) Fixed cost/capacity charge Jacobsen thermal BOOT plus fuel costs Electro-Maxx Emergency IPP 980 27.1 20 Fixed cost/capacity charge thermal BOO plus fuel costs Mpanga SHP IPP 1,517 9.0 20 Stepped tariff SAEMS BOO Levelized tariff over PPA: USc 7.732 Buseruka SHP IPP 4,244 13.5 40 Three-tier tariff (peak, Hydromax BOO off-peak, shoulder) Stepped tariff (16 years/24 years) Levelized tariff over PPA: USc 8.3 Bugoye SHP IPP 5,054 12.9 25 Stepped tariff TrønderEnergi BOO Levelized tariff over PPA: USc 8.14 Ishasha SHP IPP 2,298 8.3 20 Three-tier tariff (peak, BOO off-peak, shoulder) Stepped tariff Weighted and levelized tariff over PPA: USc 8.3 Mubuku I SHP IPP n.a. 3.0 2 Privatized government BOO asset Mubuku III SHP IPP 2,143 5.38 20 Privatized government BOO asset Kakira Sugar Bagasse IPP n.a. 8.83 20 (each) 3 PPAs (weighted BOO PPA1+2 (12 MW) average PPA3 (20 MW) across all PPAs) Kinyara Sugar Bagasse IPP 930 8.1 20 BOO Source: Compiled by the authors, based on various primary and secondary source data. Note: The average 2013 rate of exchange of the Uganda shilling to the U.S. dollar was taken from www.oanda.com ($1 = U Sh 0.0004), accessed February 1, 2015. BOO = build-own-operate; BOOT = build-own-operate-transfer; CAPEX = capital expenditure; GoU = Government of Uganda; HPP = hydropower plant; IPP = independent power project; kW = kilowatt; kWh = kilowatt-hour; MW = megawatt; O&M = operations and maintenance; PPA = power purchase agreement; SAEMS = South Asia Energy Management Systems; SHP = small hydropower plant; USc = U.S. cent; n.a. = not applicable. a. Projects have been granted varying percentages of indexing for inflation on O&M costs, which has changed the effective tariffs since the conclusion of the PPAs, according to data from the Electricity Regulatory Authority (ERA) website (http://www.era.co.ug, accessed February 1, 2015). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 246 Case Study 5: Power Generation Developments in Uganda Public Projects Nalubaale (Owen Falls) HPP/Kiira HPP Both of the large hydropower projects of the Jinja-Nile hydropower complex, Nalubaale (formerly Owen Falls) and Kiira, are located roughly 2 kilometers (km) downstream from the source of the Nile as it exits Lake Victoria.18 The projects have an installed capacity of 180 MW and 200 MW, respectively. However, the cumulative average power supply from the entire complex is no more than about 140 MW (peak 220 MW).19 The low effective power genera- tion capacity results from two factors. First, the hydrology of Lake Victoria, which is 80 percent dependent on regional rainfall, has shrunk markedly since the drought of 2006. Second, the treaty between Egypt and Uganda that regulates the permissible outflow of Lake Victoria—and hence possible power ­ generation—has come increasingly under challenge.20 The Owen Falls HPP was built under British colonial rule and commissioned in 1954, initially with a capacity of 150 MW. The project was then owned and operated by the UEB, established in the same decade. In subsequent years, the plant’s performance deteriorated until, after the Idi Amin regime, its capacity dropped to 50 MW. In the 1990s, the project was rehabilitated and expanded to its current installed capacity of 180 MW, with World Bank support. The Kiira HPP was fully commissioned in 2004. The project, which is considered an expansion of the Nalubaale HPP, was initiated by the government in 1993 with financial support from the World Bank and the Swedish International Development Cooperation Agency (Sida), but its first stage was not completed until 2003. As previously noted, both are now operated under the Eskom concession. Public Projects in the Pipeline At the time of this report, the government was in the process of finalizing the financing for the Muzizi HPP, a 46 MW hydropower project in the Lake Albert region. This initially PPP-earmarked project is being implemented by the UEGCL, which will procure an EPC contractor through an international competitive bid (ICB). KfW, along with the French Agence Française de Développement (AfD), intend to provide concessional loans for this project, which is expected to reach financial close in 2016. The Nyagak III SHP, a 5 MW project located in the West Nile Rural Electrification Company (WENRECO) isolated grid in the West Nile region, was also in the later stages of project preparation at the end of 2014. This PPP project, the first of its kind in Uganda, will be i ­mplemented through a special-­ purpose vehicle (SPV), in which the private developer will be co-shareholder with the UEGCL. KfW also supports this p ­ roject. Financial close is expected in 2016. Independent Power Projects Uganda’s experience in IPP development is among the most interesting in Africa. By 2012, it had implemented 11 IPP projects across a diverse set of generation technologies and project capacities. Between 2015 and 2018 it is expected that up to 20 small-scale (1–20 MW) projects will be added to this Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 247 portfolio through the government’s cooperation with KfW on the GETFiT Uganda program.21 A Short History of IPPs in Uganda, 1950–2012 Mubuku I SHP (5 MW) was commissioned in the 1950s to provide electricity for the copper ore extraction ventures of Kilembe Mines Ltd. Since these core operations stalled in the 1970s, the company has been selling electricity to the Ugandan grid. Kakira Sugar Ltd. (52 MW/32 MW available to grid) is East Africa’s biggest sugar producer. After effective expropriation through Idi Amin’s forced exodus of Indians in 1972, the owners began rebuilding the sugar production facilities in 1985 with support from IDA and the African Development Bank (AfDB). Since 2003, the cogeneration facilities of the sugar plant in Jinja have been feeding noncaptive electricity into the Uganda grid. From initially only marginal excess power, the available capacity increased to 32 MW by 2014. The latest expansion (to 30 MW total capacity, with 20 MW to grid in 2012/13) went hand in hand with an expansion of sugar production facilities. The expansion was realized with financing from local commercial banks and the East African Development Bank (EADB). Mubuku III SHP (10.5 MW) is a hydropower plant linked to the extraction operations of the Kasese Cobalt Company Ltd., which uses most of the electric- ity generated. The IPP project was commissioned in 1998 and realized at a cost of $22.5 million. In the first decade of its operation, nearly all of the plant’s generation was for captive use. Namanve Thermal (50 MW), one of the two remaining thermal power plants in the country, is operated by Jacobsen of Norway. Currently, the plant is on cold standby for emergency backup. The company won the build-operate-transfer (BOT) deal after a much-disputed ICB process. The total investment cost of $62 million was financed through one Ugandan and one Norwegian commercial bank, and supported by the Norwegian Agency for Development Cooperation (NORAD). Until the expiry of the PPA in March 2015, Jacobsen was paid a capacity charge by the UETCL, although effectively payments come directly from the government. The future ownership and operation of this project is under dis- cussion. The most likely scenarios are that the PPA with Jacobsen is extended until 2021 or that ownership is transferred to the UEGCL on the basis of a build-own- operate-transfer (BOOT) arrangement. The second option would require that the government repay, in full, the outstanding debt to the Norwegian financiers. Kinyara Sugar Cogen (14.5 MW/4.5 MW available to grid) is the second power plant based on bagasse cogeneration technology currently operative in Uganda. The cogeneration facilities were installed in 2009 at an estimated invest- ment cost of $13.2 million. In 2014, Kinyara Sugar Works Ltd. was in the final stages of planning an expansion of the power plant, which will increase its installed capacity to 44 MW (24 MW available to grid). Bugoye SHP (13 MW), located on the Mubuku River, is currently operated by TrønderEnergi of Norway. A financing consortium consisting, on the equity side, Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 248 Case Study 5: Power Generation Developments in Uganda of TrønderEnergi and Norfund, and of the Emerging Africa Infrastructure Fund (EAIF) on the debt side, raised the total investment costs of $65.7 million, with some grant support from the government of Norway. The plant began commer- cial operation in 2011. The project was implemented through an EPC contract (Noremco, ABB, Mavel). Tororo Thermal (50 MW) is often considered the first indigenous African IPP; it is financed, built, and operated solely by Africans. The HFO-based thermal plant was implemented in two stages. In 2009, the first 20 MW came online, while the additional 30 MW were commissioned in 2012. The project cost of $49 million was funded by local investors and commercial banks and was consid- erably cheaper than the Jacobsen plant. Mpanga SHP (18 MW) was commissioned in 2011. The project was devel- oped and is operated by the South Asia Energy Management Systems (SAEMS), a U.S.-based renewable power developer. The $27.5 million project was financed through a multiproject international facility of $110 million, of which the EAIF, the Netherlands Development Finance Company (FMO), and the German Investment and Development Corporation (DEG), financed $72 million. VS Hydro of Sri Lanka was the EPC contractor for the project. Ishasha SHP (6.4 MW) is the first power plant of an expected series of projects developed by Sri Lankan developers. Eco Power Ltd. realized the build- ­ own-operate (BOO) project in the remote west of the country at a cost of $14.71 million, of which the 65 percent debt portion was financed by Sri Lankan commercial banks. The construction process was partially implemented and entirely supervised by Eco Power Ltd. under a split contract. Buseruka SHP (9 MW) was developed by Hydromax (Uganda) Ltd., a domes- tic hydropower developer backed by the Uganda civil contractor Dott Services Ltd. The project was commissioned in 2012 and realized at a total cost of $38.2 million, for which African Preferential Trade Area Bank (PTA) and AfDB provided the debt financing. This project, too, was carried out under a split con- tract, with Dott Services Ltd. being responsible for the civil works and Tata Consulting Engineers for design and engineering. As indicated, with an estimated total investment volume of $860 million, the Bujagali HPP (250 MW) still ranks among the largest privately financed hydro- electric power projects in Sub-Saharan Africa. From the government’s side, the project was supported by ODA (which took the form of equity contributions) and by a sovereign guarantee of payments by the off-taker. The security package offered to the developer and lenders also included significant contributions by the WBG, which provided a partial risk guarantee (PRG) for the debt tranche and a $115 million equity investment guarantee from the MIGA. Further project financing and operational details are provided in table 10.6. The GETFiT Project Portfolio One of the key measures in the 2007 Renewable Energy Policy was the introduc- tion, through ERA, of a REFiT scheme. To avoid impacts on end-user tariffs, REFiTs were purposefully kept low and did not cover the levelized cost of Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 249 Table 10.6  Overview of Bujagali HPP—Implementation, Financing, and Cost: Uganda Date of entry into commercial operation 2012 Financial close 2007 Contract type BOOT Shareholder equity $151 million Amount supplied by development finance institutions $512 million (IFC, EIB, Proparco, KfW, AfDB, (and participating institutions) FMO, DEG, AFD) Commercial lending (and participating banks) $115 million (Standard Chartered, Absa) Engineering, procurement, and construction Salini Equipment supplier Alstom/Sinohydro Capacity charge (levelized average over lifetime of PPA) USc/kWh 0.987 Sales to the grid (MWh, 2013) 1,375.57 Source: Compiled by the authors, based on various primary and secondary source data. Note: Absa = South African commercial bank; AFD = Agence Française de Développement; AfDB = African Development Bank; BOOT = build-own-operate-transfer; DEG = German Investment and Development Corporation; EIB = European Investment Bank; FMO = Netherlands Development Finance Company; HPP = hydropower plant; IFC = International Finance Corporation; KfW = Kreditanstalt für Wiederaufbau; kWh = kilowatt-hour; MWh = megawatt-hour; PPA = power purchase agreement; USc = U.S. cent. electricity for the renewable energy technologies included. Also ERA was not successful in obtaining international funding subsidies or carbon credit facilities for renewable energy. The IPP projects implemented between 2007 and 2012 were either financed against the balance sheets of sugar factories or came at higher prices than the REFiTs, both in terms of effective tariff charges22 and transaction costs. A key positive outcome of this phase, however, was that the basic regulatory framework started to be operationalized and capacitated. The 2007 REFiT levels were revised by ERA in 2011, but the proposed tariffs still did not cover the levelized cost of electricity over all RETs. KfW then helped ERA to develop the GETFiT approach to incentivize new investments to plug the gap between supply and demand until the two new large hydropower proj- ects, Isimba and Karuma (described in the next section), came online. The primary GETFiT mechanism is a grant-based premium payment over the REFiT levels to close the gap with the levelized cost of energy for ­ eligible technologies—namely, small hydropower, biomass, bagasse, and solar PV. The per-kWh-based GETFiT subsidy is calculated over the 20-year lifetime of the PPA but works as a performance-based payment over the first five years of opera- tion to enhance the project’s debt-service profile. An important and valuable part of the program was the development of a full set of legal documents—among them standardized (and investor-approved) PPAs, implementation agreements (IAs), and direct agreements (DAs) (securing lender takeover rights). In addition, World Bank PRGs are available to successful projects to address off-taker and termination risks. This was an innovative offering in the sense that the Bank offered in-principle approval for a portfolio of projects, thus potentially reducing the transaction costs for individual projects. The PRGs are designed to backstop government support for letters of credit (LCs) issued by commercial Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 250 Case Study 5: Power Generation Developments in Uganda banks against defaults by the utility. The letters can be drawn by a developer in the event of an interruption in PPA payments by the UETCL, and the PRG guarantees the issuing bank’s debt, thus offering certainty about liquidity to lend- ers and project developers. Once an LC is drawn, the national government is obligated to repay the amount drawn (with interest) to the issuing bank within a certain period. The repayment period allows time for the resolution of the issues that led to the default and for the World Bank to intervene if necessary. If the issuing bank is not reimbursed during this period, then it may call in the PRG. At the time of writing, no GETFiT project had used this facility. This may change as projects that rely more on commercial debt rather than on funding from other development finance institutions approach financial close. GETFiT also supports lender due diligence and has assisted the government of Uganda in streamlining procedures essential for IPP project implementation, such as the permit and licensing process as well as the operationalization of tax and custom exemptions provided for IPP projects in Uganda. Three competitive tenders were run between 2013 and 2015 for small hydro- power and biomass (1–20 MW) based on quality, rather than the price of proj- ects. Projects had to meet minimum qualitative benchmarks (table 10.7). Prices were determined by the REFiT plus the premium payment. Project developers had to propose their own sites, conduct full feasibility and interconnection stud- ies, and secure ERA permits and environmental and social impact assessments in compliance with the performance standards of the IFC, including, where Table 10.7  GETFiT Evaluation Criteria, Uganda Classic GETFiT (small hydro, biomass, bagasse) GETFiT solar facility Financial and economic performance Economic performance Minimum financial internal rate of return, debt-service Economic rate of return cover ratio, sensitivity Project maturity and location Dynamic production cost, economic rate of return, contribution to energy balance and grid stability Environmental and social performance Environmental and social performance Quality and compliance with IFC rules on environmental and social impact assessment and environmental and social action plan Quality and compliance with IFC rules on Resettlement Action Plan and livelihood restoration framework Technical and organizational performance Technical and organizational performance Feasibility of proposed site Quality of technical documentation Quality of technical documentation Project implementation timeline/expected commissioning date Project implementation timeline Price proposed per kilowatt-hour Maturity of project and financial package (70 percent of total score) Risk analysis Source: Compiled by the authors, based on various primary and secondary source data. Note: GETFiT = global energy transfer feed-in tariff; IFC = International Finance Corporation. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 251 applicable, a Resettlement Action Plan. An additional competitive tender was run in 2014 for solar PV projects with a maximum size of 5 MW. GETFiT also funded a secretariat supported by an implementation consultant. The secretariat ran the tenders and assessed bids with ultimate approval from an investment committee. By early 2015, GETFiT had confirmed support for a total of 15 projects with an accumulated capacity of 128 MW (table 10.8). Forty-one applications were received over three bid rounds.23 In January 2015, the third and last request for proposals (RfP) under the original GETFiT setup was launched. At the final GETFiT Investment Committee meeting in June 2015 a further six projects were approved although, because of funding constraints, just three small hydropower projects totaling 25 MW were to be set up: Nyamagasani I and II and Ndugutu. For the solar PV tenders, 24 candidates submitted expressions of interest, out of which 9 were short-listed and 7 submitted bids. Two developers were awarded two 5 MW projects each at a tariff of $0.164/kWh, substantially lower than the directly negotiated deals in Rwanda and Nigeria, which are above $0.25/kWh. Nevertheless, the Ugandan GETFiT PV prices are disappointing; they are twice the levels obtained in South Africa’s Renewable Energy Independent Power Project Procurement Programme (REIPPPP). Granted, the investment context in Uganda is very different from that of South Africa in terms of scale and risk, but the premium still seems high. Hopefully greater competition in subsequent rounds will drive prices lower. GETFiT was designed as a temporary facility and will likely be phased out. The idea was to stimulate the small-scale renewable energy market, initially through a premium payment but also by firming up the contractual framework and provid- ing confidence to investors. It remains to be seen whether further regular competi- tive tenders will be conducted by ERA after the withdrawal of donor support. Chinese-Funded Projects In February 2015, financing conditions for two large Chinese-funded projects had been approved by the Ugandan parliament.24 According to the PSIP, the third major hydropower scheme, Ayago (also 600 MW), is scheduled for launch in 2018. The bidding and award processes used for the Karuma and Isimba HPPs have taken various turns over the past two decades. The government’s plans for Karuma were revised many times before a decision was made sometime in 2009/10 to implement it as a public project. Initially listed as a PPP, Karuma had been under development by Norway’s Norpak Power Ltd. since the late 1990s, based on a 250 MW design. Norpak lost its exclusivity in 2008 after it failed to raise sufficient funds to advance the project beyond the feasibility stage.25 After the government decided to increase Karuma’s planned capacity to 600 MW and procure a new feasibility study, support from Western donors waned over concerns about the environmental impact of the project, which lies on the boundary of one of Uganda’s most pristine national parks. One additional com- ment frequently made by stakeholders has been the considerably larger “ticket size” (financing packages) offered by Chinese and other non-Western financiers, Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 252 Table 10.8  Overview of Approved GETFiT Projects, Uganda Total REFiT GETFiT Capacity investment cost (USc/ top-up Name (MW)a RET Developer/promoter (US$, millions) kWh) (USc/kWh) Equity/debt origin Nyamwamba 9.2 SHP SAEMS 26.8 8.5 1.4 SAEMS/FMO Rwimi 5.5 SHP Eco Power 20.8 9.8 1.4 Eco Power/BIO PH Industrial Biomass 1 Biomass gasification PH Industrial Farms 3.5 10.3 1 Shareholder/domestic commercial SAIL Cogen 11.9 (6.9) Bagasse cogeneration Sugar Allied Industries Ltd. 21.6 9.5 0.5 Shareholder/domestic commercial Kikagati 16 SHP TrønderEnergi 64.4 8.5 1.4 Norfund/EAIF Kakira Cogen extension 32 (20) Bagasse cogeneration Kakira Sugar Ltd. 60.7 9.5 0.5 Shareholder/domestic commercial Nengo Bridge 6.7 SHP Jacobsen 30 9.4 1.4 Jacobsen/EADB Muvumbe 6.5 SHP Vidullanka 14.1 9.4 1.4 Muvumbe/international commercial Lubilia 5.4 SHP DI Frontier 18.7 9.9 1.4 DI Frontier/FMO Siti I 6.1 SHP DI Frontier 14.8 9.6 1.4 DI Frontier/FMO Siti II 16.5 SHP DI Frontier 34 8.5 1.4 DI Frontier/FMO Sindila 5.2 SHP KMR Infrastructure 17.1 9.9 1.4 KMRI/OPIC Waki 4.8 SHP Hydromax Ltd. 18.11 10.1 1.4 Shareholder/PTA Tororo North/South 10 Solar Simba/Building Energy 18 11 5.3b Shareholder/shareholder Soroti I/II 10 Solar Access/TSK 18 11 5.3b Access/FMO Source: Compiled by the authors, based on various primary and secondary source data. Note: EADB = East African Development Bank; EAIF = Emerging Africa Infrastructure Fund; FMO = Netherlands Development Finance Company; GETFiT = global energy transfer feed-in tariff; kWh = kilowatt-hour; MW = megawatt; OPIC = Overseas Private Investment Corporation; PTA = Preferential Trade Area Bank; REFiT = renewable energy feed-in tariff; RET = renewable energy technology; SAEMS = South Asia Energy Management Systems; SHP = small hydropower plant; USc = U.S. cent. a. For plants with captive use (bagasse), only the generation capacity available to the grid will be supported through GETFiT premiums. b. Average top-up. Case Study 5: Power Generation Developments in Uganda 253 which exceed the maximum loan amounts available from international financial institutions. The tedious coordination efforts and transaction costs occasioned by the multitude of financiers involved in the Bujagali HPP project apparently had left a lasting impression on Ugandan government officials. Once the new consultant submitted the revised studies for Karuma, the MEMD implemented a new procurement process on the basis of a public EPC model, including project financing.26 The MEMD, following the provisions of the Public Procurement and Disposal of Public Assets (PPDA) Act, established evaluation and contract committees, both staffed solely with senior officials from the MEMD and other sector institutions. Although the PPDA Act generally offers comprehensive guidelines for conducting public procurement, the highly politicized process soon ran aground after allegations of bribery and violation of the guidelines surfaced.27 As a result, in September 2012 the PPDA Authority, and subsequently the Inspectorate General of Government (IGG), called, in March 2013, for a halt to the process, called for a review, and opened investiga- tions. Its report identified various violations of procurement regulations.28 Although Uganda’s High Court confirmed a violation of procurement guidelines assessed by the PPDA Authority in November 2012,29 the tender process con- tinued after a short interruption with a reevaluation of the technical bids. CWE of China again emerged as the best-qualified bidder. However, the procurement process had lost all public credibility and was effectively suspended. Confronted with the impasse, President Yoweri Museveni utilized the occa- sion of the 2013 Durban, South Africa, BRICS30 conference and a meeting with Chinese president Xi Jinping to award the Karuma HPP to Sinohydro and the Isimba HPP to CWE. For both projects, the China ExIm Bank committed, in principle, the required debt financing. Awarding the Isimba HPP at this point in time surprised many donors and DFIs. However, the prospect of receiving an attractive financing deal for both projects from the China ExIm Bank swayed the government.31 As appealing as the deal may have been, its acceptance may have not been in compliance with Ugandan law, in particular with the PPDA Act.32 In early 2014, the final financing conditions for both projects were presented to the Ugandan parliament, which approved the $1.4 billion loan agreement for Karuma in March 2015. The deal specified that the government would provide a 15 percent advance equity investment (amounting to $253 million for Karuma), which the contractors used to kick off preliminary works. Funds came from the dedicated reserves that the government had earmarked and accumu- lated since 2007. Loan repayments will be made through electricity payments under a still- to-be-concluded PPA with UETCL. Payments will be backed by the government through separate guarantee agreements, as for the Bujagali HPP. At the time of this writing, details of the contractual arrangements were still under discussion. However, the Ugandan government and ExIm Bank of China have agreed on a capacity payment basis for both projects. Effective tariff levels for Isimba and Karuma were not presented to the public. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 254 Case Study 5: Power Generation Developments in Uganda Karuma HHP The ExIm Bank of China is providing financing for the Karuma HPP in the amount of $1.437 billion (85 percent of the total funding required)—see table 10.9). Forty-five percent of the loan amount will take the form of an export buy- ers’ credit (a commercial loan) at an annual interest rate equal to the LIBOR33 plus 3.5 percent, with a repayment period of 15 years and a five-year grace period. The lender will assess a one-time management fee of 0.75 percent and a commitment fee of 0.5 percent of the loan amount. The terms include the cost of loan insurance. Fifty-five percent of the loan amount will be in the form of a “preferential export-based credit.” The repayment period is 20 years, with a 5-year grace period. The interest rate is 2 percent per year. The lender will assess a one-time management fee of 1 percent and a commitment fee of 0.75 percent. Isimba HHP The ExIm Bank of China, through its preferential export buyers’ credit win- dow, is providing financing for the Isimba HPP in the amount of $482.2 mil- lion (85 percent of the total funding required) at an annual interest rate of 2 percent over a period of 20 years, with a 5-year grace period (table 10.10). Table 10.9  Karuma HPP Project Data, Uganda Installed capacity 600 MW Estimated total cost $1.6 billion, including interconnection Estimated cost per megawatt $2.34 milliona Engineering, procurement, and construction Sinohydro Commitment of Ugandan government 15 percent of total costs; guarantee agreement Funding source ExIm Bank of China Expected date of entry into commercial operation 2019 Source: Compiled by the authors, based on various primary and secondary source data. Note: HPP = hydropower plant; MW = megawatt. a. This figure assumes construction costs of $1,400 million for the Karuma HPP, and $200 million to build the required high-voltage grid infrastructure. Table 10.10  Isimba HPP Project Data, Uganda Installed capacity 183 MW Estimated total cost $570 million, including interconnection Estimated cost per megawatt $3 milliona Engineering, procurement, and construction CWE (subcontracting to Sinohydro) Commitment of Ugandan government 15 percent of total costs; guarantee agreement Funding source (and amount) ExIm Bank of China ($482.2 million) Expected date of entry into commercial operation 2018 Source: Compiled by the authors, based on various primary and secondary source data. Note: HPP = hydropower plant; MW = megawatt. a. This figure assumes construction costs of $550 million for Isimba HPP. In comparison with the Karuma HPP, this project will require significantly less expenditure for power evacuation owing to its proximity to the Bujagali HPP. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 255 The lender is charging a one-time management fee of 1 percent of the loan amount and a commitment fee of 0.75 percent. Concerns remain about the project’s compliance with applicable international environmental and social safeguards. Ayago HHP Ayago HPP, another major Nile-based hydropower project, located in the vicin- ity of Murchison Falls National Park, had long been promoted by Japanese developers—the Electric Power Development Company Ltd. (J-Power) and ­ Nippon Koei Co. Ltd.—supported by the Japan International Cooperation Agency (JICA). After a prefeasibility study was submitted to the MEMD, the Ugandan government, in April 2013, signed a memorandum of understanding (MoU) with the Mapa Construction Company, a Turkish infrastructure conglom- erate. Subsequently, Japanese support for the project ceased.34 After negotiations with the Turkish developer reached an impasse (owing to a $1.9 billion price tag and the denial of a sovereign guarantee), this developer, too, abandoned the project. In late 2013, the Ugandan government awarded the EPC contract for Ayago HPP to China Gezhouba Group for a price of $1.6 billion (table 10.11). In early 2015, financing arrangements for the project were still under discus- sion with the ExIm Bank of China. Compared with the swift conclusion of the financing arrangements for the Karuma and Isimba HPPs, progress on Ayago has been slow. This may be due to the government’s initial plan to implement the three major hydropower projects in staged phases. Others have pointed to the large risk exposure of the ExIm Bank of China to the Ugandan energy sector. Alternatively, given the current dip in demand growth, some doubts may have emerged about whether demand would be sufficient for the 1,000 MW under implementation. If that is true, projects situated in environmentally sensitive areas may be delayed. Finally, Uganda has not yet fully incorporated ­ opportunities for energy imports through the Eastern Africa Power Pool (EAPP) into sector planning and practice. Once relevant infrastructure is built between Ethiopia, Kenya, and Uganda, imported electricity may become a cost-competi- tive solution. Table 10.11  Ayago HPP Project Data, Uganda Installed capacity 600 MW Estimated total cost $1.6 billion, including interconnection Estimated cost per megawatt $2.67 million Engineering and construction China Gezhouba Group Commitment of Ugandan government To be confirmed Funding source ExIm Bank of China Expected date of entry into commercial operation To be confirmed Source: Compiled by the authors, based on various primary and secondary source data. Note: HPP = hydropower plant; MW = megawatt. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 256 Case Study 5: Power Generation Developments in Uganda Measuring the Outcomes This section compares the results obtained from international competitive bid- ding, directly negotiated projects, FiTs, and the recent Chinese-funded projects. In general, it can be said that the government has been successful in achieving its development goals for the power generation sector. With close to 1,000 MW under implementation or in later feasibility stages, capacity under development has multiplied within a short time frame of three years. Uganda has also managed to develop a mix of public projects financed by Chinese sources and privately financed small-scale IPP projects, a mix that is unique in Sub-Saharan Africa. The late 2000s were shaped by the need to attract international investment to replace costly diesel-based generation and to avert the financial demise of the energy sector. The facilitation of small-scale RET projects and the implementa- tion of the GETFiT program were based on a desire to mitigate the interim sup- ply shortages expected to emerge in 2015. Since the commissioning of the Bujagali HPP in 2012, pressures on the Ugandan government have eased notice- ably—albeit only on the supply side, not the consumer tariff side. Since then, the sector strategy seems to have consolidated, and more forward-looking policies are reflected in decision making. Procurement Approaches: A Shift in Policy The Ugandan government intends to follow a two-pronged policy for procuring generation capacity in the years to come. For large-scale projects, international competitive bidding seems to have been abandoned in favor of direct awards to international—effectively Chinese—contractors. On the other end of the scale, targeted policies (promoted in particular by ERA) aim to further encourage for- eign investment in IPP projects involving all types of generation from small to medium scale.35 The government has utilized the full spectrum of procurement approaches over the past 15 years (table 10.12). With the current uptake in small-scale RET development facilitated by the GETFiT support mechanism, up to 15 REFiT and Table 10.12  Summary of Procurement Models Used since the Sector Reform of 1999/2000, Uganda International competitive bidding Direct award Unsolicited bids Lugogo (emergency diesel) Kiira (HPP) Kakira Sugar (bagasse)a Namanve (emergency HFO) Kiira (emergency diesel) Kinyara Sugar (bagasse)b Bujagali (HPP) Mutundwe (emergency diesel) Bugoye (SHP)b Karuma (HPP) Tororo (emergency HFO)b Isimba (HPP) Mpanga (SHP)b Ishasha (SHP)b Buseruka (SHP)b Source: Compiled by the authors, based on various primary and secondary source data. Note: HFO = heavy fuel oil; HPP = hydropower plant; SHP = small hydropower plant. a. The first and second power purchase agreements were individually negotiated, and the third occurred under the renewable energy feed-in tariff (REFiT), with global energy transfer feed-in tariff (GETFiT) support. b. Individually negotiated tariff. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 257 2 competitively bid projects will complete the picture. Some aspects of the country’s procurement methods, in particular the abandonment of international ­ competitive bidding in favor of direct awards for large hydropower, merit further analysis and consideration. The Case for the Direct Award of the Karuma and Isimba Projects Whereas the ICB process is regulated by legislation, in particular the PPDA Act, the direct award of contracts such as utility-scale hydropower projects has no specific legal foundation. The Ugandan government has therefore achieved its objective of setting up large projects of critical importance to the security of the nation’s energy supply. Only six months passed between the awards and the first steps by the EPC contractors toward final design studies. Another six months later, after the provision of a substantial advance payment by the government, the projects are in early stages of construction. For the time being, ICB and IPP are perceived by the government of Uganda as too costly and time consuming for large-scale projects. Public and government perceptions have been shaped—understandably, but nevertheless erroneously— by unfavorable comparisons of the government-owned Nalubaale and Kiira with the privately sponsored Bujagali HPP, in particular, with regard to cost and imple- mentation timelines. The Argument for Lower Costs Whereas these projects sell electricity to the UETCL at an estimated $0.012, Bujagali-generated electricity is bought at roughly USc 10 more. There is little appreciation that the costs of Nalubaale and Kiira are fully amortized or that the tariffs approximate short-run, rather than long-run marginal costs. For the Karuma and Isimba HPPs, the government publicly communicates an expected tariff range of USc 4–6/kWh. Representatives of development partners, as well as the private sector, have questioned these numbers, and a closer look at current cost estimates and the financing conditions under discussion do not immediately bear out the government’s expectations. At $3.44 million/MW, the Bujagali HPP certainly ranks among the more expensive projects of its scale in the world (IRENA 2012). Karuma’s likely cost is estimated at $2.33 million/MW, whereas Isimba’s, at $3 million/MW, is close to Bujagali’s. The government argues that final costs for public projects will be lower owing to lower transaction costs between lenders and, as government offi- cials have recently maintained, the “hidden cost” or “financing premium” of pri- vate investment—the suggestion being that private investors seek a higher return than the currently favored alternatives. Overall, it is too early to support or reject the government’s stance, and it remains to be seen whether actual costs match the projections. Neither Karuma nor Isimba has reached formal financial close, which indicates that the govern- ment’s equity contribution or some other aspect of the financing arrangements may still be altered to the disadvantage of the Ugandan government and consum- ers. Furthermore, frequent cost overruns for large hydropower projects mean that Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 258 Case Study 5: Power Generation Developments in Uganda the attractiveness of these projects is more likely to diminish than to improve. Ultimately what counts is the contracted tariff, which still has to be revealed. The government’s cost argument for pursuing direct awards may turn out to be built on sand. Meanwhile, the lack of transparency surrounding the award and the related negotiation process create the risk that the final total costs of the two projects may be inflated by illicit money flows. The ICB/IPP approach was arguably more beneficial for the national budget, at least in the short term. For the Chinese-promoted projects, the govern- ment had to make an advance payment of roughly $320 million (equivalent to 15 percent of estimated total project costs); its equity contribution for the Bujagali HPP was only $20 million (or 2.3 percent of the total cost). Although dedicated reserves for this investment had been accumulated over the past years, this significant capital expenditure is no longer available for other strategic investments in the energy sector. The Argument for Shorter Implementation Timelines The other main argument presented for direct awards is their comparatively shorter implementation timelines. The full procurement cycle for the Bujagali HPP is said to have taken more than 12 years. In contrast, the implementation of the similar-sized Kiira HPP in the early 2000s is recorded—inaccurately—as hav- ing proceeded without complication or delay. If the Karuma and Isimba projects took six years from award to expected ­ commission, a transparent international competitive bidding procurement process that conforms to all (international) legalities and formalities cannot compete.36 Several major factors cause delay in ICBs: • An ICB process can effectively encompass up to three consecutive procure- ments: (1) developer/investor, (2) EPC, and (3) O&M provider. • An ICB is more sensitive and prone to interference by external actors. As illus- trated by the first Karuma procurement attempt, in an imperfect procurement environment and absent clear judicial procedures and remedies, this can easily lead to an impasse in procurement and thus to delays • The time required for coordination among a multitude of commercial and development finance institutions, along with associated transaction costs, has been named as a serious disadvantage by Ugandan stakeholders. • If they apply, international high standards for environmental and social sus- tainability require substantive baseline studies and implementation schemes that are, in contrast to domestic environmental legislation, time consuming. With specific reference to the two latter points, officials of the Ugandan govern- ment speak frankly about a “lesson learned” from the Bujagali HPP procurement. And, indeed, lengthy and expensive investor arrangements and delays occasioned by protracted environmental studies at a time when Uganda was relying on costly thermal power have justifiably caused lasting grievances among officials. At first glance, therefore, the decision for direct awards would seem to be based on sound Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 259 facts and judgment, particularly if one takes into account the recent international competitive bidding experience around the Karuma HPP. It is possible that international competitive bidding per se was not the cause of the failure, but rather the institutional arrangements made for its implementa- tion, especially the exclusion of external experts from the procurement process and decision-making bodies. Furthermore, Ugandan government officials seem to forget that the first failed attempt to implement the Bujagali HPP was the result of a flawed direct-award process, which in the end had to be aborted after illicit money flows and corruption came to light. At the time of writing, the direct award of the Karuma and Isimba HPPs may result in a gain of about two years in comparison with Bujagali. Present delays in reaching financial close may yet shrink that gain. Construction delays may shrink it further. The Future of Private Sector Investment and of Thermal and RET Project Development President Museveni and numerous officials now often publicly discourage private sector involvement in the energy sector.37 In so doing, they effectively negate the impressive development of the Ugandan private sector in the last decade. With good reason, investors rank Uganda as one of the top destinations worldwide for private sector investment in RET (BNEF 2014). With regard to thermal-based power generation, by contrast, the near-term prospects for the private sector do not seem as bright. The Legacy of the Sector Crisis With existing emergency thermal capacity only occasionally dispatched and unre- liable government payments for the availability of Namanve and Tororo, there are few incentives for additional international investment into thermal power. The current balance of demand and supply, coupled with lower-than-expected growth in demand, has contributed to a deterioration of the business case for expensive thermal power. With tariffs ranging from $0.23 to $0.30/kWh, thermal-based power is not competitive. Moreover, in the wake of the sector crises of the late 2000s, the government, jointly with development coopera- tion partners, has taken steps to avoid the need for installation of additional thermal-based power plants. With an estimated additional generation capacity of 170 MW facilitated through the GETFiT program, which will come on-grid between 2015 and 2018, the likelihood of dispatch of (additional) thermal power has been brought close to zero. Nevertheless, future market opportunities for thermal power could arise as a consequence of petroleum exploitation in Uganda. Once commercial operations have started, residual gas or, if the envisaged refinery is built, residual heavy fuel could generate a business case for promoters of thermal power plants. Yet recent media reports suggest that the commencement of oil exploitation may well be postponed beyond 2018. The thermal power sector will likely remain dormant for some years to come. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 260 Case Study 5: Power Generation Developments in Uganda In the past, the government has utilized a range of procurement methodolo- gies, from direct awards to “pure” IPP-promoted, unsolicited bids. The outcomes of these arrangements are inconclusive, as tariffs were heavily influenced by externalities such as fuel prices, fuel sources, and the government’s decreasing dependency on thermal power, among other factors. Across the various procure- ment processes tariff levels declined without any discernible connection to pro- curement type. The Rise of Small-Scale RET Projects Since the first IPP projects were commissioned in the late 2000s, the RET sector has undergone a remarkable evolution. At the time of writing, in addition to the four assets already operational, more than 15 RET projects across various genera- tion types are in their late feasibility stages and approaching financial close and implementation. The reasons for these developments are multifaceted, but some core lessons are clear. Until 2012, sectoral arrangements and contractual conditions were directly negotiated between ERA, the UETCL, and the MEMD, resulting in high trans- action costs and comparably high tariff levels. These projects reflected an energy sector in transition, characterized by grant support through develop- ment cooperation, varying tariff arrangements, and divergent provisions in PPAs and governmental guarantees. All tariffs effectively agreed upon by ERA between 2008 and 2012 went significantly beyond the then-applicable REFiT levels introduced in the 2007 Renewable Energy Policy,38 which, as previously indicated, had ­ purposefully been set low to shield the end-user tariff from price impacts. Since 2012, the Ugandan government and its entities, notably ERA, have enhanced and complemented the existing policy on private investment in renew- able energy by addressing regulatory shortfalls. The government and ERA have understood the need for investment security in the face of high up-front capital expenditures for RET project development and long return timelines. While some of these enhancements can certainly be attributed to the government’s cooperation with the GETFiT program, other key requirements for a successful IPP environment were promoted at the government’s and ERA’s own discretion. The 2012 interconnection policy, which recognized the government’s responsi- bility to provide a grid connection for REFiT projects, is a noteworthy example. Furthermore, the establishment of the joint interconnection task force in 2014 to address the cumulative effects of decentralized generation and the integration of RET projects has further increased investor confidence. In the facilitation of small-scale RET, ERA has demonstrated regulatory flex- ibility in the implementation of suitable incentivizing mechanisms. This has been achieved by opening the sector to competitive bidding structures for different RET types in cooperation with the GETFiT program. Two approaches have been taken. First, for small hydropower, biomass, and bagasse, ERA and GETFiT have introduced a hybrid system of REFiT and top-up payments, with a competitive tender procedure. As previously presented, projects are evaluated by an external Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 261 appraisal team and ranked according to their overall quality, the capacity of the developer, and the level of project preparedness. As an outcome, an external expert team effectively supports ERA in selecting the most promising and advanced projects eligible for the REFiT. Simultaneously, this external expertise has further sparked investor interest in the Ugandan project pipeline and made it significantly easier for investors to attract financing. The second procurement approach introduced a price-competitive compo- nent into the general project selection process, enabling ERA to include solar PV in the power generation mix. This methodology was adopted to reflect the level- ized cost of solar PV, which presently is not easily quantified. For the time being, price-competitive bidding has been implemented only for solar PV, but the Electricity Act (1999) generally allows competitive bidding across all technolo- gies. In the future, a similar approach might be used to harness wind or biomass resources. Other instruments to facilitate project-financed RET projects complemented the incentivizing frameworks. Examples include standardized legal agreements and the mitigation of off-taker risks through a sovereign guarantee and the World Bank PRG program. Most important, however, the Ugandan government and ERA have understood the need for cohesiveness in policy and frameworks, as well as the importance of transparency and reliability. If Uganda firmly pursues its current path, it is well positioned to become a model for RET facilitation in Sub-Saharan Africa. Notes 1. The following section draws heavily (and with permission) from Kapika and Eberhard (2013). 2. The UEB was not able to finance investments or service debts and was thus financially dependent on government support. Collection rates were as low as 50 percent; loss rates exceeded 30 percent. Less than 5 percent of Uganda’s population had access to electricity. 3. The full name of the plan was the Ugandan Power Sector Restructuring and Privatisation: New Strategy Plan and Implementation Plan, Government of Uganda, 1999. 4. Umeme’s shareholders were Globeleq (56 percent) and Eskom Enterprises (44 percent). Eskom Enterprises exited at this stage, with Globeleq the sole remaining 5. shareholder. 6. http://uk.reuters.com/article/2012/01/12/uganda-electricity-subsidy-idUKL6E8CC2​ D120120112, last accessed February 1, 2015. 7. In some regards, the period between 2005 and 2012 also produced positive outcomes: for example, the doubling of electricity connections and available generation capacity, which effectively exceeded the increase seen in the years 1950 until the initialization of the 1998 reforms. Furthermore, the improvements in loss and collection rates gen- erated stable money flows between sector actors and enabled UETCL and Umeme to further rehabilitate and expand electricity infrastructure (USAID 2013). Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 262 Case Study 5: Power Generation Developments in Uganda 8. Incentives to invest in new generation capacities could arguably be boosted by increas- ing end-user tariffs as in 2012. However, the political and sectoral environment is currently not favorable for such measures. In the context of the 2016 elections, government has repeatedly declared that it intends to reduce end-user tariffs ­ ­ particularly for industrial consumers. 9. http://www.getfit-uganda.org/, accessed February 1, 2015. 10. http://global-climatescope.org/en/, accessed February 1, 2015. 11. All inclusive of interest during construction. Interestingly, the Power Sector Investment Plan (PSIP) already lists the Isimba hydropower plant as a public project, long before the IPP or PPP approach had been publicly dismissed by the government. 12. With a total final price of $300 million (installation + capacity payments), the Kiira 50 MW plant was four times as expensive as Aggreko’s plant in Rwanda at $74 million and twice as expensive as the $160 million for the Lugogo 50 MW. Furthermore, stake- holders and observers characterized the procurement process “as rushed and shrouded in secrecy,” which led the World Bank to pull out and instead provide IDA support for the $206 million Mutundwe plant, which was commissioned in 2008 (http://www​ .theeastafrican.co.ke/news/EAC-foots-huge-energy-bill-as--thermal​-plants-have-a​ -field-day/-/2558/1226360/-/7dtern/-/index.html, accessed February 1, 2015). 13. http://www.getfit-uganda.org/information-for-developers/get-fit-solar-facility-eoi/, accessed February 1, 2015. 14. For small hydropower and bagasse in 2013. 15. Under the EPC model, the government or public utility hires a private firm to build the plant, but ownership resides with the state. This is distinctly not an IPP, where the utility purchases electricity from a private firm that builds, owns, and operates the power plant in question. 16. The direct awards of the Karuma, Isimba, and Ayago HPPs may not be in line with the Public Procurement and Disposal of Public Assets Act (PPDA, 2003). In this act, which defines the rules of procurement for public entities, direct awards are lawful only in specified circumstances. Section 85 of the PPDA stipulates: “(1) Direct pro- curement or disposal is a sole source procurement or disposal method for procure- ment or disposal requirements where exceptional circumstances prevent the use of competition; (2) Direct procurement or disposal shall be used to achieve efficient and timely procurement or disposal, where the circumstances do not permit a competitive method.” Due to the existing energy surplus at the time of the award, it can hardly be argued that circumstances did not permit a competitive tender. 17. Electricity Regulatory Authority, personal communication, November 2014. 18. Other public projects funded and implemented in cooperation with Chinese investors and contractors are dealt with in the section on Chinese-funded projects. 19. The Nalubaale and Kiira HPPs have the capacity of running a higher peak capacity, but 220 MW has been chosen to match the 800 cubic meters per second (m3/s) aver- age release from Lake Victoria (140 MW) that is currently permitted and the current plant factor of 62 percent (data from May 2012–February 2013). 20. The 1929 Nile Waters Agreement, amended in 1953, was concluded between Egypt and Great Britain, which represented its then-protectorate, Uganda. The agreement stipulates that no works are to be undertaken on the Nile, its tributaries, or the Lake Basin that would reduce the volume of water reaching Egypt. These agreements are currently being challenged by Ugandan officials claiming that Uganda was not Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Case Study 5: Power Generation Developments in Uganda 263 effectively represented at the conclusion of this agreement and cannot be bound to supranational legal acts of the British colonial government. However, it seems that Uganda confirmed commitment to the 1953 agreement in a bilateral memorandum of understanding in 1991. 21. GETFiT Uganda is supported by the United Kingdom (through the Department for International Development [DfID]/Department of Energy and Climate Change [DECC]), Norway, Germany, and the European Union’s Infrastructure Trust Fund. It also cooperates with a World Bank partial risk guarantee facility. http://www.getfit​ -uganda.org/, accessed February 1, 2015. 22. No IPP that reached financial close between 2007 and 2012 utilized the Ugandan renewable energy feed-in tariff (REFiT), but tariff levels were individually negotiated between the developer or sponsor and ERA, the UETCL, and the MEMD. 23. Fifteen bids were submitted in round 1; 8 in round 2; and 18 in round 3. GETFiT policy allows rejected projects to apply again. Overall, more than 30 projects applied. 24. Financial close for the Karuma and Isimba HPPs, following parliamentary approval of their financing conditions, is still a matter of debate. Whereas some representatives of the MEMD claim the deal is “sealed,” other sector stakeholders and development partners have not been informed of the final decision. The 2014 Sector Performance Report also does not announce the conclusion of the financing agreement. One remaining point of discussion is allegedly the collateral demanded for the loans made by the China ExIm Bank. That collateral is in the form of future oil revenues. 25. http://www.newvision.co.ug/D/8/21/655225, accessed February 1, 2015. 26. Before this time, procedures primarily prescribed by multilateral financing institutions had been utilized, as exemplified in the case of Bujagali. 27. http://www.independent.co.ug/cover-story/7709-chinese-firm-warns-uganda-on​ -karuma?format=pdf, accessed February 1, 2015. 28. According to media reports, the bidder, CWE, had unduly relied on capacities and guarantees of its parent company, Three Gorges Hydro, and made false statements regarding reference projects. 29. Another chamber of the High Court found no violations of procurement procedures. In late 2014, the case was still pending before the East African Court of Justice, an organ of the East African Community. 30. Brazil, Russian Federation, India, China, and South Africa. 31. Personal communication. 32. http://allafrica.com/stories/201310070369.html, accessed February 1, 2015. 33. London Interbank Offered Rate. 34. The JICA and the Japanese developers’ consortium cited environmental concerns as their reasons for renouncing the project. While these (valid) concerns may have contrib- uted to the decision, it seems apparent that the government’s involvement of another developer led to frustrated expectations and, consequently, the decision to abandon. 35. A third possible pillar for future project implementation is suggested by the recently initiated PPP projects, Muzizi and Nyagak III. At the time of writing, however, it is too early to say whether PPPs will become a steady part of Uganda’s approach to capacity procurement. 36. A time frame of six years obviously excludes the time “lost” during the preceding struggle to make an award following the international competitive bidding process. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 264 Case Study 5: Power Generation Developments in Uganda 37. http://www.wsj.com/articles/privately-funded-electricity-too-expensive-for-uganda​ -president-says-1413827013, accessed February 1, 2015. 38. $0.589 for hydro and $0.596 for bagasse projects. References BNEF (Bloomberg New Energy Finance). 2014. “Climatescope 2014.” http://global​ climatescope.org/en/. Last accessed February 1, 2015. -­ Dhalla, G. 2011. Performance of the Ugandan Power Sector to 2017. Report submitted to the Ministry of Energy and Mineral Resources, Kampala. Government of Uganda. 2010. “National Development Plan 2010/11–2014/15.” http:// opm.go.ug/assets/media/resources/30/National%20Development%20Plan%202010:​ 11%20-%202014:15.pdf. Last accessed February 1, 2015. IRENA (International Renewable Energy Agency). 2012. Renewable Energy Technologies: Cost Analysis Series, Volume 1, Hydropower. Abu Dhabi: IRENA. Kapika, J., and A. Eberhard. 2013. Power-Sector Reform and Regulation in Africa: Lessons from Kenya, Tanzania, Uganda, Zambia, Namibia and Ghana. Cape Town: Human Sciences Research Council Press. MEMD (Ministry of Energy and Mineral Development). 2011. “Power Sector Investment Plan.” Prepared by Parsons Brinckerhoff, MEMD, Kampala. SE4ALL. 2012. “Uganda Country Profile.” Kampala. http://www.se4all.org/wp-content​ /­uploads/2014/01/Uganda-Country-Profile.pdf. USAID (U.S. Agency for International Development). 2013. Africa Infrastructure Program, Uganda Power Sector Assessment Report. Washington, DC: USAID. World Bank. 2014. Implementation Completion and Results Report 92996-UG. Component E Under Privatisation and Utility Sector Reform Project, Support to Umeme Ltd. Washington, DC: World Bank. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 A ppendi x A Total Investments in Electric Power Generation in Sub-Saharan Africa Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   265   266 Table A.1  Total Annual Investments in Electric Power Generation, by Country or Territory: Sub-Saharan Africa, 1990–2014 US$, millions Cumulative, Country or territory 1990–2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Angola — — — 45.0 — — — — — — — — — — 163.2 Benin — — — — — — — — — — — — — — — Botswana — — — — — — — — — 1,252.0 — — — — — Burkina Faso — — — — — — — — — — — — — — — Burundi — — — — — — — — — — — — — — — Cabo Verde — — — — — — — — 6.6 — 80.0 — — — — Cameroon — — — — — — — — — 126.0 342.0 637.0 — — — Canary Islands — — — — — — — — — — — — — — — Central African Republic — — — — — — — — — — — 25.0 — — — Ceuta — — — — — — — — — — — — — — — Chad — — — — — — — — — — — — — — — Comoros — — — — — — — — — — — — — — — Congo, Dem. Rep. — — — — — — — — — 341.0 — 367.5 — — 40.3 Congo, Rep. — — — — — — — — — — — — — — — Côte d’Ivoire 465.0 — — — — — — — — 134.0 — — 571.0 341.0 — Djibouti 14.8 — — 9.9 18.9 — — — — — — — — — — Equatorial Guinea — — — — — — — — — — 356.6 — — — — Eritrea 17.0 — 68.8 — — — — — — — — — — — — Ethiopia 233.0 — — — — 324.0 — — — 244.5 — 123.0 951.0 — 420.3 Gabon — — — — — — — — — — 398.0 — — — — Gambia, The — — — — — 36.2 — — — — — — — — — Ghana 411.3 — — — — — — 200.0 — 761.0 — — — 330.0 — table continues next page Table A.1  Total Annual Investments in Electric Power Generation, by Country or Territory: Sub-Saharan Africa, 1990–2014 (continued) US$, millions Cumulative, Country or territory 1990–2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Guinea 107.3 — — — — — — — — — 446.2 — — — — Guinea-Bissau — — — — — — — — — — — — — — — Kenya 333.7 — — — — — — 51.1 205.0 188.5 — 126.2 284.0 258.0 900.0 Lesotho — — — — — — — — — — — — — — — Liberia — — — — — — — — — — — — — — 12.8 Madagascar 92.0 — — — — 23.1 — 17.8 — — — — — — — Madeira — — — — — — — — — — — — — — — Malawi — — — — — — — — — — — — — — — Mali 144.4 — — — — — — — — — — — — 467.0 — Mauritania — — — — 23.8 — — — — — — — — — — Mauritius 317.4 — — — 95.2 120.4 — — — — — — — — — Mayotte — — — — — — — — — — — — — — — Melilla — — — — — — — — — — — — — — — Mozambique — — — — — — — — — — — — — — — Namibia — — — — — — — — — — — — — — — Niger — — — — — — — — 125.0 — — 20.5 — — — Nigeria — 240.0 1,182.7 — — — — — 540.0 — 660.0 — — 1,753.0 — Réunion — — — — — — — — — — — — — — — Rwanda — — — — — — — — — — — 200.0 — — — Saint Helena — — — — — — — — — — — — — — — São Tomé and Príncipe — — — — — — — — — — — — — — — Senegal 65.0 — — — — 110.0 — — — — 22.0 — — 254.3 163.5 table continues next page 267 268 Table A.1  Total Annual Investments in Electric Power Generation, by Country or Territory: Sub-Saharan Africa, 1990–2014 (continued) US$, millions Cumulative, Country or territory 1990–2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Seychelles — — — — — — — — — — — — — — — Sierra Leone 204.1 — — — 33.0 — 15.0 — 35.4 — 1.6 30.0 — — — Somalia — — — — — — — — — — — — — — — South Africa — — — — — 13.7 9.9 — — — 3,076.5 — 6,164.4 4,213.8 3,405.4 Sudan — 300.0 — — 1,071.4 221.5 — — 361.0 87.0 — — — — — Swaziland — — — — — — — — — — — — — — — Tanzania 127.2 316.0 — — — 32.0 123.2 — — — — — — — — Togo — — — — — — — — 196.0 — — — — — 308.0 Uganda 274.0 — — 56.0 — — 56.0 860.0 180.7 97.5 — — 41.5 — 1,688.4 Western Sahara — — — — — — — — — — — — — — — Zambia — — — — — — — — — 279.0 — — 72.0 — 821.5 Zimbabwe — — — — — — — — — — — — — 389.0 — Total 2,806.2 856.0 1,251.5 110.9 1,242.4 880.9 204.1 1,128.9 1,649.6 3,510.5 5,382.9 1,529.2 8,083.9 8,006.1 8,875.6 Total without South Africa 2,806.2 856.0 1,251.5 110.9 1,242.4 867.2 194.2 1,128.9 1,649.6 3,510.5 2,306.4 1,529.2 1,919.5 3,792.3 5,470.2 Sources: IPP and China investment totals are based on extensive primary and secondary source data (including the Private Participation in Infrastructure database, AidData, and direct correspondence with country and project contacts). ODA, concessionary DFI/MFI, and Arab funding have been sourced by AidData (for which OECD data are a reference point) and cross-checked with secondary sources. The authors have also actively engaged with researchers at both AidData, OECD, and those involved in AICD. Note: ODA is defined as those flows to countries and territories on the DAC List of ODA Recipients (available at http://www.oecd.org/dac/stats/daclist.htm) and to multilateral development institutions which are provided by official agencies, including state and local governments, or by their executive agencies. AICD = Africa Infrastructure Country Diagnostic; DAC = Development Assistance Committee; DFI = development finance institution; IPPs = independent power projects; MFI = multilateral finance institution; ODA = official development assistance; OECD = Organisation for Economic Co-operation and Development. “—” indicates 0 investment. Table A.2  Total Annual Investments in Electric Power Generation, by Source of Funding: Sub-Saharan Africa, 1990–2013 US$, millions Source of Cumulative, funding 1990–2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 IPPs 1,427.4 556.0 462.0 101.0 95.2 312.3 189.1 1,077.8 1,121.7 686.0 843.0 356.2 6,561.9 5,857.1 ODA (OECD) 295.4 — — — — 324.0 — 51.1 18.0 58.5 — — — — DFI 947.6 — 18.0 9.9 530.7 13.0 15.0 — 129.0 282.0 2,679.1 — — — Arab flows 135.6 — 50.8 — 616.4 10.1 — — 381.0 — — 20.5 — — China flows — 300.0 720.7 — — 221.5 — — — 2,484.0 1,860.8 1,152.5 1,522.0 2,149.0 Sources: IPP and China investment totals are based on extensive primary and secondary source data (including the Private Participation in Infrastructure database, AidData, and direct correspondence with country and project contacts). ODA, concessionary DFI/MFI, and Arab funding have been sourced by AidData (for which OECD data are a reference point) and cross-checked with secondary sources. The authors have also actively engaged with researchers at both AidData, OECD, and those involved in AICD. Note: ODA is defined as those flows to countries and territories on the DAC List of ODA Recipients (available at http://www.oecd.org​ /dac/stats/daclist.htm) and to multilateral development institutions which are provided by official agencies, including state and local governments, or by their executive agencies. AICD = Africa Infrastructure Country Diagnostic; DAC = Development Assistance Committee; DFI = development finance institution; IPPs = independent power projects; MFI = multilateral finance institution; ODA = official development assistance; OECD = Organisation for Economic Co-operation and Development. “—” indicates 0 investment. 269 270 Table A.3  Total Annual Investments in Electric Power Generation, by Source of Funding: Sub-Saharan Africa (Excluding South Africa), 1990–2013 US$, millions Source of Cumulative, funding 1990–2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 IPPs 1,427.4 556.0 462.0 101.0 95.2 298.6 179.2 1,077.8 1,121.7 686.0 444.0 356.2 397.5 1,643.3 ODA (OECD) 295.4 — — — — 324.0 — 51.1 18.0 58.5 — — — — DFI 947.6 — 18.0 9.9 530.7 13.0 15.0 — 129.0 282.0 1.6 — — — Arab flows 135.6 — 50.8 — 616.4 10.1 — — 381.0 — — 20.5 — — China flows — 300.0 720.7 — — 221.5 — — — 2,484.0 1,860.8 1,152.5 1,522.0 2,149.0 Sources: IPP and China investment totals are based on extensive primary and secondary source data (including the Private Participation in Infrastructure database, AidData, and direct correspondence with country and project contacts). ODA, concessionary DFI/MFI, and Arab funding have been sourced by AidData (for which OECD data are a reference point) and cross-checked with secondary sources. The authors have also actively engaged with researchers at both AidData, OECD, and those involved in AICD. Note: ODA is defined as those flows to countries and territories on the DAC List of ODA Recipients (available at http://www.oecd.org​ /dac/stats/daclist.htm) and to multilateral development institutions which are provided by official agencies, including state and local governments, or by their executive agencies. AICD = Africa Infrastructure Country Diagnostic; DAC = Development Assistance Committee; DFI = development finance institution; IPPs = independent power projects; MFI = multilateral finance institution; ODA = official development assistance; OECD = Organisation for Economic Co-operation and Development. “—” indicates 0 investment. A ppendi x B Government Investments in Electric Power Generation in Sub-Saharan Africa Table B.1  Government Investments in Electric Power Generation, by Country or Territory: Sub-Saharan Africa, Cumulative 1990–2013 Country or territory Total installed capacity (MW) Investment (US$, millions) Angola 841 1,809.1 Benin 145 189.8 Botswana 76 317.1 Burkina Faso 177 279.0 Burundi 2 2.9 Cabo Verde 74 94.1 Cameroon 307 444.3 Central African Republic 0 — Chad 99 143.3 Comoros 22 31.3 Congo, Dem. Rep. 0 — Congo, Rep. 390 608.8 Côte d’Ivoire 0 — Djibouti 0 — Equatorial Guinea 93 126.6 Eritrea 38 58.0 Ethiopia 1,048 2,818.0 Gabon 0 — Gambia, The 60 86.6 Ghana 379 546.6 Guinea 99 156.4 Guinea-Bissau 0 — Kenya 464 1,022.0 Lesotho 0 — Liberia 0 — table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   271   272 Government Investments in Electric Power Generation in Sub-Saharan Africa Table B.1  Government Investments in Electric Power Generation, by Country or Territory: Sub-Saharan Africa, Cumulative 1990–2013 (continued) Country or territory Total installed capacity (MW) Investment (US$, millions) Madagascar 300 549.5 Malawi 166 444.2 Mali 73 104.9 Mauritania 13 18.8 Mauritius 156 225.3 Mozambique 24 35.3 Namibia 238 261.3 Niger 62 90.4 Nigeria 1,298 2,043.8 Rwanda 59 99.5 Saint Helena 2 2.9 São Tomé and Príncipe 24 37.9 Senegal 250 361.1 Seychelles 62 90.2 Sierra Leone 7 43.6 Somalia 10 14.5 South Africa 10,098 13,954.0 Sudan and South Sudan 502 508.3 Swaziland 0 — Tanzania 726 1,322.5 Togo 0 — Uganda 90 129.6 Western Sahara 2 2.9 Zambia 285 763.3 Zimbabwe 0 — Total, SSA 18,761 29,837.9 Total, SSA, excluding South Africa 8,663 15,883.9 Note: Total installed capacity from 1990 to 2012 is based on data from the U.S. Energy Information Administration. Figures for 2013 were taken from World Bank’s own database. The total government or utility investment over this period was calculated by taking the total capacity added between 2013 and 1990 and subtracting the megawatts known because of IPPs, Chinese or ODA/DFI/Arab investment in the country. The number that remains is treated as government investment. Any government numbers that were independently verified were used. Where specific projects were not available to cross-check for government investment, investment numbers were assigned based on average costs per technology in Sub-Saharan Africa. This is at best an estimate of government investment, and anyone using these numbers should look at all the assumptions carefully. DFI = development finance institution; IPPs = independent power projects; MW = megawatt; ODA = official development assistance; SSA = Sub-Saharan Africa. “—” indicates 0 investment. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 A ppendi x C Investments in Electric Power Generation in Sub-Saharan Africa Financed by Official Development Assistance and Development Finance Institutions Table C.1  Official Development Assistance (ODA) and Development Finance Institution (DFI) Investments in Electric Power Generation, by Country and Project: Sub-Saharan Africa, 1990–2012 Total Capacity Year of investment Type of Project Technology (MW) investment (US$, millions) financing Agency Botswana Morupule B Power Coal 600 2009 214.0 Concession AfDB Station loan Morupule B Power Coal 2009 68.0 Concession WB Station loan Burkina Faso Samendini Dam Project Hydro 2.5 2008 44.0 Concession Middle East (BADEA, loan KDF, SFD, Abu Dhabi) Samendini Dam Project Hydro 2008 7.0 Concession OFID loan Samendini Dam Project Hydro 2008 36.5 Concession IsDB loan Samendini Dam Project Hydro 2008 8.0 Concession Bank of West Africa loan Samendini Dam Project Hydro 2008 8.1 Concession Entrepreneurship loan and Development Bank of Western Africa Economic Association Samendini Dam Project Hydro 2008 26.4 Government of Burkina Faso table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   273   274 Investments in Electric Power Generation in Sub-Saharan Africa Table C.1  Official Development Assistance (ODA) and Development Finance Institution (DFI) Investments in Electric Power Generation, by Country and Project: Sub-Saharan Africa, 1990–2012 (continued) Total Capacity Year of investment Type of Project Technology (MW) investment (US$, millions) financing Agency Cabo Verde Extension of Thermal Diesel 20 2008 6.6 Concession African Power Station at loan Development Santiago Island Fund Djibouti Boulaos Power Diesel 10 1999 14.8 Concession KDF Generating Project loan Boulaos Power Diesel 14 2004 13.9 Concession AFESD Generating Station loan Project (Fourth Phase) Boulaos Power Diesel 2004 5.0 Concession OFID Generating Station loan Project (Fourth Phase) Boulaos Power Diesel 21 2003 9.9 Concession AFESD Generating Station loan Project (Third Phase) Eritrea Blesa Power Station Diesel 15 1995 17.0 Concession KDF Expansion loan Hirgigo Thermal Power Diesel 88 2002 6.0 Concession OFID Plant Project loan Hirgigo Thermal Power Diesel 2002 25.8 Concession KDF Plant Project loan Hirgigo Thermal Power Diesel 2002 12.0 Concession BADEA Plant Project loan Hirgigo Thermal Power Diesel 2002 25.0 Concession ADFD Plant Project loan Ethiopia Ashegoda Wind Farm Wind 120 2009 58.5 ODA loan France (AFD) in Tigray Gilgel Gibe II Project Hydro 420 2005 264.0 Concession Italy loan Gilgel Gibe II Project Hydro 2005 60.0 Concession EIB loan Gilgel Gibe I Hydro 184 1997 189.0 Concession WB (IDA) Hydroelectric Plant loan Gilgel Gibe I Hydro 1997 44.0 Concession EIB and Nordic Hydroelectric Plant loan Ghana Takoradi Thermal Combined 300 1993/94 170.7 Concession WB (IDA) Power Plant cycle loan Takoradi Thermal Combined 1993/94 39.5 Concession EIB Power Plant cycle loan table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investments in Electric Power Generation in Sub-Saharan Africa 275 Table C.1  Official Development Assistance (ODA) and Development Finance Institution (DFI) Investments in Electric Power Generation, by Country and Project: Sub-Saharan Africa, 1990–2012 (continued) Total Capacity Year of investment Type of Project Technology (MW) investment (US$, millions) financing Agency Takoradi Thermal Combined 1993/94 9.8 Concession BADEA Power Plant cycle loan Takoradi Thermal Combined 1993/94 21.5 Concession KDF Power Plant cycle loan Takoradi Thermal Combined 1993/94 29.9 Concession France Power Plant cycle loan Takoradi Thermal Combined 1993/94 30.0 Concession UK Power Plant Cycle loan Guinea Hydroelectricity Hydro 75 1999 21.1 ODA grant Canada (CIDA) in Garafiri Hydroelectricity Hydro 1999 12.0 Concession BADEA in Garafiri loan Hydroelectricity Hydro 1999 4.1 Concession IsDB in Garafiri loan Hydroelectricity Hydro 1999 10.9 Concession IsDB in Garafiri loan Hydroelectricity Hydro 1999 20.4 Concession KDF in Garafiri loan Hydroelectricity Hydro 1999 9.8 Concession KDF in Garafiri loan Hydroelectricity Hydro 1999 29.0 Concession SFD in Garafiri loan Kenya (Sang’oro Power Plant) Hydro 60 2007 51.1 Concession Japan (JICA) Sondu-Miriu loan Hydropower Project Madagascar Energy Sector Diesel 19.6 1996 92.0 Concession WB and EIB Development Project loan Andekaleka Hydro 29 2005 6.5 Concession OFID Hydroelectric loan (Phase II) Andekaleka Hydro 2005 10.1 Concession KDF Hydroelectric loan (Phase II) Andekaleka Hydro 2005 6.5 Concession BADEA Hydroelectric loan (Phase II) Mali Power Plant at Manantali Hydro 200 1997 144.4 Concession IDA, BOAD, CIDA, Dam (plant and loan AFD, BID, KfW turbines only) (multilateral) table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 276 Investments in Electric Power Generation in Sub-Saharan Africa Table C.1  Official Development Assistance (ODA) and Development Finance Institution (DFI) Investments in Electric Power Generation, by Country and Project: Sub-Saharan Africa, 1990–2012 (continued) Total Capacity Year of investment Type of Project Technology (MW) investment (US$, millions) financing Agency Mauritania Expansion of Diesel 22 2004 23.8 Concession AFESD Nouadhibou Power loan Generation Station Mauritius Fort George Power Diesel 30 1996 13.4 Concession KDF Station Extension loan Project Niger Kandadji Dam Project Hydro 130 2011 20.5 Concession KDF loan Kandadji Dam Project Hydro 2008 15.0 Concession OFID loan Kandadji Dam Project Hydro 2008 20.0 Concession SFD loan Kandadji Dam Project Hydro 2008 50.0 Concession IsDB loan Kandadji Dam Project Hydro 2008 30.0 Concession AfDB loan Kandadji Dam Project Hydro 2008 10.0 Concession BADEA loan Rwanda Rukarara II Micro Hydro Hydro 2 2011 1.3 ODA grant Belgium Sierra Leone Western Area Power Diesel 16 2010 1.6 Concession SFD Generation loan (additional loan) Western Area Power Diesel 16 2006 8.0 Concession BADEA Generation Project loan Western Area Power Diesel 16 2006 7.0 Concession BADEA Generation Project loan Bumbuna Hydro Hydro 50 1990 50.7 Concession AfDB Power Project loan Bumbuna Hydro Hydro 1995 28.8 Concession AfDB Power Project loan Bumbuna Hydro Hydro 2005 1.8 Concession AfDB Power Project loan Bumbuna Hydro Hydro 2008 16.4 Concession AfDB Power Project loan Bumbuna Hydro Hydro 2009 1.1 Concession AfDB (NTF) Power Project loan Bumbuna Hydro Hydro 2004 12.9 Concession WB Power Project loan table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Investments in Electric Power Generation in Sub-Saharan Africa 277 Table C.1  Official Development Assistance (ODA) and Development Finance Institution (DFI) Investments in Electric Power Generation, by Country and Project: Sub-Saharan Africa, 1990–2012 (continued) Total Capacity Year of investment Type of Project Technology (MW) investment (US$, millions) financing Agency Bumbuna Hydro Hydro 1990 124.6 Concession Italy Power Project loan Bumbuna Hydro Hydro 2005 23.8 Concession Italy Power Project loan Bumbuna Hydro Hydro 2008 18.0 Concession Italy Power Project loan Bumbuna Hydro Hydro 2004 10.2 Concession DFID Power Project loan Bumbuna Hydro Hydro 2006 10.0 Concession OFID Power Project loan South Africa Medupi Power Station Coal 4,800 2010 1,135.5 Concession AfDB loan Medupi Power Station Coal 2010 1,542.0 Concession World Bank (IBRD) loan Sudan Merowe Dam Hydro 1,250 2004 455.0 Concession AFESD loan Merowe Dam Hydro 2004 210.0 Concession SFD loan Merowe Dam Hydro 2004 156.4 Concession KDF loan Merowe Dam Hydro 2004 200.0 Concession ADFD loan Merowe Dam Hydro 2004 50.0 Concession Oman loan Expansion of Hydro 775 2008 30.0 Concession OFID Roseires Dam loan Expansion of Hydro 2008 73.0 Concession IsDB Roseires Dam loan Expansion of Hydro 2008 36.0 Concession SFD Roseires Dam loan Expansion of Hydro 2008 25.0 Concession ADFD Roseires Dam loan Expansion of Hydro 2008 197.0 Concession AFESD Roseires Dam loan Uganda Power Project 3 Hydro 200 1994 125.4 Equity, loan World Bank (IDA) (Extension of Owen Falls) Power Project 3 Hydro 1994 15.2 Concession World Bank (IDA) (Extension of loan Owen Falls) table continues next page Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 278 Investments in Electric Power Generation in Sub-Saharan Africa Table C.1  Official Development Assistance (ODA) and Development Finance Institution (DFI) Investments in Electric Power Generation, by Country and Project: Sub-Saharan Africa, 1990–2012 (continued) Total Capacity Year of investment Type of Project Technology (MW) investment (US$, millions) financing Agency Uganda (cont.) Power Project 3 Hydro 1994 20.0 Concession IsDB (Extension of loan Owen Falls) Power Project 3 Hydro 1994 45.0 Concession AfDB (Extension of loan Owen Falls) Power Project 3 Hydro 1994 24.6 Concession Norway, Norfund (Extension of loan Owen Falls) Power Project 3 Hydro 1994 21.3 Concession Others (UK, Sweden, (Extension of loan Sida, etc.) Owen Falls) Note: ODA, concessionary DFI/MFI, and Arab funding have been sourced by AidData (for which OECD data is a reference point) and cross-checked with secondary sources. ODA is defined as those flows to countries and territories on the DAC List of ODA Recipients (available at http://www.oecd.org/dac/stats/daclist.htm) and to multilateral development institutions provided by official agencies, including state and local governments, or by their executive agencies. Several projects have various investment flows sourced from a number of aid agencies. Each agency’s contribution is listed separately. However, the total installed capacity (in megawatts) for the project is listed only once. Empty cells indicate that no information was available. ADFD = Abu Dhabi Fund for Development; AFD = Agence Française de Développement; AfDB = African Development Bank; AFESD = Arab Fund for Economic and Social Development; BADEA = Arab Bank for Economic Development in Africa; BID = Banco Interamericano de Desarrollo; BOAD = West African Development Bank; CIDA = Canadian International Development Agency; DAC = Development Assistance Committee; DFI = development finance institution; DfID = Department for International Development; EIB = European Investment Bank; IBRD = International Bank for Reconstruction and Development; IDA = International Development Association; IsDB = Islamic Development Bank; JICA = Japan International Cooperation Agency; KDF = Kuwait Development Fund; KfW = Kreditanstalt für Wiederaufbau; MFI = multilateral finance institution; MW = megawatt; NTF = Nordic Trust Fund; ODA = official development assistance; OECD = Organisation for Economic Co-operation and Development; OFID = OPEC Fund for International Development; SFD = Saudi Fund for Development; Sida = Swedish International Development Cooperation Agency; WB = World Bank. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 A ppendi x D Investments in Electric Power Generation in Sub-Saharan Africa Financed by Chinese Sources Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   279   280 Table D.1  Investments Funded by Chinese Sources, by Country and Project: Sub-Saharan Africa, 1990–2014 Capacity Financial Total investment Country Project Technology (MW) close Project status (US$, millions) Angola CIF Cement Hydro, large 35 2014 Operational 73.4 Botswana Morupule B Power Station Coal 600 2009 Operational/construction 970.0 Cameroon Memve’ele Hydropower Project Hydro 201.2 2011 Construction 637.0 Central African Republic Boali No. 3 Hydropower Plant Hydro, small 9.6 2011 Operational 25.0 Congo, Dem. Rep. Zongo-II Hydropower Scheme Hydro, large 150 2011 Construction 367.5 Congo, Rep. Imboulou Dam Hydro, large 120 2009 Operational 341.0 Congo, Rep. Liouesso Hydropower Station Hydro, small 19.2 2014 Construction 40.3 Côte d’lvoire Soubré Hydropower Project Hydro, large 270 2012 Construction 571.0 Equatorial Guinea Malabo Power Plant Expansion CCGT + OCGT 84 2010 Operational 99.6 Equatorial Guinea Djiploho Hydropower Project Hydro, large 120 2010 Operational 257.0 Ethiopia Fan Hydropower Project Hydro, large 97 2009 Operational 186.0 Ethiopia Adama Wind Farm Wind, onshore 50 2011 Operational 123.0 Ethiopia Genale (GD-3) Multipurpose Hydro, large 245 2012 Construction 451.0 Ethiopia Gilgel Gibe III Hydro, large 400 2012 Operational 500.0 Ethiopia Adama Wind Farm II Wind, onshore 100 2014 Operational 293.3 Ethiopia Messabo Harrena Wind Farm Wind, onshore 51 2014 Construction 127.0 Gabon Poubara Hydropower Project Hydro, large 160 2010 Operational 398.0 Ghana Bui Hydropower Project Hydro, large 400 2009 Operational 621.0 Guinea Kaleta Hydropower Project Hydro, large 240 2010 Construction 446.2 Mali Gouina Hydropower Project Hydro 147 2013 Construction 467.0 Nigeria Omotosho Power Plant Phase I OCGT + CCGT 335 2002 Operational 361.0 Nigeria Papalanto Power Gas Turbine Power Plant, in Ogun OCGT + CCGT 335 2002 Operational 359.7 Nigeria Omotosho Power Plant II (NIPP) OCGT + CCGT 513 2010 Operational 660.0 table continues next page Table D.1  Investments Funded by Chinese Sources, by Country and Project: Sub-Saharan Africa, 1990–2014 (continued) Capacity Financial Total investment Country Project Technology (MW) close Project status (US$, millions) Nigeria Zungeru Hydropower Project Hydro 700 2013 Construction 1,293.0 Sudan Al Fulah Natural gas 105 2001 Operational 300.0 Sudan Garri (Qarre) I & II, at El Gaili CCGT 300 2005 Operational 221.5 Sudan Hydraulic Works for Merowe Dam and HPP Project Hydro 12.5 2009 Operational 87.0 Togo/Benin Adjarala Hydro 147 2014 308.0 Uganda Isimba Hydropower Project Hydro 183 2015 Loan agreement signed 556.0 Uganda Karuma Hydropower Project Hydro 600 2014 Loan agreement in process 1,688.4 Zambia Kariba North Bank Power Station Extension Project Hydro 360 2009 Operational 279.0 Zambia Mazabuka Coal 300 2014 Construction, but financing 560.0 not complete Zambia Lunzua Hydro, small 14.8 2014 Operational 31.5 Zimbabwe Kariba South Bank Power Station Extension Project Hydro 300 2013 Construction 389.0 Note: CCGT = combined-cycle gas turbine; HFO = heavy fuel oil; MW = megawatt; OCGT = open-cycle gas turbine. 281 A ppendi x E Independent Power Projects in Sub-Saharan Africa Table E.1  IPP Investments in Angola, by Project Project information Project name 1 Project name 2 Chicapa Hydroelectric Plant Biocom (Malanje) Capacity (MW) 16 30 Technology Hydro, small (<20 MW) Waste/bagasse Total investment (US$, millions) 45.0 89.8 Year of financial close 2003 2014 Commercial operation date 2008 Project status Operational Operational Procurement method Direct negotiation Direct negotiation Number of bids Contract period (years) 40 Contract type Build-operate-transfer Sponsors/developer ALROSA Co. Ltd. (Almazy Rossii-Sakha Company) (55%­—Russian Federation) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method Total DFI financing (US$, millions) ODA grants (US$, millions) Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. DFI = development finance institution; IPP = independent power project; MW = megawatt; ODA = official development assistance. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5   283   284 Independent Power Projects in Sub-Saharan Africa Table E.2  IPP Investments in Cabo Verde, by Project Project information Project name Electra Cabeolica Wind Project Capacity (MW) 25.5 Technology Wind, onshore Total investment (US$, millions) 80.0 Year of financial close 2010 Commercial operation date 2010 Project status Operational Procurement method Number of bids Contract period (years) 20 Contract type Build-own-operate Sponsors/developer Electra (Cabo Verde), Africa Finance Corporation (Nigeria) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method EIB (loan, $39 million, 2010), AfDB (loan, $19 million, 2010) Total DFI financing (US$, millions) 58.0 ODA grants (US$, millions) Local credit enhancements and security Variable government payments arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; DFI = development finance institution; EIB = European Investment Bank; IPP = independent power project; MW = megawatt; ODA = official development assistance. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Independent Power Projects in Sub-Saharan Africa 285 Table E.3  IPP Investments in Cameroon, by Project Project information Project name 1 Project name 2 Dibamba Power Plant Kribi Power Plant Capacity (MW) 88 216 Technology HFO/MSD CCGT Total investment (US$, millions) 126.0 342.0 Year of financial close 2009 2010 Commercial operation date 2009 2013 Project status Operational Operational Procurement method Direct negotiation Direct negotiation Number of bids Contract period (years) 20 20 Contract type Build-operate-transfer Build-operate-transfer Sponsors/developer AES Corporation KPDC was 56% owned by AES, with the remaining 44% (56%, United States), in the hands of the Cameroon government. It was Cameroon (44%) built by Finland’s Wartsila, running on natural gas from the offshore Sanaga-South field operated by Cameroon’s state oil company, SNH, and independent producer Perenco—the first major commercial development of Cameroon’s substantial gas reserves. In November 2013, AES announced it would sell its stake in Cameroon to Actis (Globeleq parent company), a global pan-emerging market investor, for  $220 million of net equity proceeds. Sale was completed in 2014. Engineering, procurement, and Wartsila construction Fuel arrangement Heavy fuel oil/tolling Gas supply agreement has been signed with a agreement with AES state-owned gas supplier. Sonel as toller Debt-equity ratio 75/25 Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method IFC (loan, $31 million, AfDB (loan, $57 million, 2011), EIB (loan, $41 million, 2010), AfDB (loan, 2012), other (loan, $23 million, 2012), IDA $31 million, 2010), FMO (guarantee, $82 million, 2012), IFC (loan, $31 million, 2010) (loan, $77 million, 2012) Total DFI financing (US$, millions) 93.0 198.0 ODA grants (US$, millions) Local credit enhancements and Sovereign guarantee security arrangements Foreign credit enhancements and Typical project finance WB partial risk guarantees (enabled local bank security arrangements security agreements participation) implemented but details not made public Note: Empty cells indicate that no information was available. AfDB = African Development Bank; CCGT = combined-cycle gas turbine; DFI = development finance institution; EIB = European Investment Bank; FMO = Netherlands Development Finance Company; HFO = heavy fuel oil; IDA = International Development Association; IFC = International Finance Corporation; IPP = independent power project; KPDC = Kribi Power Development Company; MSD = medium-speed diesel; MW = megawatt; ODA = official development assistance; WB = World Bank. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 286 Table E.4  IPP Investments in Côte d’Ivoire, by Project Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 Compagnie Ivoirienne Compagnie Ivoirienne Azito Power Project Compagnie Ivoirienne Azito Power Compagnie Ivoirienne de Production de Production de Production Project de Production d’Électricité (CIPREL) d’Électricité (CIPREL) d’Électricité (CIPREL) d’Électricité (CIPREL) Capacity (MW) 99 111 288 111 146 111 Technology OCGT OCGT OCGT OCGT OCGT + CCGT OCGT + CCGT Total investment (US$, millions) 108.0 134.0 223.0 134.0 207.0 134.0 Year of financial close 1994 1997 1999 2009 2013 2013 Commercial operation date 1995 2000 Project status Operational, planning/ Operational, planning/ Operational Operational Under Reached financial close reached financial close reached financial construction close Procurement method Direct negotiation Direct negotiation International Direct negotiation International Direct negotiation competitive bid competitive bid Number of bids 3 Contract period (years) 19 24 Contract type Build-own-operate- Build-own-operate- transfer transfer Sponsors/developer SAUR International with SAUR International with Globeleq (77%, SAUR International with SAUR International with 88% (a joint venture 88% (a joint venture United Kingdom), 88% (a joint venture 88% (a joint venture between French SAUR between French Aga Khan Fund between French between French SAUR Group owned by SAUR Group owned (Switzerland) SAUR Group owned Group owned by Bouygues, 65%, and by Bouygues, 65%, by Bouygues, 65%, Bouygues, 65%, and EDF, 35%), with BOAD, and EDF, 35%), with and EDF, 35%), with EDF, 35%), with BOAD, Proparco, and IFC BOAD, Proparco, and BOAD, Proparco, and Proparco, and IFC holding the remaining IFC holding the IFC holding the holding the remaining 12%. In 2005, all remaining 12%. In remaining 12%. In 12%. In 2005, all shares sold to 2005, all shares sold 2005, all shares sold shares sold to Bouygues (France, to Bouygues (France, to Bouygues (France, Bouygues (France, 98%), except BOAD 98%), except BOAD 98%), except BOAD 98%), except BOAD (2%). (2%). (2%). (2%). table continues next page Table E.4  IPP Investments in Côte d’Ivoire, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 Engineering, procurement, and construction Fuel arrangement Government Government Government Government Government Government procures fuel procures fuel procures fuel procures fuel procures fuel procures fuel Debt-equity ratio 70/30 Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing BOAD (loan, $9 million, AfDB (loan, $14 IFC, AfDB, and Proparco method 1994), IFC (loan, million, 1998), IDA $18 million, 1995), (guarantee, $30 IFC (equity, $1 million, million, 1999), IFC 1995), IBRD (loan, (loan, $41 million, $80 million, 1995) 1999), IFC (syndication, $31 million, 1999) Total DFI financing (US$, millions) 108.0 — 116.0 — — — ODA grants (US$, millions) Local credit enhancements Sovereign and security guarantee, arrangements escrow account equivalent to one month capacity charge Foreign credit enhancements World Bank partial and security risk guarantee arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; BOAD = West African Development Bank; CCGT = combined-cycle gas turbine; DFI = development finance institution; EDF = Électricité de France; IBRD = International Bank for Reconstruction and Development; IDA = International Development Association; IFC = International Finance Corporation; IPP = independent power project; MW = megawatt; ODA = official development assistance; OCGT = open-cycle gas turbine. In “Total DFI financing” cells “—” indicates 0 financing. 287 288 Independent Power Projects in Sub-Saharan Africa Table E.5  IPP Investments in The Gambia, by Project Project information Project name Brikama Capacity (MW) 25 Technology HFO + MSD/HFO Total investment (US$, millions) 36.2 Year of financial close 2005 Commercial operation date 2006 Project status Operational Procurement method Number of bids Contract period (years) Contract type Sponsors/developer Global Electrical Group (GEG) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method Total DFI financing (US$, millions) ODA grants (US$, millions) Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. DFI = development finance institution; HFO = heavy fuel oil; IPP = independent power project; MSD = medium-speed diesel; MW = megawatt; ODA = official development assistance. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Table E.6  IPP Investments in Ghana, by Project Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Takoradi II Sunon-Asogli Power CENIT Energy Takoradi II Kpone IPP Plant Capacity (MW) 220 200 126 110 350 Technology OCGT/CCGT OCGT + CCGT OCGT + CCGT OCGT + CCGT CCGT Total investment (US$, millions) 110.0 200.0 140.0 330.0 900.0 Year of financial close 1999 2007 2009 2013 2014 Commercial operation date 2000 2011 2012 2014 2017 Project status Operational Operational Operational Under construction Financial close Procurement method Direct negotiation Direct negotiation Direct negotiation Direct negotiation Number of bids Contract period (years) 25 Contract type Build-own-operate- Build-own-operate Build-own-operate transfer Sponsors/developer CMS (90%, United Shenzhen Electric GECAD (100%, CMS (90%, United States), VRA Africa Finance Corporation (AFC) States), VRA (10%, (60%, China), United States) (10%, Ghana). CMS sold shares (31.85%), CenPower Holdings Ghana). CMS sold China-Africa to TAQA (90%, United Arab Limited (21%), a consortium of shares to TAQA Development Fund Emirates) in 2007. Ghanaian investors, Sumitomo (90%, United Arab (40%, China) Corporation (28%), Mercury Power Emirates) in 2007. (15%), and FMO (4.15%) Engineering, procurement, Mitsui & Co. (Japan) Mitsui & Co. (Japan) and KEPCO and construction and KEPCO E&C E&C (Republic of Korea) (Republic of Korea) Fuel arrangement Government Interim fuel agreement Government procures fuel procures fuel for access to West African Gas Pipeline gas Debt-equity ratio 72/28 Local shareholder equity Local strategic investor, (entity, US$, millions) Togbe Afede XIV table continues next page 289 290 Table E.6  IPP Investments in Ghana, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Takoradi II (cont.) Sunon-Asogli Power CENIT Energy Takoradi II (cont.) Kpone IPP (cont.) Plant (cont.) (cont.) Foreign shareholder equity (entity, US$, millions) DFI agency and financing IFC (loan, $60 million, Other (loan, IFC and a consortium of FMO (equity, $10.3 million), DBSA method 2004) $67 million, international development (loan, $53 million), OFID (loan, 2008), other finance institutions led by the $7 million), EAIF ($25 million), (quasi-equity, FMO. The lenders participating FMO (loan, $24 million), and $10 million, in the consortium include the others 2008), AfDB AfDB, Deutsche Investitions- (loan, $32 million, und Entwicklungs 2011) Gesellschafte, Emerging Africa Infrastructure Fund, ICF-Debt Pool, and Proparco. The OPEC Fund for International Development and the Canada Climate Change Program are participating alongside the IFC. Total DFI financing (US$, millions) 60.0 — 109.0 347.5 207.0 ODA grants (US$, millions) Local credit enhancements and Sovereign guarantee Variable government security arrangements (phase 1), payments $3 million letter of credit provided by government (phase 1) Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; CCGT = combined-cycle gas turbine; DBSA = Development Bank of Southern Africa; DFI = development finance institution; EAIF = Emerging Africa Infrastructure Fund; FMO = Netherlands Development Finance Company; IFC = International Finance Corporation; IPP = independent power project; MW = megawatt; OCGT = open-cycle gas turbine; ODA = official development assistance; OFID = OPEC Fund for International Development; OPEC = Organization of the Petroleum Exporting Countries; VRA = Volta River Authority. In “Total DFI financing” cells “—” indicates 0 financing. Table E.7A  IPP Investments in Kenya, by Project Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 Mombasa Barge- Iberafrica Power Ltd. Kipevu II/Tsavo Ormat Olkaria III Iberafrica Power Ltd. Mumias Power Mounted Power Geothermal Power Plant Project/Westmont Plant, OrPower4 (phases 1, 2, and 3) Capacity (MW) 46 44 75 13 12 26 Technology OCGT MSD/HFO MSD/HFO Geothermal MSD/HFO Waste Total investment (US$, millions) 65.0 50.3 86.0 105.0 13.7 50.0 Year of financial close 1996 1996 1999 1999 1999 2008 Commercial operation date 1997 1997 2001 2000, 2009 2000 2009 Project status Concluded Operational Operational Operational Operational Operational Procurement method Direct negotiation Direct negotiation International International Direct negotiation Direct competitive bid competitive bid negotiation Number of bids 3 2 Contract period (years) 7 7 20 20 15 Contract type Build-own-operate Build-own-operate Build-own-operate Build-own-operate Build-own-operate Build-own- operate Sponsors/developer Westmont Ltd. (Malaysia) Union Fenosa (80%, Spain), Cinergy and IPS jointly Ormat Turbines Ltd. Union Fenosa (80%, Mumias Sugar KPLC Pension Fund owned 49.9%. Cinergy (100%, Israel) Spain) and KPLC Company Ltd. (Kenya, 20%) since 1997 sold to Duke Energy in Pension Fund (100%, Kenya) 2005. CDC/Globeleq (20%, Kenya) (30%, United Kingdom), since 1997 Wartsila (15%, Finland), and IFC (5%) retain remaining shares since 2000. Engineering, procurement, and construction table continues next page 291 292 Table E.7A  IPP Investments in Kenya, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 Mombasa Barge- Iberafrica Power Ltd. Kipevu II/Tsavo (cont.) Ormat Olkaria III Iberafrica Power Ltd. Mumias Power Mounted Power (cont.) Geothermal Power (cont.) Plant (cont.) Project/Westmont Plant, OrPower4 (cont.) (phases 1, 2, and 3) (cont.) Fuel arrangement Originally Westmont was Iberafrica buys fuel and Tsavo buys fuel and passes The only fuel Iberafrica buys fuel to procure fuel and passes cost through to cost through to KPLC arrangement per se and passes cost then pass through to KPLC based on the units based on the units is that OrPower4 through to KPLC the utility. However, generated and specific generated and specific was granted a based on the units following dispute with consumption consumption parameters Geothermal generated and fuel supplier about parameters agreed on agreed on in the PPA. Resource License specific taxes after the first year in the PPA. from the consumption of operation, the utility government to parameters agreed took over procurement. which it pays a on in the PPA. royalty of sorts ($0.004/kWh or USc 0.4/kWh). Debt-equity ratio 72/28 78/22 Local shareholder KPLC Staff Pension Fund 9.45 equity (entity, ($9.4 million in direct US$, millions) loans and guarantees; $5 million through a local Kenyan bank) Foreign shareholder Union Fenosa (Spain) 9.48 Ormat (100%) since equity (entity, ($12.7 million in direct 1998—until 2008 US$, millions) loans and $20 million in guarantees) table continues next page Table E.7A  IPP Investments in Kenya, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 DFI agency and IFC (loan, $18 million, 2000), MIGA (guarantee, financing method IFC (equity, $2 million, $49 million, 2000), 2000), IFC (quasi-equity, MIGA (guarantee, $3 million, 2000), IFC $70 million, 2002), (syndication, $24 million, MIGA (guarantee, 2000), IFC (risk manage­ $89 million, 2009), ment, $2 million, 2001), (guarantee, $110 CDC own account million, 2011) ($13 million), DEG own account (€11 million), DEG syndicated (€2 million) Total DFI financing (US$, millions) — — 82.0 — — — ODA grants — — — — — — (US$, millions) Local credit An advance payment cash Letter of comfort provided A standby letter of An advance payment Payment enhancements deposit initially, but by government, escrow credit, covering cash deposit guarantee and security Iberafrica presently has account equivalent to several months of initially, but arrangements no payment security. one month of capacity billing (although Iberafrica charge, and a standby only finalized at end presently has no letter of credit equivalent of 2006) payment security to three months of billing Foreign credit MIGA guarantee enhancements and security arrangements Note: Empty cells indicate that no information was available. CDC = Commonwealth Development Corporation; DEG = German Investment and Development Corporation; DFI = development finance institution; HFO = heavy fuel oil; IFC = International Finance Corporation; IPP = independent power project; IPS = Industrial Promotion Services; KPLC = Kenya Power and Lighting Company; kWh = kilowatt-hour; MIGA = Multilateral Investment Guarantee Agency; MSD = medium-speed diesel; MW = megawatt; OCGT = open-cycle gas turbine; ODA = official development assistance; PPA = power purchase agreement; USc = U.S. cent. In “Total DFI financing” and “ODA grants” cells “—” indicates 0 financing or grants, respectively. 293 294 Table E.7B  IPP Investments in Kenya, by Project Project information Project name 7 Project name 8 Project name 9 Project name 10 Project name 11 Project name 12 Rabai Power Plant Ormat Olkaria III Iberafrica Power Ltd. Ormat Olkaria III Triumph HFO Power Thika Thermal Geothermal Power Geothermal Power Plant Power Project Plant, OrPower4 Plant, OrPower4 (phases 1, 2, and 3) (phases 1, 2, and 3) Capacity (MW) 90 35 52.5 36 83 87 Technology MSD/HFO and steam cycle Geothermal MSD/HFO Geothermal MSD/HFO MSD/HFO Total investment (US$, millions) 155.0 128.7 59.9 126.2 140.0 144.0 Year of financial close 2008 2009 2009 2011 2012 2012 Commercial operation date 2010 2009 2009 2013 2015 2013 Project status Operational Operational Operational Operational Construction Operational Procurement method International competitive bid Direct negotiation Direct negotiation Direct negotiation International International competitive bid competitive bid Number of bids 4 5 9 Contract period (years) 20 25 20 20 Contract type Build-own-operate-transfer Build-own-operate Build-own-operate Build-own-operate Build-own-operate Build-own-operate Sponsors/developer Aldwych, 34.5%; BWSC Ormat Turbines Ltd. Union Fenosa Ormat Turbines Ltd. Broad Holding (Kenya), Melec PowerGen (Danish, but owned by (100%, Israel) (80%, Spain), KPLC (100%, Israel) Interpel Investments (part of Matelec Mitsui of Japan), 25.5%; Pension Fund (Kenya), Tecaflex Group) (90%, FMO, 20%; IFU (Danish (20%, Kenya) since (Kenya), Southern Lebanon) bilateral lender), 20% 1997 Inter-trade (Kenya) Engineering, BWSC, codeveloper, sponsor, XJ International MAN Diesel procurement, and and shareholder; EPC, Engineering (Germany) and construction contractor and operations Company (wholly Matelec Group and maintenance owned subsidiary of contractor State Grid Corporation of China) table continues next page Table E.7B  IPP Investments in Kenya, by Project (continued) Project information Project name 7 Project name 8 Project name 9 Project name 10 Project name 11 Project name 12 Fuel arrangement Fuel supply agreement with Iberafrica buys fuel Kenol of Kenya and passes cost through to KPLC based on the units generated and specific consumption parameters agreed on in the PPA Debt-equity ratio 75/25 74/26 75/25 Local shareholder equity (entity, US$, millions) Foreign shareholder Ormat (100%) since Ormat (100%) since equity (entity, 1998—until 2008 1998—until 2008 US$, millions) DFI agency and Other (loan, $126 million, MIGA (guarantees, MIGA (guarantees, MIGA (guarantee, AfDB (loan, financing method 2008); DEG, 15%; FMO, $49 million, 2000; $49 million, 2000; $12 million, 2012), €28 million, 2012), 25%; EAIF, 25%; Proparco, $70 million, 2002; $70 million, 2002; IDA (guarantee, IFC (loan, €28 25%; European Financing $89 million, 2009), $89 million, 2009), $45 million, 2012) million, 2012), Partners, 10% EIB (loan, $155 EIB (loan, $155 IDA (guarantee, million, 2010), MIGA million, 2010), $45 million, 2012), (guarantee, $110 MIGA (guarantee, MIGA (guarantee, million, 2011) $110 million, 2011) $62 million, 2012) Total DFI financing (US$, millions) 126.0 155.0 — — — 64.0 ODA grants (US$, millions) — — — — — — table continues next page 295 296 Table E.7B  IPP Investments in Kenya, by Project (continued) Project information Project name 7 Project name 8 Project name 9 Project name 10 Project name 11 Project name 12 Rabai Power Plant (cont.) Ormat Olkaria III Iberafrica Power Ltd. Ormat Olkaria III Triumph HFO Power Thika Thermal Geothermal Power (cont.) Geothermal Power Plant (cont.) Power Project Plant, OrPower4 Plant, OrPower4 (cont.) (phases 1, 2, and 3) (phases 1, 2, (cont.) and 3) (cont.) Local credit Support letter from Letter of comfort An advance payment Letter of comfort enhancements and government of Kenya provided by cash deposit provided by security (covers political risk but government, initially, but government, arrangements falls short of being an escrow account Iberafrica presently escrow account outright guarantee). KPLC equivalent to one has no payment equivalent to one issued a letter of credit month of capacity security. month of capacity equivalent to five months charge, and a charge, and a of capacity payments (debt standby letter of standby letter of service, fixed costs, and credit equivalent to credit equivalent equity returns) and two three months of to three months of months of fuel payments billing billing Foreign credit Partial risk guarantees Partial risk guarantees enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; DEG = German Investment and Development Corporation; DFI = development finance institution; EAIF = Emerging Africa Infrastructure Fund; EIB = European Investment Bank; EPC = engineering, procurement, and construction; FMO = Netherlands Development Finance Company; HFO = heavy fuel oil; IDA = International Development Association; IFC = International Finance Corporation; IFU = Danish Investment Fund for Developing Countries; IPP = independent power project; KPLC = Kenya Power and Lighting Company; MIGA = Multilateral Investment Guarantee Agency; MSD = medium-speed diesel; MW = megawatt; ODA = official development assistance; PPA = power purchase agreement. In “Total DFI financing” and “ODA grants” cells “—” indicates 0 financing or grants, respectively. Table E.7C  IPP Investments in Kenya, by Project Project information Project name 13 Project name 14 Project name 15 Project name 16 Kinangop Greenfield Wind Project Gulf Power Lake Turkana Wind Power Ormat Olkaria III Geothermal Power Plant, OrPower4 (phases 1, 2, and 3) Capacity (MW) 60 80 300 26 Technology Wind, onshore MSD/HFO Wind, onshore Geothermal Total investment (US$, millions) 150.0 108.0 861.1 91.1 Year of financial close 2013 2013 2014 2014 Commercial operation date Delayed 2014 2017 Project status Construction/stalled Operational Financial close Operational Procurement method REFiT International competitive bid Direct negotiation Direct negotiation Number of bids 5 Contract period (years) 20 20 Contract type Build-own-operate Build-own-operate Build-own-operate Build-own-operate Sponsors/developer Aeolus Kenya, AIIF2, which became Consortium of local investors: KP&P Africa BV, a group of Dutch involved in the project in 2012 to Gulf Energy Ltd. and Noora entrepreneurs, acts with Aldwych assist the developer Aeolus Kenya Power Ltd. International as codevelopers. to conclude all material contracts and deliver a bankable project, is the majority owner of the project company, Kinangop Wind Park (KWP), while Norfund held the remaining equity. Engineering, procurement, and construction Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) table continues next page 297 298 Table E.7C  IPP Investments in Kenya, by Project (continued) Project information Project name 13 Project name 14 Project name 15 Project name 16 Kinangop Greenfield Wind Project Gulf Power (cont.) Lake Turkana Wind Power (cont.) Ormat Olkaria III Geothermal (cont.) Power Plant, OrPower4 (phases 1, 2, and 3) (cont.) Foreign shareholder equity Finnfund, IFU, Norfund (entity, US$, millions) DFI agency and financing method About three-quarters of the Senior debt: AfDB, €115 million; 80€ million project will be Tranche ‘B’ ECA Facility funded debt financed. IFC, OFID, and €20 million; Tranche ‘B’ ECA Standard Bank Group Ltd. Facility covered €100 million; are each lending €20 million EIB Senior Loan ‘A,’ €50 million; ($26 million). There are EIB Senior Loan ‘B,’ €50 million; $32 million in equity FMO, €35 million; Proparco, investments and $76 million €20 million; ICCF, €30 million in long-term debt financing. Mezzanine: DEG, €20 million; The debt portion consists of EADB, €5 million; PTA, €10 an IFC A Loan, and million; AfDB, €2 million commercial lending through Equity: IFU, €7.5 million; Norfund, an IFC B Loan and OFID. €16 million; Finnfund, €16 million Total DFI financing (US$, millions) — 52.0 595.8 — ODA grants (US$, millions) — — — — Local credit enhancements and Government of Kenya letter of security arrangements support Foreign credit enhancements and IDA guarantee, MIGA EKF (Danish export credit agency) to security arrangements guarantee approximately DKr 1 billion to EIB and AfDB Note: Empty cells indicate that no information was available. AfDB = African Development Bank; AIIF2 = African Infrastructure Investment Fund 2; DEG = German Investment and Development Corporation; DFI = development finance institution; DKr = Danish kroner; EADB = East African Development Bank; ECA = Excess Crude Account; EIB = European Investment Bank; EKF = Eksport Kredit Fonden; FMO = Netherlands Development Finance Company; HFO = heavy fuel oil; ICCF = Interact Climate Change Facility; IDA = International Development Association; IFC = International Finance Corporation; IFU = Danish Investment Fund for Developing Countries; IPP = independent power project; MIGA = Multilateral Investment Guarantee Agency; MSD = medium-speed diesel; MW = megawatt; ODA = official development assistance; OFID = OPEC Fund for International Development; PTA = Preferential Trade Area Bank; REFiT = renewable energy feed-in tariff. In “Total DFI financing” and “ODA grants” cells “—” indicates 0 financing or grants, respectively. Independent Power Projects in Sub-Saharan Africa 299 Table E.8  IPP Investments in Madagascar, by Project Project information Project name Hydelec Madagascar S.A. Capacity (MW) 15 Technology Hydro, small (<50 MW) Total investment (US$, millions) 17.8 Year of financial close 2007 Commercial operation date 2008 Project status Operational Procurement method Number of bids Contract period (years) 15 Contract type Build-operate-transfer Sponsors/developer Hydelec Madagascar (100%, Madagascar) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method AfDB (loan, $9 million, 2007), MIGA (guarantee, $20 million, 2008) Total DFI financing (US$, millions) 9.0 ODA grants (US$, millions) Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; DFI = development finance institution; IPP = independent power project; MIGA = Multilateral Investment Guarantee Agency; MW = megawatt; ODA = official development assistance. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 300 Table E.9  IPP Investments in Mauritius, by Project Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 Deep River Beau Champ, FUEL Power Belle Vue Power St. Aubin Power Project, Compagnie Medine aka Consolidated Plant Plant aka Compagnie Thermique Energy Ltd. Thermique du Sud de Savannah Capacity (MW) 28.4 36.7 71.2 32.5 90 13 Technology Waste/bagasse Waste/bagasse Coal/bagasse Waste/bagasse OCGT/CCGT Waste/bagasse Total investment (US$, millions) 85.0 109.7 109.3 95.2 81.5 38.9 Year of financial close 1997 1998 1998 2004 2005 1994–2011 Commercial operation date Project status Operational Operational Operational Operational Operational Operational Procurement method International competitive bid Number of bids Contract period (years) 20 20 20 Contract type Build-own-operate Build-own- Build-own-operate Build-own-operate operate Sponsors/developer Sugar Investment Trust Sugar Harel Freres (51%, Sugar Investment Trust (10%, Mauritius) Investment Mauritius), Sugar (15%, Mauritius), Mon Trust (20%, Investment Trust Tresor Mon Desert Mauritius) (14%, Mauritius), (19%, Mauritius), SIDEC (27%, Savannah Sugar France) Estates (15%, Mauritius), Societe Union St. Aubin (15%, Mauritius), Sechilienne-SIDEC (25%, France) table continues next page Table E.9  IPP Investments in Mauritius, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 Engineering, procurement, and construction Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method EIB (loan, $17 million, 1998) Total DFI financing (US$, millions) — — 17.0 — — — ODA grants (US$, millions) Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. CCGT = combined-cycle gas turbine; DFI = development finance institution; EIB = European Investment Bank; IPP = independent power project; MW = megawatt; OCGT = open-cycle gas turbine; ODA = official development assistance. In “Total DFI financing” cells “—” indicates 0 financing. 301 Table E.10  IPP Investments in Nigeria, by Project 302 Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 AES Nigeria Barge Limited Okpai Independent Afam Power Project Azura Aba Integrated Power Project (embedded) Capacity (MW) 270 480 630 450 141 Technology OCGT/CCGT OCGT/CCGT OCGT/CCGT OCGT OCGT Total investment (US$, millions) 240.0 462.0 540.0 895.0 460.0 Year of financial close 2001 2002 2008 2015 2013 Commercial operation date 2001 2005 2008 2016 2013 Project status Operational Operational Operational Financial close expected Operational Procurement method Direct negotiation Unsolicited proposals Direct negotiation Direct negotiation Direct negotiation Number of bids 1 8 Contract period (years) 13 20 20 20 Contract type Build-own-operate Build-own-operate Build-own-operate Build-own-operate Sponsors/developer Enron (100%, United States), Nigerian National Petroleum NNPC (55%, Nigeria), Aldwych International, AIIF, and Geometric sold to AES (95%) and YFP Corporation (60%, Nigeria), Shell (30%, ARM in conjunction with the (5%, Nigeria) in 2000 Nigerian Agip Oil Company United Kingdom/ government of Edo State, (20%, Italy, with Agip owned Netherlands), Elf which has about 5% equity by ENI since 2003), and (Total) (10%, stake in the project. Phillips Oil Company (20%, France), Agip United States) have (5%, Italy) maintained equity since 2001. Engineering, procurement, Siemens and Julius Berger General Electric and construction Nigeria Fuel arrangement Utility arranges fuel. Project company provides fuel. Project company 15-year fuel supply agreement Fuel supply provides fuel. with Seplat with a gas supply agreement with letter of credit Shell Debt-equity ratio 0/100 0/100 80/20 Local shareholder equity 5% Main equity sponsors: Azura-Edo (entity, US$, millions) Ltd., 97.5%, comprising APHL, 50% (Amaya Capital, 80%; American Capital, 20%); AIM Energy Group, 30%; ARM, 6%; Aldwych, 14%; Edo State, 2.5% table continues next page Table E.10  IPP Investments in Nigeria, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Foreign shareholder equity 20% 0.45 Main equity sponsors: Azura-Edo (entity, US$, millions) Ltd., 97.5%, comprising APHL, 50% (Amaya Capital, 80%; American Capital, 20%); AIM, 30%; ARM, 6%; Aldwych, 14%; Edo State, 2.5% DFI agency and financing The $120 million in financing KfW Bankengruppe of Germany, Subordinated debt: method was funded from a FMO, IFC, DEG, French IFC, EIB, and EAIF; consortium of four Investment Corporation, EAIF, equity: IFC, commercial banks and three World Bank Group, Swedfund, $4 million DFIs. The DFIs are FMO, OPIC African Export-Import Bank, and DEG. The commercial banks are the Africa Merchant Bank (France), a division of Belgolaise Bank; United Bank for Africa (Nigeria); Rand Merchant Bank (South Africa); and Diamond Bank (Nigeria). Total DFI financing (US$, millions) 60.0 — — 332.5 4.0 ODA grants (US$, millions) Local credit enhancements Sovereign guarantee, $60 million PPA backed by oil revenues PPA backed by oil and security letter of credit from Ministry of Nigerian Petroleum revenues of arrangements of Finance Development Company Nigerian Petroleum Development Company Foreign credit OPIC political risk insurance Credit enhancement partial risk enhancements and guarantees (IBRD) security arrangements Note: Empty cells indicate that no information was available. AIIF = African Infrastructure Investment Fund; APHL = Azura Power Holding Limited; ARM = Asset and Resource Management; CCGT = combined- cycle gas turbine; DEG = German Investment and Development Corporation; DFI = development finance institution; EAIF = Emerging Africa Infrastructure Fund; EIB = European Investment Bank; FMO = Netherlands Development Finance Company; IBRD = International Bank for Reconstruction and Development; IFC = International Finance Corporation; IPP = independent power project; MW = megawatt; 303 NNPC = Nigerian National Petroleum Corporation; OCGT = open-cycle gas turbine; ODA = official development assistance; OPIC = Overseas Private Investment Corporation; PPA = power purchase agreement; YFP = Yinka Folawiyo Power. In “Total DFI financing” cells “—” indicates 0 financing. 304 Independent Power Projects in Sub-Saharan Africa Table E.11  IPP Investments in Rwanda, by Project Project information Project name KivuWatt Capacity (MW) 100 Technology Methane gas Total investment (US$, millions) 200.0 Year of financial close 2011 Commercial operation date 2015 Project status Construction Procurement method Direct negotiation Number of bids Contract period (years) 25 Contract type Build-own-operate Sponsors/developer ContourGlobal (100%, United States) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method MIGA (guarantee, $26 million, 2011), AfDB (loan, $25 million, 2011). U.K., Dutch, Swedish, and Swiss governments loaned $91 million. Total DFI financing (US$, millions) 116.0 ODA grants (US$, millions) — Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; DFI = development finance institution; IPP = independent power project; MIGA = Multilateral Investment Guarantee Agency; MW = megawatt; ODA = official development assistance. In “ODA grants” cell “—” indicates 0 grants. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Table E.12  IPP Investments in Senegal, by Project Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 GTi Dakar Ltd. Kounoune I IPP Saint-Louis-Dagana- Sendou Tobene Podor Rural Electrification Capacity (MW) 52 67.5 19 125 87.5 Technology OCGT + CCGT MSD/HFO Solar, PV Coal MSD/HFO Total investment (US$, millions) 65.0 110.0 22.0 254.3 163.5 Year of financial close 1997 2005 2010 2013 2014 Commercial operation date 2000 2008 2017 2015 Project status Operational Operational Operational Construction Construction Procurement method International competitive bid International competitive bid International International International competitive bid, competitive bid competitive bid then direct negotiation Number of bids 2 1 Contract period (years) 15 15 25 Contract type Build-own-operate-transfer Build-own-operate Build-operate-transfer Sponsors/developer IFC, Sondel (Greenwich Air Melec PowerGen (part of Office National de Service Inc.) Matelec Group, Lebanon), l’Electricite (73%, Mitsubishi (Japan) Morocco), IFC (17%) Engineering, procurement, MEGS, a joint venture between MHI Equipment Europe, France and construction Sondel and General Electric (member, Mitsubishi Heavy Industries Group) Fuel arrangement During the project negotiations, the structure of the FSA and purchase power agreement (PPA) were changed to turn the PPA into a tolling agreement. Debt-equity ratio 70/30 Local shareholder equity (entity, US$, millions) table continues next page 305 306 Table E.12  IPP Investments in Senegal, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 GTi Dakar Ltd. (cont.) Kounoune I IPP (cont.) Saint-Louis-Dagana- Sendou (cont.) Tobene (cont.) Podor Rural Electrification (cont.) Foreign shareholder equity (entity, US$, millions) DFI agency and financing IFC (loan, $13 million, 1997), IDA (guarantee, $7 million, IFC (equity, AfDB, FMO IFC lead arranger, Euro method IFC (equity, $2 million, 1997), 2005), IDA (loan, $10 million, $1 million, 2010) tranche = €78.5 million – IFC (syndication, $3 million, 2005), IFC (loan, $21 million, €28.5 million A Loan by IFC, 1997), IFC (equity, $1 million, 2005). and €50 million B Loan 1998), IFC (syndication, (€25 million by FMO and $12 million, 1998), IFC €25 million by EAIF), and a (quasi-equity, $7 million, local tranche for the CFA 1998), IFC (risk management, equivalent of €13.5 million $1 million, 2002) by BOAD Total DFI financing (US$, millions) 39.0 53.7 1.0 108.0 135.1 ODA grants (US$, millions) Local credit enhancements Government guarantee, escrow Government guarantee, a letter and security account of credit from Senelec arrangements Foreign credit Credit insurance through a A partial risk guarantee, but IDA partial risk guarantee enhancements and guarantee program of SACE, never signed by government security arrangements the Italian export credit agency, and a partial interest subsidy through the Mediocredito Central Subsidy Department (MCSD) Note: Empty cells indicate that no information was available. AfDB = African Development Bank; BOAD = West African Development Bank; CBAO = Banking Company of West Africa; CCGT = combined-cycle gas turbine; DFI = development finance institution; EAIF = Emerging Africa Infrastructure Fund; FMO = Netherlands Development Finance Company; FSA = Fuel Supply Agreement; HFO = heavy fuel oil; IDA = International Development Association; IFC = International Finance Corporation; IPP = independent power project; MEGS = Mediterranean Electric Generating Services; MHI = Manitoba Hydro International; MSD = medium-speed diesel; MW = megawatt; OCGT = open-cycle gas turbine; ODA = official development assistance; PV = photovoltaic; SENELEC = Société Nationale d’Électricité du Sénégal. Independent Power Projects in Sub-Saharan Africa 307 Table E.13  IPP Investments in Sierra Leone, by Project Project information Project name Addax Biomass Plant Capacity (MW) 15 Technology Biomass Total investment (US$, millions) 30 Year of financial close 2011 Commercial operation date 2013 Project status Operational Procurement method Direct negotiation Number of bids Contract period (years) Contract type Build-own-operate Sponsors/developer Addax & Oryx Group (100%, United Kingdom) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio 61/39 Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method AfDB (loan, $30 million, 2011) Total DFI financing (US$, millions) 30 ODA grants (US$, millions) Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; DFI = development finance institution; IPP = independent power project; MW = megawatt; ODA = official development assistance. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 308 Table E.14  IPP Investments in Tanzania, by Project Project information Project name 1 Project name 2 Project name 3 Project name 4 Independent Power Songas-Songo Songo Gas-to-Power Mtwara Region Gas-to-Power Symbion Tanzania Ltd. Project Project Capacity (MW) 100 189 18 120 Technology MSD/HFO CCGT OCGT/CCGT OCGT/CCGT Total investment (US$, millions) 127.2 316.0 32.0 123.2 Year of financial close 1997 2001 2005 2006 Commercial operation date 2002 2004 2007 2006, 2007 Project status Operational Operational Operational Operational Procurement method Direct negotiation International competitive bid International competitive bid Direct negotiation Number of bids 2 Contract period (years) 20 20 25 Expiry Oct. 2014 Contract type Build-own-operate Build-own-operate Build-own-operate Emergency/short-term Sponsors/developer VIP Engineering and TransCanada sold majority shares to AES Artumas Group Inc. (87%, Canada), Built by Richmond, sold Marketing Ltd. (Tanzania), (United States) in 1999 and AES sold FMO (13%) to Dowans, then to MechMar Energy Sdn Bhd majority shares to Globeleq (United Symbion Kingdom) in 2003. All preferred equity shares were converted into “Loan Notes” in June 2009. Only common shares remain. Engineering, procurement, Larsen and Toubro (L&T) and construction Fuel arrangement IPTL imports fuel, which is a Songo Songo gas is provided to project Fuel is provided by a consortium that TANESCO purchases pass-through to the company at a rate of $0.55/MMBtu for includes the project sponsor (has a natural gas, and fuel utility. turbines I–V and at $2.17/MMBtu for 25.4% stake in the gas concession), is a pass-through. turbine VI. at a charge of $5.00/MMBtu, which is passed through to utility. Debt-equity ratio 0/100 70/30 0/100 0/100 table continues next page Table E.14  IPP Investments in Tanzania, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Local shareholder equity VIP (30% in kind, Tanzania— 4.83 100% financed with balance sheet (entity, US$, millions) disputed) has sought to of shareholders sell shares. Foreign shareholder equity Mechmar (70%, Malaysia) 5.67 100% financed with balance sheet Equity financed (entity, US$, millions) has sought to sell shares. of shareholders DFI agency and financing IBRD (loan, $183 million, 2001), FMO, 13% equity shareholder method EIB (loan, $55 million, 2001) Total DFI financing (US$, millions) — 249.0 4.2 — ODA grants (US$, millions) — 100.3 — — Local credit enhancements Sovereign guarantee, Escrow account: for first 115 MW, with the Tariff Equalization Fund provided a No government and security arrangements liquidity facility equivalent government matching every $1 spent by fixed-value account designed to guarantees to four months of capacity the project company; liquidity facility make up the difference between charge (but not yet equivalent to four months of capacity the national tariff and the established) charge for the first three years, declining to cost-based tariff (which would two months starting in year four through otherwise be charged to the final the remaining years of the contract consumer) under the project. Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. CCGT = combined-cycle gas turbine; DFI = development finance institution; EIB = European Investment Bank; FMO = Netherlands Development Finance Company; HFO = heavy fuel oil; IBRD = International Bank for Reconstruction and Development; IPP = independent power project; IPTL = Independent Power Tanzania Ltd.; MMBtu = million British thermal units; MSD = medium-speed diesel; MW = megawatt; OCGT = open-cycle gas turbine; ODA = official development assistance; TANESCO = Tanzania Electric Supply Company. In “Total DFI financing” and “ODA grants” cells “—” indicates 0 financing or grants, respectively. 309 310 Independent Power Projects in Sub-Saharan Africa Table E.15  IPP Investments in Togo, by Project Project information Project name Centrale Thermique de Lomé Capacity (MW) 100 Technology Triple fuel Total investment (US$, millions) 196.0 Year of financial close 2008 Commercial operation date 2010 Project status Operational Procurement method Direct negotiation Number of bids Contract period (years) 25 Contract type Build-operate-transfer Sponsors/developer ContourGlobal (80%, United States), IFC (20%) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method IFC (equity/loan) and OPIC Total DFI financing (US$, millions) 161.0 ODA grants (US$, millions) Local credit enhancements and security arrangements Payment guarantee Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. DFI = development finance institution; IFC = International Finance Corporation; IPP = independent power project; MW = megawatt; ODA = official development assistance; OPIC = Overseas Private Investment Corporation. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Table E.16A  IPP Investments in Uganda, by Project Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 Kasese Cobalt Kilembe Mines Kakira Bujagali Hydro Project ECO Ishasha Mini Tronder/Bugoye Hydro (Mubuku III) (Mubuku I) Cogeneration Hydropower Plant Electric Power Project Plant (Mubuku II) Capacity (MW) 9.9 5.4 32 250 6.5 13 Technology Hydro, small Hydro, small Waste/bagasse Hydro Hydro, small (<20 MW) Hydro, small (<20 MW) (<20 MW) (<20 MW) Total investment (US$, millions) 22.5 16.2 56.0 860.0 14.0 65.7 Year of financial close 1999 1975 2003 2007 2008 2008 Commercial operation date 2013 2012 2011 2009 Project status Operational Not operational Operational Operational Operational Operational Procurement method Direct Direct negotiation/ International competitive Direct negotiation Direct negotiation negotiation REFiT (PPA3) bid Number of bids 3 Contract period (years) 20 20 30 30 20 Contract type Build-own-operate Build-operate-transfer Build-operate-transfer Build-operate-transfer Sponsors/developer Blue Earth Government of Madhvani Group BEL Ltd. (Sithe Global Power) Eco Power (100%, Tronder Power Ltd. Refineries Inc. Uganda (51%) (100%, Uganda) (58%, United States), Sri Lanka) (100%, Norway) (100%, Aga Khan Fund (31%, Uganda) Switzerland) Engineering, procurement, In-house/consultant and construction Fuel arrangement Debt-equity ratio 78/22 70/30 53/32 (14% grant by government of Norway) Local shareholder equity Nonrecourse Tronder (entity, US$, millions) table continues next page 311 312 Table E.16A  IPP Investments in Uganda, by Project (continued) Project information Project name 1 Project name 2 Project name 3 Project name 4 Project name 5 Project name 6 Kasese Cobalt Kilembe Mines Kakira Bujagali Hydro Project ECO Ishasha Mini Tronder/Bugoye Hydro (Mubuku III) (Mubuku I) Cogeneration (cont.) Hydropower Plant Electric Power Project (cont.) (cont.) Plant (cont.) (cont.) (Mubuku II) (cont.) Foreign shareholder equity Balance sheet Norfund (entity, US$, millions) DFI agency and financing EADB MIGA (guarantee, EAIF/FMO/government of method $115 million, 2007), Norway/Norfund IFC (loan, $130 million, 2007), IDA (guarantee, $115 million, 2007), AfDB (loan, $110 million, 2007), EIB (loan, $130 million, 2007) Total DFI financing — — 15.0 370.0 — 48.2 (US$, millions) ODA grants (US$, millions) GETFiT 14% grant by government of Norway Local credit enhancements Government payment Government payment and security arrangements guarantee guarantee Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; DFI = development finance institution; EADB = East African Development Bank; EAIF = Emerging Africa Infrastructure Fund; EIB = European Investment Bank; FMO = Netherlands Development Finance Company; GETFiT = global energy transfer feed-in tariff; IDA = International Development Association; IFC = International Finance Corporation; IPP = independent power project; MIGA = Multilateral Investment Guarantee Agency; MW = megawatt; ODA = official development assistance; PPA = power purchase agreement; REFiT = renewable energy feed-in tariff. In “Total DFI financing” cells “—” indicates 0 financing. Table E.16B  IPP Investments in Uganda, by Project Project information Project name 7 Project name 8 Project name 9 Project name 10 Project name 11 Project name 12 Mpanga Hydro Power Namanve Power Kinyara Cogeneration Buseruka/Hydromax Tororo Power Station Tororo Power Project Plant Plant Hydropower Plant Station Capacity (MW) 18 50 7.5 9 16 34 Technology Hydro, small (<20 MW) MSD/HFO Waste/bagasse Hydro, small (<20 MW) MSD/HFO MSD/HFO Total investment (US$, millions) 27.0 74.0 29.0 27.0 41.5 41.5 Year of financial close 2008 2008 2009 2009 2009 2012 Commercial operation date 2011 2011 2012 2010 Project status Operational Operational Operational Operational Operational Operational Procurement method Direct negotiation International Direct negotiation Direct negotiation Direct negotiation competitive bid Number of bids 3 Contract period (years) 20 6 20 30 9 Contract type Build-operate-transfer Build-operate- Build-operate-own Build-operate-transfer Build-operate-own transfer Sponsors/developer SAEMS (100%, Jacobsen Elektro Kinyara Sugar Group Hydromax Limited Electro-Maxx (100%, United States) (100%, Norway) (100%, Uganda) (100%, Uganda) Uganda) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio 70/30 60/40 Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method EAIF ($14 million), FMO AfDB (loan, $9 million, 2009) Total DFI financing (US$, millions) 20.0 — — 9.0 — — ODA grants (US$, millions) Local credit enhancements and Payment guarantee Payment guarantee Variable government Government security arrangements payments payment guarantee Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; DFI = development finance institution; EAIF = Emerging Africa Infrastructure Fund; FMO = Netherlands Development 313 Finance Company; HFO = heavy fuel oil; IPP = independent power project; MSD = medium-speed diesel; MW = megawatt; ODA = official development assistance; SAEMS = South Asia Energy Management Systems. In “Total DFI financing” cells “—” indicates 0 financing. Table E.16C  IPP Investments in Uganda, by Project 314 Project information Project name 13 Project name 14 Project name 15 Project name 16 Project name 17 Project name 18 Kakaka Hydropower Rwimi Lubilia Hydropower Muvumbe Nengo Bridge SAIL Cogen Project Hydropower Project Hydropower Hydropower Project Project Project Capacity (MW) 5 5.4 5.4 6.5 6.9 6.9 Technology Hydro, small (<20 MW) Hydro, small Hydro, small (<20 MW) Hydro, small Hydro, small Waste/bagasse (<20 MW) (<20 MW) (<20 MW) Total investment (US$, millions) 18.0 18.0 18.0 14.0 27.0 22.0 Year of financial close 2015 2015 2015 2015 2015 2015 Commercial operation date 2016 2016 2016 2016 2016 2015 Project status Financing in process Financing in Financing in process Financing in Financing in process Construction finished, process process not interconnected Procurement method REFiT REFiT REFiT REFiT REFiT REFiT Number of bids Contract period (years) 20 20 20 20 20 20 Contract type Build-operate-transfer Build-operate- Build-operate-transfer Build-operate- Build-operate- Build-own-operate transfer transfer transfer Sponsors/developer Frontier (Danish private Eco Power (100%, Frontier (Danish private Vidullanka (100%, Jacobsen Elektro Sugar Allied Industries equity fund) Sri Lanka) equity fund) Sri Lanka) (100%, Norway) (Uganda) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio 70/30 65/35 Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method EAIF, FMO EAIF, FMO EADB Total DFI financing (US$, millions) — — — — — — ODA grants (US$, millions) GETFiT GETFiT GETFiT GETFiT GETFiT Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. DFI = development finance institution; EADB = East African Development Bank; EAIF = Emerging Africa Infrastructure Fund; FMO = Netherlands Development Finance Company; GETFiT = global energy transfer feed-in tariff; IPP = independent power project; MW = megawatt; ODA = official development assistance; REFiT = renewable energy feed-in tariff. In “Total DFI financing” cells “—” indicates 0 financing. Table E.16D  IPP Investments in Uganda, by Project Project information Project name 19 Project name 20 Project name 21 Project name 22 SAEMS Nyamwamba SHPP Siti I/II Hydropower Project Tororo North/South Tororo North/South Capacity (MW) 9.2 21.5 10 10 Technology Hydro, small (<20 MW) Hydro, large Solar PV Solar PV Total investment (US$, millions) 34.0 48.0 18.0 18.0 Year of financial close 2015 2015 2015 2015 Commercial operation date 2016 2016–17 Project status Construction started in 2014 Financing in process Financing in process Financing in process Procurement method REFiT REFiT International competitive bid International competitive bid Number of bids Contract period (years) 20 20 Contract type Build-operate-transfer Build-operate-transfer Sponsors/developer SAEMS (100%, United States) Frontier (Danish private Simba/Building Energy Access/TSK equity fund) Engineering, procurement, and construction Fuel arrangement Debt-equity ratio 73/27 70/30 75/25 75/25 Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method Other (loan, $24 million, EAIF, FMO ($5.3 million) FMO FMO 2012) of which EAIF accounts for $6 million Total DFI financing (US$, millions) 6.0 5.3 — — ODA grants (US$, millions) GETFiT GETFiT Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. DFI = development finance institution; EAIF = Emerging Africa Infrastructure Fund; FMO = Netherlands Development Finance Company; IPP = independent power project; MW = megawatt; ODA = official development assistance; PV = photovoltaic; REFiT = renewable energy feed-in tariff; SAEMS = South Asia Energy Management Systems; SHPP = small hydropower project. In “Total DFI financing” cells “—” indicates 0 financing. 315 316 Independent Power Projects in Sub-Saharan Africa Table E.17  IPP Investments in Zambia, by Project Project information Project name 1 Project name 2 Ndola Energy Tata Itezhi-Tezhi Hydropower Plant Capacity (MW) 50 120 Technology MSD/HFO Hydro Total investment (US$, millions) 72.0 230.0 Year of financial close 2012 2014 Commercial operation date 2013 2016 Project status Operational Construction Procurement method Direct negotiation Direct negotiation Number of bids Contract period (years) 25 Contract type Build-operate-transfer Sponsors/developer Subsidiary of Concordia Tata Enterprises (50%, India), Energy (Group of ZESCO (50%, Zambia) Mauritius) Engineering, procurement, and construction (EPC) Chinese EPC/international competitive bid for EPC Fuel arrangement Debt-equity ratio Local shareholder equity (entity, US$, millions) Foreign shareholder equity (entity, US$, millions) DFI agency and financing method EIB (equity, $18 million, 2011); 2014: a $142 million loan by DBSA, Proparco, AfDB, and FMO Total DFI financing (US$, millions) — 162.0 ODA grants (US$, millions) Local credit enhancements and security arrangements Foreign credit enhancements and security arrangements Note: Empty cells indicate that no information was available. AfDB = African Development Bank; DBSA = Development Bank of Southern Africa; DFI = development finance institution; EIB = European Investment Bank; FMO = Netherlands Development Finance Company; HFO = heavy fuel oil; IPP = independent power project; MSD = medium-speed diesel; MW = megawatt; ODA = official development assistance; ZESCO = Zambia Electricity Supply Corporation. In “Total DFI financing” cell “—” indicates 0 financing. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Table E.18  IPP Investments in South Africa, by Project Local credit Total Com­ Total DFI enhance- investment Finan- mercial Procure- DFI agency and financing ments and Capacity (US$, cial ­operation Project ment Sponsors/ financing (US$, security Project (MW) Technology ­millions) close date ­status method developer method ­millions) arrangements Bethlehem Hydro 7 Hydro, small 13.7 2005 2009, 2012 Operational DN NuPlanet (26%, Other (loan, $5 5.0 (<20 MW) Netherlands) million, 2005) Darling Wind Farm 5 Wind, 9.9 2006 2008 Operational DN Darling — onshore Independent Power Producer Pty Ltd. (26%, South Africa) Sasol 373 OCGT/CCGT 399.0 2010 2010 Operational DN Sasol — SlimSun Swartland 5 Solar, PV 26.1 2012 2013 Operational ICB IDC, in 2012 R 8.9 Payment Solar Park (exchange guarantee rate, 0.12) RustMo1 Solar 6.9 Solar, PV 28.0 2012 2013 Operational ICB IDC, in 2012 R 9.8 Payment Farm (exchange guarantee rate, 0.12) Konkoonsies Solar 9.7 Solar, PV 43.9 2012 2013 Operational ICB IDC, in 2012 R 15.0 Payment Energy Facility (exchange guarantee rate, 0.12) Aries Solar Energy 9.7 Solar, PV 44.5 2012 2013 Operational ICB IDC, in 2012 R 15.0 Payment Facility (exchange guarantee rate, 0.12) Greefspan PV 9.9 Solar, PV 53.5 2012 2014 Operational ICB IDC, in 2012 R 10.0 Payment Power Plant (exchange guarantee rate, 0.12) Mulilo Solar 10 Solar, PV 39.3 2012 2013 Operational ICB IDC, in 2012 R 13.6 Payment PV De Aar (exchange guarantee rate, 0.12) table continues next page 317 318 Table E.18  IPP Investments in South Africa, by Project (continued) Local credit Total Com­ Total DFI enhance- investment Finan- mercial Procure- DFI agency and financing ments and Capacity (US$, cial ­operation Project ment Sponsors/ financing (US$, security Project (MW) Technology ­millions) close date ­status method developer method ­millions) arrangements Herbert PV 20 Solar, PV 105.3 2012 2013 Operational ICB IDC, in 2012 R 12.8 Payment Power Plant (exchange guarantee rate, 0.12) Mulilo Solar 20 Solar, PV 79.1 2012 2015 Operational ICB IDC, in 2012 R 26.9 Payment PV Prieska (exchange guarantee rate, 0.12) Dassieklip Wind 27 Wind, 83.1 2012 2014 Operational ICB IDC, in 2012 R 18.0 Payment Energy Facility onshore (exchange guarantee rate, 0.12) MetroWind Van 27 Wind, 74.8 2012 2014 Operational ICB — Payment Stadens Wind onshore guarantee Farm Soutpan Solar Park 28 Solar, PV 155.7 2012 2014 Operational ICB — Payment guarantee Witkop Solar Park 30 Solar, PV 174.3 2012 2014 Operational ICB — Payment guarantee Touwsrivier 36 Solar, PV 197.5 2012 2014 Operational ICB — Payment Solar Park guarantee De Aar Solar PV 45.6 Solar, PV 178.0 2012 2014 Operational ICB Globeleq DBSA, in 2012 R 43.0 Payment (exchange guarantee rate, 0.12) South Africa 45.6 Solar, PV 173.6 2012 2014 Operational ICB Globeleq DBSA, in 2012 R 41.9 Payment Mainstream (exchange guarantee Renewable rate, 0.12) Power Droogfontein table continues next page Table E.18  IPP Investments in South Africa, by Project (continued) Local credit Total Com­ Total DFI enhance- investment Finan- mercial Procure- DFI agency and financing ments and Capacity (US$, cial ­operation Project ment Sponsors/ financing (US$, security Project (MW) Technology ­millions) close date ­status method developer method ­millions) arrangements Khi Solar One 50 Solar, CS 509.8 2012 Construction ICB IFC, EIB, DBSA, 298.7 Payment and IDC all guarantee have debt; IDC also has 29% equity. Letsatsi Solar 64 Solar, PV 320.9 2012 2014 Operational ICB — Payment Photovoltaic guarantee Park Lesedi Solar 64 Solar, PV 322.7 2012 2014 Operational ICB — Payment Photovoltaic guarantee Park Hopefield Wind 65.4 Wind, 195.6 2012 2014 Operational ICB — Payment Farm onshore guarantee Kalkbult 72.5 Solar, PV 274.9 2012 2013 Operational ICB DBSA, in 2012 R 29.8 Payment (exchange guarantee rate, 0.12) Kathu Solar Plant 75 Solar, PV 430.4 2012 2014 Operational ICB DBSA, in 2012 R 45.0 Payment (exchange guarantee rate, 0.12) Solar Capital 75 Solar, PV 296.6 2012 2014 Operational ICB — Payment De Aar guarantee Noblesfontein 75 Wind, 196.8 2012 2014 Operational ICB — Payment Phase 1 onshore guarantee Kouga Wind Farm 80 Wind, 235.6 2012 2014 Operational ICB IDC, in 2012 R 53.9 Payment onshore (exchange guarantee rate, 0.12) table continues next page 319 320 Table E.18  IPP Investments in South Africa, by Project (continued) Local credit Total Com­ Total DFI enhance- investment Finan- mercial Procure- DFI agency and financing ments and Capacity (US$, cial ­operation Project ment Sponsors/ financing (US$, security Project (MW) Technology ­millions) close date ­status method developer method ­millions) arrangements Dorper Wind Farm 97.5 Wind, 286.1 2012 2014 Operational ICB — Payment onshore guarantee KaXu Solar One 100 Solar CS 976.3 2012 2014 Operational ICB billion; 454.8 DBSA, R 1.2 ­ Payment IDC, R 830 guarantee million; IFC, R 600 million; IFC (as Implemen- tation Entity of the Clean Technology Fund), R 232 million. Mezzanine debt: DBSA, R 195 million; IDC, R 195 million Equity: IDC, 29% Jeffreys Bay 138 Wind, 366.5 2012 2014 Operational ICB Globeleq DBSA, 101.8 Payment onshore R 849 million guarantee Cookhouse 138.6 Wind, 295.6 2012 2014 Operational ICB — Payment Wind Farm onshore guarantee Vredendal 8.82 Solar, PV 29.1 2013 Operational ICB — Payment Solar Park guarantee Stortemelk Hydro 4.4 Hydro, small 17.4 2013 Operational — Payment Pty Ltd. (<20 MW) guarantee table continues next page Table E.18  IPP Investments in South Africa, by Project (continued) Local credit Total Com­ Total DFI enhance- investment Finan- mercial Procure- DFI agency and financing ments and Capacity (US$, cial ­operation Project ment Sponsors/ financing (US$, security Project (MW) Technology ­millions) close date ­status method developer method ­millions) arrangements Upington Solar PV 8.9 Solar, PV 26.5 2013 Operational ICB — Payment guarantee Aurora-Rietvlei 9 Solar, PV 30.3 2013 Operational ICB — Payment Solar Power guarantee Neusberg Hydro 10 Hydro, small 73.5 2013 Operational ICB IDC, in 2013 R 19.7 Payment Electric (<20 MW) (exchange guarantee Project A rate, 0.12), senior and mezzanine debt Chaba Wind Farm 21 Wind, 54.4 2013 Operational ICB IDC, in 2013 R 15.5 Payment Project onshore (exchange guarantee rate, 0.12) Waainek Wind 23.3 Wind, 69.7 2013 Construction ICB IDC, in 2013 R 19.9 Payment Power onshore (exchange guarantee rate, 0.12) Linde 36.8 Solar, PV 147.2 2013 Operational ICB — Payment guarantee Bokpoort CSP 50 Solar CS 642.2 2013 Construction ICB IDC (25% equity) 45.1 Payment Project guarantee Grassridge Wind 59.8 Wind, 161.3 2013 Operational ICB IDC, 2013 46.1 Payment Energy Project onshore guarantee Boshof Solar Park 60 Solar, PV 312.0 2013 Operational ICB OPIC 222.7 Payment guarantee table continues next page 321 322 Table E.18  IPP Investments in South Africa, by Project (continued) Local credit Total Com­ Total DFI enhance- investment Finan- mercial Procure- DFI agency and financing ments and Capacity (US$, cial ­operation Project ment Sponsors/ financing (US$, security Project (MW) Technology ­millions) close date ­status method developer method ­millions) arrangements Dreunberg 69.6 Solar, PV 286.6 2013 Operational ICB — Payment guarantee Sishen Solar 74 Solar, PV 294.8 2013 2014 Operational ICB — Payment Facility guarantee Solar Capital 75 Solar, PV 326.9 2013 Operational ICB IDC 111.1 Payment De Aar 3 guarantee Jasper Power 75 Solar, PV 290.7 2013 Operational ICB DBSA 60.0 Payment Company guarantee West Coast One 90.8 Wind, 252.1 2013 Operational ICB DBSA 44.1 Payment Wind Farm onshore guarantee Tsitsikamma 94.8 Wind, 365.9 2013 Construction ICB — Payment Community onshore guarantee Wind Farm Amakhala Emoyeni 133.7 Wind, 497.0 2013 Construction ICB IFC 76.1 Payment Wind Farm onshore guarantee Gouda Wind 135.5 Wind, 336.3 2013 Operational ICB — Payment Project onshore guarantee Mkuze 16.5 Biomass 95.6 2015 Financing ICB — Payment and guarantee approvals under way Johannesburg 18 Landfill gas 24.8 2014 Partially ICB — Payment Landfill Gas to opera- guarantee Electricity tional Tom Burke Solar 60 Photovoltaic, 2014 Construction ICB — Payment Park thin film guarantee fixed table continues next page Table E.18  IPP Investments in South Africa, by Project (continued) Local credit Total Com­ Total DFI enhance- investment Finan- mercial Procure- DFI agency and financing ments and Capacity (US$, cial ­operation Project ment Sponsors/ financing (US$, security Project (MW) Technology ­millions) close date ­status method developer method ­millions) arrangements Adams Solar PV 2 75 Photovoltaic, 2014 Construction ICB — Payment crystalline guarantee fixed Electra Capital 75 Photovoltaic, 2014 Construction ICB — Payment (Pty) Ltd. crystalline guarantee fixed Mulilo Sonnedix 75 Photovoltaic, 108.0 2014 Construction ICB — Payment Prieska PV crystalline guarantee fixed Mulilo Prieska PV 75 Photovoltaic, 200.0 2014 Construction ICB IDC, 2014 20.2 Payment crystalline guarantee single axis Pulida Solar Park 75 Photovoltaic, 2014 Financing ICB — Payment thin film done guarantee fixed Noupoort 80 Wind, 180.0 2014 Construction ICB EKF and DBSA 108.5 Payment Mainstream onshore guarantee Wind Nojoli Wind Farm 86.6 Wind, 2014 Financing ICB — Payment onshore done guarantee Longyuan Mulilo 96.5 Wind, 180.0 2014 Financing ICB IDC 63.0 Payment De Aar onshore done guarantee Maanhaarberg Wind Energy Facility table continues next page 323 Table E.18  IPP Investments in South Africa, by Project (continued) 324 Local credit Total Com­ Total DFI enhance- investment Finan- mercial Procure- DFI agency and financing ments and Capacity (US$, cial ­operation Project ment Sponsors/ financing (US$, security Project (MW) Technology ­millions) close date ­status method developer method ­millions) arrangements Ilanga CSP 100 Concentrated 735.4 2014 Construction ICB IDC and DBSA 180.0 Payment 1/Karoshoek solar guarantee Solar One power, parabolic trough, with storage (4.5 hours per day) Xina Solar One 100 Concentrated 880.0 2014 Construction ICB DBSA, R 800 316.8 Payment solar million; IDC guarantee power, R 750 million; parabolic AfDB, R 1.5 trough, billion; IDC, with 20% equity storage (5 hours per day) Red Cap–Gibson 110 Wind, 202.5 2014 Financing ICB — Payment Bay onshore done guarantee Khobab Wind Farm 137.7 Wind, 315.0 2014 Construction ICB DBSA, EKF 214.2 Payment onshore guarantee Loeriesfontein 138.2 Wind, 315.0 2014 Construction ICB DBSA, EKF 208.5 Payment 2 Wind Farm onshore guarantee Longyuan Mulilo 139.0 Wind, 264.6 2014 Financing ICB IDC 85.5 Payment De Aar 2 North onshore done guarantee Wind Energy Facility Note: Empty cells indicate that no information was available. Renewable Energy Independent Power Project Procurement Programme (REIPPPP) investment data are derived from public sources and have an error range of about 10 percent. Final financial close data are different from bid data and are not yet publicly available. AfDB = African Development Bank; CCGT = combined-cycle gas turbine; CSP = concentrated solar power; DBSA = Development Bank of Southern Africa; DFI = development finance institution; DN = direct negotiation; EIB = European Investment Bank; EKF = Eksport Kredit Fonden (Danish export credit agency); ICB = international competitive bid; IDC = Industrial Development Corporation; IFC = International Finance Corporation; IPP = independent power project; MW = megawatt; OCGT = open-cycle gas turbine; OPIC = Overseas Private Investment Corporation; PV = photovoltaic; R = rand. In “Total DFI financing” cells “—” indicates 0 financing. Environmental Benefits Statement The World Bank Group is committed to reducing its environmental footprint. In support of this commitment, the Publishing and Knowledge Division leverages electronic publishing options and print-on-demand technology, which is located in regional hubs worldwide. Together, these initiatives enable print runs to be lowered and shipping distances decreased, resulting in reduced paper ­consumption, chemical use, greenhouse gas emissions, and waste. The Publishing and Knowledge Division follows the recommended standards for paper use set by the Green Press Initiative. The majority of our books are printed on Forest Stewardship Council (FSC)–certified paper, with nearly all containing 50–100 percent recycled content. The recycled fiber in our book paper is either unbleached or bleached using totally chlorine-free (TCF), processed chlorine-free (PCF), or enhanced elemental chlorine-free (EECF) processes. More information about the Bank’s environmental philosophy can be found at http://www.worldbank.org/corporateresponsibility. Independent Power Projects in Sub-Saharan Africa  •  http://dx.doi.org/10.1596/978-1-4648-0800-5 Inadequate electricity services pose a major impediment to reducing extreme poverty and boosting shared prosperity in Sub-Saharan Africa. Simply put, Africa does not have enough power. Despite the abundant low-carbon and low-cost energy resources available to Sub-Saharan Africa, the region’s entire installed electricity capacity, at a little over 80 gigawatts (GW), is equivalent to that of the Republic of Korea. Looking ahead, Sub-Saharan Africa will need to ramp up its power generation capacity substantially. The investment needed to meet this goal largely exceeds African countries’ already stretched public finances. Increasing private investment is critical to help expand and improve electricity supply. Historically, most private sector finance has been channeled through privately financed independent power projects (IPPs), supported by nonrecourse or limited recourse loans, with long-term power purchase agreements with the state utility or another off-taker. Between 1990 and 2014, IPPs have spread across Sub-Saharan Africa and are now present in 18 countries. However, private investment could be much greater and less concentrated. The objective of Independent Power Projects in Sub-Saharan Africa: Lessons from Five Key Countries is to evaluate the experience of IPPs and identify lessons that can help African countries attract more and better private investment. The analysis is based primarily on in-depth case studies carried out in five countries—Kenya, Nigeria, South Africa, Tanzania, and Uganda—that have the most extensive experience with IPPs. At the core of this analysis is a reflection on whether IPPs have in fact benefited Sub-Saharan Africa, and how they might be improved. ISBN 978-1-4648-0800-5 Africa Renewable Energy and Access Program (AFREA) SKU 210800