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March 2020 LONG TERM GENERATION EXPANSION PLAN 2020-2039(DRAFT)CEYLON ELECTRICITY BOARD Transmission and Generation Planning Branch Transmission Division Ceylon Electricity Board Sri Lanka March 2020 Long Term Generation Expansion Planning Studies 2020-2039 Compiled and prepared by The Generation Planning Unit Transmission and Generation Planning Branch Ceylon Electricity Board,Sri Lanka Long-term generation expansion planning studies are carried out every two years by the Transmission&Generation Planning Branch of the Ceylon Electricity Board,Sri Lanka and this report is a biennial publication based on the results of the latest expansion planning studies.The data used in this study and the results of the study,which are published in this report,are intended purely for this purpose.Price Rs.4000.00 Ceylon Electricity Board,Sri Lanka,2020 Note:Extracts from this book should not be reproduced without the approval of General Manager CEB Foreword The Report on Long Term Generation Expansion Planning Studies 2020-2039,presents the results of the latest expansion planning studies conducted by the Transmission and Generation Planning Branch of the Ceylon Electricity Board for the planning period 2020-2039,and replaces the Long Term Generation Expansion Plan 2018-2037.This report,gives a comprehensive view of the existing generating system,future electricity demand and future power generation options in addition to the expansion study results.The latest available data were used in the study.The Planning Team wishes to express their gratitude to all those who have assisted in preparing the report.We would welcome suggestions,comments and criticism for the improvement of this publication.March 2020.Transmission and Generation Planning Branch Letters:5th Floor,Head Office Bldg.Tr.and Generation Planning Branch Ceylon Electricity Board 5th Floor,Ceylon Electricity Board Sir Chittampalam A.Gardinar Mw.P.O.Box 540 Colombo 02 Colombo,Sri Lanka e-mail:cegptgp.trceb.lk Tel: 94-11-2329812 Fax: 94-11-2434866 Prepared by:Reviewed by:Mr.V.B.Wijekoon Dr.M.N.S.Perera Chief Engineer(Generation Planning)Additional General Manager(Transmission)Mr.M.B.S Samarasekara Former Chief Engineer(Generation Planning)Mr.P.L.G.Kariyawasam Former Additional General Manager(Transmission)Mr.M.L.Weerasinghe Deputy General Manager(Trans.&Gen.Planning)Electrical Engineers Mr.R.B Wijekoon Mr.J Nanthakumar Mrs.D.C Hapuarachchi Former Deputy General Manager(Trans.&Gen.Planning)Mrs.M.D.V Fernando Mr.K.H.A Kaushalya Mr.K.A.M.N.Pathiratne Any clarifications sought or request for copies of the report should be sent to the Deputy General Manager(Transmission and Generation Planning)at the address above.Page i CONTENT Page Contents i Annexes v List of Tables vi List of Figures viii Acronyms x Executive Summary E-1 1 Introduction 1-1 1.1 Background 1-1 1.2 The Economy 1-1 1.2.1 Electricity and Economy 1-2 1.2.2 Economic Projections 1-2 1.3 Energy Sector 1-3 1.3.1 Energy Supply 1-3 1.3.2 1.3.3 Energy Demand Emissions From Energy Sector 1-4 1-5 1.4 Electricity Sector 1-6 1.4.1 1.4.2 Ease of Doing Business Access to electricity 1-6 1-7 1.4.3 Electricity Consumption 1-8 1.4.4 Capacity and Demand 1-9 1.4.5 Generation 1-11 1.5 1.6 Implementation of Planning Cycle Planning Process 1-14 1-14 1.7 Objectives 1-14 1.8 Structure of the Report 1-15 2.The Existing and Committed Generating System 2-1 2.1 Hydro and Other Renewable Power Generation 2-1 2.1.1 CEB Owned Hydro and Other Renewable Power Plants 2-1 2.1.2 Other Renewable Power Plants Owned by IPPs 2-5 2.1.3 Capability of Existing Hydropower Plants 2-5 2.2 Thermal Generation 2-7 2.2.1 CEB Thermal Plants 2-7 2.2.2 Independent Power Producers(IPPs)2-10 3 Electricity Demand:Past and the Forecast 3-1 3.1 Past Demand 3-1 3.2 3.3 Policies,Guidelines and Future Major Development Projects for Electricity Demand Forecast 3.2.1 Policies and Guidelines 3.2.2 Future Major Development Projects Demand Forecasting Methodology 3-3 3-3 3-3 3-4 3.3.1 Medium Term Demand Forecast(2020-2023)3-4 3.3.2 Long Term Demand Forecast(2024-2044)3-5 3.4 Base Demand Forecast 3-10 3.5 Development of END USER Model(MAED)for Load Projection 3-11 3.6 Demand Forecast Scenarios 3-13 Page ii 3.7 Comparison with Past Forecasts 3-15 3.8 Electricity Demand Reduction and Demand Side Management 3-16 4 Thermal Power Generation Options for Future Expansions 4-1 4.1 Thermal Options 4-1 4.1.1 Available Studies for Thermal Plants 4-1 4.1.2 Thermal Power Candidates 4-2 4.1.3 Candidate Thermal Plant Details 4-2 4.2 Fuel 4-4 4.3 Screening of Generation Options 4-9 4.3.1 Thermal Plant Specific Cost Comparison 4-10 4.4 Current Status of Non Committed Thermal Projects 4-10 4.5 India-Sri Lanka Electricity Grid Interconnection 4-12 5 Renewable Generation Options for Future Expansions 5-1 5.1 Introduction 5-1 5.2 Major Renewable Energy Development 5-2 5.2.1 Available Studies on Hydro Projects 5-2 5.2.2 Committed Hydro Power Projects 5-3 5.2.3 Candidate Hydro Power Projects 5-4 5.2.4 Details of the Candidate Hydro Power 5-5 5.3 Hydro Power Capacity Extensions 5-6 5.3.1 Mahaweli Complex 5-6 5.3.2 Samanala Complex 5-8 5.3.3 Laxapana Complex 5-8 5.4 Other Renewable Energy Development 5-9 5.4.1 Projected future development 5-10 5.4.2 Wind Power Development 5-14 5.4.2.1 Development of Mannar Wind Farm Project 5-14 5.4.2.2 Development of Pooneryn Renewable Energy park 5-15 5.4.3 Solar Power Development 5-15 5.4.3.1 Development of Rooftop Solar PV Installations 5-16 5.4.3.2 Development of Small Scale Distributed Solar PV Project development 5-17 5.4.3.3 Development of large Scale Solar PV Parks 5-17 5.4.4 Mini-hydro Development 5-17 5.4.5 Biomass Power Development 5-18 5.4.6 Municipal Solid Waste Based Power Generation 5-18 5.4.7 Other Forms of Renewable Energy Technologies 5-19 5.4.8 Renewable Energy Grid Integration Study 2020-2030 5-19 5.4.9 Development of Grid Scale Storage Technologies 5-20 5.4.9.1 Pumped Storage Hydro Power Development 5-20 5.4.9.2 Development of Grid Scale Battery Energy Storages 5-22 6 Generation Expansion Planning Methodology and Parameters 6-1 6.1 Generation Planning Code 6-1 6.2 National Energy Policy and Strategies 6-1 6.3 6.4 Policy on Composition of Electricity Generation of Sri Lanka Preliminary Screening of Generation Options 6-2 6-3 6.5 Planning Software Tools 6-3 6.4.1 SDDP and NCP Models 6-3 Page iii 6.4.2 MAED Model 6-3 6.4.3 WASP Package 6-4 6.4.4 MESSAGE Software 6-4 6.4.5 OPTGEN Software 6-4 6.5 Hydro Power Development 6-5 6.6 Assessment of Environmental Implications and Financial Scheduling 6-5 6.7 Modeling of Other Renewable Energy 6-5 6.8 Study Parameters 6-6 6.8.1 Study Period 6-6 6.8.2 Economic Ground Rules 6-6 6.8.3 Plant Commissioning and retirements 6-6 6.8.4 Cost of Energy Not Served(ENS)6-6 6.8.5 Reserve Margin 6-6 6.8.6 Loss of Load Probability(LOLP)6-7 6.8.7 Discount Rate 6-7 6.8.8 Plant Capital Cost Distribution among Construction Years 6-7 6.8.9 Assumptions and Constraints Applied 6-7 7 Generation Expansion Planning Study Development of the Reference Case 7-1 7.1 Introduction 7-1 7.2 Reference Case Plan 7-1 7.2.1 System Capacity Distribution 7-3 7.2.2 System Energy Share 7-4 7.2.3 Environmental Emissions and Implications 7-5 8 Results of Generation Expansion Planning Study Base Case Plan 8-1 8.1 Results of the Preliminary Screening of Generation Options 8-1 8.2 Government Policy on Composition of Electricity Generation 8-2 8.3 Base Case Plan 8-3 8.3.1 System Capacity Distribution 8-7 8.3.2 System Energy Share 8-11 8.3.3 Fuel,Operation and Maintenance Cost 8-13 8.3.4 Reserve Margin and LOLP 8-16 8.3.5 Spinning Reserve Requirement 8-17 8.4 Impact of Demand Variation on Base Case Plan 8-17 8.5 Impact of Discount Rate Variation on Base Case Plan 8-18 8.6 Impact of Fuel Price Sensitivity on Base Case Plan 8-19 8.7 Summary 8-20 9 Results of Generation Expansion Planning Study Scenario Analysis 9-1 9.1 LTGEP 2018-2037 Base Case Equivalent Scenario 9-1 9.2 Energy Mix with Nuclear Power Development Scenario 9-2 9.3 HVDC Interconnection Scenario 9-3 9.4 Comparison of Energy Supply alternatives in 2039 9-5 9.4.1 Global Context 9-5 9.4.2 Sri Lankan Context 9-6 10 Environmental Implications 10-1 10.1 Greenhouse Gases 10-1 10.2 Country Context 10-1 10.2.1 Overview of Emissions in Sri Lanka 10-1 Page iv 10.2.2 Ambient Air Quality&Stack Emission Standards 10-2 10.3 Uncontrolled Emission Factors 10-4 10.4 Emission Control Technologies 10-5 10.5 Emission Factors Used 10-6 10.6 Environmental Implications Base Case 10-8 10.7 Environmental Implications Other Scenarios 10-9 10.7.1 Comparison of Emissions 10-9 10.7.2 Cost Impacts of CO2 Emission Reduction 10-12 10.8 Climate Change 10-13 10.8.1 Background 10-13 10.8.2 Climate Finance 10-16 10.8.3 Sri Lankan Context 10-16 10.9 Environmental Impact Mitigation Renewable Energy Development 10-21 10.10 Externalities 10-22 11 Recommendations of the Base Case Plan 11-1 11.1 Introduction 11-1 11.2 Recommendations for the Base Case Plan 11-1 11.2.1 Short Term Recommendations for 2020 and 2021 11-1 11.2.2 Long Term Recommendations 11-2 12 Implementation and Investment of Generation Projects 12-1 12.1 Committed and Candidate Power Plants in the Base Case 12-1 12.1.1 Committed Plants 12-1 12.1.2 Present Status of the Committed and Candidate Power Plants 12-1 12.2 Power Plants Identified in the Base Case Plan from 2020 to 2030 12-3 12.3 Implementation Schedule 12-4 12.4 Investment Plan for Base Case Plan 2020 2039 and Financial Options 12-6 12.4.1 Investment Plan for Base Case Plan 2020 2039 12-6 12.4.2 Financial Options 12-6 13 Contingency Analysis 13-1 13.1 Risk Events 13-1 13.1.1 Variation in Hydrology 13-1 13.1.2 Variation in Demand 13-1 13.1.3 Delays in Implementation of Power Plants 13-2 13.1.4 Long Period Outage of a Major Power Plant 13-3 13.2 Evaluation of Contingencies 13-3 11.2.1 Single Occurrence of Risk Events 13-3 11.2.2 Simultaneous Occurrence of Several Risk Events 13-5 13.3 Conclusion 13-9 14 Revision to Previous Plan 14-1 14.1 Government Policies 14-1 14.1 Demand Forecast 14-2 14.2 Fuel Prices Variation 14-3 14.3 Revised Capability of Existing Hydro Power Plants 14-4 14.4 Integration of Other Renewable Energy(ORE)14-4 14.5 Introduction of Battery Storage as an ESS 14-4 14.6 Environmental Emissions 14-5 14.7 Overall Comparison 14-6 Page v References Annexes Annex 2.1 Reservoir System in Mahaweli,Kelani and Walawe River Basins A2-1 Annex 3.1 Scenarios of the Demand Forecast A3-1 Annex 4.1 Candidate Thermal Plant Data Sheets A4-1 Annex 5.1 Candidate Hydro Plant Data Sheets A5-1 Annex 5.2 Other Renewable Energy Tariff A5-3 Annex 5.3 Other Renewable Energy Projections for Low&High Demand Scenarios A5-4 Annex 5.4 Methodology of the Renewable Energy Integration Study 2020-2030 A5-5 Annex 5.5 Modeled Wind Turbine Characteristics and Power Plant Output A5-6 Annex 5.6 Solar and Mini-Hydro Plant Production Profiles A5-7 Annex 5.7 Cost Details Other Renewable Energy A5-9 Annex 6.1 Methodology of the Screening of Curve A6-1 Annex 8.1 Screening of Generation Options A8-1 Annex 8.2 Capacity Balance for the Base Case 2020-2039 A8-3 Annex 8.3 Energy Balance for the Base Case 2020-2039 A8-4 Annex 8.4 Annual Energy Generation and Plant Factors A8-5 Annex 8.5 Fuel Requirements and Expenditure on Fuel A8-11 Annex 8.6 High Demand Case A8-12 Annex 8.7 Low Demand Case A8-14 Annex 9.1 Base Case equivalent to 2018-2037 A9-1 Annex 9.2 Energy Mix with Nuclear Power Development A9-3 Annex 9.3 India-Sri Lanka HVDC Interconnection Scenario A9-5 Annex 12.1 Investment Plan for Major Hydro&Thermal Projects(Base Case),2020-2039 A12-1 Annex 12.2 Investment Plan for Major Wind&Solar Developments(Base Case),2020-2039 A12-4 Annex 14.1 Actual Generation Expansions and the Plans from 1992-2018 A14-1 Annex 15 Addendum A15 Page vi LIST OF TABLES Page E.1 Base Load Forecast:2020-2044 E-10 E.2 Base Case Plan(2020-2039)E-11 1.1 Demographic and Economic Indicators of Sri Lanka 1-2 1.2 Forecast of GDP Growth Rate in Real Terms 1-3 1.3 Comparison of CO2 Emissions from Fuel Combustion 15 1.4 CO2 Emissions in the Recent Past 16 1.5 Installed Capacity and Peak Demand 1-9 1.6 Electricity Generation 1994 2018 1-11 2.1 Existing and Committed Hydro and Other Renewable Power Plants 2-2 2.2 Existing Other Renewable Energy(ORE)Capacities 2-5 2.3 Expected Monthly Hydro Power and Energy Variation of the Existing Hydro Plants for the Selected Hydro Conditions 2-6 2.4 Plant Retirement Schedule 2-7 2.5 Details of Existing and Committed Thermal Plants 2-8 2.6 Characteristics of Existing and Committed CEB Owned Thermal Plants 2-9 2.7 Details of Existing and Committed IPP Plants 2-10 3.1 Electricity Demand in Sri Lanka,2004-2018 3-1 3.2 Variables Used for Econometric Modeling 3-5 3.3 Base Load Forecast 2020-2044 3-10 3.4 Main&Sub Sector Breakdown for MAED 3-11 3.5 Annual Average Growth Rate 2020-2045 3-12 3.6 MAED Reference Scenario 3-12 3.7 Comparison of Past Demand Forecasts with Actuals(in GWh)3-15 4.1 Capital Cost Details of Thermal Expansion Candidates 4-3 4.2 Characteristics of Candidate Thermal Plants 4-3 4.3 Oil Prices and Characteristics for Analysis 4-5 4.4 Coal Prices and Characteristics for Analysis 4-6 4.5 Associated Cost for LNG Development 4-8 4.6 Specific Cost of Candidate Thermal Plants in USCts/kWh(LKR/kWh)4-10 5.1 Characteristics of Candidate Hydro Plants 5-5 5.2 Capital Cost Details of Hydro Expansion Candidates 5-6 5.3 Details of Victoria Expansion 5-7 5.4 Expansion Details of Samanalawewa Power Station 5-8 5.5 Energy and Demand Contribution from Other Renewable Sources 5-9 5.6 Projected Future Development of ORE(Assumed as Committed in Base Case Plan)5-10 5.7 Wind resource regimes and expected annual capacity factors 5-14 5.8 Solar resource regimes and average capacity factors 5-15 5.9 Estimated capital cost of development for proposed PSPP sites locations 5-22 6.1 Committed Power Plants 6-8 6.2 Candidate Power Plants 6-8 6.3 Plant Retirement Schedule 6-9 7.1 Generation Expansion Planning Study Reference Case(2020-2039)7-2 7.2 Capacity Additions by Plant Type Reference Case(2020-2039)7-3 Page vii 7.3 Reduction in Annual CO2 Emissions in Base Case Plan(In CO2 million tons)7-5 8.1 Generation Expansion Planning Study-Base Case(2020-2039)8-4 8.2 Generation Expansion Planning Study-Base Case Capacity Additions(2018 2037)8-6 8.3 Capacity Additions by Plant Type Base Case 8-7 8.4 Capacity Distribution for Selected Years in Base Case 8-10 8.5 Cost of Fuel,Operation and Maintenance of Base Case 8-13 8.6 Capacity Additions by Plant Type High Demand Case 8-17 8.7 Capacity Additions by Plant Type Low Demand Case 8-18 8.8 Fuel Price Escalation percentages(from 2020 prices)8-19 8.9 Cost impact of fuel price escalation of Base case(million US$)8-19 8.10 Comparison of the Sensitivities of the Base Case Plan 8-20 9.1 Capacity Additions by Plant Type Base Case equivalent to LTGEP 2018-2037 9-2 9.2 Capacity Additions by Plant Type Energy Mix with Nuclear Power Development 9-3 9.3 Capacity Additions by Plant Type HVDC Interconnection Scenario 9-4 9.4 Present&Projected Power Generation Mix in Other Countries 9-5 10.1 CO2 Emissions from fuel combustion 10-2 10.2 Ambient Air Quality Standards and Proposed Stack Emission Standards of Sri Lanka 10-3 10.3 Comparison of Ambient Air Quality Standards of Different Countries and Organisation 10-3 10.4 Comparison of Emission Standards for Coal Power Plants of Different Countries and Organisations 10-4 10.5 Uncontrolled Emission Factors(by Plant Technology)10-5 10.6 Abatement Factors of Typical Control Devices 10-6 10.7 Emission Factors of the Coal Power Plants 10-7 10.8 Emission Factors per Unit Generation 10-7 10.9 Air Emissions of Base Case 10-8 10.10 Summary of Major COP Decisions 10-14 11.1 Short Term Power Requirement 11-1 11.2 Potential Locations for Future Power Generation Projects 11-4 12.1 ORE Additions 2020-2030 12-4 13.1 Expected Annual Energy Output of Five Hydro Conditions and the Difference Compared with Annual Average Hydro Energy 13-1 13.2 Implementation Delays of plants Case 1 13-2 13.3 Implementation Delays of Committed Power Plants 13-3 13.4 Details of Risk Event Outage of a Major Power Plant 13-3 13.5 Estimation of Annual Energy Shortage Risk with Plant Implementation Delay Risk(Case 1)13-3 13.6 Breakdown of the capacity additions identified for 2019-2021 period 13-4 13.7 Estimation of Annual Energy Shortage Risk with Plant Implementation Delay Risk(Case 2)13-4 13.8 Impact of Single Occurrence of Risk Events for the Basecase of LTGEP 2020-2039 13-5 13.9 Estimation of Annual Energy Deficit and Energy Shortage Risk 13-6 13.10 Available Plant Capacities in Critical Period for Each Year 13-6 Page viii LIST OF FIGURES Page 1.1 Growth Rates of GDP and Electricity Sales 1-2 1.2 Share of Gross Primary Energy Supply by Source 1-4 1.3 Gross Energy Consumption by Sectors including Non-Commercial Sources 1-4 1.4 CO2 Emissions from Fuel Combustion 2016 1-6 1.5 Level of Electrification 1-7 1.6 Sectorial Consumption of Electricity(2005-2018)1-8 1.7 Sectorial-Consumption of Electricity(2018)1-8 1.8 Sri Lanka Per Capita Electricity Consumption(2003-2017)1-9 1.9 Asian Countries Per Capita Electricity Consumption(2004-2016)1-9 1.10 Total Installed Capacity and Peak Demand 1-10 1.11 Other Renewable Energy Capacity Development 1-10 1.12 Generation Share in the Recent Past 1-12 1.13 Renewable Share in the Recent Past 1-12 1.14 World Electricity Generation(GWh)1-13 1.15 World Electricity Generation by Source as Percentage 1-13 2.1 Location of Existing,Committed and Candidate Power Stations 2-3 2.2 Potential of Hydropower System from Past 35 Years Hydrological Data 2-6 3.1 Past System Loss 3-2 3.2 Past trend in the Load factor 3-2 3.3 Change in Daily Load Curve Over the Last Eight Years 3-2 3.4 Consumption Share Among Different Consumer Categories 3-3 3.5 Net Loss Forecast 2020-2044 3-7 3.6(a)Analysis of Night peak,Day peak and Off peak Trends 2011-2017 3-8 3.6(b)Load Profile Shape Forecast 3-8 3.7 System Load Factor Forecast 2020-2044 3-9 3.8 Generation Forecast Comparison 3-13 3.9 Peak Demand Forecast Comparison 3-13 3.10 Generation Forecast of Low,High,Long Term Time Trend and MAED with Base 3-14 3.11 Peak Demand Forecast of Low,High,Long Term Time Trend and MAED with Base 3-14 4.1 World Bank and IMF Crude Oil Price Forecast 4-4 4.2 World Bank and IMF Coal Price Forecast 4-5 4.3 World Bank and IMF Natural Gas Price Forecast 4-7 5.1 Total Renewable Energy Capacity Development 5-11 5.2 Past and Future Other Renewable Energy(ORE)Capacity Development 5-12 5.3 Energy Contribution of Renewable Energy Sources and Energy Share for Next 20 Years 5-13 5.4 Three Selected Sites for PSPP after Preliminary Screening 5-21 7.1 Cumulative Capacity by Plant Type in Reference Case 7-4 7.2 Energy Mix over next 20 years in Reference Case 7-5 8.1 Cumulative Capacity by Plant type in Base Case 8-8 8.2 Capacity Mix over next 20 years in Base Case 8-9 8.3 Capacity Wise Renewable Contribution over next 20 years 8-9 8.4 Firm Capacity Share over next 20 years in Base Case 8-10 8.5 Energy Mix over next 20 years in Base Case 8-11 8.6 Percentage Share of Energy Mix over next 20 years in Base Case 8-12 8.7 Renewable Contribution over next 20 years based on energy resources 8-12 8.8 Percentage Share of Renewables over next 20 years in Base Case 8-13 Page ix 8.9 Fuel Requirement of Base Case 8-14 8.10 Expected Variation of Fuel Cost in Base Case 8-14 8.11 Expected Annual Coal and Natural Gas Requirement of the Base Case 8-15 8.12 Variation of Reserve Margin in Base Case 8-16 9.1 Capacity Share Comparison in 2039 9-6 9.2 Energy Share Comparison in 2039 9-6 10.1 Average Emission Factor 10-2 10.2 Comparison of Stack Emission of Coal Power Plants 10-4 10.3 PM,SO2,NOx and CO2 emissions of Base Case Scenario 10-9 10.4 SO2,NOx and CO2 Emissions per kWh generated 10-9 10.5 SO2 Emissions 10-10 10.6 NOx Emissions 10-10 10.7 CO2 Emissions 10-11 10.8 Particulate Matter Emissions 10-11 10.9 Average Emission Factor Comparison 10-12 10.10 Comparison of System Cost with CO2 Emissions 10-12 10.11 Comparison of Incremental Cost for CO2 Reduction 10-13 10.12 CO2 Emission Reduction in Base Case Compared to Reference Case 10-18 12.1 Implementation Plan 2020-2039 12-5 12.2 Investment Plan for Base Case 2020 2039 12-6 13.1 High and Low Energy Demand Variation Compared with the Base Demand 13-2 13.2 Installed Capacity with Peak Demand(Contingency Event 1)13-7 13.3 Available Capacity in Critical Period with Peak Demand(Contingency Event 1)13-7 13.4 Available Capacity in Critical Period with Peak Demand(Contingency Event 2)13-8 13.5 Available Capacity in Critical Period with Peak Demand(Contingency Event 3)13-8 14.1 Comparison of 2019 and 2017 Energy Demand Forecasts 14-2 14.2 Comparison of 2019 and 2017 Peak Demand Forecasts 14-3 14.3 Fuel price variation of LTGEP 2017 and LTGEP 2014 14-3 14.4 Comparison of ORE Capacity Addition between LTGEP 2019<GEP 2017 14-4 14.5 CO2 and Particulate Emissions 14-5 14.6 SOx and NOx Emissions 14-5 Page x ACRONYMS ADB -Asian Development Bank API -Argus/McCloskeys Coal price Index bcf -Billion Cubic Feet BOO -Build,Own and Operate BOOT -Build,Own,Operate and Transfer CCY -Combined Cycle Power Plant CEA -Central Environmental Authority CEB -Ceylon Electricity Board CECB -Central Engineering Consultancy Bureau CIDA -Canadian International Development Agency CIF -Cost,Insurance and Freight CDM -Clean Development Mechanism CER -Certified Emission Reduction COP -Conference of Parties DSM -Demand Side Management DTF -Distance to Frontier EIA -Environmental Impact Assessment ENS -Energy Not Served EOI -Expression of Interest ESP -Electrostatic Precipitator FGD -Flue Gas Desulphurization FOB -Free On Board FOR -Forced Outage Rate GDP -Gross Domestic Product GHG -Green House Gases GIS -Geographic Information System GT -Gas Turbine HHV -Higher Heating Value HVDC -High Voltage Direct Current IAEA -International Atomic Energy Agency IDC -Interest During Construction IEA -International Energy Agency IMF -International Monetary Fund INDC -Intended Nationally Determined Contributions IPCC -Inter-Governmental Panel on Climate Change IPP -Independent Power Producer JBIC -Japan Bank for International Cooperation JICA -Japan International Cooperation Agency LKR -Sri Lanka Rupees KPS -Kelanatissa Power Station LCC -Line Commutated Converter LCOE -Levelised Cost of Electricity LDC -Load Duration Curve Page xi LF -Load Factor LNG -Liquefied Natural Gas LOLP -Loss of Load Probability LTGEP -Long Term Generation Expansion Plan mscfd -Million Standard Cubic Feet per Day MAED -The Model for Analysis of Energy Demand MMBTU -Million British Thermal Units MTPA -Million Tons Per Annum NDC -Nationally Determined Contributions NEPS -National Energy Policy and Strategy NG -Natural Gas OECD -Organization for Economic Co-operation and Development OECF -Overseas Economic Co-operation Fund ORE -Other Renewable Energy OTEC -Ocean Thermal Energy Conversion O&M -Operation and Maintenance PF -Plant Factor PM -Particulate Matter PPA -Power Purchase Agreement PSPP -Pumped Storage Power Plant PV -Present Value RFP -Request For Proposals SAM -System Advisor Model SDDP -Stochastic Dual Dynamic Programming ST -Steam Turbine UNFCCC -United Nations Framework Convention on Climate Change USAID -United States Agency for International Development US$-American Dollars WASP -Wien Automatic System Planning Package WB -World Bank WHO -World Health Organization VSC -Voltage Source Converter Generation Expansion Plan 2019 E-1 EXECUTIVE SUMMARY Background.As per section 24(1)(c)of the Sri Lanka Electricity Act no 20 of 2009(as amended),Ceylon Electricity Board(CEB)as the Transmission Licensee has a statutory duty to ensure that there is sufficient capacity from generation plants to meet reasonable forecast demand for electricity.Additionally,under section 17(c)of the Act,CEB is required to add such capacity on the most economically advantageous terms and in the most transparent manner.CEB prepares Long-Term Generation Expansion Plan(LTGEP)once in every two years for a 20-year period ahead to ensure that the firm capacity technologies that the CEB is required to procure meets the principle of least cost.Hence,this LTGEP serves as the first check of least cost before procurement is carried competitively to further ensure least cost and transparency.In addition,CEBs LTGEPs also provide the capacity additions from Non-Conventional Renewable Energy(NCRE)based generating technologies,(termed as Other Renewable Energy-ORE in this report)to supplement firm generating capacity and to maintain renewable share and fuel diversity to meet government policy guidelines.The specific government policy as applicable to the Electricity Industry is titled the General Policy Guidelines in Respect of the Electricity Industry and the methodology to formulate and approve such policy guidelines is stipulated under section 5 of the Sri Lanka Electricity Act no 20 of 2009(as amended)and under section 30 of the Public Utilities Commission of Sri Lanka(PUCSL)Act no 35 of 2002.The first General Policy Guidelines in respect of the Electricity Industry published after the enactment of the Sri Lanka Electricity Act was in 2009 and remained until April 2019 where an amendment was issued on the 10th April 2019.As the planning studies contained in this LTGEP 2020-2039 has commenced in 2018 and the first draft submission for the approval of the Public Utilities Commission was made in May 2019,the policy guidelines available during the preparation of this report were the guidelines as contained in the original General Policy Guidelines as issued in 2009.However,all possible efforts have been taken to incorporate as much policy changes as contained in the amended policy guideline that was published in April 2019.This report presents the generation expansion planning studies carried out by the Transmission and Generation Planning Branch of the Ceylon Electricity Board,for the period 2020-2039.The report includes information on the existing generation system,generation planning methodology,system demand forecast,investment and implementation plans for the proposed projects and recommends the most economical sequence of generating capacity additions to meet the least cost E-2 Generation Expansion Plan-2019 and government policies while maintaining the statutory reliability criteria.The final summarized results of the planning studies are presented in the“revised base case plan as given in Table E.2 Electricity Demand is envisaged to grow at 4.9%annually for the next 20 years The demand forecasting methodology as used in the planning studies consists of a combination of medium-term forecast and long-term forecasts.Such forecasts also incorporate planned new mega development projects identified by the government.Five-year sales forecasts prepared by the five distribution licensees and time trend analysis of historical demand are used to determine the medium-term forecast.The econometric approach is used to make the long-term forecast.The econometric approach first develops a correlation between past electricity sales and significant independent variables in different sectors and then the projections available for such variables are substituted to forecast future demand.Even though demand-side management(DSM)is considered as an important tool to conserve and optimize the use of electrical energy at the end-user level,demand reduction due to possible DSM measures are not considered in the forecasts.The responsibility to carry out energy efficiency,energy conservation and demand-side management programs is primarily vested with Sri Lanka Sustainable Energy Authority of Sri Lanka(SLSEA).The Operational Demand Side Management is to be carried out by the Presidential Task Force on Energy Demand Side Management(PTF on EDSM)and guided by a National Steering Committee(NSC).Thus,electrical utilities do not have control over the implementation of DSM programs at present.Further,the DSM forecasts and targets are ambitious and their actual realization is based on many other external factors,including end-user willingness.Therefore,demand reduction due to possible DSM measures are not considered in the forecasts that resulted in the base case plan as presented in this report.However,if any conservation is achieved through DSM activities,actual reductions to demand as a result would be captured and reflected in the demand forecasts of subsequent LTGEPs.The shape of the daily load profile is expected to change gradually and the growth rate of the day peak shows a higher increase than the growth rate of the night peak.It is estimated that the day peak would surpass the night peak by 2027.The forecasted annual average growth rate of energy demand for the next 20 years is 4.9%and the annual peak demand growth rate is around 4.6%.The load forecast used is given in Table E.1.Generation Expansion Plan 2019 E-3 National Obligations on Mitigating Global and Local Environmental Implications Planning Studies as contained in this report are carried out to meet all the environmental and climate change obligations of Sri Lanka during the 20 year planning horizon.Sri Lanka,being a partner to COP21 Paris agreement on mitigation of global climate change induced impacts,presented the Nationally Determined Contributions(NDC)to strengthen global efforts of both mitigation and adaptation.In response to challenges posed by climate change,Sri Lanka has taken several positive steps by introducing national policies,strategies and actions to mitigate climate change induced impacts.According to the ratified NDCs in September 2016 by UNFCCC,among mitigation strategies,Sri Lanka expects a 4%unconditional and 16%conditional reduction of greenhouse gas emissions in the electricity sector.This is incorporated in the LTGEP 2020-2039 by integrating more Other Renewable Energy(ORE)based generation and low carbon thermal generating options to meet the Sri Lankas obligations in COP21 Paris agreement on mitigation of global climate change induced impacts.In addition,the latest General Policy Guidelines for Electricity Industry(as issued in April 2019)requires Non-Conventional Renewable Energy(NCRE),(referred to as ORE in this report)to be developed to the optimum levels to diversify generation mix and to minimise dependence on imported resources.It requires ORE resources to be promoted based on a priority order arrived at considering resource potential,economics,the maturity of the technology and quality of supply.First three ORE resources in this priority order are identified as mini-hydro,wind and solar followed by other ORE resources.The policy guidelines also highlight the need to progress with the vision to achieve 50%of electricity generated from renewable sources(under favourable weather conditions)by 2030.In addition,the policy also advocates Other Renewable Energy based generation to be optimally developed to provide 1/3rd of the power demand by 2030.Planning studies as contained in this report has incorporated above policy requirements(though they are issued at the end of the planning studies)as much as possible.When a major power project is initiated,a detailed environmental impact assessment(EIA)is carried out taking into account the inter-related socio-economic,cultural and human-health impacts and impacts to the ecological systems,both beneficial and adverse.These are performed as location specific studies.Necessary mitigation measures are also identified during such Environmental Impact Assessments and such requisites are included in preparing RFPs of relevant power projects,thereby ensuring environmental commitments during implementation stage as well.E-4 Generation Expansion Plan-2019 Committed and Candidate Firm Power alternatives for the Growing Electricity Demand The latest General Policy Guidelines states that;While a high priority is to be given to environmental protection,a suitable generation mix from firm energy sources must be maintained to strengthen the countrys economy and energy security.It also stipulates that;to ensure security,availability and reliability of supply,installed firm power capacity(based on firm energy sources such as fossil fuels and storage hydro)shall be there at all time to provide at least a 2/3rd of the demand for power.The policy also gives the diversified fuel mix in the installed firm power capacity to be maintained by 2030,namely,30sed on Liquefied Natural Gas or indigenous Natural Gas,30%on Coal,25%on large storage hydro and 15%utilizing furnace oil produced during local refinery process as a by-product and ORE based firm energy sources(such as biomass).The candidate thermal power plant options considered for the study are;45 MW gas turbines,300 MW diesel-fired combined cycle plants,150 MW,300 MW&600 MW natural gas-fired combined cycle plants,300 MW high efficient and 600 MW supercritical coal-fired steam plants and 15 MW reciprocating engines.Further,the introduction of 600 MW nuclear power plant is also considered in a separate scenario.3 x 35 MW gas turbines at Kelanitissa as identified in the 2018-2037 LTGEP were considered as a committed project and the same is mentioned as 130 MW capacity in this revised LTGEP 2020-2039 considering updated information available.A 300 MW dual-fuel(natural gas/auto diesel)fired combined cycle power plant was identified to be commissioned by 2019 in previous LTGEPs(LTGEP 2015-2034 and LTGEP 2018-2037).This power plant was planned to be constructed at Kerawalapitiya.Though the procurement process for the same was initiated,the award could not be made due to legal disputes.Non-implementation of such planned low-cost power capacities necessitated adding supplementary power capacity for shorter/medium terms as stop-gap measures until planned long term capacities are added to ensure reliability and to avoid possible power shortage.320 MW of furnace oil-fired reciprocating engine based power plants were identified in the LTGEP 2018-2037 to be installed and commissioned by 2018 as short/medium term measures.170 MW out of this total capacity has been added to the system through the extension of existing IPP contracts.Also,4 x 24 MW reciprocating engine power plants(at the grid substations of Habarana,Moneragala,Horana and Pallekelle)and a 100 MW reciprocating engine based power plant at Galle as identified in LTGEP 2018-2037 are considered as committed medium-term projects in the preparation of this LTGEP.Generation Expansion Plan 2019 E-5 The ongoing hydropower projects of 35 MW Broadlands,122 MW Uma Oya and 31 MW Moragolla are considered as committed power projects.The latest updated commissioning schedules of these hydro projects were used in preparing this revised LTGEP.The proposed 15 MW Thalpitigala hydropower project was considered as a candidate plant for the year 2024,considering the cabinet approvals secured by the Ministry of Irrigation and Water Resource Management.The proposed 24 MW Seethawaka Ganga hydropower project to be developed by Ceylon Electricity Board was considered for the year 2023.More than 3.5 GW of Renewable Energy Development from Cleaner Indigenous Resources The 100MW wind farm project that is currently being developed by Ceylon Electricity Board at Mannar was considered as a committed project.One of the main objectives of this large wind farm is to operationally test a novel semi-dispatchable operating strategy,by which more wind resources are expected to be integrated.As the transmission infrastructure has been already developed,the remaining wind potential in Mannar is required to be developed next in phases to meet ORE additions facilitated in this LTGEP to meet government policy targets.During the planning studies,the contribution from ORE was considered and different ORE technologies were modelled as appropriate.Maximum possible ORE integration has been facilitated in this LTGEP to meet government policies,subjected to the operational constraints.A separate renewable integration study was carried out to identify the year by year renewable resource integration.The operational flexibility,transmission and system constraints were considered in this study.A strong renewable energy development has been facilitated through this plan with a more than fivefold increase to the expected total renewable capacity for the next twenty years as compared to the past two decades.The cumulative ORE capacities envisaged at the end of 20 years are 1,323 MW from wind,2,210 MW from solar,654 MW from mini-hydro and 144 MW from biomass.Higher ORE share is expected to maximize the utilization of indigenous natural resources.With decreasing global price trends due to improvements to solar PV technology and economies of scale during solar photovoltaic production,development of solar PV has been gaining momentum in Sri Lanka.Solar PV additions take place at present under different schemes such as small-scale rooftop,small scale and large scale ground mounted systems.Incentives offered to high end domestic consumers to avoid consumption in higher blocks in the increasing block tariff domestic tariff structure had contributed to higher interest to install domestic solar rooftop systems.Installation of solar PV systems at rooftops helps the country to utilize the otherwise unproductive asset of rooftop area for a productive economic purpose.Government of Sri Lanka(GOSL)launched an accelerated solar development campaign in 2016 to promote rooftop solar E-6 Generation Expansion Plan-2019 installations in the country.The program objective of reaching 200 MW of rooftop solar PV capacity by 2020 has been already achieved and a continuous growth in rooftop capacity is observed.Procurement work for two directly grid connected ground mounted solar PV projects has been initiated to integrate distributed solar PV schemes at multiple grid locations in sizes of 60 x 1 MW and 90 x 1 MW.Potential large scale solar PV development as concentrated parks too are being studied at few earmarked potential sites such as Pooneryn and Moneragala,which are to be developed in phases.Additional techno/social/environmental feasibility studies are required and securing land is required prior to committing for development of transmission infrastructure to evacuate power from these sites.Ideally,a priority order is preferred to be developed jointly by CEB and SLSEA to phase out the total ORE development during the 20-year period considering the favourability of resource and additional transmission infrastructure development costs.However,different grid integration strategies such as the geographical distribution of Solar PV installations,curtailment during low demand hours and energy storage systems may be required when penetration of solar PV capacity increases,to reduce adverse implications of large solar PV due to variability,intermittency and resource uncertainty.Wind Power is another large indigenous clean energy resource in Sri Lanka with a considerable potential for future development.Large scale wind power development in the country is presently focused in main resource areas such as Mannar,Pooneryn,Puttalam and North.Development of wind resources both as distributed and concentrated sites is to be carried out to meet ORE additions planned for the planning period.However,integration of wind resource need to be done giving due considerations to various technical constraints due to its intermittency and strong seasonality.The wind power capacities presented in this report are expected to experience daily and weekly curtailments to overcome technical and operational restrictions,the amount of which is expected to increase gradually over the years with higher penetration.Therefore,features to remotely curtail wind generation(if so required)to meet technical and operational requirements and methods to treat such curtailments need to be incorporated to future contracts,agreements and specifications.Encouraging the development of other newer forms of clean energy technologies,CEB has called for an Expression of Interest from prospective private developers for the development of geothermal energy conversion,compressed air-based power generation,ocean thermal energy conversion(OTEC),ocean energy conversion(Wave),biogas power generation and other storage applications such as grid-scale battery storages and hybrid systems.Facilitation for similar applications will continue with the progress of commercialization of technologies.Generation Expansion Plan 2019 E-7 Development of 3 GW of Natural Gas&2.1 GW of Coal Based Generation Infrastructure to Ensure Reliable and Economic Supply of Electricity Firm power sources that are available to be dispatched on system requirement and presents an unvarying output while in operation is essential for the proper,reliable and healthy operation of a power system.However continuous delays in implementing the planned low-cost firm power projects have adversely affected the electricity grid as well as the national economy.Coal power has been identified as one of the most economical generating options to maintain economy/affordability of supply.According to a study conducted by New Energy and Industrial Technology Development(NEDO)-Japan,the Foul point area in Trincomalee was identified as the most promising site to carry out future coal power development,considering attributes such as access to the deep sea.Extension of existing Lakvijaya power station is also considered as a near term coal power development alternative due to the possibility of faster implementation to urgently overcome the firm power capacity deficit at low cost.In all new planned coal power projects,necessary environmental impact mitigation measures such as strict emission control,indoor coal storages and enclosed coal handling facilities are incorporated along with higher conversion efficiency.Such mitigation measures are incorporated over and above what is required to meet current environmental laws of the country but at an additional capital cost of about 700USD per kW,compared to a conventional coal power plant.Supercritical technology based coal plants have enhanced operating efficiency and reduced coal consumption,which in turn decrease overall emissions.Possibility of introducing such supercritical power plants with larger unit capacities would be evaluated considering other system constraints.Natural gas(NG),being a low carbon fuel alternative for thermal generation is the next planned fuel addition to the generation mix of the country and the first NG fired power plant was identified in the LTGEP 2015-2034.This LTGEP 2020-2039 has adhered to the government policy on fuel diversification in installed firm capacity and added liquefied natural gas(LNG)based generating capacity to meet government policy targets.The existing combined cycle plants that are operating on diesel/naphtha/furnace oil at present are expected to be converted to natural gas once supply of LNG/NG is established Natural gas power generation depends on the availability of natural gas fuel handling infrastructure to import,re-gasify and distribute natural gas.When sourcing LNG for Sri Lanka,a strategically decided mixture of long and medium term LNG contracts along with short term spot market purchases can be adopted to minimize the“take or pay”type contractual risks under fuel price and to significant weather related uncertainties.E-8 Generation Expansion Plan-2019 Planning studies have considered current fuel price trends of LNG and capital cost recovery of LNG supply infrastructure.Both the floating storage regasification unit(FSRU)and land-based LNG regasification terminal are considered in the studies.Establishing LNG fuel handling and supply infrastructure is important to gain the maximum benefit of LNG based power generation which is much more economical and environmentally friendly than fuel oils.Any delays in establishing LNG infrastructure would cause the LNG power plants to operate on fuel oil,resulting in additional cost on power generation as well as increased environmental emissions.Main load centres of Sri Lanka are in the Western region of the country.Therefore,locating low carbon natural gas based power plants are recommended to be developed in the Western region to facilitate easy distribution of Natural Gas via pipelines,lower transmission losses while complying with the environmental regulations of the Western region.Natural gas exploration work is in progress in the Mannar basin and there is a possibility of using such gas in the natural gas-fired power plants when such fuel is commercially available at economically favourable prices.Key Results of Generation Expansion Planning Study The optimal expansion plan as contained in this report is derived using planning software OPTGEN,SDDP and WASP.The base case as contained in table E2 includes the yearly generation capacity additions that provide the total lowest present value cost for the period,while meeting the reliability criteria and other constraints.Variations to demand growth and fuel prices are presented under sensitivity analysis.Each plant sequence presented under a given scenario is the least cost plant sequence for the given scenario.The draft LTGEP 2020-2039 was initially prepared by CEB based on the government policy guidelines,the planning code and the reliability criteria as published in the gazette notification 2019/28 by PUCSL.Upon submitting same to the Board of CEB for approval,the Board requested it to be revised to incorporate a higher reliability criterion than what is published by PUCSL by increasing the lower and upper limits of reserve capacity margin to 10%and 25%respectively from 2.5%to 20%as contained in the PUCSL gazette notification 2019/28.Accordingly,the base case plan of LTGEP 2020-2039 was changed based on the higher reliability criteria.The Board granted its approval to this base case plan on 22nd April 2019,subject to PUCSL revising the gazette notification to include the enhanced reliability limits proposed by the Board.The Board approved LTGEP 2020-2039 containing the new base case(termed original base case hereafter)was submitted to PUCSL approval on 24th May 2019.Generation Expansion Plan 2019 E-9 The original base case plan prepared based on above enhanced reserve margins and submitted to the Public Utilities Commission of Sri Lanka on 24th May 2019 is given in Table 8.1 of this report.The capacity balance,energy balance and dispatch schedule pertaining to the original base case plan are given in Annex:8.2,Annex:8.3 and Annex:8.4 respectively.All scenario analysis carried out for the original base case plan such as introducing nuclear power and HVDC interconnection to the power system are kept unchanged in this report as an additional reference.Though Cabinet approval also was received for the enhanced reliability criteria proposed by the Board,PUCSL had not revised the original gazette notification to include the new reliability criteria.After several written clarifications and meetings between PUCSL and CEB,PUCSL finally requested CEB to revise and resubmit the original base case as contained in the draft LTGEP 2020-2039 submitted to PUCSL,to comply with the reliability criteria stipulated in PUCSL gazette 2019/28.The revised base case plan of the LTGEP 2020-2039 prepared after adopting the gazetted reliability criteria of PUCSL of 2.5%(minimum)and 20%(maximum)reserve margin is presented as an addendum in this draft LTGEP 2020-2039 report and is termed revised base case plan.This draft LTGEP 2020-2039 had accommodated other observations of the commission such as using economic costs,meeting renewable energy policy target for 2030 and using realistic implementation schedules of the power projects based on the updated project information.The revised base case plan is given in the Table E.2 and Table Ad.1 of Annex 15 of the Long Term Generation Expansion Plan 2020-2039 report.The capacity balance,energy balance and dispatch schedule of the revised base case plan are given in Tables Ad 6,Ad 7 and Ad 8 of Annex 15 respectively.It is to be noted that all analysis as contained in this LTGEP 2020-2039 report is same as the original submission made to PUCSL on 24th May 2019,except the following sections that were changed subsequently with the addendum.Executive summary Base case plan Section on externalities Contingency analysis E-10 Generation Expansion Plan-2019 Table E.1-Base Load Forecast:2020-2044 Year Demand Net Loss*Net Generation Peak Demand(GWh)Growth Rate(%)(%)(GWh)Growth Rate(%)(MW)2020 16914 7.4%8.78 18542 7.2050 2021 18194 7.6%8.62 19910 7.4254 2022 19187 5.5%8.46 20959 5.3403 2023 20233 5.5%8.30 22065 5.3561 2024 21337 5.5%8.15 23230 5.3728 2025 22501 5.5%8.00 24458 5.3903 2026 23667 5.2%7.90 25696 5.179 2027*24819 4.9%7.80 26918 4.8B41 2028 26025 4.9%7.70 28195 4.7D44 2029 27279 4.8%7.60 29522 4.7F55 2030 28573 4.7%7.50 30890 4.6H72 2031 29917 4.7%7.45 32325 4.6Q01 2032 31279 4.6%7.40 33778 4.5S32 2033 32675 4.5%7.35 35267 4.4U69 2034 34119 4.4%7.30 36806 4.4X14 2035 35607 4.4%7.25 38390 4.367 2036 37126 4.3%7.25 40028 4.3c28 2037 38692 4.2%7.25 41716 4.2e97 2038 40298 4.2%7.25 43448 4.2h73 2039 41937 4.1%7.25 45215 4.1q55 2040 43623 4.0%7.25 47033 4.0t45 2041 45368 4.0%7.25 48914 4.0w45 2042 47170 4.0%7.25 50857 4.054 2043 49037 4.0%7.25 52870 4.076 2044 50978 4.0%7.25 54963 4.009 5 Year Average Growth 6.0%5.8%5.1 Year Average Growth 5.5%5.3%4.8 Year Average Growth 4.9%4.8%4.6% Year Average Growth 4.7%4.6%4.5%*Net losses include losses at the Transmission&Distribution levels and any non-technical losses,Generation(Including auxiliary consumption)losses are excluded.This forecast will vary depend on the hydro thermal generation mix of the future.*It is expected that day peak would surpass the night peak from this year onwards Generation Expansion Plan 2019 E-11 Table E.2 Revised Base Case 2020-2039 YEAR RENEWABLE ADDITIONS THERMAL ADDITIONS THERMAL RETIREMENTS LOLP3 20 Solar 100 MW(including 35 MW committed)Wind 20 MW (2x10 MW Chunnakam Wind)Mini Hydro 15 MW*Biomass 5 MW*200 MW Short Term Basis Supplementary Power Plants 100 MW Short Term Basis Supplementary Power Plants 145 MW Reciprocating Engine Power Plants 6 x 5 MW Northern Power 1.427 2021 Solar 110 MW (including 70 MW 2x10MW committed)100 MW Mannar Wind Park Mini Hydro 20 MW*Biomass 5 MW*Uma Oya HPP 122 MW Broadlands HPP 35 MW 395 MW Reciprocating Engine Power Plants 130 MW Gas Turbine 2 100 MW ACE Embilipitiya 20 MW ACE Matara 51 MW Asia Power 200 MW Short Term Basis Supplementary Power Plants 100 MW Short Term Basis Supplementary Power Plants 1.362 2022 Solar 60 MW Wind 150 MW(including 60 MW committed)Mini Hydro 20 MW*Biomass 5 MW*4 x 24 MW Reciprocating Engine Power Plants 100 MW Reciprocating Engine Power Plants Galle 200 MW Open Cycle Operation of 1 x 300 MW Natural Gas fired Combined Cycle Power Plant Western Region2 290 MW Reciprocating Engine Power Plants 1.424 2023 Solar 60 MW Wind 110 MW Mini Hydro 20 MW*Biomass 5 MW*Moragolla HPP 31 MW Seethawaka HPP 24 MW 100 MW Steam Turbine Operation of 1 x 300 MW Natural Gas fired Combined Cycle Power Plant Western Region2(Combined Cycle Operation)(Identified in LTGEP 2015-2034 and LTGEP 2018-2037 to be commissioned by 2019)300 MW Natural Gas fired Combined Cycle Power Plant Western Region2(Identified in LTGEP 2018-2037 to be commissioned by 2021)300 MW Lakvijaya Coal Power Plant Extension 163 MW Combined Cycle Power Plant(KPS2)4 190 MW Reciprocating Engine Power Plants 4x17 MW Kelanitissa Gas Turbines 115 MW Gas Turbine 1 4x9 MW Sapugaskanda Diesel Ext.1 163 MW Sojitz Kelanitissa Combined Cycle Plant 4 0.449 2024 Solar 60 MW Wind 90 MW Mini Hydro 20 MW*Biomass 5 MW*Thalpitigala HPP 15 MW 300 MW Natural Gas fired Combined Cycle Power Plant 4x17 MW Sapugaskanda Diesel1 0.345 2025 Solar 80 MW Wind 40 MW Mini Hydro 20 MW*Biomass 5 MW*300 MW Natural Gas fired Combined Cycle Power Plant 4x15.6 MW CEB Barge Power Plant1 0.331 2026 Solar 90 MW Wind 35 MW Mini Hydro 10 MW*Biomass 5 MW*2 x 300 MW New Coal fired Power Plant (Foul Point Phase I)60 MW Reciprocating Engine Power Plants 4x9 MW Sapugaskanda Diesel Ext.1 0.077 2027 Solar 90 MW Wind 50 MW Mini Hydro 10 MW*Biomass 5 MW*-0.210 2028 Solar 100 MW Wind 40 MW Mini Hydro 10 MW*Biomass 5 MW*Pumped Storage HPP 200 MW -0.152 E-12 Generation Expansion Plan-2019 YEAR RENEWABLE ADDITIONS THERMAL ADDITIONS THERMAL RETIREMENTS LOLP3 29 Solar 100 MW Wind 40 MW Mini Hydro 10 MW*Biomass 5 MW*Pumped Storage HPP 200 MW -0.121 2030 Solar 100 MW Wind 20 MW Mini Hydro 10 MW*Biomass 5 MW*Pumped Storage HPP 200 MW 300 MW New Coal fired Power Plant (Change to Super critical will be evaluated)-0.019 2031 Solar 100 MW Wind 60 MW Mini Hydro 10 MW*Biomass 5 MW*-0.155 2032 Solar 110 MW Wind 50 MW Mini Hydro 10 MW*Biomass 5 MW*300 MW Natural Gas fired Combined Cycle Power Plant 196 MW Reciprocating Engine Power Plants 4 x 24 MW Reciprocating Engine Power Plants 100 MW Reciprocating Engine Power Plants Galle 0.128 2033 Solar 110 MW Wind 35 MW Mini Hydro 10 MW*Biomass 5 MW*300 MW Natural Gas fired Combined Cycle Power Plant Western Region 300 MW New Coal Power Plant (Change to Super critical will be evaluated)165 MW Combined Cycle Plant(KPS)163 MW Combined Cycle Plant(KPS-2)3 x 8.93 MW Uthuru Janani Power Plant 0.182 2034 Solar 120 MW Wind 70 MW Mini Hydro 10 MW*Biomass 5 MW*300 MW New Coal Power Plant (Change to Super critical will be evaluated)-0.105 2035 Solar 120 MW Wind 45 MW Mini Hydro 10 MW*Biomass 5 MW*300 MW Natural Gas fired Combined Cycle Power Plant Western Region 300 MW Natural Gas fired Combined Cycle Power Plant 300MW West Coast Combined Cycle Power Plant 0.060 2036 Solar 110 MW Wind 50 MW Mini Hydro 10 MW*Biomass 5 MW*300 MW Natural Gas fired Combined Cycle Power Plant-0.055 2037 Solar 110 MW Wind 50 MW Mini Hydro 10 MW*Biomass 5 MW*-0.241 2038 Solar 110 MW Wind 70 MW Mini Hydro 10 MW*Biomass 5 MW*300 MW New Coal Power Plant (Change to Super critical will be evaluated)-0.193 2039 Solar 110 MW Wind 70 MW Mini Hydro 5 MW*Biomass 5 MW*300 MW Natural Gas fired Combined Cycle Power Plant-0.178 Total PV Cost up to year 2039,USD 16,555 mil USD(LKR 2,981.45 billion)GENERAL NOTES:1.Retirement of these plants would be evaluated based on the plant conditions.2.The plant has dual fuel capability and would be operated with Natural Gas.3.Refer Contingency Analysis for additional capacity requirements in occurrence of risk events.4.PPA of Sojitz Kelanitissa is scheduled to be expired in 2023,and will be operated as a CEB Natural Gas fired power plant from 2023 to 2033 with the conversion.West Coast and Kelanithissa Combined Cycle plant are converted to Natural Gas in 2023 with the development of LNG based infrastructure.*Mini-hydro and Biomass annual capacity additions are not restricted to the planned capacities.Committed plants are shown in Italics.All plant capacities are given in gross values.Generation Expansion Plan 2019 E-13 Battery storage is proposed to be added to the system in phase development.(Total 50 MW by 2025 and 100 MW by 2030).Exact capacities and entry years will be evaluated during the detailed design stage of battery storage integration.PV cost includes the cost of projected ORE development,USD 2274.04 million based on economic cost.Cost of battery storage is not included in the PV cost.Thalpitigala and Gin Ganga multipurpose hydropower plants are proposed and developed by Ministry of Irrigation.As a committed power plant,Thalpitigala is scheduled to begin commercial operation by 2024 while feasibility studies are still being carried out for Gin Ganga project.Seethawaka HPP is expected in 2023 while PSPP units are expected in 2028,2029 and 2030 respectively.Refer addendum for the required transmission system reinforcements for the implementation of major power plants in the years up to 2026.A generation capacity shortage is observed in the short term up to the year 2023 when compared to forecasted demand due to non-implementation of projects identified in previous plans,mainly delays in the implementation of the two 300 MW natural gas-fired combined cycle projects which should have been commissioned in 2019 and 2021 as per previous plans.Therefore,it is necessary to ensure adequate short term capacity additions during the initial years.The demand forecast as contained in this report(table 3.3)is the results of detailed forecasting studies carried out in 2018,the usual commencement year of the work related to LTGEP 2020-2039.As the consensus with PUCSL to revise the draft plan was reached in January 2020,demand forecasts are not revised performing a complete planning cycle to include the latest demand data,as that would further delay the submission and approval process of the plan.However,as actual sales figures are now available for years 2018 and 2019,those demand figures could be appropriately used in short term studies to revise the short-term capacity requirement identified in this report to determine the actual minimum capacity requirement for initial years.Once the planned low cost long term major plants are commissioned during 2023 2025,the majority of short term capacity additions are to be retired as shown in the revised base case.The capacity share from coal and natural gas as contained in this report are maintained to comply with the fuel diversity requirement of firm capacity as stipulated in the government policy guidelines.Accordingly,by 2025 the firm capacity share of coal power plants is to be 22%and natural gas power plants to be 38%.By 2030,this share will be 30%from coal and 30%from natural gas,complying exactly with the policy targets.Implementation of the Plan and Future Work This plan only stipulates the most economical capacity additions for the future.To implement such plans,the assistance of all stakeholders is required.The National Energy Policy and Strategies as published in the Gazette Extraordinary 2135/61 dated 09th August 2019 states under section 3.9;Considering limitation to land with specific attributes that are required to develop certain technologies and considering the extensive financial losses incurred in the past owing to E-14 Generation Expansion Plan-2019 shifting of sites to locate power plants,strategic locations to establish future energy infrastructure will be earmarked and secured in advance to ensure timely implementation of such facilities and to minimise adverse social impacts.It is hence of utmost importance to identify and secure land required to locate power capacities as identified in this plan.It is important to recognise the continuous development of coal as a baseload power generating option,not only to maintain the fuel diversity but also due to unparallel economic advantages that it offers.It was noted during the planning studies that other prominent economies in the region such as India,Indonesia,Vietnam and Bangladesh are continuing the development of coal power plants owing to the economic advantages they offer.Timely implementation of coal plants is considered essential to keep costs of electricity down and thereby making costs of production of Sri Lankan goods low to compete with regional countries.In order to facilitate the harnessing of indigenous resources and to maintain renewable energy portfolio in the generation mix,a total of 3,495 MW of ORE capacity has been identified to be developed during the planning horizon.Once developed,energy coming from such ORE based power plants are expected to replace the energy that otherwise would have to be generated from thermal power plants.Though ORE based plants,other than biomass and solid waste,do not contribute to installed firm capacity,the energy contribution from such plants reduces the need to install firm capacity in the long run.Thus,unless such ORE capacities identified are not developed,share of thermal firm capacity additions need to be increased in future plans.Responsibility of identifying and preparing renewable resource inventories and maps and managing such renewable energy resources lies with Sri Lanka Sustainable Energy Authority.CEB,through this plan,has facilitated the absorption of ORE based resources.However,for the actual and economical exploitation of such ORE resources,CEB requires the assistance of other agencies.Introduction of pumped storage power plants as a grid scale energy storage solution is mandatory to enhance the planned ORE absorption and to give operational flexibility.The present high cost of battery energy storage technologies is expected to decline in future with the technology developments,thus making battery energy storage a possible economically viable solution.To facilitate such development and to gain knowledge of such technology,battery storage is facilitated in this report for phased development.It is important to note that actual energy dispatch in a given future year would depend on the fuel prices prevailing in that year and weather conditions.Based on the fuel price forecasts considered for planning purposes and at average weather conditions coal generation is expected to have a share of 28%by 2025 and 41%by 2030.The Energy contribution from natural gas in 2025 and Generation Expansion Plan 2019 E-15 2030 would be 29%and 22%respectively.Contribution from renewable energy is going to be over 37%by 2025 and 35%by 2030.Under favourable weather conditions,the latter is expected to go further up.The generating capacity mix identified in this plan is operationally capable of raising the share of generation from cleaner sources,(Natural Gas and renewable energy)up to 70%of total generation.The total present value of implementing the revised Base Case Plan 2020-2039 in the next 20 years is approximately USD 16,555 million with discount rate of 10%.E-16 Generation Expansion Plan-2019 Immediate Actions to be taken:(i)Reciprocating engine power plants for short term requirement.The anticipated capacity shortage for the period till 2023 is to be met through the development of reciprocating engine power plants.Development of these power plants expeditiously is essential to increase low reserve capacity margins in the initial years and avoid capacity shortage as a result.170 MW of extended IPP plants and 300 MW of short-term capacity in operation in 2020 is expected to be retired in 2021.As a result,395 MW of capacity is seen as required for 2021.This is in addition to another 145 MW required for 2020.If further extension of IPP contracts is expected to be considered along with other competitive capacity procurements,initiation of such capacity additions is recommended to be commenced at earliest upon obtaining approval to this plan.(ii)Reciprocating engine power plants on medium-term requirement.Out of 320 MW reciprocating engine capacity identified in LTGEP 2018-2037,following power projects had been identified as medium-term capacity developments.It is essential to fast track the development of these projects and complete the projects by 2022.a)4x24 MW Reciprocating engines plants at four grid locations.b)100 MW Reciprocating engine based power plant in Galle (iii)Commissioning of 35 MW Broadlands,122MW Uma Oya,and 31 MW Moragolla by the year 2021,2021 and 2023 respectively.(iv)Commissioning of 100 MW wind farm at Mannar by the year 2021.The semi dispatchable Mannar wind farm that is expected to generate approximately 337GWh annually need to be expedited.As the transmission infrastructure is already available up to Mannar,additional wind resource at Mannar island needs to be developed next.Generation Expansion Plan 2019 E-17(v)Commissioning of Other renewable energy projects Approximate capacity addition of 1,200 MW of Wind and 2,000 MW of solar is facilitated through this plan for the 20 year planning horizon.It is the responsibility of all agencies including Sustainable Energy Authority to carry out necessary resource availability studies and to come out with suitable locations where such capacities could be developed.(vi)130 MW of gas turbines by the year 2021 The power plant is expected to add much needed peaking capacity and reduce the dependency on hydropower.(vii)Natural gas fired combined cycle power plants and associated LNG import infrastructure.Two,300 MW dual fuel combined cycle power plants must be commissioned in western region by 2023.The associated LNG supply infrastructure having sufficient capacity to be developed on a fast track basis to cater to the two new power plants and the existing combined cycles that are to be converted to natural gas.Two additional 300 MW natural gas fired combined cycle power plants are identified as required for 2024 and 2025.The land acquisition process and all other necessary approvals are required to be obtained immediately to commence the project procurement activities for these two power plants.Development of associated transmission facilities also required to be commenced in parallel to the power plant implementation schedule.Early approval to this LTGEP is essential to commence development work on those two plants.(viii)Extension of Lakvijaya Power Plant.The 4th Unit of Lakvijaya coal power plant is planned to be commissioned by 2023.Prompt action is required from all stakeholder authorities to enable timely implementation of the project on the targeted date.E-18 Generation Expansion Plan-2019(ix)High efficient coal power plant development Two,300 MW High Efficient Coal Power Plants are planned to be commissioned in 2026 at Foul Point in Trincomalee.The land acquisition process and all other necessary approvals are required to be obtained immediately to commence the project procurement activities.(x)Pumped storage power plant development Implementation of 3 x 200MW pumped storage power plant has been identified for 2028,2029 and 2030 respectively.Pumped storage plants with variable speed pumping mechanisms is not only useful as an energy storage method,but also to facilitates absorption of maximum ORE and reduces possible ORE generation curtailments.In addition,this will operate as a peaking power plant by minimizing the high cost thermal generation.It is also identified that such pumped storage hydro plants are required in the future to provide operational flexibility,including fast ramping up/down capability and frequency regulation.In order to account for the occurrence of risk events,a separate contingency analysis has been carried out as contained under Contingency Analysis for the first five year period.Low hydrology than what is planned,increase in demand beyond forecast,delays in implementation of power plants and outage of a major power plant are considered as risk events in the contingency analysis.Generation Expansion Plan-2019 Page 1-1 CHAPTER 1 INTRODUCTION 1.1 Background The Electricity sector in Sri Lanka is governed by the Sri Lanka Electricity Act,No.20 of 2009 amended by Act No.31 of 2013 1.Ceylon Electricity Board(CEB),established by CEB Act No.17 of 1969(as amended),is under legal obligation to develop and maintain an efficient,coordinated and economical system of Electricity supply in accordance with Licenses issued.CEB is responsible for most of the generation and distribution licenses while being sole licensee for transmission.CEB has been issued a generation license,a transmission license and four distribution licenses.Lanka Electricity Company(LECO),a subsidiary of CEB is the other distribution licensee and there are several Independent Power Producers,whose production is also purchased by CEB.The Public Utilities Commission of Sri Lanka(PUCSL)is the regulator of the sector and was established by the PUCSL Act No.35 of 2002 and empowered by the Electricity Act.The Sri Lankan power system has a total installed capacity of approximately 4046 MW by end of year 2018 with a total dispatchable capacity of 3436 MW.The maximum demand recorded in 2018 was 2616 MW and total net generation was 1537GWh.Generation expansion planning is a part of the process of achieving an efficient and economical electricity supply system to the country.In order to meet the increasing demand for electrical energy,while considering the retirements of existing the thermal plants,new generating stations need to be installed as and when necessary.The planning studies presented in this report are based on the Annual Report 2017 of Central Bank of Sri Lanka 2 and electricity sector data up to 2018.The information presented has been updated to December 2018 unless otherwise stated.The generating system has to be planned taking into consideration the electricity demand growth,generation technologies,environmental and climate change considerations,fuel diversification mix,prevailing government policies and financial requirements.Evaluation of each type of candidate generating plant technologies,from both renewable and thermal is screened,to select the optimum plant mix schedule in the best interest of the country.1.2 The Economy In the last six years(2013-2018),the real GDP growth in the Sri Lanka economy has varied from 5%to 3.2%in 2018.Details of some demographic and economic indicators are given in Table 1.1.Page 1-2 Generation Expansion Plan-2019 Table 1.1-Demographic and Economic Indicators of Sri Lanka Units 2013 2014 2015 2016 2017 2018 Mid-Year Population Millions 20.58 20.77 20.97 21.20 21.44 21.67 Population Growth Rate%0.8 0.9 0.9 1.1 1.1 1.1 GDP Real Growth Rate%3.4 5 5 4.5 3.4 3.2 GDP/Capita(Market prices)US$3609 3819 3842 3886 4104 4102 Exchange Rate(Avg.)LKR/US$129.11 130.56 135.94 145.60 152.46 162.54 GDP Constant 2010 Prices Mill LKR 7,846,202 8,235,429 8,647,833 9,034,290 9,344,839 9,644,728 Source:Annual Report 2018,Central Bank of Sri Lanka 1.2.1 Electricity and Economy Electricity demand growth rate in the past has most of the times revealed a direct correlation with the growth rate of the countrys economy.Figure 1.1 shows growth rates of electricity demand and GDP from 1997 to 2018.Figure 1.1-Growth Rates of GDP and Electricity Sales 1.2.2 Economic Projections The Central Bank of Sri Lanka has forecasted the latest GDP growth rates in real terms for four consecutive years,which is published in Annual Report 2018 of Central Bank of Sri Lanka 2 and Annual Report 2017 of Central Bank of Sri Lanka 3 as depicted in Table 1.2.-20.0-15.0-10.0-5.00.05.010.015.020.01997199819992000200120022003200420052006200720082009201020112012201320142015201620172018Electricity Demand Growth(%)Growth Rate(%)YearGDPElectricityGeneration Expansion Plan-2019 Page 1-3 Table 1.2-Forecast of GDP Growth Rate in Real Terms Year 2018 2019 2020 2021 2022 2023 2017 Forecast 5.0 5.5 60 6.0 6.0 2018 Forecast 4.0 4.5 5.0 5.0 5.0 Source:Annual Reports 2017&2018,Central Bank of Sri Lanka 1.3 Energy Sector 1.3.1 Energy Supply Biomass or fuel wood,petroleum and hydro are the major primary energy supply sources,which cater the Sri Lankan energy demand.Petroleum turns out to be the major source of commercial energy,which covers more than 40 percent of the energy demand.Biomass or fuel wood,which is mainly a non-commercial fuel,at present also provides approximately 40 percent of the countrys total energy requirement.Although electricity and petroleum products are the major forms of commercial energy,an increasing amount of biomass is also commercially grown and traded.Hydropower which covers 6%of the total primary energy supply is the main indigenous source of primary commercial energy in Sri Lanka.Estimated potential of hydro resource is about 2000MW,of which significant resource has already been harnessed.Further exploitation of hydro resources is becoming increasingly difficult owing to social and/or environmental impacts associated with large-scale development.Apart from these,there is a considerable potential for wind and solar power development.The first commercial wind power plants were established in 2010 and the total capacity of wind power plants by end of 2018 is 128MW.100MW wind farm at Mannar Island is at the implementation stage.The steps have been initiated to harness the economical wind and solar potential in Sri Lanka in an optimal manner.The first commercial solar power plants were commissioned in year 2016 and the total capacity of commercial solar power plants by end of 2018 was 51MW and nearly 170MW of solar roof tops were also connected by end of 2018.Scattered developments of small scale solar power plants have been already initiated and feasibility studies were initiated to develop solar power plants in park concept.By end of 2018,37 small scale solar PV parks of 1MW has been awarded to private investors for development and another 90 small scale solar PV parks of 1MW has been under evaluation to award during 2019.As at present,the total fossil fuel requirement of the country is imported either as crude oil or as refined products and used for transport,power generation,industry and other applications.Apart from this,initiatives have been launched in towards oil exploration with the prime intention of harnessing potential petroleum resources in the Mannar Basin.Exploration license has been awarded to explore for oil and natural gas in the Mannar Basin off the north-west coast and drilling of the test wells has been carried out.At present,natural gas has been discovered in Mannar basin(off shore from Kalpitiya Pennisula)with a potential of 70 mscfd.Discoverable gas amount of this reserve is estimated approximately 300 bcf.This may even extend beyond the potential of 2TCF with daily extraction rates of 100 mscfd but further exploration should be carried out in order to verify these figures.In 2017 the primary energy supply consisted of Biomass(4607 ktoe),Petroleum(5462 ktoe),Coal(1358 ktoe),Hydro(738 ktoe)and other renewable sources(387 ktoe).The share of these in the gross primary Page 1-4 Generation Expansion Plan-2019 energy supply from 2012 to 2017 is shown in Figure 1.2.Hydro electricity is adjusted to reflect the energy input required in a thermal plant to produce the equivalent amount of electricity.Figure 1.2-Share of Gross Primary Energy Supply by Source 1.3.2 Energy Demand Figure 1.3-Gross Energy Consumption by Sectors including Non-Commercial Sources Sectorial energy consumption trend from 2012 to 2017 is shown in Figure 1.3.According to the above chart,household and commercial sector appears to be the largest sector in terms of energy consumption when all the traditional sources of energy are taken into account.Further,it shows a decreasing trend while industry and Transport sector shows an increasing trend.46798.9D.5C.5CCB967%6%8%9%7%6%4%4%8%2%3%3%3%2%3%0 0 1220132014201520162017Share%YearPetroleumBiomassHydroCoalOther Renewable Energy25%&1$)66GFEA%0 0 1220132014201520162017Share%YearIndustryTransportHousehold,commercial and othersSource:Sri Lanka Sustainable Energy Authority Source:Sri Lanka Sustainable Energy Authority Generation Expansion Plan-2019 Page 1-5 The consumption for 2017 is made up of biomass(4564 ktoe),petroleum(4364 ktoe),coal(44.2 ktoe)and electricity(1150 ktoe).Due to poor conversion efficiency of biomass,the composition of the net(or useful)energy consumption in the domestic sector could be different from the above.On the other hand,being the cheapest and most easily accessible source of energy,fuel wood still dominates the domestic sector consumption.Even though it is traded in urban and suburban areas fuel wood is still classified as a non-commercial form of energy.1.3.3 Emissions from Energy Sector The Total CO2 Emission levels of Sri Lanka are 20.9 Million tons,which is approximately only 0.06%of the total CO2 emissions generated in the World.The absolute emission levels as well as the per capita emission levels are much below compared to many other countries in the world as tabulated in Table 1.3.Table 1.3-Comparison of CO2 Emissions from Fuel Combustion Country kg CO2/2010 US$of GDP kg CO2/2010 US$of GDP Adjusted to PPP Tons of CO2 per Capita Total CO2 Emissions(Million tons)Sri Lanka 0.26 0.09 0.99 20.9 Pakistan 0.67 0.17 0.79 153.4 India 0.84 0.269 1.57 2076.8 Indonesia 0.44 0.17 1.74 454.9 Malaysia 0.63 0.28 6.93 216.2 Thailand 0.60 0.23 3.55 244.6 China 0.93 0.46 6.57 9101.5 Japan 0.19 0.24 9.04 1147.1 France 0.10 0.12 4.38 292.9 Denmark 0.10 0.13 5.84 33.5 Germany 0.19 0.21 8.88 731.6 Switzerland 0.06 0.08 4.53 37.9 United Kingdom 0.14 0.15 5.65 371.1 USA 0.2.9 0.29 14.95 4833.1 Canada 0.30 0.35 14.91 540.8 Australia 0.26 0.36 16.0 392.4 Qatar 0.46 0.27 30.77 79.1 Brazil 0.19 0.15 2.01 416.7 World 0.42 0.30 4.35 32314.2 Even though electricity sector is the major contributor for emissions in the world,the transport sector contributes for majority of the emissions in Sri Lanka.The contribution to emissions from electricity sector of recent four years is tabulated in Table 1.4 and sector wise comparison of CO2 emissions in 2016 is shown in Figure 1.4.Source:IEA CO2 Emissions from Fuel Combustion(2018 Edition)04-2016 Data Page 1-6 Generation Expansion Plan-2019 42%5$A%8E%6%Table 1.4-CO2 Emissions in the Recent Past Year Sri Lanka CO2 Emissions(Million tons)Electricity Sector CO2 Emissions (Million tons)2013 13.74 4.04 2014 16.74 6.79 2015 19.5 6.8 2016 20.9 8.7 Figure 1.4-CO2 Emissions from Fuel Combustion 2016 1.4 Electricity Sector 1.4.1 Ease of Doing Business The“Ease of Doing Business”index ranks countries based on capability of starting businesses with an overall Distance to Frontier(DTF)score.The score is determined by several factors which includes the subsection of“Getting Electricity”.The Getting Electricity index is based on the procedures,time and cost required for a business to obtain a permanent electricity connection for a newly constructed warehouse,while assessing efficiency of connection process,Reliability of supply and transparency of tariff index measures,reliability of power supply and the price of electricity.The Doing the business 2019 05 report published by World Bank Group,classified Sri Lanka at an overall Distance to Frontier(DTF)score of 61.22 creating a Ease of Doing Business rank of 100th out of(a)World (a)Sri Lanka Source:IEA CO2 Emissions from Fuel Combustion(2018 Edition)04-2016 Data Source:IEA CO2 Emissions from Fuel Combustion(2018 Edition)04-2016 Data Generation Expansion Plan-2019 Page 1-7 190 countries,with the subsection of Getting Electricity DTF score of 74.37 which ranked 84th out of all 190 countries.1.4.2 Access to Electricity By the end of December,2018,approximately 99%of the total population had access to electricity from the national electricity grid.Figure 1.5 shows the percentage level of electrification district wise as at end of June 2016.Figure 1.5-Level of Electrification Page 1-8 Generation Expansion Plan-2019 1.4.3 Electricity Consumption Figure 1.6-Sectorial Consumption of Electricity(2005-2018)The amount of energy consumed by each sector(i.e.each tariff category)from 2005 to 2018 is shown in Figure 1.6 while Figure 1.7 depicts sectorial electricity consumption share in 2018.These Figures reveal that the industrial and commercial(general purpose,hotel,government)sectors consumption together is more than the consumption in the domestic sector.This is a pleasing situation for an economy with ambitious GDP growth projections.Figure 1.7-Sectorial Consumption of Electricity(2018)The average per capita electricity consumption in 2017 and 2018 were 626kWh per person and 650 kWh per person respectively.Generally,it has been rising steadily;however,in the period 2007 2009 with the slowing down of the electricity growth,the per capita consumption has stagnated.A similar trend is observed during 2012 to 2013.Figure 1.8 illustrates the trend of per capita electricity consumption of Sri Lanka from 2004 to 2018.It is compared to other Asian countries per capita electricity consumption variation from 2004 to 2013 as depicted in Figure 1.9.2859305632193230340136413917405340024041443847995005518949515149555959636772768489942690285928942910287930993372352135833751387341424323457514941675193020261974226524902614275229843183353538114031108125135133132129132138132135133133130130020004000600080001000012000140001600020052006200720082009201020112012201320142015201620172018GWhYearDomesticReligiousIndustrialCommercialStreet LightingDomestic,37.0%Religious,1%Industrial,32%Commercial,29%Street Lighting,1%Generation Expansion Plan-2019 Page 1-9 01002003004005006007008009001000110012001300140015001600170018002004200520062007200820092010201120122013201420152016kWh/personYearVietnamIndiaPakistanSri LankaBangladesh 1.4.4 Capacity and Demand Sri Lanka electricity requirement was growing at an average annual rate of around 5%-6%during the past 20 years,and this trend is expected to continue in the foreseeable future.The total installed capacity peak demand over the last twenty years are given in the Table 1.5 and graphically shown in Figure 1.10.The development of other renewables through the past years is illustrated in Figure 1.11 Table 1.5-Installed Capacity and Peak Demand Year Installed Capacity Capacity Growth Peak Demand Peak Demand Growth MW(%)MW(%)1998 1636 337 1099 1682 391 14 00 1764 504 9 01 1874 645 3 02 1893 122-2 03 2180 1516 7 04 2280 563 3 05 2411 648 12 06 2434 193 8 07 2444 0.442-2.7 08 2645 822 4 09 2684 168-3 10 2818 555 5 11 3141 10!63 10 12 3312 5!46-100200300400500600700kWh/PersonYearFigure 1.8 Sri Lanka Per Capita Electricity Consumption(2004-2018)Figure 1.9 Asian Countries Per Capita Electricity Consumption(2004-2016)250300350400450500550600650700200420052006200720082009201020112012201320142015201620172018kWh/PersonYearPage 1-10 Generation Expansion Plan-2019 Year Installed Capacity Capacity Growth Peak Demand Peak Demand Growth MW(%)MW(%)2013 3355 1!64 1 14 3932 17!52-1 15 3847-283 6 16 4018 4$53 7 17 4060 1%23 3 18 4046-0.3 2616 4%Last 5 year avg.growth 0.73%5.01%Last 10 year avg.growth 4.67%3.81%Last 20 year avg.growth 4.73%3.79%Figure 1.10 Total Installed Capacity and Peak Demand Figure 1.11 Other Renewable Energy Capacity Development 0400800120016002000240028003200360040004400199819992000200120022003200420052006200720082009201020112012201320142015201620172018Inst.Capacity&Peak Demand(MW)YearNon Dispatachble Capacity MWDispatachble Capacity MWPeak Demand39738811211916118121222732036744245551656261001002003004005006007002003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Capacity(MW)YearGeneration Expansion Plan-2019 Page 1-11 1.4.5 Generation In early stages the electricity demand of the country was mainly supplied by hydro generation and the contribution from thermal generation was minimal.With the time,thermal generation has become prominent.At present,thermal generation share is much higher than that of hydro.Further the other renewable energy generation from mini hydro,wind,solar,dendro etc is also increasing.Electricity Generation during the last twenty-five years is summarized in Table 1.6 and graphically shown in Figure 1.12.Table 1.6-Electricity Generation 1994-2018 Year Hydro Generation Other Renewable Thermal Generation Self-Generation Total GWh%GWh%GWh%GWh%GWh 1994 4073 93.4 0 0.0 265 6.1 22 0.5 4360 1995 4496 94.2 0 0.0 260 5.5 17 0.4 4774 1996 3233 72.0 3 0.1 1102 24.5 152 3.4 4490 1997 3426 67.1 4 0.1 1441 28.2 235 4.6 5107 1998 3892 69.1 6 0.1 1620 28.8 114 2.0 5632 1999 4135 67.5 21 0.3 1871 30.6 97 1.6 6125 2000 3138 46.3 46 0.7 3437 50.7 158 2.3 6780 2001 3030 46.2 68 1.0 3361 51.2 105 1.6 6564 2002 2575 37.4 107 1.6 4074 59.1 136 2.0 6892 2003 3175 42.0 124 1.6 4263 56.4 0 0.0 7562 2004 2739 33.8 208 2.6 5051 62.3 115 1.4 8113 2005 3158 36.3 282 3.2 5269 60.5 0 0.0 8709 2006 4272 45.9 349 3.7 4694 50.4 0 0.0 9314 2007 3585 36.8 347 3.6 5800 59.6 0 0.0 9733 2008 3683 37.5 438 4.5 5697 58.0 0 0.0 9819 2009 3338 34.0 552 5.6 5914 60.3 0 0.0 9803 2010 4969 46.7 731 6.9 4948 46.5 0 0.0 10649 2011 3999 35.2 725 6.4 6629 58.4 2.9 0.0 11356 2012 2710 23.1 736 6.3 8280 70.6 1.4 0.0 11727 2013 5990 50.3 1179 9.9 4729 39.7 0 0.0 11898 2014 3632 29.5 1217 9.9 7466 60.6 0 0.0 12316 2015 4904 37.5 1467 11.2 6718 51.3 0 0.0 13090 2016 3481 24.6 1160 8.2 9507 67.2 0 0.0 14148 2017 3059 20.8 1464 10.0 10148 69.2 0 0.0 14671 2018 5149 33.8 1715 11.2 8390 55.0 0 0.0 15255 Last 5 year av.Growth 9.12%8.94%2.96%5.50%Last 10 year av.Growth 4.94.42%3.96%5.04%The Total Generation and ORE Generation excludes the contribution from Rooftop Solar Page 1-12 Generation Expansion Plan-2019 Figure 1.12-Generation Share in the Recent Past Sri Lankan Power System has operated maintaining 30%-60%share of renewable energy throughout the recent years.This trend will be continued in the future also with the optimum amount of renewable energy integration to the system.Total renewable energy share over the past ten years are shown in Figure 1.13.Figure 1.13 Renewable Share in the Recent Past 020004000600080001000012000140001600018000199819992000200120022003200420052006200720082009201020112012201320142015201620172018Generation(GWh)YearHydro GenerationOil GenerationCoal GenerationSelf GenerationOther Renewable0 0Pp0002000300040005000600070008000200720082009201020112012201320142015201620172018PercentageEnergy(Gwh)YearMajor HydroOther RETotal RE PercentageGeneration Expansion Plan-2019 Page 1-13 In Comparison World Electricity Generation has been mainly depended on Thermal Generation throughout the past two decades.Coal Power Generation is the major source contributing approximately 40%of the World Electricity Generation from 1996 to 2016.Gas power Generation has increased from 15%to 23%,while Oil Power Generation has decreased from 9%to 3%during the past two decades.The total Renewable Generation including Large Hydro power has increased from 20%-23%during the time horizon while Nuclear Power Generation has decreased from 17%to 10%.World Electricity Generation during the last twenty years is summarized in Figure 1.14 and World Electricity Generation by source as a percentage is shown in Figure 1.15 Figure 1.14 World Electricity Generation(GWh)Figure 1.15 World Electricity Generation by Source as Percentage 0500000010000000150000002000000025000000300000001996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 20082009 2010 2011 2012 2013 2014 2015 2016GWhCoalOilGasNuclearHydroGeothermalBiofuelsWasteSolar PVSolar thermalWindTide0 0Pp095199619971998199920002001200220032004200520062007200820092010201120122013201420152016CoalOilGasNuclearHydroORESource:International Energy Agency Statistics Source:International Energy Agency Statistics Page 1-14 Generation Expansion Plan-2019 1.5 Implementation of Planning cycle The performance evaluation of previous years indicates that the CEB overall cost at selling point has increased by 5.75%in 2018 compared to 2016.The Transmission and Distribution losses of CEB has improved from 9.63%in 2016 to 8.34%by 2018.The previous versions of LTGEP have identified the commissioning of low cost major power plants in the system.The LTGEP 2013-2032,had identified the commissioning of 2x 250 MW Sampoor Coal Power Plant by 2018.The Sampoor Coal Power plant which went through the initial gestation stage,that is finalizing the feasibility studies,EIA,land reservation,and initiating tender procedure,was cancelled in 2015.In LTGEP 2015-2034,a 300 MW Natural Gas Combined Cycle plant was introduced to be commissioned in 2019.After receiving the commission approval for LTGEP 2015-2034 in September 2016,the tender process was initiated by CEB in November 2016.However,the Power Plant has not been awarded and timely implementation of the power plant in 2019 is not achievable.Due to the non-implementation of low cost power plant as planned in to the system high cost supplementary power needed to be procured to overcome shortages as stop gap measures.Supplementary Power sources of 56MW had provided 37.2 GWh for a period of 7 months in 2018.The PPA of retired IPP,ACE Power Embilipitya was extended and it supplied 362.84 GWh energy in 2018.1.6 Planning Process CEB is under a statutory duty to develop and maintain an efficient,co-coordinated and economical system of electricity supply for the whole of Sri Lanka.In order to fulfill the above duty,CEB revises the Long Term Generation Expansion Plan(LTGEP)once in two years complying with Section 43 of Sri Lanka Electricity Act,No 31 of 2013.Intensive studies are conducted by the Transmission and Generation Planning Branch of the CEB in order to prepare this plan.A coordinating committee representing the relevant Branches of CEB meets during the study period to review the study inputs and the findings.Operating information on the existing generating plants is obtained from records maintained in the Generation Planning Branch and the individual power stations.Operational information and system limitations are obtained from the System Control and the Generation Division of CEB.The details of Independent Power producers are verified from latest power purchase agreements.Details and costs of candidate thermal and hydro plants which are to be considered for system addition are obtained from various pre-feasibility and feasibility studies commissioned by CEB in the recent past.These data are used on computer models and a series of simulations are conducted to derive the feasible optimum generation expansion sequence.1.7 Objectives The objectives of the generation planning studies conducted by CEB are,(a)To determine the Demand Forecast for next 25 years.(b)To investigate the feasibility of new generating plants for addition to the system in terms of plant and system characteristics.Generation Expansion Plan-2019 Page 1-15 (c)To specifically investigate the future operations of the hydro-thermal system in order to determine the most economical operating policy for reservoirs,hydro and thermal plants.(d)To conduct system simulation studies to determine the economically optimum mix of generating plants to meet the forecast demand and the acceptable reliability levels in the 20 year period ahead.(e)To investigate the robustness of the economically optimum plan by analyzing its sensitivity to changes in the key input parameters.1.8 Structure of the Report The Long Term Generation Expansion Plan 2020-2039 consists of the following chapters as indicated in the Grid Code.Chapter 2 Presents the existing and committed generation system of Sri Lanka.Chapter 3 The past and forecast electricity demand with the forecasting methodology is explained.Chapter 4 Thermal Generation options for the future system expansions are discussed.Chapter 5 Renewable Generation options for the future system expansions are discussed.Chapter 6 Explains the Generation expansion planning guidelines,methodology and the parameters.Chapter 7 Explains the Development of the Reference Case.Chapter 8 Describes the Development of the Base Case and Sensitivity Analysis.Chapter 9 Focuses on Policy and Scenario Analysis.Chapter 10 Discusses the Environmental implications of the expansion plan.Chapter 11 Elaborates the Recommendations of the Base Case Plan.Chapter 12 Based on required implementation schedule and investments for the generation projects.Chapter 13 Shall concentrate on the contingency analysis on the provided plan.Chapter 14 Provides a comparison of this year plan with the previous plan.Generation Expansion Plan-2019 Page 2-1 CHAPTER 2 THE EXISTING AND COMMITTED GENERATING SYSTEM The existing generating system in the country is mainly owned by CEB with a considerable share owned by the private sector.Until 1996 the total electricity system was owned by CEB.Since 1996,private sector has also participated in power generation.The existing generating system in the country has approximately 4046 MW of installed capacity by 2019 including non-dispatchable plants of capacity 610 MW owned by private sector developers.The majority of dispatchable capacity is owned by CEB(i.e.about 84%of the total dispatchable capacity),which includes 1398.85 MW of hydro and 1504 MW of thermal generation capacity.Balance dispatchable capacity,which is totally thermal plants,is owned by Independent Power Producers(IPPs).2.1 Hydro and Other Renewable Power Generation Hydropower is the main renewable source of generation in the Sri Lanka power system and it is mainly owned by CEB.However,other renewable sources such as mini hydro,wind,solar,dendro,and biomass are also connected to the system,which are owned by the private sector developers.2.1.1 CEB Owned Hydro and Other Renewable Power Plants Most of the comparatively large scale hydro resources in Sri Lanka have been developed by the CEB.At present,hydro projects having capacities below 10MW(termed mini hydro),are allowed to be developed by private sector as run-of river plants and larger hydro plants are to be developed by the CEB.Since these run-of river type mini hydro plants are non-dispatchable,they are modeled differently from CEB owned hydro plants in the generation expansion planning simulations.The operation and maintenance cost of these CEB hydro power plants was taken as 12.24 US$/kW per annum.(a)Existing System The existing CEB generating system has a substantial share based on hydropower(i.e.1398.85 MW hydro out of 2903 MW of total CEB installed capacity).Approximately 48%of the total existing CEB system capacity is installed in 17 hydro power stations and 32%of the total energy demand was met by the major hydro plants in 2018.Details of the existing and committed hydro system are given in Table 2.1 and the geographical locations of the Power Stations are shown in the Figure 2.1.The major hydropower schemes already developed are associated with Kelani and Mahaweli river basins.Five hydro power stations with a total installed capacity of 369.8 MW(26%of the total hydropower capacity)have been built in Laxapana Complex where two cascaded systems are associated with the two main tributaries of Kelani River,Kehelgamu Oya and Maskeliya Oya.The five stations in this complex are generally not required to operate for irrigation or other water requirements;hence they are primarily designed to meet the power requirements of the country.Castlereigh and Moussakelle are the major storage reservoirs in the Laxapana hydropower complex located at main tributaries Kehelgamu Oya and Maskeliya Oya respectively.Castlereigh reservoir with active storage of 52 MCM feeds the Wimalasurendra Power Station of capacity 2 x 25MW at Norton-bridge,while Canyon 2 x 30MW is fed from the Moussakelle reservoir of storage 108 MCM.Page 2-2 Generation Expansion Plan-2019 Table 2.1-Existing and Committed Hydro and Other Renewable Power Plants Plant Name Units x Capacity Capacity(MW)Expected Annual Avg.Energy(GWh)Active Storage(MCM)Rated Head(m)Year of Commissioning Canyon 2 x 30 60 160 107.9(Moussakelle)207.2 1983-Unit 1 1989-Unit 2 Wimalasurendra 2 x 25 50 112 52.01(Castlereigh)227.38 1965 Old Laxapana 3x 9.6 2x12.5 53.8 286 0.245(Norton)472.4 1950 1958 New Laxapana 2 x 58 116 552 0.629(Canyon)541 Unit 1 1974 Unit 2 1974 Polpitiya 2 x 45 90 453 0.113(Laxapana)259 1969 Laxapana Total 369.8 1563 Upper Kotmale 2 x 75 150 409 0.8 473 Unit 1-2012 Unit 2-2012 Victoria 3 x 70 210 865 688 190 Unit 1-1985 Unit 2-1984 Unit 3-1986 Kotmale 3 x 67 201 498 154 201.5 Unit 1-1985 Unit 2&3 88 Randenigala 2 x 61.3 122.6 454 462 77.8 1986 Ukuwela 2 x 20 40 154 2.1 75.1 Unit 1&2 76 Bowatenna 1 x 40 40 48 23.5 50.9 1981 Rantambe 2 x 25 50 239 3.4 32.7 1990 Nilambe 2 x 1.6 3.2-0.005 110 1988 Mahaweli Total 816.8 2667 Samanalawewa 2 x 60 120 344 218 320 1992 Kukule 2 x 37.5 75 300 1.67 186.4 2003 Small hydro 17.25 Samanala Total 212.25 644 Existing Total 1398.85*4874 Committed Broadlands 2x17.5 35 126 0.198 56.9 2020 Moragolla 2x15.1 30.2 97.6 1.98 69 2023 Mannar Wind Park 103.5 337 2020 Multi-Purpose Projects Uma Oya 2x61 122 290 0.7 722 2021 Total 290.7 850.6*Note:*According to feasibility studies.*3MW wind project at Hambantota not included.Generation Expansion Plan-2019 Page 2-3 Figure 2.1-Location of Existing,Committed and Candidate Power Stations The development of the major hydro-power resources under the Mahaweli project added seven hydro power stations(Ukuwela,Bowatenna,Kotmale,Upper Kotmale,Victoria,Randenigala and Rantambe)to the national grid with a total installed capacity of 817 MW(58.4%of the total hydropower capacity).Three major reservoirs,Kotmale,Victoria and Randenigala,which were built under the accelerated Mahaweli development program,feed the power stations installed with these reservoirs.The latest major power station in this system is 150MW Upper Kotmale hydro power plant.Polgolla-diversion weir(across Mahaweli Ganga),downstream of Kotmale and upstream of Victoria,diverts Mahaweli waters to irrigation systems via Ukuwela power station(40 MW).After generating electricity at Ukuwela power station the water is discharged to Sudu Ganga,upstream of Amban Ganga,which carries water to Bowatenna reservoir.It then feeds both Bowatenna power station(40MW)and No.Power Plant Capacity MW Hydro Power Plants(Existing)1 Canyon 60 2 Wimalasurendra 50 3 New Laxapana 116 4 Old Laxapana 53.8 5 Polpitiya 90 6 Kotmale 201 7 Victoria 210.3 8 Randenigala 126.8 9 Rantambe 51.8 10 Ukuwela 38.6 11 Bowatenna 40 12 Samanalawewa 120 13 Udawalawe 6 14 Inginiyagala 11.25 15 Nilambe 3.2 16 Kukule 75 17 Upper Kotmale 150 18 Moragahakanda 25 Hydro Power Plants(Committed)19 Broadlands 35 20 Uma Oya 122 21 Moragolla 30.2 Hydro Power Plants(Candidate)22 Thalpitigala 15 23 Seethawaka 24 Other Renewable(Committed)24 Mannar Wind Park 100 Thermal Power Plants A Lakvijaya Coal Power Plant 900 B Kelanithissa PP,Sojitz PP 523 C Sapugaskanda PP,Asia Power 211 D Uthuru Janani 27 E CEB Barge Mounted Plant 60 F West Coast PP 300 G Northern Power 38 H ACE Power Embilipitiya 100 H 24 Page 2-4 Generation Expansion Plan-2019 mainly Mahaweli System-H by means of separate waterways.Water discharged through Bowatenna power station goes to Elahera Ela and is available for diversion to Mahaweli systems D and G.The schematic diagrams of the hydro reservoir networks are shown in Annex 2.1.Unlike the Laxapana cascade,the Mahaweli system is operated as a multi-purpose system.Hence power generation from the associated power stations is governed by the down-stream irrigation requirements as well.These requirements being highly seasonal which in turn affects the operation of these power stations during certain periods of the year.Samanalawewa hydro power plant of capacity 120MW was commissioned in 1992.Samanalawewa reservoir,which is on Walawe River and with active storage of 218 MCM,feeds this power plant.Kukule power project which was commissioned in 2003,is a run-of river type plant located on Kukule Ganga,a tributary of Kalu Ganga.Kukule power plant is 70 MW in capacity and which provides an average of 300 GWh of energy per year under average hydro conditions.The contribution of the three small hydro plants(Inginiyagala 11.25MW,UdaWalawe-6MW and Nilambe 3.2MW)to the National Grid is comparatively small(20.45MW)and is dependent on irrigation water releases from the respective reservoirs.(b)Committed Plants The 35MW Broadlands hydropower project located near Kithulagala on the Maskeliyaoya was considered as a committed plant.The dam site of the project is to be located near Polpitiya power house and in addition to the main dam,there will be a diversion weir across Kehelgamuoya.The project has a 0.198 MCM active storage and it is expected to generate 126GWh energy per annum.It will be added to the system in 2020.122MW Uma Oya multipurpose hydro power project was considered as a com
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Global Recovery Insights 2020www.ufi.org/researchSUPPORTED BY:PRODUCED BY:Part 2:The future of digital and hybrid eventsContentsSECTION 1SECTION 2SECTION 3SECTION 4SECTION 5SECTION 6SECTION 7SECTION 8SECTION 9SECTION 1034567811131415WelcomeKey areas of focusKey findingsUptake of digital eventsA strong preference for networking at live eventsReturn on investment is a challenge for exhibitors Familiarity increases comfort with digitalA safety conscious option?Attracting new audiencesConclusion2G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Dear industry colleagues,We are happy to publish the second part of this global study,which follows on from the first part which was published in October.(Part 1 is available here)As with Part 1,this report is based on a quantitative survey of trade shows visitors and exhibitors,with 9,000 responses in 10 languages representing trade show participation in over 30 countries.The first part looked at how visitors and exhibitors were feeling the impact of the lack of live events and the impact on them both personally and professionally.We were relieved to see that the core value proposition of face to face remains strong,and there was no evidence of any long-term shift away from live events.This report focuses on the experience of visitors and exhibitors at digital events;how they perceive the current digital offerings,their views on future spend and what role they think hybrid will play in the visitor journey.The core findings echo the first report in the strong demand for the return of live events.Visitors recognise some strengths in digital notably the time and cost benefits and are increasingly happy for some content to be delivered digitally.Exhibitors have strong preference for live events across all aspects,but particularly for networking,and they feel that digital events currently do not provide a good ROI.So while the future remains uncertain,it is clear that the core value proposition of our industry,connecting markets by bringing people together face to face,remains strong.Digital products are opening new possibilities for our industry they have the potential to attract new audiences,they can maintain an audience connection with those unable or unwilling to attend at the moment,and so offer new opportunities to further strengthen our live events.As we emerge from this pandemic,we should view digital as an opportunity,not a threat,and we should seize this opportunity to make our live events better.Our customers are waiting for us to do so,so the future is in our hands.Yours sincerely,Kai HattendorfUFI Managing Director/CEOWelcome3G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Key areas of focusFieldwork in late summer 2020A second phase of research will be conducted in January 2021 to determine any change in sentiment and the impact of budget planning.The experience of trade show visitors and exhibitors with digital events to-date1.Strengths and weaknesses of the current digital proposition4.The role hybrid events may play in the visitor journey2.Exhibitor views on future spend at digital events3.Building on UFI and Exploris previous Global Visitor and Global Exhibitor Insight reports,this study investigates:MethodologyS E C T I O N 2Comparisons with GRI Part 1 and previous Global Insights reports where available,these reports are available to UFI members at www.ufi.org/researchA quantitative survey of trade show visitors and exhibitors,gaining 9,000 responses,in 10 languages,representing trade show participation in over 30 countries.4G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Key FindingsVisitors and exhibitors have a strong preference for live eventsAs of late summer,half of regular trade show visitors and exhibitors had experienced a digital event.They reported that they preferred live events across all aspects,especially for networking.Visitors recognise some strengths in digitalAudiences do recognise the time and cost benefits of attending an event digitally.They also find them an effective was to access content,with 53%of visitors feeling that digital events were the same as,if not better than live events for providing quality content.Return of investment is lacking for exhibitors in digitalExhibitors overall feel that live events offer better return on investment,driven by the better networking opportunities(86%prefer live)and ability to generate leads(80%prefer live).Dedicated sponsor experiences improve exhibitor perceptionsWhere a company has participated in a third-party digital event as a sponsor or exhibitor,they tend to have a somewhat more favorable view of digital events vs.those who have organised their own event or been a speaker or content provider at a third-party event.Their likelihood to spend at future digital events is also increased.Digital events could maintain audience connectionThere is an increased preference(30%vs 19%)for attending the digital element of a hybrid event amongst visitors who are particularly concerned with safety and travel disruption,suggesting digital elements could play an important role in helping show brands to stay connected with portions of their audience who are unable,or unwilling to attend in-person.Digital events have the potential to attract new audiencesAudiences have an increased interest in attending a hybrid event digitally when it is a new event to them(35%vs 19%)suggesting that organisers can use the digital elements of their hybrid events to attract new audiences.This could be especially important when visitors are reporting they will favour familiar events when it comes to participating in-person.S E C T I O N 35G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Uptake of digital eventsAs of late summer,half of regular trade show visitors had participated in a digital event of some kind.Exhibitors had also participated in similar numbers.However,many exhibiting companies had chosen to organise their own virtual events,with only a small proportion(13%)choosing to sponsor or exhibit at a third-party event at that point in time.Since the start of the COVID-19 crisis,have you.Over half of exhibitors have now used digitalS E C T I O N 4The low barrier to entry for digital events could present a challenge to traditional event organisers who may be faced with increasing numbers of exhibitors choosing to organise their own digital events.This is a trend we will examine more closely in the second phase of Global Recovery Insights.Only 13%of exhibitors had sponsored or exhibited at a 3rd-party event6G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0A strong preference for networking at live eventsBoth visitors and exhibitors strongly prefer live events across almost every aspect.They particularly rate the networking aspect of face-to-face events-an element that digital models were struggling to successfully replicate through the middle of the year.Visitors recognise some value in digital eventsIn your opinion,how do virtual events compare to live events when it comes to.S E C T I O N 5However visitors are starting to recognise the strengths of digital events in meeting some objectives.Visitors view digital events as being more time and cost effective than traditional events and feel they are equally good at delivering quality content.But live events are still their preferred channel for“doing business”and finding new suppliers,with only 6%of visitors currently preferring digital events for their sourcing activities.Virtual events are much better Quality of networkingVirtual events are a little betterNo difference Live events are a little better Live events are much better Overall enjoyable experienceDoing businessFinding new suppliersGetting new ideas and inspiration25%80%Quality of educational content32 %Value for timeCost of attending7G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0S E C T I O N 6Return on investment is a challenge for exhibitorsWhilst budgets for live events have been temporarily frozen by many companies,marketing budgets for other channels had yet to be subjected to large cuts as of late summer.Budgets for digital events had even increased in some instances,suggesting that there were pots of money available for digital event organisers with a compelling proposition.Since the start of the COVID-19 crisis,to what extent have your marketing budgets for the following channels changed?Other marketing channelsVirtual eventsDown by 50%or moreDown by 25%-49%Down by 10%-24%Down by less than 10%Marketing budget unchangedUp by less than 10%Up by 10%-24%Up by 25%-49%Up by 50%or more8G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0But exhibitors are reporting concerns about the return on investment available to them through digital events,rating them poorly for generating leads,with only one in ten respondents rating digital events as better than live events in this aspect.Three quarters of exhibitors feel live events still offer them better return on investment.In your opinion,how do virtual events compare to live events when it comes to.Exhibitors prefer live events across all aspectsReturn oninvestmentVirtual eventsare much betterRepresentingyour brandGenerating sales/leadsOverall experienceQuality of networkingVirtual eventsare a little betterNo differenceLive eventsare a little betterLive eventsare much better 9G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Companies that have increased their budget for digital events are less likely to see their spend returning to live events immediately.(21%of those who have increased their digital event budget state their live event spend will return immediately vs 28%overall).However these companies are only marginally more likely(15%vs 12%)to think their budget for live events will never return to pre-covid levels,suggesting that their digital events will tail off or run alongside their live events rather than replace them over the longer term.Digital as a short term fix?Even where budget for digital events has been increased,live events are still the preferred channel.Return of live event budget by spend on digital events10G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Familiarity increases comfort with digitalLikelihood of sponsoring a digital event in the future,split by past behaviourAs of late summer,only a small percentage(13%)of exhibitors had experienced a dedicated exhibiting or sponsorship experience at a third party event.For the majority who had participated in a digital event,it was as a content provider or by organising their own event.Any experience of digital has increased the likelihood of exhibitors to spend in this area in future,suggesting that organisers should continue to find ways to let exhibitors get a good sense of what their digital propositions offer to encourage them to commit financially.S E C T I O N 7But interestingly,those who got a dedicated sponsor or exhibitor experience,now hold the most favorable views of digital events.They rate them notably more highly for generating leads and delivering ROI.However networking remains an area they view as weak and they still prefer live events across all aspects.Those who have participated in a digital event are notably more likely to sponsor digital events in the future,in particular those who have already sponsored other peoples digital events.Probably or definitely will sponsor digital events in future11G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Now exhibitors have a more nuanced understanding of the types of digital experience available to them,this will be a key topic of study for the second phase of research to determine what aspects are adding particular value.Exhibitors views of digital vs.live events for achieving different objectives12G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0A safety conscious option?S E C T I O N 8As they prefer live events,our current audience are undecided as to whether they would still attend a hybrid event digitally,if the option to attend in-person were available to them.To what extent would you be interested in attending a hybrid event,i.e.a live event that also can be attended virtually?But when we examine the group of visitors who believe their attendance at live events may reduce,we see an increase in interest for digital attendance.This group is much more likely than average to express concerns about safety at a live event and in the surrounding city and to be concerned about travel disruption.They appear to see digital attendance as an option to help them continue to participate in events,whilst they still have short-term concerns about attending in-person.500 %less likely to to value in-person networkingmore likely to favour strict safety measuresmore likely to want to attend digitallyI plan to attend fewer events in future-I am:Not at all interestedNot very interestedFairly interestedVery interestedSomewhat interested13G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Attracting new audiencesWe reported in part one of Global Recovery Insights that both visitors and exhibitors planned to rely on previous experience when deciding which events to return to in-person-this suggested that familiar and trusted show brands would be best placed to attract their audience back.S E C T I O N 9There is a strong preference for attending a familiar event in-person(56el they are more likely to attend in-person vs 19%digitally).However when considering an event they have never attended before,visitors interest in attending virtually increases(38%preferring to attend in-person,vs 63%who would at least consider attending digitally).This suggests that digital events could form an important part of the marketing funnel for driving new attendees to live events in future.They could also have a valuable role to play in creating connections with individuals who may never consider attending the event in-person due to time or distance restrictions.If the following were organised as hybrid events,would you be more likely to attend in-person or virtually?Visitors are more interested in attending online if the event is new to themAn event you have not attended beforeAn event that you have previously attendedMuch more likely to attend in personA little more likelyto attend in personEqually likely to attend either wayA little more likely to attend virtuallyMuch more likely to attend virtually14G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0Not try to replicate a live eventA typical trade show caters to a wide range of visitor and exhibitor objectives.In fact,many see that as a unique advantage of a trade show,as they can accomplish many goals in a few intense business days.It is yet to be proven that lifting this generalist model and replicating it in a digital environment is either possible or desirable.The digital event of the future may add value by focusing on single objectives for attendees and exhibitors such as education or generating top-of-funnel leads,allowing other channels including live trade shows,to meet other needs more effectively.Guide its audience through a new journeyUnfamiliarity with the new ways of working around digital events is breeding discomfort among exhibitors.They are unsure of the value of digital events and lack the experience to make the most of the opportunities they offer.The more familiar they become with the channel,the more highly they rate it.We have seen organiser driven initiatives such as exhibitor training and collaborative sales relationships consistently associated with higher exhibitor Net Promoter Scores at live events(Global Exhibitor Insights 2017).Show teams will need to find effective ways of encouraging potential exhibitors to consider digital,then guiding them to make the most effective use of it.Contribute to an engaged communityThe interest in participating in a new event as a digital attendee suggests digital has an important role to play in an organiser marketers toolkit,bringing fresh audiences to the show brand who may become the physical attendees of the future.But they may also offer additional ways to engage existing audiences,providing more personalised content that can be consumed frequently throughout the year.Attendees recognise the advantages of digital events for providing quality content and may be ready to participate more frequently in sessions that are more tailored or more timely than can be provided at an annual trade show.Meet an audience where they are atHowever,there are potentially valuable audiences for digital events who may never wish to,or be able to,attend the event in-person.Whether this is pressure on time or travel budget,or shorter-term concerns around travel safety,digital events offer show brands a new way to connect.With many trade show audiences skewing towards an older,male demographic,(Explori global benchmarks)digital has the potential to access new audiences that do not currently consider a trade show floor as a place for them.ConclusionWhilst the strong preference for live events among our customers suggests that digital events are not seen as a substitute for getting face-to-face,there appear to be areas where they will continue to add value.S E C T I O N 10The digital event of the future will:15G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0About ExploriReport authorsSuzanne Van MontfoortResearch Director(Bespoke),ExploriChristian DruartResearch Manager,UFISophie HoltManaging Director,Explori The official research partner of UFIThank you to all research participantsUFI Diamond SponsorsUFI Research PatronUFI and Explori would like to thank the trade show organisers and UFI members and partners who supported the wide collection of data that made this research possible.The authors also wish to thank the research teams at Explori,GRS and GRS Explori,and in particular Charlotte Penn and Mitch Deeming for the significant work that has gone in to producing this report.Explori provides scalable research solutions for exhibition organisers all over the world.With a global client base including Hyve,Clarion Events,Informa,Comexposium,Messe Frankfurt,Emerald,Diversified Communications and many others contributing to their global data set of industry benchmarks.Exploris research platform is designed to support organisers in gathering meaningful customer experience insight across multiple territories and languages.Over 3,000 events worldwide now work with Explori including trade shows,digital events and conferences.As part of their partnership with UFI,Explori produces annual reports giving insight into the customer experience of visitors and exhibitors across the industry.Explori is independently owned by its founders,directors and employees and is headquartered in London.16G LO B A L R E C O V E R Y I N S I G H T S 2 0 2 0UFI is the global trade association of the worlds tradeshow organisers and exhibition centre operators,as well as the major national and international exhibition associations,and selected partners of the exhibition industry.UFIs main goal is to represent,promote and support the business interests of its members and the exhibition industry.UFI directly represents more than 50,000 exhibition industry employees globally,and also works closely with its 60 national and regional association members.More than 800 member organisations in 83 countries around the world are presently signed up as members.Around 1,000 international trade fairs proudly bear the UFI approved label,a quality guarantee for visitors and exhibitors alike.UFI members continue to provide the international business community with a unique marketing media aimed at developing outstanding face-to-face business opportunities.www.ufi.orgAbout UFIThe Global Association of the Exhibition Industry
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1,618 dayswind African Energy Atlasafrica-energy-2020/2021 editionISSN 2046-0473Share of global oil productionAccess toElectricity(2017)GenerationNatural gas productionup by 4.8%Installed capacityNew capacity in 2019227GW9.6GW8.6S6,061MWHydro18,854MWLiquid fuels49,110MWCoal66,061MWNatural gasAverage time PPAsigning to operationAnnual solar capacity increase52rican Energy Atlas 2020/2021 EditorThalia Griffiths-thaliaafrica-CartographerDavid BurlesContributing EditorsDan Marks,John Hamilton,Jon MarksEmail:subscriptionscbi-Web:www.africa- 2020 Cross-border Information.All rights reserved.Data and information published in the African Energy Atlas isprovided to Cross-border Information(CbI)by its staff and networkof correspondents through extensive surveys of sources andpublished with the intention of being accurate.CbI cannot insureagainst or be held responsible for inaccuracies and assumes noliability for any loss whatsoever arising from use of such data.No portion of this publication may be photocopied,reproduced,retransmitted,put into a computer system or otherwiseredistributed without prior authorisation from Cross-borderInformation.Registered office:4 Bank Buildings,Station Road,Hastings,EastSussex TN34 1NG,UK.Directors:JJ Marks,JM Ford,JD Hamilton,NJ Carn,E Gillespie2 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020Cover illustrationPower generation data is taken from African Energy Live Data and isfor end 2019,except average time from PPA signing to operation,whichis based on all available information in the database.Electricity access data is sourced from the SEforALL/World Bankdatabase.Oil and gas data is for 2018 and taken from the BP Statistical Reviewof World Energy,June 2019.Power definitionsStatus:Operating:plants that are producing electricity,even if this issubstantially below maximum capacity.Construction:building work is ongoing at the site.Planned:any project which has not yet begun construction.Thisincludes projects which are at a very early stage of development,such as identified hydro sites,as well as those which are muchmore advanced.The data tables shown under the maps refer onlyto projects with a planned commercial operation date of 2025 orearlier.Fuels:Natural gas:any plant fuelled by natural gas,whatever the source,including both LNG and pipeline gas.Liquid fuels:includes all fuel oils,crude oils,shale oil and liquidgases.Coal:technologies using coal as the original source of energy.Nuclear:refers to technologies utilising the energy containedwithin the atomic structure of matter,including both fission andfusion.Hydroelectricity:any technology based on the movement orweight of water from a river or reservoir,including pumpedstorage.Solar:any technology producing electricity using energy fromthe sun.Wind:any technology producing electricity using energy fromthe wind.Geothermal:any plant using underground temperaturedifferentials to produce power.Biomass:technology using organic matter as a feedstock,including biogas technologies.Other:includes combinations of fuels and hybrids where theindividual capacities are not known,as well as ocean technologies,coal bed methane and industrial process heat.About the AtlasThe power maps in the African Energy Atlas 2020/2021 areinformed by African Energy Live Data,an industry-leadingdatabase with detailed entries on more than 6,500 powergeneration plants and projects.The Atlas is necessarilyconstrained in the number of projects that can be displayed.For more information please see the following note onpower definitions and visit the African Energy website,whereyou may explore the interactive Live Data map.Cartographer David Burles has used a wide variety of othersources to craft the maps but while considerably more opensource material is available to inform our maps and graphicsthan when the Atlas was first published in 2007,huge gapsremain to even the most fundamental data sets.We welcome positive and negative feedback,and datasuggestions to enrich forthcoming editions.Please contactpublishing director Nick Carn(nickafrica-).ContentsAFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 3FOCUSIntroduction 4On-grid generation capacity,Access to electricity 5African Energy Live Data 6Roads,railways,ports,airports 12Climate,population,income,fossil fuels,power generation 13Finance 14Political risk ratings 15Regional groupings 16Economic Africa 17Sovereign ratings 17Economic indicators by country 18Key energy trends 20POWER National power companies 21Regional power pools 21Trends 22North Africa 24Morocco 25Algeria 26Tunisia 27Libya 28Egypt 29The Mediterranean Basin 30Sub-Saharan Africa 32West African Power Pool 32Southern Africa Power Pool 33Senegal,Mauritania,The Gambia,Guinea-Bissau 34Guinea,Sierra Leone,Liberia,Cape Verde 35Cte dIvoire 36Ghana,Togo,Benin 37Nigeria 38Mali,Burkina Faso,Niger 40Cameroon,Central African Republic,Chad 41Rep.of Congo,Gabon,Equatorial Guinea,STP 42Central African Power Pool 43Democratic Republic of Congo 43Sudan,South Sudan 44Ethiopia,Eritrea,Djibouti,Somalia 45Uganda 46Kenya 47Rwanda,Burundi,Malawi 48Eastern Africa Power Pool 48Tanzania 49Angola 50Namibia 51Zambia 52Zimbabwe 53Botswana 54Mozambique 55South Africa,eSwatini,Lesotho 56Madagascar,Indian Ocean islands 58UPSTREAM OIL AND GASNational oil and gas companies and state regulators 59Opec,GECF,EITI 59North Africa 60Morocco 61Algeria 62Tunisia 64Libya 65Egypt 66Sub-Saharan Africa 69Mauritania,Senegal,The Gambia 71Guinea,Guinea-Bissau,Sierra Leone,Liberia 72Mali,Burkina Faso,Niger,Chad,Central African Rep.73Cte dIvoire 74Ghana,Togo,Benin 75Cameroon 76Nigeria 77Niger Delta 78Equatorial Guinea,So Tom and Prncipe 80Gabon 81Republic of Congo 82Democratic Republic of Congo 83Sudan,South Sudan 84Ethiopia,Eritrea,Djibouti 85Somalia 86Angola 87Uganda,Rwanda,Burundi 89Kenya 90Tanzania 91Zambia,Zimbabwe,Malawi,Botswana 92Mozambique,Ruvuma Basin 93Namibia 94South Africa 95Madagascar,Indian Ocean 96DOWNSTREAM 98Primary energy demand projections 99Oil refineries,CTL and GTL plants 100Gas development and commerce 1024 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020IntroductionThe outlook for Africa was unusually positive when thelast edition of the African Energy Atlas was published in2018.“Peaceful political transitions,an upturn in naturalresources prices and a broader range of investors enteringelectricity supply and other industries all point to theemergence of a more dynamic,mature continental economy,”the introduction asserted,marking the Atlass second decade ofpublication.Maps and graphics in this new edition similarlychart positive trends in politics,economic management,technological change and sustainable investment not least thenumber of renewable energy schemes now under way buteven before the Covid-19 pandemic locked down the globaleconomy,the trends recorded in Atlas 2020/2021 were far froma celebration of good news across the continent.Africas needs remain huge and daunting:the AfricanDevelopment Bank calculates that upgrading the continentsinfrastructure needs some$130bn-$170bn/yr;the financing gapis$68bn-$108bn/yr(see Finance).There has been an upturn inprivate equity and some other investment,but they are nowherenear the levels that can start to address infrastructure shortfallsand lack of access to sustainable clean energy.Governance remains spotty,with some advances but alsobackward steps.Benin and Zambia were among the firstcountries to replace autocracy with democracy in 1991,as abonus from the end of the Cold War,but are now ranked onlypartly free by Freedom House.Indeed,the US advocacy groupnow ranks only five African polities in its highest free category;by this metric some 20 states are still not free at all.Short-term problems may be exacerbated by underlyingweaknesses.As Atlas 2020/2021 was published,the coronavirusepidemic was spreading worldwide,while crude oil prices hadhit record low levels,below even those of the 2007-08 globalfinancial crisis.Coronavirus highlights global vulnerabilities thatcan floor interconnected economies.Even if Europe and theUS have erected ever more barriers to migration,the outbreakhas shown how walls alone cannot solve global problems.Africas rural exodus has created megacities like Lagos,Cairoand Kinshasa,whose populations live between extreme wealthand grinding poverty.Providing adequate services has becomea defining political issue of the decade,as urban and peri-urbanpopulations demand higher standards of education,health andaccess to energy from often creaking state bodies.Enlightened governments are seeking to rise to this challenge,by accelerating moves to create more investor-friendly andinnovative environments.Countries like Ghana and Kenya havedramatically raised access levels;Egypt,Morocco and SouthAfrica(at least until its governance crisis)have developedstructures to attract investment in solar power and otherrenewable energies.Mozambiques efforts to work with IOCsmean its natural gas exports are set to take off while its northernneighbour Tanzanias resources remain in the ground.Governance moves The trend towards improved governance has continued its slowupward trajectory.Some of Africas old-school tyrants havedeparted Zimbabwes Robert Mugabe died in 2019 andEgypts Hosni Mubarak in February 2020 and a few leadershave been elected without drawing on traditionalconstituencies,such as Tunisias President Kais Saied.Theremoval of Jacob Zuma and his replacement as president byCyril Ramaphosa helped stem a disastrous trend towards statecapture in South Africa.In Nigeria,President MuhammaduBuhari can claim a few wins against the kleptocracy that soundermines Africas most populous country.But much remains to be done:South Africa is a better placeafter Zuma,but Ramaphosa has yet to reverse a decline that hastaken Eskom from being one of the worlds top four powercompanies to the edge of collapse.Nigerian reforms have failedto make any impact on the oil industry and other drivers ofextreme graft.A number of elderly rulers hang on after decadesin power.While francophone West African countries are lookingto mark their improving economic performance with atransition from the CFA franc to a new currency,the eco,theirCentral African counterparts remain mired in problems.Stability is a prized commodity,with violence involving jihadistmilitias wracking the Sahel undermining hard-earnedinvestment efforts by Burkina Faso and Mali,among others and making Central African Republic all but ungovernable.Political transitions in Algeria and Sudan have yet to prove thatestablished structures can be overthrown by popularmovements,despite the creation of a civilian/militarytransitional government in Khartoum.Reforms since AbiyAhmed became Ethiopias prime minister impressed sufficientlyto win him the 2019 Nobel Peace Prize,but questions haveemerged about the trajectory of change.On the resources front,major minerals and hydrocarbons playshave until now been driven by demand from China,and otherindustrialised nations.Africa played an important role inEconomies battle to accommodate carbontransition amid uncertaintyInvestors are being asked to provide unprecedented funding to help Africa tackle climate change and transitiontowards a post-carbon economy.The African Energy Atlas 2020/2021 seeks to provide an overview of trends ininfrastructure and resources,along with an idea of some of the many policy challenges confronting the continent SectionBeijings rise to global power status,with China providingunprecedented levels of finance and infrastructuredevelopments,in parallel with its appetite for natural resources.This means China now serves as the prism through which othernations define their relations with Africa.Growing strategic competition has become apparent duringDonald Trumps presidency,but involves more than just the US,China and former colonial powers.Newer players like Turkey,the UAE and Russia are making a mark on African conflictsand investment plays,while governments are increasinglyrealising they can use this competition to their advantage.Carbon in transitionThe 2014 oil price crash caused havoc in many resourceproducers.Covid-19 and conflict between key producers wrecking the historic 2016 deal between Opec states,led bySaudi Arabia,and non-Opec countries,led by Russia flooredthe market in March 2020,just as oil-dependent economies likeRepublic of Congo were claiming some recovery.Thesedevelopments could have long-term ramifications for oil pricesand for the industry itself.Resources developers face longer-term problems in a world looking to tackle climate change bytransiting out of carbon.While many producer governments arestill in denial,their prized oil and coal reserves may never bedeveloped.Many will be left with stranded assets,even if globaloil consumption remains at around 100m b/d.As the carbon transition accelerates,rising electric car sales inwealthier economies will lead more oil giants to becomerenewables-focused a trend already under way at majors suchas BP,Eni,Shell and Total.Gas producers seem in a betterposition,as they supply the transition fuel necessary to balanceAFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 591 100a 901 60 30%0 15%No data20,000MW 5,000MW 19,999MW1,500MW 4,999MW500MW 1,499MW100MW 499MWLess than 100MWEGYPT100ALGERIA100ETHIOPIA44SOUTHAFRICA84ANGOLA42NIGERIA54LIBYA70MOROCCO100GHANA79ZAMBIA40UGANDA22KENYA64CAMEROON61MALI43DEM.REP.OF CONGO19NIGER20EQUAT.GUINEA 67TANZANIA33SUDAN56TOGO 48SENEGAL62MOZAMBIQUE27BOTSWANA63BENIN 43RWANDA 34NAMIBIA53GABON92MADAGASCAR24MALAWI13BURUNDI 9GUINEA-BISSAU26ZIMBABWE40THE GAMBIA56SIERRA LEONE 23SOUTHSUDAN25SOMALIA33BURKINAFASO 25LIBERIA 21MAURITANIA43GUINEA35C?TED?IVOIRE66MAURITIUS98EGYPT59,885ALGERIA21,134ETHIOPIA4,270SOUTHAFRICA56,329ANGOLA5,715NIGERIA13,278LIBYA10,890MOROCCO9,576GHANA5,059ZAMBIA2,878UGANDA1,177KENYA2,788CAMEROON1,478MALI667DEM.REP.OF CONGO2,376NIGER170EQUAT.GUINEA 339TANZANIA1,512SUDAN3,941TOGO 201SENEGAL1,226MOZAMBIQUE2,875BOTSWANA795BENIN 226RWANDA 186NAMIBIA622GABON709MADAGASCAR734MALAWI459BURUNDI 73GUINEA-BISSAU50ZIMBABWE2,294THE GAMBIA128SIERRA LEONE158SOUTHSUDAN12SOMALIA7BURKINAFASO 402LIBERIA 148MAURITANIA368GUINEA647C?TED?IVOIRE2,179S?O TOM?&PRNCIPE 37MAURITIUS711CAPEVERDE234C.A.R.25CHAD121COMOROS 41REP.OFCONGO783DJIBOUTI 143ERITREA 160LESOTHO 76SEYCHELLES109ESWATINI 100TUNISIA 5,980CAPEVERDE93C.A.R.30CHAD11SEYCHELLES100COMOROS 80REP.OFCONGO66DJIBOUTI 60ERITREA 48LESOTHO 34ESWATINI 74TUNISIA 100S?O TOM?&PRNCIPE 73W Sahara(under UNmandate)549PERCENTAGE OFPOPULATION WITH ACCESSTO ELECTRICITY,2017Source:SEforAll,The Energy Progress Report 2019 African Energy 2020(www.africa-)INSTALLED ON-GRIDGENERATIONCAPACITY,2019Source:African Energy Live Data African Energy 2020(www.africa-)The Atlas teamThe African Energy Atlas was created in 2007 to hold the growingstore of cartographic materials built up by the African Energynewsletter,created in April 1998.It has since grown into asignificant reference work covering African Energys core areas ofinterest:power,upstream oil and gas,downstream hydrocarbonsand wider African finance and policy issues.This content iscomplemented by African Energy Live Data,an industry-leadingdatabase with entries on more than 6,500 power generationprojects and an ambitious growth trajectory.Many of the maps in Atlas 2020/2021 are informed by Live Data,which along with a wide variety of other sources have been craftedinto maps by cartographer David Burles.African Energy editorThalia Griffiths leads the publication with articles from Griffiths,African Energy power editor Dan Marks,associate editor JohnHamilton and editorial director Jon Marks.electricity grids.However,even that could change as renewabletechnologies are increasingly supported by storageinfrastructure,allowing surplus solar and wind to be used atnight or during calm periods.Next-generation natural resource plays will be a feature of thischanging market,even before hydrogen and other fuels emergeto further challenge hydrocarbons.Increased dependence onlithium batteries,cobalt,helium and other raw materials for newtechnologies will accentuate the growing competition betweenglobal corporations,China and other players for rare minerals.These are present in countries like Democratic Republic ofCongo that have been wracked by resource wars in previousdecades.While global industries enter a period of acceleratedchange,African governments will have to move prudently toavoid the same old problems re-emerging.6 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020African Energy Live Data300,000275,000250,000225,000200,000175,000150,000125,000100,00075,00050,00025,000MW20101112131415161718192021222324250Pipeline12,470MW12.4%7,739MW7.7%1,828MW1.8!,383MW21.2 6MW 0.2bMW 0.110MW 0.38,758MW38.4,560MW17.4R2MW 0.5MW 0.01,907MW19.3,983MW9.0%1,830MW1.3&,021MW18.0AMW 0.03%1,084MW 0.7!0MW 0.1Y9MW 0.4U9MW 0.4B,733MW29.50,872MW21.3g,433MW28.4!,483MW9.0E,968MW19.4%1,830MW0.8P,006MW21.16,277MW15.3%5,628MW2.4%5,911MW 2.55MW 0.4%1,216MW 0.51MW 0.4%OtherBiomass/biogasGeothermalWindSolarHydroelectricityNuclearCoalNatural gas&liquid fuelsLiquid fuelsNatural gasNatural gasLiquid fuelsNatural gas&liquid fuelsCoalNuclearHydroelectricitySolarWindGeothermalBiomass/biogasOther*AFRICANorth AfricaWest AfricaCentral AfricaEast AfricaSouthern AfricaYES(4.4%/2.4%)YES(5.0%/1.9%)YES(4.8%/2.7%)YES(4.3%/2.8%)YES(3.3%/2.4%)YES(3.6%/2.4%)Installed capacitykept up withpopulation?Increase ininstalled capacitygrowth rate?Installedcapacity kept upwith GDP growth?Proportion ofrenewablesincreased?Proportion of non-hydro renewablesincreased?Increase in non-hydro renewablesgrowth rate?Proportion of liquid fuels*decreased?SCORECARDFOR 2019The Africa scorecard uses data from African Energy Live Data to provide snapshots ofthe state of the electricity sector during 2019.It illustrates whether electricity generation isexpanding at the same rate as population and GDP growth,whether renewable energy useis increasing and if the rate of increase is being sustained,and whether reliance on costlyfuel oils is being reduced.*only plants running exclusively on liquid fuels are included in this figureSources:population and GDP from the International Monetary Fund(2020);African Energy Live Data African Energy 2020(www.africa-)NO(4.4%/9.0%)NO(5.0%/16.7%)YES(4.8%/2.3%)YES(4.3%/3.2%)NO(3.3%/8.0%)YES(3.6%/2.5%)NO(4.4%/5.6%)NO(5.0%/8.5%)NO(4.8%/9.5%)YES(4.3%/4.0%)NO(3.3%/7.6%)YES(3.6%/2.5%)YES(21%/20%)YES(10%/8%)NO(20%/20%)NO(65%/65%)YES(63%/62%)NO(25%/25%)YES(6%/5%)YES(5%/4%)YES(2.0%/1.7%)NO(0.2%/0.2%)YES(15%/12%)NO(6.5%/6.5%)YES(23%/20%)NO(45%/48%)YES(25%/18%)NO(0%/9.7%)YES(25%/18%)NO(3.5%/5.1%)NO(9.3%/9.2%)NO(4.5%/4.4%)NO(18%/16%)YES(14.2%/14.8%)YES(27%/29%)NO(8.5%/8.5%)ALL AFRICA ENERGY MIX(on-grid&distributed),201025All statistics were compiled before the impact of the coronavirus on the Africanpower industry or economy could be assessed.*distributed includes off-gridand plants embedded within thegrid but supplying third partiessuch as industries and mines.*other includes combinationsof fuels and hybrids where theindividual capacities are notknown,as well as oceantechnologies,coal bed methaneand industrial process heat.Source:African Energy Live Data African Energy 2020(www.africa-)ALL AFRICA ENERGY MIX(on-grid&distributed*)African Energy 2020(www.africa-)Source:African Energy Live Data200020102019The graphics contained in these pages from African Energy LiveData illustrate the many transitions that Africa is going throughand that these are still only at an early stage.The scorecard shows that the growth rate of non-hydropowerrenewable power continues to be exponential,with a year-on-year increase of 23%in 2019 compared to 20%in 2018.Overall growth of installed capacity has slowed however,ascan be seen from the scorecard,and the proportion of costlyand polluting liquid fuels in the energy mix marginallyincreased.This hints at underlying transitions in market structure whichhave slowed the pace of growth.Attention has shifted totransmission and distribution,while many governments arelooking to the private sector for investment and scaling backthe role of state-owned enterprises.The graph on page 9 showing net capacity additions byownership type shows that by 2022,more than half of newcapacity additions in each region will be privately funded.Giventhe short lead times of private wind and solar plants this is likelyto be an underestimate.Regionally,North Africa will continue to be the largest marketbut other regions are set to gain in importance.West andSouthern Africa have growing pipelines of projects which arehere significantly underestimated because likely largeSectionWSHNC2LGINSTALLED ON-GRID GENERATION CAPACITY BY COUNTRY AND FUEL,Q1 2020AlgeriaAngolaBeninBotswanaBurkina FasoBurundiCameroonCape VerdeCentral African RepublicChadComorosCongo,Dem.Rep.Congo,Rep.(Brazzaville)C?te d?IvoireDjiboutiEgyptEquatorial GuineaEritreaeSwatini(Swaziland)EthiopiaGabonGambiaGhanaGuineaGuinea-BissauKenyaLesothoLiberiaLibyaMadagascarMalawiMaliMauritaniaMauritiusMoroccoMozambiqueNamibiaNigerNigeriaRwandaS?o Tom?&Pr?ncipeSenegalSeychellesSierra LeoneSomaliaSouth AfricaSouth SudanSudanTanzaniaTogoTunisiaUgandaWestern Sahara*ZambiaZimbabweNorth AfricaSub-Saharan AfricaTOTALMWNaturalgasLiquidfuelsNatural gas&liquid fuelsCoalNuclearHydro-electricitySolarWindGeothermal Biomass/biogasOtherTOTAL20,0625002026753465721,1791543361,026183,6061,47945810,00624197294,59850,92414,74765,6711,732591053304138419761204113551431,290291539619128750281337423601,6755771413491224321,1822042316384351,04010310673,548121,541100481202631054,40914,37718,78621,1345,715226795402731,47823425121412,3767832,17914359,8853391601004,2707091285,059647502,7887614810,8907344596673687119,5752,87562217013,278186371,225109158756,329123,9411,5122015,9801,1775492,8782,294108,013119,015227,028465951479064331,54224301,6595,6091801,3294871201201,04338,6594,92443,5832163,3873732827192,3571948792,832127603,8173241,5803668287388137318318611,7572,1833471,938933523,6001,91356333559922,3971,0814,85931,02635,88636635911,5145-43-56-20-3686585301277-9-110-2,1531054807732,5562,8605,415*under UN mandate indicates less than 1MW or zero Source:African Energy Live Data African Energy 2020(www.africa-)600613,76712043,0523001,2103,76745,34349,110151,800151,8001,81598230831831402523223811129130514037271116753220102911,38873243363013806555262,1182462072,6562,9255,581AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 7Overviewprocurement programmes in South Africa are not counted byLive Data until procurement is under way.It is clear from page 10 that 2019 was a breakthrough year forsolar power.Nearly 2GW was added while in previous yearscapacity additions have never exceeded 1GW.The market is alsoincreasingly diverse,with large numbers of small projects andincreasing numbers of small and medium projects.Wind continues to make slower progress.The number of largeprojects continues to increase but there are fewer medium andsmaller projects.This represents a problem for the wind industry,as it is more reliant on a few large markets and it has struggledto add new revenue streams in the way that solar has.Inparticular,it has so far been unable to take advantage of theburgeoning commercial and industrial market.20101112131415161718192021222324250Pipeline2010111213141516171819202122232425Pipeline20101112131415161718192021222324250Pipeline135,000130,000125,000120,000115,000110,000105,000100,00095,00090,00085,00080,00075,00070,00065,00060,00055,00050,00045,00040,00035,00030,00025,00020,00015,0005,00010,00040,00035,00030,00025,00020,00015,0005,00010,00040,00035,00030,00025,00020,00015,0005,00010,00020101112131415161718192021222324250Pipeline90,00085,00080,00075,00070,00065,00060,00055,00050,00045,00040,00035,00030,00025,00020,00015,0005,00010,00020101112131415161718192021222324250Pipeline025,00020,00015,0005,00010,00020101112131415161718192021222324250Pipeline05,00010,0000MWMWMWMWMWMWNorth AfricaWest AfricaCentralAfricaEastAfricaSouthernAfricaNorth AfricaWest AfricaCentral AfricaEast AfricaSouthern AfricaOtherBiomass/biogasGeothermalWindSolarHydroelectricityNuclearCoalNatural gas&liquid fuelsLiquid fuelsNatural gasNET ANNUAL CAPACITY ADDITIONS BY REGION,201025Source for all charts:African Energy Live Data African Energy 2020(www.africa-)NORTH AFRICA ON-GRID ENERGY MIX,201025WEST AFRICA ON-GRID ENERGY MIX,201025SOUTHERN AFRICA ON-GRID ENERGY MIX,201025EAST AFRICA ON-GRID ENERGY MIX,201025CENTRAL AFRICA ON-GRID ENERGY MIX,2010258 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020African Energy Live Data North Africa remains by some way the largest market inAfrica.This is illustrated by the to-scale graphics on this page.The region has seen a burst of activity in Egypt,adding largevolumes of gas,solar and wind power to the grid.Morocco andTunisia are also becoming major markets for solar powerdevelopment,with wind programmes also significant.Central Africa continues to lag and the current pipelinesuggests it will fall even further behind.Political instability,poor governance and weakeconomies prevent large-scaleinvestment as well as deterringoff-grid providers.New interconnectionscombined with pragmaticleadership and growingeconomies could see EastAfrica emerge as asignificant market.TheNorth AfricaWest AfricaCentralAfricaEastAfricaSouthernAfrica Section2010N W C E SMW2011N W C E S2012N W C E S2013N W C E S2014N W C E S2015N W C E S2016N W C E S2017N W C E S2018N W C E S2019N W C E S2020N W C E S2021N W C E S2022N W C E S2023N W C E S2024N W C E S2025N W C E SPipeline15,00014,00013,00012,00011,00010,0009,0008,0007,0006,0005,0004,0003,0002,0001,00001,000MW15,00014,00013,00012,00011,00010,0009,0008,0007,0006,0005,0004,0003,0002,0001,00001,000RentalState ownedPrivately ownedNorth AfricaWest AfricaCentral AfricaEast AfricaSouthern AfricaNWCESSource for both charts:African Energy Live Data African Energy 2020(www.africa-)NET ANNUAL CAPACITY ADDITIONS BY OWNERSHIP TYPE AND REGION(on-grid and distributed),201025201011121314151617181920,00015,0005,00010,0000MWRentalState ownedPrivately ownedNET ANNUAL CAPACITY ADDITIONSBY OWNERSHIP TYPE(on-grid and distributed),201019AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 9Regional viewregion is already emerging as a driver of innovative policy,andregulation and investment into renewable energy is increasingrapidly.It is a hub and incubator for the off-grid industry as wellas having established a track record of utility and market reform.Southern Africa is also set to see substantial investment inrenewable energy.Solar,wind and hydropower in particular arelikely to increase substantially while coal capacity is set todecrease as existing plants in South Africa are decommissioned.West Africa has been hampered by poor policy makingresulting in inefficient grids unable to support major industrialdemand.The region is a major target for commercial andindustrial developers supporting industry and mines using dieselto manage sporadic grid supply.The region is in danger ofmissing out on low cost renewable energy which could offsetthe cost of expensive thermal power.Greater regionalinterconnectivity may help in this regard,particularly byintroducing policy and regulatory competition.The graphic below illustrates the slow and patchy growth ofprivate sector investment on the continent over the decade.State-owned investment has been much more significant andalso grew more rapidly until 2019.There are significant time lags in power sector developmentgiven the average development time on the continent,which isbelieved to be around seven years.A long period of reform isstarting to pay off,with 2019 showing more private than publicinvestment in generation in both East and West Africa.The pipeline shows that the private sector will become theleading source of investment into generation from 2022.Thiscreates new challenges,such as the need to move away fromgovernment guarantees through market and utility reform.Focus in the past has been on creating independent powerproducer and public-private partnership frameworks andcredible procurement programmes.Moving forwards,governments will be pushed to create financially viable andefficient markets capable of generating and growing therevenues needed to support private investment.Identify power plants and analyse markets African Energy Live Data is a live-updated online databasefeaturing more than 6,500 power plants and projects across Africa.Identify owners,developers,offtakers,financiers and their portfolioof projects and find opportunities for investment and sales Support strategic planning by analysing trends by country from2010 alongside key economic&demographic statisticsContact Alex Wark for a demonstration.E:salesafrica-www.africa- AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020African Energy Live Data2010100201090807060504030201002011201220132014201520162017201820192,00095857565554535251551,9001,8001,7001,6001,5001,4001,3001,2001,1001,0009008007006005004003002001000MW2011201220132014201520162017201820192010201020100201120122013201420152016201720182019251551,2001,1001,0009008007006005004003002001000MW20112012201320142015201620172018201950MW 20 50MW10 20MW5 10MWLess than 5MW50MW 20 50MW5 20MWLess than 5MW200MW 100 200MW50 100MWLess than 50MW200MW 100 200MW50 100MWLess than 50MWSource for all charts:African Energy Live Data African Energy 2020(www.africa-)NUMBER OF SOLAR PROJECTS ADDED BY SIZE,201019SOLAR CAPACITY ADDITIONS BY PROJECT SIZE,201019NUMBER OF WIND PROJECTS ADDED BY SIZE,201019WIND CAPACITY ADDITIONS BY PROJECT SIZE,201019 Solar and wind continue to make inroads into African marketsas they become the cheapest source of energy and a usefulcomplement to grids overly reliant on seasonal hydropower orcostly thermal power.2019 saw a step change in solar investment,where the capacityadded more than doubled to nearly 2GW in one year,around20%of all new capacity.Prior to the coronavirus,similarcapacity additions were expected in the years 2020-2022.Medium-large capacity solar projects remain the most valuablemarket,boosted in 2019 by the commissioning of many 50MWprojects at Benban in Egypt.The 50MW market was the mostvaluable 2013-2018,led by procurement in South Africa.Small and micro solar projects less than 20MW is a growingmarket representing more than 250MW in 2019.This is anunderestimate due to the lack of data on projects smaller than1MW.10-20MW is an emerging market with significantpotential in Africa due to the possibility of locating theseprojects close to demand centres without major grid upgradesand lower impact on government balance sheets.Projects in the5-10MW range have been constrained by high developmentcosts relative to returns.There has been very strong growth in the 0-5MW solarmarket,which is dominated by commercial and industrial(C&I)plants.Several private equity funds have made C&I their firstinvestment as it offers a potentially quicker and better diversifiedroute to project portfolios with total installed capacitycomparable to a utility-scale plant.Section56 days60 days429 days196 days1,058 days334 days353 days296 days1,058 days334 days353 days424 days1,053 days223 days701515951 days286 days914 days163 days508 days128 days164 days476 days333 days372 days1109508 days832329602 days437 days610 days98211 days664 days225 days149 days422 days718 days192 days708 days97552333 days19612 days88808 days121 days225 days765 daysPreferred bidder to PPAPPA to financial closeFinancial close to start of constructionStart of construction to operationPreferred bidder to PPAPPA to financial closeFinancial close to start of constructionStart of construction to operationAVERAGE SOLAR DEVELOPMENT TIMELINES BY PROCUREMENT PROGRAMMEMorocco Noor Ouarzazate I CSPMorocco Noor Ouarzazate II&III CSPEgypt Solar FiT Round I PVEgypt Solar FiT Round II PVZambia Scaling Solar Round I PVSouth Africa REIPPP1 PVSouth Africa REIPPP2 PVSouth Africa REIPPP3 PVSouth Africa REIPPP4 PV(expected)AVERAGE WIND DEVELOPMENT TIMELINES BY PROCUREMENT PROGRAMMESouth Africa REIPPP1South Africa REIPPP2South Africa REIPPP3South Africa REIPPP4(expected)AFRICA WIND ON-GRID AVERAGEAFRICA SOLAR ON-GRID AVERAGESource for both charts:African Energy Live Data African Energy 2020(www.africa-)AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 11Solar and wind The wind power market has become more concentrated,failing to achieve consistent growth.While large-scale projectsoffering very low tariffs have become more prevalent in moredeveloped markets,investment into smaller and medium sizedprojects has diminished.The result is an over-reliance on a few large markets.Countrieswith smaller grids have been unable to access the potentiallyvery low cost technology.This is often due to poor windresources but in many countries because of difficult logistics anda lack of institutional capacity and policy.The graphic above compares the timelines of several highprofile procurement programmes.One of the aims of theprocurement programmes was to speed up delivery of projects,as well as reduce the cost of power.Although prices fell over rounds in nearly all cases partly asa result of the falling cost of technology and partly greaterexperience and more developed supply chains in-country timelines have more often lengthened.In South Africa,despite procurement of new capacitybecoming more urgent,the time from selection as a preferredbidder to operation has increased in every round,from 951 daysin round 1 for solar to 2,031 days in round 4.For wind itincreased from 983 days to 2,164 days.This time does notinclude the preparation of projects for bidding,an intensiveprocess in South Africa.In South Africa,solar projects selected in rounds 3 and 4 tooklonger to move from the signing of key agreements tocommercial operations than the African average.This is true ofmost of the Egyptian solar feed-in tariff projects.The growing inefficiency of the South African process isillustrated by the fact that the large and more complexconcentrated solar projects procured in Morocco were deliveredwithin a comparable timeframe,despite construction delays.For wind,however,it is clear that procurement programmeshave substantially reduced development time from signing keyagreements to commercial operation.In fact,in all but round 4in South Africa the entire process from selection as a preferredbidder to operation was quicker than the average time fromagreement signing to commercial operation on the continent.African connections:Roads,railways,ports,airportsCAPEVERDEPRAIAANGOLAS O U T HA F RIC AMADAGASCARBOTSWANAZIMBABWEZAMBI AESWATINILESOTHOMALAWITANZANIAKENYAUGANDARWANDABURUNDIGABONNAMIBIADJIBOUTIERITREAS U D A NN IG E RCENTRALAFRICAN REPUBLICEQUAT.GUINEAS?O TOM?&PRNCIPEREP.OFCONGOCAMEROONM A L IA L G E RIAL IBYAEGYPTTUNISIAMOROCCO Western Sahara(under UNmandate)MAURITANIAMAURITIUSR?union(Fr.)SENEGALTHE GAMBIAGUINEA-BISSAUGUINEASIERRA LEONELIBERIAC?TED?IVOIRETOGOBENINMOZAMBIQUESOMALIACOMOROSMayotte(Fr.)Annob?n(Eq.Guinea)BURKINAFASOGHANA(BRAZZAVILLE)N IG E RIASEYCHELLESETH IO PIADEMOCRATICREPUBLICOF CONGOSOUTH SUDANC H A DJohannesburgDurbanPort ElizabethBloemfonteinBeiraCabinda(Ang.)MwanzaDar es SalaamMombasaNampulaNdolaBulawayoLubumbashiKisanganiMbuji-MayiBenguelaDoualaBerberaPortSudanElFasherLagosKanoPort HarcourtAbidjanAlexandriaLuxorAswanBenghaziCasablancaMarrakechOranFrancistownWalvisBayEastLondonTangierAgadezWauTimbuktuNouadhibouEl AyounSfaxAtarRegganeTamanrassetConstantineTobrukN?maSt-LouisKayesKankanGaoKumasiBoboDioulassoIbadanArlitZinderEnuguMaiduguriSarhSuezPort SaidSafagaMinyaWadi HalfaAtbaraKostiAssabMassawaKassalaKismayoMtwaraPointe-NoireMatadiKuitoNamibeTsumebLivingstoneBlantyreToliaraMahajangaToamasinaInhambaneKimberleyCape TownArushaMossel BayPietermaritzburgL?deritzTaolanaroPembaMonguHuamboLuenaKanangaMbandakaPort-GentilBukavuSongeaMbeyaTangaMoyaleLokichokioHargeisaBosasoGaroweDireDawaWadMedaniGuluIsiroButaBuniaKound?raAbuSimbelBordjMokhtarOujdaF?sBiskraAnnabaTozeurNyalaZou?ratKadunaParakou Sekondi-TakoradiFrancevilleIleboKalemieSolweziKaminaKinduBumbaKigomaKasamaAntsirabeTeteNacalaMalanjeMenongueLobitoUpingtonLamuMusinaVryburgLubangoJorf LasfarGharda?aBizerteSabhaGhatIn Am?nasNz?r?kor?SokotoGedarefOu?ssoIkelaLuauSaurimoKuvangoMaunSpringbokOudtshoornMananjaryFianarantsoaErmeloMbalaGonderWeldiyaMekeleRichards BaySaldanhaTemaBeja?aDamiettaGizaMalakalAgadirHurghadaSharmel-SheikhMarsaAlamK?nitraBagamoyoAb?ch?Al-KufraAntsirananaTangerMedEntebbeTenkeAwashKisumuNational boundaryPrincipal roadMain railwayBusiest airports,Feb 2020(20 scheduled passengerflights,daily average)Source:L.TanaL.TanganyikaLakeVictoriaLake Malawi(L.Nyasa)L.KivuL.AlbertL.VoltaL.ChadL.NasserL.TurkanaSaharaLibyanDesertAtlasMountainsNigerBenueNileBlueNileU?l?CongoKasa?ZambeziVaalOrangeSinaiZanzibar I.CapeAgulhasTROPIC OF CAPRICORNTROPIC OF CANCERCape ofGood HopePemba I.Mafia I.Cap BonJerbaCapriviStripCopper-beltWhiteNileL.MweruL.EdwardChariOmoJubaLimpopoCairoTripoliAlgiersDakarKanoN?DjamenaWad MedaniGonderDjibouti VilleMombasaNairobiLagosLobitoCapeTownBeira123433441556678899EQUATORT?n?r?Mah?PraslinKilimanjaroSalPRETORIAMAPUTOWINDHOEKGABORONEHARAREANTANANARIVOLUSAKALUANDAKINSHASABRAZZAVILLENAIROBILILONGWELIBREVILLEYAOUND?BANGUIKAMPALAMOGADISHUADDISABABAASMARAKHARTOUMN?DJAMENAABUJANIAMEYACCRALOM?PORTO-NOVOYAMOUSSOUKROMONROVIAFREETOWNCONAKRYBISSAUDAKARBAMAKOCAIRONOUAKCHOTTTRIPOLITUNISALGIERSRABATDJIBOUTIVILLEMORONIPORT-LOUISMBABANEMASERUBANJULMALABOS?O TOM?BUJUMBURADODOMAJUBAOUAGADOUGOUKIGALIVICTORIA African Energy 2020(www.africa-)TRANS-SAHARANTRADE ROUTESAncient trade routes thatcrossed the Sahara Deserthave been adapted forformal and informal trade,including a variety ofsmuggling networks.TRANSGUINEAN RAILWAYSProposed rail links taking minerals to a planneddeep-water port SE of Conakry.BENGUELA RAILWAYLinking the port of Lobito with the DRC,it providedan export route for Zambian and Congolese copperduring the mid-20th century.Heavily damagedduring the Angolan civil war(1975-2002),a new linehas been built with Chinese help.The Lobito-Luausection opened in 2015 and a full service fromTenke began in 2018.TRANS-AFRICAN HIGHWAYS(TAH)An international programme to develop a transcontinental road network.NORTH-SOUTH ROUTES:TAH-2:Algiers-Agadez-Lagos(Trans-Sahara)TAH-3:Tripoli-N?Djamena-Kinshasa-Windhoek-Cape TownTAH-4:Cairo-Khartoum-Addis Ababa-Nairobi-Lusaka-Gaborone-Cape TownEAST-WEST ROUTES:TAH-1:Cairo-Tripoli-Algiers-Rabat-DakarTAH-5:Dakar-Bamako-N?DjamenaTAH-6:N?Djamena-DjiboutiTAH-7:Dakar-Freetown-Abidjan-LagosTAH-8:Lagos-Yaound?-Bangui-Kisangani-Nairobi-MombasaTAH-9:Lobito-Lubumbashi-Harare-BeiraWALVIS BAY CORRIDORSA network of transport corridorslinking Namibia?s largest port with:1.SOUTH AFRICA:TRANS-ORANJE,to Pretoria/Johannesburg via Upington,with a link to L?deritz;TRANS-KALAHARI,to Pretoria/Johannesburg via Botswana.A railwayto export Botswanan coal is proposed,to run alongside the highway.2.ZAMBIA:TRANS-CAPRIVI,a strong competitor to the Tazararailway for Zambian and DRC copperexports.3.ANGOLA:TRANS-CUNENE.MOROCCOHIGH-SPEED RAILAfrica?s first high-speed railservice,Al-Boraq,linkingCasablanca with Tangieropened in 2019.ADDIS ABABA AIRPORTBole International Airport has been expandedto triple its capacity.A new terminal opened inJanuary 2019 can accommodate up to 22mpassengers/yr.NEW EGYPTIAN AIRPORTSThe construction of five new airports was announced in 2017:SphinxInternational Airport in Giza,New Capital Airport,Bredwell Airport in Sinai,South Red Sea Airport and Ras Sidr Airport.Japan is funding a newpassenger terminal at Alexandria?s Borg El Arab International Airport.DAKAR?S NEW AIRPORTBlaise Diagne International Airportopened in December 2017.Costing$575m,it has a capacity of 10m passengers/yr.KHARTOUM NEW INTERNATIONAL AIRPORTKNIA began construction in 2019;it will have acapacity of approximately 7.5m passengers/yr.DJIBOUTIChinese-funded projects includethree ports,two airports and awater pipeline from Ethiopia,aswell as a Chinese military base.SINGLE AFRICAN AIR TRANSPORT MARKETSAATM is a flagship project of the AU?s Agenda 2063 and aims to create asingle unified air transport market in Africa,liberalise civil aviation and actas an impetus to the continent?s economic integration agenda.Officiallylaunched in January 2018 with 23 countries as starting participants.ETHIOPIA-DJIBOUTI RAILWAYAfrica?s second electric railway beganoperations in 2016,linking Addis Ababa withDjibouti?s new Doraleh Multipurpose Port.LEKKI DEEP SEA PORTConstruction has begun on developing new container and berth facilities in LagosFree Trade Zone by Singapore-based Tolaram Group?s Lekki Port LFTZ Enterprise.ALGERIA?S EAST-WEST HIGHWAY(A1)A six-lane 1,200km road running from theMoroccan border to the Tunisian border builtby Chinese(west and central sections)andJapanese(east)consortia.EGYPT?S NEW CAPITAL CITYA 700 km2 development 45km east of Cairo with an internationalairport is planned to accommodate 5m and become Egypt?s newadministrative capital;developed by the government and the military.NORTH-SOUTH CORRIDORA Comesa initiative comprising a road and rail network of over10,000km,linking eight countries in Southern and Central Africa()with the aim of strengthening cross-border trade and tourism.TAZARA RAILWAYBuilt with Chinese assistance in the 1970s to link Zambia withDar es Salaam,avoiding Zimbabwe and South Africa.EAST AFRICANINFRASTRUCTUREProjects include the EastAfrican Railways Master Planand Lamu Port-South Sudan-Ethiopia Transport(LAPSSET)Corridor.TANZANIAN PORTSDar es Salaam port is beingexpanded,while a$10bnnew port and free trade zoneis planned at Bagamoyo.MOZAMBIQUE?S CORRIDORSNACALA CORRIDOR:Linking Malawi to the sea and the newNacala-a-Velha port,the outlet for Moatize coal exports.BEIRA CORRIDOR:An important gateway for landlockedcountries to the west of Mozambique.MAPUTO CORRIDOR:Linking South Africa?s industrialheartland with the deepwater ports of Maputo and Matola.A port at Techobanine,south of Maputo,has been proposedto export coal from Botswana.NIGERIA RAILAbuja-Kaduna railway opened in 2016,part of a CCECC contract to equipthe Lagos-Kano route with modern standard gauge rail.The same companyis building the Lagos-Calabar highway.Future Port Harcourt-Maiduguri andLagos-Calabar rail lines are being supported by Russia.ETHIOPIAN RAILWAYSA standard gauge railway running north fromAwash to Weldiya and Mekele is being built.KENYAN RAILStandard gaugerailway fromMombasa toSuswa viaNairobi andEmbakasi inlandcontainer depot,with proposedextensions toKisumu and theUgandan border.BENIN BACKBONE PROJECTIncludes a new S?m?-Krak?airport to serve southern Nigeria and Benin,rehabilitation of the Cotonou-Parakou railway and construction of aninternational standard gauge railway linking Parakou with Niamey.KRIBI PORT&INDUSTRIAL COMPLEXChina Harbour Engineering Company are building a new deep-sea port and associatedinfrastructure on the southern Cameroonian coast,opening the region?s minerals,cottonand other commodities to the world?s markets.A railway linking Kribi to southernCameroon?s Mbalam iron ore deposit is also being developed.12 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020Climate,population,income,fossil fuels,power generationANGOLASOUTHAFRICAMADAGASCARBOTSWANAZIMBABWEZAMBIAESWATINILESOTHOMALAWITANZANIAKENYAUGANDARWANDABURUNDIDEM.REP.OFCONGOGABONNAMIBIADJIBOUTIERITREASUDANCHADNIGERCENTRALAFRICANREP.EQ.GUINEAS?O TOM?&PRNCIPECAMEROONMALIALGERIALIBYAEGYPTTUNISIAMOROCCO Western Sahara (under UN mandate)MAURITANIACAPEVERDEMAURITIUSR?union(Fr.)SENEGALTHE GAMBIAGUINEA-BISSAUGUINEASIERRA LEONELIBERIAC?TED?IVOIRETO.BE.MOZAMBIQUESOMALIACOMOROSMayotte(Fr.)BURKINAFASOGH.(BRAZZAVILLE)NIGERIASEYCHELLESETHIOPIAREP.OFCONGOSOUTHSUDAN010203040050100150200250300350500550600DOUALA CAMEROONElevation:9mJ F M A M J J A S O N DmmC0BAMAKO MALIElevation:381m10203040050100150200250300J F M A M J J A S O N DmmC0ENTEBBE UGANDAElevation:1,155m102030050100150200250J F M A M J J A S O N DmmC0SABHA LIBYAElevation:440m10203040050100J F M A M J J A S O N DmmC0KHARTOUM SUDANElevation:379m10203040050100J F M A M J J A S O N DmmC0J F M A M J J A S O N DCAPE TOWN S AFRICAElevation:13m102030050100150mmCSIRTEBASINGHADAMESBASINTINDOUFBASINTADLA BASINKAROO BASINof which:prospective areaOuagadougouYaound?DoualaN?DjamenaLubumbashiMbuji-MayiKisanganiAddisAbabaAccraKumasiConakryNairobiMonroviaTripoliTunisAntananarivoBamakoCasablancaRabatF?sMaputoKdOnAbujaPHAAbaBBenin CityIbIbadanKd KadunaLLom?NNnewiOn OnitshaPH Port HarcourtUUyoBKigaliDakarMogadishuDurbanPort ElizabethPretoriaKampalaLusakaHarareKanangaSabhaBamakoKhartoumDoualaEntebbeCape TownAlgiersBrazzavilleMombasaMarrakechNiameyKanoIbFreetownCape TownAbomeyPointe-NoireBukavuLilongweNouakchottTangierMatolaAUNEkurhuleniLMajor power generation centres(existing and proposed)Thermal power(coal,oil,gas)HydroelectricityNuclearWindSolarGeothermalGDP per capita,2018Urban agglomerations:estimated populations,2020US$6,001 $3,001$6,000$1,501$3,000$701$1,500$0$700No data5.0 million (named in bold,and with figures)1.0 4.9 million(named)0.5 1.0 millionSahelian zoneLow rainfall but greatseasonal variation,high temperaturesTropical zone withdry seasonsSeasonal variation intemperature and rainfall,long dry seasonsHumid tropical zoneHigh rainfall andtemperatures,short dryseasonEquatorial zoneHigh temperatures all year,high rainfall,short dryseason,if at allMediterranean zoneHot dry summers,mild wet wintersDesert zoneVery high daytimetemperatures,very littleprecipitationMajor oil/gasareas andrecentsignificantdiscoveriesMajorcoal/lignitedepositsMajor shalegas basinsAve.daily max.temp.Ave.daily min.temp.Ave.precipitationAfourerAbdelmoumenAswanDal,KajbarMeroweKoebergElDabaZafaranaTekezeTana-Beles,Tis AbayMelka WakenaAwash,KokaGilgel Gibe,Halale-WerabesaTana RiverBujagali,Owen FallsRuziziManantaliKal?ta,SouapitiKossouAkosomboJebba,KainjiMambillaLower Sanaga RiverGrandPoubaraIngaZongoUpperLualabaRuacanaKafue,KaribaCahora Bassa,Mphanda NkuwaIngulaLesotho HighlandsGariep,VanderkloofRift ValleyOlkariaDarnahRas Gharib-Zeit BaySidi DaoudMisratah,TarhunaHassiR?MelA?n Beni MatharTangier,T?touanSebkhate TahAkhfennirMombasaDar es SalaamKidatu,Kihansi,Stiegler?s GorgeKwanzaRiverWalvis BayL?deritzOranjemundHwangeSere(Koekenaap)Cape TownCoega(Port Elizabeth)East LondonMossel BayUpingtonMorupuleMatimba,MedupiGauteng&Mpumalanga provincesAlgiersTemaAbidjanKureimatCairo,Nile Delta,Port SaidAl-Khums,TripoliSirteBenghaziOuarzazatePort LouisIkopa RiverManiaRiverEssaouiraBoujdour,Foum Al-OuedMohamm?diaJorf LasfarOranEgbinNiger DeltaKhartoumPort Sudan,ArkyiaiBizerteBatoka Gorge,Devil?s GorgeMaputoTubatseMoatizeChicamba,MavuziLake Turkana,BubisaMkumburaAshegodaKom OmboKougaCapeVerdeGrand RenaissanceVictoria NileTurkwelDakarTunisAllal El Fassi,Al-WahdaHassiMessaoud Annaba,SkikdaTuNurDagash,ShereikBaro,GebaAdama,Debre BirhanMmamabulaSoyo(ALNG)Boou?CholletSoundaPointe-NoireNoun RiverLuandaKisanganiNzemaDe Aar,PrieskaPofadderCairo20.9mLagos14.4mJohannesburg5.8mLuanda8.3mJeradaHassi R?MelHassi MessaoudGulf ofGab?sBerkineBasinSaharafieldsGhadamesBasinSirteBasinNileDeltaGulf ofSuezFoxtrotJubilee,TENDobaFula(coalbedmethane)WesternDesertMurzuqBasinRio delRey BasinMugladBasinMelutBasinLakeAlbertBasinSongo SongoMnazi BayPande,TemaneCabindaLower CongoBasinAlbaOkumeOgoou?DeltaEtam?HwangeMmamabula,WaterbergKwaZulu-NatalMoltenoBredasdorp BasinKuduIbhubesiLuenaMorupuleAnambraSpringbokFlatsMaambaSoutpansbergErmelo,WitbankHighveldOffshoreRuvumaBasinMuiBasinSankofaMoatizeRuhuhuSongwe-KiwiraLuangwaIlliziBasinEmeraude,LoangoElBormaSengwaAgademNiger Delta(Akata-Agbada)Offshore S TanzaniaNiassaProvinceKinshasa 14.3mKhartoum5.8mDar es Salaam6.7mS LokicharBasinKwanza BasinGreater Tortue AhmeyimZohrAwash ValleyAboadzeKathu,JasperUpingtonEl HamraweinShiroroSangomarAbidjan5.2mAlexandria5.3mLekkiGreater BirallahYakaar-TerangaMSGBCBasin African Energy 2020(www.africa-)FOSSIL FUELSAfrica 8.6%Rest of world91.4%OILProductionin 2018:Sources:AfDB,AUC&ECA,African Statistical Yearbook 2019;United Nations,Department of Economic and Social Affairs,Population Division(2018),World UrbanizationProspects:The 2018 RevisionPOWER GENERATIONPOPULATION AND INCOMECLIMATE ZONESSources:UNEP(2008),Africa:Atlas of OurChanging Environment;Africa 6.1%Rest of world93.9%GASAfrica 4.0%Rest of world96.0%COALCountry populations,mid-2019(millions)Nigeria201.051%urbanEthiopia 110.1Egypt 101.2Democratic Rep.of Congo 86.7South Africa 58.1Tanzania 60.9Kenya 52.2Algeria 42.7Sudan 42.5Uganda 45.7Morocco 36.6Ghana 30.1Mozambique 31.4Madagascar 27.0Cameroon 25.3Angola 31.8C?te d?Ivoire 25.5Rest of Africa21Africa total:1,318.3mNiger 21.4Burkina Faso 20.34345356728247335466637573851571730AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 13FinanceAdvisers and financiers hungry for above-average rates ofreturn and new business opportunities have talked upAfricas potential to emerge as a major frontier for privateinfrastructure financing.Their support for a far greater numberof IPPs and other privately financed infrastructure,longer-termdebt financing operations,mergers and acquisitions and othertransactions holds undoubted promise for cash-strapped butpotentially fast-growing economies.In parallel,China has takena lead in developing sometimes controversial financing structuresthat have seen huge investments in infrastructure becoming areality as roads are built and electricity generated.Others see the potential for providing billions of dollars more,as the World Bank Group,African Development Bank(AfDB),European Union,Germany,France and other bilateral donorshave all placed infrastructure at the centre of their developmentpolicies.AfDB vice-president for private sector,infrastructureand industrialisation Pierre Guislain has estimated Africasinfrastructure needs at$130bn-$170bn/yr,with a financing gapof$68bn-$108bn.He argued that,while“this may soundinsurmountable,it also presents an opportunity to fosterinnovative financial solutions and partnerships that have thepotential to unlock funding”.This huge challenge will be amplified by the Covid-19pandemic,which was blighting economies worldwide as Atlas2020/2021 was published.The early signs were not promising,with investors likely to seek comfort in established marketsrather than emerging frontiers for investment.The global health crisis came after a period when private equityand other cutting-edge investors had worked hard to unlockAfricas infrastructure potential,seeking to tap new interest frompension funds,sovereign wealth funds,equities market and otherprivate investors,which have so far been largely absent fromdeals on the continent.Long underdeveloped sectors such aspower generation in sub-Saharan Africa have seen an uptick inprivate support,but have a majority of economies seen a bigfinancial boom in line with the continents ambitions?Thebrutal answer was no,even before the Covid-19 pandemicundermined so many assumptions.Local and internationalprivate financing flows for critical sectors like water andsanitation,electricity distribution and transmission remainelusive in all but a few economies.The problems are familiar:persistent bottlenecks due tobureaucracy,over-complex and costly financial structures andinsolvent local counterparts continue to hold up otherwisecommercially viable schemes.IPPs,merchant power structuresand investment in transmission companies are the norm in LatinAmerica and Asia,but in Africa,the number of IPPs whilegrowing remains highly constrained,and successful privateelectricity distribution companies like Umeme in Uganda arevery much an exception.Africa is looking at African solutions to raise finance via localbanks,pension funds and other emerging investor classes.Initiatives such as the African Continental Free Trade Area havepotential to create a vibrant new trading bloc in regions thattransact a pitifully small percentage of their commerce withtheir neighbours.It is not surprising that West Africa,which hasdone more than most to promote open borders and,via theCFA franc,a common currency is the most integrated.Whereborders remain closed as between Algeria and Morocco since1994 all sides lose.Local content African resources have global importance,but investors still findit hard to place their money in these industries,despite countriespromoting local content initiatives that give a minimumpercentage of equity in oil fields to local companies.Nigeriahas developed a well-established network of indigenouscompanies operating across its oil industry.New upstreamlicences in Republic of Congo require 25%local content,usually around 10%for state-owned Societe Nationale desPetroles du Congo and the rest for local private companies;theymay lack the capital necessary to finance their share and couldcarry reputational risks from beneficial ownerships involvingpolitically exposed persons.South Africa needs huge uplift for a population that,nearly 30years on,is still waiting for its post-apartheid expectations ofsocial equity and economic advancement to be met.The blackeconomic empowerment industry has become associated withcrony capitalist ploys to enrich only a few.During Jacob Zumasfailed presidency,the once mighty state utility Eskom waspotentially fatally damaged by economic mismanagement andstate capture.Eventually even the Renewable Energy IPPProcurement Programme widely seen as a model for solar andwind procurement on the continent was endangered.Efforts to strengthen both national public sector structures andlocal business practices are essential if Africa is to attractanywhere near the necessary levels of financing to support14 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020Financiers see huge potential butbottlenecks frustrate as debt rises againHuge figures are bandied about for infrastructure costs and for the funds to support the carbon transition.Butwhile financiers have money for well-structured projects,a potential revolution in energy investment is held backby lack of capacity,moribund markets and governance shortfalls,while heavily indebted resource-dependenteconomies remain as vulnerable as ever to volatile global markets.Covid-19 will accentuate these weaknessesSectionsustainable growth.Among initiatives,the African LegalSupport Facility in Abidjan is working to strengthen publicsector entities such as the many all but insolvent public utilities,which make very weak counterparts for private sector investors,and governments that in negotiations are often confronted bybatteries of expensive international lawyers.The Chinese model of infrastructure financing has producedsome remarkable results,even if critics point to problemsassociated with the unexpectedly high cost of financing linkedto asset-backed deals,the employment of Chinese personnelover local workers,and major operations and maintenanceshortfalls.Its 85-15 model involves China putting up 85%of aprojects cost in supposedly soft loans backed by Chineseinsurers.Often linked to exports of oil or minerals to feed hugeChinese demand,these structures have allowed cash-strappedeconomies like Guinea to build infrastructure that mightotherwise prove impossible.Debt distress This model,too,is showing strains as the Chinese state andcorporates look to place projects on a more commercial basis.As payments arrears have built up across sub-Saharan Africa,AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 15InfrastructureConsortiumfor Africa(ICA)$9,180m(38%)West Africa$14.13bn(34%)excludingSouth AfricaNorth Africa$7.69bn(18%)Central Africa$3.51bn(8%)East Africa$3.39bn(8%)SouthernAfrica$4.62bn(11%)South Africa$7.88bn(19%)Other$0.74bn(2%)African nationalgovernments$7,486m(31%)China$477m(2%)Other bilaterals/multilaterals$4,428m(18%)Private$2,485m(10%)InfrastructureConsortiumfor Africa(ICA)$10,154m(23%)Africannationalgovernments$7,690m(18%)China$18,330m(42%)Other bilaterals/multilaterals$1,386m(3%)Private$6,282m(14%)ENERGY SECTOR FINANCINGBY SOURCE,2014ENERGY SECTOR FINANCINGBY SOURCE,2018TOTAL ENERGY SECTOR FINANCING BY REGION,2018(total:$43.84bn)African Energy 2020(www.africa-)Source:ICA,Annual Report 2018ICA members:African Development Bank(AfDB),Development Bank of Southern Africa(DBSA),European Commission(EC),European Investment Bank(EIB),World Bank Group,G7 countries(Canada,France,Germany,Italy,Japan,UK,USA),Russian Federation,South Africa.Republic of Congos mid-2019 debt restructuring set aprecedent by involving the Chinese government in reschedulingan unsustainable debt.Nearly a quarter of Kenyas total externaldebt is now owed to China much of it linked to thecontroversial standard gauge railway scheme on terms thathave proved more onerous than expected at the time loans werepublicly signed.What is certain is that interest rates are higherand maturities shorter on Chinese debt than the terms offeredby the World Bank and AfDB.The International Monetary Fund has expressed increasingconcern that levels of debt distress are again rising across thecontinent.Chinese loans are most often cited as a cause,butAfrican treasuries have built up a range of debt from sovereignbonds to domestic paper.Earlier in the decade,a return toborrowing via bond markets was seen as a signal of renewedstrength;some borrowers,including Ghana and Gabon,are evennow still talking about new Eurobonds.But the mood of debtmarkets is generally depressed,despite the temptations ofglobally low interest rates.Another oil price crash has the potential to cause havoc inresources producers.The 2016 deal between Opec and non-Opec countries helped to stabilise prices and improveproducers finances.However,this unravelled dramatically asSaudi Arabia and Russia fell out in March 2020 over how toaccommodate US shale production and their own ambitions todominate the market.In a bid to arrest a dramatic price collapseand stabilise global markets,producers were obliged to agree thebiggest oil production cuts in history.While apparently good news for oil importers,lower prices alsohave ramifications for other natural resources producers,givenuncertain global growth and declining commodity demand.Like junior and independent oil companies,publicly listedmining companies face a difficult outlook.Many of these playersanyway face longer-term problems in a world looking to tackleclimate change by transiting out of carbon.While manyproducer governments are still in denial,their prized oil andcoal reserves may never be developed(and certainly not on theterms some still demand).Many will be left with stranded assets.7(highest risk)654321(lowest risk:no African countries)POLITICAL RISKRATINGS,MARCH2020Medium/long-termpolitical risk ratings forAfrican countries?exporttransactions underthe OECD consensusSource: African Energy 2020(www.africa-)Regional groupingsG5 SahelMano River Union(MRU)Gulf of GuineaCommission(GCC)/Commission du Golfede Guin?e(CGG)Commission ofCentral African Forests/Commission des For?tsd?Afrique Centrale(Comifac)Eastern AfricaStandby Force(EASF)Southern AfricanCustoms Union(Sacu)Liptako-GourmaAuthority(LGA)/Autorit?du Liptako-Gourma(ALG)International Conferenceon the Great Lakes Region(ICGLR)/Conf?renceInternationale sur la R?giondes Grands Lacs(CIRGL)Economic Community of the Great Lakes Countries(ECGLC)/Communaut?conomique des Pays des Grands Lacs(CEPGL)Controls Sinelac(Soci?t?International d?Electricit?des paysdes Grands Lacs)Niger Basin Authority(NBA)/Autorit?duBassin du Niger(ABN)Lake TanganyikaAuthority(LTA)/Autorit?du LacTanganyika(ALT)Tripartite Permanent TechnicalCommission(TPTC)Permanent Okavango River BasinWater Commission(Okacom)Organisation for theDevelopment of theSenegal River(OMVS)Lake Victoria Basin Commission(LVBC)Orange-Senqu River Commission(Orasecom)Lake Chad BasinCommission(LCBC)/Commission du bassindu Lac Tchad(CBLT)Congo-Oubangui-SanghaBasin Commission/Commission Internationaledu Bassin Congo-Oubangui-Sangha(CICOS)Nile Basin Initiative(NBI)Nile River Basin CooperativeFramework Agreement(CFA)Volta Basin Authority(VBA)Gambia RiverBasin DevelopmentOrganization(OMVG)Limpopo Watercourse Commission(Limcom)Zambezi Watercourse Commission(Zamcom)African Union(AU)Community of Sahel-Saharan States(CEN-SAD)/Communaut?des EtatsSah?lo-SahariensEast AfricanCommunity(EAC)A B CArab Maghreb Union(AMU)/Union duMaghreb Arabe(UMA)Southern AfricanDevelopment Community(SADC)Intergovernmental Authorityon Development(Igad)AEconomic Communityof West African States(Ecowas)/Communaut?Economique des Etatsde l?Afrique de l?Ouest(CEDEAO)Common Market for Easternand Southern Africa(Comesa)Economic Community ofCentral African States(ECCAS)/Communaut?Economique desEtats de l?Afrique Centrale(CEEAC)AA B DA EFor Africa?s monetary groupings,see page 17;for regional power pools,see page 21 African Energy 2020(www.africa-)THE AFRICAN UNION AND REGIONAL ECONOMIC COMMUNITIES(RECs)RECOGNISED BY THE AUOTHER ECONOMIC,SECURITY AND ENVIRONMENTAL ORGANISATIONSRIVER AND LAKE ORGANISATIONSSADCapplicantEcowasapplicantEcowasassociatememberLCBCobserverstatusLCBC non-participantNBIobserverCo-opted membersStatus of regional integration in each REC:A Free trade area establishedB Customs unionC Single marketD All countries in the REC have applied the protocol on freedom of movementE Economic and monetary unionSource:AfDB,AUC&ECA,African Statistical Yearbook 201916 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020Economic AfricaTHEGAMBIA Western Sahara (under UNmandate)COMOROSERITREAETHIOPIAGUINEALIBERIAS?O TOM?&PRNCIPEBURUNDIR?union(Fr.)Mayotte(Fr.)MOROCCOMALI GUINEA-BISSAUBURKINAFASOREP.OFCONGO(BRAZZAVILLE)Cabinda(Ang.)C?TED?IVOIRESOUTHSUDANTUNISIAEGYPTGHANANIGERIAUGANDATANZANIANAMIBIABOTSWANAMOZAMBIQUEESWATININIGERSENEGALBENINSOUTHAFRICACAPEVERDESIERRALEONEDJIBOUTIZIMBABWEMALAWIKENYAZAMBIAANGOLALESOTHOSOMALIASEYCHELLESLIBYARWANDAALGERIASUDANCHADGABONEQ.GUINEACENTRALAFR.REP.DEM.REP.OF CONGOMAURITANIAMADAGASCARMAURITIUSTOGOCAMEROONDakar:Banque Centrale des Etats del?Afrique de l?Ouest(BCEAO)(UEMOA?s central bank)Association of AfricanCentral Banks(AACB)/Association des BanquesCentrales Africaines(ABCA)Abidjan:African Development Bank(AfDB)Bourse R?gionale desValeurs Mobili?res(BRVM)Quatre Bornes:HQ of Indian OceanCommission(IOC)/Commission del?Oc?an Indien(COI)Addis Ababa:AU CommissionPretoria:African Tax Administration Forum(ATAF)Development Bank of Southern Africa(DBSA)Abuja:HQ of Economic Communityof West African States(Ecowas)/Communaut?Economique des Etatsde l?Afrique de l?Ouest(CEDEAO)Arusha:HQ of East AfricanCommunity(EAC)Lusaka:HQ of Common Market for Easternand Southern Africa(Comesa)Rabat:HQ of Arab MaghrebUnion(AMU)/Union du MaghrebArabe(UMA)Gaborone:HQ of Southern AfricanDevelopment Community(SADC)Windhoek:HQ of SouthernAfrican CustomsUnion(Sacu)Cairo:HQ of League of Arab States/Arab LeagueAfrican Export-Import Bank(Afreximbank)Libreville:HQ of EconomicCommunity ofCentral AfricanStates(ECCAS)/Communaut?Economique des?tats de l?AfriqueCentrale(CEEAC)Djibouti Ville:HQ of IntergovernmentalAuthority on Development(Igad)Nairobi:AfricanTrade Insurance AgencyKhartoum:Arab Bank forEconomicDevelopmentin Africa(BADEA)Kampala:East African Development BankJohannesburg:Pan-African InfrastructureDevelopment Fund(PAIDF)Midrand:Pan-African Parliament(PAP)Nepad(New Partnership forAfrica?s Development)Planningand Coordinating AgencyBujumbura:PTA(PreferentialTrade Area)Bank(the financial armof Comesa)Lom?:West AfricanDevelopment Bank(WADB)/BanqueOuest Africaine deD?veloppement(BOAD)Ecowas Bank forInvestment andDevelopment(EBID)/Banque d?Investissementet de D?veloppement dela CEDEAO(BIDC)HQ of EcobankYaound?:Banque des?tats de l?Afrique Centrale(BEAC)(Cemac?s central bank)Lagos:HQ of AFCHQ of United Bank for Africa(UBA)Casablanca:HQ of Africa50Infrastructure FundDouala:Bourse R?gionale desValeurs Mobili?resd?Afrique Centrale(BVMAC)Sub-SaharanAfrica(SSA)MiddleEast&NorthAfrica(MENA)Cemac UEMOA=CFA Franc ZoneFrance CFA Franc Zone Comoros=Franc ZoneCemac isknown in Englishas the Economicand MonetaryCommunity ofCentral AfricaUEMOA is known inEnglish as the WestAfrican Economic andMonetary Union(WAEMU)NAMENAMEMembers of Africa Finance Corporation(AFC)Stock exchangesMembers of Bourse R?gionale desValeurs Mobili?res(BRVM)Members of Bourse R?gionale desValeurs Mobili?res d?AfriqueCentrale(BVMAC)Members of the Franc ZoneMembers of the West AfricanMonetary Zone(WAMZ)Members of theCommon Monetary Area(CMA)/MultilateralMonetary Area(MMA)NAMECHADS.SUDANNIGERIACAMEROONREP.OF CONGOEQUAT.GUINEAGABONANGOLANAME?Sub-Saharan African oil exporters?(IMF category where net oil exports makeup at least 30%of total exports)Division betweenMiddle East&NorthAfrica(MENA)andSub-Saharan Africa:World BankInternationalMonetaryFund(IMF)AfricanDevelopmentBank(AfDB)regionsAfrica ContinentalFree Trade Area(AfCFTA):Ratifying partiesSigned but notratifiedCFA(Communaut?financi?re d?Afrique)Franc ZoneUnion Economique et Mon?taireOuest Africaine(UEMOA)Currency:eco(from mid-2020)Communaut?Economique etMon?tairede l?AfriqueCentrale(Cemac)North AfricaWestAfricaCentralAfricaEastAfricaSouthernAfricaCurrency:CentralAfrican CFA francSOVEREIGN RATINGSCountryMoody?s FitchAngolaB3BBotswanaA2CameroonB2BCongo,D.R.Caa1Congo,Rep.Caa2CCCC?te d?IvoireBa3B EgyptB2B EthiopiaB1BGabonCaa1CCCGhanaB3BKenyaB2B MauritiusBaa1MoroccoBa1BBBMozambiqueCaa3CCCNamibiaBa1BBNigeriaB2BRwandaB2B SenegalBa3South AfricaBa1BBTanzaniaB1TunisiaB2B UgandaB2B ZambiaCaCCCLong-term issuer ratings,April 2020Source:ratings agencies African Energy 2020(www.africa-)ALL AFRICA AND REGIONS:201820192020SELECTED INDICATORS2017est.proj.proj.Real GDP3.63.54.04.1North Africa4.94.34.44.3West Africa2.73.33.63.6Central Africa1.12.23.63.5East Africa5.95.75.96.1Southern Africa1.61.22.22.8Consumer price inflation*12.610.99.28.1North Africa14.212.89.27.4West Africa13.09.59.79.1Central Africa9.37.34.74.1East Africa14.014.512.511.4Southern Africa9.37.47.16.6Overall fiscal balance*5.84.54.03.7North Africa9.66.04.84.1West Africa5.04.23.93.9Central Africa3.01.41.00.3East Africa3.84.13.73.5Southern Africa4.54.14.24.1External current account*3.63.02.83.0North Africa7.45.75.05.0West Africa0.20.40.10.2Central Africa4.32.01.01.3East Africa5.04.94.64.6Southern Africa2.12.93.03.3Fiscal balance is government income minus spending*annual average.*including grants.Source:AfDB,OECD&UNDP,African Economic Outlook 2019Annual%growth%of GDPSUB-SAHARAN AFRICA:20192020SELECTED INDICATORS20172018proj.proj.Real GDP3.03.23.23.6 Oil exporting countries0.51.52.12.5excluding Nigeria0.20.21.52.4 Oil importing countries4.54.33.94.3excluding South Africa6.16.05.45.6 Middle-income countries2.02.32.52.8 Low-income countries*7.06.76.16.4 Countries in fragile situations3.94.74.25.2Consumer price inflation*10.98.58.48.0Fiscal balance(incl.grants)4.63.74.34.3External current account2.32.73.63.8Reserves(months of imports)5.04.94.74.6*excluding low-income countries in fragile situations.*annual average.Source:IMF,Regional Economic Outlook,Sub-Saharan Africa,Oct 2019Annual%growth%ofGDPAFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 17Economic indicators by country20101040020100202030401214161820222010 121416182022Gross domestic product Constant prices(real GDP),percentage change on previous yearConsumer price inflation Percentage change on previous yearCurrent account balance Percentage of GDP20101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202266.7124.736.478.454.454.263.527.636.853.064.019.120.6ALGERIAGDP:$681.4bnPopulation:43.4mNORTH OF THE SAHARASUB-SAHARAN AFRICAEGYPTGDP:$1,391.3bnPopulation:99.2mLIBYAGDP:$61.6bnPopulation:6.6mMOROCCOGDP:$328.7bnPopulation:35.6mTUNISIAGDP:$149.2bnPopulation:11.8mANGOLAGDP:$203.4bnPopulation:30.1mBENINGDP:$40.7bnPopulation:11.8mBOTSWANAGDP:$44.1bnPopulation:2.4mBURKINA FASOGDP:$42.2bnPopulation:20.3mBURUNDIGDP:$8.4bnPopulation:11.5mCAMEROONGDP:$100.9bnPopulation:25.5mCAPE VERDEGDP:$4.3bnPopulation:0.56mCENTRAL AFRICAN REPUBLICGDP:$4.3bnPop:5.2mCHADGDP:$31.8bnPopulation:12.8mCOMOROSGDP:$2.4bnPopulation:0.87mDEMOCRATIC REP.OF CONGOGDP:$83.1bnPop:97.9mREP.OF CONGO(Brazzaville)GDP:$32.8bnPopulation:4.6mC?TE D?IVOIREGDP:$117.1bnPopulation:26.3mDJIBOUTIGDP:$6.0bnPopulation:1.1mEQUATORIAL GUINEAGDP:$29.0bnPopulation:1.4mERITREAGDP:$6.5bnPopulation:6.2mETHIOPIAGDP:$12.4bnPopulation:1.1mGDP:$240.2bnPopulation:95.6mGABONGDP:$39.6bnPopulation:2.1mTHE GAMBIAGDP:$6.4bnPopulation:2.3mGHANAGDP:$209.8bnPopulation:30.2mGUINEAGDP:$33.3bnPopulation:13.6mGDP figures are based on purchasing-power-parity(PPP)valuation ofthe country?s GDP,measured in current international dollars.GDP and population figures are for 2019.Some data are IMF estimates,including most data for 2018 and beyond.Source:Iinternational Monetary Fund,World Economic Outlook Database,October 2019ESWATINI18 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020Section20101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202220101040020100202030401214161820222010 12141618202252.4161.870.320.565.02015:52.82016:379.82017:187.92018:83.5No data prior to:2012(GDP,inflation)2011(current account)*Source:AfDB Statistical Yearbook 2019No data prior to 2013No inflation data,no GDP data prior to 201239.52018:63.32019:50.42020:62.12021:67.22022:67.649.72019:58.02020:66.72021:62.92022:75.6African Energy 2020(www.africa-)GUINEA-BISSAUGDP:$3.6bnPopulation:1.8mKENYAGDP:$191.3bnPopulation:49.4mLESOTHOGDP:$7.4bnPopulation:2.0mLIBERIAGDP:$6.5bnPopulation:4.6mMADAGASCARGDP:$46.0bnPopulation:27.1mMALAWIGDP:$25.2bnPopulation:20.3mMALIGDP:$47.2bnPopulation:19.1mMAURITANIAGDP:$19.8bnPopulation:4.1mMAURITIUSGDP:$31.7bnPopulation:1.3mMOZAMBIQUEGDP:$40.6bnPopulation:31.2mNAMIBIAGDP:$27.7bnPopulation:2.5mNIGERGDP:$25.8bnPopulation:23.3mNIGERIAGDP:$1,216.8bnPopulation:201.0mRWANDAGDP:$30.3bnPopulation:12.4mGDP:$0.75bnPopulation:0.22mSENEGALGDP:$64.6bnPopulation:16.8mSEYCHELLESGDP:$3.1bnPopulation:0.10mSIERRA LEONEGDP:$13.1bnPopulation:7.7mSOMALIAGDP:$12.7bnPopulation:15.6m*SOUTH AFRICAGDP:$809.0bnPopulation:58.8mSOUTH SUDANGDP:$21.4bnPop:13.4mSUDANGDP:$176.0bnPopulation:43.2mTANZANIAGDP:$191.6bnPopulation:56.3mTOGOGDP:$15.0bnPopulation:8.2mUGANDAGDP:$104.8bnPopulation:39.8mZAMBIAGDP:$76.0bnPopulation:18.3mZIMBABWEGDP:$40.3bnPopulation:14.9mSouth Sudan 7.9%Rwanda 7.8%C?te d?Ivoire 7.5%Ghana 7.5%Ethiopia 7.4%TOP ANDBOTTOM FIVECOUNTRIES,2019Real GDPgrowth%changeAngola 0.3%Sudan 2.6%Equatorial Guinea 4.6%Zimbabwe 7.1%Libya 19.1%Consumerpriceinflation%changeCurrentaccountbalance%of GDPZimbabwe 161.8%Sudan 50.4%South Sudan 24.5%Liberia 22.2%Angola 17.2%Mali 0.17nin 0.28%Niger 1.35%Guinea-Bissau 2.58%Eritrea 27.6%Eritrea 11.3%Republic of Congo 6.8%eSwatini 2.5%South Sudan 2.3%Angola 0.9%Seychelles 16.7%Niger 20.0%Guinea 20.7%Liberia 21.2%Mozambique 58.0%S?O TOM?&PRNCIPEAFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 19Key trends:Reserves,production,consumption&exportsAlgeriaLibyaNigeriaSpain 16.6Italy 16.3Italy 4.3France 4.0,Spain 1.5India 4.0China 1.5Japan 2.1Pakistan 1.3Thailand 1.3Spain 4.1France 3.6Zimbabwe502South Africa 9,893Botswana?s coal reservesare estimated to be approx.200bn tonnes(Sources:Botswana Ministry ofMinerals,Energy&WaterResources;US Chamberof Commerce)Significant coaldeposits in Teteprovince,andpotentially a similaramount in NiassaMexico 1.4Turkey 2.2Egypt 3.3Algeria 12.2Angola 8.4Rep.of Congo(Brazzaville)1.6Equatorial Guinea 1.1Gabon 2.0Libya 48.4Nigeria37.5Sudan 1.5Chad 1.5SouthSudan3.5Uganda1.7AngolaIndia 2.2NorthAfricaWestAfricaEast&SouthernAfricaCanadaCentral&SouthAmericaAustralasiaChinaEuropeUnitedStatesOther Asia-Pacific(incl.Japan&Singapore)IndiaMiddle EastTurkey 4.7Egypt 2.1Algeria 4.3Libya 1.4Nigeria 5.313.78.26.5Technicallyrecoverableshale gasresourcesRecent discoveriesoffshore Tanzaniaand Mozambiquetotal at least 6 tcm,according toindustry estimatesPipelineLNG020406080100120140160180200220240260280300320340360380400420440460480500020406080100120140160180200020406080100120140160020406080100120220020406080100140020406080100120140160180200200004060810121416181802000040608101214161820000406081012141618200004060810121416182000040608101214161820000406081012141618Rest of AfricaChadSouth SudanSudanGabonRep.of CongoEquat.GuineaEgyptLibyaAlgeriaAngolaNigeriaRest of AfricaLibyaEgyptNigeriaAlgeriaRest of AfricaSouth AfricaRest of AfricaEgyptAlgeriaSouth AfricaRest of AfricaSouth AfricaRest of AfricaEgyptAlgeriaSouth AfricaMorocco1.116.82.563.158.39.516.18.24.471.927.611.34.02.11.21.41.22.07.9PROVED OIL RESERVES,end-2018Billion barrelsTotal:125.3bn bbls(7.2%of world reserves)Countries with proved reserves ofmore than 1bn bbls:African Energy 2020(www.africa-)Sources:BP Statistical Review of World Energy,June 2019;US Energy Information Administration(2011),World Shale Gas Resources:An Initial AssessmentPROVED NATURAL GAS RESERVES,end-2018 Trillion cubic metresTotal:14.4 tcm(7.3%of world reserves)Countries with proved reserves ofmore than 1 tcm:PROVED COAL RESERVES,end-2018Million tonnesTotal:13,217m tonnes(1.2%of world reserves)Countries with proved reserves ofmore than 500m tonnes:HYDROELECTRIC POWER CONSUMPTION2000 total:17.0m tonnes oil equivalent(2.8%of world)2018 total:30.1m toe(3.2%of world)NUCLEAR POWER CONSUMPTION2000 total:2.9m toe(0.5%of world)2018 total:2.5m toe(0.4%of world)OIL PRODUCTION Million tonnes2000 total:371.6m tonnes/7,789 thousandbarrels/day(10.4%of world production)2018 total:388.7m tonnes/8,193 thousandbarrels/day(8.7%of world production)GAS PRODUCTION Million tonnes oil equivalent2000 total:116.2m toe/135.1 billion cubic metres(5.6%of world production)2018 total:203.4m toe/236.6 billion cubic metres(6.1%of world production)COAL PRODUCTION Million tonnes oil equivalent2000 total:130.5m toe(5.7%of world production)2018 total:155.8m toe(4.0%of world production)COAL CONSUMPTION Million tonnes oil equivalent2000 total:82.8m toe(3.5%of world consumption)2018 total:101.4m toe(2.7%of world consumption)GAS CONSUMPTION Million tonnes oil equivalent2000 total:47.9m toe/55.7 billion cubic metres(2.3%of world consumption)2018 total:129.0m toe/150.0 billion cubic metres(3.9%of world consumption)OIL CONSUMPTION Million tonnes oil equivalent2000 total:122.2m toe/2,465 thousandbarrels/day(3.2%of world consumption)2018 total:191.3m tonnes/3,959 thousandbarrels/day(4.1%of world consumption)GAS FROM AFRICA,2018 Billion cubic metresMovements of more than 1 bcm:CRUDE OIL FROM AFRICA,2018 Million tonnesMovements of more than 1m tonnes:20 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020PowerHarare:HQ of SAPPBrazzaville:HQ of CAPP/PEACAddis Ababa:HQ of EAPPCotonou:HQ ofWAPP/EEEOAAbidjan:Association of Power Utilities of Africa(APUA)/Association des Soci?t?s d?Electricit?d?Afrique(ASEA)Algiers:African EnergyCommission(Afrec)/Commission Africainede l?Energie(CAE)ComelecHQrotatesbetweenmemberstatesMaghreb ElectricityCommittee/Comit?Maghr?bin del?Electricit?(Comelec)Southern AfricanPower Pool(SAPP)Central AfricanPower Pool(CAPP)/Pool Energ?tiquede l?AfriqueCentrale(PEAC)West African PowerPool(WAPP)/Syst?me d?Echangesd?Energie ElectriqueOuest Africain(EEEOA)Eastern Africa PowerPool(EAPP)BotswanaPowerCorporation(BPC)Soci?t?Nationaled?Electricit?(Snel)Lesotho Electricity Company(LEC)Electricidade de Mo?ambique(EDM),Hidroel?ctrica de Cahora Bassa(HCB)Egenco,EscomNamPowerEskomEswatini Electricity Company(EEC)Tanzania Electric SupplyCompany(Tanesco)ZescoZimbabweElectricity SupplyAuthority(Zesa)Soci?t?Nationale del?Electricit?et du Gaz(Sonelgaz)Office Nationalde l?Electricit?etde l?Eau Potable(ONEE)Soci?t?Tunisienne del?Electricit?et du Gaz(Steg)General ElectricityCompany of Libya(Gecol)Egyptian ElectricityHolding Company(EEHC),Egyptian ElectricityTransmissionCompany(EETC)Soci?t?Mauritanienned?Electricit?(Somelec)SonabelCEB:Communaut?Electrique du B?ninCEET:Compagnie Energie Electrique du TogoCIE:Compagnie Ivoirienne d?Electricit?CI-Energies:Soci?t?des Energies de C?te d?IvoireE2C:Energie Electrique du CongoEAGB:Empresa Publica de Electricidade e Agua de Guin?-BissauECG:Electricity Company of GhanaEDG:Electricit?de Guin?eEDSA:Electricity Distribution and Supply AuthorityEgenco:Electricity Generation CompanyEGTC:Electricity Generation and Transmission CompanyEMAE:Empresa de Agua e ElectricidadeENDE:Empresa Nacional de Distribui?o de ElectricidadeEscom:Electricity Supply Corporation of MalawiGamek:Gabinete de Aproveitamento do M?dio KwanzaGRIDCo:Ghana Grid CompanyLEC:Liberia Electricity CorporationNawec:National Water and Electricity Company of GambiaNEDCo:Northern Electricity Distribution CompanyNBET:Nigerian Bulk Electricity Trading PLCProdel:Empresa P?blica de Produ?o de ElectricidadeSBEE:Soci?t?B?ninoise d?Energie ElectriqueSEEG:Soci?t?d?Electricit?et d?Eaux du GabonSegesa:Sociedad de Electricidad de Guinea EcuatorialSenelec:Soci?t?Nationale d?Electricit?du S?n?galSonabel:Soci?t?Nationale d?Electricit?du BurkinaTCN:Transmission Company of NigeriaVRA:Volta River AuthorityElectraCI-Energies,CIENawecEDGEAGBLECEnergiedu Mali(EDM)ECG,GRIDCo,NEDCo&VRACEETSBEE&CEB NBET,TCNSenelecEDSA,EGTCSoci?t?Nig?rienned?Electricit?(Nigelec)RegidesoEthiopian ElectricPower(EEP)Kenyan Electricity Generating Company(Kengen),Kenya Electricity Transmission Company(Ketraco),Kenya PowerRwanda Energy Group(REG)MDEC,SEDC,Setco,SHGC,STPG UEGCL,UETCL,UmemeJiro sy Rano Malagasy(Jirama)CentralElectricityBoard(CEB)PublicUtilitiesCorporation(PUC)Madji na Mwendje ya Komor(MA-MWE),Electricit?d?Anjouan(EDA)Nugal ElectricalCo-operative(NEC)Electricit?deDjibouti(EDD)Eritrean ElectricCorporation(EEC)South SudanElectricityCorporation(SSEC)Soci?t?Nationaled?Electricit?(SNE)E2CEnergieCentrafricaine(Enerca)EneoCameroonSEEGEMAESegesa ENDE,Gamek,Prodel,RedeNacional deTransporte deElectricidade(RNT)MDEC:Merowe Dam Electricity CompanyRegideso:R?gie de Production et de Distributiond?Eau et d?Electricit?SEDC:Sudanese Electricity Distribution CompanySHGC:Sudanese Hydro Power Generation CompanySetco:Sudanese Electricity Transmission CompanySTPG:Sudanese Thermal Power Generation CompanyUEGCL:Uganda Electricity Generation Company Ltd.UETCL:Uganda Electricity Transmission Company Ltd.PotentialmembersNATIONAL POWERCOMPANIESREGIONAL POWER POOLSWithdrew fromEAPP Feb 2016AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 2122 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020TrendsAnumber of energy transitions have begun to move frommarket buzz to on-the-ground activity at a notable scale.The changes are throwing up new challenges thatindicate the next transitions on the continent,as governmentslook for ways around payment guarantees and find that the onlysolutions are sustainable utilities or more open markets,whilework on regional trading is starting to make this more possible.Africas transitions cannot be seen in isolation.The change of focusfrom generation to transmission and distribution comes as severalcountries find that they no longer have a shortage of supply butof demand.Weak grids,high losses,low access and consumption,and expensive power continue to suppress markets.Ghana claimsto have excess supply,but in December 2019,off-grid generatorGenser Energy raised$366m to build a large gas pipeline networkto supply its expanding captive power plants.These plants supplypower to mines that are connected to the grid but whose qualityof supply is so poor they are looking elsewhere.Kenya faces asimilar situation where supply appears to have outstripped demandat the same time as per capita electricity consumption is belowthe African average and off-grid solar home systems are installedbeneath Kenya Powers distribution lines.One solution has been to invest in transmission and distribution.Kenyas last-mile connection programme has increased accesswhile a transmission line to the west of the country currentlysupplied by Uganda is expected to end the supply surplus.Private investment in transmission is being seriously explored inthe country by both the World Bank Groups InternationalFinance Corporation and the Africa50 infrastructure fund.Atthe same time,interconnections are being planned or built acrossEast Africa that will increase the potential market and helpcountries balance demand and supply without suppressinginvestment or demand or drastically increasing the cost of power.Solar progressSolar power is proving an increasingly useful technology for Africa.Prices have come down to the extent that solar can be used todisplace most fossil fuels,reducing Africas foreign exchangeexposure.Solar systems can be small and can be located close todemand or where the grid is best able to evacuate the power.Requiring limited logistics,solar is very suitable for small andpoorer countries.It can be used off-grid or hybridised withthermal plants to reduce costs or hydropower plants to helpmanage water levels.There are also abundant funding options andnumerous developers,while the industry is helped by a very lowconstruction failure rate and a track record of generally limitedconstruction delays and cost over-runs.This has made solar poweran easy decision for African governments.Africas multiple energy transitions startto bear fruitThe many energy transitions slowly taking place in Africa have begun to make an impact on the ground.As wellas the move to lower carbon generation,these include transitions to private financing of the power sector,to afocus on transmission and distribution,and to a mix of grid and isolated systemsNatural gas 65,671MW 28.9%Liquid fuels 18,786MW8.3%Natural gas&liquid fuels 43,583MW19.2%Coal 49,110MW 21.6%Nuclear 1,815MW0.8%Hydroelectricity 35,886MW15.8%Solar 5,415MW 2.4%Wind 5,581MW 2.5%Geothermal 831MW 0.4%Biomass/biogas 130MW 0.06%Other 220MW 0.1%Natural gas 27,330MW 19.8%Liquid fuels10,714MW 7.8%Natural gas&liquid fuels28,766MW 20.9%Coal 41,898MW 30.4%Nuclear 1,815MW1.3%Hydroelectricity 25,877MW18.8%Solar 28MW 0.02%Wind 973MW 0.7%Geothermal 207MW 0.2%Biomass/biogas 9MW 0.007%Other 104MW 0.1%Source:African Energy Live Data African Energy 2020(www.africa-)AFRICA?S ON-GRID ENERGY MIX,Q1 2020Total:227,028MWSource:African Energy Live Data African Energy 2020(www.africa-)AFRICA?S ON-GRID ENERGY MIX,2010Total:137,721MWAn increasing number of intermittent generation plants as wellas weak grids have resulted in the first utility-scale batteryprojects being contemplated.Morocco has made major strideswith recent procurements of large solar and battery systems.South Africas Eskom is considering a major programme andpotential developers showed strong interest in storage in a recentrequest for information looking for short-term options tomitigate the countrys power crisis.Senegal is investigating alarge battery project and recently brought online its first utility-scale renewable power and battery plant.Countries likeNamibia are looking at battery systems and there are alsoproposals in Kenya.A number of renewable energy-plus-batteryprojects are being considered in smaller countries wherenetworks are unable to handle intermittent energy.SectionMarket movesCheap renewables have also started to provide a spur for thenascent development of markets.In Namibia,the modifiedsingle buyer model is largely based on solar power,which ischeap enough to make it attractive to purchase as an alternativeto the grid.The decision to develop solar and wind projects asIPPs in South Africa has combined with the financial crisis atEskom to push the government towards sector unbundling.The need to account for the system cost of renewables whichresult in other plants being used less frequently and thereforebecoming more expensive is pushing countries like Namibiaand Kenya to introduce more clarity into their tariffs and powerpurchase agreements about the various costs involved insupplying power.This,in turn,is creating the potential for newmarkets for power grid services.The transition to private sector development alongside thegreater use of renewable power is having a clear impact H12019 saw the lowest additions of new generation capacity innearly a decade.This is partly the result of insufficient griddemand in key markets.Another factor is that,althoughgovernment policy has switched to privately financedgeneration,weak utility finances and limited policyimplementation mean that,while new state utility-built capacityhas declined in many countries,private investment has notincreased sufficiently to plug the gap.This is a marked change from previous years.For the first timemore generation capacity was added by the private sector thanby state utilities(1.5GW v 1.2GW)in H1 2019,according toAfrican Energy Live Data.In the whole of 2018,14.2GW wasadded by state utilities compared with 3.1GW by the privatesector.The difference was even more dramatic in 2017,withonly 1.4GW added by the private sector but 11.6GW by thestate.The shift to solar was clear as more solar capacity was addedthan any other technology in H1 2019,with 917MW.The increase in private capacity coupled with the weakness ofutilities and increasing levels of government debt has resulted inseveral larger governments questioning support given to IPPs.Most notable are larger countries like Ghana,Kenya,Nigeria andAFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 2310020106040200201120122013201420152016201720182019OtherBiomass/biogasGeothermalWindSolarHydroelectricityNuclearCoalNat.gas&liquid fuelsLiquid fuelsNatural gas African Energy 2020(www.africa-)ON-GRID GENERATION CAPACITY BY FUEL,201019Source:African Energy Live Data100%ofpopulation80604020020102011201220132014201520162017North AfricaWest AfricaCentral AfricaEast AfricaSouthern Africa African Energy 2020(www.africa-)ELECTRICITY ACCESS BY REGION,201017Sources:SEforALL,Tracking SDG7:The EnergyProgress Report 2019;UN Population DivisionSouth Africa.All four are looking for alternatives to governmentguarantees or support agreements.Kenya is again looking to diluteits letter of support which the government provides instead of apayment guarantee in light of the collapse of the Kinangopproject,when the government called in its letter of supportfollowing delays caused by land issues.Ghana has lashed out atprivate developers and is attempting to renegotiate tariffs andchange thermal capacity payments from take-or-pay to take-and-pay.South Africa is giving strong hints that it will not providegovernment guarantees for future IPP procurement and NigeriasTreasury has been reluctant to provide further guarantees since theAzura-Edo gas power project.Azura-Edo was Nigerias first fullyprivatised IPP to reach financial close in December 2015,but noIPPs have closed since then.Meanwhile,Ghana,Nigeria and South Africa are all strugglingwith the fallout of failed or inadequate reform policies,whichmakes ending government guarantees difficult.This wasepitomised in 2019 by the failed concessioning of the ElectricityCompany of Ghana,the catastrophic collapse of Eskom,and threatby the Nigerian Electricity Regulatory Commission to canceldistribution concessions as a result of failure to make minimumpayments to the Nigerian Bulk Electricity Trader.Both Ghana andSouth Africa are likely to require support from internationaldonors to resolve the financial crises facing their utilities.Other countries have emerged as more forward thinking.Zambia has engaged Africa GreenCo as a creditworthyintermediary offtaker between struggling utility Zesco and thecountrys IPPs.GreenCo will be able to supply industrialofftakers and ultimately the Southern Africa Power Pool in theevent of non-payment by Zesco,as well as having recourse toguarantee schemes from KfW and the African Trade InsuranceAgency.Namibia is looking to the domestic and then regionalmarket to reduce sector risk.NamPower is moving towards arole as generator of last resort and transmission and marketoperator with the establishment of the modified single buyermodel.Cte dIvoires cash waterfall mechanism,which sees theprivate utility operator CI-Energies,IPPs and gas suppliers paidbefore other expenses,continues to pay dividends after majorexpansions to the Ciprel and Azito gas power plants reachedfinancial close in early 2020.North AfricaThe shift from gas to renewables and the associatedcommercial challenges will directly affect both NorthAfricas wider energy sector and economic performancein general.Moroccos 2009 National Energy Strategy set a targetof 42%renewable power by 2020.Although this will not be met,it is close.According to African Energy Live Datas current snapshotof the project pipeline,just over 37%of power will be generatedby renewables by year-end,rising to just under 40%in 2021.By 2022,the target will be substantially exceeded.If mootedchanges go ahead to the 13-09 procurement law,under whichmost private sector wind and solar projects are being developed,a significant number of plants that currently do not have expectedcommissioning dates could improve the picture dramatically.Ahead of the COP22 climate change meeting in Marrakech in2016,Morocco added a further target of reaching 52%ofrenewables capacity by 2030.This will require an accelerationin renewables commissioning to keep pace with a new wave ofgas-fired plants linked to long-term import plans and thedevelopment of domestic production.The Jorf Lasfar,DharDoum and Al-Wahda gas-fired plants(each expected to have1.2GW installed capacity),were originally planned for 2021 butalong with a regasification terminal have been postponed untilthe end of the decade.Similarly,no gas-fired power plants are expected to startconstruction in the rest of the region for the next several years.In Egypt,Cairo Electricity Production Companys 650MWCairo West extension project is expected to start production in2020.After that,no large-scale gas-fired plant is envisaged inthe current five-year plan to 2022.While some additional plantsare on the drawing board for the following five years,it is farfrom certain they will be built.By 2028,the Dabaa nuclear plantis expected to have added 4.8GW of baseload capacity.Additionally,there is no way of reliably divining how muchrenewable capacity may have been commissioned by that point.Part of the difficulty for Egyptian power sector planners is thatby end-2019 the system had achieved a reserve capacity of 83%,meaning there is no need to build more.The authorities areencouraging private sector offers for renewables projects buthave insisted on very low power purchase agreement(PPA)prices.The subtext is that developers and financers have to takewhat they are offered.The involvement of a large number of counterparties in themassive Benban solar park in southern Egypt,which was fullycommissioned in 2019,has created a diverse ecosystem of projectsponsors,consultants,financers,engineers and equipment24 AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020North Africa anticipates shift from gas torenewablesThe evolution of electric power generation in North Africa has reached a tipping point,with Morocco close tomeeting its first major renewable energy target and the end of a five-year trend of massive gas-fired powerprocurement across the regionsuppliers,all keen to embark on new schemes.Whether they willor not partly depends on how strictly the ministry sticks to itschallenging price requirements but also on other factors,such ashow rapidly inefficient thermal plants are decommissioned.Another huge strategic decision due in 2020 is the privatisationof one or more of the three 4.8GW gas-fired plants built bySiemens.Any new private sector owners will have to sign freshPPAs with Egyptian Electricity Transmission Company.Thegovernment may want a high sale price or a low PPA price.Thisdecision may affect what commercial terms apply elsewhere.Meanwhile,in Algeria,all of the 8GW of gas-fired power plantsthat Sonelgaz ordered from GE in 2013 were all still at variousstages of construction in early 2020,with most of themexpected to be completed by 2021,although more delays arepossible.After that,the development of further gas-firedgeneration is limited to the 1.3GW Umashe plant,whichHyundai Engineering&Construction is due to deliver in 2025.Based as it is on a questionable strategy of developing a domesticsolar panel construction industry,Algerias renewablesprogramme is in the doldrums.Tunisia is pushing ahead with wind and solar schemes but nonew gas-fired generation will be built once the combined-cyclegas turbine unit of the 450MW Rades C gas plant and the650MW Mornaguia plant are completed in 2020 and the450MW Skhira plant in 2021.Beleaguered Libya desperately needs more power generation butuntil the political and security environment improves it isstruggling to complete existing projects,while budget constraintsmean that finding finance for new projects is also hard.Natural gas 50,924MW47.1%Liquid fuels 4,409MW 4.1%Natural gas&liquid fuels38,659MW 35.8%Coal 3,767MW 3.5%Nuclear 15MW 0.01%Hydroelectricity 4,859MW4.5%Solar 2,556MW 2.4%Biomass/biogas 1MW 0.001%Other 167MW 0.2%Wind 2,656MW 2.5%Source:African Energy Live Data African Energy 2020(www.africa-)NORTH AFRICA?S ON-GRID ENERGY MIX,Q1 2020Total:108,013MWMoroccoWtGCGLSSSWWSGGHHHCGHHCHWWWSGLW WLSSSSSSSSSSSSSSSGWWWGHHHXHHHHHHHHHWWLHHWGLGHHHHHHHHHHHHHHHHWHCWWHHHGLWMOROCCOSPAINCanary Is.(Spain)Western Sahara(under UN mandate)MAUR.WesternSahara(under UNmandate)Canary Is.(Spain)MAURITANIAA L G E R I ATANGIERT?TOUANAL-HOCE?MAO R I E N TA LFS MEKNSSAL?BENI MELLALKH?NIFRASETTAT MARRAKECH SAFITA F I L A L E TS O U S S M A S S AG U E L M I M O U E D N O U NE L AY O U N S A K I A E L H A M R A CASABLANCARABATK?NITRAD R?A EL AYOUNSAKIAEL HAMRADAKHLAOUED EDDAHABRABATF?sOujdaNadorMelilla(Sp.)Al-Hoce?maTazaFiguigEl Ayoun(La?youne)TarfayaTan TanGuelmimSidi IfniAgadirEssaouiraSafiOuarzazateBeniMellalKhouribgaK?nitraT?touanGibraltar(UK)MohammediaElJadidaSmaraZagTiznitTaroudantTataZagoraJorfLasfarErfoudMissourBou?rfaTendraraDebdouJeradaTafraouteEr RachidiaTarifaKh?nifraOualiliBeniTajjiteBoudnibAssaTazenakhtMekn?sCasablancaMediounaChemaiaChichaouaBourdimCeuta(Sp.)TangerMedTangierMarrakech(Tensiftsubstations)TlemcenSidi AliBoussidiGhazouetAgdzMideltMatmataMsounGteterBeniHadifaOutat El HajEnjilBouananeBouizakarneBir LharOuezzaneTinghirSidiKacemBerrechidSettatKalla desSghragnaBeja?dKh?missetElHajebGuercifA?n BeniMatharLoukkosEl OualiBoujdourDakhlaLagouiraEl Ayoun(La?youne)00200100KilometresMiles1,000MW 100 999MW10 99MW3 9MWtttGGGNatural gasLiquid fuelsGas&liquid fuelsCoalThermal unknownHybridHydroelectricitySolar photvoltaic(except where marked CSP)WindBiomass/biogas400kV power line220kV power line60kV power lineConstructionPlannedLHSWOperatingLHSWLHSWC222CCXXX10000KmMiles200M E D I T E R R A N E A NS E AStraitofGibraltarMoulouyaTensiftDr?aDr?aOumerRbiaSebouAlbor?n(Sp.)A T L A N T I CO C E A NElAbidBethZaLanzaroteFuerteventuraA T L A N T I CO C E A N LALLATAKERKOUSTBIN EL OUIDANEBOUTFERDAABDELMOUMEN (STEP)HASSAN IMOULAYYOUSSEFAL-MASSIRAIMFOUTDAOURATNOOR ATLASNOORATLASNOOR ATLASNOORATLASNOORATLASNOOR ATLASNOOR PV II(gas-solar)BOUAREGMOHAMMED VASFALOUAL-WAHDAKASBAZIDANIAIFAHSA(STEP)IDRESS INOORTAFILALET(LAMAADID)NOORTAFILALET(MSOUNA)NOORTAFILALET(OULAD KHAOUA)ELKANSERAAIRPORTTIT MELLILOULED GHANEMAKHFENNIRIIIWWFOUMAL-OUEDCIMENTSDU MAROCMANSOURED DAHBIOULJETES SOLTANETAZABAB OUENDERAL-KOUDIA AL-BAIDA I,IIJEBELLAHDIDTALAMBOT123451 HAOUMA2 KHALLADI3Fardioua4Mellousa5 LAFARGE MAROC6 ALLAL EL FASSI7 VOLTALIA I8 M?DEZ EL MENZEL(STEP)9 VOLTALIA II10 TANAFNIT EL BORJKH?NIFRA COMPLEX:11 IMEZDILFANE12 TAJEMOUT13 TASKDERT14 AHMED EL HANSALI OUED ELMAKHAZINE6789101112131415161715 A?T MESSAOUD16 AFOURER(STEP)17 AFOURER18 TILOUGGUIT AVAL19 TILOUGGUIT AMONT20 MELLOUL I21 MELLOUL II22 MIDELT23 NOOR MIDELTCSP&PV,PHASE I24 NOOR MIDELTCSP&PV,PHASE II25 NOOR PV II26 MIDELTPLATINUM24SSWWWWPLATINUM POWERNOOR INOOR IIVOLTALIA IITISKRADVOLTALIA I23NOOR PV IINOOR PV IINOORPV II22NOOR PV IINOORPV IITAHADDARTWWWLYNNA BIO POWERTANGIER IITANGIER IHASSAN II25 261819 2021SSSSOUARZAZATE NOOR I CSPNOOR II CSPNOOR III CSPNOOR IVWWWPLATINUM POWERYNNA BIO POWERAMOUGDOULMAROC CHIMIEOUALIDIAtGCCOCPUNITS V-VIUNITS I-IVDHARDOUMSWSNOOR BOUJDOURWWFOUM AL-OUEDCIMENTS DU MAROCAFTISSATWLLHARMATTANSSWWWWPLATINUM POWERNOOR INOOR IIVOLTALIA IITISKRADVOLTALIA ICSP:concentrated solar powerGTP:gas-to-powerLNG:liquefied natural gasSTEP:station de transfert d?nergiepar pompage(pumped storage)150kV150kVGAZODUC PEDRO DURANFARRELL(GPDF)/GAZODUC MAGHREBEUROPE(GME)FROM HASSI R?MELFUTURE GASPIPELINES?150kVx2x2x2x2x2x2x2x2x2 African Energy 2020(www.africa-)Former Spanish Sahara underUN mandate pending finaldecolonisation;sovereigntycontested by Morocco andPolisario Front.Algerian-Moroccan border not ratifiedsouth of Figuig.AFRICAN ENERGY ATLAS 2020/2021 APRIL 2020 25Capacity(MW)9,8381,0333,350Plants/projectsOperatingConstructionPlanned*Source:African Energy Live Data,April 2020.www.africa- with a planned commercial operation date of 2025 or earlier.Sources:SEforALL;IMFAccess to electricity(2017,millions)Population 34.85Those with access34.85%with access100AlgeriaWSXGGGGGSXLGLLLGGGSSSGXLXLXSL2GGLL2GSSGSGSGSGGGGGGSGHGHGXGSSSSSSGGSSSGGGGGGGG GSGGG GSGHHHHGGG GGGSGG GXLGM A L IM O R O C C OL I B Y AALGERIAN I G E RM O R O CCOTUNISIAT U N I S I 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