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EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)
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EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)

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EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)

EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC)

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  • 1. EASTERN AFRICA POWER POOL (EAPP) AND EAST AFRICAN COMMUNITY (EAC) REGIONAL POWER SYSTEM MASTER PLAN AND GRID CODE STUDY FINAL MASTER PLAN REPORT VOLUME I 01 -Introduction 02 -Demand Forecast (WBS 1100) 03 -Generation Supply Study & Planning Criteria (WBS 1200) 04 -Supply-Demand Analysis & Project Identification (WBS 1300) May 2011 SNC LAVALIN INTERNATIONAL INC. in association with PARSONS BRINCKERHOFF
  • 2. PREFACE  The  objective  of  the  present  study  is  to  identify  regional  power  generation  and  interconnection  projects  in  the  power  systems  of  EAPP  and  EAC  member  countries  in  the  short‐to‐long  term.  The  study also aims at developing a common Grid Code (Interconnection Code) in order to facilitate the  integrated development and operations of the power systems of the member countries.    The  study  further  aims  at  contributing  to  the  institutional  capacity  building  for  the  EAPP  and  EAC  through training of counterpart staff. The development of institutional capacity will enable EAPP/EAC  to  implement  the  subsequent  activities,  including  the  updating  of  both  the  Master  Plan  and  the  Interconnection Code.  This  study  covers  the  following  countries  in  alphabetical  order:  Burundi,  Djibouti,  Democratic  Republic of Congo, Egypt, Ethiopia, Kenya, Rwanda, Sudan, Tanzania and Uganda.  The Master Plan Report has been organized according to the following structure:  Volume  Section  Executive Summary    Volume I  01 – Introduction  02 ‐ Demand Forecast (wbs 1100)  03 ‐ Generation Supply Study & Planning Criteria (wbs 1200)  04 ‐ Supply‐Demand Analysis & Project Identification (wbs 1300)  Volume II  05 ‐ Transmission Network Study (wbs 1400)  06 ‐ Interconnection Studies (wbs 1500)  07 ‐  Regional Market Operator Location (wbs 2900)  Volume III  08 ‐ System Studies For Expansion Plan (wbs 2100)  Volume IV  09 ‐ Environment Impact Assessment (wbs 2200)  10 ‐ Cost Estimates And Implementation Schedules (wbs 2300)  11 – Financial & Economic Evaluation – Risk and Benefits (wbs 2400/2500)  12 ‐ Development and Investment Plan (wbs 2600)  13 ‐ Institutional and tariff aspects (wbs 2700)  14 – Project Funding (wbs 2800)  15 – Conclusions  Appendix A  TOR, Cost Estimates and Implementation Schedules for Feasibility Studies  for Projects identified in the first five years  Appendix B  Part I – WBS 1100 Demand Forecast  Part II – WBS 1200‐1300 Gen. Supply Study – Supply Demand Analysis  Part III – WBS 1400‐1500 Transm. Network – Interconnection Studies  Part IV – WBS 2600‐2700 Investment Plan – Institutional & Tariff Aspects     
  • 3. Final Master Plan Report Acronyms and Abbreviations May 2011 EAPP/EAC Regional PSMP & Grid Code Study Acronyms and Abbreviations A AC Alternate Current AEO Annual Energy Outlook AfDB African Development Bank AICD Africa Infrastructure Country Diagnostic ARIMA Autoregressive Integrated Moving Average ARR Annual Required Revenue Avg Average B BADEA Arab Economic Development Bank in Africa bbl Oil barrel BCR Benefit/Cost Ratio BR Burundi C CAPEX Capital Expenditure CBEMA Computer and Business Equipment Manufacturers’ Association CCGT Combined Cycle Gas Turbine - Thermal Power Plant CDM Clean Development Mechanism CEO Chief Executive Officer CF Capacity Factor CIRR Commercial Interest Reference Rate CKT Circuit CO2 Carbon Dioxide COR Composite Outage Rate CPI Consumer Price Index D DB Djibouti DC Direct Current DC Democratic Republic of Congo DGHER General Directorate for Hydropower and Rural Electrification DOE Department of Energy (USA) DRC Democratic Republic of Congo DSCR Debt Service Coverage Ratio E EAC East African Community EAPMP East African Power Master Plan Study EAPP Eastern Africa Power Pool EdD Électricité de Djibouti EDF Électricité de France EEHC Egyptian Electric Holding Company EEPCo Ethiopia Electric Power Corporation
  • 4. Final Master Plan Report Acronyms and Abbreviations May 2011 EAPP/EAC Regional PSMP & Grid Code Study EETC Egyptian Electricity Transmission Company EG Egypt EIA Energy Information Administration EIC Existing Interconnections EIJLLST Egypt, Iraq, Jordan, Libya, Lebanon, Syria and Turkey EIRR Economic Internal Rate of Return EMF Electro-Magnetic Field EMP Environmental Management Plan ENPTPS Eastern Nile Power Trade Program Study ENPV Economic Net Present Value ENTRO Eastern Nile Technical Regional Office EPC Engineering Procurement and Construction EPCM Engineering Procurement and Construction Management Esc. Escalation ESIA Environmental and Social Impact Assessment ET Ethiopia EU European Union F FC Fictitious Company FDI Foreign Direct Investment FIRR Financial Internal Rate of Return FNPV Financial Net Present Value FOR Forced Outage Rate FS Feasibility Study FttH Fibre-to-the-Home G GCI Global Competitiveness Index GDP Gross Domestic Product GHG Green House Gases GNI Gross National Income GoE Government of Ethiopia GT Gas Turbine GTP Growth and Transformation Plan H HFO Heavy Fuel Oil HPP Hydro Power Plant HVAC High Voltage Alternate Current HVDC High Voltage Direct Current I ICNIRP International Commission of Non-Ionizing Radiation Protection ICS Interconnected System (Ethiopia) ICT Information and Communication Techonology IDC Interest during Construction IDO Industrial Diesel Oil
  • 5. Final Master Plan Report Acronyms and Abbreviations May 2011 EAPP/EAC Regional PSMP & Grid Code Study IFC International Financial Corporation IMF International Monetary Fund Inst. Cap. Installed Capacity IP Internet Protocol IPO Initial Public Offering IPP Independent Power Producer IRR Internal Rate of Return IT Information Technology J JMP Joint Multipurpose Project K KenGen Kenya Electricity Generation Company KETRACO Kenya Electricity Transmission Company Limited KPLC Kenya Power and Lighting Company Ltd KTCIP Kenya Telecommunications Infrastructure Project KY Kenya L LAP Libyan African Portfolio LCEMP Least Cost Electricity Master Plan LCPDP Least Cost Power Development Plan LD Liquidated Damage LDC Load Duration Curve LDCs Least Developed Countries Level of Prep. Level of Preparedness LFO Light Fuel Oil LNG Liquefied Natural Gas LOLE Loss of Load Expectation LOLP Loss of Load Probability LRMC Long Run Marginal Cost LRO Light Residual Oil LSD Low-Speed Diesel Engine LTPSPS Long-Term Power System Planning Study LVL Level M MAED Model for Analysis of Energy Demand Max Maximum MD Maximum Power Demand Min Minimum MINIFRA Rwanda Ministry of Infrastructure MOU Memorandum of Understanding MoWR Ministry of Water and Energy MP Master Plan MPIP Medium-term Public Investment Plan MSD Medium-Speed Diesel Engine
  • 6. Final Master Plan Report Acronyms and Abbreviations May 2011 EAPP/EAC Regional PSMP & Grid Code Study N NBI Nile Basin Initiative NEC Sudan National Electricity Corporation NELSAP Nile Equatorial Lakes Subsidiary Action Program NG Natural Gas NGP National Generation Plan Nom. Cap. Nominal Capacity NPV Net Present Value O OCGT Open Cycle Gas Turbine - Thermal Power Plant ODA Official Development Assistance OECD Organization of Economic Cooperation and Development OLADE Organización Latinoamericana de Energía (Latin American Energy Organization) OLTC On-Load Tap Changers O&M Operation and Maintenance ONRD Office of Natural Resources Damage OPEC Organization of the Petroleum Exporting Countries OPEX Operating Expenditure OPTGEN Optimal Generation (Planning Model) P PF Plant Factor PPA Power Purchase Agreement PPE Personal Protective Equipment PSIP Power Sector Investment Plan PSMP Power System Master Plan Study pu Per Unit R RALF Regression Analysis Load Forecast RCC Regional Coordination Center RECO Rwanda Energy Corporation Ref Reference REGIDESO Régie de production Distribution d’Eau et d’Electricité RFP Request for Proposal RGP Regional Generation Plan RMO Regional Market Operator RMOC Regional Market Operation Center RoC Return on Capital RoCE Return on Capital Employed RoE Return on Equity ROR Run-Of-River RTL Rwandatel S.A. RW Rwanda RWASCO Rwanda Water Supply Corporation
  • 7. Final Master Plan Report Acronyms and Abbreviations May 2011 EAPP/EAC Regional PSMP & Grid Code Study S SAPP Southern African Power Pool SCS Self-Contained System (Ethiopia) SD Sudan SDDP Stochastic Dual Dynamic Programming SEACOM SEEE Society of Electrical and Electronics Engineers SIL Surge Impedance Loading SINELAC Société Internationale d’Électricité des Pays des Grands Lacs SNEL Société Nationale d’Électricité – République Démocratique du Congo SPV Special Project Vehicle SRMC Short Run Marginal Cost SSEA Strategic/Sectoral, Social and Environmental Assessment of Power Development Options in the Nile Equatorial Lakes Region STPP Steam Thermal Power Plant SVC Static Var Compensator T TANESCO Tanzania Electric Supply Company Ltd TOR Terms of Reference TPP Thermal Power Plant TSO Transmission System Operator TZ Tanzania U UETCL Uganda Electricity Transmission Company UEGCL Uganda Electricity Generation Company Limited UG Uganda UIC Unlimited Interconnections UN United Nations UNCTAD United Nations Conference on Trade And Development USBR United States Bureau of Reclamation UTL Uganda Telecom Ltd W WACC Weighted Average Cost of Capital WB World Bank WBS Work Breakdown Structure WEF World Economic Forum Y yr Year
  • 8. Final Master Plan Report Introduction May 2011 EAPP/EAC Regional PSMP & Grid Code Study SECTION 1 Introduction
  • 9. Final Master Plan Report 1-1 Introduction May 2011 EAPP/EAC Regional PSMP & Grid Code Study 1 INTRODUCTION 1.1 Study Objectives The objective of the study is to identify power generation and interconnection projects, at Master Plan level, to interconnect the power systems of EAPP and EAC countries in short- to-long term. The study also aims at developing common Transmission Interconnection Code in order to facilitate the integrated development and operations of the power systems of EAPP and EAC countries. The study further aims at contributing to the institutional capacity building for the EAPP and EAC staff through training of counterpart staff. The development of institutional capacity will enable EAPP / EAC to implement the subsequent activities, including the updating of both the Master Plan and the Grid Code reports. This study covers the following countries in alphabetical order: Burundi, Djibouti, Democratic Republic of Congo, Egypt, Ethiopia, Kenya, Rwanda, Sudan, Tanzania and Uganda. 1.2 Project Background On 24 February 2005, the Energy Ministers from seven (7) Eastern Africa countries, namely: Burundi, Democratic Republic of Congo (DRC), Egypt, Ethiopia, Kenya, Rwanda and Sudan signed an Inter-Governmental Memorandum of Understanding (MOU) for the establishment of the Eastern Africa Power Pool (EAPP). The signature of the MOU was followed by the signature of an Inter-Utility MOU by the Chief Executive Officers (CEOs)/Managing Directors of the countries’ nine (9) Power Utilities. This event heralded the formal launching of EAPP. The EAPP member utilities are: REGIDESO (Burundi), SNEL (DRC), EEHC (Egypt), EEPCo (Ethiopia), KenGen and KPLC (Kenya), ELECTROGAZ (Rwanda), NEC (Sudan) and SINELAC (DRC, Rwanda and Burundi). In further developments, EAPP has been adopted by the 11th Summit of the Common Market for Eastern and Southern Africa (COMESA) Authority of Heads of State and Government held in Djibouti from 15-16 November 2006 and has been considered as COMESA’s Specialized Institution for Electric Power. Given that some member countries of EAC overlap with those of EAPP, these two institutions signed an MOU on September 2009, whereby EAPP and EAC agree to jointly implement the present Power Master Plan and Grid Code Study for which EAPP is designated as the Implementation Agency. In this document when reference is made to “EAPP countries” it is understood that this designates the group of ten countries mentioned above. Countries in the region, by and large, have been planning and implementing the development of their power system in an isolated manner with a view to satisfying the national demand growth. Bilateral power exchange agreements exist between some countries in the Region. However, the volume of power exchange is not significant and exporting parties have frequently been unsuccessful in their commitments to deliver the power in accordance with their contractual obligations because of deficits in their systems. The existing power interconnection projects include: • DRC, Burundi, and Rwanda interconnected from a jointly developed hydro power station Ruzizi II, (capacity 45 MW) operated by a joint utility [SOCIETE D’ELECTRICITE DES PAYS DES GRAND LACS (SINELAC)];
  • 10. Final Master Plan Report 1-2 Introduction May 2011 EAPP/EAC Regional PSMP & Grid Code Study • Cross-border electrification between Uganda and Rwanda, Tanzania and Uganda, and Kenya and Tanzania; • Kenya – Uganda interconnection; and • Egyptian power system interconnection through Libya to other Maghreb countries and Southern Europe; and through Jordan to Eastern Mediterranean. Other ongoing power interconnection systems are shown in:Table 1-1 Power trading through common planning and implementation of regional generation and interconnection projects has been identified as one important strategy for tackling the problems associated with power supply shortages, low access, high cost and poor supply reliability. However, at present, the power interconnections within the region are limited for realization of shared benefits that would be generated through integrated development of their power systems. Presently, Kenya, Tanzania and Uganda under the auspices of the East African Community (EAC), are developing plans to (i) interconnect and strengthen their power systems in order to share power supplies, and (ii) further extend the power system interconnections to countries outside EAC countries. The Master Plan which was finalized in March 2005 has identified regional generation and transmission projects for integrated development. A series of studies have been completed in the last 5 years that cover opportunities for cross-border interconnections in the region. These include the EAPMP1 , SSEA2 , ENTRO3 , Ethiopia-Djibouti Interconnection, and the 2004 World Bank Scoping Study4 . Implementation planning is going ahead for the interconnection of the national grids for the five equatorial Lakes countries (Burundi, Kenya, Uganda, DRC, and Rwanda). 1 East Africa Power System Master Plan Study (Uganda, Kenya, Tanzania) 2 Stategic/Sectoral, social and Environmental Assessment of Power Development Options (Burundi, Eastern DRC, Kenya, Rwanda, Tanzania, Uganda) 3 Eastern Nile Power Trade Study (Egypt, Sudan, Ethiopia) 4 Joint UNDP/WB Energy Sector Management Assistance Program (ESMAP), Opportunities for Power Trade in the Nile Basin, Final Scoping Study, January 2004
  • 11. Final Master Plan Report 1-3 Introduction May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 1-1 Ongoing Interconnection projects From To Type / Length Capacity (MW) Earliest Year in Operation Status Comments Tanzania Kenya 400 kV 2 circuits 260 Km 1520 2015 Ongoing FS, detailed design and tender documents preparation Bidding for line construction may start at the end of 2011. Rusumo Rwanda 220 kV 1 circuit 115 Km 320 2015 FS completed Lines associated to the Rusumo Falls HPP connecting the project with the grids of Tanzania, Rwanda and Burundi. Rusumo Burundi 220 kV 1 circuit 158 Km 280 2015 Rusumo Tanzania 220 kV 1 circuit 98 Km 350 2015 Ethiopia Kenya 500 kV-DC bipole 1120 Km 2000 2016 Design and tender document preparation study to start early 2011 New design study aims at highly optimistic completion of phase I (1000 MW) of the project by 2013 and phase II upgrade to 2000 MW by 2019. Ethiopia Sudan 500 kV 4 circuits 570 Km 3200 2016 FS completed
  • 12. Final Master Plan Report 1-4 Introduction May 2011 EAPP/EAC Regional PSMP & Grid Code Study From To Type / Length Capacity (MW) Earliest Year in Operation Status Comments Egypt Sudan 600 kV-DC bipole 1665 Km 2000 2016 FS completed Uganda Kenya 220 kV 2 circuits 254 Km 300 2014 Under construction Runs from Lessos substation in Kenya to Bujagali substation passing through Tororo substation in Uganda, duplicating the existing 132kV line. Uganda Rwanda 220 kV 2 circuits 172 Km 250 2014 Detailed and Tender Documents preparation study starts in 2011 Line from Mbarara to Mirama (border Uganda) to Birembo/Kigali (Rwanda) Rwanda DRC 220 kV 1 circuit 68 Km 370 2014 Under construction Line between new substation at Kibuye Methane Gas plant in Rwanda and Goma (DRC), thus completing the loop around lake Kivu. DRC Burundi 220 kV 1 circuit 105 Km 330 Expected in 2014 FS, detailed engineering and tender documents preparation study to start early 2011 Line from future substation Kamanyola/Ruzizi III (DRC) to Bujumbura (Burundi). Study Includes 220kV line between a new substation in Bujumbura to Kiliba (DRC). Burundi Rwanda 220 kV 330 2016 FS update to start early 2011 Line Rwegura (Burundi) – Kigoma (Rwanda), previous FS recommended 110kV. Feasibility Study update to re-examine 220kV option and re-route line to feed intermediate locations.
  • 13. Final Master Plan Report 1-5 Introduction May 2011 EAPP/EAC Regional PSMP & Grid Code Study 1.3 Content and objectives of the master plan report This Master Plan Report provides the findings from the Regional Power System Master Plan. The Interconnection Code (Grid Code) is part of a separate report. The Master Plan first discusses all the input data necessary for the planning exercise: Demand Forecast (WBS 1100), Generation Supply analysis, including existing and future thermal, hydro and renewable energy projects, and planning criteria (WBS 1200). The existing transmission network data and models are compiled in WBS 1400 and common planning criteria and basic unit costs are developed for the candidate interconnection projects in WBS 1500. A preliminary identification of the regional projects (generation and interconnections) is performed including a supply-demand analysis for each country and a regional interconnection plan is developed under WBS 1300. An estimation of the regional benefits of different scenarios is also performed. Detailed system studies for each country and reinforcement needs are identified in WBS 2100 while other aspects of the projects such as the environmental impacts (WBS 2200), Cost Estimates (2300), Financial-Economic Analysis and risk assessment (WBS 2500) are presented in the report. Finally an investment plan for the identified interconnection projects is developed in WBS 2600 and the analysis of institutional and tariff aspects as well as project funding requirements are included in WBS 2700 and WBS 2800 respectively. An analysis of the requirements and recommendation for the location of the Regional Market Operator (RMOC) – RCC is carried out under WBS 2900. Appendix A contains for the initial phase of development (2013-2017) the TOR, cost estimates and implementation schedules for the indentified projects. Appendix B contains specific information and tables for particular sections of the report.
  • 14. Final Master Plan Report 1-6 Introduction May 2011 EAPP/EAC Regional PSMP & Grid Code Study 1.4 Organization of the report EXECUTIVE SUMMARY MAIN REPORT 1 INTRODUCTION 2 DEMAND FORECAST (1100) 3 GENERATION SUPPLY STUDY AND PLANNING CRITERIA (1200) 4 SUPPLY-DEMAND ANALYSIS AND PROJECT IDENTIFICATION (1300) 5 TRANSMISSION NETWORK STUDY (1400) 6 INTERCONNECTION STUDIES (1500) 7 REGIONAL MARKET OPERATIONS CENTRE LOCATION (2900) 8 SYSTEM STUDIES FOR EXPANSION PLAN (2100) 9 ENVIRONMENTAL IMPACT ASSESSMENT (2200) 10 COST ESTIMATES AND SCHEDULES (2300) 11 FINANCIAL AND ECONOMICAL EVALUATIONS – Risks and Benefits (2500) 12 DEVELOPMENT AND INVESTMENT PLAN (2600) 13 INSTITUTIONAL AND TARIFF ASPECTS (2700) 14 PROJECT FUNDING (2800) 15 CONCLUSIONS APPENDICES APPENDIX A – TOR, Cost Estimates and Implementation Schedules for Feasibility Study for Projects Identified for the Initial Phase Development (2013-2017) APPENDIX B – General Appendices
  • 15. Final Master Plan Report WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study SECTION 2 Demand Forecast WBS 1100
  • 16. Final Master Plan Report WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study TABLE OF CONTENTS 1.  DEMAND FORECASTING: GENERAL PRINCIPLES ..............................................1-1  1.1  The Need for Demand Forecasting ............................................................................1-1  1.2  Demand Forecasting Techniques...............................................................................1-1  2.  ADOPTED APPROACH TO DEMAND FORECASTING...........................................2-1  2.1  Data Collection ...........................................................................................................2-1  2.2  Approach to Reviewing the Existing National Demand Forecasts..............................2-1  2.3  PB Independent Demand Forecasts ..........................................................................2-2  3.  REVIEW OF EXISTING NATIONAL DEMAND FORECASTS ..................................3-1  3.1  Burundi .......................................................................................................................3-1  3.2  Djibouti........................................................................................................................3-2  3.3  East DRC....................................................................................................................3-7  3.4  Egypt ........................................................................................................................3-10  3.5  Ethiopia.....................................................................................................................3-12  3.6  Kenya .......................................................................................................................3-14  3.7  Rwanda ....................................................................................................................3-18  3.8  Sudan .......................................................................................................................3-20  3.9  Tanzania...................................................................................................................3-22  3.10  Uganda .....................................................................................................................3-23  4.  INDEPENDENT PB DEMAND FORECASTS............................................................4-1  4.1  Burundi .......................................................................................................................4-1  4.2  Djibouti........................................................................................................................4-4  4.3  DRC............................................................................................................................4-6  4.4  Egypt ..........................................................................................................................4-8  4.5  Ethiopia.....................................................................................................................4-10  4.6  Kenya .......................................................................................................................4-12  4.7  Rwanda ....................................................................................................................4-15  4.8  Sudan .......................................................................................................................4-18  4.9  Tanzania...................................................................................................................4-21  4.10  Uganda .....................................................................................................................4-23 
  • 17. Final Master Plan Report WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study LIST OF TABLES Table 3-1  Extended NELSAP Demand Forecast for Burundi (Base Case) .....................3-2  Table 3-2  LCEMP Demand Forecast (Base Case)..........................................................3-4  Table 3-3  LCEMP Demand Forecast (High Case)...........................................................3-5  Table 3-4  LCEMP Demand Forecast (Low Case)............................................................3-6  Table 3-5  Extended NELSAP Demand Forecast for East DRC (Base Case)..................3-8  Table 3-6  Extended NELSAP Demand Forecast for East DRC (High Case)...................3-9  Table 3-7  Extended NELSAP Demand Forecast for East DRC (Low Case) .................3-10  Table 3-8  Extended EEHC Demand Forecast for Egypt (Base Case)...........................3-12  Table 3-9  Extended EEPCO Demand Forecast for Ethiopia (Base Case – Moderate I Scenario) .......................................................................................................3-14  Table 3-10  Extended 2008 LCPDP Demand Forecast for Kenya (Base Case)...............3-16  Table 3-11  Extended 2009 LCPDP Demand Forecast (Base Case) ...............................3-17  Table 3-12  Extended NELSAP Demand Forecast for Rwanda (Base Case)...................3-19  Table 3-13  Extended LTPSP Demand Forecast for Sudan (Base Case) ........................3-21  Table 3-14  Extended PSMP Demand Forecast for Tanzania (Base Case).....................3-23  Table 3-15  PSIP Demand Forecasts for Uganda (Base, High and Low Cases)..............3-24  Table 4-1  PB Base, High and Low Demand Forecast for Burundi...................................4-2  Table 4-2  PB Base, High and Low Demand Forecast for Djibouti ...................................4-4  Table 4-3  RSWI Base, High and Low Demand Forecast for East DRC...........................4-6  Table 4-4  PB Base, High and Low Demand Forecast for Egypt......................................4-8  Table 4-5  PB Base, High and Low ICS Demand Forecast for Ethiopia .........................4-10  Table 4-6  PB SCS Demand Forecast for Ethiopia.........................................................4-12  Table 4-7  PB Base, High and Low Demand Forecast for Kenya...................................4-13  Table 4-8  PB Base, High and Low Demand Forecast for Rwanda................................4-16  Table 4-9  PB Base, High and Low Demand Forecast for Sudan...................................4-19  Table 4-10  PB Base, High and Low Demand Forecast for Tanzania ..............................4-21  Table 4-11  PB Base, High and Low Demand Forecast for Uganda.................................4-23  LIST OF FIGURES Figure 4-1  PB Peak Demand Forecast for Burundi (MW).............................................4-3  Figure 4-2  PB Sent Out Generation Forecast for Burundi (GWh).................................4-3  Figure 4-3  PB Peak Demand Forecast for Djibouti (MW) .............................................4-5  Figure 4-4  PB Sent Out Generation Forecast for Djibouti (GWh) .................................4-5  Figure 4-5  RSWI Peak Demand Forecast for East DRC (MW).....................................4-7  Figure 4-6  RSWI Sent Out Generation Forecast for East DRC (GWh).........................4-7  Figure 4-7  PB Peak Demand Forecast for Egypt (MW) ................................................4-9  Figure 4-8  PB Sent Out Generation Forecast for Egypt (GWh) ....................................4-9  Figure 4-9  PB ICS Peak Demand Forecast for Ethiopia (MW) ...................................4-11  Figure 4-10  PB ICS Sent Out Generation Forecast for Ethiopia (GWh)........................4-11  Figure 4-11  PB Peak Demand Forecast for Kenya (MW)..............................................4-14  Figure 4-12  PB Sent Out Generation Forecast for Kenya (GWh)..................................4-14  Figure 4-13  PB Peak Demand Forecast for Rwanda (MW)...........................................4-17  Figure 4-14  PB Sent Out Generation Forecast for Rwanda (GWh)...............................4-17  Figure 4-15  PB Peak Demand Forecast for Sudan (MW) .............................................4-20  Figure 4-16  PB Sent Out Generation Forecast for Sudan (GWh) .................................4-20  Figure 4-17  PB Peak Demand Forecast for Tanzania (MW).........................................4-22  Figure 4-18  PB Sent Out Generation Forecast for Tanzania (GWh).............................4-22  Figure 4-19  PB Peak Demand Forecast for Uganda (MW) ...........................................4-24  Figure 4-20  PB Sent Out Generation Forecast for Uganda (GWh) ...............................4-24
  • 18. Final Master Plan Report 1-1 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 1. DEMAND FORECASTING: GENERAL PRINCIPLES A demand forecast is the prediction of demand for power (MW) and energy (GWh) into the future. The maximum power demand (MD) in a period is known as the peak demand, and this is usually the headline figure which is quoted when developing demand forecasts. It should be noted however, that in electrical systems with predominantly thermal capacity, it is more important for planning purposes to know the peak demand rather than the amount of electrical energy required, since the peak demand often sets the capacity expansion goal. On the other hand, for systems with large amounts of hydro-electric capacity, it is equally important to know the level of energy demand, as these systems may have energy limitations. It is thus the usual practice in any detailed demand forecast to predict the level of energy demand first, and then derive the peak demand using appropriate load and coincidence factors. 1.1 The Need for Demand Forecasting A demand forecast is a primary requirement for electricity planning studies. Demand forecasts are needed for: • Generation planning, • Transmission planning, • Distribution planning, • Financial planning, • Feasibility studies, • Pricing and tariff setting, and, • Operational planning (short-term). Different demand forecasts are required for the short, medium or long term and for different levels of the system (e.g. generation, transmission substations, distribution substations and at consumer terminals). Rigorous demand forecasting may be necessary for a number of reasons, such as: • It is often essential for outside parties (e.g. bilateral and multilateral financiers, private sector investors and project shareholders) to be convinced of the reasonableness of future load growth and the corresponding investment plan before making a financial commitment. • Large consumers are often more optimistic about future growth than is justified by the prevailing economic climate. This may result in an over-estimate of load with a consequent over-investment. • In markets where demand is approaching saturation, judgements formed from buoyant market growth in the past may not be a good guide to growth in the future. • Utilities will frequently over-estimate demand allowing for the time required to secure finance and the necessary project construction approvals. 1.2 Demand Forecasting Techniques The only certainty about a demand forecast is that it will not match the out-turn. To cover this eventuality it is essential to develop a demand forecasting technique that is appropriate and suitable to the objectives of the forecast. No technique can be considered incorrect for demand forecasting. The technique adopted will depend on the time frame under
  • 19. Final Master Plan Report 1-2 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study consideration, the size of the system, the plant available and the data available. In other words the type of demand forecast technique adopted should fall in line with the requirements of the study and based on the availability of data. There are four main demand forecasting techniques, namely: • Intuitive based demand forecasting • Extrapolation based demand forecast • End user demand forecast • Econometric demand forecasting A general overview of each of these methods is detailed in the sub-sections below. Intuitive The term intuitive forecasting can be used to describe methods which rely largely on experience and quick calculations using simple assumptions (i.e. the use of the immediate past performance and an assumption that the rates of change will continue unaltered in the near future). The intuitive load forecast should not be entirely discounted, as it is after all in the background of reviewers’ minds when they appraise other peoples’ demand forecasts. In some instances, the lack of available data may make intuitive forecasting the only possible option. The forecast may be appropriate for minor developments, isolated systems and small Island utilities. An alternative approach, but still within the intuitive forecasting framework, would be to apply a growth factor that is obtained for a country with similar economic characteristics. Indeed, it may be beneficial to compare load forecasts with the performance of a similar system in another part of the world at a comparable stage of development. This will particularly be the case where (i) there is little statistical information available on past loads, such as in new areas of supply, (ii) data errors that cannot be easily corrected, or, (iii) it becomes necessary to forecast on the results of direct enquiry and demographic and economic statistics. Such forecasting is no more than guesswork, but the results can be used to cross-check on forecasts prepared by more scientific methods. Where a new system of forecasting is to be prepared, it is often helpful to make a comparison of the intuitive forecasts prepared in the past and subsequent performance. Extrapolation Extrapolation techniques look at past trends in energy and power demand over time and, extend them into the future. Any time series may be decomposed into three elements: • Trend • Seasonal variation • Serial dependency (auto-regression). Trend is defined as “the long-term average growth and may be regarded in some way as an average increase in a time series”. Superimposed on this may be a seasonal variation. Seasonal in this sense is defined as “a cyclic variable that has roughly the same beginning and end values for a given period of time (similar to the properties of a sine wave)”. Such variations may be seen over a 24 hour period, a weekly period, an annual period, or even a longer period.
  • 20. Final Master Plan Report 1-3 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Finally there may be a dependency between successive values. For example, if the value in the previous period was high, the value in the current period may be high. Such behaviour could relate to the random use of batch processing equipment. This interdependency is known as auto-regression. There are a wide range of techniques for analysing data on a time series basis including: • Moving Average • Exponential smoothing • Autoregressive techniques • Simple Regression • ARIMA (autoregressive integrated moving average) End User End-user demand forecast modelling draws on many utility forecasting methods. The distinguishing characteristic of end-user modelling is the detailed description of how energy is used. Such models usually begin by specifying uses for which energy is ultimately required, such as heating water, cooling buildings and cooking food. The model then describes, via mathematical equations and accounting identities, the types of energy-using equipment that businesses and households have, and how much energy is used by each type of equipment to satisfy the predetermined levels of end-use energy demanded. A large amount of survey data and statistics are needed by such a model. By summing up the units of equipment times the average energy used by each class of equipment, total energy demand by fuel type is revealed. Multiplying types of equipment by average use values is just an accounting framework, but even so, it can generate insights into the way energy is used now and in the future. Optimisation end-user models are a step beyond accounting end-user models. By specifying an objective function (such as minimising cost) and identifying both the unit costs of using energy in the given processes and the constraints to the system, the accounting end-user model can be transformed into a device that will predict how customers will act (assuming that their objective function is properly specified), given the assumptions about costs and constraints. End-user models are often linked to econometric models. End-user models are often weakest in predicting consumers' fuel-use decisions. With the available data, they can easily describe where the energy is being used and for what purposes but, without a theory to explain choices, they are limited in their ability to predict the future. The ideal end-user model (which is rarely achieved) would, for example, not only tell us the average watts of lighting energy in households, and how this amount has changed over time, but also what caused households and/or housing operators to make these changes. End-user forecasting can be highly accurate, particularly for green-field developments, and for forecasts of residential demand. An extension of end-user demand forecasting is load- density-based forecasting, in which the maximum load in any area is based upon the surface area occupied by each consumer type and a power density (i.e. watts per square meter) associated with that consumer type. This can be especially useful for distribution planning. End-user forecasts also encompass developments in sectors such as industry and agriculture where consumption patterns can be established for, say, cement production or water pumping.
  • 21. Final Master Plan Report 1-4 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Econometric Analysis This class of model, like the time series model (extrapolation), uses historical data to predict the future. Econometric analysis however, attempts to go beyond time series models by explaining the causes of the identified trends. Econometric models postulate explicit causal relationships between the dependent variable (either energy or power) and independent variables (either economic (e.g. GDP), technological (e.g. number and type of appliances; industrial processes), demographic (e.g. population) or other variables (e.g. weather)). Assuming these relationships are true it should then be possible to determine the historical relationships between electrical demand and such parameters as GDP by sector, personal income, the price of electricity etc. Future levels of these economic variables are then forecast and used as inputs to determine future levels of consumption. One advantage of econometric forecasting is the ease with which high and low scenario load forecasts can be derived and the logical basis on which the can be formed. This merely requires changes in the forecast rate of the input variables, e.g. economic growth and electricity price. A faster economic growth will produce a higher load forecast whilst the imposition of price increases will reduce forecast levels of energy demand. Econometric modelling would be preferred to time series analysis. Even if both techniques could predict changes in demand with equal accuracy, the econometric model would be more valuable since it might help in understanding why changes in demand were occurring. Top-down and Bottom-up Approaches An additional classification of demand forecast techniques is between bottom-up and top- down approaches. Most demand forecasting methodologies utilise a bottom-up approach. A bottom-up approach concentrates on predicting demand at the consumer level (i.e. electricity sales). This sales forecast may then be converted to a system power demand forecast at different voltage levels by summation of each individual consumer level sales forecast and the use of loss estimates and load factors (see Equation 2.1). Using a top-down approach is generally not recommended. A top-down approach involves the estimate of demand at a generation level (i.e. forecasting MW sent out, GWh sent out). This technique includes implicit assumptions about the behaviour of losses in the future, and does not permit a breakdown by consumer sector.
  • 22. Final Master Plan Report 2-1 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 2. ADOPTED APPROACH TO DEMAND FORECASTING The purpose of this report is to identify or provide an array of demand forecast scenarios (namely base, high and low scenarios) for each EAPP/EAC member country, suitable for deriving Master Plans for the EAPP/EAC member countries. In this sub-section we detail the approach adopted to achieve this objective. Our approach can be divided into three parts: • Data collection • Review of existing national demand forecast • Derivation of independent demand forecast scenarios We detail our approach to each of these parts in turn below. 2.1 Data Collection The first step in achieving the objective detailed above is to carry out an extensive data collection exercise. The data collection exercise comprised: • A short visit to each country to meet with the utility representative(s) and to initiate the data collection. The visit to each country also allowed the Consultant to see at first hand the level of development in the country. Where data relating to demand forecasting was not readily available, requests were made for: − Previous demand forecasts. − Historic electrical data (hourly load data, loss data, peak demand, generation, sales data etc). − Historic economic and demographic data (GDP, population etc). − Economic and demographic forecast data (GDP, population etc). − Any background information relating to topics such electrification, loss reduction etc. • Following the visit to each country: − A review of the data collected was undertaken. − Desktop research was carried out to expand on the data made available in country. − The Consultants (PB and SNC) databases were searched for information relating to the countries of the EAPP/EAC. − Where gaps were identified we made requests for additional data. 2.2 Approach to Reviewing the Existing National Demand Forecasts The next step in determining base, high and low demand forecast scenarios for each EAPP/EAC country member is to identify the most recent existing national demand forecast available and review the adopted methodology, key assumptions and overall results. This review will allow us to form an opinion on the suitability of the forecast for use in the EAPP/EAC study. The EAPP/EAC study horizon year is 2038 and most existing national demand forecasts do not extend this far into the future. As such, we have extended the existing national demand forecasts to cover the study horizon. The process for reviewing the existing national demand forecast (for each country) is summarised follows:
  • 23. Final Master Plan Report 2-2 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study • Identify most recent demand forecast available for each country • Review the most recent demand forecast for: − Methodology. − Assumptions. − Level of detail1 . − Magnitude of demand growth. − Suitability for inclusion in the EAPP/EAC study, including a comparison with the current level of demand to ensure that the demand forecasted today is in line with the current level of demand. • Extend the national forecast to cover the planning horizon of the study by either using the same methodology as used to develop the original forecast (if possible) or by using trend line analysis2 or growth rate extrapolation techniques. • Offer our comments on the extended existing demand forecast, including the likelihood of this forecast being achieved and the constraints that may hinder its attainment. 2.3 PB Independent Demand Forecasts In addition to reviewing the most recent existing demand forecast for each country, we have developed independent base, high and low demand forecasts. Our independent demand forecasts are based on our own assumptions and methodologies, utilising the data collected and analysed as part of the data collection process (see sub- section 2.1). Where data availability and quality permit, the independent demand forecasts are based on our econometric based Regression Analysis Load Forecast (RALF) model. The data available for some of the EAPP/EAC countries however is of poor quality, un- reliable and contains many gaps. If the data does not permit an independent econometric demand forecast to be developed, then we use a combination of growth rate analysis, electrification assumptions, population data and specific consumption assumptions to derive suitable independent demand forecasts3 . 1 This typically includes identifying whether the forecast includes both an energy and power forecast, whether it is developed at a sales level, broken down by consumer category etc. 2 Trend Line Analysis is carried out using the Microsoft Excel trend line tool. A trend line can be added to any charted historic dataset (using a simple X Y Chart). A trend line equation and a R2 correlation statistic can also be displayed. The R2 statistic can be used to determine the reasonableness of the trend line fit to the historic data and the equation can be used to project future values. 3 A description of the methodologies used (RALF or other) are provided in the Appendices of those countries where these methodologies have been employed.
  • 24. Final Master Plan Report 3-1 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 3. REVIEW OF EXISTING NATIONAL DEMAND FORECASTS In this section of the report we outline the existing national demand forecasts available for each member country of the EAPP/EAC. Each existing national demand forecast has been extended to cover the period to 2038. In the following sub-sections we detail the existing national demand forecast, covering the following: • Who developed the forecast, • When was the forecast developed, • What methodology was employed, • How we extended the forecast to cover the period to 2038, • The extended forecast, and, • Comments on the existing/extended demand forecast Further details of each review are provided in the respective Appendices provided with this report. 3.1 Burundi The latest national demand forecast available for Burundi was produced by Fichtner and RSWI in October 2008 as part of the Nile Basin Initiative (NBI) study entitled ‘Nile Equatorial Lakes Subsidiary Action Program (NELSAP). The Burundian NELSAP demand forecast was developed in tandem with demand forecasts for Tanzania and Rwanda. The objective of the demand forecast was to develop an end- user model, which focused on the structure of the different electricity consumer groups and their specific consumption. It should be noted, however, that some elements of trend-line and econometric techniques were also been taken into consideration. As the NELSAP demand forecast only covered the period to 2025, we have extended the current national forecast to cover the period up to the planning horizon of this study. In order to extend the existing forecast we used trend line analysis to identify existing trends in generation sent out, sales and peak demand forecasts and used the resulting mathematical trend line formulas to project the forecast for the additional 13 years required. Several demand forecast scenarios were developed as part of the study. Further details of the methodology and assumptions used in the derivation of the NELSAP demand forecast are provided in Appendix A. The extended NELSAP base case demand forecast scenario is presented in Table 3-1 below.
  • 25. Final Master Plan Report 3-2 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-1 Extended NELSAP Demand Forecast for Burundi (Base Case) We consider the assumed growth rates in peak demand, generation and sales to be very high, with average annual growth around 11 per cent per annum. An average annual increase of this size would require a significant amount of annual investment in generation, transmission and distribution. The assumption that losses are to remain at around 26 per cent from 2015 onwards does not seem to reflect the most effective use of resources. It is also a concern to see such a large growth in demand not reflected in a change in the make-up of demand. The load factor is assumed to fall from 36 per cent to around 30 per cent. It would be reasonable to expect that the load factor would increase as more connections are made to the system and the timing and type of demand begins to reflect that of other similarly sized economies. A full description of our review of the NELSAP demand forecast is provided in Appendix A. 3.2 Djibouti The most recent Least Cost Electricity Master Plan (LCEMP) study for Djibouti was completed by PB in November 2009 and covers the period 2008 to 2038. The PB demand Sales Generation Peak  Demand Load Factor Sales Generation Peak  Demand (GWh) (GWh) (%) (GWh) (MW) (%) (%) (%) (%) 2008 63 27 30.0% 90 29 2009 86 31 26.5% 117 37 36.5% 30.0% 29.4% 2010 93 41 30.6% 134 43 35.2% 8.1% 14.5% 16.0% 2011 99 36 26.7% 135 44 34.9% 6.5% 0.7% 1.6% 2012 104 39 27.3% 143 47 34.8% 5.1% 5.9% 6.3% 2013 125 45 26.5% 170 56 34.5% 20.2% 18.9% 19.8% 2014 147 53 26.5% 200 66 34.5% 17.6% 17.6% 17.8% 2015 170 61 26.4% 231 77 34.2% 15.6% 15.5% 16.5% 2016 195 70 26.4% 265 89 34.0% 14.7% 14.7% 15.4% 2017 222 79 26.2% 301 102 33.8% 13.8% 13.6% 14.4% 2018 251 88 26.0% 339 116 33.5% 13.1% 12.6% 13.6% 2019 281 100 26.2% 381 131 33.3% 12.0% 12.4% 13.1% 2020 314 111 26.1% 425 147 33.0% 11.7% 11.5% 12.4% 2021 348 124 26.3% 472 165 32.8% 10.8% 11.1% 12.0% 2022 385 137 26.2% 522 184 32.5% 10.6% 10.6% 11.6% 2023 425 151 26.2% 576 204 32.2% 10.4% 10.3% 11.3% 2024 467 166 26.2% 633 227 31.9% 9.9% 9.9% 10.9% 2025 513 182 26.2% 695 251 31.6% 9.9% 9.8% 10.7% 2026 560 200 26.3% 760 274 31.6% 9.2% 9.3% 9.3% 2027 610 217 26.3% 827 300 31.5% 8.8% 8.9% 9.4% 2028 661 236 26.3% 898 327 31.4% 8.5% 8.5% 9.0% 2029 716 256 26.3% 972 355 31.2% 8.2% 8.2% 8.7% 2030 772 277 26.4% 1,049 385 31.1% 7.9% 7.9% 8.3% 2031 831 298 26.4% 1,129 415 31.0% 7.6% 7.7% 8.0% 2032 892 320 26.4% 1,213 448 30.9% 7.4% 7.4% 7.7% 2033 956 344 26.4% 1,299 481 30.8% 7.1% 7.2% 7.5% 2034 1,022 368 26.5% 1,389 516 30.8% 6.9% 6.9% 7.2% 2035 1,090 393 26.5% 1,482 552 30.7% 6.7% 6.7% 7.0% 2036 1,160 419 26.5% 1,579 589 30.6% 6.5% 6.5% 6.8% 2037 1,233 445 26.5% 1,679 628 30.5% 6.3% 6.3% 6.6% 2038 1,308 473 26.6% 1,781 667 30.5% 6.1% 6.1% 6.4% Assumed  Calender Year Losses
  • 26. Final Master Plan Report 3-3 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study forecast developed for the Djibouti LCEMP is derived using PB’s econometric based RALF model. Base, high and low demand forecast scenarios were developed for this study. Further details of the methodology and assumptions used in the derivation of the LCEMP demand forecast are provided in Appendix B. The base, high and low LCEMP demand forecasts are presented in Table 3-2, Table 3-3 and Table 3-4 below.
  • 27. Final Master Plan Report 3-4 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-2 LCEMP Demand Forecast (Base Case)
  • 28. Final Master Plan Report 3-5 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-3 LCEMP Demand Forecast (High Case)
  • 29. Final Master Plan Report 3-6 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-4 LCEMP Demand Forecast (Low Case)
  • 30. Final Master Plan Report 3-7 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 3.3 East DRC The latest available demand forecast for the eastern region of the DRC is that produced by RSW International in October 2007 as part of the Nile Basin Initiative (NBI) Nile Equatorial Lakes Subsidiary Action Programme (NELSAP) feasibility study on the Interconnection of the Electricity Networks of the Nile Equatorial Lakes Countries. The NELSAP study indentifies two key variables in the derivation of future power requirements in the DRC. These are: • Consumer demand • Power losses By initially working out the level of consumer demand it is assumed that through the addition of losses and the application of a load factor, a peak demand forecast can be derived. As a consequence of the data available to RSW, the proposed consumer demand forecasting approach considers a mix of econometric and simplified analytical approaches to determining the level of consumer demand, including the introduction of key estimates based on its overall and regional experience, and also when necessary, simple common sense. As the NELSAP demand forecast only covered the period to 2020, we have extended the current national forecast to the end of the planning horizon of this study. In order to extend the existing forecast we have used trend line analysis to identify existing trends in sales, sent out generation and peak demand forecasts and used the resulting mathematical trend line formulas to project the forecast for the additional 18 years required. Details relating to the specific assumptions made for the base, high and low demand forecast scenarios are provided in Appendix C. The base, high and low NELSAP demand forecasts are presented in Table 3-5, Table 3-6 and Table 3-7 below. Projections of demand for the eastern region of DRC are very hard to develop given the lack of reliable and consistent historical data. The projected growth rates for the base, high and low scenarios are reasonable and not overly optimistic given the potential for development in the region.
  • 31. Final Master Plan Report 3-8 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-5 Extended NELSAP Demand Forecast for East DRC (Base Case) Total Sales Losses Losses Generation Peak Demand Load Factor (GWh) (GWh) (%) (GWh) (MW) (%) 1 2005 168.0 42.0 20.0% 210.0 50.0 47.9% 2 2006 176.4 43.1 19.6% 219.5 52.2 48.0% 3 2007 185.3 44.1 19.2% 229.4 54.5 48.1% 4 2008 194.7 45.2 18.8% 239.8 56.9 48.1% 5 2009 204.5 46.1 18.4% 250.7 59.4 48.2% 6 2010 214.9 47.1 18.0% 262.0 62.0 48.2% 7 2011 227.0 48.0 17.5% 275.0 65.1 48.2% 8 2012 239.9 48.8 16.9% 288.7 68.3 48.2% 9 2013 253.6 49.5 16.3% 303.1 71.7 48.3% # 2014 268.2 49.9 15.7% 318.2 75.3 48.3% # 2015 283.8 50.2 15.0% 334.0 79.0 48.3% # 2016 300.5 51.8 14.7% 352.3 83.3 48.3% # 2017 318.3 53.3 14.3% 371.6 87.8 48.3% # 2018 337.3 54.6 13.9% 391.9 92.6 48.3% # 2019 357.6 55.8 13.5% 413.4 97.7 48.3% # 2020 379.3 56.7 13.0% 436.0 103.0 48.3% # 2021 402.1 58.6 13.0% 460.7 108.7 48.4% # 2022 426.4 60.6 12.4% 487.0 114.8 48.4% # 2023 452.1 62.8 12.2% 514.9 121.4 48.4% # 2024 479.3 65.3 12.0% 544.6 128.3 48.5% # 2025 508.1 68.1 11.8% 576.1 135.6 48.5% # 2026 538.4 71.2 11.7% 609.6 143.4 48.5% # 2027 570.3 74.7 11.6% 645.0 151.6 48.6% # 2028 604.0 78.5 11.5% 682.5 160.2 48.6% # 2029 639.3 82.8 11.5% 722.1 169.4 48.7% # 2030 676.4 87.5 11.5% 764.0 179.0 48.7% # 2031 715.4 92.7 11.5% 808.1 189.1 48.8% # 2032 756.2 98.3 11.5% 854.6 199.8 48.8% # 2033 799.0 104.5 11.6% 903.5 211.0 48.9% # 2034 843.7 111.2 11.6% 954.9 222.8 48.9% # 2035 890.5 118.5 11.7% 1,009.0 235.1 49.0% # 2036 939.3 126.3 11.9% 1,065.6 248.0 49.0% # 2037 990.3 134.7 12.0% 1,125.0 261.5 49.1% # 2038 1,043.4 143.8 12.1% 1,187.2 275.7 49.2% Assumed  Calender Year
  • 32. Final Master Plan Report 3-9 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-6 Extended NELSAP Demand Forecast for East DRC (High Case) Total Sales Losses Losses Generation Peak Demand Load Factor (GWh) (GWh) (%) (GWh) (MW) (%) 2005 168.0 42.0 20.0% 210.0 50.0 47.9% 2006 178.1 43.5 19.6% 221.6 52.7 48.0% 2007 188.9 45.0 19.2% 233.9 55.5 48.1% 2008 200.4 46.5 18.8% 246.9 58.5 48.2% 2009 212.7 47.9 18.4% 260.6 61.7 48.2% 2010 225.8 49.2 17.9% 275.0 65.0 48.3% 2011 240.7 50.8 17.4% 291.5 68.9 48.3% 2012 256.6 52.4 16.9% 309.0 73.0 48.3% 2013 273.8 53.7 16.4% 327.5 77.4 48.3% 2014 292.3 54.9 15.8% 347.2 82.1 48.3% 2015 312.2 55.8 15.2% 368.0 87.0 48.3% 2016 333.6 58.3 14.9% 391.9 92.6 48.3% 2017 356.7 60.6 14.5% 417.3 98.6 48.3% 2018 381.6 62.8 14.1% 444.4 105.0 48.3% 2019 408.5 64.8 13.7% 473.3 111.8 48.3% 2020 437.5 66.5 13.2% 504.0 119.0 48.3% 2021 468.2 69.4 13.0% 537.6 126.8 48.4% 2022 501.1 72.3 12.6% 573.4 135.1 48.4% 2023 536.3 75.4 12.3% 611.6 144.0 48.5% 2024 573.8 78.7 12.1% 652.5 153.5 48.5% 2025 613.7 82.4 11.8% 696.1 163.6 48.6% 2026 656.1 86.4 11.6% 742.5 174.4 48.6% 2027 701.1 90.7 11.5% 791.8 185.8 48.6% 2028 748.8 95.4 11.3% 844.2 197.9 48.7% 2029 799.3 100.5 11.2% 899.8 210.7 48.8% 2030 852.7 106.0 11.1% 958.6 224.2 48.8% 2031 909.0 111.9 11.0% 1,020.9 238.5 48.9% 2032 968.4 118.2 10.9% 1,086.6 253.5 48.9% 2033 1,031.0 125.1 10.8% 1,156.0 269.4 49.0% 2034 1,096.8 132.4 10.8% 1,229.1 286.1 49.0% 2035 1,165.9 140.2 10.7% 1,306.1 303.6 49.1% 2036 1,238.5 148.5 10.7% 1,387.0 322.0 49.2% 2037 1,314.6 157.4 10.7% 1,472.1 341.4 49.2% 2038 1,394.4 166.9 10.7% 1,561.3 361.6 49.3% Assumed  Calender Year
  • 33. Final Master Plan Report 3-10 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-7 Extended NELSAP Demand Forecast for East DRC (Low Case) 3.4 Egypt The latest national demand forecast available for Egypt was produced by EEHC in 2007 and estimates demand for electricity from 2008 to 20264 . The EEHC electricity demand forecast utilises the econometric based computer package E- views, focussing on regression analysis to determine electricity sales in each consumer category. The economic and demographic factors considered in the regression analysis are GDP/sector, electricity price/sector and population. 4 See Appendix D for a description of the transformation made to convert the financial information provided by EAPP into a calendar year format. Total Sales Losses Losses Generation Peak Demand Load Factor (GWh) (GWh) (%) (GWh) (MW) (%) 1 2005 168.0 42.0 20.0% 210.0 50.0 47.9% 2 2006 174.6 42.5 19.6% 217.1 51.7 48.0% 3 2007 181.5 43.0 19.1% 224.4 53.4 48.0% 4 2008 188.6 43.4 18.7% 232.0 55.2 48.0% 5 2009 196.1 43.8 18.3% 239.9 57.1 48.0% 6 2010 203.8 44.2 17.8% 248.0 59.0 48.0% 7 2011 213.4 44.7 17.3% 258.1 61.4 48.0% 8 2012 223.6 45.1 16.8% 268.7 63.9 48.0% 9 2013 234.3 45.4 16.2% 279.7 66.5 48.0% # 2014 245.5 45.6 15.7% 291.1 69.2 48.0% # 2015 257.4 45.6 15.0% 303.0 72.0 48.0% # 2016 270.2 46.1 14.6% 316.4 75.3 48.0% # 2017 283.8 46.5 14.1% 330.3 78.7 47.9% # 2018 298.1 46.8 13.6% 344.9 82.3 47.8% # 2019 313.3 46.8 13.0% 360.1 86.1 47.8% # 2020 329.3 46.7 12.4% 376.0 90.0 47.7% # 2021 346.5 46.5 13.0% 393.0 94.6 47.4% # 2022 364.3 46.5 11.3% 410.8 99.2 47.3% # 2023 383.0 46.4 10.8% 429.4 104.0 47.1% # 2024 402.7 46.2 10.3% 448.9 109.1 47.0% # 2025 423.3 46.0 9.8% 469.3 114.5 46.8% # 2026 444.9 45.7 9.3% 490.6 120.2 46.6% # 2027 467.4 45.4 8.8% 512.8 126.2 46.4% # 2028 491.0 45.0 8.4% 535.9 132.5 46.2% # 2029 515.6 44.5 7.9% 560.1 139.1 46.0% # 2030 541.2 44.0 7.5% 585.1 146.0 45.7% # 2031 567.9 43.3 7.1% 611.2 153.3 45.5% # 2032 595.7 42.7 6.7% 638.3 160.9 45.3% # 2033 624.6 41.9 6.3% 666.4 168.9 45.0% # 2034 654.6 41.0 5.9% 695.6 177.3 44.8% # 2035 685.7 40.1 5.5% 725.8 186.0 44.6% # 2036 718.0 39.1 5.2% 757.1 195.1 44.3% # 2037 751.5 38.0 4.8% 789.6 204.6 44.1% # 2038 786.2 36.8 4.5% 823.1 214.5 43.8% Assumed  Calender Year
  • 34. Final Master Plan Report 3-11 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study As the EEHC demand forecast only covered the period to 2026, we have extended the current national forecast to the end of the planning horizon of this study. In order to extend the existing forecast we have used trend line analysis to identify existing trends in sales, generation sent out and peak demand forecasts and used the resulting mathematical trend line formulas to project the forecast for the additional 12 years required. Further details of the methodology and assumptions used in the derivation of the EEHC demand forecast are provided in Appendix D. The extended base case EEHC national demand forecast is presented in Table 3-8 below. The EEHC demand forecast is econometric based and utilises the well-known E-views forecasting software. The E-views software is software is an excellent demand forecasting tool and thus we concur with the methodology adopted to derive the EEHC demand forecast. The key assumptions of the EEHC demand forecast relate to the forecasts of GDP and population. The population forecast growth rate ranges from 1.8 per cent and 1.3 per cent per annum. We find this rate of growth to be reasonable and in line with the latest United Nations (UN) Population Division estimate. Of more significance to the forecast results are the sectoral GDP forecast assumptions. Total GDP is forecast to grow at a rate of 5.5 per cent per annum throughout the EEHC forecast period. At this rate of growth, GDP is expected to be around 2.6 times today’s value by 2026. We find this rate of overall growth to be plausible and not excessive given the current stature of the Egyptian economy and potential for further growth. An average annual increase in demand of around 5 per cent per annum would require a reasonable but not unsustainable amount of annual investment in generation, transmission and distribution. We find no issue with the EEHC demand forecast, although it should be noted that high and low demand forecasts were not provided.
  • 35. Final Master Plan Report 3-12 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-8 Extended EEHC Demand Forecast for Egypt (Base Case) 3.5 Ethiopia The most recent demand forecast available for Ethiopia is presented in EEPCO’s “Highlights on Power Sector Development Program” Report dated June 2008. It is assumed for this study that the Moderate I Scenario is the current base case national forecast5 . The Moderate I forecast is based on an econometric model which presents the relationships between electricity demand growth, electricity price in each tariff category and the level of economic activity. The econometric model contains three sub-forecasts (ICS, SCS and rural forecasts). The ICS forecast utilises assumptions relating to GDP and electrification rates. The SCS forecast has been based on trend analysis while the rural electrification forecasts are treated separately based on the Government electrification target. The sales forecasts are then combined with projected loss rates to produce forecasts of energy generation and through the use of average load factors, the capacity (MW) requirement to deliver the demanded energy was estimated. 5 We make this assumption on the basis that the forecast suggested in the Target Scenario is extremely high and assumes an annual average growth rate of 15.5 per cent over 20+ years. We do not believe this to be credible without the identification of a new and vast oil or gas reserve. The Moderate I scenario provides a demand forecast which is higher than the Moderate II forecast but significantly less than Target forecast. Sales Generation Peak  Demand Load Factor Sales Generation Peak  Demand (GWh) (GWh) (%) (GWh) (MW) (%) (%) (%) (%) 2008 106,558 22,240 17.3% 128,798 21,000 70.0% 2009 117,920 19,135 14.0% 137,056 22,330 70.1% 10.7% 6.4% 6.3% 2010 125,536 20,220 13.9% 145,756 23,729 70.1% 6.5% 6.3% 6.3% 2011 133,559 21,352 13.8% 154,910 25,200 70.2% 6.4% 6.3% 6.2% 2012 142,000 22,532 13.7% 164,532 26,753 70.2% 6.3% 6.2% 6.2% 2013 150,876 23,762 13.6% 174,638 28,383 70.2% 6.3% 6.1% 6.1% 2014 160,190 25,041 13.5% 185,231 30,089 70.3% 6.2% 6.1% 6.0% 2015 169,965 26,369 13.4% 196,334 31,880 70.3% 6.1% 6.0% 6.0% 2016 180,241 27,752 13.3% 207,993 33,760 70.3% 6.0% 5.9% 5.9% 2017 191,043 29,171 13.2% 220,214 35,651 70.5% 6.0% 5.9% 5.6% 2018 202,398 30,626 13.1% 233,024 37,630 70.7% 5.9% 5.8% 5.6% 2019 214,333 32,137 13.0% 246,470 39,703 70.9% 5.9% 5.8% 5.5% 2020 226,881 33,707 12.9% 260,589 41,874 71.0% 5.9% 5.7% 5.5% 2021 240,076 35,339 12.8% 275,416 44,149 71.2% 5.8% 5.7% 5.4% 2022 253,956 37,036 12.7% 290,992 46,534 71.4% 5.8% 5.7% 5.4% 2023 268,558 38,800 12.6% 307,358 49,034 71.6% 5.7% 5.6% 5.4% 2024 283,920 40,633 12.5% 324,553 51,654 71.7% 5.7% 5.6% 5.3% 2025 300,086 42,540 12.4% 342,626 54,402 71.9% 5.7% 5.6% 5.3% 2026 317,100 44,523 12.3% 361,623 57,284 72.1% 5.7% 5.5% 5.3% 2027 335,626 45,662 12.0% 381,288 60,213 72.3% 5.8% 5.4% 5.1% 2028 354,876 47,114 11.7% 401,991 63,311 72.5% 5.7% 5.4% 5.1% 2029 375,198 48,454 11.4% 423,651 66,541 72.7% 5.7% 5.4% 5.1% 2030 396,638 49,663 11.1% 446,301 69,909 72.9% 5.7% 5.3% 5.1% 2031 419,248 50,724 10.8% 469,972 73,417 73.1% 5.7% 5.3% 5.0% 2032 443,075 51,619 10.4% 494,693 77,071 73.3% 5.7% 5.3% 5.0% 2033 468,168 52,330 10.1% 520,498 80,874 73.5% 5.7% 5.2% 4.9% 2034 494,577 52,839 9.7% 547,416 84,832 73.7% 5.6% 5.2% 4.9% 2035 522,350 53,128 9.2% 575,478 88,947 73.9% 5.6% 5.1% 4.9% 2036 551,537 53,180 8.8% 604,717 93,224 74.0% 5.6% 5.1% 4.8% 2037 582,186 52,976 8.3% 635,162 97,668 74.2% 5.6% 5.0% 4.8% 2038 614,346 52,499 7.9% 666,846 102,282 74.4% 5.5% 5.0% 4.7% LossesAssumed  Calender Year
  • 36. Final Master Plan Report 3-13 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Further details of the methodology and assumptions used in the derivation of the EEPCO demand forecast are provided in Appendix E. As the EEPCO demand forecast only covered the period to 2030, we have extended the current national forecast to cover the whole of the planning horizon of this study. In order to extend the existing Moderate I forecast we have adopted generation and peak demand growth rate assumptions. The extended EEPCO base case demand forecast (Moderate I scenario) is presented in Table 3-9 below. We believe the econometric model used to derive the above forecast to be typical of most econometric models. Whilst we find no issue with the methodology adopted to derive the national demand forecast, it should be noted that we consider the resulting demand forecast to be high. The assumed underlying GDP growth rate would result in a level of real GDP that is 5 times its current value in 2030, but almost 10 times its current value in 2038. Even in very favourable global and local market conditions the assumed level of GDP growth would be very difficult to achieve. Peak demand is estimated to increase at an average annual rate of 10.6 per cent per annum between 2008 and 2038. An average annual increase in peak demand of this nature would require a significant amount of annual investment in generation, transmission and distribution. A full description of the EEPCO demand forecast is provided in Appendix E.
  • 37. Final Master Plan Report 3-14 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-9 Extended EEPCO Demand Forecast for Ethiopia (Base Case – Moderate I Scenario) 3.6 Kenya In recent years the MoE in Kenya have developed annual demand forecasts as part of their Least Cost Power Development Plan (LCPDP). The two most recent forecasts are contained in the 2008 and the 2009 LCPDP. Base, high and low demand forecast scenarios were developed, but we focus our review on the base case scenario in each LCPDP study. Generation Sent Out Peak Demand Load Factor Generation Growth Rate Peak Demand Growth Rate (GWh) (MW) (%) (%) (%) 2009 4,828 1,201 45.9% 2010 5,620 1,398 45.9% 16.4% 16.4% 2011 6,325 1,573 45.9% 12.5% 12.5% 2012 7,083 1,762 45.9% 12.0% 12.0% 2013 7,897 1,964 45.9% 11.5% 11.5% 2014 8,816 2,193 45.9% 11.6% 11.6% 2015 9,823 2,443 45.9% 11.4% 11.4% 2016 10,917 2,715 45.9% 11.1% 11.1% 2017 12,038 2,994 45.9% 10.3% 10.3% 2018 13,182 3,279 45.9% 9.5% 9.5% 2019 14,374 3,575 45.9% 9.0% 9.0% 2020 15,610 3,883 45.9% 8.6% 8.6% 2021 16,888 4,201 45.9% 8.2% 8.2% 2022 18,265 4,543 45.9% 8.2% 8.2% 2023 19,750 4,912 45.9% 8.1% 8.1% 2024 21,351 5,311 45.9% 8.1% 8.1% 2025 23,079 5,741 45.9% 8.1% 8.1% 2026 24,944 6,204 45.9% 8.1% 8.1% 2027 26,958 6,705 45.9% 8.1% 8.1% 2028 29,134 7,247 45.9% 8.1% 8.1% 2029 31,486 7,832 45.9% 8.1% 8.1% 2030 34,030 8,464 45.9% 8.1% 8.1% 2031 36,787 9,150 45.9% 8.1% 8.1% 2032 39,766 9,891 45.9% 8.1% 8.1% 2033 42,987 10,692 45.9% 8.1% 8.1% 2034 46,469 11,558 45.9% 8.1% 8.1% 2035 50,233 12,495 45.9% 8.1% 8.1% 2036 54,302 13,507 45.9% 8.1% 8.1% 2037 58,701 14,601 45.9% 8.1% 8.1% 2038 63,455 15,783 45.9% 8.1% 8.1% Year Moderate I
  • 38. Final Master Plan Report 3-15 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 2008 LCPDP The demand forecast contained within the 2008 LCPDP covers the period 2008 to 2030. The projection of power and energy demand was made through the use of the Model for Analysis of Energy Demand (MAED). The MAED model is an end-use forecast model that is designed to evaluate medium and long-term demand for energy in a country (or in a region). As the LCPDP demand forecast only covered the period to 2030, we have extended the current national forecast to the end of the planning horizon of this study. In order to extend the existing forecast we have used trend line analysis to identify existing trends in both the generation sent out and peak demand forecasts and used the resulting mathematical trend line formulae to project the forecast for the additional 8 years required. The extended 2008 LCPDP base case demand forecast is presented in Table 3-10. The MAED model used to derive the 2008 LCPDP demand forecast provides a robust end- user demand forecasting tool. We understand that the underpinning assumption behind the MAED model is the GDP growth forecasts. In the base case, an unfaltering GDP growth rate of 10 per cent per annum for the years 2013 to 2030 is assumed. Even in very favourable global and local market conditions this level of GDP growth would be very difficult to achieve. Furthermore, historical analysis of GDP growth statistics in countries worldwide indicates that this level of sustained economic growth has rarely occurred and can rarely be sustained without (i) vast, new mineral reserves being discovered or, (ii) a significant increase in Foreign Direct Investment (FDI). An average annual increase in demand of around 9 per cent per annum would also require a significant amount of annual investment in generation, transmission and distribution. A full description of the 2008 LCPDP demand forecast is provided in Appendix F.
  • 39. Final Master Plan Report 3-16 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-10 Extended 2008 LCPDP Demand Forecast for Kenya (Base Case) 2009 LCPDP The demand forecast developed for the 2009 LCPDP covers the period 2010 to 2030. In contrast to the 2008 LCPDP, the projections of power and energy demand in the 2009 LCPDP were made through the use of the Microsoft E-views econometric software. As the LCPSP demand forecast only covered the period to 2030, we have extended the current national forecast to the end of the planning horizon of this study. In order to extend the existing forecast we have maintained a constant growth rate in sales, generation and peak demand of 14.3 per cent per annum for the remainder of the planning period. The extended demand forecast (base case only) is presented in Table 3-11 below. Generation Peak Demand Load Factor Generation Peak Demand (GWh) (MW) (%) (%) (%) 2008 7,676 1,194 73.4% 2009 8,140 1,313 70.8% 6.0% 10.0% 2010 8,954 1,445 70.8% 10.0% 10.0% 2011 9,847 1,589 70.8% 10.0% 10.0% 2012 10,830 1,747 70.8% 10.0% 10.0% 2013 12,134 1,958 70.8% 12.0% 12.0% 2014 13,739 2,193 71.5% 13.2% 12.0% 2015 15,390 2,456 71.5% 12.0% 12.0% 2016 16,743 2,672 71.5% 8.8% 8.8% 2017 17,988 2,871 71.5% 7.4% 7.4% 2018 19,327 3,085 71.5% 7.4% 7.4% 2019 20,765 3,314 71.5% 7.4% 7.4% 2020 22,310 3,561 71.5% 7.4% 7.4% 2021 24,187 3,860 71.5% 8.4% 8.4% 2022 26,222 4,185 71.5% 8.4% 8.4% 2023 28,428 4,537 71.5% 8.4% 8.4% 2024 30,723 4,919 71.3% 8.1% 8.4% 2025 33,307 5,333 71.3% 8.4% 8.4% 2026 35,936 5,753 71.3% 7.9% 7.9% 2027 38,786 6,210 71.3% 7.9% 7.9% 2028 41,831 6,697 71.3% 7.9% 7.9% 2029 45,217 7,227 71.4% 8.1% 7.9% 2030 48,775 7,795 71.4% 7.9% 7.9% 2031 52,412 8,393 71.3% 7.5% 7.7% 2032 56,402 9,037 71.2% 7.6% 7.7% 2033 60,651 9,723 71.2% 7.5% 7.6% 2034 65,170 10,453 71.2% 7.4% 7.5% 2035 69,968 11,229 71.1% 7.4% 7.4% 2036 75,058 12,053 71.1% 7.3% 7.3% 2037 80,450 12,927 71.0% 7.2% 7.2% 2038 86,154 13,852 71.0% 7.1% 7.2% Assumed  Calender Year
  • 40. Final Master Plan Report 3-17 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-11 Extended 2009 LCPDP Demand Forecast (Base Case) As previously stated, we believe that it is unrealistic to assume a five to seven fold increase in GDP between now and 2030 unless major new mineral reserves are discovered or FDI contributions increase manifold. It should be noted that there is a considerable difference between the 2008 and the 2009 LCPDP demand forecasts. Although the key input assumptions remain largely unchanged, the 2009 LCPDP forecast is considerably higher than the 2008 LCPDP forecast. The marked difference in projected load levels can only be attributed to the change to the adopted forecasting methodology and model. Furthermore, the out-turn demand for electricity in Kenya in 2009 indicates growth at a slower rate than that projected in the 2008 LCPDP. This would seem to indicate that the 2009 LCPDP forecast should have been more conservative with the assumptions. Our Generation Peak Demand Load Factor Generation Peak Demand (GWh) (MW) (%) (%) (%) 2009 7,391 1,205 70.0% 2010 7,838 1,278 70.0% 6.0% 6.1% 2011 8,292 1,352 70.0% 5.8% 5.8% 2012 8,916 1,454 70.0% 7.5% 7.5% 2013 9,692 1,581 70.0% 8.7% 8.7% 2014 10,935 1,783 70.0% 12.8% 12.8% 2015 12,495 2,038 70.0% 14.3% 14.3% 2016 14,278 2,328 70.0% 14.3% 14.2% 2017 16,315 2,661 70.0% 14.3% 14.3% 2018 18,643 3,040 70.0% 14.3% 14.2% 2019 21,303 3,474 70.0% 14.3% 14.3% 2020 24,342 3,970 70.0% 14.3% 14.3% 2021 27,815 4,536 70.0% 14.3% 14.3% 2022 31,783 5,183 70.0% 14.3% 14.3% 2023 36,318 5,923 70.0% 14.3% 14.3% 2024 41,500 6,768 70.0% 14.3% 14.3% 2025 47,421 7,733 70.0% 14.3% 14.3% 2026 54,186 8,837 70.0% 14.3% 14.3% 2027 61,917 10,097 70.0% 14.3% 14.3% 2028 70,751 11,538 70.0% 14.3% 14.3% 2029 80,846 13,184 70.0% 14.3% 14.3% 2030 92,380 15,065 70.0% 14.3% 14.3% 2031 105,560 17,214 70.0% 14.3% 14.3% 2032 120,620 19,670 70.0% 14.3% 14.3% 2033 137,829 22,477 70.0% 14.3% 14.3% 2034 157,493 25,683 70.0% 14.3% 14.3% 2035 179,963 29,348 70.0% 14.3% 14.3% 2036 205,638 33,535 70.0% 14.3% 14.3% 2037 234,976 38,319 70.0% 14.3% 14.3% 2038 268,500 43,786 70.0% 14.3% 14.3% Assumed  Calender Year
  • 41. Final Master Plan Report 3-18 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study analysis of the results of the two forecasts shows that this is not the case and we would question the validity of this forecast. A full description of the 2009 LCPDP demand forecast is provided in Appendix F. 3.7 Rwanda The latest national demand forecast available for Rwanda was produced by RSWI and Fichtner in October 2008 as part of the Nile Basin Initiative (NBI) Nile Equatorial Lakes Subsidiary Action Program (NELSAP) study on the Electricity Transmission Lines linked to the Rusumo Falls Hydro-Electric Generation Plant. The Rwandan NELSAP demand forecast was developed in tandem with demand forecasts for Tanzania and Burundi. The objective of the demand forecast was to develop an end-user model, which focused on the structure of the different electricity consumer groups and their specific consumption. It should be noted, however, that some elements of trend-line and econometric techniques have also been taken into consideration. As the NELSAP demand forecast only covered the period to 2025, we have extended the current national forecast to the end of the planning horizon for this study. In order to extend the existing forecast we have used trend line analysis to identify existing trends in the sent out generation and peak demand forecasts and used the resulting mathematical trend line formulas to project the forecast for the additional 13 years required. Further details of the methodology and assumptions used in the derivation of the NELSAP demand forecast are provided in Appendix G. We consider the assumed growth rates in peak demand and generation to be very high, with average annual growth around 11 per cent per annum. Growth rates of this magnitude require massive amounts of coordinated investment in infrastructure and while “technically” possible, in our view, we do not believe this is likely to be achieved under a base case scenario. Given our concerns with the base case demand forecast detailed above, we have not reviewed the other demand forecast scenarios developed as part of the 2009 LCPDP.
  • 42. Final Master Plan Report 3-19 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-12 Extended NELSAP Demand Forecast for Rwanda (Base Case) Generation Peak Demand Load Factor (GWh) (MW) (%) 1998 186.8 37.0 57.6% 1999 189.7 37.6 57.6% 2000 192.6 38.1 57.6% 2001 195.5 38.7 57.6% 2002 198.3 39.3 57.6% 2003 201.2 39.9 57.6% 2004 204.1 40.4 57.6% 2005 207.0 41.0 57.6% 2006 231.6 45.4 58.2% 2007 256.2 49.8 58.7% 2008 280.8 54.2 59.1% 2009 305.4 58.6 59.5% 2010 330.0 63.0 59.8% 2011 386.2 73.4 60.1% 2012 442.4 83.8 60.3% 2013 498.6 94.2 60.4% 2014 554.8 104.6 60.5% 2015 611.0 115.0 60.7% 2016 697.4 131.8 60.4% 2017 783.8 148.6 60.2% 2018 870.2 165.4 60.1% 2019 956.6 182.2 59.9% 2020 1043.0 199.0 59.8% 2021 1161.8 224.8 59.0% 2022 1280.6 250.6 58.3% 2023 1399.4 276.4 57.8% 2024 1518.2 302.2 57.3% 2025 1637.0 328.0 57.0% 2026 1780.5 355.8 57.1% 2027 1922.5 385.7 56.9% 2028 2070.7 417.0 56.7% 2029 2225.0 449.7 56.5% 2030 2385.4 483.8 56.3% 2031 2552.0 519.3 56.1% 2032 2724.7 556.1 55.9% 2033 2903.6 594.3 55.8% 2034 3088.6 633.9 55.6% 2035 3279.7 674.9 55.5% 2036 3477.0 717.3 55.3% 2037 3680.4 761.0 55.2% 2038 3890.0 806.1 55.1% Year Historic Data NELSAP National Plan PB Extension
  • 43. Final Master Plan Report 3-20 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 3.8 Sudan In 2005, PB were commissioned with the task of developing a LTPSP study for the whole of Sudan, which included an extensive end-user survey based demand forecast. A variety of methodologies have been utilised to derive the demand forecasts for the LTPSP study, primarily based around the results of the detailed market survey performed by NEC. Forecasts for the domestic and agricultural forecasts use end-use approaches. From the results of the household energy survey, average electricity consumption patterns were identified on a state by state and urban rural/basis for each of the 7 income categories identified in the survey. An end-use demand forecast model was developed to calculate changes in total domestic consumption as household income and electrification rates increase respectively. The short-term demand forecast for the large commercial and industrial sector is based upon production output forecasts from existing NEC customers. In the medium-term the load from committed large commercial and industrial projects are added to the underlying growth of existing customers and in the long-term the energy and electricity requirements to serve the growing economy in Sudan are used as the driving parameters to estimate future electricity demands. Growth in demand for the small commercial and Government sectors are based upon estimates of customer numbers and specific consumption per customer. The forecasts for each consumer category were developed on a state by state basis. The electricity forecasts for total generation (GWh) and peak demand (MW) at the sent-out generation level are derived from the application of power and energy losses to the total sector sales forecasts presented above and the application of appropriate coincident after diversity load factors. Further details of the methodology and assumptions used in the derivation of the LTPSP demand forecast are provided in Appendix H. As the LTPSP demand forecast only covered the period to 2030, we have extended the current national forecast to the end of the planning horizon for this study. In order to extend the existing forecast we have used trend line analysis to identify existing trends in both electricity sales and peak demand forecasts and used the resulting mathematical trend line formulae to project the forecast for the additional 8 years required. The extended LTPSP base case demand forecast is presented below in Table 3-13.
  • 44. Final Master Plan Report 3-21 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 3-13 Extended LTPSP Demand Forecast for Sudan (Base Case) The demand forecast developed as part of the LTPSP study was an end-user forecast based on an extensive survey. The survey results provided an indication of the patterns, requirements and uses of electricity in Sudan at the time. The end-user methodology adopted to develop the demand forecast is reasonable for determining the future load in Sudan. A key component in determining the demand for electricity into the future however, is the electrification rate. At the time of the study, NEC declared that they would invest significantly in increasing the number of connections to the grid and this led to the assumption that 80 per cent of the country would be connected to the grid by 2025. As the LTPSP study specifically states, “Achieving the high level of demand growth is heavily reliant on the successful completion of the stated electrification projects across the whole of the country. We note that the number of connections required on an annual basis are significantly higher than have been achieved historically. NEC are confident that they will be able to achieve these electrification rates and to fulfil the Government’s policy. Failure to complete these projects and/or lower growth rates in final connection to the distribution networks by households will inevitably lead to lower outturn levels of electricity demand than shown here.” In the 5 years since the demand forecast was first developed, it is apparent that NEC have not reached the levels of electrification that were assumed in the study. While the level of growth experienced in Sudan is very high and commendable, this is significantly below the forecast figure and indicates that NEC fell short of its own targets. Sales Generation Peak Demand Load Factor Sales Generation Peak Demand (GWh) (GWh) (%) (GWh) (MW) (%) (%) (%) (%) 2006 6,371 2,067 24.5% 8,438 1,475 65.3% 2007 10,483 3,220 23.5% 13,704 2,244 69.7% 64.5% 62.4% 52.1% 2008 14,596 4,237 22.5% 18,833 3,013 71.4% 39.2% 37.4% 34.3% 2009 18,708 5,124 21.5% 23,832 3,781 71.9% 28.2% 26.5% 25.5% 2010 22,820 5,884 20.5% 28,704 4,550 72.0% 22.0% 20.4% 20.3% 2011 25,088 6,077 19.5% 31,166 4,979 71.5% 9.9% 8.6% 9.4% 2012 27,357 6,417 19.0% 33,774 5,407 71.3% 9.0% 8.4% 8.6% 2013 29,625 6,725 18.5% 36,350 5,836 71.1% 8.3% 7.6% 7.9% 2014 31,894 7,001 18.0% 38,895 6,264 70.9% 7.7% 7.0% 7.3% 2015 34,162 7,246 17.5% 41,408 6,693 70.6% 7.1% 6.5% 6.8% 2016 36,731 7,523 17.0% 44,254 7,153 70.6% 7.5% 6.9% 6.9% 2017 39,300 7,766 16.5% 47,066 7,614 70.6% 7.0% 6.4% 6.4% 2018 41,869 7,975 16.0% 49,844 8,074 70.5% 6.5% 5.9% 6.0% 2019 44,438 8,151 15.5% 52,589 8,535 70.3% 6.1% 5.5% 5.7% 2020 47,007 8,295 15.0% 55,302 8,995 70.2% 5.8% 5.2% 5.4% 2021 49,700 8,429 14.5% 58,129 9,437 70.3% 5.7% 5.1% 4.9% 2022 52,393 8,529 14.0% 60,923 9,879 70.4% 5.4% 4.8% 4.7% 2023 55,087 8,597 13.5% 63,684 10,321 70.4% 5.1% 4.5% 4.5% 2024 57,780 8,634 13.0% 66,414 10,763 70.4% 4.9% 4.3% 4.3% 2025 60,473 8,639 12.5% 69,112 11,205 70.4% 4.7% 4.1% 4.1% 2026 63,292 9,042 12.5% 72,334 11,741 70.3% 4.7% 4.7% 4.8% 2027 66,111 9,444 12.5% 75,556 12,276 70.3% 4.5% 4.5% 4.6% 2028 68,931 9,847 12.5% 78,778 12,812 70.2% 4.3% 4.3% 4.4% 2029 71,750 10,250 12.5% 82,000 13,347 70.1% 4.1% 4.1% 4.2% 2030 74,569 10,653 12.5% 85,222 13,883 70.1% 3.9% 3.9% 4.0% 2031 77,383 11,055 12.5% 88,437 14,327 70.5% 3.8% 3.8% 3.2% 2032 80,208 11,458 12.5% 91,666 14,847 70.5% 3.7% 3.7% 3.6% 2033 83,031 11,862 12.5% 94,893 15,372 70.5% 3.5% 3.5% 3.5% 2034 85,849 12,264 12.5% 98,113 15,902 70.4% 3.4% 3.4% 3.4% 2035 88,658 12,665 12.5% 101,323 16,437 70.4% 3.3% 3.3% 3.4% 2036 91,456 13,065 12.5% 104,521 16,977 70.3% 3.2% 3.2% 3.3% 2037 94,239 13,463 12.5% 107,702 17,522 70.2% 3.0% 3.0% 3.2% 2038 97,005 13,858 12.5% 110,863 18,072 70.0% 2.9% 2.9% 3.1% Assumed  Calender Year Losses
  • 45. Final Master Plan Report 3-22 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 3.9 Tanzania In December 2007 SNC published their Power System Master Plan (PSMP) study report. This study was carried out for TANESCO on behalf of The Government of the United Republic of Tanzania. In 2009, an updated PSMP demand forecast was developed by TANESCO experts, under the supervision of SNC during an ‘on-the-job’ training course. For this study, we consider the regional extrapolation/trend line demand forecast to be the ‘official’ forecast of demand. The regional load forecast was carried out in four steps: • Derive a forecast of sales for the load centres area using a trend-line approach in which the trends in number of customers and the unit consumption in each category of load are studied and projected; • Assess the impact of the issues specific to Tanzania; • Estimate the losses and derive the energy required; • Estimate the load factors that would apply in an unconstrained system. The process to be used for the trend-line forecast will consist of the following steps: • For each category for which data are available, tabulate the number of customers, the sales and the unit consumption for the full historical period available (roughly twenty years) • Plot the above data • Review the data and the graphs derived from it to assess anomalies and trends • Either correct anomalies or obtain explanations for them • Project the number of customers for the period taking account of issues likely to have an impact on growth (e.g. rural electrification policies) • Project the unit consumption for the same period taking account of issues likely to have an impact on growth (e.g. the removal of constraints on generation) • Multiply the unit consumption in each year by the number of customers forecast for that year to obtain the estimated sales Further details of the methodology and assumptions used in the derivation of the PSMP demand forecast are provided in Appendix I. As the PSMP demand forecast only covered the period to 2033, we have extended the current national forecast to the end of the planning horizon for this study. In order to extend the existing forecast we have used trend line analysis to identify existing trends in both the generation sent out and peak demand forecasts and used the resulting mathematical trend line formulae to project the forecast for the additional 5 years required. We believe the methodology employed to determine the PSMP demand forecast is robust and in line with demand forecasting best-practice. The PSMP demand forecast projects an average annual increase in peak demand of around 7.2 per cent. An average annual growth rate of this figures results in a 7 fold increase over the 28 year period. Similar growth rates are projected for sent out generation. An average annual increase in peak demand/generation of this nature would require a significant amount of annual investment in generation, transmission and distribution. If such a large amount of investment is required to fund the new generation, transmission and distribution projects required in order to meet this demand, then less money would be available for investment in other sectors of the economy, and this in turn would cast doubts on the ability of other
  • 46. Final Master Plan Report 3-23 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study sectors to grow at the rates required to achieve the high growth rates predicated in the demand forecast. It should be noted however, that the Government of Tanzania has identified 5 key areas of strategic importance (of which Energy Infrastructure is one) in its medium-term Public Investment Plan (MPIP) for the period 2009/10 to 2014/15. The MPIP highlights the importance of fast-tracking the flow of public investment into the energy infrastructure industry so as to stimulate increased participation of other key players in the Tanzanian economy. This suggest that Government will do all it can to ensure funds are available to allow the energy sector to develop in line with the demand forecast developed as part of the PSMP. Table 3-14 Extended PSMP Demand Forecast for Tanzania (Base Case) 3.10 Uganda The latest demand forecast available for Uganda was developed by PB as part of the on- going Power Sector Investment Plan (PSIP) study. The PSIP demand forecast projects demand for electricity over the period 2008 to 2038 for three different scenarios; base, high and low. The PSIP demand forecast is derived using PB’s econometric based RALF model. Generation Peak Demand Load Factor (GWh) (MW) (%) 2010 5,293 895 67.5% 2011 5,773 981 67.2% 2012 6,439 1,103 66.7% 2013 7,081 1,213 66.6% 2014 7,489 1,285 66.5% 2015 8,135 1,398 66.5% 2016 8,987 1,542 66.5% 2017 9,895 1,698 66.5% 2018 10,704 1,839 66.5% 2019 11,326 1,945 66.5% 2020 11,994 2,061 66.4% 2021 12,701 2,182 66.5% 2022 13,440 2,311 66.4% 2023 14,398 2,479 66.3% 2024 15,245 2,628 66.2% 2025 16,145 2,783 66.2% 2026 17,112 2,953 66.1% 2027 18,116 3,131 66.0% 2028 19,379 3,353 66.0% 2029 20,536 3,558 65.9% 2030 21,745 3,770 65.8% 2031 23,042 4,002 65.7% 2032 24,449 4,254 65.6% 2033 26,164 4,532 65.9% 2034 27,917 4,838 65.9% 2035 29,854 5,168 65.9% 2036 31,978 5,527 66.1% 2037 34,311 5,918 66.2% 2038 36,873 6,344 66.4% Assumed  Calender Year
  • 47. Final Master Plan Report 3-24 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Further details of the methodology and assumptions used in the derivation of the PSIP demand forecast are provided in Appendix J. The base, high and low PSIP demand forecasts are presented below in Table 3-15. Table 3-15 PSIP Demand Forecasts for Uganda (Base, High and Low Cases) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2009 2784 541 58.7% 2877 561 58.5% 3397 597 65.0% 2010 2901 570 58.1% 3026 596 58.0% 3982 702 64.8% 2011 3012 597 57.6% 3188 633 57.5% 4564 805 64.7% 2012 3121 623 57.2% 3371 673 57.2% 5146 908 64.7% 2013 3203 643 56.9% 3560 715 56.8% 5663 998 64.8% 2014 3279 662 56.5% 3788 764 56.6% 6165 1084 64.9% 2015 3351 679 56.3% 4030 816 56.4% 6651 1167 65.1% 2016 3419 695 56.2% 4288 871 56.2% 7122 1247 65.2% 2017 3481 710 56.0% 4561 929 56.0% 7577 1324 65.3% 2018 3540 724 55.8% 4851 990 55.9% 8018 1398 65.5% 2019 3622 741 55.8% 5123 1045 56.0% 8518 1480 65.7% 2020 3676 750 56.0% 5362 1091 56.1% 8977 1551 66.1% 2021 3778 772 55.9% 5685 1158 56.0% 9537 1647 66.1% 2022 3913 800 55.8% 6056 1233 56.1% 10178 1759 66.1% 2023 4048 828 55.8% 6434 1310 56.1% 10831 1873 66.0% 2024 4184 857 55.7% 6821 1389 56.1% 11497 1990 66.0% 2025 4321 886 55.7% 7216 1470 56.0% 12175 2109 65.9% 2026 4459 915 55.6% 7620 1552 56.0% 12867 2231 65.8% 2027 4598 944 55.6% 8031 1636 56.0% 13570 2355 65.8% 2028 4738 973 55.6% 8450 1722 56.0% 14287 2482 65.7% 2029 4880 1003 55.5% 8878 1809 56.0% 15016 2612 65.6% 2030 5022 1033 55.5% 9313 1898 56.0% 15757 2744 65.6% 2031 5065 1032 56.0% 9754 1978 56.3% 16548 2883 65.5% 2032 5246 1069 56.0% 10203 2069 56.3% 17348 3025 65.5% 2033 5428 1107 56.0% 10659 2162 56.3% 18156 3168 65.4% 2034 5611 1145 55.9% 11123 2257 56.3% 18972 3312 65.4% 2035 5796 1184 55.9% 11594 2353 56.2% 19797 3459 65.3% 2036 5982 1223 55.8% 12072 2450 56.2% 20629 3607 65.3% 2037 6170 1262 55.8% 12559 2549 56.2% 21470 3757 65.2% 2038 6358 1301 55.8% 13052 2650 56.2% 22319 3908 65.2% PB High CasePB Base CasePB Low Case Year
  • 48. Final Master Plan Report 4-1 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4. INDEPENDENT PB DEMAND FORECASTS In this section of the report we outline the independent PB demand forecasts developed specifically using the data made available for this study. Further details of each review are provided in the respective Appendices provided with this report. 4.1 Burundi In addition to reviewing the most recent national demand forecast available for Burundi, we have produced our own base; high and low national demand forecast scenarios. These scenarios are based upon our own assumptions and methodology, utilising the data collected/made available as part of this study. Due to the lack of economic data as well as the unavailability of sales by consumer category, this forecast has been developed on the basis of the country electrification rate, an assumed level of specific consumption, an assumption relating to the number of persons per household and a population forecast provided by the UN. High and low demand forecast scenarios have also been developed. These forecasts differ from the base case demand forecast having adopted different assumptions relating to the rate of electrification and population for the derivation of total sales. Details of the methodology employed and any assumptions made are provided in Appendix A. The base, high and low independent PB demand forecasts are presented in Table 4-1 and summarised in Figure 4-1 and Figure 4-2 below.
  • 49. Final Master Plan Report 4-2 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 4-1 PB Base, High and Low Demand Forecast for Burundi (GWh) (MW) LF (%) (GWh) (MW) LF (%) (GWh) (MW) LF (%) 2008 93.6 28.9 36.9% 93.6 28.9 36.9% 93.6 28.9 36.9% 2009 98.2 29.6 37.9% 98.2 29.6 37.9% 98.2 29.6 37.9% 2010 102.2 30.0 38.9% 102.2 30.0 38.9% 102.2 30.0 38.9% 2011 119.9 34.3 39.9% 124.3 35.6 39.9% 132.8 38.0 39.9% 2012 138.0 38.5 40.9% 146.9 41.0 40.9% 164.3 45.9 40.9% 2013 156.4 42.6 41.9% 170.0 46.3 41.9% 196.5 53.5 41.9% 2014 175.1 46.6 42.9% 193.6 51.5 42.9% 229.6 61.1 42.9% 2015 194.2 50.5 43.9% 217.6 56.6 43.9% 263.4 68.5 43.9% 2016 213.3 54.2 44.9% 242.2 61.6 44.9% 298.5 75.9 44.9% 2017 232.7 57.9 45.9% 267.3 66.5 45.9% 334.4 83.2 45.9% 2018 252.4 61.4 46.9% 292.8 71.3 46.9% 371.1 90.3 46.9% 2019 272.3 64.9 47.9% 318.8 76.0 47.9% 408.6 97.4 47.9% 2020 292.5 68.3 48.9% 345.2 80.6 48.9% 446.9 104.3 48.9% 2021 312.3 71.4 49.9% 371.6 85.0 49.9% 485.9 111.2 49.9% 2022 332.2 74.5 50.9% 398.3 89.3 50.9% 525.6 117.9 50.9% 2023 352.4 77.5 51.9% 425.5 93.6 51.9% 566.0 124.5 51.9% 2024 372.7 80.4 52.9% 453.0 97.7 52.9% 607.1 131.0 52.9% 2025 393.1 83.3 53.9% 480.8 101.8 53.9% 648.9 137.4 53.9% 2026 413.2 85.9 54.9% 508.4 105.7 54.9% 690.7 143.6 54.9% 2027 433.4 88.5 55.9% 536.3 109.5 55.9% 733.1 149.7 55.9% 2028 453.6 91.0 56.9% 564.4 113.2 56.9% 776.1 155.7 56.9% 2029 474.0 93.5 57.9% 592.8 116.9 57.9% 819.7 161.6 57.9% 2030 494.5 95.8 58.9% 621.5 120.5 58.9% 863.8 167.4 58.9% 2031 514.7 98.1 59.9% 650.2 123.9 59.9% 908.5 173.1 59.9% 2032 534.9 100.3 60.9% 679.0 127.3 60.9% 953.7 178.8 60.9% 2033 555.1 102.4 61.9% 708.1 130.6 61.9% 999.4 184.3 61.9% 2034 575.5 104.4 62.9% 737.5 133.8 62.9% 1,045.6 189.8 62.9% 2035 595.9 106.5 63.9% 767.0 137.0 63.9% 1,092.4 195.2 63.9% 2036 616.0 108.3 64.9% 796.9 140.2 64.9% 1,140.7 200.6 64.9% 2037 636.1 110.2 65.9% 826.9 143.2 65.9% 1,189.5 206.1 65.9% 2038 656.2 112.0 66.9% 857.1 146.3 66.9% 1,238.9 211.4 66.9% PB Low Case PB Base Case PB High Case Year
  • 50. Final Master Plan Report 4-3 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-1 PB Peak Demand Forecast for Burundi (MW) Figure 4-2 PB Sent Out Generation Forecast for Burundi (GWh) 0 50 100 150 200 250 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Peak Demand (MW) PB Low Case PB Base Case PB High Case 0 200 400 600 800 1000 1200 1400 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Generation (GWh) PB Low Case PB Base Case PB High Case
  • 51. Final Master Plan Report 4-4 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4.2 Djibouti The most recent national demand forecast available for Djibouti was developed by PB in 2009 as part of the LCEMP study. The forecasts developed for the LCEMP study (as discussed in Section 5 and Appendix B of this report) are representative of PB’s independent view of electrical demand growth in Djibouti. The base, high and low LCEMP demand forecasts are presented in Table 4-2 and summarised in Figure 4-3 and Figure 4-4 below. Table 4-2 PB Base, High and Low Demand Forecast for Djibouti Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2005 210 50 47.9% 210 50 47.9% 210 50 47.9% 2006 217 52 48.0% 220 52 48.0% 222 53 48.0% 2007 224 53 48.0% 229 54 48.1% 234 56 48.1% 2008 232 55 48.0% 240 57 48.1% 247 59 48.2% 2009 240 57 48.0% 251 59 48.2% 261 62 48.2% 2010 248 59 48.0% 262 62 48.2% 275 65 48.3% 2011 258 61 48.0% 275 65 48.2% 291 69 48.3% 2012 269 64 48.0% 289 68 48.2% 309 73 48.3% 2013 280 66 48.0% 303 72 48.3% 328 77 48.3% 2014 291 69 48.0% 318 75 48.3% 347 82 48.3% 2015 303 72 48.0% 334 79 48.3% 368 87 48.3% 2016 316 75 48.0% 352 83 48.3% 392 93 48.3% 2017 330 79 47.9% 372 88 48.3% 417 99 48.3% 2018 345 82 47.8% 392 93 48.3% 444 105 48.3% 2019 360 86 47.8% 413 98 48.3% 473 112 48.3% 2020 376 90 47.7% 436 103 48.3% 504 119 48.3% 2021 393 95 47.4% 461 109 48.4% 538 127 48.4% 2022 411 99 47.3% 487 115 48.4% 573 135 48.4% 2023 429 104 47.1% 515 121 48.4% 612 144 48.5% 2024 449 109 47.0% 545 128 48.5% 653 154 48.5% 2025 469 115 46.8% 576 136 48.5% 696 164 48.6% 2026 491 120 46.6% 610 143 48.5% 742 174 48.6% 2027 513 126 46.4% 645 152 48.6% 792 186 48.6% 2028 536 132 46.2% 682 160 48.6% 844 198 48.7% 2029 560 139 46.0% 722 169 48.7% 900 211 48.8% 2030 585 146 45.7% 764 179 48.7% 959 224 48.8% 2031 611 153 45.5% 808 189 48.8% 1021 238 48.9% 2032 638 161 45.3% 855 200 48.8% 1087 254 48.9% 2033 666 169 45.0% 904 211 48.9% 1156 269 49.0% 2034 696 177 44.8% 955 223 48.9% 1229 286 49.0% 2035 726 186 44.6% 1009 235 49.0% 1306 304 49.1% 2036 757 195 44.3% 1066 248 49.0% 1387 322 49.2% 2037 790 205 44.1% 1125 262 49.1% 1472 341 49.2% 2038 823 214 43.8% 1187 276 49.2% 1561 362 49.3% PB High CasePB Base CasePB Low Case Year
  • 52. Final Master Plan Report 4-5 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-3 PB Peak Demand Forecast for Djibouti (MW) Figure 4-4 PB Sent Out Generation Forecast for Djibouti (GWh) 0 50 100 150 200 250 300 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 Peak Demand (MW) PB Low Case PB Base Case PB High Case 0 200 400 600 800 1000 1200 1400 1600 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 Generation (GWh) PB Low Case PB Base Case PB High Case
  • 53. Final Master Plan Report 4-6 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4.3 DRC The most recent national demand forecast available for East DRC was developed by RSWI in October 2007. Projections of demand for the eastern region of DRC are very hard to develop given the lack of reliable and consistent historical data. The projected growth rates assumed in the RSWI forecast for the base, high and low scenarios are reasonable and not overly optimistic given the potential for development in the region and therefore we see no need to produce an independent forecast of demand for the Eastern region of the DRC. The base, high and low RSWI demand forecasts are presented in Table 4-3 and summarised in Figure 4-5 and Figure 4-6 below. Table 4-3 RSWI Base, High and Low Demand Forecast for East DRC Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2005 210 50 47.9% 210 50 47.9% 210 50 47.9% 2006 217 52 48.0% 220 52 48.0% 222 53 48.0% 2007 224 53 48.0% 229 54 48.1% 234 56 48.1% 2008 232 55 48.0% 240 57 48.1% 247 59 48.2% 2009 240 57 48.0% 251 59 48.2% 261 62 48.2% 2010 248 59 48.0% 262 62 48.2% 275 65 48.3% 2011 258 61 48.0% 275 65 48.2% 291 69 48.3% 2012 269 64 48.0% 289 68 48.2% 309 73 48.3% 2013 280 66 48.0% 303 72 48.3% 328 77 48.3% 2014 291 69 48.0% 318 75 48.3% 347 82 48.3% 2015 303 72 48.0% 334 79 48.3% 368 87 48.3% 2016 316 75 48.0% 352 83 48.3% 392 93 48.3% 2017 330 79 47.9% 372 88 48.3% 417 99 48.3% 2018 345 82 47.8% 392 93 48.3% 444 105 48.3% 2019 360 86 47.8% 413 98 48.3% 473 112 48.3% 2020 376 90 47.7% 436 103 48.3% 504 119 48.3% 2021 393 95 47.4% 461 109 48.4% 538 127 48.4% 2022 411 99 47.3% 487 115 48.4% 573 135 48.4% 2023 429 104 47.1% 515 121 48.4% 612 144 48.5% 2024 449 109 47.0% 545 128 48.5% 653 154 48.5% 2025 469 115 46.8% 576 136 48.5% 696 164 48.6% 2026 491 120 46.6% 610 143 48.5% 742 174 48.6% 2027 513 126 46.4% 645 152 48.6% 792 186 48.6% 2028 536 132 46.2% 682 160 48.6% 844 198 48.7% 2029 560 139 46.0% 722 169 48.7% 900 211 48.8% 2030 585 146 45.7% 764 179 48.7% 959 224 48.8% 2031 611 153 45.5% 808 189 48.8% 1021 238 48.9% 2032 638 161 45.3% 855 200 48.8% 1087 254 48.9% 2033 666 169 45.0% 904 211 48.9% 1156 269 49.0% 2034 696 177 44.8% 955 223 48.9% 1229 286 49.0% 2035 726 186 44.6% 1009 235 49.0% 1306 304 49.1% 2036 757 195 44.3% 1066 248 49.0% 1387 322 49.2% 2037 790 205 44.1% 1125 262 49.1% 1472 341 49.2% 2038 823 214 43.8% 1187 276 49.2% 1561 362 49.3% PB High CasePB Base CasePB Low Case Year
  • 54. Final Master Plan Report 4-7 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-5 RSWI Peak Demand Forecast for East DRC (MW) Figure 4-6 RSWI Sent Out Generation Forecast for East DRC (GWh) 0 50 100 150 200 250 300 350 400 2005 2008 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 Peak Demand (MW) NP Base Case NP Low Case NP High Case 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2005 2008 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 Generation (GWh) NP Base Case NP Low Case NP High Case
  • 55. Final Master Plan Report 4-8 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4.4 Egypt EEHC provided a base case demand forecast which was deemed by PB to be reasonable. However, high and low demand forecast scenarios were not provided. Therefore we have produced our own independent base, high and low national demand forecast scenarios. These base, high and low scenarios have been developed using our own assumptions and methodology, utilising the data collected/made available as part of this study. The PB demand forecasts developed for Egypt are derived using PB’s own econometric RALF model. Details of the RALF model methodology and any assumptions made are provided in Appendix D. The base, high and low independent PB demand forecasts are presented in Table 4-4 and summarised in Figure 4-7 and Figure 4-7 below. Table 4-4 PB Base, High and Low Demand Forecast for Egypt Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2007 119,920 18,500 74.0% 119920 18,500 74.0% 119920 18,500 74.0% 2008 129,019 19,855 74.2% 129244 19,882 74.2% 129301 19,888 74.2% 2009 138,043 21,269 74.1% 138749 21,354 74.2% 138925 21,375 74.2% 2010 147,555 22,762 74.0% 148801 22,911 74.1% 149114 22,949 74.2% 2011 155,948 24,056 74.0% 158939 24,462 74.2% 160571 24,706 74.2% 2012 164,702 25,404 74.0% 169608 26,093 74.2% 172702 26,565 74.2% 2013 173,827 26,809 74.0% 180827 27,806 74.2% 185538 28,530 74.2% 2014 183,335 28,272 74.0% 192618 29,603 74.3% 199106 30,605 74.3% 2015 193,237 29,795 74.0% 205001 31,489 74.3% 213439 32,794 74.3% 2016 201,942 31,120 74.1% 217293 33,353 74.4% 228850 35,147 74.3% 2017 211,552 32,608 74.1% 230819 35,430 74.4% 245824 37,766 74.3% 2018 221,522 34,152 74.0% 245015 37,608 74.4% 263789 40,537 74.3% 2019 231,862 35,753 74.0% 259906 39,892 74.4% 282790 43,467 74.3% 2020 242,582 37,413 74.0% 275519 42,286 74.4% 302871 46,563 74.3% 2021 251,968 38,855 74.0% 290830 44,624 74.4% 323881 49,799 74.2% 2022 261,645 40,341 74.0% 306828 47,065 74.4% 346047 53,212 74.2% 2023 271,620 41,873 74.1% 323538 49,613 74.4% 369418 56,809 74.2% 2024 281,901 43,450 74.1% 340984 52,271 74.5% 394043 60,597 74.2% 2025 292,494 45,075 74.1% 359192 55,043 74.5% 419974 64,584 74.2% 2026 302,394 46,584 74.1% 377231 57,779 74.5% 446473 68,650 74.2% 2027 312,313 48,104 74.1% 395681 60,586 74.6% 473932 72,874 74.2% 2028 322,494 49,663 74.1% 414865 63,501 74.6% 502737 77,302 74.2% 2029 332,941 51,263 74.1% 434804 66,529 74.6% 532938 81,943 74.2% 2030 343,661 52,904 74.2% 455525 69,674 74.6% 564588 86,805 74.2% 2031 353,018 54,334 74.2% 475660 72,731 74.7% 597226 91,831 74.2% 2032 362,579 55,795 74.2% 496519 75,896 74.7% 631365 97,086 74.2% 2033 372,350 57,287 74.2% 518124 79,172 74.7% 667059 102,578 74.2% 2034 382,333 58,811 74.2% 540496 82,562 74.7% 704362 108,316 74.2% 2035 392,532 60,367 74.2% 563657 86,069 74.8% 743331 114,308 74.2% 2036 400,731 61,600 74.3% 586001 89,436 74.8% 784537 120,645 74.2% 2037 409,074 62,853 74.3% 609080 92,910 74.8% 827569 127,259 74.2% 2038 417,564 64,128 74.3% 632914 96,495 74.9% 872489 134,161 74.2% PB High Case Year PB Low Case PB Base Case
  • 56. Final Master Plan Report 4-9 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-7 PB Peak Demand Forecast for Egypt (MW) Figure 4-8 PB Sent Out Generation Forecast for Egypt (GWh) 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Peak Demand (MW) PB Low Case PB Base Case PB High Case 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Generation (GWh) PB Low Case PB Base Case PB High Case
  • 57. Final Master Plan Report 4-10 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4.5 Ethiopia In addition to reviewing the most recent demand forecast available for Ethiopia, we have produced our own demand forecast scenarios. These scenarios are based upon our own assumptions and methodology, utilising the data collected/made available as part of this study. In the following sub-sections we detail our alternative forecast. The Ethiopian electrical system comprises of two systems. These are the ICS system and the SCS system. We have adopted different methodologies to determine the future level of demand in each of these systems. The ICS forecasts are derived using PB’s RALF model. The SCS forecast is derived separately from the ICS utilising a simplistic sales growth assumption to project sales into the future. A loss reduction programme has been identified and losses are then added to the sales forecast to determine the level of net generation. A peak demand forecast is determined through the application of an assumed system load factor. Details of the model methodology and any assumptions made are provided in Appendix E. The base, high and low ICS demand forecasts are presented in Table 4-5 and are summarised in Figure 4-9 and Figure 4-10 below. The SCS demand forecast is presented in Table 4-6. Table 4-5 PB Base, High and Low ICS Demand Forecast for Ethiopia Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2008 3765 747 57.5% 3765 747 57.5% 3765 747 57.5% 2009 4118 810 58.0% 4118 810 58.0% 4118 810 58.0% 2010 4377 861 58.0% 4480 881 58.0% 4532 892 58.0% 2011 4707 926 58.0% 4931 970 58.0% 5045 992 58.0% 2012 5022 987 58.1% 5385 1058 58.1% 5574 1095 58.1% 2013 5356 1051 58.2% 5879 1153 58.2% 6156 1207 58.2% 2014 5722 1121 58.3% 6430 1259 58.3% 6811 1333 58.3% 2015 6066 1186 58.4% 6979 1364 58.4% 7479 1462 58.4% 2016 6431 1255 58.5% 7575 1478 58.5% 8214 1603 58.5% 2017 6818 1329 58.6% 8223 1602 58.6% 9022 1757 58.6% 2018 7228 1406 58.7% 8928 1736 58.7% 9911 1927 58.7% 2019 7663 1489 58.8% 9693 1882 58.8% 10889 2113 58.8% 2020 8125 1576 58.9% 10525 2040 58.9% 11964 2318 58.9% 2021 8537 1655 58.9% 11328 2195 58.9% 13032 2525 58.9% 2022 8969 1739 58.9% 12193 2363 58.9% 14196 2750 58.9% 2023 9424 1827 58.9% 13124 2543 58.9% 15466 2995 58.9% 2024 9902 1920 58.9% 14128 2737 58.9% 16850 3263 59.0% 2025 10404 2017 58.9% 15209 2946 58.9% 18361 3554 59.0% 2026 10867 2106 58.9% 16277 3152 59.0% 19890 3850 59.0% 2027 11349 2200 58.9% 17421 3373 59.0% 21548 4170 59.0% 2028 11854 2297 58.9% 18645 3609 59.0% 23346 4517 59.0% 2029 12381 2399 58.9% 19958 3863 59.0% 25297 4893 59.0% 2030 12931 2506 58.9% 21363 4134 59.0% 27413 5301 59.0% 2031 13425 2601 58.9% 22732 4398 59.0% 29530 5709 59.0% 2032 13937 2700 58.9% 24190 4680 59.0% 31814 6150 59.1% 2033 14469 2803 58.9% 25742 4979 59.0% 34276 6624 59.1% 2034 15021 2910 58.9% 27395 5298 59.0% 36932 7136 59.1% 2035 15595 3021 58.9% 29155 5637 59.0% 39796 7687 59.1% 2036 16190 3136 58.9% 31030 5999 59.1% 42885 8282 59.1% 2037 16809 3255 58.9% 33028 6384 59.1% 46218 8924 59.1% 2038 17451 3379 59.0% 35155 6794 59.1% 49813 9616 59.1% PB High CasePB Base CasePB Low Case Year
  • 58. Final Master Plan Report 4-11 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-9 PB ICS Peak Demand Forecast for Ethiopia (MW) Figure 4-10 PB ICS Sent Out Generation Forecast for Ethiopia (GWh) 0 2,000 4,000 6,000 8,000 10,000 12,000 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 Peak Demand (MW) PB Low Case PB Base Case PB High Case 0 10,000 20,000 30,000 40,000 50,000 60,000 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 Generation (GWh) PB Low Case PB Base Case PB High Case
  • 59. Final Master Plan Report 4-12 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 4-6 PB SCS Demand Forecast for Ethiopia 4.6 Kenya In addition to reviewing the most recent demand forecast available for Kenya, we have produced our own base, high and low national demand forecast scenarios. These scenarios are based upon our own assumptions and methodology, utilising the data collected/made available as part of this study. The demand forecasts developed for Kenya are derived using PB’s RALF model. Details of the model methodology and any assumptions made are provided in Appendix F6 . The base, high and low PB demand forecasts are presented in Table 4-7 and summarised in Figure 4-11 and Figure 4-12 below 6 It should be noted that the PB high case is based on the GDP assumptions made in the Vision 2030 report and are considered to be too high for use in this study. Year Sales (GWh) Generation (GWh) Losses (GWh) Losses (%) Peak Demand (MW) Load Factor (%) 2009 47.68 57.34 9.66 16.9% 11.38 57.5% 2010 51.01 61.35 10.34 16.9% 12.17 57.5% 2011 54.58 65.64 11.06 16.9% 13.02 57.5% 2012 58.40 70.24 11.84 16.9% 13.94 57.5% 2013 62.49 75.16 12.66 16.9% 14.91 57.5% 2014 66.87 80.42 13.55 16.9% 15.96 57.5% 2015 71.55 86.05 14.50 16.9% 17.07 57.5% 2016 76.56 92.07 15.51 16.9% 18.27 57.5% 2017 81.91 98.51 16.60 16.9% 19.55 57.5% 2018 87.65 105.41 17.76 16.9% 20.91 57.5% 2019 93.78 112.79 19.01 16.9% 22.38 57.5% 2020 100.35 120.68 20.34 16.9% 23.94 57.5% 2021 107.37 129.13 21.76 16.9% 25.62 57.5% 2022 114.89 138.17 23.28 16.9% 27.41 57.5% 2023 122.93 147.84 24.91 16.9% 29.33 57.5% 2024 131.54 158.19 26.66 16.9% 31.39 57.5% 2025 140.74 169.27 28.52 16.9% 33.58 57.5% 2026 150.60 181.11 30.52 16.9% 35.93 57.5% 2027 161.14 193.79 32.65 16.9% 38.45 57.5% 2028 172.42 207.36 34.94 16.9% 41.14 57.5% 2029 184.49 221.87 37.39 16.9% 44.02 57.5% 2030 197.40 237.40 40.00 16.9% 47.10 57.5% 2031 211.22 254.02 42.80 16.9% 50.40 57.5% 2032 226.01 271.80 45.80 16.9% 53.93 57.5% 2033 241.83 290.83 49.01 16.9% 57.70 57.5% 2034 258.75 311.19 52.44 16.9% 61.74 57.5% 2035 276.87 332.97 56.11 16.9% 66.06 57.5% 2036 296.25 356.28 60.03 16.9% 70.69 57.5% 2037 316.98 381.22 64.24 16.9% 75.64 57.5% 2038 339.17 407.91 68.73 16.9% 80.93 57.5%
  • 60. Final Master Plan Report 4-13 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 4-7 PB Base, High and Low Demand Forecast for Kenya Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2008 6436 1072 68.5% 6436 1072 68.5% 6436 1072 68.5% 2009 6220 1028 69.1% 6262 1035 69.1% 6561 1087 68.9% 2010 6414 1062 69.0% 6533 1082 68.9% 7055 1172 68.7% 2011 6772 1123 68.8% 6883 1142 68.8% 7702 1284 68.5% 2012 7165 1190 68.8% 7327 1217 68.7% 8426 1407 68.3% 2013 7535 1252 68.7% 7816 1301 68.6% 9311 1559 68.2% 2014 7903 1314 68.6% 8340 1390 68.5% 10292 1728 68.0% 2015 8262 1375 68.6% 8901 1485 68.4% 11379 1914 67.8% 2016 8638 1438 68.6% 9452 1579 68.3% 12583 2122 67.7% 2017 9032 1505 68.5% 10038 1679 68.3% 13918 2353 67.5% 2018 9445 1575 68.5% 10662 1785 68.2% 15399 2609 67.4% 2019 9876 1647 68.4% 11326 1898 68.1% 17040 2893 67.2% 2020 10328 1724 68.4% 12031 2019 68.0% 18862 3210 67.1% 2021 10802 1804 68.4% 12717 2136 68.0% 20882 3561 66.9% 2022 11298 1888 68.3% 13443 2259 67.9% 23123 3952 66.8% 2023 11817 1975 68.3% 14211 2390 67.9% 25611 4386 66.7% 2024 12361 2067 68.3% 15024 2529 67.8% 28374 4870 66.5% 2025 12930 2164 68.2% 15884 2676 67.8% 31442 5409 66.4% 2026 13527 2265 68.2% 16709 2817 67.7% 34849 6008 66.2% 2027 14151 2370 68.2% 17577 2965 67.7% 38635 6675 66.1% 2028 14849 2491 68.1% 18545 3134 67.6% 42966 7448 65.9% 2029 15581 2618 67.9% 19566 3312 67.4% 47794 8313 65.6% 2030 16350 2751 67.8% 20646 3501 67.3% 53179 9281 65.4% 2031 17068 2876 67.8% 21672 3680 67.2% 57980 10148 65.2% 2032 17819 3006 67.7% 22750 3869 67.1% 63226 11097 65.0% 2033 18603 3143 67.6% 23883 4068 67.0% 68959 12138 64.9% 2034 19423 3286 67.5% 25073 4277 66.9% 75224 13279 64.7% 2035 20279 3435 67.4% 26324 4497 66.8% 82074 14531 64.5% 2036 21174 3592 67.3% 27492 4704 66.7% 87688 15560 64.3% 2037 22110 3756 67.2% 28714 4919 66.6% 93695 16664 64.2% 2038 23087 3927 67.1% 29990 5145 66.5% 100125 17848 64.0% PB Low Case PB Base Case PB High Case Year
  • 61. Final Master Plan Report 4-14 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-11 PB Peak Demand Forecast for Kenya (MW) Figure 4-12 PB Sent Out Generation Forecast for Kenya (GWh) 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Maximum Demand (MW) PB Low Case PB Base Case PB High Case 0 20,000 40,000 60,000 80,000 100,000 120,000 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 Generation (GWh) PB Low Case PB Base Case PB High Case
  • 62. Final Master Plan Report 4-15 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4.7 Rwanda In addition to reviewing the most recent demand forecast available for Rwanda, we have produced our own base; high and low national demand forecast scenarios. These scenarios are based upon our own assumptions and methodology, utilising the data collected/made available as part of this study. Due to the lack of economic data as well as the unavailability of sales by consumer category, the independent demand forecast has been developed on the basis of the country electrification rate, an assumed level of specific consumption, an assumption relating to the number of persons per household and a population forecast provided by the UN. High and low demand forecast scenarios have also been developed. These forecasts differ from the base case demand forecast having adopted different assumptions relating to the rate of electrification and population for the derivation of total sales. Appendix G provides a detailed description of the adopted methodology and assumptions used to determine the PB demand forecasts for Rwanda. The base, high and low case demand forecast is presented in Table 4-8 and summarised in Figure 4-13 and Figure 4-14 below.
  • 63. Final Master Plan Report 4-16 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 4-8 PB Base, High and Low Demand Forecast for Rwanda Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2005 207 41 57.6% 207 41 57.6% 207 41 57.6% 2006 213 42 57.6% 213 42 57.6% 213 42 57.6% 2007 219 43 57.6% 219 43 57.6% 219 43 57.6% 2008 230 46 57.6% 230 46 57.6% 230 46 57.6% 2009 245 49 57.6% 245 49 57.6% 245 49 57.6% 2010 266 53 57.6% 266 53 57.6% 266 53 57.6% 2011 279 55 57.6% 286 57 57.6% 293 58 57.6% 2012 293 58 57.6% 306 61 57.6% 320 63 57.6% 2013 307 61 57.6% 327 65 57.6% 349 69 57.6% 2014 321 64 57.6% 349 69 57.6% 378 75 57.6% 2015 335 66 57.6% 372 74 57.6% 409 81 57.6% 2016 350 69 57.6% 395 78 57.6% 441 87 57.6% 2017 364 72 57.6% 419 83 57.6% 475 94 57.6% 2018 379 75 57.6% 444 88 57.6% 510 101 57.6% 2019 395 78 57.6% 469 93 57.6% 546 108 57.6% 2020 410 81 57.6% 495 98 57.6% 583 115 57.6% 2021 426 84 57.6% 521 103 57.6% 621 123 57.6% 2022 441 87 57.6% 548 109 57.6% 661 131 57.6% 2023 457 90 57.6% 576 114 57.6% 702 139 57.6% 2024 473 94 57.6% 604 120 57.6% 743 147 57.6% 2025 489 97 57.6% 633 125 57.6% 786 156 57.6% 2026 506 100 57.6% 663 131 57.6% 831 165 57.6% 2027 522 103 57.6% 693 137 57.6% 876 174 57.6% 2028 539 107 57.6% 724 143 57.6% 923 183 57.6% 2029 556 110 57.6% 756 150 57.6% 971 192 57.6% 2030 574 114 57.6% 788 156 57.6% 1020 202 57.6% 2031 591 117 57.6% 821 163 57.6% 1072 212 57.6% 2032 609 121 57.6% 855 169 57.6% 1124 223 57.6% 2033 627 124 57.6% 890 176 57.6% 1178 233 57.6% 2034 645 128 57.6% 925 183 57.6% 1234 244 57.6% 2035 664 132 57.6% 961 190 57.6% 1290 256 57.6% 2036 683 135 57.6% 998 198 57.6% 1350 267 57.6% 2037 702 139 57.6% 1036 205 57.6% 1412 280 57.6% 2038 721 143 57.6% 1075 213 57.6% 1474 292 57.6% PB High CasePB Base CasePB Low Case Year
  • 64. Final Master Plan Report 4-17 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-13 PB Peak Demand Forecast for Rwanda (MW) Figure 4-14 PB Sent Out Generation Forecast for Rwanda (GWh) 0 50 100 150 200 250 300 350 2005 2008 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 Peak Demand (MW) PB Low Case PB Base Case PB High Case 0 200 400 600 800 1,000 1,200 1,400 1,600 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Generation (GWh) PB Low Case PB Base Case PB High Case
  • 65. Final Master Plan Report 4-18 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4.8 Sudan Given the disparity between the most recent national demand forecast (as provided in the LTPSP study) and the current level of demand, we have developed new demand forecast scenarios (base, high and low) for Sudan. These forecasts have been developed so as to: • Take into account the current level of load, and, • Retain the electrification targets of NEC over a longer period of time so as to retain the ‘official’ national outlook. In order to develop the PB base case demand forecast we have used trend line analysis to identify existing trends in the level of sales in each consumer category and used the resulting mathematical trend line formulae to project the forecast for the study period. We have applied the mathematical formulae presented in the trend line analysis above in order to derive estimates of sales in each consumer category. In order to derive the level of generation (GWh sent out) we assume that losses fall from their current level of 20 per cent to 13 per cent in 0.5 per cent increments between 2010 and 2023. The level of losses is assumed to stay constant from 2023 onwards. In order to derive the peak demand forecast, we have assumed that the load factor will remain constant at 60.7 per cent. In addition to the base case demand forecast detailed above we have developed a “high” case demand forecast. The key assumptions adopted for the high case demand forecast are as follows: • Peak demand in 2038 is assumed to be the same as that achieved under the base case demand forecast scenario. • Sent out generation in 2038 is assumed to be the same as that achieved under the base case demand forecast scenario. • Linear interpolation is used to derive the level of peak demand and sent out generation between 2010 and 2038. • Losses are assumed to fall from their current level of 20 per cent to 13 per cent in 0.5 per cent increments between 2010 and 2023, remaining constant thereafter. In addition to the base and high demand forecast scenarios, we have developed a low demand forecast which follows the same methodology as detailed for the base case forecast above but we assume lower 2nd order historic polynomial relationships. Appendix H provides a detailed description of the adopted methodology and assumptions used to determine the PB demand forecasts for Sudan. The base, high and low independent PB demand forecasts are presented in Table 4-9 and summarised in Figure 4-15 and Figure 4-16 below.
  • 66. Final Master Plan Report 4-19 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Table 4-9 PB Base, High and Low Demand Forecast for Sudan Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2009 6,118 1,151 60.7% 6,118 1,151 60.7% 6,118 1,151 60.7% 2010 6,621 1,246 60.7% 7,211 1,357 60.7% 9,541 1,795 60.7% 2011 7,326 1,378 60.7% 8,264 1,555 60.7% 12,964 2,439 60.7% 2012 8,071 1,519 60.7% 9,436 1,775 60.7% 16,387 3,083 60.7% 2013 8,857 1,666 60.7% 10,733 2,019 60.7% 19,810 3,727 60.7% 2014 9,681 1,821 60.7% 12,161 2,288 60.7% 23,232 4,371 60.7% 2015 10,544 1,984 60.7% 13,723 2,582 60.7% 26,655 5,015 60.7% 2016 11,445 2,153 60.7% 15,426 2,902 60.7% 30,078 5,659 60.7% 2017 12,382 2,330 60.7% 17,273 3,250 60.7% 33,501 6,303 60.7% 2018 13,356 2,513 60.7% 19,270 3,626 60.7% 36,924 6,947 60.7% 2019 14,366 2,703 60.7% 21,421 4,030 60.7% 40,347 7,591 60.7% 2020 15,411 2,899 60.7% 23,731 4,465 60.7% 43,770 8,235 60.7% 2021 16,490 3,103 60.7% 26,204 4,930 60.7% 47,193 8,879 60.7% 2022 17,603 3,312 60.7% 28,845 5,427 60.7% 50,616 9,523 60.7% 2023 18,750 3,528 60.7% 31,657 5,956 60.7% 54,039 10,167 60.7% 2024 20,044 3,771 60.7% 34,844 6,556 60.7% 57,462 10,811 60.7% 2025 21,384 4,023 60.7% 38,248 7,196 60.7% 60,885 11,455 60.7% 2026 22,770 4,284 60.7% 41,874 7,878 60.7% 64,308 12,099 60.7% 2027 24,202 4,553 60.7% 45,731 8,604 60.7% 67,731 12,743 60.7% 2028 25,680 4,831 60.7% 49,825 9,374 60.7% 71,154 13,387 60.7% 2029 27,204 5,118 60.7% 54,164 10,190 60.7% 74,577 14,031 60.7% 2030 28,774 5,414 60.7% 58,754 11,054 60.7% 78,000 14,675 60.7% 2031 30,391 5,718 60.7% 63,603 11,966 60.7% 81,423 15,319 60.7% 2032 32,054 6,031 60.7% 68,718 12,929 60.7% 84,846 15,963 60.7% 2033 33,762 6,352 60.7% 74,105 13,942 60.7% 88,269 16,607 60.7% 2034 35,517 6,682 60.7% 79,773 15,009 60.7% 91,692 17,251 60.7% 2035 37,318 7,021 60.7% 85,727 16,129 60.7% 95,114 17,895 60.7% 2036 39,165 7,369 60.7% 91,976 17,304 60.7% 98,537 18,539 60.7% 2037 41,058 7,725 60.7% 98,525 18,537 60.7% 101,960 19,183 60.7% 2038 42,997 8,090 60.7% 105,383 19,827 60.7% 105,383 19,827 60.7% PB High CasePB Base CasePB Low Case Year
  • 67. Final Master Plan Report 4-20 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-15 PB Peak Demand Forecast for Sudan (MW) Figure 4-16 PB Sent Out Generation Forecast for Sudan (GWh) 0 20,000 40,000 60,000 80,000 100,000 120,000 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Peak Demand (MW) PB Low Case PB Base Case PB High Case 0 5,000 10,000 15,000 20,000 25,000 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Generation (GWh) PB Low Case PB Base Case PB High Case
  • 68. Final Master Plan Report 4-21 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4.9 Tanzania In addition to reviewing the most recent national demand forecast available for Tanzania, we have developed our own base, high and low demand forecast scenarios. These scenarios are based upon our own assumptions and methodology, utilising the data collected/made available as part of this study. The base case demand forecast developed for Tanzania is derived using PB’s RALF model. We have additionally developed high and low demand forecast scenarios. These scenarios have been developed using the same methodology as outlined for the PB base case demand forecast, with the exception that high and low GDP and population forecasts have been adopted respectively. Appendix I provides a detailed description of the adopted methodology and assumptions used to determine the PB demand forecasts for Tanzania. The base, high and low independent PB demand forecasts are presented below in Table 4-10 and Figure 4-17 and Figure 4-18 below. Table 4-10 PB Base, High and Low Demand Forecast for Tanzania Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2008 4143 694 68.2% 4143 694 68.2% 4143 694 68.2% 2009 4273 714 68.3% 4324 722 68.3% 4367 730 68.3% 2010 4486 750 68.3% 4594 767 68.4% 4686 782 68.4% 2011 4742 791 68.4% 4914 819 68.5% 5061 844 68.5% 2012 5013 835 68.5% 5256 874 68.6% 5466 910 68.6% 2013 5299 882 68.6% 5621 933 68.7% 5904 981 68.7% 2014 5602 931 68.7% 6013 997 68.9% 6377 1058 68.8% 2015 5900 980 68.7% 6431 1064 69.0% 6887 1141 68.9% 2016 6236 1035 68.8% 6870 1136 69.1% 7430 1229 69.0% 2017 6591 1093 68.9% 7339 1212 69.1% 8016 1325 69.1% 2018 6967 1154 68.9% 7841 1293 69.2% 8648 1428 69.1% 2019 7364 1218 69.0% 8377 1380 69.3% 9330 1539 69.2% 2020 7707 1273 69.1% 8861 1458 69.4% 9969 1643 69.3% 2021 8066 1331 69.2% 9374 1540 69.5% 10651 1753 69.4% 2022 8442 1391 69.3% 9917 1628 69.6% 11381 1871 69.4% 2023 8835 1455 69.3% 10492 1720 69.6% 12161 1998 69.5% 2024 9247 1521 69.4% 11100 1818 69.7% 12995 2133 69.6% 2025 9678 1590 69.5% 11744 1921 69.8% 13887 2277 69.6% 2026 10130 1662 69.6% 12425 2030 69.9% 14840 2431 69.7% 2027 10603 1738 69.6% 13146 2146 69.9% 15859 2596 69.7% 2028 11098 1817 69.7% 13909 2268 70.0% 16949 2773 69.8% 2029 11617 1900 69.8% 14717 2398 70.1% 18115 2961 69.8% 2030 12038 1967 69.9% 15417 2509 70.1% 19170 3131 69.9% 2031 12474 2036 69.9% 16150 2625 70.2% 20286 3310 70.0% 2032 12927 2108 70.0% 16918 2747 70.3% 21469 3500 70.0% 2033 13395 2182 70.1% 17724 2875 70.4% 22721 3702 70.1% 2034 13881 2258 70.2% 18568 3009 70.4% 24047 3915 70.1% 2035 14385 2338 70.2% 19452 3149 70.5% 25451 4140 70.2% 2036 14911 2421 70.3% 20369 3295 70.6% 26924 4377 70.2% 2037 15457 2507 70.4% 21329 3448 70.6% 28483 4629 70.2% 2038 16023 2596 70.5% 22335 3608 70.7% 30134 4894 70.3% PB High CasePB Base CasePB Low Case Year
  • 69. Final Master Plan Report 4-22 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-17 PB Peak Demand Forecast for Tanzania (MW) Figure 4-18 PB Sent Out Generation Forecast for Tanzania (GWh) 0 1,000 2,000 3,000 4,000 5,000 6,000 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 Peak Demand (MW) PB Base Case PB Low Case PB High Case 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 Generation (GWh) PB Low Case PB Base Case PB High Case
  • 70. Final Master Plan Report 4-23 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study 4.10 Uganda The most recent national demand forecast available for Uganda was developed by PB as part of the PSIP study. The forecasts developed for the PSIP study (as discussed in Section 5 and Appendix J of this report) are representative of PB’s independent view of electrical demand growth in Uganda. The base, high and low PSIP demand forecasts are presented in Table 4-11 and summarised in Figure 4-19 and Figure 4-20 below. Table 4-11 PB Base, High and Low Demand Forecast for Uganda Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) Generation (GWh) Peak Demand (MW) Load Factor (%) 2009 2784 541 58.7% 2877 561 58.5% 3397 597 65.0% 2010 2901 570 58.1% 3026 596 58.0% 3982 702 64.8% 2011 3012 597 57.6% 3188 633 57.5% 4564 805 64.7% 2012 3121 623 57.2% 3371 673 57.2% 5146 908 64.7% 2013 3203 643 56.9% 3560 715 56.8% 5663 998 64.8% 2014 3279 662 56.5% 3788 764 56.6% 6165 1084 64.9% 2015 3351 679 56.3% 4030 816 56.4% 6651 1167 65.1% 2016 3419 695 56.2% 4288 871 56.2% 7122 1247 65.2% 2017 3481 710 56.0% 4561 929 56.0% 7577 1324 65.3% 2018 3540 724 55.8% 4851 990 55.9% 8018 1398 65.5% 2019 3622 741 55.8% 5123 1045 56.0% 8518 1480 65.7% 2020 3676 750 56.0% 5362 1091 56.1% 8977 1551 66.1% 2021 3778 772 55.9% 5685 1158 56.0% 9537 1647 66.1% 2022 3913 800 55.8% 6056 1233 56.1% 10178 1759 66.1% 2023 4048 828 55.8% 6434 1310 56.1% 10831 1873 66.0% 2024 4184 857 55.7% 6821 1389 56.1% 11497 1990 66.0% 2025 4321 886 55.7% 7216 1470 56.0% 12175 2109 65.9% 2026 4459 915 55.6% 7620 1552 56.0% 12867 2231 65.8% 2027 4598 944 55.6% 8031 1636 56.0% 13570 2355 65.8% 2028 4738 973 55.6% 8450 1722 56.0% 14287 2482 65.7% 2029 4880 1003 55.5% 8878 1809 56.0% 15016 2612 65.6% 2030 5022 1033 55.5% 9313 1898 56.0% 15757 2744 65.6% 2031 5065 1032 56.0% 9754 1978 56.3% 16548 2883 65.5% 2032 5246 1069 56.0% 10203 2069 56.3% 17348 3025 65.5% 2033 5428 1107 56.0% 10659 2162 56.3% 18156 3168 65.4% 2034 5611 1145 55.9% 11123 2257 56.3% 18972 3312 65.4% 2035 5796 1184 55.9% 11594 2353 56.2% 19797 3459 65.3% 2036 5982 1223 55.8% 12072 2450 56.2% 20629 3607 65.3% 2037 6170 1262 55.8% 12559 2549 56.2% 21470 3757 65.2% 2038 6358 1301 55.8% 13052 2650 56.2% 22319 3908 65.2% PB High CasePB Base CasePB Low Case Year
  • 71. Final Master Plan Report 4-24 WBS 1100 Demand Forecast May 2011 EAPP/EAC Regional PSMP & Grid Code Study Figure 4-19 PB Peak Demand Forecast for Uganda (MW) Figure 4-20 PB Sent Out Generation Forecast for Uganda (GWh) 0 500 1000 1500 2000 2500 3000 3500 4000 4500 2009 2012 2015 2018 2021 2024 2027 2030 2033 2036 Peak Demand (MW) PB Base Case PB Low Case PB High Case 0 5000 10000 15000 20000 25000 2009 2012 2015 2018 2021 2024 2027 2030 2033 2036 Generation (GWh) PB Base Case PB Low Case PB High Case
  • 72. Final Master Plan Report WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study WBS 1200 Generation Supply Study and Planning Criteria
  • 73. Final Master Plan Report i WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study TABLE OF CONTENTS 1  SCOPE AND OBJECTIVES.................................................................................. 1-1  1.1  Objectives .............................................................................................................. 1-1  1.2  Scope of Study....................................................................................................... 1-1  1.3  Covered Geographic area...................................................................................... 1-3  1.4  Methodology .......................................................................................................... 1-5  1.4.1  Data completion and harmonization for new power options .................................. 1-6  2  DATA SOURCES .................................................................................................. 2-1  2.1  Primary reference reports ...................................................................................... 2-1  2.2  List of references.................................................................................................... 2-2  3  CRITERIA FOR GENERATION PLANNING......................................................... 3-1  3.1  Scope..................................................................................................................... 3-1  3.2  Economic criteria.................................................................................................... 3-1  3.2.1  Objective function................................................................................................... 3-1  3.2.2  Study period and reference year for discounting ................................................... 3-2  3.2.3  Discount rate.......................................................................................................... 3-2  3.2.4  Escalation .............................................................................................................. 3-2  3.2.5  Shadow pricing ...................................................................................................... 3-3  3.2.6  Cost of un-served energy....................................................................................... 3-3  3.2.7  Allocation of costs for multipurpose projects.......................................................... 3-4  3.3  Generation planning criteria................................................................................... 3-4  3.3.1  Reliability criteria and reserve................................................................................ 3-4  3.3.2  Outage rates .......................................................................................................... 3-4  3.3.3  Plant service lives .................................................................................................. 3-5  3.3.4  Retirement of existing plant.................................................................................... 3-5  3.3.5  Rental units ............................................................................................................ 3-6  3.3.6  Operation, maintenance and other costs ............................................................... 3-6  4  EXISTING AND FUTURE GENERATION OPTIONS BY COUNTRY ................... 4-1  4.1  Hydrology and hydro generation analysis.............................................................. 4-1  4.1.1  Hydrology............................................................................................................... 4-1  4.1.2  Calibration of hydro plants production.................................................................... 4-1  4.2  Total identified options by country.......................................................................... 4-2  4.3  Summary of present and future generation resources......................................... 4-19  5  FUTURE HYDROELECTRIC OPTIONS ............................................................... 5-1  5.1  Identifications of new hydroelectric options............................................................ 5-1  5.2  Capital costs for future hydro projects.................................................................... 5-4  5.2.1  Procedure for updating costs ................................................................................. 5-4  5.2.2  Mitigation costs ...................................................................................................... 5-8  5.2.3  Interest during construction.................................................................................... 5-9  5.3  Minimum lead times to on-power ......................................................................... 5-10  5.4  Primary screening of future hydro options ........................................................... 5-11  5.4.1  Rejected options .................................................................................................. 5-16  5.5  Future hydro generation costs ............................................................................. 5-18  5.6  Ranking by cost and earliest availability .............................................................. 5-24
  • 74. Final Master Plan Report ii WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 6  FUTURE THERMAL OPTIONS............................................................................. 6-1  6.1  Capital costs for future thermal projects................................................................. 6-1  6.1.1  Generic capital costs.............................................................................................. 6-1  6.1.2  Interest during construction.................................................................................... 6-5  6.2  Minimum lead times to on-power ........................................................................... 6-6  6.3  Plant heat rates...................................................................................................... 6-7  6.4  Fuel prices ............................................................................................................. 6-7  6.4.1  Oil........................................................................................................................... 6-7  6.4.2  Natural Gas............................................................................................................ 6-8  6.4.3  Coal........................................................................................................................ 6-9  6.4.4  Geothermal .......................................................................................................... 6-10  6.4.5  Net calorific value................................................................................................. 6-10  6.4.6  Fuel forecast ........................................................................................................ 6-10  6.5  Future thermal generation costs .......................................................................... 6-12  6.6  Thermal plant retirements .................................................................................... 6-17  7  IDENTIFICATION OF POTENTIAL REGIONAL PROJECTS............................... 7-1  LIST OF FIGURES Figure 1-1  Country resources and potential interconnections ......................................... 1-2  Figure 1-2  Eastern DRC study area ................................................................................ 1-5  Figure 4-1  Average annual hydro production per country ............................................... 4-2  Figure 6-1  Evolution of NG prices for different regions.................................................... 6-8  Figure 6-2  Fuel forecast................................................................................................. 6-12  LIST OF TABLES Table 2-1  List of project reports...................................................................................... 2-1  Table 2-2  List of References .......................................................................................... 2-2  Table 3-1  Index values for escalating capital costs ........................................................ 3-3  Table 3-2  Selected outage rates for generation planning............................................... 3-5  Table 3-3  Plant service lives........................................................................................... 3-5  Table 3-4  Operation, maintenance and other costs ....................................................... 3-6  Table 4-1  Annual hydro production for identified options ............................................... 4-2  Table 4-2  Burundi Generation ........................................................................................ 4-4  Table 4-3  Djibouti Generation......................................................................................... 4-5  Table 4-4  Eastern DRC Generation ............................................................................... 4-6  Table 4-5  Egypt Generation ........................................................................................... 4-7  Table 4-6  Ethiopia Generation........................................................................................ 4-9  Table 4-7  Kenya Generation ........................................................................................ 4-11  Table 4-8  Rwanda Generation ..................................................................................... 4-13  Table 4-9  Sudan Generation ........................................................................................ 4-14  Table 4-10  Tanzania Generation.................................................................................... 4-16  Table 4-11  Uganda Generation...................................................................................... 4-18  Table 4-12  Present and future potential generation resources ...................................... 4-19  Table 5-1  Typical cost values for projects ...................................................................... 5-2  Table 5-2  List of identified new hydro options ................................................................ 5-3  Table 5-3  Ethiopia previous estimated costs for hydro options (Costs in MUSD) .......... 5-6 
  • 75. Final Master Plan Report iii WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-4  Sudan previous estimated costs for hydro projects (Costs in MUSD)............ 5-7  Table 5-5  IDC - typical increments for hydro projects..................................................... 5-9  Table 5-6  IDC for hydroelectric projects (Interest rate = 10%) ..................................... 5-10  Table 5-7  Generic times for project activities ............................................................... 5-10  Table 5-8  Minimum on-power lead times for hydroelectric plants (years) .................... 5-11  Table 5-9  Classification of hydro resources ................................................................. 5-13  Table 5-10  Primary screening of future hydro options.................................................... 5-14  Table 5-11  Potential DRC sites for after 2017................................................................ 5-18  Table 5-12  EAPP Region Future Hydroelectric projects – Unit Generation costs.......... 5-20  Table 5-13  EAPP Hydro Options – Ranking by unit cost and earliest on-power............ 5-25  Table 5-14  Total new hydro for the first two 5 year periods of the study (MW) .............. 5-28  Table 6-1  Comparative costs for coal fired STPPs - 2009 $ excluding IDC ................... 6-2  Table 6-2  Typical unit costs for STPP ............................................................................ 6-2  Table 6-3  Comparative costs for Geothermal, OCGT and CCGT - 2009 $, no IDC....... 6-4  Table 6-4  Unit costs for Generic Thermal plants - 2009 $, no IDC................................. 6-5  Table 6-5  Typical disbursement schedules during construction..................................... 6-5  Table 6-6  Interest during construction - typical increments for thermal plants ............... 6-6  Table 6-7  Generic TPP Unit costs - $/kW with IDC ........................................................ 6-6  Table 6-8  Minimum on-power lead times for thermal plants........................................... 6-7  Table 6-9  Heat Rates for different Thermal Plants ......................................................... 6-7  Table 6-10  Oil price projections - 2038............................................................................. 6-8  Table 6-11  NG price projections - 2038............................................................................ 6-9  Table 6-12  Coal price projections - 2038.......................................................................... 6-9  Table 6-13  Typical net calorific values ........................................................................... 6-10  Table 6-14  Fuel Forecast ............................................................................................... 6-11  Table 6-15  Illustrative future unit generation costs in c/kWh, based on 75% CF ........... 6-13  Table 6-16  Thermal generation costs by country ........................................................... 6-14  Table 6-17  Existing and committed thermal retirements ................................................ 6-17 
  • 76. Final Master Plan Report 1-1 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 1 SCOPE AND OBJECTIVES 1.1 Objectives The objectives of this program component are to: • Update the available data on generation supply for each country, including the existing facilities, rehabilitation projects, ongoing plant construction, supply import and export, and any other stations that may be developed during the planning period (2013 to 2038). • Establish a list of existing and potential energy sources suitable to meet the demand of the combined systems, including at least hydroelectric, thermal and geothermal sources. • For each candidate plant, list information on capital costs (including environmental mitigation costs), operation and maintenance costs and earliest in service date • For hydroelectric options, rank projects in accordance with attractiveness including cost. • Explain the generation planning criteria such as reliability criteria, outage rates and service lives • Provide a hydrology database for all the hydro sites used in the study • Update the hydro energy capability of all the hydro plants considered in the study The listing of existing, committed and future generation options will provide the basic data base for the supply-demand analysis (Module 1C-1300), and the subsequent generation/transmission financial and economic studies in phase II. Note this activity covers generation only. Transmission is dealt with in Module 1D. 1.2 Scope of Study The requirements for the generation supply study are defined in the list of objectives provided above. The scope may be considered in two parts: • The identification and data assembly for all existing generation plants, plants that are committed for the period up to January 2013 and future generation options that can be used to meet national load demands up to year 2038, on a country by country basis. • The identification and data collection for projects, both existing and future, that may be used to meet the demand of combined systems. The development of the data bases of country resources for the first part of the scope requirement has been based on the most recent master plans available, supplemented by any other recent presentations on behalf of the energy ministry or electric utility of each country. The initial listing of these resources was included in the Inception Report, and these have been reviewed by the national utilities and any comments or requested changes arising from that review have been incorporated in the listings included with this report. The updated country lists of existing and identified new options are provided in Section 4.2. The identification of projects that could be part of a regional supply arises directly out of the first stage. Clearly any projects with the potential to provide regional supply, i.e. outside of the country of the project, will largely be defined by size. However a preliminary comparison between load demands and available indigenous resources for the planning period has
  • 77. Final Master Plan Report 1-2 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study shown that, with the exception of Ethiopia, eventually the demand in each country will exceed local supply even without screening out higher risk projects.1 Thus the identification and eventual assessment of larger projects that could provide a contribution to a regional supply backbone, has to take into account timing, and the option of pre-building larger projects that could provide exports for a number of years. This, in turn, requires that generation plans for regional country groupings be evaluated, to determine the economics of any such pre-build strategies. Figure 1-1 below provides an illustration of potential in-country resources as of year 2038, based on existing plant and new generation options based on indigenous resources only. This figure also indicates which countries may be expected to have a surplus of resources up to the end of the planning period. For the generation supply study, the identification of these regional projects has been based solely on installed capacity. The criterion used has been to select projects with an installed capacity that is equal to or more than two years of load growth in the country of the project. These projects are listed in Section 7. Figure 1-1 Country resources and potential interconnections 1 Projects with potential constraints for environmental, social or legal issues. i.e. excluding generation using imported fuels but including nuclear plants. EGYPT 62,200 MW SUDAN 15,300 MW ETHIOPIA 14,300 MW DJIBOUTI 200 MW KENYA 7,000 MW UGANDA 3,400 MW TANZANIA 6,100 MW DRC Countries with export potential Countries with import needs Power transfer between countries RWANDA 500 MW DRC 2100 MW BURUNDI 500 MW Installed capacities based on current master plans for year 2030 Values are indicative and include presently planned transfers
  • 78. Final Master Plan Report 1-3 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 1.3 Covered Geographic area The study area covers the countries of the member utilities of the EAPP which are: REGIDESO (Burundi), SNEL (DRC), EEHC (Egypt), EEPCo (Ethiopia), KenGen and KPLC (Kenya), ELECTROGAZ (Rwanda), NEC (Sudan) and SINELAC (DRC, Rwanda and Burundi). In addition EdD (Djibouti) is included. The primary objective of the study is to determine the opportunities for and viability of regional supply through interconnections and power trading. In that context the existing, committed and planned interconnections are an important aspect of the study. These are: Existing interconnections: • DRC, Burundi, and Rwanda interconnected from a jointly developed hydro power station Ruzizi II, (capacity 45 MW) operated by a joint utility (SINELAC) • Cross-border electrification between Uganda and Rwanda, Tanzania and Uganda, and Kenya and Tanzania • Kenya – Uganda interconnection • Egyptian power system interconnection through Libya to other Maghreb countries and Southern Europe; and through Jordan to Eastern Mediterranean Ongoing projects in the region include: A preliminary compilation of information has shown the following projects with tentative dates: • Ethiopia-Kenya 500 KV HVDC: final feasibility study out. Commissioning 2013 • Ethiopia-Sudan 220 KV: commissioning end of 2010 • Ethiopia-Djibouti 283KM of 220 KV: commissioning by 2011 • Ethiopia-Sudan Sudan-Egypt 500 HVDC: feasibility study report has been prepared. Financings are being sought • Kenya – Tanzania 400 KV / NELSAP: commissioning 2015 • Kenya-Uganda 220 KV / NELSAP: commissioning 2014 • Uganda–Rwanda 220 KV /NELSAP: commissioning 2014 • Rwanda-Burundi 220 KV / NELSAP: commissioning 2014 • Burundi-DRC 220 KV / NELSAP: commissioning 2014 • Rusumo Falls Project 63 MW: commissioning 2016 Planning initiatives Presently, Kenya, Tanzania and Uganda, under the auspices of the East African Community (EAC), are developing plans to (i) interconnect and strengthen their power systems in order to share power supplies, and (ii) further extend the power system interconnections to countries outside EAC countries.
  • 79. Final Master Plan Report 1-4 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study A series of studies have been completed in the last 5 years that cover opportunities for cross-border interconnections in the region. These include the EAPMP2 [7], SSEA3 [1,2], ENPTPS4 [10], Ethiopia-Djibouti Interconnection, and the 2004 World Bank Scoping Study5 . Implementation planning is going ahead for the interconnection of the national grids for the five equatorial Lakes countries (Burundi, Kenya, Uganda, DRC, and Rwanda). DRC study area The current study is considering generation sources within the EAPP that could provide either surplus generation or markets for other EAPP countries with surpluses. The situation of the Congo is unique. Currently the DRC exports to the SAPP via Zambia from 220 kV lines from South Katanga. This supply is provided from Inga I and II, and from the three midsized hydro projects in South Katanga, that provide almost all their output of about 460 MW to Zambia / SAPP. By comparison the Eastern provinces of DRC are interconnected north south, and with Rwanda - to the Ruzizi plants. The most important of the existing and potential hydroelectric resources in the DRC are in the western part of the country and in South Katanga. The DRC provides major exports to Zambia and the SAPP from the Inga plants on the Congo River and hydro projects in South Katanga. In the very long term there is the possibility that Grand Inga can be developed (44,000 MW) with the potential to supply the SAPP, the Mediterranean Power Pool along North Africa and the Northern part of the Nile basin among other regions. However this possibility cannot be considered sufficiently well defined to include Grand Inga supply as part of the current study. Irrespective of any technical and financing difficulties this project could not be brought into service within 20-25 years. Given this situation, the part of the DRC that is considered relevant to the EAPP is considered to be limited to the parts of the DRC that are within the Nile basin. This definition has also been used in the previous SSEA study by SNC-Lavalin for the NBI/NELSAP, and the 2007 NBI interconnection study. These areas are shown in the figure overleaf as shaded, and are made up as follows: • Oriental (eastern part) • Kivu North • Maniema (eastern part) • Kivu South • Katanga (northern part) 2 Uganda, Kenya and Tanzania 3 Burundi, Eastern DRC, Kenya, Rwanda, Tanzania and Uganda 4 Egypt, Sudan and Ethiopia 5 Joint UNDP/WB Energy Sector Management Assistance Program (ESMAP), Opportunities for Power Trade in the Nile Basin, Final Scoping Study, January 2004
  • 80. Final Master Plan Report 1-5 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Figure 1-2 Eastern DRC study area 1.4 Methodology The generation supply study consists of four steps for each country: • Identification of all existing generating plants, including basic identification information such as: name, type, installed capacity and (for hydro) energy generation capability. • Identification of all identified future generation options, again including name, type, installed capacity and (for hydro) energy generation capability. • Collection of plant data for existing and future plant options, as is required for generation planning purposes • Harmonization of project information (e.g., to a common cost or reliability level) and preparation of the generation data base. In the context of this study, existing plants include committed new plant to be commissioned by January 2013. The notion of future power options applies to the planning period of 2013 to 2038. Required plant data (existing, committed and planned projects) for generation expansion modeling includes: • Technical characteristics (forced outage rates, maintenance periods, heat rates of each plant or unit, reservoir characteristics, design heads, and long term inflows) • Performance characteristics (nameplate and effective capacity, firm capacity under minimum reservoir operating levels, thermal efficiency, firm and average energy levels) • Fixed and variable operating costs
  • 81. Final Master Plan Report 1-6 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study • Capital costs for committed and planned projects, including construction schedules of disbursements • Information on project level of preparation, including environmental approvals 1.4.1 Data completion and harmonization for new power options Data on new power options was harmonized to the extent feasible to improve the validity of the project and plan comparisons. This included the following elements: Capital costs given in the previous studies were adjusted for inflation, using the indices provided in Section 3. For all projects the “overnight” cost i.e., excluding interest during construction, was to be used, and an amount for IDC was added. The IDC amount was determined as described in Section 3. Mitigation costs were reviewed and harmonized. The estimates given in previous reports were reviewed. If mitigation costs are included, these were retained. Where no mitigation costs are included, then an amount equal to 5 % of the project cost was added. These were included in the confirmed capital costs. Project lead times to on-power were taken from the reference reports, and reviewed/adjusted. If insufficient information was available, lead times were based on the planning criteria shown in Section 5.3 and 6.2, that relate plant size and level of preparation to overall lead time. It is essential that realistic lead times are used in developing new generation sequences. Fixed and variable operation and maintenance costs were based on international experience from the SNC-Lavalin data base, as are included in the planning criteria. Technical characteristics were obtained from previous reports (or from country electric utilities for existing plants), and are summarized in the tables included in Module 1C-1300 Performance characteristics will be obtained from previous reports (or from country electric utilities for existing plants), supplemented by SNC-Lavalin experience data from international sources. Information on trans-border imports or exports was obtained from the country electric utilities, NELSAP, ENPTPS and the EAPP. Hydro generation capability - The terms of reference require that "the results of the hydro systems energy capability for the region be determined by the review of each country´s hydrology". It is noted that this work for Tanzania was up to date. Also the previous studies for hydro projects in Ethiopia and Sudan are recent and used hydrology updated for those studies. In some cases missing periods of hydrological information were filled with the methodology described in Appendix B. For this generation supply study the generation estimates from previous reports were used. The later generation planning studies will use hydrologic sequences that are presently being updated. Other renewable energy sources such as large solar or wind energy projects were included in the data base. Project data for existing, committed and evaluated new power options were combined in the form of a catalogue, as is shown later in Module 1C - 1300. This is the data required for the SNC-Lavalin generation planning models (SDDP, OPTGEN)6 to be used in later activities. 6 A description of SDDP and OPTGEN can be found in the appendices of Module 1C – 1300.
  • 82. Final Master Plan Report 2-1 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 2 DATA SOURCES 2.1 Primary reference reports During the Inception Phase data has been assembled from primary sources such as original project reports, secondary sources such as master plan studies, and as feedback from participating utilities. Identified studies that contain key information for generation planning include the following: Table 2-1 List of project reports Report  Coverage Ethiopia – Master Plan 2006 Ethiopia master plan of load forecast, generation and  transmission  Ethiopia – Master Plan 2008 Summary update  Ethiopia master plan of load forecast, generation and  transmission  Ethiopia – Djibouti interconnection  Planned supply from Ethiopia to Djibouti   Ethiopia – Prefeasibility studies of Border,  Mandaya,  (included in ENPTPS –2007)7   Major hydro developments on the blue Nile  Ethiopia – Prefeasibility studies of  Beko Abo  and Karadobi hydro on Blue Nile Abay  Major hydro developments on the blue Nile  EAPMP,  2005  Uganda, Kenya, Tanzania and interconnections  NELSAP ‐ SSEA .  2007  Uganda, Kenya, Tanzania, Burundi, Eastern DRC and Rwanda NBI Preliminary Basin‐Wide Study, 2008  Nile basin countries NELSAP ‐ Interconnections of the electricity  networks of the Nile Equatorial countries.   2007  Equatorial Lakes countries NELSAP ‐  Rusumo Falls feasibility study  ‐  2009 Rusumo Falls project, and alternative generation options NELSAP ‐  Rusumo Falls transmission studies  Rusumo Falls project, transmission requirements  interconnection to Rwanda, Burundi and West Tanzania,  centred on the Rusumo hydro project  EGL – Studies on Ruzizi III and Sisi 5 (Ruzizi 4)  hydro sites (in progress)  Draft feasibility and prefeasibility studies on the these two  projects respectively  Kenya Power System Master Plan December 2008  Kenya new generation options Uganda Power System Master Plan – 2009  Uganda new generation options Uganda – Studies of Karuma hydro being done  for the Ministry of Energy  Cost and generation data for the Karuma site downstream of  Bujagali  Sudan – Hydro studies by Fichtner  Prefeasibility studies of hydro sites on the Nile, in the South of  Sudan  Sudan – Power System Master Plan  Sudan new generation options Tanzania Power System Master Plan – 2009  Tanzania new generation options Rwanda – Power System Master Plan (in  progress)  Rwanda  new generation options Blue Nile basin study ‐  USBR, 1964 – On  request  Basin study with original information on site identification and  selection, including the Mabil project  Awash IV feasibility study – Electroconsult,  2006  Project report Genale III  feasibility study – Lahmeyer, 2005 Project report 7 A further study on the development of these projects on the Blue Nile / Abbay rivers is about to start, (Joint Multipurpose Program JMP-1) and will provide additional information on these proposed projects
  • 83. Final Master Plan Report 2-2 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Report  Coverage Genale IV pre‐feasibility study  ‐ Lahmeyer,  2006  Project report Gojeb feasibility study  ‐ H. Humphreys, 1997 Project report Geba feasibility study – Norplan and  Norconsult, 2005  Project report Baro I&II feasibility study  ‐ Lahmeyer, 2005  Project report Aleltu  East feasibility study – Acres, 1995  Project report Aleltu basin study , 1994 . Not obtained  Project report Chemoga Yeda Feasibility study – Lahmeyer,  2005  Project report Halele Worabesa Stage I feasibility study ‐   Lahmeyer, 2000  Project report Halele Worabesa Stage II feasibility study –  Lahmeyer, 2005  Project report 2.2 List of references During the preparation of the data base for existing and new generation options a list of references were prepared, including the above reports, which are keyed by ID number to the project information provided in the country tables in Section 4.2. This list of references follows in Table 2-2 below: Table 2-2 List of References References  1  SSEA 1 (2005)  2  SSEA II/III (2006)  3  PSMP Tanesco (2009) 4  Feasibility study Rusumo 2008  5  DRC/SSEA II report  6  Male Cifarha ‐ Les Resources Hydroeléctriques du Zaïre 1994 7  EAPMP  8  ENTRO ToR   9  NBI Preliminary Basin Study  10  ENTRO EDF  Eastern Nile Power Trade Program Study 2007‐ including hydro prefeasibility studies M3 Vol  3  11  NBI Fichtner prefeasibility, Study on Electrical Transmission Lines Linked to Rusumo Falls Hydroelectric  Generating Station, October 2008  12  EU‐EGL Fichtner Etude de faisabilité pour l´aménagement hydroélectrique de Ruzuzi III April 2009  13  EU‐EGL Fichtner Etude de préfaisabilité pour l´aménagement hydroélectrique de Sisi 5 June 2009  14  EEHC Annual report 2007/8  15  Ethiopia Central Statistics Agency ‐ Installed generating capacity and electricity production by station  2005/6  16  Hydropower of Ethiopia ‐ Status, potential and prospects ‐ Solomon Seyoum Hailu 
  • 84. Final Master Plan Report 2-3 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study References  17  Electrogaz 2009  18  MINIFRA semi annual report 2009  19  Sudan NEC 2008 Annual Report  20  Kenya country presentation at EAPP workshop Sept 09 21  Ethiopia country presentation at EAPP workshop Sept 09 22  Sudan NEC LTPSPS Generation data book (2007) 23  Feasibility study Rusumo Falls  2008 (draft)  24  Ethiopia Review of Power system Expansion Master Plan 2005 25  Prefeasibility studies of Border and Mandaya ‐ EdF/ENTRO Power Trade Study Module M5  26  Power projects proposed and under construction‐www.skyscrapercity.com 27  Kenya Least Cost Power Development Plan 2009‐30, Dec 2008 28  Kenya Least Cost Power Development Plan 2005‐25,  2004 29  East Africa business News Nov 27, 2009 30  Sudan NEC LTPSPS Generation plan report 5 (2007) 31  Karadobi Multipurpose project, pre‐feasibility study Norplan 2006 32  Genale 3D Multipurpose Project ‐ Feasibility study ‐  Lahmeyer 2007 33  Genale 6D Multipurpose Project ‐ Feasibility study ‐  Norplan 2009 34  Feasibility study of Chemoga Yeda I and 2 Lahmeyer 2006 35  Geba Hydroelectric Project ‐ Feasibility study ‐  Norplan 2005 36  Feasibility Study of Halele Werabesa Sate I hydroelectric project ‐ Lahmeyer 2000  37  Uganda ‐ Generation Plan (draft) Report, PB October 2009 38  Ethiopia  Power System Expansion Master Plan Update 2006 39  Feasibility study of Gojeb Medium Hydropower Project, Humphreys, 1997  40  Beko Abo Multipurpose Project ‐  Reconnaissance Study, NORPLAN, 2007 (Nov) 41  Gibe IV project profile EEPCO, 2009  42  Feasibility Study of the Baro Multipurpose Project ‐ final report ‐  NORPLAN, September 2006  43  Gibe IV and V update report ‐ Pietrangeli /Salini June 2008 44  Aleltu Basin  Study ‐ Acres  International, 1994 45  Awash IV Feasibility Study ‐ ELC 2006  46  Ethiopia ‐ Investment Opportunities in Geothermal Energy Development in Six Selected Geothermal  Projects, Ministry of Mines and Energy December 2008   47  EEPCo ‐ Highlights of power sector development program 2009‐2018, June 2008 48  Semliki hydro prefeasibility study, 2005 49  Hydropower in Ethiopia ‐ Staged construction of Tekeze Dam, Waterpower April 2009 
  • 85. Final Master Plan Report 2-4 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study References  50  Burundii country presentation at EAPP workshop Sept 09 51  NELSAP Interconnection study October 2007 52  Kenya ‐ Hydroelectric Cascades. Appendix to Least cost plan 2009‐30 (Ref 27) 53  Kenya TPP Characteristics ‐ KENGEN/KPLC meeting ‐ EAPP Inception Mission (2009)  54  Uganda River Nile Hydro Potential ‐ Uganda Electrical Generation Company ‐ Hydro Power Development  Unit ‐ EAPP Inception Mission (2009)  55  Rwanda Expansion Plan (2002)  56  Gibe 3 Ethiopia Hydro Project ‐ Official Webpage ‐ EEPCo (2009) 57  Sudan NEC LTPSPS Hydrology report (2007) 58  Merowe: The Largest water resources project under construction in Africa ‐ Lahmeyer/Dams‐Sudan  (2006)  59  EEHC Official E‐mail communications ‐ TPP and HPP characteristics (2009) 60  Djibouti Least Cost Electricity Master Plan (Final Report) ‐ PB ‐ November 2009 61  Uganda Potential Hydro Power Sites ‐ Final Report ‐ SWECO International (Dec. 2000)  62  Bujagali Hydro Power Project Social and Environmental Assessment ‐ Main Report ‐ Burnside (2006) 63  EEPCO email 08‐Feb‐2010   64  Rapport définitif de faisabilité de l'aménagement de KABU 16 ‐ Vol. 1  ‐ SOGREAH (1995)   65  Etude de Préfaisabilité des aménagements hydro‐électriques Jiji et Mulembwe ‐ Vol. 1&2 ‐ BEROCAN  (2000)  66  Kaganuzi multipurpose project ‐ Feasibility study ‐ Vol. III ‐ Draft Report ‐ NORCONSULT (1987)  67  Faisabilité détaillée de l'aménagement hydro‐électrique de Nyabarongo ‐ SOGREAH (1999)  68  NEC Sudan Projects Profile 2006‐2011 – Issued 2009 ‐ www.necsudan.com 
  • 86. Final Master Plan Report 3-1 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 3 CRITERIA FOR GENERATION PLANNING 3.1 Scope The characterization of project performance and cost has to reflect standardized criteria and parameters for hydro and thermal plants cost and performance, and for generation planning. These data are shown in the following subsections. Additional information used for the calculation of generation costs is provided in Sections 5 and 6. Economic criteria • Reference year and study horizon • Discount rates and escalation • Cost of un-served energy • Shadow pricing Generation planning • System reliability criteria (e.g., LOLP/LOLE) • Reserve margins • Outage rates and maintenance schedules • O & M costs, and other owners costs for the region • Service lives Hydroelectric plants: See Section 5 • Capital costs adjusted to a standard reference year • Rated and firm capacity • Firm and average energy • Capital cost disbursement schedule Thermal plants: See Section 6 • Unit costs for different plant types / sizes and fuel types • Station service • Heat rate • Fuel sources and costs • Fuel calorific value 3.2 Economic criteria 3.2.1 Objective function The general purpose of generation investment planning is to determine the least cost schedule of commissioning of new generation units over a given period of time within acceptable levels of reliability of power supply. More precisely, the objective cost function is: min [NPV(Investment costs + O&M costs + Fuel costs + Un-served energy cost + Externalities)] where:
  • 87. Final Master Plan Report 3-2 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study • NPV: Net Present Value over the planning period (2013-2038) • Investment costs: generation and interconnection investment costs over the planning period • O&M costs: O&M cost of generation and interconnection over the planning period • Fuel costs: Fuel cost of generation (TPP) over the planning period • Un-served energy cost: cost of un-served energy (i.e. unsupplied) energy over the planning period • Externalities: Other costs or benefits such as mitigation costs, irrigation benefits, etc… 3.2.2 Study period and reference year for discounting All costs are to be expressed in terms of mid 2009 costs. No further escalation is applied to capital costs or operating costs for the base case. The identification and assessment of new power options to meet the forecast load growth covers the period 2013 to 2038. 3.2.3 Discount rate The discount rate may be considered as the time value of money, and is used to calculate the present value of a series of future costs. While the discount rate may be linked to borrowing costs, for the purpose of planning studies the selection of an appropriate value should reflect the opportunity cost of capital. The discount rate will therefore tend to be higher in regions or countries where capital is relatively scarcer. The discount rate is also affected by the use of escalation in comparative studies8 . The discount rate for comparisons would be approximately higher by the amount of cost inflation, than the discount rate used for an analysis at constant prices (i.e. a 10 % discount with constant prices would yield the same answer as, say, a nominal rate of 13 % if 3 % escalation were included in all future costs). It is noted that a discount rate of 12 % was used in the 2009 TANESCO PSMP update, and was used in the EAPMP and in the Kenya 2004 and 2008 Least Cost Plan. This rate was also used in the 2004 study on the Zambia- Tanzania-Kenya Interconnector. However the World Bank SSEA study for the East Africa region [1, 2] that ended in 2006 based all generation planning on a discount rate of 10 %. The choice of discount rate is discretionary. Use of a higher discount rate will tend to favour thermal plants in cost comparisons with hydro due to their lower initial costs, but higher yearly operating costs, while lower discount rates would favour hydroelectric plants, where most of the expenditures are at the beginning of the project cycle. A real discount rate of 10% (i.e. excluding inflation) will be used in converting capital costs into equivalent annual costs over the life of an asset. In the context of this study, a discount rate of 10% will also be used for very preliminary comparisons of unit generation costs for initial screening of options. 3.2.4 Escalation Information on escalation may be taken from two sources: the US Department of Labour statistics and the USBR construction costs trends index. These provide similar results, as compared below: 8 Econometric Analysis of Fishers Equation – American Journal of Economics and Sociology, Jan 1, 2005, Peter Philips
  • 88. Final Master Plan Report 3-3 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 3-1 Index values for escalating capital costs   US Dept Labour USBR Year  Generation Transmission Actual 2003=100 2003  100  100 250 100 2004  105.2 101.4 274 110 2005  121.6 101.3 288 115 2006  128.0 103.3 303 121 2007  132.0 104.7 316 126 2008  145.5 110.7 345 138 2009  133.8 (p) 113.2 (p) 329 132 The above sources are: - The US Department of Labour Producer Price Index Industry Data for: • Electric Power Generation • Bulk Power Transmission and Control - The US Bureau of Reclamation Construction Costs Trends – composite trend index for October of each year. Capital cost adjustments for hydro and thermal projects will be based on the US Department of Labour indices. It is noted that TANESCO use 2.5 % per year to index or update project capital costs, to a reference planning year. Future fuel costs are from projections by the Energy Information Administration (Section 6.4). 3.2.5 Shadow pricing Shadow pricing is not used, as there is no restriction on currency trading. However differences in foreign exchange requirements between alternative plans should be identified. 3.2.6 Cost of un-served energy The cost of un-served energy depends on the perceived cost of outages (lost energy) to consumers. A typical value used in the East African region for planning studies has been 1.10 US$/kWh. This value is appropriate and will be used in the EAPP study. It is noted that un-served energy is treated as part of the operating cost since it is modeled as an artificial thermal plant with high fuel cost and infinite capacity, and thus may affect the timing of new plant additions, and amount of reserve that provides the least cost plan. The assumption of a relatively high cost of un-served energy would lead to a requirement for more new generation to reduce operating costs. In practice the development of alternative generation plans should require common reliability levels to be met, so un-served energy, if it exists should be similar for all alternatives, and thus this factor would not normally be a significant factor in comparisons of alternative generation plans.
  • 89. Final Master Plan Report 3-4 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 3.2.7 Allocation of costs for multipurpose projects A number of identified hydropower options also have the potential for providing benefits from flow regulation, i.e. for flood control and irrigation. Conventionally for some “economic” planning studies a credit is applied for such non power benefits. For this EAPP study, given the scarcity of estimates of potential benefits, or data from which these could be estimated, no credit will be given for secondary (non-power) benefits from multipurpose projects. It also has to be recognized that as benefits come from outside the electrical sector, it would be improbable that compensation for any such benefits would accrue to the operator of the power project. However it may be noted that in an economic evaluation of multipurpose projects, an approximation for comparison purposes could be made by assuming that 50% of the cost of the dam would be shared, i.e., financed by some agency responsible for the irrigation scheme or civil protection aspects such as flood control. 3.3 Generation planning criteria 3.3.1 Reliability criteria and reserve For systems where hydro makes an important component of the supply balance, normally a generation reliability criteria based on energy is needed. The reason is that in a hydro- dominated system the installed capacity normally exceeds the peak load by more than 20- 30% but the amount of firm energy is only slightly above the demand for energy. In this case a LOLP-based criterion will not capture the decrease in energy reserve over time. The historical record of hydrology used in this study consists of 35 years of monthly values. The criteria used for hydro-dominated systems are based on probabilities. In the case of the simulations with historic monthly inflow records that are used for the present study, the criteria to be met for every month in the study period are the following: • The probability of deficit must be less than 100%. This means that for a given month in the study period, not all of the hydro sequences examined may result in deficits, even if the deficits are small, and; • The probability that in any month the deficit is greater than 2% of the energy demand should be less than 5%. This means that no more than 2 hydro sequences should produce deficits greater than 2% of the demand9 . It is considered that deficits of 2% of the demand or lower can be managed by the system operator by making some operational adjustments in the system and the probability of this event occurring should be small (equal or less than 5%). For thermal systems typically a maximum loss of load expectation (LOLE) of 5 days per year, and a reserve margin on installed capacity of not less than the size of the largest unit is used. These criteria are considered appropriate and will be retained for this study. 3.3.2 Outage rates The availability of generation for a plant is the result of the duration of planned or scheduled maintenance periods and forced outage rates. The following tabulations show the rates selected for this study. These are similar to those used in the EAPMP. 9 2 sequences represent 2/35 ~ 5%
  • 90. Final Master Plan Report 3-5 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 3-2 Selected outage rates for generation planning Generation  type  Scheduled maintenance (weeks  per year)  Forced outage Rate (% of time  per year)  Availability factor  (%)  Coal STPP  6  8 80  Oil STPP  4  7 80  OCGT  4  5 80  CCGT  3  5 80  MSD  5  8 75  LSD  4  8 75  Geothermal  2  6 80  Cogeneration  8  6 75  Nuclear  4  3 90  Hydroelectric  4  0 90  3.3.3 Plant service lives The following service lives will be used in determining average unit generation costs for preliminary comparisons, and for determining retirement dates for existing and future plant in the development of generation plans: Table 3-3 Plant service lives Generation type Normal service life (years) OCGT  20 CCGT  20 MSD  20 LSD  25 Coal and oil STPP 25 Geothermal 25 Cogeneration 25 Nuclear  40 Hydroelectric plant 5010 3.3.4 Retirement of existing plant Existing generating units are assumed to be retired at the end of their normal “economic” service life, except for hydroelectric plants, which are assumed to remain in service. Assumed retirement dates for existing thermal plants will be as indicated in the national plans, or if not indicated, will be based on the above table. Retirement dates for new thermal 10 Normally extended by major equipment replacement and maintenance
  • 91. Final Master Plan Report 3-6 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study will be in accordance with the above table.11 For the generation planning model the default on-power month is January, and retirement month is December. 3.3.5 Rental units Emergency leased units will not be included as a generation resource. 3.3.6 Operation, maintenance and other costs Unit generation costs include allowances for operation and maintenance, interim replacement, and insurance. For thermal plants, the operation and maintenance cost is separated into fixed and variable components. For hydroelectric plant, all O and M cost is considered as fixed. Interim replacement is an annual allowance to cover periodic replacement of major equipment items that have a shorter service life than the overall project, such as turbines in a hydroelectric project. The allowances shown below will be used. Table 3-4 Operation, maintenance and other costs Plant type  Unit size (MW)  Fixed O&M (US$/kW/yr)  Variable O&M (US$/kWh)  Interim  Replacement (%)  Insurance (%)  Coal STPP  100‐500 50  0.0065 0.35  0.25 Coal STPP  50  70  0.0065 0.35  0.25 Oil STPP  100‐500 30  0.0045 0.35  0.25 Oil STPP  50  35  0.0045 0.35  0.25 OCGT  60  10  0.0050 0.35  0.25 CCGT  3x60  20  0.0040 0.35  0.25 MSD  50  20  0.0120 0.35  0.25 LSD  50  9  0.0100 0.35  0.25 Geothermal  70  35  0.0045 0.35  0.25 Cogeneration  20  70  0.0065 0.35  0.25 Nuclear  1000  75  Incl. in fixed 0.35  0.25 Hydroelectric  All  10  0 0.25  0.10 11 Service life for Nuclear plants is taken from UK experience and scheduled retirement dates – World Nuclear Association web site - Nuclear Power in the UK, November 2009
  • 92. Final Master Plan Report 4-1 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 4 EXISTING AND FUTURE GENERATION OPTIONS BY COUNTRY 4.1 Hydrology and hydro generation analysis The hydro energy is one of the most important natural resources in the Eastern Africa, for that reason and in accord with the TOR and the inception report, it was necessary to do an in-depth analysis of the hydrology and the potential hydro generation for the existing and future projects. 4.1.1 Hydrology The terms of reference require that "the results of the hydro systems energy capability for the region be determined by the review of each country´s hydrology". It is noted that this work for Tanzania was up to 2006 for 35 years of hydrological information in m3 /s for a monthly base (1972-2006). To have the hydrological information for the other countries in the same base a model developed by the Latin American Energy Organization (OLADE) called SUPER was used to fill up the missing information. The hydrological model of SUPER uses a mathematical representation of time series of inflows at different sites. The parameters for these series are estimated on the basis of historical records. A probabilistic representation of the inflows and their time and space dependencies can be achieved using the mean monthly flows, the standard deviations in monthly flows, correlation between stations in the same month, serial correlation for the same station and correlation between successive months for different stations. For these analyses the model uses the Matalas model and the Crosby and Maddock method. Appendix B includes a description of the hydrological model while the inflows database for all the countries on a monthly basis for the period 1972-2006 is included in Appendix C. 4.1.2 Calibration of hydro plants production Using the hydrological information produced with the hydrological model of SUPER, simulations of the hydro generation were carried out using the SDDP model. Each hydro plant’s yearly production was calibrated; at the same time the firm energy production was obtained, considering the production in 5% of the driest hydrological series (also called 1 in 20). The following Table 4-1 and the respective Figure 4-1 show a summary by country for the long term annual hydro production of the identified existing and committed hydro plants listed in Table 4-2 to Table 4-11. The potential annual hydro production for all the region is 167.8 TWh and the difference in relation with the references obtained from the studies of the projects and historical generation for the existing plants is only 1%. The firm energy is around 69% of the average generation. The total capacity is 32,319 MW, which means the average plant factor is around 59%. The potential of Ethiopia is around 46% of the whole region. The details by country and by hydro plant are included in Appendix D.
  • 93. Final Master Plan Report 4-2 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-1 Annual hydro production for identified options Country  MW  Hydro generation in GWh  Average Reference Variation Firm  %  Egypt  2902 13897 13932 ‐0.3% 13205  95%  Ethiopia  16204 76986 77588 ‐0.8% 53923  70%  Kenya  1300 6135 6093 0.7% 3573  58%  Burundi, Eastern DRC, Rwanda *  961 4620 4674 ‐1.2% 3628  79%  Sudan  4678 26393 26281 0.4% 22298  84%  Tanzania  3544 19722 19250 2.5% 13613  69%  Uganda  2730 20025 20218 ‐1.0% 20019  100% EAPP  32319 167778 168036 ‐0.2% 130259  78%  * Rwanda, Burundi and East DRC are merged because of the shared Ruzizi projects.  Figure 4-1 Average annual hydro production per country Values for the Firm Energy % for Uganda, Egypt and Sudan are high because hydro energy is available year-long, given the size of their reservoirs, be it natural or artificial. (e.g. Lake Victoria in Uganda, Aswan dam in Egypt) 4.2 Total identified options by country A listing has been prepared on a country by country basis of all the existing and identified future power options. These project lists are provided in Table 4-2 to Table 4-11 below. The following may be noted: • Projects less than 10 MW have been omitted 8% 46% 4% 3% 16% 12% 12% Egypt Ethiopia Kenya Burundi, Eastern DRC,  Rwanda Sudan Tanzania
  • 94. Final Master Plan Report 4-3 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study • Emergency rental units have been omitted • An existing or committed plant is defined as one which will be on-power in January 2013 • Plants due for retirement prior to January 2013 have been omitted • On-power dates for committed projects have been taken from country master plans, and based on reviews of the Inception Report by participating utilities; these dates are believed to be up to date. • On power dates for other projects have been based on the level of preparation of the project and size, as outlined in Sections 5.3 and 6.2. In some cases the earliest on-power date is affected by other issues, as are shown in Section 5.4 so reference should be made to Table 5-10. Some of the projects included in the listings may be considered less certain due to the need of further assessment; however, these have been included as the objective has been to provide a maximum listing of potential, however the comments in Table 5-10 should be noted. • Projects that are mutually exclusive have been omitted (i.e., would be in conflict with a project in the listing (such as Masindi in Uganda) • Hydro energy values are based on country level simulations carried out for this study. Downstream benefits from storage operation are not attributed • Capital costs have been updated and harmonized • Future project listings are not intended to suggest an order of preference for development • Retirements of existing or committed thermal plants have not been taken into account, as these tables are intended as a catalogue of resources. Projected retirement dates for existing thermal are shown in Table 6-17. • Based on the service lives assumed for this study, most thermal plant to be installed near the beginning of the planning period would be retired before the end of the planning period. The References used for filling the following tables are all listed in Table 2-2.
  • 95. Final Master Plan Report 4-4 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-2 Burundi Generation Plant Name  Nom.  Energy Plant Factor  Level Min. Earliest  Ref Cap.  Avg.  Firm of lead time year  MW  GWh  GWh Prep. (years) on power  Hydro Existing Rwegura  18.0  70  59 0.44 1986  51 Mugere  8.0  31  26 0.44 1982  51 Ruvyironza  1.3  5  4 0.44 1984  51 Gikonge  0.9  3  3 0.44 1982  1 Nyemanga  2.8  11  9 0.44 1988  50 S/T  31.0  120  101   Thermal existing Bujumbura  5.5  36  36 0.75 1996  1 Total Ex. 2012  36.5  156  115   Imports/Sharing Existing Ruzizi II  12.0  83  83   1 S/T  12.0  83  83   Total Ex. Supply 2012 48.5  239  198   Hydro Future Kabu 16  20.0  113  100 0.64 F 5 2015  1 Kagunuzi Complex  39.0  187  177 0.55 F 6 2016  1 Mpanda  10.0  40  34 0.46 F 6 2016  1 Mule 34  16.5  54  45 0.37 PF 6 2016  1 Jiji 03  15.5  40  33 0.29 PF 6 2016  1 Siguvyaye  90.0  510  486 0.65 F/D 6 2016  1 S/T  191.0  940  836   Imports/Sharing Future Lake Kivu gas plant 2  66.7  438  438 0.75 F   Rusumo   20.0  49  43 0.28 F 5 2015  3,4,23 Ruzizi III  48.3  222  222 0.52 F 8 2018  1 Ruzizi IV  95.7  420  420 0.50 PF 9 2019  S/T  230.7  691  685   Total Fut. Options  421.7  2069  1959   Total Fut. Supply  470.1  2308  2157   Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 96. Final Master Plan Report 4-5 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-3 Djibouti Generation Plant Name  Nom. Cap.  MW  Energy in  GWh  Plant  Factor  Level  of  Prep.  Min. lead time (years)  Earliest  year on  power  Ref Avg.  Firm GWh  GWh Thermal Existing Boulaos  108  662  662 0.7    60 Marabout  15  92  92 0.7    60 S/T  123  754  754    Total Ex. Supply  123  754  754    Thermal Future Geothermal 20  60  420  420 0.8    60 Diesel 7  28  196  196 0.8    60 Diesel 12  84  589  589 0.8    60 OCGT 15  15  105  105 0.8    60 S/T  187  1310  1310    Imports/Sharing Future Ethiopia  100  350  350 0.80 2010  Total Fut. Options  287  1310  1310    Total Fut. Supply  410  2065  2065    Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 97. Final Master Plan Report 4-6 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-4 Eastern DRC Generation Plant Name  Nom.  Cap.  MW  Energy in  GWh  Plant  Factor  Level  Of  Prep.  Min. lead  time  (years)  Earliest  year on  power  Ref  Avg.  Firm GWh  GWh Hydro Existing Tshopo 1  19  142  122 0.87    Ruzizi I  30  136  100 0.52    Ruzizi II  36  247  190 0.78    S/T  85  525  412    Thermal Existing SNEL  18  53  53 0.34    S/T  18  53  53    Imports/Sharing Existing Ruzizi I  ‐14  ‐39  ‐39    Ruzizi II  ‐24  ‐167  ‐167    S/T  ‐38  ‐206  ‐206    Total Ex. Supply  65  578  465    Hydro Future Piana Mwanga ‐ rehab  29  182  122 0.72 R 6 2017  Bendera  43  143  100 0.38 R 6 2017  2,5,6 Babeda I  50  341  190 0.78 R 6 2017  2,5,6 Bengamisa  48  363  135 0.86 R 6 2017  2,5,6 Mugomba  40  163  107 0.47 R 6 2017  2,5,6 Semliki  28  118  262 0.48 R 6 2017  2,5,6,48 Ruzizi III  145  664  306 0.52 F 6 2016  2,5,6 Ruzizi IV (Sisi 5C)  287  1249  121 0.50 PF 9 2019  2,5,6 Wannie Rukula  668     R 9 2019  2,5,6 S/T  1338  3222  1342    Imports/Sharing Future Lake Kivu gas Plant 2  67  438  438 0.75 F    2 Ruzizi III  ‐97  ‐444  ‐840 F 8 2018  2,5,6 Ruzizi IV  ‐191  ‐840  ‐840 PF 9 2019  2,5,6 S/T  ‐221  ‐846  ‐1242    Total Fut. Options  1117  2376  100    Total Fut. Supply  1182  2954  565    Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 98. Final Master Plan Report 4-7 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-5 Egypt Generation Plant Name  Nom.  Cap. MW  Energy in GWh  PF  Level   Of   Prep.  Min.   Lead time  (years)  Earliest  year on  power  Ref Avg.  Firm  GWh  GWh  Hydro Existing  Aswan 1  322  1512  1434  0.54           10,14  High Aswan  2,100  9921  9425  0.54           10,14  Aswan II  270  1770  1695  0.75           10,14  Esna  86  411  384  0.55           10,14  Naga Hamadi  64  19  13  0.03           10,14  Diamata  20  88  88  0.50        2012     S/T  2862  13722  13039                 Wind/Solar Existing  Wind Zafarana total  305  830  830  0.30        2008  14  Solar  100  613  613  0.70        2009  14  S/T  405  1443  1443                 Thermal Existing  Total thermal 2009  19,062  133586  133586  0.80        2009     Sidir Khir CCGT  750  5256  5256  0.80        2010     Nobaria 3 CCGT  750  5256  5256  0.80        2010  9,10,14  Kurimat 3 CCGT  750  5256  5256  0.80        2010  9,10,14  Tebbin STPP  700  4906  4906  0.80        2010  9,10  Atf CCGT  750  5256  5256  0.80        2010     Cairo West STPP  700  4906  4906  0.80        2011     Nowebaa CCGT  750  5256  5256  0.80        2012     Abu Kir STPP  1,300  9110  9110  0.80        2012     Banha CCGT  750  5256  5256  0.80        2012     S/T  26262  184044  184044                 Imports/Sharing Existing  Lybia  ‐150  ‐800  ‐800              10,14  Jordan  ‐500  ‐800  ‐800              10,14  S/T  ‐650  ‐1600  ‐1600                 Net Ex. Supply  28879  197609  196926                 Hydro Future  Assiut  40  175  166  0.50  D     2015  14  S/T  40  175  166                 Wind/Solar Future  Wind Zafarana total  7,530  19,789  19,789  0.30        2008  14,59  S/T  7530  19789  19789                 Thermal Future  Ain Sokhna STPP  1,300  9110  9110  0.80        2014  59  Qassasen CCGT  1,250  8760  8760  0.80        2014  59  Qassasen CCGT  250  1752  1752  0.80        2015  59  Giza North CCGT  1,000  6132  6132  0.70        2013  59  Giza North CCGT  500  3066  3066  0.70        2014  59  Suez STPP  650  4555  4555  0.80        2014  59  Helwan south STPP  1,300  9110  9110  0.80        2015  59  Helwan south STPP  1,300  9110  9110  0.80        2017  59  Qena STPP  650  4555  4555  0.80        2015  59  Qena STPP  650  4555  4555  0.80        2016  59  Damietta West 1 CCGT  1,500  10512  10512  0.80        2017  59  Damietta West 2 CCGT  1,500  10512  10512  0.80        2019  59 
  • 99. Final Master Plan Report 4-8 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Plant Name  Nom.  Cap. MW  Energy in GWh  PF  Level   Of   Prep.  Min.   Lead time  (years)  Earliest  year on  power  Ref Avg.  Firm  GWh  GWh  Safaga STPP  1,300  9110  9110  0.80        2018  59  Steam 650 MW  16,250  113880  113880  0.80        2019‐2027  59  Combined cycle  8,250  57816  57816  0.80        2019‐2027  59  Dabaa nuclear  5,000  39420  39420  0.90        2018‐2027  59  S/T  42650  301957  301957                 Total Fut. Options  50220  321921  321912                 Total Fut. Supply  79099  519531  518838                 Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 100. Final Master Plan Report 4-9 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-6 Ethiopia Generation Plant Name  Nom  Cap.   MW  Energy in GWh Plant   Factor  Level of   Prep.  Min.  lead  time  (years)  Earliest  year on  power  Ref Avg.  Firm GWh  GWh  Hydro Existing Tis Abbay 1  11 35  24 0.35 1964  10,15,38 Tis Abbay 2  73 417  237 0.65 2001  10,15,38 Finchaa  134  760  548 0.65 1973 ‐ 2003  10,15,38 Gilgel Gibe 1  192  878  587 0.52 2004  10,15,38 Malka Wajana  153  437  254 0.33 1988  10,15,38 Awash 1  43 100  64 0.27 1960  10,15,38 Awash 2  32 138  89 0.49 1966  10,15,38 Awash 3  32 152  98 0.54 1971  10,15,38 Gibe II  420  1914  1279 0.52 2009  10,47 Beles  460  2134  1684 0.53 2010  10,15,21,47 Tekeze I  300  1390  785 0.53 2009  10,47,49 S/T  1851  8356  5650    Wind Existing Ashegoda wind  120  526  526 0.50    2,7 Adana  51 223  223 0.50    S/T  171  749  749    Thermal Existing Dire Dawa Diesel  44 289  289 0.75    15 Awash 7 Diesel  35 230  230 0.75    15 Kaliti  Diesel  14 92  92 0.75    15 Aluto Geothermal  7 48  48 0.75    10 Small diesel  57 250  250 0.50    15 S/T  157  909  909    Imports/Sharing Existing Sudan  120  1900  1900 2010   20 S/T  120  1900  1900    Total Ex. Supply  2299  11914  8207    Hydro Future Gibe III  1,870  6087  3881 0.37 C 2013  10,21,26,47 Gibe IV  1,468  5644  3611 0.44 C 5 2015  41,10,47 Halele Worabesa  422  2215  1204 0.60 F 8 2014  10,47 Chemoga‐Yeda  280  1384  840 0.56 D 6 2016  10,26,47 Geba I & II  372  1802  1329 0.55 F 8 2018  10,47 Genale 3D  258  1228  855 0.54 D 6 2015  10,26 Baro 1 and 2 + Genji  900  4522  3546 0.57 D 6,7 2016, 2017  10,42,47 Mandaya  2,000  11950  8834 0.68 PF 9 2019  10,25 Border  1,200  6331  5789 0.60 PF 9 2019  10,25,47 Gibe V  662  1882  1202 0.32 PF 9 2019  43, 47 Beko Abo  2,100  10825  7300 0.59 R 9 2019  8 Karadobi  1,600  8784  6081 0.63 F 8 2018  10 Genale 6D  246  1609  1114 0.75 D 6 2016  10,26 Gojeb  150  526  373 0.40 D 6 2016  10
  • 101. Final Master Plan Report 4-10 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Plant Name  Nom.   Cap.  MW  Energy in GWh Plant   Factor  Level of   Prep.  Min.  lead  time  (years)  Earliest  year on  power  Ref Avg.  Firm GWh  GWh  Tekeze II  450  1758  990 0.45 PF 9 2019  47 Aleltu East  186  885  619 0.54 F 8 2018  10 Aleltu West  265  1028  598 0.44 PF 9 2019  10 Awash 4  38 166  106 0.50 F 6 2016  10 S/T  14467  68627  48272    Thermal Future Aluto Langano geothermal  75 493  493 0.75 PF 6 2016  46 Tendaho geothermal  100  657  657 0.75 PF 8 2018  46 Corbetti geothermal  75 493  493 0.75 PF 8 2018  46 Abaya geothermal  100  657  657 0.75 PF 8 2018  46 Tulu Moye geothermal  40 263  263 0.75 PF 8 2018  46 Dofan Fantale geothermal  60 394  394 0.75 PF 8 2018  46 S/T  450  2957  2957    Imports/Sharing Future Djibouti  ‐100  ‐350  ‐350 0.80 2010  Sudan  ‐1200  ‐7,000  ‐7,000 2010  21 Kenya  ‐2,000  ‐14,000  ‐14,000 2013  S/T  ‐3300  ‐21,350  ‐21350    Total Fut. Options  11617  48634  28278    Total Fut. Supply  13916  60547  37485    Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 102. Final Master Plan Report 4-11 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-7 Kenya Generation Plant Name  Nom.  Cap. MW  Energy in GWh Plant  Factor  Level of  Prep.  Min. lead  time  (years)  Earliest year  on power  Ref Avg.  Firm GWh  GWh Hydro Existing Misc plants  10           27 Tana  20  37  23 0.21 1932‐55  27,2,7,52 Wanji  7  37  26 0.61 1952  27,2,7,52 Kambaru  94  460  240 0.56 1974  27,2,7 Gitaru  225  892  461 0.45 1978  27,2,7 Kindaruma  40  168  87 0.48 1968  27,2,7 Masinga  40  191  92 0.55 1981  27,2,7 Kiambere  164  916  486 0.63 1988  27,2,7,52 Sondu Miriu  60  404  330 0.77 2008  27,2,7,52 Turkwell  106  437  281 0.47 1991  27,2,7,52 Sangoro  21  143  117 0.78 C 2011  20 Kindaruma U3  25  105  54 0.48 C 2012  20 Tana ‐ Extension  10  26  16 0.30 C 2010  27 S/T  823  3816  2214    Wind Existing Ngong  20  88  88 0.50 2012  S/T  20  88  88    Thermal Existing Olkaria 1  45  355  355 0.90 1981  27 Olkaria 2  105  828  828 0.90 2003  27 OrPower 4a  13  102  102 0.90 2000  27 OrPower 4b  35  276  276 0.90 2008  20 Olkaria 3  geothermal  35  230  230  0.75        2010  27  Kipevu 1 Diesel  75  526  526 0.80 1999  27 Kipevu new GT  60  394  394 0.75 1987/1999  27 Nairobi Fiat  13  91  91 0.80 1999  2,20,27 Diesel  120  788  788 0.75 2010  20 Iberafrica IPP  56  368  368 0.75 2000  27 Athi river diesel  IPP (Thika)  240  1577  1577  0.75        2012  20  Rabai diesel IPP  89  585  585 0.75 2009  20 Iberafrica 3 IPP  53  348  348 0.75 2009  20 Tsavo IPP  74  519  519 0.80 2001  27 Cogen  26  0  0  0.00 2001  20 Aggreko IPP  60  394  394 0.75    27           S/T  1100  7380  7380    Total Ex. Supply  1916  11283  9681             
  • 103. Final Master Plan Report 4-12 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Plant Name  Nom.  Cap. MW  Energy in GWh Plant  Factor  Level of  Prep.  Min. lead  time  (years)  Earliest year  on power  Ref Avg.  Firm GWh  GWh Hydro Future Mutonga  60  336  198 0.64 F 6 2016  27 Low Grand Falls  140  707  415 0.58 F 7 2017  27 Magwagwa  120  525  345 0.50 F 7 2017  2 Total Ewaso  Ngiro  180  568  306  0.36  F  7  2017     Karura  56  184  95 0.37 PF 6 2016  S/T  556  2319  1359    Wind Future Turkana wind  300  1314  1314 0.50 2013  20 Aeolus Wind  160  700  700 0.50 2013  Osiwo wind  50  219  219 0.50 2013  20 Karura  56  182  182 0.37    S/T  406  1715  1715    Thermal Future Geothermal  Fut. Res.  2800  18396  18396  0.75           27  Olkaria 4 & 5  geothermal  140  920  920  0.75        2014  27  Mombasa Coal  1200  8410  8410 0.80    Cogen  126  828  828 0.75    S/T  4266  28553  28553    Imports/Sharing Future Ethiopia Phase  1  1000  7008  7008  0.80        2013  27  Ethiopia Phase  2  1000  7008  7008  0.80         2013  27  Tanzania  ‐200  ‐1403  ‐1403 0.80 2015  27 S/T  1600  9810  98210    Total Fut.  Options  7188  43097  41777                 Total Fut.  Supply  8805  54380  51818                 Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 104. Final Master Plan Report 4-13 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-8 Rwanda Generation Plant Name  Nom.  Cap.  MW  Energy in  GWh  Plant  Factor  Level of  Prep.  Min. lead  time  (years)  Earliest  year on  power  Ref  Avg.  Firm GWh  GWh Hydro Existing Mukungwa  12.5  57  57  0.52        1982  1,51  Ntaruka  11.3  51  51  0.52        1959  1,51  Gihiria  1.8  8  8  0.52        1985  1,51  Gisenyi  1.2  5  5  0.52        1969  1,51  Small/mini hydros  10.0  46  46  0.52     2  2012  18  S/T  37  168  168                 Thermal Existing  Gatsata  4.7  31  31  0.75        1975  51  Jabana   7.8  51  51  0.75           51  Mukungua  4.5  30  30  0.75        2006  51  New Diesel  20.0  131  131  0.75        2009  17  RIG Kivu gas pilot  4.5  30  30  0.75        2009  17  S/T  42  273  273                 Imports/Sharing Existing  Ruzizi I  14.0  124  124              1  Ruzizi II  12  83  83              1  Uganda  1  3  3                 S/T  27  210  210                 Total Ex. Supply  105  650  650                 Hydro Future  Nyabarongo  27.8  150  129  0.62  D  4  2014  1,51  Rukarara I  9.5  42  42  0.50  F  4  2014  18  S/T  37  192  170                 Thermal Future  Biomass/peat  50.0  329  329  0.75  F     2013  18  Kivu gas Plant 1  100.0  657  657  0.75  F     2013  29  S/T  150  986  986                 Imports/Sharing Future  Kivu gas Plant 2 (shared)  66.7  438  438  0.75  F     2015     Rusumo  20.0  49  43           2015  3,4,23 Ruzizi III  48.3  222  222  0.52  F  8  2018  2,5,6  Ruzizi IV  89.0  373  373  0.48  PF  9  2019  2,5,6  S/T  223.7  1082  1076                 Total Fut. Options  411  2259  2232                 Total Fut. Supply  516  2909  2882                 Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 105. Final Master Plan Report 4-14 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-9 Sudan Generation Plant Name  Nom.  Cap.  MW  Energy in  GWh  Plant  Factor  Level  Of  Prep.  Min. lead  time  (years)  Earliest  Year on  power  Ref  Avg.  Firm GWh  GWh Hydro Existing Rosieres  280  1948  1716 0.79 1971  10,19 Sennar  15  52  46 0.40 1962  10,19 Kashm El Girba  18  80  80 0.51 1965  10,19 Jebel Aulia  30  131  119 0.50 2003  10,19 Merowe  1250  5701  4771 0.52 2009  Sennar extension  50  174  153 0.40 C 2011  22 Rosieres/Dinder  135  939  827 0.79 C 2012  19,22 S/T  1778  9026  7711    Thermal Existing Dr. Sharif 1 STPP  60  420  420 0.80 1985  10,19 Dr. Sharif 2 STPP  120  788  788 0.75 1994  10,19 Khartoum North OCGT  50  329  329 0.75 1992  22 Khartoum North STPP  160  1051  1051 0.75    22 Khartoum North STPP  200  1314  1314 0.75 2008  22 Garri 1 CCGT  220  1445  1445 0.75 2003  10,19 Garri 2 CCGT  240  1577  1577 0.75 2008  22 Garri 4 STPP  100  657  657 0.75 2007  22 Kilo MSD  40  263  263 0.75 2007  22 Atbara MSD  13  88  88 0.75 2003  19 Kassala 1‐5 STPP  50  329  329 0.75 2007  30 Kosti  1&2 STPP  250  1643  1643 0.75 2010  30 Al Fula 1&2 STPP  270  1774  1774 0.75 2010  30 Kosti 3&4 STPP  250  1643  1643 0.75 2010  22 Al Fula 3&4 STPP  270  1774  1774 0.75 2010  22 S/T  2293  15094 15094    Imports/Sharing Existing Ethiopia  ‐120  ‐1900  ‐1900 2010   20 S/T  ‐120  ‐1900  ‐1900   
  • 106. Final Master Plan Report 4-15 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Plant Name  Nom.  Cap.  MW  Energy in  GWh  Plant  Factor  Level  Of  Prep.  Min. lead  time  (years)  Earliest  Year on  power  Ref  Avg.  Firm  GWh  GWh Total Ex. Supply  3951  22220  20905    Hydro Future Rumela  30  83  79 0.31 C 2013  9,10,30 Sabaloka  90  670  546 0.85 PF 2017  9 Shereiq  315  1962  1695 0.71 F 6 2016  9,10,30 Kagbar  300  1413  1186 0.54 F 8 2018  9,10,30 Dal 1 (Low)  340  1968  1698 0.66 PF 8 2018  9,10,30 Dagash  285  1503  1294 0.60 PF 9 2019  9,10,30 Fula 1  720  4134  3382 0.66 PF 9 2020  9,10,30 Shukoli  210  1443  1209 0.78 PF 9 2020  9,10,30 Lakki  210  1443  1209 0.78 PF 9 2020  9,10,30 Bedden  400  2748  2287 0.78 PF 9 2020  9,10,30 S/T  2900  17367  14587    Thermal Future Port Sudan 1‐3 STPP  405  2838  2838 0.80 2013  22.3 Garri 3 1‐3 STPP  405  2838  2838 0.80 2013  22,30 Garri 3  U4 STPP  135  946  946 0.80 2013  22,30 El Bagair 1&2 STPP  270  1892  1892 0.80 2013  22,30 El Bagair 3&4 STPP  270  1892  1892 0.80 2013  22,30 Crude fired  2 x 238  476  3336  3336 0.80 6 2016  30 Crude fired 3 x 475  1425  9986  9986 0.80 6 2016  30 CCGT 3 x 208  624  4373  4373 0.80 3 2013  30 CCGT 4 x 342  1368  9587  9587 0.80 3 2013  30 CCGT  4 x 458  1832  12839  12839 0.80 3 2013  30 S/T  7210  50528  50528    Imports/Sharing Future Ethiopia  1200  7000  7000    20 S/T  1200  7000  7000    Total Fut. Options  11310  74895  72115    Total Fut. Supply  15261  97114  93020    Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design
  • 107. Final Master Plan Report 4-16 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Note: Negative Imports in the table represent Exports. Table 4-10 Tanzania Generation Plant Name  Nom.  Cap.  MW  Energy in  GWh  Plant  Factor  Level  of  Prep.  Min. lead  time  (years)  Earliest  year on  power  Ref Avg. Firm GWh GWh Hydro Existing Mtera  80  335 218 0.48    1988  3 Kidatu  204  909 646 0.51    1975  3 Hale  21  81 54 0.44    1967  3 Kihansi  180  663 491 0.42    2000  3 Pangani Falls  68  289 192 0.49    1995  3 Nyumba ya Mungu  8  34 21 0.48    1968  3 S/T  561  2311 1622       Thermal Existing Songas 1  42  276 276 0.75       3 Songas 2  120  788 788 0.75       3 Songas 3  40  263 263 0.75       3 Ubongo GT  100  657 657 0.75       3 Tegeta IPTL  100  657 657 0.75       3 Tegeta GT  45  296 296 0.75    2009  3 Mwanza  60  420 420 0.80    2010  3 Ubongo EPP  100  657 657 0.75    2011  3 Cogen  37  243 243 0.75    2011  3 S/T  644  4257 4257       Total Ex. in 2012  1205  6569 5879       Hydro Future Ruhudji  358  1928 1377 0.61 F/D 6  2016  3 Rusumo  63  444 419 0.80 F 6  2016  3 Kakono  53  404 416 0.87 PF 6  2016  3 Songwe Bigupu  34  153 107 0.51 PF 6  2016  3 Songwe Sofre  157  780 512 0.57 PF 9  2019  3 Songwe Manolo  149  736 494 0.56 PF 8  2020  3 Masigira  118  664 519 0.64 PF 8  2018  3 Mpanga  144  955 698 0.76 PF 8  2018  3 Taveta  145  850 657 0.67 PF 8  2020  3 Rumakali  222  1475 988 0.76 F 8  2018  3 Ikondo  340  1832 1393 0.62 PF 9  2019  3 Stieglers Gorge  1200  6674 4410 0.63 PF 9  2019  3 S/T  2941  16895 11991       Thermal Future
  • 108. Final Master Plan Report 4-17 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Plant Name  Nom.  Cap.  MW  Energy in  GWh  Plant  Factor  Level  of  Prep.  Min. lead  time  (years)  Earliest  year on  power  Ref Avg. Firm GWh GWh Kiwira  200  1402 1402 0.80    2013  3     GWh GWh     Kinyerezi  240  1577 1577 0.75    2013  3 Mnazi Bay   300  1971 1971 0.75    2017  3 Ngaka   400  2803 2803 0.80    2024  3 Mchuchuma  400  2803 2803 0.80    2025  3 S/T  1540  10556 10556       Imports/Sharing Future From Ethiopia (through Kenya)  200  1489 1489 0.85    2014  3 From Zambia  200  1489 1489 0.85    2015  3 Total Fut. Options  4881  30429 25526       Total Fut. Supply  6128  36998 31405       Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 109. Final Master Plan Report 4-18 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 4-11 Uganda Generation Plant Name  Nom.  Cap.  MW  Energy in  GWh  Plant  Factor  Level of  Prep.  Min. lead  time  (years)  Earliest  year on  power  Ref Avg. Firm GWh GWh Hydro Existing Misc plants  15     0.00    37 Nalubaale  180  767 766 0.49    37 Kira 11‐15  200  747 747 0.43    37 Bujagali 1‐5  250  1970 1966 0.90 C 2011  37 Small hydros(commited)  50     0.00 C 2011  37 S/T  695  3485 3480    Thermal Existing Kakira  17  112 112 0.75    2,7 Namanve  50  329 329 0.75    Invespro HFO IPP  50  329 329 0.75 2010  Electromax IPP  10  66 66 0.75 2009  S/T  127  834 834    Total Ex. Supply  822  4319 4314    Hydro Future Karuma high  700  5512 5512 0.90 F 8 2018  37 Murchison Falls  high  750  5904 5903 0.90 PF 9 2019  37 Isimba  100  788 788 0.90 PF 6 2016  37 Ayago    550  4336 4336 0.90 PF 9 2019  37 Small hydro candidates  37     PF 6 2016  37 S/T  2137  16540 16540    Thermal Future Kampala steam  56  392 392 0.8 6 2016  37 Tallow steam  53  371 371 0.8 6 2016  37 Tallow GT  57  399 399 0.8 6 2016  37 Tallow CCGT  185  1296 1296 0.8 6 2016  37 Tallow diesel  10  70 70 0.8 6 2016  37 Geothermal  33  231 231 0.8 6 2016  37 S/T  394  2761 2761    Total Fut. Options  2531  19301 19301    Total Fut. Supply  3353  23620 23615    Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design Note: Negative Imports in the table represent Exports.
  • 110. Final Master Plan Report 4-19 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 4.3 Summary of present and future generation resources Based on the project listings in the previous section, the total resources in each country for 2013 and 2030 may be summarized as shown below. The resources are limited to resources as presented in the master plans for each country. Demands are taken from the Module 1A- 1100 report. This table provides a clear indication that Ethiopia, and possibly the DRC will be significant net exporters. The Uganda resource total includes a number of hydro projects on the Nile. The DRC is a special case. As was noted in Section 1, this study is only considering resources in the Eastern part of the country. However the DRC total undeveloped resources may be in the order of 60,000 MW. Unfortunately this potential has not been assessed to a level where it may be incorporated into the planning process. Table 4-12 Present and future potential generation resources COUNTRY  Existing  FUTURE TOTAL DEMAND SURPLUS  2012  2013‐2030 2030 2030 2030  MW  MW MW MW MW  Burundi  49  422 470 385 86  Djibouti  123  187 310 198 112  East DRC  74  1,117 1,191 179 1,012  Egypt 25,879  46,570 72,449 69,909 2,540  Ethiopia  2,179  13,617 15,796 8,464 7,332  Kenya 2,051  6,288 8,339 7,795 544  Rwanda  103  411 514 484 30  Sudan 3,951  11,310 15,261 11,054 4,207  Tanzania  1,205  4,881 6,086 3,770 2,316  Uganda  822  2,531 3,353 1,898 1,455  TOTAL 36,436  87,334 123,769 104,136 19,633 
  • 111. Final Master Plan Report 5-1 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 5 FUTURE HYDROELECTRIC OPTIONS 5.1 Identifications of new hydroelectric options Potential hydroelectric projects in each country have been identified in country generation expansion plans, as a result of previous studies at the reconnaissance, prefeasibility and feasibility levels. These projects are all listed in the previous section in the country project listings. However relatively recent master plans were only available for certain countries, and for the other countries the candidate lists were made up from other sources, as listed in Section 2. In general it has been assumed that projects listed in master plans have been judged as potentially acceptable in terms of costs and social and environmental potential impacts. However it has to be recognized that some projects will require further assessment before they can be included in short or mid-term plans. To take this into account the screening process described in Section 5.4 has proposed that projects needing further assessment should be considered for implementation after 2018. Similarly a number of the identified projects are at a very preliminary stage of preparation, and would consequently need long lead times for implementation. This fact has also been taken into account, in prioritizing future developments. Hydropower planning consists of the steps required to identify and evaluate potential hydroelectric sites, and then to arrange implementation of a selected hydroelectric project. This can include upgrades of existing projects, as well as new plants. The hydropower planning and implementation process therefore comprises the following steps: • Identification and inventory of potential sites • Reconnaissance investigation of selected sites • Prefeasibility study of preferred sites • Feasibility studies of best sites • Design and tender documents • Construction Usually identification and inventory activities will go ahead quite separately from the power system studies that are used to define future new generation needs. By comparison, all later stages of hydroelectric project planning are closely related to the overall power system planning process. The project evaluation studies leading up to the project commitment at each stage includes the full range of activities needed to define the project scheme, to estimate generation benefits, and to evaluate the project. The difference between each phase is the level of effort applied to each phase, in terms of engineering and extent of field investigations and, to a large degree, the accuracy of the estimated project costs is directly related to the extent of the field investigations. While much may be made of the need for optimization studies to define the project size (e.g. dam height and installed capacity), the economics of a reasonably, if sub-optimal, scheme will only differ marginally from the estimated economic viability of the ideal project. It is instructive to compare the level of generally accepted levels of expenditures, and resulting contingency allowances with the amount of field investigations in the various study phases. This indicates the importance of assessing the actual level of preparation of a project, and the level of confidence in the results.
  • 112. Final Master Plan Report 5-2 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-1 Typical cost values for projects Cost Element  REC PF  F  Total Contingency allowances %* 25 10‐15  8‐10  ‐‐ Accuracy %  35 15  8  ‐‐ Filed investigation costs as % of cost of each study phase ** 14 42  47  ‐‐ Field investigation cost as % of total study costs estimates ** 3 12  24  39 Study cost as % of total capital  0.4 0.6  1.1  2.1 Level of Prep ‐ C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design  *Indicated  contingency  allowances  are  percentages  of  total  costs  for  construction,  engineering  and  construction supervision.  **Based on approximate cost of field investigations The list of identified future hydro options is provided in Table 5-2 below. (The level of preparedness is taken from the reference reports.)
  • 113. Final Master Plan Report 5-3 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-2 List of identified new hydro options Country  Name  Installed  Average  Firm Level Country  Name  Installed  Average  Firm Level Capacity  Energy  Energy of Capacity  Energy  Energy of (MW) (GWh)  (GWh) Prep. (MW)  (GWh)  (GWh) Prep. Burundi  Jiji 03  15.5 40  33 PF Kenya  Mutonga 60  336  198 F Kabu 16  20  113  100  F  Low  Grand  Falls  140  707  415  F  Kaganuzi A  34 98.00  PF Magwagwa 120  525  345 F Kaganuzi  Complex  39  187  177  F  Total  Ewaso  Ngiro  180  568  306  F  Mpanda  10 40  34 F Karura  56  184  95  PF  Mule 34  16.5 54  45 PF Siguvyaye  90 510.00  486 F/D Rwanda Nyabarongo 27.8  150  129 D East DRC  Piana Mwanga  29 182  122 REC Sudan  Sabaloka 90  670  546 PF Bendera  43 143  100 REC Shereiq 315  1962  1695 F Babeda I  50 341  190 REC Kagbar 300  1413  1186 F Bengamisa  48 363  135 REC Dal 1 (Low) 340  1968  1698 PF Mugomba  40 163  107 REC Dagash 285  1503  1294 PF Semliki  28 118  262 REC Fula 1 720  4134  3382 PF Ruzizi III  145 664  306 F Shukoli 210  1443  1209 PF Ruzizi IV (Sisi  5C)  287  1249  121  PF  Lakki  210  1443  1209  PF  Wannie Rukula  668   REC Bedden 400  2748  2287 PF Egypt  Assiut  40 175  166 D Tanzania  Ruhudji 358  1928  1377 F/D Ethiopia  Gibe III  1,870 6087  3881 C Rusumo 63  444  419 F Gibe IV  1,468 5644  3611 C Kakono 53  404  416 PF Halele  Worabesa  422  2215  1204  F  Songwe  Bigupu  34  153  107  PF  Chemoga‐Yeda  280 1384  840 D Songwe Sofre 157  780  512 PF Geba I & II  372  1802  1329  F  Songwe  Manolo  149  736  494  PF  Genale 3D  258 1228  855 D Masigira 118  664  519 PF Baro 1 and 2 +  Genji  900  4522  3546  D  Mpanga  144  955  698  PF  Mandaya  2,000 11950  8834 PF Taveta 145  850  657 PF Border  1,200 6331  5789 PF Rumakali 222  1475  988 F Gibe V  662 1882  1202 PF Ikondo 340  1832  1393 PF Beko Abo  2,100  10825  7300  R  Stieglers  Gorge  1200  6674  4410  PF  Karadobi  1,600 8784  6081 F Uganda  Karuma high 700  5512  5512 F Genale 6D  246  1609  1114  D  Murchison  Falls  high  750  5904  5903  PF  Gojeb  150 526  373 D Isimba 100  788  788 PF Tekeze II  450 1758  990 PF Ayago   550  4336  4336 PF Aleltu East  186 885  619 F Aleltu West  265 1028  598 PF Awash 4  38 166  106 F
  • 114. Final Master Plan Report 5-4 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 5.2 Capital costs for future hydro projects Capital costs for hydro projects were taken from the most recent master plan or project study report. It was always assumed that the most recent report provides the best information, even if there are significant differences with previous reports. Costs were updated as is described in Section 5.2.1. These estimates were checked to determine if they included IDC and environmental mitigation costs. Where mitigation costs were not included in the basic project construction cost estimate, an allowance was added, as outlined in Section 5.2.2. Allowances for interest during construction were added, where not included in the basic previous estimate, as outlined in Section 5.2.3. It may be noted that relatively detailed cost estimates were only available for some projects. Particularly cost estimates were available for most of the Ethiopian hydro projects and for the Dal scheme in Sudan. Summary estimates for the projects in Kenya, Tanzania and Uganda studied for the EAPMP were available. Studies for the projects in Burundi and Rwanda were generally available. For the SSEA study some of the project costs were re-estimated, including: • Kabu 16 and Mpanda in Burundi • Nyabarongo in Rwanda • Igamba 2 in Tanzania Cost breakdowns for these projects were available. For the Eastern DRC projects the only data available was that provided in the compendium by Male Cifarha [6]. The cost estimates for the projects for the Ethiopia MoWR and ENPTPS are mostly recent and are relatively consistent. The estimates for the EAPMP were reviewed as part of the 2006 SSEA study and all those estimates are considered to be reasonable and consistent. No assessment could be made of the estimates for the DRC and Burundi, Rwanda projects, other than those referred to above. In any case these estimates are old, and more modern design concepts could change the costs significantly. 5.2.1 Procedure for updating costs Information on the projects being assessed is provided in the various study reports done previously. These various studies are at different levels of engineering development, and were done at different times in the past. Also in some case the documentation on these projects is not complete. Built into these estimates are possibilities for different criteria or approaches to have been used, such as application of contingencies, environmental mitigation, and overheads such as owner’s costs. It is assumed that in accordance with normal practice for “economic” assessment of projects with the expectation of public sector implementation, taxes and duties have not been included. For the purpose of making the comparisons in this assessment, it was necessary to compare projects with all capital costs adjusted to a common reference year, 2009. Ideally all project costs would be re-estimated using standard criteria, however this was not practical because of the incomplete reference material, and because some 80 projects were in the initial list of new hydro options. Consequently costs were adjusted using the escalation indices provided in Section 3.2.4.
  • 115. Final Master Plan Report 5-5 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Burundi Costs for all projects were obtained from the SSEA study, and were referenced to 2004 prices. These were generally reviewed for the SSEA study, and some were re-estimated as noted above. All costs were escalated from 2004 to 2009 Eastern DRC Projects The most important DRC new hydro options are the proposed Ruzizi III and Ruzizi IV (Sisi 5) projects. Both of these have very current studies, and these cost estimates were used without modification. For the DRC projects, costs as of 1990 were provided for most of these sites in the Cifarha 1994 report [6]. The ONRD12 estimates include a 20% provision for contingencies, and 15% for owner’s costs. Estimates are provided for various transmission alternatives; however these are not directly included in the capital cost estimates. The Sicai- Tractionel study13 included 10% for contingencies, and a further 30% is added for “complementary” costs. No reference is given to transmission costs. The SEEE/Inter G14 estimates include transmission, but do not refer to overheads or contingencies. It was assumed that none of the DRC estimates included interest during construction, or an allowance for environmental or mitigation costs. With regard to mitigation costs, no specific major potential environmental risks were stated or indicated in the supporting reports. The capital costs shown in the original DRC source reports were escalated to 2004 for the SSEA study, and now have been further escalated to 2009. It should be noted that all the reference studies, except for Ruzizi III and Ruzizi IV are very preliminary and old. Additionally application of escalation to adjust costs for a long period can only give a general approximation of equivalent current costs. Egypt The only new hydro project scheduled for after 2013 in Egypt is the 40 MW Assiut barrage. No cost data was obtained for this project, so a proxy value of 3000 $/kW was assumed. It is noted that this project is primarily for level control on the Nile, and thus will not be part of a prioritized or optimized generation scheduling process. Ethiopia Almost all of the projects are listed in the 2006 master plan, and were then referred to in the EEPCo 2008 planning report [47]. Project costs provided in the 2008 report were taken to be at 2007 price levels and were escalated to 2009. In view of the number of potential hydro developments in Ethiopia, their importance in any future regional power market, and the number of available reports, a comparison was made of the alternative estimates shown in Table 5-3 below. These costs exclude interest during construction. It should be noted that the 2008 report showed generation and transmission costs separately. It is therefore assumed that with the exception of plant connections to the grid, transmission costs are not included in these costs. 12 Étude du système électroénergétique de la Province du Kivu, Energoprojekt y ONRD, 1972 13 Reconnaissance des ressources hydro-électriques dans le nord-est, Vol. 2 – esquisses d’aménagements, SICAI- Tractionel, Juin 1972 14 Études inventaires des sites hydrauliques en vue de leur équipement avec des mini ou microcentrales hydro-électriques au Zaïre, S.E.E.E – O.C.C.R.-INTER G
  • 116. Final Master Plan Report 5-6 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-3 Ethiopia previous estimated costs for hydro options (Costs in MUSD) Project  Installed  2008  ENTRO MoWR  MoWR Other Ref/year Report Capacity  Highlight  EDF Report Reference  (MW)  Report  2007 date costs Border  1200 1626  1481    Mandaya  2000 2640  2472    Beko Abo  2100    2838 2007    Karadobi  1600 2040  2232 2006    Gibe III  1870 1704  2205    Gibe IV  1468  2214  2100        2214  EEPCo Gibe IV  project profile ‐  2009  Gibe V  662 879     Halele  Worabesa  422  507           217 stage  1  Feasibility study  Halele Worabesa   Stage 1‐ Lahmeyer  2000  Chemoga‐Yeda  280  403  465        391  Feasibiility study  Chemoga Yeda ‐  Lahmeyer 2006  Aleltu East  186  438  438        379  Aleltu basin study ‐   Acres 1994  Aleltu West  265 561  561    Baro 1 and 2 +  Genji  900     976  976  2006        Gojeb  153 288  268    Geba I & II  372  535  379  excl TL  286  2005        Genale 3D  258  304  272  excl TL  308 excl TL  2007        Genale 6D  246  383  363  exc TL  470  2009        Tekeze II  450 435     Awash 4  38 49  49    Capital costs in the current study are shown in bold
  • 117. Final Master Plan Report 5-7 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Kenya The Low Grand Falls and Mutonga projects were included in the latest Kenya master plan of 200815 . Costs are assumed at 2008 price levels which are the same as 2009 prices, so no adjustment was made. The Magwagwa and Ewaso Ngiro projects were included in the EAPMP, and so were escalated from 2004 to 2009. Rwanda The Nyabarongo site was originally studied in 1999 by Sogreah. For the SSEA study costs were escalated to 2004. For the current study theses costs were further escalated to 2009. Sudan The cost data for the Sudan projects was available from the following sources: • Costs for the Sabaloka, Fula 1, Shukoli, Lakki, Bedden and Rumela were updated to 2006 prices from the NEC LTPPS 2003 data book by the ENPTPS. These costs were then further escalated to 2009 for this study. • Costs for the Shereiq, Dagash and Kagbar projects were taken from the NEC Generation Plan of 2006 were used for the ENPTPS, with some adjustments. These have been escalated from 2006 to 2009 for this study. • The cost for the low Dal scheme was taken from the prefeasibility study of the Dal project undertaken as part of the ENPTPS. That cost has been updated to 2009 for this study. These costs are compared below, and exclude interest during construction and allowances for mitigation costs. Table 5-4 Sudan previous estimated costs for hydro projects (Costs in MUSD) Project  MW  ENTRO EdF 2007  NEC Hydrology data book 2007  NEC Generation plan report 2007 Sabaloka  90  596  523   Shereiq  315  1190  826 876  Dagash  285  1048  719 800  Kagbar  300  1125  379 Stage 1 861  Dal 1 (low)  340  1113  846 955  Fula 1  720  1319  1157   Shukoli  210  420  368   Lakki  210  429  376   Bedden  400  880  772   Rumela  30  193  169   15 Kenya least cost power development plan, 2009-2030, December 2008
  • 118. Final Master Plan Report 5-8 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Tanzania All the hydroelectric options presented in this study were taken from the 2009 Tanzania PSMP [3]. As these costs are at 2008/9 price levels no further adjustment was made. Uganda The cost estimates for the candidate Uganda projects were originally developed in the 1997 Uganda hydro study16 . The project costs were re-estimated as part of the EAPMP [7]. At that time a number of sites were being considered, some of which were mutually exclusive (i.e., Masindi and the main stream Nile projects – Karuma, Ayago and Murchison Falls). Also since then, studies have now considered larger projects for Karuma, Ayago and Murchison Falls. The Isimba site has been considered for development as well. The Uganda 2009 master plan [37] includes a number of small hydro projects, however only four larger projects are considered, (e.g., more than 30 MW), i.e. • Murchison Falls 750 MW • Ayago 550 MW • Karuma 700 MW • Isimba 100 MW The plan refers to the Bugumira 110 MW project however notes that it would not be built if Isimba goes ahead, so it is not considered in this study. The total project costs given in the generation plan are at 2008/9 price levels so have not been adjusted further. 5.2.2 Mitigation costs Mitigation or environmental costs will typically cover land purchase, resettlement costs, relocation/replacement of roads, bridges and buildings in the reservoir area and in the immediate project area. The extent of the mitigation requirements will vary with the type and size of hydro project as well as local land use and population concentrations. Where project cost estimates were available, these were reviewed to determine if mitigation costs had been included, as a specific cost element. The approach to correcting for mitigation costs was to either include the mitigation cost amount from the previous estimate, or where no such allowance was made, to add a contingency amount. The 2004 EAPMP study that covered Tanzania, Uganda and Kenya included an allowance for mitigation costs for all projects, based on the estimates and scope provided in the original reference reports. These costs were then escalated to 2004 for the EAPMP analyses. These escalated 2004 costs have been retained, when not superseded by more recent studies. For Uganda some costs have been updated for the 2009 Master Plan, and these costs are understood to exclude mitigation costs. An adjustment has been applied accordingly. For those Uganda projects not included in the master Plan, the EAPMP costs which included a mitigation allowance were used. For Tanzania the recent new master plan was based on costs escalated from the EAPMP, and thus included allowances for mitigation costs. For Kenya project costs both from the EAPMP or the 2008 Master Plan included mitigation costs. For Ethiopia, it is understood that all project costs include mitigation costs the project cost estimates used in the Sudan 2008 Master Plan are understood to exclude mitigation costs, so an allowance was added. For the projects in Burundi, East DRC and Rwanda, project costs were escalated from those shown in the 2006 SSEA study. Some of the original reference project reports showed some 16 Kennedy and Donkin – Uganda Electricity Board Hydropower Development Master Plan .- 1997
  • 119. Final Master Plan Report 5-9 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study allowance for mitigation measures, while others have stated that any such costs would be covered by the civil works contingency amount. In the latter cases the civil works contingency amount was usually about 25%, which is relatively high. Normally civil works contingencies will be in the order of 15%, although higher amounts would be included if there are major underground works. A contingency of 25% on civil works typically would correspond to about 15-18% of the overall project cost. By comparison, aside from special situations, mitigation costs could range from 1- 2% for a run of the river project to 5-8% of total project cost for a project with a significant upstream reservoir area. For the purpose of the earlier SSEA study and this EAPP study it was assumed that the civil works contingency will cover routine mitigation costs for run of the river and projects with pondage. For reservoir projects a further 5% has been added. This applies to the following SSEA sites: • Burundi: Mpanda, Kaganuzi, Kakono, Mule, Siguvyaye. • All DRC projects. • Rwanda: Nyabarongo. The 5% amount was calculated on the total project cost, exclusive of IDC, and has been added to the total cost with IDC for the calculation of unit generation costs. The mitigation amounts, where added to the project cost, as shown later in Table 5-12. 5.2.3 Interest during construction For the preliminary ranking of new power options, capitalized costs (i.e., including interest during construction assuming a 10 % interest rate) were used. In many case the previous project estimates are presented as project costs without financing costs during construction. For these projects, and to provide a measure of standardization, standard IDC factors were used. These were a function of project size and thus construction period, and assumed the disbursement schedules shown in Table 5-6 below. The corresponding IDC factors are as follows: Table 5-5 IDC - typical increments for hydro projects Years of construction % of total cost 2 10.65 3 15.68 4 18.05 5 24.24 In the case of Uganda, the project costs already included IDC, however only the total cost was available, so that corresponding total cost was retained.
  • 120. Final Master Plan Report 5-10 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-6 IDC for hydroelectric projects (Interest rate = 10%)    2 YEAR PROGRAM 3 YEAR PROGRAM Time  Factor  % Cost With Time Factor  % Cost With  Years  per year Interest Years per year Interest  Year 1  3.5 1.395965  0 0 3.5 1.395965 0 0  Year 2  2.5 1.269059  0 0 2.5 1.269059 30 38.07176  Year 3  1.5 1.15369  55 63.45294 1.5 1.15369 40 46.14759  Year 4  0.5 1.048809  45 47.1964 0.5 1.048809 30 31.46427  TOTAL    100 110.6493 100 115.6836  IDC    10.64933 15.68362    4 YEAR PROGRAM 5 YEAR PROGRAM Time  Factor  % Cost With Time Factor  % Cost With  Years  per year Interest Years per year Interest  Year 1  3.5 1.395965  10 13.95965 4.5 1.535561 10 15.35561  Year 2  2.5 1.269059  25 31.72647 3.5 1.395965 20 27.91929  Year 3  1.5 1.15369  40 46.14759 2.5 1.269059 20 25.38117  Year 4  0.5 1.048809  25 26.22022 1.5 1.15369 30 34.61069  Year 5    0.5 1.048809 20 20.97618  TOTAL    100 118.0539 100 124.2429  IDC    18.05392 24.24294  5.3 Minimum lead times to on-power Based on the review of the available study reports, approximate lead times for each new project have been estimated. These are based on the indicated level of preparedness of each project in the reference reports, and the following generic times for each of the individual activities leading up to implementation and on-power. Table 5-7 Generic times for project activities Activity  Time in months  Prefeasibility study, following a reconnaissance level project identification 6‐12  Feasibility study (including consultant selection) 12‐24  Feasibility study update (where required) 6‐12  Environmental study and approval  12  Preparation of IPP process and tendering (where applicable) 12  Project financing (IPP or public ownership) 12  Final design (including consultant selection) – depending on size/complexity 12‐18  Tendering  6‐12  Construction (depending on size/complexity) 36‐60 
  • 121. Final Master Plan Report 5-11 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Actual times will vary considerably, depending on environmental approval process, private or public ownership, commitment of the host government, feasibility of financing, size and complexity of the project, and the extent to which activities may be fast tracked (i.e., carried out in parallel, such as final design and preparation of the EIA). Corresponding total minimum lead times to on power, as a function of plant size and level of preparedness, corresponding to the above time allowances, and result in the following minimum time frames, expressed in years. Table 5-8 Minimum on-power lead times for hydroelectric plants (years) Present project status  Project preparation Tender/Construction  Total  Reconnaissance/Preliminary less than 100 MW  3 3 6  100 to 150 MW  4 4 8  more than 150 MW  4 5 9  Prefeasibility less than 100 MW  2 4 6  100 to 150 MW  3 5 8  more than 150 MW  3 6 9  Feasibility less than 100 MW  2 4 6  100 to 150 MW  2 5 7  more than 150 MW  2 6 8  Design/tender documents less than 100 MW  1 3 4  100 to 150 MW  1 4 5  more than 150 MW  1 5 6  These values allow no margin for delays between successive development stages. They also do not provide for additional delays for approval and financing activities. At least one year should be added to the above values for any project that is not being fast tracked. 5.4 Primary screening of future hydro options In Sections 4.2 and 4.3 the full range of previously identified regional resources that might be available to meet the needs of the region have been identified. In this section this list of options is screened to ensure that: • any long lead times are identified • projects with a need for further assessment are identified • projects with insufficient information, or at a minimal level of preparation are screened out. • conclusions of previous studies such as the SSEA for East Africa countries are taken into account.
  • 122. Final Master Plan Report 5-12 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study The objective is to ensure that project scheduling (current candidate for 2013 to 2017 or long term) is respected and that non qualifying projects are not included. This screening has noted previously identified environmental and social issues, however has provided no independent assessment. This is therefore a primary screening. Approach The initial step was to compile a long list of all identified specific power development options and, in the case of thermal options, potentially appropriate generic options, as is shown above. The assessment has been limited to projects that are not yet fully committed. Projects such as Bujagali that are under construction are not assessed. The resulting long list of new power options is shown in Table 5-2. This table includes alternatives for some hydroelectric sites (that are mutually exclusive, such as Masindi and Ayago in Uganda, and the Kabu / Kaganuzi alternatives in Burundi). Screening Criteria Four basic screening criteria have been adopted, as follows: • Availability of data (prefeasibility level or better), to provide an adequate basis for evaluation. In applying this criterion it is important to remember that a site discarded due to lack of sufficient information may still provide potential for development and, depending on other factors, should be investigated further. • Options would be retained, for which residual environmental or socio-economic impacts are considered tolerable and in compliance with national laws and international conventions. One sensitive aspect to this qualification is the question of sites located in national parks or game reserves. The screening has included sites in the parks or reserves; as such development could be permissible under present national laws.17 However, development in National Parks or Game reserves would contravene the Algiers Convention, which is either signed by or in force in each of the countries of the region. • High unit costs: Where the unit cost of hydro generation has been determined as too high and thus definitively uneconomic. However recognizing that the criterion should be the cost of alternative diesel burning imported LFO, this upper limit would be in the order of 20 c/kWh, at least for smaller hydro projects in the Eastern DRC, Rwanda, Burundi region, and this value has been assumed. • Minimum size of project should be greater or equal to 10 MW for Rwanda, Burundi and Eastern DRC and greater or equal to 30 MW for the other countries. The 10 MW criterion refers to the minimum size that could have some impact on power supply for a neighbouring country and thus reflects regional nature of the study context. The 30 MW criterion is applied to the larger generating countries, and is the minimum value used in master plan studies in Kenya and Tanzania. These criteria were also used in the SSEA NELSAP study. Failure to meet any of these criteria would result in an identified project being eliminated from the overall project candidate list under this screening. The status of environmental and social impact assessments of power options has been done at scoping level. Details of the Environmental and Social Impact Assessment (ESIA) will need to be undertaken during the feasibility study. 17 There have been situations in the region where the designation of National Park has been downgraded to game preserve due to population pressures.
  • 123. Final Master Plan Report 5-13 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-10 shows projects assigned to the following groups: • In - i.e. available for scheduling at any time after the minimum on power date • After 2017 – a potential future candidate for which level of preparedness is insufficient at this time, or for which the reference source document / master plan has indicated the project to be a long term option • After 2020 – a special case that refers to expected interconnection of South Sudan areas into the system by about year 2020 • Out – for projects that have been clearly assessed as uneconomic, or which would be in conflict with other projects, or which are deemed to need further assessment. This primary screening process has therefore classed potential future hydro resources as follows: Table 5-9 Classification of hydro resources Classification  MW Total hydro resource – excluding redundancies 26,778 Excluded  1,308 Net available  25,473 Available for 2013‐2017 9,918 Available after 2017 or 2020 15,554
  • 124. Final Master Plan Report 5-14 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-10 Primary screening of future hydro options Name  NOM.  CAP  (MW)  PREVIOUS STUDY Excludes  planning/basin studies  IN A  MP?  SCREEN  RESULT  Comment / previous assessment  LVL  YEAR  SOURCE  BURUNDI           Kabu 16  20  F  1995  SOGREAH N/A IN Being prepared for financing Kagunuzi A  34  REC  1987  NORCONSULT N/A OUT environment   Mule 34  17  PF  2000  SOGREAH N/A OUT high cost  Siguvyaye  90  F  1980  ITS N/A > 2017 considered for IPP  Kaganuzi Complex  39  F  1987  NORCONSULT N/A OUT conflicts with Kabu 16,  and impacts Jiji 03  16  PF  2000  SOGREAH N/A OUT high cost   Mpanda  10  PF  1997  HYDROPLAN N/A IN considered for IPP   EAST DRC           Wannie Rukula  688  REC  1972  SICAI TRACTIONEL  N/A  > 2017  insufficient data available and long  lead time   Piana Mwanga  38  REC  2004     N/A  > 2017  insufficient data available and long  lead time REHAB   Kyimbi Bender II  43  REC  2004  RSW  N/A  > 2017  insufficient data available and long  lead time REHAB   Bangamisa  48  REC  1982  OCCR SEEE  N/A  > 2017  insufficient data available and long  lead time   Babeda 1  50  REC  1972  SICAI TRACTIONEL  N/A  > 2017  insufficient data available and long  lead time   Semliki  28  REC  1972  ONRD  N/A  > 2017  insufficient data available and long  lead time   Sisi 5C  287  PF  2009  FICHTNER N/A IN for regional supply   Mugomba  40  REC  1972  ONRD  N/A  > 2017  insufficient data available and long  lead time   Ruzizi III  145  F  2009  FICHTNER N/A IN for regional supply   EGYPT           ETHIOPIA          Mabil  1200  REC  1984  USBR    > 2017  optimum Abbay cascade  being  studied JMP 1   Mandaya  2000  PF  2007  EDF/SCOTT WILSON  MP  IN  midterm plan + Optimum being  studied JMP   Halele Worabesa  422  F  2005  LAHMEYER MP IN midterm plan   Genale 6D  246  F  2009  LAHMEYER MP IN long term indicative plan Karadobi  1600  PF  2006  NORPLAN  MP  > 2017  long term indicative plan + JMP 1  study  Tekaze II  450       MP > 2017 long term indicative plan Genale 3D  258  F  2007  LAHMEYER MP IN midterm plan   Beko Abo  2100  REC  2007  NORPLAN     > 2017  preliminary study and subject to  JMP 1   Gibe III  1870  C     EEPCo MP IN midterm plan   Border  1200  PF  2007  EDF/SCOTT WILSON  MP  > 2017  long term indicative plan + JMP  study   Chemoga‐Yeda  280  F  2006  LAHMEYER MP IN midterm plan   Geba I & II  372  F  2005  NORCONSULT MP IN midterm plan   Awash 4  38  F  2006  ELECTROCONSULT     IN  planned for local supply so not in  power trade program   Gibe IV  1468     2009  EEPCO MP IN midterm plan   Baro 1 and 2 + Genji  900  F  2006  NORPLAN MP > 2017 long term indicative plan Gibe V  662        EEPCo MP > 2017 long term indicative plan Aleltu West  265        ACRES MP > 2017 long term indicative plan
  • 125. Final Master Plan Report 5-15 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  NOM.  CAP  (MW)  PREVIOUS STUDY Excludes  planning/basin studies  IN A  MP?  SCREEN  RESULT  Comment / previous assessment  LVL  YEAR  SOURCE  Gojeb  153  F  1997  HUMPHREYS MP IN was to be IPP   Aleltu East  186  F  1995  ACRES MP > 2017 long term indicative plan KENYA           Magwagwa  120  F  1991  NIPPON KOIE    > 2017  Information has to be updated  before in plan  Low Grand Falls  140  F  1998  NIPPON KOIE MP IN in current master plan   Mutonga  60  F  1998  NIPPON KOIE MP IN in current master plan   Ewaso Ngiro  180  F/D  2000  KNIGHT PIESOLD > 2017 environmental issues to be clarified RWANDA           Nyabarongo  28  F  1999  SOGREAH N/A SUDAN           Shukoli  210     1993  ACRES  MP  > 2017  Southern region ‐ wait for  interconnection  Lakki  210     1993  ACRES  MP  > 2017  Southern region ‐ wait for  interconnection  Bedden  400     1993  ACRES  MP  > 2017  Southern region ‐ wait for  interconnection  Fula 1  720     1993  ACRES  MP  > 2017  Southern region ‐ wait for  interconnection  Shereiq  315  F  1999  HYDROPROJECT  MP  IN  in NEC 2008 annual report for before  2030  Dal 1 (low)  340     1993  ACRES  MP  > 2017  in NEC 2008 annual report for before  2030  Dagash  285     1993  ACRES  MP  > 2017  in NEC 2008 annual report for before  2030  Kagbar  300  F  1997  HYDROPROJECT  MP  IN  in NEC 2008 annual report for before  2030  Sabaloka  90     1993  ACRES > 2017 study by GIBB in 1977   Rumela  30  F  1982  SOGREAH MP IN priority project  TANZANIA           Stieglers Gorge 3  300  PF  1984  NORPLAN  MP  AFTER  2017  Major project, environmental issues,  PF only  Igamba Falls (Stage 2)*  8  D  CURR ENT  MCC  MP  IN     Kakono (High)  53  PF  1976  NORCONSULT MP > 2017 Old study, PF only, long lead time Stieglers Gorge 2  600  PF  1984  NORPLAN  MP  > 2017  Major project, environmental issues,  PF only  Mpanga  144  PF  1997  SWEDPOWER/NORCO NULT  MP  > 2017  Old study, PF only, long lead time   Ruhudji  358  F  CURR ENT  IPP  MP  IN     Masigira  118  PF  1997  SWEDPOWER/NORCO NULT  MP  > 2017  PF only, long lead time   Rumakali  222  F  1997  SWEDPOWER/NORCO NULT  MP  > 2017  PF only, long lead time   Stieglers Gorge 1  300  PF  1984  NORPLAN  MP  > 2017  major project, environmental issues,  PF only  Songwe Manolo  149  PF  2003  NORPLAN MP > 2017 International ‐ no sponsor Songwe Sofre  157  PF  2003  NORPLAN MP > 2017 International ‐ no sponsor Ikondo  340  PF  1984  NORCONSULT MP > 2017 old preliminary study   Taveta  145  PF  1984  NORCONSULT MP > 2017 old preliminary study   Rusumo Falls (Full)  63  F  2010  SNC MP IN committed  
  • 126. Final Master Plan Report 5-16 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  NOM.  CAP  (MW)  PREVIOUS STUDY Excludes  planning/basin studies  IN A  MP?  SCREEN  RESULT  Comment / previous assessment  LVL  YEAR  SOURCE  Songwe Bipugu  34  PF  2003  NORPLAN MP > 2017 International ‐ no sponsor Luiche  15  REC  1983  NORCONSULT OUT lack of info  Kinansi II  120  PF  1997  SWEDPOWER/NORCO NULT     OUT  high cost    UGANDA           Murchison base  222  PF  1997  KENNEDY AND  DONKIN     > 2017  PF only, long lead time, env issues   Kalagala 1‐7  315  PF  1998  LAHMEYER OUT not acceptable if Karuma built Murchison  High  750        MP > 2017 alternative to Murchison base Ayago South  234  PF  1997  KENNEDY AND  DONKIN     > 2017  PF only, long lead time, env issues   Karuma low  200  F  1997  KENNEDY AND  DONKIN  MP  IN     Masindi ‐1  360  PF  1997  KENNEDY AND  DONKIN     OUT  Environmental impacts   Isimba  100  F     MP IN Masindi ‐ 2   360  PF  1997  KENNEDY AND  DONKIN     OUT  Environmental impacts  Ayago North+South   550     1997  KENNEDY AND  DONKIN  MP  > 2017  PF only, long lead time, env issues   kalagala 8‐10  135  PF     MP OUT not acceptable if Karuma built Karuma ( high  alternative)  700      Under study  MP  IN  alternative to Karuma low  Small hydro   60        MP IN Com mitted  MP: Master Plan; LVL: Level Level of Preparedness - C: Construction; F: Feasibility; PF: Prefeasibility; REC: Reconnaissance; D: Design IPP: Independent Power Producer; JMP: Joint Multipurpose project 5.4.1 Rejected options Further information on the rejected or excluded options is provided as follows: Burundi Kaganuzi A and Kaganuzi Complex: The project (both options would involve a diversion on the Kaburantwa river and power facilities on the Kaganuzi river. The Kaburantwa project would divert a maximum of 8m3 /s from the Kaburantwa River. This compares with the 10.6 m3 /s average flow at the downstream Kabu 16 site on this river. Consequently this diversion for either of the Kaganuzi options would both eliminate the Kabu 16 site, and would reduce the Kaburantwa river average flow to 20% of its present average. The Kaganuzi A project would develop the most head, and therefore would provide the maximum use of the hydroelectric resource. However the Kaganuzi C scheme would supply irrigation water to the Imbo plain. The Kaganuzi C project was considered ready for final design and the Kaburantwa project had been studied in detail. Little information is available on Kaganuzi A. Both Kaganuzi options would require the Kaburantwa diversion to be viable. The Kaganuzi complex (i.e., Kaganuzi C and Kaburantwa) has been rejected because of the major environmental and social risk from the required diversion of the Kaburantwa River. However with an indicated firm energy cost of over 10 cents/kWh, after allowing a credit for its multipurpose function, it is unlikely that the project would be economic, at least in a regional context.
  • 127. Final Master Plan Report 5-17 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study This option was studied originally by Lahmeyer in 1983 and then by Norconsult, as described in their report of 198718 . Hydroplan also studied it in an undated report.19 Tanzania Kihansi II: This project would be a 2 x 60 MW addition to the existing project lower Kihansi project, together with the construction of an upstream storage dam. The combined powerhouse addition and upstream storage project was not listed as a candidate in the EAPMP. However the Upper Kihansi storage project, was assessed. This project was reassessed in the 2009 Tanzania power system master plan, and both energy benefits and capital costs were re-estimated. The project was found to be very costly as there was insufficient water to take full benefit from the improved flow regulation and increased turbine capacity. Uganda Kalagala: The project would be located on the Victoria Nile 25 km downstream of Owen Falls and also downstream of the proposed Bujagali project. The project would be a conventional run of river development comprising 7 45 MW units (315 MW) in a first phase, and a further 3 units (135 MW) in the second stage for a total capacity of 450 MW. The project could provide low cost energy, at an average cost in the order of 4 cents/kWh, and firm energy would be relatively high, due to the regulating effect of Lake Victoria. The project has been studied to the prefeasibility level20 , and a preliminary assessment of environmental potential impacts has been prepared21 . It has long been recognized that development of the three projects of Bujagali, Kalagala and Karuma would result in a major risk to tourism, as well as resulting in other significant social and environmental impacts. Consequently recent planning has assumed that either, but not both, Kalagala and Karuma could be constructed. In line with this concept, in 2002 the Uganda Government signed an offset agreement with the World Bank, as part of the agreements related to the Bujagali project, which set aside the Kalagala project to protect its natural habitat, environmental and spiritual values and for tourism development22 . Consequently the Kalagala project has not been considered as a candidate for inclusion in any portfolios to meet future loads. Masindi 1-2: The Masindi scheme consists of two 360 MW stages, to divert flow from the Nile downstream of Lake Kyoga to Lake Albert, some 200 km downstream. This project would therefore provide a major reduction in flows of the Nile between these two points, and has therefore been rejected because of major environmental / social risk. This project would also displace the Ayago and Murchison Falls hydro options. It would therefore be a trade-off between reduced Nile flows through the park, and possible new infrastructure construction in the park. 18 Norconsult, Kagunuzi Multipurpose Project, Feasibility Study, Volume III, Hydropower Scheme, Draft Report, African Development Bank, February 1987 19 Hydroplan Ingenieur-Gesellschaft mbh/Fichtner Beratende Ingenieure, Étude finale de faisabilité du projet hydroagricole et hydroélectrique de Kaganuzi C, Rapport préliminaire de Seconde Phase, Tome I, Rapport de synthèse et volets hydro- agricole, organisationnel, électrique et économique, République du Burundi, Ministère de l’Énergie et des Mines, Ministère de l’Agriculture et de l’Élevage 20 Kennedy and Donkin, (Uganda) Hydropower development master plan, 1997 21 ESG International Inc., WS Atkins (Epsom UK), Bujagali Hydropower Project - Environmental Impact, prepared for AES Nile Power, March 2001 22 IBRD/IDA Management report and recommendation in response to the inspection panel investigation report, Uganda, Third Power Project, fourth Power Project and Bujagali Hydropower project, June 2002, and Annex 2 letter from the Minister of Finance, Planning and Economic Development to the World Bank, June 4, 2002
  • 128. Final Master Plan Report 5-18 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study The indicated cost of firm energy is 6 cents/kWh or more, and may be significantly higher depending on the construction time, primarily to complete the 70 km power tunnels. Information on the project is limited, and for this reason it was not considered in the EAPMP. Options delayed due to insufficient data This situation primarily relates to identified sites in the Eastern DRC. With the exception of Ruzizi IV (Sisi 5C) and two rehabilitation projects, these sites have only been evaluated at a reconnaissance level, and these studies were prior to 1980 [6]. Based on the very preliminary data available, eight sites were recommended for further study in the 2006 SSEA study, of which the Ruzizi IV (Sisi 5C) site has been subject to more detailed studies. For the current study the remaining seven projects are classified as potential sites for after 2017. In any case the minimum lead times to on power would achieve the same result. The total installed capacity of these sites would be 935 MW. These sites include: Table 5-11 Potential DRC sites for after 2017 DRC Projects  MW Wannie Rukula  688  Piana mwanga  38  Kyimbi Benera II 43  Bengamisa  48  Babeda  50  Semliki  28  Mugomba  40  5.5 Future hydro generation costs For the purpose of comparing alternative new generation options, unit capacity ($/KW) and energy (US$/MWh) costs have been estimated using a simplified economic analysis. The capital cost includes interest during construction, which is a function of the scheduling of capital expenditures during construction, the length of the construction period, and the discount rate (Planning criteria in Section 3). The unit cost of capacity is estimated from the capital cost, including interest during construction, and the nominal plant installed capacity. (Note that the firm capacity of the plant, especially for run of the river hydroelectric projects may be significantly lower). Average annual costs over the life of the project are calculated for the capacity component, using the parameters outlined in the planning criteria and assuming uniform annual payment of capital and interest. Unit energy costs ($/MWh) are calculated from capital charges and variable operation and maintenance costs. The total cost of energy generation is a function of plant capacity factor and combines the fixed annual capacity component ($/kW-year/hours of operation) with the variable energy component (cents/kWh). In the case of the hydroelectric option the plant capacity factor, and thus average hours of operation, is defined. This procedure does not take into account any future escalation operating costs. The calculation of unit generation costs for hydroelectric projects is shown in Table 5-12 that follows23 24 . The above procedure is useful in comparing relative plant costs, however for 23 Table 5.12 shows relatively high unit costs for the Mpanda 10 MW project in Burundi and the Nyabarongo 27.8 MW project in Rwanda. The source references for these costs are given in Tables 4.2 and 4.8 respectively. For both these projects the
  • 129. Final Master Plan Report 5-19 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study hydroelectric projects this does not take into account different plant capacity factors (CF) - derived as: CF (%) = 100 Table 5-12 provides a listing of all identified hydro projects, including some of those shown as excluded in Table 5-10. This is to provide a complete listing of comparative costs. However in the ranking of projects by costs and on power date shown in Table 5-13 these excluded projects are not shown. The parameters used to calculate hydro generation costs are provided in the planning criteria given in Section 3. These parameters, as related to this study to establish overall new generation resources, include: • Adjustment of capital cost to a common reference year (2009) • Allocation of costs for multipurpose projects (no adjustment used for this study) • Service lives • Operation, maintenance and other costs • Construction period and interest during construction project costs were re-estimated in 2004 as part of the SSEA 1 study using quantities from the original reports. Also in both cases the costs included transmission to the grid, which is the conventional procedure for hydro. In the case of Mpanda the transmission cost was 5% of the total, while for Nyabarongo the transmission cost was 10 % of the total. 24 The unit cost shown in Table 5.12 for the Sabaloka 90 MW project in Sudan is also relatively high. Capital cost was taken from the 2008 NBI Preliminary Basin-wide Study, however is essentially the same as that shown in the EDF Power Trade Study (see Module 3, Volume 4,, which were escalated to 596 MUSD in 2006 prices, based on the 2003 NEC LTPPS. Costs include transmission, however while no cost breakdown was identified, the EDF report states that transmission costs to connect to the grid were included however for all projects this cost was less than 4 % of the total project cost.
  • 130. Final Master Plan Report 5-20 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-12 EAPP Region Future Hydroelectric projects – Unit Generation costs Name  Generation  Investment Costs Annual Costs (MUSD) Unit Prices  Inst  Cap.  MW  Avrg  Energy  GWh  Orig cost  MUSD  Price  Year  Esc.  Index  2009  Esc to Dec.  09 MUSD  Const  Years  IDC  %  Cost w/  IDC  MUSD  Env.  Mitigation  MUSD  Total  Cost  MUSD  Amort  O & M  Insurance  +Interim  Repl.  Total  Energy  cost  c/kWh  Invest  Cost  $/kW  BURUNDI Jiji 03  16 40  42.20 2004 127.2 53.67 3 15.68 62.09  2.68 64.78 6.53 0.08 0.23 6.84 17.09  4179  Kabu 16  20 113  38.34 2004 127.2 48.76 3 15.68 56.41  2.44 58.85 5.94 0.10 0.21 6.24 5.52  2943  Kaganuzi A  34 98  50.85 2004 127.2 64.68 3 15.68 74.82  3.23 78.05 7.87 0.17 0.27 8.32 8.49  2296  Kaganuzi Complex 39 187  136.12 2004 127.2 173.13 3 15.68 200.28  8.66 208.94 21.07 0.20 0.73 22.00 11.76  5357  Mpanda  10 40  42.66 2004 127.2 54.26 3 15.68 62.77  2.71 65.48 6.60 0.05 0.23 6.88 17.21  6548  Mule 34  17 54  33.00 2004 127.2 41.97 3 15.68 48.56  2.10 50.65 5.11 0.08 0.18 5.37 9.94  3070  Siguvyaye  90 510  280.00 2004 127.2 356.13 4 18.05 420.43  17.81 438.23 44.20 0.45 1.53 46.18 9.06  4869  EAST DRC Piana Mwanga  29 182  35.00 2004 127.2 44.52 3 15.68 51.50  2.23 53.72 5.42 0.15 0.19 5.75 3.16  1853  Bendera  43 143  52.06 2004 127.2 66.22 3 15.68 76.60  3.31 79.91 8.06 0.22 0.28 8.55 5.98  1858  Babeda I  50 341  101.42 2004 127.2 129.00 3 15.68 149.23  6.45 155.68 15.70 0.25 0.54 16.50 4.84  3114  Bengamisa  48 363  100.34 2004 127.2 127.62 4 18.05 150.66  6.38 157.04 15.84 0.24 0.55 16.63 4.58  3272  Mugomba  40 163  71.20 2004 127.2 90.56 4 18.05 106.91  4.53 111.44 11.24 0.20 0.39 11.83 7.26  2786  Semliki  28 118  34.50 2004 127.2 43.88 4 18.05 51.80  2.19 54.00 5.45 0.14 0.19 5.78 4.89  1928  Ruzizi III  145 664  394.47 2009 100.0 394.47 4 18.05 465.69  19.72 485.41 48.96 0.73 1.70 51.38 7.74  3348  Ruzizi IV (Sisi 5C) 287 1249  482.85 2009 100.0 482.85 4 18.05 570.02  24.14 594.17 59.93 1.44 2.08 63.44 5.08  2070  Wannie Rukula  688 6000  1184.69 2004 127.2 1506.81 4 18.05 1778.84  75.34 1854.19 187.01 3.44 6.49 196.94 3.28  2695  EGYPT Assiut  40 175  120.00 2004 127.2 152.63 4 18.05 180.18  7.63 187.81 18.94 0.20 0.66 19.80 11.31  4695  ETHIOPIA Gibe III  1870 6087  1704.00 2007 101.4 1727.17 5 24.24 2145.89  0.00 2145.89 216.43 9.35 7.51 233.29 3.83  1148  Gibe IV  1468 5644  2214.00 2007 101.4 2244.11 5 24.24 2788.15  0.00 2788.15 281.21 7.34 9.76 298.31 5.29  1899  Halele Worabesa 422 2215  507.00 2007 101.4 513.90 4 18.05 606.67  0.00 606.67 61.19 2.11 2.12 65.42 2.95  1438 
  • 131. Final Master Plan Report 5-21 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  Generation  Investment Costs Annual Costs (MUSD) Unit Prices  Inst  Cap.  MW  Avrg  Energy  GWh  Orig cost  MUSD  Price  Year  Esc.  Index  2009  Esc to Dec.  09 MUSD  Const  Years  IDC  %  Cost w/  IDC  MUSD  Env.  Mitigation  MUSD  Total  Cost  MUSD  Amort  O & M  Insurance  +Interim  Repl.  Total  Energy  cost  c/kWh  Invest  Cost  $/kW  Chemoga‐Yeda  280 1384  403.00 2007 101.4 408.48 4 18.05 482.23  0.00 482.23 48.64 1.40 1.69 51.72 3.74  1722  Geba I & II  372 1802  535.00 2007 101.4 542.28 4 18.05 640.18  0.00 640.18 64.57 1.86 2.24 68.67 3.81  1721  Genale 3D  258 1228  304.00 2007 101.4 308.13 4 18.05 363.76  0.00 363.76 36.69 1.29 1.27 39.25 3.20  1410  Baro 1 and 2 + Genji 900 4522  976.00 2006 104.5 1020.21 4 18.05 1204.40  0.00 1204.40 121.47 4.50 4.22 130.19 2.88  1338  Mandaya  2000 11950  2640.00 2007 101.4 2675.90 5 24.24 3324.62  0.00 3324.62 335.32 10.00 11.64 356.95 2.99  1662  Border  1200 6331  1626.00 2007 101.4 1648.11 5 24.24 2047.66  0.00 2047.66 206.53 6.00 7.17 219.69 3.47  1706  Gibe V  662 1882  879.00 2007 101.4 890.95 5 24.24 1106.95  0.00 1106.95 111.65 3.31 3.87 118.83 6.31  1672  Beko Abo  2100 10825  2838.40 2006 104.6 2968.97 5 24.24 3688.73  0.00 3688.73 372.04 10.50 12.91 395.45 3.65  1757  Karadobi  1600 8784  2040.00 2007 101.4 2067.74 5 24.24 2569.03  0.00 2569.03 259.11 8.00 8.99 276.10 3.14  1606  Genale 6D  246 1609  383.00 2007 101.4 388.21 4 18.05 458.30  0.00 458.30 46.22 1.23 1.60 49.06 3.05  1863  Gojeb  150 526  288.00 2007 101.4 291.92 3 15.68 337.70  0.00 337.70 34.06 0.75 1.18 35.99 6.84  2251  Tekaze II  450 1758  435.00 2007 101.4 440.92 4 18.05 520.52  0.00 520.52 52.50 2.25 1.82 56.57 3.22  1157  Aleltu East  186 885  438.00 2006 104.5 457.84 4 18.05 540.50  0.00 540.50 54.51 0.93 1.89 57.34 6.48  2906  Aleltu West  265 1028  561.00 2006 104.5 586.41 4 18.05 692.28  0.00 692.28 69.82 1.33 2.42 73.57 7.16  2612  Awash 4  38 166  49.00 2006 104.5 51.22 3 15.68 59.25  0.00 59.25 5.98 0.19 0.21 6.37 3.84  1559  KENYA Mutonga  60 336  235.30 2008 100.0 235.30 3 15.68 272.20  0.00 272.20 27.45 0.30 0.95 28.71 8.54  4537  Low Grand Falls 140 707  460.90 2008 100.0 460.90 4 18.05 544.11  0.00 544.11 54.88 0.70 1.90 57.48 8.13  3887  Magwagwa  120 525  294.50 2004 127.2 374.57 4 18.05 442.20  0.00 442.20 44.60 0.60 1.55 46.75 8.90  3685  Karura  56 184  196.00 2009 100.0 196.00 3 15.68 226.74  0.00 226.74 22.87 0.28 0.79 23.94 13.01  4049  Ewaso Ngiro  180 568  312.00 2004 127.2 396.83 5 24.24 493.04  0.00 493.04 49.73 0.90 1.73 52.35 9.22  2739  RWANDA Nyabarongo  28 150  96.75 2004 127.2 123.06 3 15.68 142.35  6.15 148.50 14.98 0.14 0.52 15.64 10.42  5342  SUDAN Sabaloka  90 670  596  2006 104.5 623.00 4 18.05 735.47  31.15 766.62 77.32 0.45 2.68 80.45 12.01  8518  Shereiq  315 1962  876  2006 104.5 915.68 5 24.24 1137.67  0.00 1137.67 114.74 1.58 3.98 120.30 6.13  3612 
  • 132. Final Master Plan Report 5-22 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  Generation  Investment Costs Annual Costs (MUSD) Unit Prices  Inst  Cap.  MW  Avrg  Energy  GWh  Orig cost  MUSD  Price  Year  Esc.  Index  2009  Esc to Dec.  09 MUSD  Const  Years  IDC  %  Cost w/  IDC  MUSD  Env.  Mitigation  MUSD  Total  Cost  MUSD  Amort  O & M  Insurance  +Interim  Repl.  Total  Energy  cost  c/kWh  Invest  Cost  $/kW  Kagbar  300 1413  763  2006 104.5 797.56 5 24.24 990.92  39.88 1030.80 103.97 1.50 3.61 109.07 7.72  3436  Dal 1 (low)  340 1968  1113 2007 101.4 1128.58 5 24.24 1402.18  0.00 1402.18 141.42 1.70 4.91 148.03 7.52  4124  Dagash  285 1503  800  2006 104.5 836.24 5 24.24 1038.97  41.81 1080.78 109.01 1.43 3.78 114.21 7.60  3792  Fula 1  720 4134  1319 2006 104.5 1378.75 5 24.24 1713.00  68.94 1781.94 179.72 3.60 6.24 189.56 4.59  2475  Shukoli  210 1443  420  2006 104.5 439.03 4 18.05 518.29  21.95 540.24 54.49 1.05 1.89 57.43 3.98  2573  Lakki  210 1443  429  2006 104.5 448.43 4 18.05 529.39  22.42 551.82 55.66 1.05 1.93 58.64 4.06  2628  Bedden  400 2748  880  2006 104.5 919.86 5 24.24 1142.87  45.99 1188.86 119.91 2.00 4.16 126.07 4.59  2972  Rumela  30 83  193  2006 104.5 201.74 3 15.68 233.38  10.09 243.47 24.56 0.15 0.85 25.56 30.79  8116  TANZAN IA Ruhudji  358 1928  494.74 2008 100.0 494.74 5 24.24 614.68  0.00 614.68 62.00 1.79 2.15 65.94 3.42  1717  Kinansi II  120 69  191.91 2008 100.0 191.91 3 15.68 222.01  0.00 222.01 22.39 0.60 0.78 23.77 34.45  1850  Masigira  118 664  208.67 2008 100.0 208.67 4 18.05 246.34  0.00 246.34 24.85 0.59 0.86 26.30 3.96  2088  Rumakali  222 1475  458.90 2008 100.0 458.90 5 24.24 570.15  0.00 570.15 57.50 1.11 2.00 60.61 4.11  2568  Mpanga  144 955  248.96 2008 100.0 248.96 4 18.05 293.91  0.00 293.91 29.64 0.72 1.03 31.39 3.29  2041  Stiegler Gorge 1 300 2230  872.68 2008 100.0 872.68 5 24.24 1084.24  0.00 1084.24 109.36 1.50 3.79 114.65 5.14  3614  Stiegler Gorge 2 600 1506  310.91 2008 100.0 310.91 5 24.24 386.28  0.00 386.28 38.96 3.00 1.35 43.31 2.88  644  Stiegler Gorge 3 300 1523  254.87 2008 100.0 254.87 5 24.24 316.66  0.00 316.66 31.94 1.50 1.11 34.55 2.27  1056  Igamba Falls (Stage 2)* 8 65  11.30 2004 127.2 14.37 3 15.68 16.63  0.00 16.63 1.68 0.04 0.06 1.78 2.73  2078  Igamba Falls 980 m 80 494  404.00 2004 127.2 513.85 4 18.05 606.62  0.00 606.62 61.18 0.40 2.12 63.71 12.90  7583  Ikondo  340 1842  640.88 2009 100.0 640.88 3 15.68 741.39  0.00 741.39 74.78 1.70 2.59 79.07 4.29  2181  Taveta  145 850  379.88 2009 100.0 379.88 3 15.68 439.46  0.00 439.46 44.32 0.73 1.54 46.59 5.48  3031  Songwe Bipugu  34 153  84.07 2004 127.2 106.93 3 15.68 123.70  0.00 123.70 12.48 0.17 0.43 13.08 8.55  3638  Songwe Sofre  157 736  255.05 2004 127.2 324.40 3 15.68 375.28  0.00 375.28 37.85 0.79 1.31 39.95 5.43  2390  Songwe Manolo 149 780  259.32 2004 127.2 329.83 3 15.68 381.56  0.00 381.56 38.48 0.75 1.34 40.56 5.20  2561  Kakono (High)  53 404  90.07 2008 100.0 90.07 3 15.68 104.20  0.00 104.20 10.51 0.27 0.36 11.14 2.76  1966  Kishanda  207 1087  181.00 2004 127.2 230.21 4 18.05 271.78  0.00 271.78 27.41 1.04 0.95 29.40 2.70  1313 
  • 133. Final Master Plan Report 5-23 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  Generation  Investment Costs Annual Costs (MUSD) Unit Prices  Inst  Cap.  MW  Avrg  Energy  GWh  Orig cost  MUSD  Price  Year  Esc.  Index  2009  Esc to Dec.  09 MUSD  Const  Years  IDC  %  Cost w/  IDC  MUSD  Env.  Mitigation  MUSD  Total  Cost  MUSD  Amort  O & M  Insurance  +Interim  Repl.  Total  Energy  cost  c/kWh  Invest  Cost  $/kW  UGANDA Luiche  15 100  68.70 2004 127.2 87.38 3 15.68 101.08  0.00 101.08 10.20 0.08 0.35 10.63 10.63  6607  Rusumo Falls (Full) 63 444  227.44 2008 100.0 227.44 4 18.05 268.50  29.45 297.95 30.05 0.31 1.04 31.40 7.07  4845  Karuma High  700 5512  2660.00 2009 100.0 2660.00 5 2660.00  133.00 2793.00 281.70 3.50 9.78 294.98 5.35  3990  Ayago    550 4336  2048.20 2009 100.0 2048.20 4 2048.20  102.41 2150.61 216.91 2.75 7.53 227.19 5.24  3910  Murchison  high 750 5904  1579.50 2009 100.0 1579.50 5 1579.50  78.98 1658.48 167.27 3.75 5.80 176.83 3.00  2211  Isimba  100 788  345.80 2009 100.0 345.80 4 345.80  17.29 363.09 36.62 0.50 1.27 38.39 4.87  3631  Notes: The Capital Cost of large hydro plants includes the cost of transmission required to connect the HPP to the system. Environmental Mitigation Costs already include IDCs.
  • 134. Final Master Plan Report 5-24 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 5.6 Ranking by cost and earliest availability The project ordering shown in Table 5-13 takes projects that are ranked in terms of energy cost, by country, and assigns them into future periods based on earliest on-power dates, as follows: • Unit costs for hydro average energy were taken from Table 5-12. • Earliest on-power dates were based on the minimum lead time criteria provided in Section 5.3, and as shown in Table 4-2 to Table 4-11. Availability (earliest on-power) is based on present level of preparation. The objective of Table 5-13 is primarily to identify those projects that could start generating in the short term 2013 to 2017 planning period, and to provide ordering in terms of generation cost. It should be noted that some projects in cascade are ordered from upstream to downstream, not by cost, e.g. • Steigler´s Gorge - three stages to project • Songwe – 3 projects Also some projects are delayed beyond their nominal earliest on-power date due to lack of a recent study, as is noted in the screening shown in Table 5-10. Some other projects are delayed as their recent country master plan has designated them as long term options. In the table certain “shared” projects are attributed to one country, as follows: • Ruzizi hydro plants – Eastern DRC • Rusumo - Tanzania
  • 135. Final Master Plan Report 5-25 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 5-13 EAPP Hydro Options – Ranking by unit cost and earliest on-power Name  Generation and capital cost  Unit Costs  Earliest  on Power  Earliest available generation 2013‐2017 MW  Earliest available generation 2018‐2022  MW  Nom. Cap  MW  Avrg Energy  GWh  Total cost  2009 MUSD  Energy cost  c/kWh  Invest  Cost $/kW  2013  2014  2015  2016  2017  2018  2019  2020  2021  2022  BURUNDI Kabu 16  20  113  58.85 5.52 2943 2015    90    Siguvyaye  90  510  420.43 9.06 4869 2016    90    Mule 34  17  54  48.56 9.94 3070 2016    17    Jiji 03  16  40  64.78 17.09 4179 2016    16    Mpanda  10  40  62.77 17.21 6548 2016    10    EAST DRC Piana Mwanga 29  182  53.72 3.16 1853 2017    29    Wannie Rukula 688  6000  1854.19 3.28 2695 2019    688    Bengamisa  48  363  157.04 4.58 3272 2017    48    Babeda I  50  341  155.68 4.84 3114 2017    50    Semliki  28  118  54.00 4.89 1928 2017    28    Bendera  43  143  79.91 5.98 1858 2017    43    Ruzizi IV (Sisi 5C) 287  1249  594.17 5.08 2070 2019    287    Mugomba  40  163  111.44 7.26 2786 2017    40    Ruzizi III  145  664  485.41 7.74 3348 2016    145    EGYPT Assiut  40  175  187.81 11.31 4695 2015    40    ETHIOPIA Baro 1 and 2 + Genji  900  4522  1204.40  2.88  1338  2016,  2017              900                 Halele Worabesa 422  2215  606.67 2.95 1438 2014    422    Mandaya  2000  11950  3324.62 2.99 1662 2019    2000    Genale 6D  246  1609  458.30 3.05 1863 2016    246    Karadobi  1600  8784  2569.03 3.14 1606 2018    1600    Genale 3D  258  1228  363.76 3.20 1410 2015    258    Tekaze II  450  1758  520.52 3.22 1157 2019    450    Border  1200  6331  2047.66 3.47 1706 2019    1200    Beko Abo  2100  10825  3688.73 3.65 1757 2019    2100    Chemoga‐Yeda 280  1384  482.23 3.74 1722 2016    280   
  • 136. Final Master Plan Report 5-26 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  Generation and capital cost  Unit Costs  Earliest  on Power  Earliest available generation 2013‐2017 MW  Earliest available generation 2018‐2022  MW  Nom. Cap  MW  Avrg Energy  GWh  Total cost  2009 MUSD  Energy cost  c/kWh  Invest  Cost $/kW  2013  2014  2015  2016  2017  2018  2019  2020  2021  2022  Gibe III  1870  6087  2145.89 3.83 1148 2013 1870     Geba I & II  372  1802  640.18 3.81 1721 2018    372    Awash 4  38  166  59.25 3.84 1559 2016    38    Gibe IV  1468  5644  2788.15 5.29 1899 2015    1468    Gibe V  662  1882  1106.95 6.31 1672 2019    662    Aleltu East  186  885  540.50 6.48 2906 2018    186    Gojeb  150  526  337.70 6.84 2251 2016    150    Aleltu West  265  1028  692.28 7.16 2612 2019    265    KENYA Low Grand Falls 140  707  544.11 8.13 3887 2017    140    Mutonga  60  336  272.20 8.54 4537 2016    60    Magwagwa  120  525  442.20 8.90 3685 2017    120    Ewaso Ngiro  180  568  493.04 9.22 2739 2016    180    Karura  56  184  226.74 13.01 4049 2017    56    RWANDA Nyabarongo  28  150  148.5 10.42 5342 2014    28    SUDAN Shukoli  210  1443  540.24 3.98 2573 2020    210    Lakki  210  1443  551.82 4.06 2628 2020    210    Fula 1  720  4134  1781.94 4.59 2475 2020    720    Bedden  400  2748  1188.86 4.59 2972 2020    400    Shereiq  315  1962  1137.67 6.13 3612 2016    315    Dal 1 (low)  340  1968  1402.18 7.52 4124 2018    340    Dagash  285  1503  1080.78 7.60 3792 2019    285    Kagbar  300  1413  1030.80 7.72 3436 2018    300    Sabaloka  90  670  766.62 12.01 8518 2017    90    TANZAN IA Stiegler Gorge 3 300  1523  316.66 2.27 1056 2019 300  300    Kishanda  207  1087  271.78 2.70 1313 2016 207  207    Igamba Falls (Stage 2) 8 65  16.63 2.73 2078 2019 8  8    Kakono (High)  53  404  104.20 2.76 1966 2016 53  53    Stiegler Gorge 2 600  1506  386.28 2.88 644 2018 600  600    Mpanga  144  955  293.91 3.29 2041 2018 144  144    Ruhudji  358  1928  614.68 3.42 1717 2016 358  358   
  • 137. Final Master Plan Report 5-27 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  Generation and capital cost  Unit Costs  Earliest  on Power  Earliest available generation 2013‐2017 MW  Earliest available generation 2018‐2022  MW  Nom. Cap  MW  Avrg Energy  GWh  Total cost  2009 MUSD  Energy cost  c/kWh  Invest  Cost $/kW  2013  2014  2015  2016  2017  2018  2019  2020  2021  2022  Masigira  118  664  246.34 3.96 2088 2018 118  118    Rumakali  222  1475  570.15 4.11 2568 2018 222  222    Ikondo  340  1842  741.39 4.29 2181 2019 340  340    Stiegler Gorge 1 300  2230  1084.24 5.14 3614 2015 300  300    Songwe Manolo 149  780  381.56 5.20 2561 2020 149  149    Songwe Sofre  157  736  375.28 5.43 2390 2019 157  157    Taveta  145  850  439.46 5.48 3031 2020 145  145    Songwe Bipugu 34  153  123.70 8.55 3638 2016 34  34    Igamba Falls 980 m 80  494  606.62 12.90 7583 2020 80  80    Kinansi II  120  69  222.01 34.45 1850 2018 120  120    UGANDA Murchison  high 750  5904  1658.48 3.00 2211 2019    750    Isimba  100  788  363.09 4.87 3631 2016    100    Ayago    550  4336  2150.61 5.24 3910 2019    550    Karuma High  700  5512  2793.00 5.35 3990 2018    700   
  • 138. Final Master Plan Report 5-28 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Total new hydro availability by December 2017, and for the next 5 year period, is summarized as follows: Table 5-14 Total new hydro for the first two 5 year periods of the study (MW) Country  New hydro on‐power 2013‐2017 New hydro on‐power 2018‐2022  Burundi  62 90 Eastern DRC 145 1,446 Egypt  40 0 Ethiopia  4,582 9,735 Kenya  256 300 Rwanda  28 0 Sudan  0 2,870 Tanzania  477 2,648 Uganda  100 2,000 TOTAL  5,691 19,089
  • 139. Final Master Plan Report 6-1 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 6 FUTURE THERMAL OPTIONS 6.1 Capital costs for future thermal projects The costs of all future thermal options that have been listed in country master plans have been harmonized, by escalating capital costs to 2009 price levels using the indices provided in Section 3.2.4, and by adding an allowance for interest during construction. The allowance for interest during construction reflects normal construction periods, as a function of plant type and size, For projects for which capital costs have not been provided, generic prices have been used, as are provided in Section 6.1.1 below. These generic prices reflect plant size and type and have been developed by comparing costs provided in country master plans with international data. 6.1.1 Generic capital costs Steam plants Various countries have included steam plants in their generation plans. These can be coal, oil or gas fired. Plant sizes range from 100-150 MW to multiples of units in the 600 MW range. A review of recent costs for coal fired steam plant indicates overnight costs (ie without financing / IDC) in the range of: • 150 MW units 2800 US$/kW • 600 MW 2000 US$/kW The comparisons and trend line for coal fired plant are shown inTable 6-1. Information sources include: • 2009 prices developed for the TANESCO PSMP • 2004 prices for the EAPMP, for Uganda, Kenya and Tanzania • 2008 prices included in the Kenya Master Plan • Prices given in the Uganda (2009) and Sudan (2000) generation plans • Prices given in the 2008 ESMAP report on equipment prices in the energy sector. These compared prices for plants were sourced in the USA, India and Romania. Romania data represented a median range and so were used.25 • SNC statistical data for EPCM packages as a function of size These costs were escalated to 2009 price levels, as required, using USBR Dept Labour cost indices for electrical generating plant.26 25 ESMAP – URS Study of equipment prices in the energy sector, June 2008 26 US Department of labout producer price index for electric power generation NAICS 221110
  • 140. Final Master Plan Report 6-2 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 6-1 Comparative costs for coal fired STPPs - 2009 $ excluding IDC Config.  Total Capacity  (MW)  Capital Cost  (MUSD)  Year  Escalation Factor  Cost 2009  Cost  ($/KW)  Source  4x50  200  760  2009 100 760 3800  SNC for TANESCO 2x100  200  600  2009 100 600 3000  SNC for TANESCO 2x150  300  780  2009 100 780 2600  SNC for TANESCO 2x100  200  190  2004 127 241 1207  EAPMP  2x150  300  260  2004 127 330 1101  EAPMP  2x150  300  742  2007 102 757 2523  Kenya  4x150  600  1234  2007 102 1259 2098  Kenya  1x56  56  167  2009 100 167 2982  Uganda PB  1x400  400  457  2006 105 480 1200  Sudan PB  1x100  100  133  2005 109 145 1450  Ethiopia PB  1x300  300  875  2007 102 893 2975  ESMAP/Romania 1x500  500  1267  2007 102 1292 2585  ESMAP/Romania 1x800  800  1801  2007 102 1837 2296  ESMAP/Romania 1x200  200  446  2007 102 455 2275  SNC EPCM Packages 1x300  300  624  2007 102 636 2122  SNC EPCM Packages 1x350  350  714  2007 102 728 2081  SNC EPCM Packages 1x400  400  800  2007 102 816 2040  SNC EPCM Packages The above values also provided the basis for oil and gas fired steam plant. The ESMAP report provided comparative costs for 300 MW coal, oil and gas fired units, which indicated oil fired plant was approximately 50 % of the price of coal fired plant, and gas fired plant 40 % for the coal plant cost. For the current study the relative costs have been assumed as: • Coal plant100 % • Oil plant 60 % • Gas plant 50 % Typical unit costs for steam generation plant used in this study were therefore as follows: Table 6-2 Typical unit costs for STPP Fuel  Unit size (MW) Cost – no IDC (US$/kW) ‐ 2009 Coal  650 2000 Coal  150 2500 Coal  100 2800 Oil  135 1700 Gas  650 1000 Gas  50 1700
  • 141. Final Master Plan Report 6-3 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Nuclear A series of 5000 MW nuclear units are included in the Egypt generation plan. Capital costs will depend on the plant type, size, supplier technology, supplier country and plant location. Kenya is also considering nuclear generation, with possible on-power of the first plant about 2020. It is understood that 1000 MW modules are planned.27 A useful basis for typical nuclear plant costs is provided by a 2006 paper by NERA28 . This provides a comparison of costs from a number of suppliers in different countries, with units typically in the 1000 MW size range. Indicated capital costs, understood to be overnight (excluding IDC) are in the range of 1000 US$/kW to 2500 US$/kW. A typical value would be about 2000 US$/kW (corresponding to a 2005 Areva price for multiple units). Escalated to 2009 the corresponding cost would be 2200 US$/kW. A report issued in 2010 by the World Nuclear Association provides somewhat higher costs29 . Typically 2008 overnight costs for a complete plant (including cooling towers, site works, land and risk) are in the order of 3000 to 4600 US$/kW. The same reference quotes a series of recent bare plant costs in the 2000 to 3500 US$/kW range. Adding balance of plant (about 27 %) would increase this range to 2500 to 4500 US$/kW. For the purpose of preliminary studies an all-in overnight cost of 3500 US$/kW has been assumed. Geothermal Geothermal generation is planned for Kenya and Ethiopia. Kenya already has significant experience with this technology. Prices in the region from recent studies, and adjusted to 2009 suggest a cost range of 2500 to 4000 US$/kW. An average cost of 3800 US$/kW, which reflects the Kenya recent master plan costs, is used for future projects in Kenya. Comparative costs are shown in Table 6-3. For Ethiopia capital costs for a series of geothermal plants are provided in a recent report issued by the Ministry of Mines and Energy30 . These estimates provided a range of 2800 to 3100 US$/kW. A unit cost of 3000 US$/kW has been used for Ethiopia projects. Gas turbines Open cycle gas turbines are proposed in the country generation plans for Tanzania and Uganda. Unit sizes are in the 50-60 MW range. Some comparative costs at 2009 price levels are shown in Table 6-3. The SNC value for the TANESCO PSMP reflected an average of 7 price quotations. Prices quoted in 2008 indicated a cost of about 850 US$/kW for 25 MW units and 650 to 730 US$/kW for 65 MW units, expressed as bare plant overnight costs. In the ENPTPS, It is also suggested to use 140 MW OCGT generics in Ethiopia. For the purpose of this study a complete plant overnight cost of 900 US$/kW has been selected for all plants. Combined cycle gas turbine plants Combined cycle plants form an important part of the Egyptian generation plan, and are included in the Kenya and Uganda expansion plans. For Egypt a series of plants with multiple 250 MW units are scheduled, as well as some 650 MW units. Previous plans by EEHC had been based on 750 MW plants, as multiples of 250 MW units. It is understood 27 Nuclear generation in Kenya was not included in the subsequent expansion plans as this option was not defined during the Inception or data gathering stage. It is understood that currently environmental assessment and preliminary site selection is underway 28 SPRU, University of Sussex and NERA Economic Consulting - The role of nuclear power in a low carbon economy – paper 4 - the economics of nuclear power, March 2006 29 World Nuclear Association – The economics of nuclear power - January 2010 30 Ministry of Mines and Energy, Investment opportunities in geothermal energy development in six selected geothermal prospects in Ethiopia,- project profiles, December 2008
  • 142. Final Master Plan Report 6-4 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study that these combined cycle plants have a configuration of approximately 2x250 MW gas turbines and a 250 MW steam plant31 . For these large combined cycle plants an average cost of 900 US$/kW has been assumed. For the midsized combined cycle plants in the 180 MW range, as included in the Kenya and Uganda expansion plans, the configuration is approximately 2x60 MW of gas turbine and 1 x 60 MW of steam plant or 1 x 120 MW of gas turbine and 1x60 of steam plant. Three quotations obtained for the TANESCO PSMP, were in the range of 1050 to 1250 US$/kW at 2008 prices. Based on this and other sources, an average cost of 1200 US$/ kW, overnight, complete plant, at 2009 prices, has been selected. Table 6-3 Comparative costs for Geothermal, OCGT and CCGT - 2009 $, no IDC Plant  Type  Config.  Fuel  Total Cap.  (MW)  Capital Cost  (MUSD)  Year  Escalation factor  Cost  2009  Cost  ($/kW)  Source  Geo  2x70    140  520 2008 100 520 3714  Kenya PSMP 33  33  132 2009 100 132 4000  Uganda PB 2x50  100  234 2005 110 257 2574  Ethiopia PB 2x70  140  518 2009 100 518 3700  SNC TANESCO OCGT  1x90  LFO  90  68 2008 100 68 756  Kenya PSMP 1x60  60  100 2007 102 102 1700  Uganda PB 3x50  NG  150  128 2009 100 128 853  SNC TANESCO 1x25  25  19 2007 102 19 775  ESMAP/Romania 1x150  150  69 2007 102 70 469  ESMAP/Romania CCGT  3x60  LFO  180  221 2008 100 221 1228  Kenya PSMP 1x185  185  419 2009 100 419 2265  Uganda PB 2x70+50  NG  150  174 2005 110 191 1276  Ethiopia PB 3x60  180  210 2009 100 210 1167  SNC TANESCO   140  155 2007 102 158 1129  ESMAP/Romania   580  411 2007 102 419 723  ESMAP/Romania Diesel plants Unit costs for conventional diesel plant have been set as: • Medium speed (LFO or gas) 1300 US$/kW • Low speed (HFO) 2000 US$/kW It may be noted that any diesel plants for Rwanda and Uganda would have to use LFO, due to transport constraints. Lake Kivu methane fuelled engines The capital cost for the first methane gas fired plant has been stated as 325 MUS$ for the 100 MW plant to be developed by Contour Global32 . This includes the gas gathering system, supply pipeline, the diesel generation plant, road access and development of port facilities at Kibuye. This yields an average cost of 3250 US$/kW. It is assumed that the infrastructure requirements for the second plant, the 200 MW to be developed by (or for supply to) a partnership of Rwanda, DRC and Burundi, would be similar, so the same unit cost is assumed. Cogeneration Cogeneration plant in the region is assumed to be steam thermal burning biomass (bagasse). Given the small size of these plants, a relatively high unit cost of 2500 US$/kW 31 Mitsubishi Heavy Industries have provided for 2 GT units each to West Delta and East Delta Electricity Production Companies. These M701F units have a rating of about 270 MW and are the GT components for the 750 MW combined cycle plants at Sidi Krir and El Atf power stations 32 East Africa Business Week – November 2009
  • 143. Final Master Plan Report 6-5 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study has been assumed as 75 % of the cost of a coal fired plant, noting that a biomass plant will include major fuel handling facilities. Table 6-4 below is a summary table of all generic capital costs used in the present study for thermal power plants: Table 6-4 Unit costs for Generic Thermal plants - 2009 $, no IDC Plant Type  Fuel Type Unit Size (MW) 2009 Cost – No IDC ($/kW)  STPP  Coal  650 2000 150 2500 100 2800 Oil  135 1700 NG  650 1000 50 1700 Nuclear  1000 (Egypt) 3500 Geothermal  70 (Kenya) 3800 <50 (Ethiopia) 3000 OCGT  NG / Oil  Any 900 CCGT  NG / Oil  250‐650 900 60‐120 1200 MSD  LFO/NG  Any 1300 LSD HFO  Any 2000 6.1.2 Interest during construction Capital costs for thermal plants, as shown above, are based on overnight costs, i.e. without interest during construction. To obtain capitalized costs for the calculation of unit generation costs, IDC has been added. These are based on standardized assumed capital disbursement schedules during construction, by plant type, as shown below: Table 6-5 Typical disbursement schedules during construction   CCGT  GT  Diesel Diesel Geo Coal Coal Oil  Oil  180  60x2  LSD MSD 2x100 2x150 2x00  2x150  Years (nominal) 3  2  3 2 4 4 4 4  4  Year 4      13 20 20 5  5  Year 3  15    15 12 35 35 40  40  Year 2  50  60  50 60 45 30 30 40  40  Year 1  35  40  35 40 30 15 15 15  15  The corresponding increments for interest during construction, based on an interest rate of 10 %, are as follows:
  • 144. Final Master Plan Report 6-6 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 6-6 Interest during construction - typical increments for thermal plants Type of plant  Years of construction costs  % of total cost  Coal STPP  4 24.4 Oil STPP  4 19.6 OCGT  2 11.1 CCGT  3 13.4 LSD  3 13.4 MSD  2 11.1 Geothermal  4 16.7 Cogeneration  3 13.4 Nuclear  5 26.3 The generic thermal power plants can therefore be summarized in the following table: Table 6-7 Generic TPP Unit costs - $/kW with IDC Type  Fuel  Type  Installed  Capacity MW  Cost No IDC $/kW  Plant Life Years  Construction  Years  IDC   %  Unit Cost  $/kW  STPP  Coal  650  2000 25 4 24.4  2488 150  2500 25 4 24.4  3110 100  2800 25 4 24.4  3483 Oil  135  1700 25 4 19.6  2033 NG  650  1000 25 4 19.6  1196 50  1700 25 4 19.6  2033 Nuclear  1000 (Egypt)  3500 40 5 26.3  4420 Geothermal  70 (Kenya)  3800 25 4 16.7  4434 <50 (Ethiopia)  3000 25 4 16.7  3501 OCGT  NG / Oil  Any  900 20 2 11.1  1000 CCGT  NG / Oil  250‐650  900 20 3 13.4  1020 60‐120  1200 20 3 13.4  1361 MSD  LFO/NG  Any  1300 20 2 11.1  1444 LSD  HFO  Any  2000 20 3 13.4  2268 6.2 Minimum lead times to on-power Total lead times to on-power will depend on the preparatory work required to define a project for approval. In the absence of specific information in source references the following lead times are used:
  • 145. Final Master Plan Report 6-7 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 6-8 Minimum on-power lead times for thermal plants Plant Type  Project preparation Procurement / Construction Total  Coal STPP 3 3 6  Oil STPP 3 3 6  LSD / MSD  1 1 2  OCGT  2 1 3  CCGT  2 1 3  Geothermal  3 3 6  Cogeneration  3 3 6  Nuclear 5 6 11  6.3 Plant heat rates Plant heat rates are a function of the specific technology and the manufacturers’ process. For this study the following typical heat rates have been adopted33 : Table 6-9 Heat Rates for different Thermal Plants Plant type Heat rate (kJ/kWh) Coal STPP 10,000 Oil STPP 10,500 OCGT 11,500 CCGT 7,900 LSD  7,900 MSD  8,000 Geothermal 20,700 Cogeneration 12,000 6.4 Fuel prices Fuel price projections are one of the key components of this study. Fuel prices directly impact the profitability of the interconnection between the different countries because high fossil fuel prices will increase the attractiveness of hydro plant with respect to thermal plant, while low fuel price might turn the interconnection non profitable. The fuel prices considered in this study reflect international prices in order to avoid internal distortions in each country related with subsidies or royalties. 6.4.1 Oil The oil prices for this study were taken from the import price of “Annual Energy Outlook 2010” (AEO2010) issued on April 2010 with projections to 2035. World oil prices can be influenced by a multitude of factors. Some tend to be short term, such as movements in exchange rates, financial markets, and weather, and some are longer term, such as expectations concerning future demand and production decisions by the Organization of the 33 heat rates were selected following review of values used in the TANESCO 2009 PSMP, the 2008 Kenya least cost plan, the Sudan 2007 master plan and the EAPMP study
  • 146. Final Master Plan Report 6-8 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Petroleum Exporting Countries (OPEC). In 2009, the interaction of market factors led prompt month contracts (contracts for the nearest traded month) for crude oil to rise relatively steadily from a January average of 41.68 US$/bbl to a December average of 74.47 US$/bbl. Changes in the world oil market over the course of 2009 served to highlight the myriad factors driving future liquids demand and supply and how a change in these factors can reverberate through the world liquids market. Over the long term, world oil prices in EIA’s outlook are determined by four broad factors: (1) non-OPEC conventional liquids supply, (2) OPEC investment and production decisions, (3) unconventional liquids supply, and (4) world liquids demand. Uncertainty in long-term projections of world oil prices can be explained largely by uncertainty about one or more of these four broad factors. Table 6-10 below shows the projections of the oil prices to 2038, for the last three years, the EIA forecast was extended using the rate of increase in 2035 over 2034. Table 6-10 Oil price projections - 2038 Year  Crude Oil US$/bbl IDO US$/L HFO US$/L 2013  78.9 0.592 0.567 2018  95.3 0.713 0.666 2023  101.6 0.763 0.704 2028  108.0 0.809 0.747 2033  117.0 0.872 0.805 2038  127.3 0.951 0.875 Levelized  96.7 0.722 0.675 Source: EIA long term forecast base scenario AEO2010 6.4.2 Natural Gas Figure 6-1 shows the evolution of NG prices for different regions. In 2009 and 2010 the prices returned around the same level of 2006. Figure 6-1 Evolution of NG prices for different regions
  • 147. Final Master Plan Report 6-9 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study While the oil market is fairly integrated at a global level, this is not the case for gas and coal which still show a strong regional spread. The main reason for these regional differentiations is the high transportation cost of gas and coal, relative to their production cost. Although the development of LNG transport facilities will introduce some degree of trade-off between regional gas markets the price differentials are not expected to fully disappear over the next 30 years. Higher world oil prices are expected to result in a shift away from petroleum consumption and toward natural gas consumption in all sectors of the international energy market. In addition, some NG contract prices are tied directly to crude oil prices, putting further upward pressure on NG prices. Finally, higher oil prices are expected to promote increases in gas based production, which in turn would lead to more price pressure on world natural gas supplies. Accordingly, natural gas prices are assumed broadly to follow the trend in oil prices, because of the continuing widespread use of oil-price indexation in long-term gas contracts and because of inter-fuel competition. For this study, considering the information provided by the countries natural gas will be significantly available for power plants only in Egypt. For this regional master plan study, the price of natural gas will reflect international market prices. Table 6-11 below shows the most recent projections by the EU for the EU/African market and the projection of DOE/EIA for a hub in the US. For this study the EU projection will be used. Table 6-11 NG price projections - 2038 Year  NG‐EU US$/MMBTU NG‐EIA US$/MMBTU 2013  6.1 5.5 2018  6.5 5.8 2023  7.3 6.3 2028  7.9 6.8 2033  8.5 7.7 2038  9.3 8.3 Levelized  6.9 6.1 6.4.3 Coal The coal price projection is based on the reference coal price used in the Tanzania PSMP 2009 updated with the latest trend reflected in the AEO 2010 projections. The reference price in 2007 was 65 US$/Mt plus $10 for transportation and $5 for handling charge, to provide a total estimated cost of 80 US$/Mt. Table 6-12 shows the forecast for the period 2013-2038: Table 6-12 Coal price projections - 2038 Year  COAL US$/Mt 2013  80.0  2018  74.3  2023  73.7  2028  74.1  2033  75.8  2038  78.6  Levelized 75.0 
  • 148. Final Master Plan Report 6-10 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 6.4.4 Geothermal The geothermal price is based on actual geothermal plant operations in Central American countries. The price used is: 0.725 $/GJ. This comes from the following: 1 kg of geothermal steam has a calorific content of 660 kcal/kg. That is equivalent to 2.7615 GJ/Mt (Metric Ton). With the price of geothermal steam at 2 $/Mt, we get the geothermal fuel price: 0.725 $/GJ We assume that this price is maintained throughout the study horizon. 6.4.5 Net calorific value The net calorific value is the quantity of heat liberated by the complete combustion of a unit of fuel when the vapour produced is assumed to remain as a vapour and the heat is not recovered. The net calorific value is a key parameter to determine the specific cost of fuel. The following table presents default values used in this study: Table 6-13 Typical net calorific values Fuel  Net Calorific Value Unit  HFO  6.15  GJ/bbl  Diesel  6.63  GJ/bbl  NG  38.30  GJ/103 m3 Coal  22.20  GJ/Mt  Geo  2.76  GJ/Mt  6.4.6 Fuel forecast Table 6-14 and Figure 6-2 show the annual projections for the fuels price in physical units and energy units:
  • 149. Final Master Plan Report 6-11 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 6-14 Fuel Forecast Year  Crude Oil  1   IDO  1   HFO  1   Coal  2   NG*  $/GJ  $/bbl  Incr (%)  $/lt  Incr (%)  US$/lt  Incr (%)  US$/Mt  Incr (%)  US$/m3  Incr (%)  IDO  HFO  Coal  NG‐EU*  NG‐EIA** 2013  78.9    0.6    0.6    80.0    0.2    15.3  13.6  3.6  6.5  5.8  2014  83.6  6.0  0.6  4.2  0.6  5.1  74.2  ‐7.2  0.2  0.0  16.0  14.3  3.3  6.5  5.8  2015  86.6  3.6  0.6  2.8  0.6  2.8  74.9  0.9  0.2  0.0  16.4  14.7  3.4  6.5  5.9  2016  89.8  3.7  0.7  5.0  0.6  2.6  74.4  ‐0.7  0.3  1.8  17.2  15.1  3.3  6.6  6.0  2017  92.5  2.9  0.7  3.6  0.6  3.3  74.6  0.2  0.3  1.8  17.8  15.6  3.4  6.7  6.1  2018  95.3  3.1  0.7  3.4  0.7  2.6  74.3  ‐0.3  0.3  1.8  18.4  16.0  3.3  6.8  6.1  2019  96.6  1.4  0.7  2.1  0.7  1.5  74.1  ‐0.3  0.3  1.8  18.8  16.2  3.3  6.9  6.2  2020  97.9  1.3  0.7  1.6  0.7  0.5  74.1  ‐0.1  0.3  1.8  19.1  16.3  3.3  7.1  6.3  2021  99.0  1.2  0.7  0.7  0.7  1.5  73.8  ‐0.4  0.3  3.0  19.3  16.5  3.3  7.3  6.4  2022  100.2  1.2  0.8  0.9  0.7  0.9  73.9  0.1  0.3  3.0  19.4  16.7  3.3  7.5  6.6  2023  101.6  1.4  0.8  1.5  0.7  1.3  73.7  ‐0.2  0.3  3.0  19.7  16.9  3.3  7.7  6.6  2024  102.8  1.2  0.8  0.9  0.7  1.3  73.7  0.0  0.3  3.0  19.9  17.1  3.3  7.9  6.6  2025  104.2  1.3  0.8  1.3  0.7  1.2  73.4  ‐0.4  0.3  3.0  20.2  17.3  3.3  8.2  6.6  2026  105.0  0.8  0.8  1.2  0.7  0.4  73.9  0.6  0.3  0.7  20.4  17.4  3.3  8.2  6.8  2027  106.5  1.4  0.8  1.1  0.7  1.6  73.7  ‐0.2  0.3  0.7  20.6  17.7  3.3  8.3  6.9  2028  108.0  1.4  0.8  1.4  0.7  1.4  74.1  0.5  0.3  0.7  20.9  17.9  3.3  8.4  7.1  2029  109.9  1.8  0.8  1.8  0.8  1.6  74.5  0.5  0.3  0.7  21.3  18.2  3.3  8.4  7.4  2030  111.2  1.1  0.8  0.8  0.8  1.6  74.7  0.3  0.3  0.7  21.5  18.5  3.4  8.5  7.6  2031  113.4  2.0  0.8  1.9  0.8  1.8  75.2  0.7  0.3  1.8  21.9  18.8  3.4  8.6  8.0  2032  115.2  1.6  0.9  1.7  0.8  1.5  75.5  0.4  0.3  1.8  22.2  19.1  3.4  8.8  8.1  2033  117.0  1.6  0.9  1.4  0.8  1.2  75.8  0.4  0.3  1.8  22.6  19.3  3.4  8.9  8.1  2034  119.0  1.7  0.9  1.7  0.8  1.7  76.3  0.7  0.3  1.8  22.9  19.6  3.4  9.1  8.3  2035  121.0  1.7  0.9  1.8  0.8  1.7  76.9  0.7  0.4  1.8  23.3  20.0  3.5  9.3  8.4  2036  123.1  1.7  0.9  1.8  0.8  1.7  77.4  0.7  0.4  1.8  23.8  20.3  3.5  9.4  8.5  2037  125.2  1.7  0.9  1.8  0.9  1.7  78.0  0.7  0.4  1.8  24.2  20.6  3.5  9.6  8.7  2038  127.3  1.7  1.0  1.8  0.9  1.7  78.6  0.7  0.4  1.8  24.6  21.0  3.5  9.8  8.8  Levelized  96.7  1.9  0.7  1.9  0.7  1.8  75.0  ‐0.1  0.3  1.7  18.7  16.2  3.4  7.3  6.5  1 From EIA long term forecast – AEO 2010 2 First year from Tanzania Master Plan August 2009. Annual adjustment from EIA forecast electric power * From ENPTPS: June 2007 adjusted to 2009 prices. Main source European Commission ** From EIA long term forecast – AEO 2010. Henry Hub Prices
  • 150. Final Master Plan Report 6-12 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Figure 6-2 Fuel forecast 6.5 Future thermal generation costs The supply-demand analyses generally reflect the ordering of new plant provided in country master plans. However these in most cases cover short term and midterm planning periods, as compared with the planning horizon up to 2038 used in this current study. Additionally some of the timing of future projects may be affected by the minimum lead times being used in this study. Consequently the preparation of preliminary alternative generation plans for the demand supply analyses also uses comparative costs for alternative thermal technologies. These are presented in Table 6-15 below and show generation costs as a function of plant capacity factor. Project generation costs are shown on a country by country basis. The unit cost of generation is based on: Fixed component • Amortization of capitalized amount • Interim replacement • Insurance • Fixed operation and maintenance Annual costs • Fuel cost • Variable operation and maintenance The parameters used to calculate the unit costs are provided in Section 3, apart from the fuel costs given in Section 6.4 above, and the plant heat rates from Section 6.3. The relative contribution of fixed costs (primarily capital) and variable cost (primarily fuel) varies considerably throughout the EAPP region, with plant size and type being the main factors. Illustrative costs are compared below in Table 6-15:
  • 151. Final Master Plan Report 6-13 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 6-15 Illustrative future unit generation costs in c/kWh, based on 75% CF Country  Type  Capacity  (MW)  Capital  cost with  IDC  ($/kW)  Fixed  cost  c/kWh  Variable  cost  c/kWh  Total  cost  c/kWh  Fixed  cost %  Variable  cost %  Egypt  STPP ‐ NG  1300  1196 2.57 1.82 3.47  59%  41% CCGT ‐ NG  1000  1021 2.04 1.43 3.47  59%  41% Nuclear  1000  4430 8.44 0.96 9.40  90%  10% Ethiopia  Geothermal  75/100  3503 6.73 1.75 8.48  79%  21% Kenya  Geothermal  140  4437 8.38 1.75 10.13  83%  17% STPP ‐ coal   (Richards Bay)  300  2919  5.92  5.05  10.97  54%  46%  Rwanda  Diesel/Methane  100  3613 6.69 2.05 8.74    Sudan  STPP ‐ Crude  250  2034 4.05 9.38 13.43  77%  23% Tanzania  STPP ‐ Coal  400  3482 6.77 2.65 9.42  30%  70% OCGT ‐ NG  240  1001 2.03 5.10 7.13  72%  28% Uganda  CCGT ‐ Gasoil  185  1361 2.68 21.73 24.41  28%  72% STPP ‐ HFO  60  2034 4.13 14.27 18.90  11%  89%
  • 152. Final Master Plan Report 6-14 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Table 6-16 Thermal generation costs by country NAME  Type  Generation  Capital Cost  Fixed Costs / Year  Variable cost c/kWh  Total Unit Cost c/kWh  Inst Cap  MW  Fuel  Life Yr  Yr GWh  Const  Yr  2009  Cost  $/kW  IDC %  Total Cost  $/kW  Fixed  Annual  Cost  $/kW  Insur  Inter  Repl  (%)  Fixed  O&M  $/kW Total  Fixed  Cost  $/kW  O&M  Fuel  Cost  Total  Plant Factor %  25  50  75  hrs / Year  2190  4380  6570  BURUNDI  EAST DRC  EGYPT  Qassasen  CCGT  1,250  NG  20  8760  3  900  19.6  1021  120   0.60  8  134  0.40  1.03  1.43  7.5  4.5  3.5  Qassasen  CCGT  250  NG  20  1752  3  900  19.6  1021  120   0.60  8  134  0.40  1.03  1.43  7.5  4.5  3.5  Giza North   CCGT  1,000  NG  20  7008  3  900  19.6  1021  120   0.60  8  134  0.40  1.03  1.43  7.5  4.5  3.5  Giza North   CCGT  500  NG  20  3504  3  900  19.6  1021  120   0.60  8  134  0.40  1.03  1.43  7.5  4.5  3.5  Damietta West 1  CCGT  1,500  NG  20  10512  3  900  19.6  1021  120   0.60  8  134  0.40  1.03  1.43  7.5  4.5  3.5  Damietta West 2  CCGT  1,500  NG  20  10512  3  900  26.6  1021  120   0.60  8  134  0.40  1.03  1.43  7.5  4.5  3.5  Combined cycle  CCGT  8,250  NG  20  57816  3  900  19.6  1021  120   0.60  8  134  0.40  1.03  1.43  7.5  4.5  3.5  Ain Sokhna  STPP  1,300  NG  25  9110  4  1000  19.6  1196  132   0.60  30  169  0.45  1.37  1.82  9.5  5.7  4.4  Suez  STPP  650  NG  25  4555  4  1000  19.6  1196  132   0.60  30  169  0.45  1.37  1.82  9.5  5.7  4.4  Helwan south   STPP  1,300  NG  25  9110  4  1000  19.6  1196  132   0.60  30  169  0.45  1.37  1.82  9.5  5.7  4.4  Helwan south   STPP  1,300  NG  25  9110  4  1000  19.6  1196  132   0.60  30  169  0.45  1.37  1.82  9.5  5.7  4.4  Qena  STPP  650  NG  25  4555  4  1000  26.6  1196  132   0.60  30  169  0.45  1.37  1.82  9.5  5.7  4.4  Qena  STPP  650  NG  25  4555  4  1000  19.6  1196  132   0.60  30  169  0.45  1.37  1.82  9.5  5.7  4.4  Safaga  STPP  1,300  NG  25  9110  4  1000  19.6  1196  132   0.60  30  169  0.45  1.37  1.82  9.5  5.7  4.4  Steam 650 MW  STPP  16,250  NG  25  113880  4  1000  19.6  1196  132   0.60  30  169  0.45  1.37  1.82  9.5  5.7  4.4  Dabaa nuclear  Nuclear  5,000  U  40  39420  5  3500  19.6  4430  453   0.60  75  555  0  0.96  0.96  26.3  13.6  9.4  ETHIOPIA  Aluto.Langano   Geo  75  Heat  25  526  4  3000  16.8  3503  386   0.60  35  442  0.25  1.50  1.75  21.9  11.8  8.5  Tendaho  Geo  100  Heat  25  701  4  3000  16.8  3503  386   0.60  35  442  0.25  1.50  1.75  21.9  11.8  8.5  Corbetti  Geo  75  Heat  25  526  4  3000  16.8  3503  386   0.60  35  442  0.25  1.50  1.75  21.9  11.8  8.5  Abaya  Geo  100  Heat  25  701  4  3000  16.8  3503  386   0.60  35  442  0.25  1.50  1.75  21.9  11.8  8.5  Tulu Moye  Geo  40  Heat  25  280  4  3000  16.8  3503  386   0.60  35  442  0.25  1.50  1.75  21.9  11.8  8.5  Dofan Fantale  Geo  60  Heat  25  420  4  3000  16.8  3503  386   0.60  35  442  0.25  1.50  1.75  21.9  11.8  8.5 
  • 153. Final Master Plan Report 6-15 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study NAME  Type  Generation  Capital Cost  Fixed Costs / Year  Variable cost c/kWh  Total Unit Cost c/kWh  Inst Cap  MW  Fuel  Life Yr  Yr GWh  Const  Yr  2009  Cost  $/kW  IDC %  Total Cost  $/kW  Fixed  Annual  Cost  $/kW  Insur  Inter  Repl  (%)  Fixed  O&M  $/kW Total  Fixed  Cost  $/kW  O&M  Fuel  Cost  Total  Plant Factor %  25  50  75  hrs / Year  2190  4380  6570  KENYA  Olkaria ext  Geo  35  Heat  25  245  3  3800  13.4  4310  475   0.60  35  536  0.25  1.50  1.75  26.2  14.0  9.9  Longonot   Geo  140  Heat  25  981  4  3800  16.8  4437  489   0.60  35  550  0.25  1.50  1.75  26.9  14.3  10.1  Suswa   Geo  140  Heat  25  981  4  3800  16.8  4437  489   0.60  35  550  0.25  1.50  1.75  26.9  14.3  10.1  Menengai   Geo  140  Heat  25  981  4  3800  16.8  4437  489   0.60  35  550  0.25  1.50  1.75  26.9  14.3  10.1  North Rift  Geo  70  Heat  25  491  4  3800  16.8  4437  489   0.60  35  550  0.25  1.50  1.75  26.9  14.3  10.1  Other   geothermal  (multiple)  Geo  140  Heat  25  981  4  3800  16.8  4437  489   0.60  35  550  0.25  1.50  1.75  26.9  14.3  10.1  Mombasa  (multiple)  STPP  300  Coal  25  2102  4  2500  24.4  3110  343   0.60  50  411  0.65  4.40  5.05  23.8  14.4  11.3  RWANDA  Biomas peat  cogen  STPP  50  Biom  25  329  3  2500  13.4  2836  312   0.60  40  369  0.60  2.40  3.00  19.9  11.4  8.6  Kivu gas plant 1  Diesel  100  Meth  25  657  2  3250  11.2  3613  398   0.60  20  440  1.20  0.85  2.05  22.1  12.1  8.7  Kivu gas plant 2  Diesel  200  Meth  25  1314  2  3250  11.2  3613  398   0.60  20  440  1.20  0.85  2.05  22.1  12.1  8.7  Generic diesel  Diesel  50  LFO  20  329  2  1300  11.2  1445  170   0.60  40  218  1.00  20.64  21.64  31.6  26.6  25.0  SUDAN  Crude fired  238  MW units  STPP  476  Crude  25  3336  4  1700  19.6  2034  224   0.60  30  266  0.45  8.93  9.38  21.5  15.5  13.4  Crude fired  475  MW units  STPP  1425  Crude  25  9986  4  1700  19.6  2034  224   0.60  30  266  0.45  8.93  9.38  21.5  15.5  13.4  CCGT 208 MW ‐  gas oil  CCGT  624  gas oil  25  4373  3  900  13.4  1021  112   0.60  8  127  0.40  9.09  9.49  15.3  12.4  11.4  CCGT 342 MW ‐  gas oil  CCGT  1368  gas oil  25  9587  3  900  13.4  1021  112   0.60  8  127  0.40  9.09  9.49  15.3  12.4  11.4  CCGT 458  MW  ‐ gas oil  CCGT  1832  gas oil  25  12839  3  900  13.4  1021  112   0.60  8  127  0.40  9.09  9.49  15.3  12.4  11.4  TANZANIA  Kiwira  STPP  200  Coal  25  1402  4  2800  24.4  3483  384   0.60  40  445  0.65  2.00  2.65  23.0  12.8  9.4 
  • 154. Final Master Plan Report 6-16 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study NAME  Type  Generation  Capital Cost  Fixed Costs / Year  Variable cost c/kWh  Total Unit Cost c/kWh  Inst Cap  MW  Fuel  Life Yr  Yr GWh  Const  Yr  2009  Cost  $/kW  IDC %  Total Cost  $/kW  Fixed  Annual  Cost  $/kW  Insur  Inter  Repl  (%)  Fixed  O&M  $/kW Total  Fixed  Cost  $/kW  O&M  Fuel  Cost  Total  Plant Factor %  25  50  75  hrs / Year  2190  4380  6570  Mchuchuma   STPP  400  Coal  25  2803  4  2800  24.4  3483  384   0.60  40  445  0.65  2.00  2.65  23.0  12.8  9.4  Ngaka  STPP  400  Coal  25  2803  4  2800  24.4  3483  384   0.60  40  445  0.65  2.00  2.65  23.0  12.8  9.4  Nyasa  STPP  200  Coal  25  1402  4  2800  24.4  3483  384   0.60  40  445  0.65  2.00  2.65  23.0  12.8  9.4  Kinyerezi   OCGT  240  NG  20  1682  2  900  11.2  1001  118   0.60  10  134  0.50  4.60  5.10  11.2  8.1  7.1  Mnazi   OCGT  300  NG  20  2102  2  900  11.2  1001  118   0.60  10  134  0.50  4.60  5.10  11.2  8.1  7.1  Generic diesel  Diesel  50  LFO  20  350  2  1300  11.2  1445  170   0.60  40  218  1.00  18.29  19.29  29.3  24.3  22.6  UGANDA  Kampala steam  STPP  56  Coal  25  392  4  2800  24.4  3483  384   0.60  70  475  0.66  4.40  5.06  26.7  15.9  12.3  Tullow steam  STPP  53  HFO  25  371  4  1700  19.6  2034  224   0.60  35  271  0.45  14.32  14.77  27.2  21.0  18.9  Tullow GT  OCGT  57  gas oil  20  399  2  900  11.2  1001  118   0.60  10  134  0.50  31.05  31.55  37.6  34.6  33.6  Tullow CCGT  CCGT  185  gas oil  20  1296  3  1200  13.4  1361  160   0.60  8  176  0.40  21.33  21.73  29.8  25.7  24.4  Tullow diesel  Diesel  10  HFO  25  66  2  2000  11.2  2223  245   0.60  40  298  1.00  21.60  22.60  36.2  29.4  27.1  Geothermal  Geo  33  Heat  25  217  4  1500  16.8  1751  193   0.60  35  238  0.45  1.50  1.95  12.8  7.4  5.6 
  • 155. Final Master Plan Report 6-17 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 6.6 Thermal plant retirements For future thermal additions (after 2013) retirement dates will be based directly on the service lives shown in the planning criteria. For existing plant the same procedure will be followed, however with the exception that for any project where the on power year was not available, year 2000 was used (i.e. resulting in about 50 % of the plant life by 2013). On power dates were generally taken from previous country master plans. The list of retirement dates for existing and committed thermal is shown in Table 6-17 below. Table 6-17 Existing and committed thermal retirements Name  Generation Retirements Inst. Cap  MW  Plant Type  Fuel Type  Plant  Life  Years  Max  Plant  Factor  %  Max  Energy  GWh  On  Power  Year  Retirement  Year  BURUNDI Bujumbura diesel  6  diesel LFO 20 75 36  1998  2018 EAST DRC SNEL  18  diesel LFO 20 75 116  2000  2020 Other  22  diesel LFO 20 75 141  2000  2020 EGYPT Shoubra El Kheima  1260  Steam NG/HFO 25 80 8830  1988  2013 Cairo West  350  Steam NG/HFO 25 80 2453  1979  2004 Caire West Ext  660  Steam NG/HFO 25 80 4625  1995  2020 Cairo South I  570  CCGT NG/HFO 20 80 3995  1989  2009 Cairo South II  165  CCGT NG/HFO 20 80 1156  1995  2015 Cairo North  1500  CCGT NG/LFO 20 80 10512  2008  2028 Wadi Hof  100  GT NG/LFO 20 80 701  1985  2005 Damietta  1200  CCGT NG/LFO 20 80 8410  1993  2013 Ataka  900  Steam NG/HFO 25 80 6307  1987  2012 Abu Sultan  600  Steam NG/HFO 25 80 4205  1986  2011 Shahab  100  GT NG/LFO 20 80 701  1982  2002 Port Said  73  GT NG/LFO 20 80 512  1984  2004 Arish  66  Steam NG/HFO 25 80 463  2000  2025 Oyoun Mousa  640  Steam NG/HFO 25 80 4485  2000  2025 Sharm el Sheik  178  GT LFO 20 80 1247  2000  2020 Hurghada  143  GT LFO 20 80 1002  2000  2020 Suez Gulf  683  Steam NG/HFO 25 80 4786  2002  2027 Port Said East  683  GT NG/HFO 20 80 4786  2003  2023 Talkha  290  CCGT NG/LFO 20 80 2032  1989  2009 Talkha 210  420  Steam NG/HFO 25 80 2943  1995  2020 Talkha 750  750  CCGT NG/LFO 20 80 5256  2008  2028 Nubaria  1500  CCGT NG/LFO 20 80 10512  2006  2026 Mahmoudia  316  CCGT NG/LFO 20 80 2215  1995  2015 Mahmoudia  75  GT NG/LFO 20 80 526  1982  2002 Kafr El‐Dawar  440  Steam NG/HFO 25 80 3084  1986  2011 Damanhour Ext  300  Steam NG/HFO 25 80 2102  1991  2016 Damanhour Old  195  Steam NG/HFO 25 80 1367  1969  1994 Damanhour  157  CCGT NG/LFO 20 80 1100  1995  2015 El‐Seiuf  200  Steam NG/LFO 25 80 1402  1984  2009
  • 156. Final Master Plan Report 6-18 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  Generation Retirements Inst. Cap  MW  Plant Type  Fuel Type  Plant  Life  Years  Max  Plant  Factor  %  Max  Energy  GWh  On  Power  Year  Retirement  Year  El‐Seiuf  113  GT HFO 20 80 792  1969  1989 Karrmouz  23  GT LFO 20 80 161  1980  2000 Abu Kir  911  Steam NG/HFO 25 80 6384  1991  2016 Abu Kir  24  GT NG/LFO 20 80 168  1983  2003 Sidi Krir 1.2  640  Steam NG/HFO 25 80 4485  2000  2025 Matrouh  60  Steam NG/HFO 25 80 420  1990  2015 Sidi Krir 3.4  683  Steam NG/HFO 25 80 4786  2002  2027 Walidia  624  Steam HFO 25 80 4373  1997  2022 Kunemat 1  1254  Steam NG/HFO 25 80 8788  1999  2024 Kunemat 2  500  CCGT NG/LFO 20 80 3504  2007  2027 Assiut  90  Steam HFO 25 80 631  1967  1992 Atfe  750  CCGT NG/HFO 20 80 5256  2009  2029 Nubaria 3  750  CCGT NG/HFO 20 80 5256  2009  2029 Wind Zarafana  305  Wind 20 50 1336  2008  2028 Solar Kurimat  140  Wind 20 50 613  2009  2029 ETHIOPIA Dire Dawa  44  diesel HFO 20 75 289  2004  2024 Awash 7  25  diesel HFO 20 75 164  2003  2023 Kaliti  14  diesel HFO 20 75 92  2003  2023 Aluto  7  geo 25 80 49  2007  2032 Small diesel  57  diesel HFO 20 75 374  1975  1995 KENYA Kipevu   75  diesel HFO 20 75 493  1999  2019 Kipevu new GT  60  GT 20 80 420  1999  2019 Nairobi Fiat   13  diesel LRO 20 75 85     2008 Olkaria 1  45  geo 25 80 315  1981  2010 Olkaria 2  70  geo 25 80 491  2003  2028 Olkaria 3  13  geo 25 80 91  2000  2025 Olbkaria 3 b  35  geo 25 80 245  2008  2033 Iberafrica IPP  56  diesel HFO 20 75 368  2000  2019 Tsavo IPP  74  diesel HFO 20 75 486  2001  2021 Cogen IPP  26  cogen Bagasse 25 75 171  2008  2025 Agrekko EPP  150  diesel LRO 20 75 986  2000  2013 RWANDA Gatsata  2  diesel LFO 20 75 13  1975  1995 Jabana diesel  8  diesel LFO 20 75 51  2000  2020 Mukungwa diesel  5  diesel LFO 20 75 30  2006  2026 New diesel  20  diesel HFO 20 75 131  2009  2029 RIG Kivu gas plant  5  diesel methane 20 75 30  2007  2027 SUDAN Dr Sharif 1  60  Steam NG 25 80 420  1985  2010 Dr. Sharif 2  120  Steam NG 25 80 841  1994  2019 Khartoum North   50  GT NG 20 80 350  1992  2012 Khartoum North   160  Steam NG 25 80 1121  2000  2025 Khartoum North   200  Steam NG 25 80 1402  2008  2033 Kuku  25  GT NG 20 80 175  1985  2005 Garri  450  CCGT NG 20 80 3154  2003  2023
  • 157. Final Master Plan Report 6-19 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study Name  Generation Retirements Inst. Cap  MW  Plant Type  Fuel Type  Plant  Life  Years  Max  Plant  Factor  %  Max  Energy  GWh  On  Power  Year  Retirement  Year  Garri  80  Steam NG 25 80 561  2008  2033 Kilo  40  GT NG 20 80 280  2007  2027 El  Fau  13  Diesel NG 20 75 85  2003  2023 Atbara  13  Diesel NG 20 75 88  2003  2023 Kassala  12  Diesel NG 20 75 76  1982  2002 Kassal 1‐5  50  Diesel NG 20 75 329  2007  2027 Port Sudan 1‐3  405  Steam NG 25 80 2838  2009  2034 Kosti 1&2  250  Steam NG 25 80 1752  2009  2034 El Bagair 1&2  270  Steam NG 25 80 1892  2009  2034 Al Fula 1&2  270  Steam NG 25 80 1892  2009  2034 Girba  7  Diesel NG 20 75 46  1983  2003 TANZANIA Songas 1  42.0  GT NG 20 80 294  2004  2024 Songas 2  120.0  GT NG 20 80 841  2005  2025 Songas 3  40.0  GT NG 20 80 280  2006  2026 Ubungo GT  102.0  GT NG 20 80 715  2007  2027 Tegeta IPTL  100.0  diesel HFO 20 75 657  2002  2022 UGANDA Kakira  17.0  Cogen Bagasse 25 75 112  2008  2039 Namanve  50.0  Diesel HFO 20 75 329  2008  2027 Invespro HFO IPP  50.0  Diesel HFO 20 75 329  2010  2015
  • 158. Final Master Plan Report 7-1 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study 7 IDENTIFICATION OF POTENTIAL REGIONAL PROJECTS The concept of the regional project is that the project could be part of a regional supply, at least for a few years. In this context it is noted that all countries except for Ethiopia and Egypt will exhaust all their identified indigenous resources before the end of the planning period in 2038. However larger projects could be important contributors to regional supply for a number of years. The criterion used at this preliminary stage for the identification of potential regional projects has been to compare project size with country load growth. Specifically, plant capacity has been compared with (preliminary) load growth estimates for 2030, and where project size is more than 2 years of load growth, the project is classified as a potential regional project. As load forecast growth varies around 6-9% / year, a uniform criterion of 15% of the 2030 preliminary load forecast has been used. This process primarily covers new hydro options, however the same criteria has been applied in reviewing larger thermal proposed additions. Country  2030 Load (MW)  15 % of 2030 load (MW) Plant Type  MW  Burundi  385  58 Siguvyaye hydro  90  Eastern DRC  179  27  Ruzizi III hydro  145  Ruzizi IV hydro  287  Wannie Rukula hydro  688  Piana Mwanga hydro  29  Bengamisa hydro  48  Babeda I hydro  50  Semliki hydro  28  Bendera hydro  43  Mugomba Hydro  40  Egypt  69,909  10,486     Ethiopia  8,464  1,270  Beko Abo hydro  2100  Mandaya hydro  2000  Gibe III hydro  1870  Karadobi Hydro  1600  Border  hydro  1200  Gibe IV hydro  1468  Kenya  7,795  1170     Rwanda  484  73  Kivu gas Plant 1  diesel  100  Kivu gas Plant 2  diesel  200  Sudan  11,054  1,658     Tanzania  3,770  565 Stieglers Gorge hydro  1200  Uganda  1,898  285  Karuma hydro  700  Ayago hydro  550  Murchison Falls  hydro  750  The generation projects identified in the previous table will be further analyzed in the regional plan (WBS 1300) These projects, whenever their earliest on-power date allows, will be assessed on earlier dates than in the national plans. This will allow identifying the potential additional net benefits (savings minus additional costs of advancing the project) to the whole EAPP region. Certain “shared” projects are attributed to one country, as follows: • Kivu methane plants – Rwanda • Ruzizi hydro plants – Eastern DRC
  • 159. Final Master Plan Report 7-2 WBS 1200 Generation supply study May 2011 & planning criteria EAPP/EAC Regional PSMP & Grid Code Study The Border project is included as it would be developed as part of the Blue Nile cascade, and because Ethiopia has a large number of midsized hydro sites that would also provide export potential. Egypt is including nuclear 1000 MW plants in its program, and certainly would have an export potential from gas fired plants or by pre-building nuclear for export.
  • 160. Draft Master Plan Report WBS 1300 Supply Demand Analysis February 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study WBS 1300 Supply-Demand Analysis and Project Identification
  • 161. Final Master Plan Report i WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study TABLE OF CONTENTS 1  OBJECTIVE AND SCOPE ....................................................................................... 1-1  1.1  Inputs ........................................................................................................................ 1-1  1.2  Tools ......................................................................................................................... 1-1  1.2.1  OPTGEN ...............................................................................................................1-2  1.2.2  SDDP.....................................................................................................................1-3  1.3  Methodology.............................................................................................................. 1-3  1.4  Main Results ............................................................................................................. 1-6  2  DEMAND FORECAST.............................................................................................. 2-1  2.1  Demand Scenarios.................................................................................................... 2-1  2.1.1  Selecting the adequate scenario ...........................................................................2-1  2.1.2  Summary of forecast results..................................................................................2-2  2.2  Demand Forecast in SDDP Format .......................................................................... 2-6  3  STUDY DATABASE................................................................................................. 3-1  3.1  Data required by SDDP............................................................................................. 3-1  3.1.1  Thermal, Wind and Solar Plants............................................................................3-1  3.1.2  Hydro Plants..........................................................................................................3-2  3.1.3  Fuels......................................................................................................................3-2  3.1.4  Demand Forecast..................................................................................................3-2  3.2  Data Required for OptGen ........................................................................................ 3-3  3.3  References................................................................................................................ 3-3  4  NATIONAL EXPANSION PLANS ............................................................................ 4-1  4.1  Tanzania ................................................................................................................... 4-1  4.1.1  Existing national expansion plan ...........................................................................4-1  4.1.2  Modified national expansion plan ..........................................................................4-2  4.1.3  Existing Vs. Modified national expansion plan ......................................................4-3  4.1.4  Investment net present value ................................................................................4-5  4.1.5  Interconnections and energy generation ...............................................................4-5  4.2  Kenya........................................................................................................................ 4-7  4.2.1  Existing national expansion plan ...........................................................................4-7  4.2.2  Modified national expansion plan ..........................................................................4-8  4.2.3  Existing Vs. Modified national expansion plan ......................................................4-9  4.2.4  Investment net present value ..............................................................................4-11  4.2.5  Interconnections and energy generation .............................................................4-11  4.3  Uganda.................................................................................................................... 4-12  4.3.1  Existing national expansion plan .........................................................................4-12  4.3.2  Modified national expansion plan ........................................................................4-13  4.3.3  Existing Vs. Modified national expansion plan ....................................................4-15  4.3.4  Investment net present value ..............................................................................4-16  4.3.5  Interconnections and energy generation .............................................................4-16  4.4  Ethiopia ................................................................................................................... 4-18  4.4.1  Existing national expansion plan .........................................................................4-18  4.4.2  Modified national expansion plan ........................................................................4-19  4.4.3  Existing Vs. Modified national expansion plan ....................................................4-20  4.4.4  Investment net present value ..............................................................................4-22  4.4.5  Interconnections and energy generation .............................................................4-22  4.5  Sudan...................................................................................................................... 4-23  4.5.1  Existing national expansion plan .........................................................................4-23 
  • 162. Final Master Plan Report ii WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.5.2  Modified national expansion plan ........................................................................4-25  4.5.3  Existing Vs. Modified national expansion plan ....................................................4-26  4.5.4  Investment net present value ..............................................................................4-28  4.5.5  Interconnections and energy generation .............................................................4-28  4.6  Egypt....................................................................................................................... 4-29  4.6.1  Existing national expansion plan .........................................................................4-29  4.6.2  Modified national expansion plan ........................................................................4-31  4.6.3  Existing Vs. Modified national expansion plan ....................................................4-32  4.6.4  Investment net present value ..............................................................................4-34  4.6.5  Interconnections and energy generation .............................................................4-34  4.7  Burundi, Eastern DRC and Rwanda ....................................................................... 4-36  4.7.1  Regional coordination..........................................................................................4-36  4.7.2  Shared Projects...................................................................................................4-36  4.7.3  New national expansion plans.............................................................................4-37  4.7.4  Investment Net Present Value.............................................................................4-41  4.7.5  Interconnections and energy generation .............................................................4-41  4.8  Djibouti .................................................................................................................... 4-46  4.8.1  Existing national expansion plan .........................................................................4-46  4.8.2  Additional 3-year Period ......................................................................................4-47  4.8.3  Investment net present value ..............................................................................4-48  4.8.4  Interconnections and energy generation .............................................................4-48  5  REGIONAL SUPPLY-DEMAND ANALYSIS............................................................ 5-1  5.1  Introduction ............................................................................................................... 5-1  5.2  Proposed Interconnections projects.......................................................................... 5-2  5.3  National Generation Plans and Regional Interconnection Plans (NGP_RIP) ........... 5-4  5.4  Regional Generation and Interconnection Plans (RGP_RIP) ................................... 5-9  5.5  Sensitivity analysis.................................................................................................. 5-12  5.5.1  National Generation Plans...................................................................................5-12  5.5.2  Regional Generation Plans..................................................................................5-13  5.6  Benefit-Cost analysis .............................................................................................. 5-14  6  IDENTIFIED PROJECTS FOR FURTHER ANALYSIS IN PHASE II....................... 6-1  6.1  Generation projects................................................................................................... 6-1  6.2  Interconnection Projects............................................................................................ 6-2 
  • 163. Final Master Plan Report iii WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study LIST OF TABLES Table 1-1  OPTGEN typical inputs/outputs...................................................................... 1-3  Table 1-2  SDDP typical inputs/outputs........................................................................... 1-3  Table 1-3  Annual Average Potential Surplus by Country ............................................... 1-6  Table 2-1  Demand Forecast Scenarios Selected........................................................... 2-1  Table 2-2  Demand Forecast Chosen Scenarios - Peak Demand and Generated Energy .. ....................................................................................................................... 2-2  Table 4-1  Tanzania Existing Vs. Modified National Expansion Plan .............................. 4-4  Table 4-2  Kenya Existing Vs. Modified National Expansion Plan................................... 4-9  Table 4-3  Uganda Existing Vs. Modified National Expansion Plan .............................. 4-15  Table 4-4  Ethiopia Existing Vs. Modified National Expansion Plan.............................. 4-21  Table 4-5  Sudan Existing Vs. Modified National Expansion Plan ................................ 4-27  Table 4-6  Egypt Existing Vs. Modified National Expansion Plan.................................. 4-32  Table 4-7  Burundi New National Expansion Plan......................................................... 4-40  Table 4-8  Eastern DRC New National Expansion Plan................................................ 4-40  Table 4-9  Rwanda New National Expansion Plan........................................................ 4-41  Table 4-10  2013 Investment NPV for Burundi, Eastern DRC and Rwanda ................... 4-41  Table 4-11  Djibouti Existing National Expansion Plan.................................................... 4-47  Table 5-1  Definition and description of the scenarios analyzed ..................................... 5-2  Table 5-2  Interconnection Projects................................................................................. 5-3  Table 5-3  Generation capacity displaced or advanced Case RGP_RIP ........................ 5-9  Table 5-4  Schedule of the interconnection projects selected Cases RGP_RIP and NGP_RIP...................................................................................................... 5-12  Table 5-5  Schedule of the interconnection projects selected Cases NGP_RIP (Base, S1, S2)................................................................................................................ 5-13  Table 5-6  Schedule of the interconnection projects selected Cases RGP_RIP (Base, S1, S2)................................................................................................................ 5-14  Table 5-7  Benefit-Cost Analysis Present Values in MUS$ ........................................... 5-15  Table 6-1  Identified Generation Projects for Phase II..................................................... 6-1  Table 6-2  Identified Interconnection Projects for Phase II.............................................. 6-2 
  • 164. Final Master Plan Report iv WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study LIST OF FIGURES Figure 1-1  OPTGEN investment and operation coordination 1-2  Figure 1-2  Methodology for developing regional plans 1-5  Figure 2-1  Peak Demand Forecasts - Burundi, Djibouti, Eastern DRC and Rwanda 2-5  Figure 2-2  Peak Demand Forecasts - Ethiopia, Kenya, Sudan, Tanzania and Uganda 2-5  Figure 2-3  Peak Demand Forecasts - Egypt 2-6  Figure 4-1  Tanzania Existing National Expansion Plan by Plant Category 4-2  Figure 4-2  Tanzania Modified National Expansion Plan by Plant Category 4-3  Figure 4-3  Tanzania Generation by Fuel Category - Modified National Expansion Plan 4-6  Figure 4-4  Kenya Existing National Expansion Plan by Plant Category 4-7  Figure 4-5  Kenya Modified National Expansion Plan by Plant Category 4-8  Figure 4-6  Kenya Generation by Fuel Category - Modified National Expansion Plan 4-12  Figure 4-7  Uganda Existing National Expansion Plan by Plant Category 4-13  Figure 4-8  Uganda Modified National Expansion Plan by Plant Category 4-14  Figure 4-9  Uganda Generation by Fuel Category - Modified National Expansion Plan 4-17  Figure 4-10  Ethiopia Existing National Expansion Plan by Plant Category 4-18  Figure 4-11  Ethiopia Modified National Expansion Plan by Plant Category 4-20  Figure 4-12  Ethiopia Generation by Fuel Category - Modified National Expansion Plan 4-23  Figure 4-13  Sudan Existing National Expansion Plan by Plant Category 4-24  Figure 4-14  Sudan Modified National Expansion Plan by Plant Category 4-26  Figure 4-15  Sudan Generation by Fuel Category - Modified National Expansion Plan4-29  Figure 4-16  Egypt Existing National Expansion Plan by Plant Category 4-30  Figure 4-17  Egypt Modified National Expansion Plan by Plant Category 4-31  Figure 4-18  Egypt Generation by Fuel Category - Modified National Expansion Plan 4-35  Figure 4-19  Burundi New National Expansion Plan by Plant Category 4-37  Figure 4-20  Eastern DRC New National Expansion Plan by Plant Category 4-38  Figure 4-21  Rwanda New National Expansion Plan by Plant Category 4-39  Figure 4-22  Interconnections in the Burundi. Eastern DRC, Rwanda Region 4-42  Figure 4-23  Burundi Generation by Fuel Category - New National Expansion Plan 4-43  Figure 4-24  Eastern DRC Generation by Fuel Category - New National Expansion Plan 4-44  Figure 4-25  Rwanda Generation by Fuel Category - New National Expansion Plan 4-45  Figure 4-26  Djibouti Existing National Expansion Plan 4-46  Figure 4-27  Djibouti Existing National Expansion Plan with Extended Study Horizon 4-48  Figure 4-28  Djibouti Generation by Fuel Category – Existing National Expansion Plan 4-49  Figure 5-1  EAPP Interconnections Case NGP_RIP 5-5  Figure 5-2  Variation of some energy sources Case NGP_EIC vs Case NGP_RIP 5-6  Figure 5-3  Balance and net flow between countries Case NGP_RIP 5-8  Figure 5-4  EAPP Interconnections Case RGP_RIP 5-10  Figure 5-5  Balance and net flow between countries Case RGP_RIP 5-11  Figure 5-6  Benefit-Cost Analysis 5-15 
  • 165. Final Master Plan Report 1-1 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 1 OBJECTIVE AND SCOPE This part of the study deals with the identification of interconnection and generation projects with regional scope, which potentially could bring regional benefits. Generation developments in each country, especially where large hydro projects are being planned, represent opportunities for exports in the initial years until the surplus is taken up by the local demand. When examined in a regional basis, exchange opportunities arise that can be leveraged by new interconnections. Also the re-scheduling of large regional hydro projects in one region can bring additional benefits by displacing expensive thermal-based generation in another region. The specific objectives of this part of the study are: • Set-up a regional database of existing, committed and candidate generation and interconnection projects for the development of the regional plans for the EAPP/EAC. • Set-up the models for advanced generation planning simulation and planning tools: SDDP & OPTGEN (see below) • To develop a supply-demand balance for each country based on the national expansion plans. • To identify significant potential surpluses of indigenous generation as an indicator of potential interconnection opportunities. • Develop regional master plans with different degrees of planning and operational coordination among the pool members. 1.1 Inputs Several Inputs are required for this part of the study, originating in other modules: • Selected demand projections from Module 1A-1100 • Existing and committed plant technical characteristics from Module 1C-1200: capacity, efficiency (heat rate for TPP and production coefficients and reservoir characteristics for HPP), fuel costs, O&M costs, outage rates. • Future plant technical characteristics from Module 1C-1200: Capacity, efficiency (heat rate for TPP and production coefficients and reservoir characteristics for HPP), fuel costs, O&M costs, outage rates and capital costs and construction schedule. • Existing interconnections characteristics (transfer capacity in MW) from Module 1D- 1500. • Future interconnections characteristics (transfer capacity in MW) and capital costs capital costs and construction schedule from Module 1D-1500. • Hydrological database for a common period for each existing and future HPP from Module 1C-1200 1.2 Tools In order to optimize the expansion of the interconnections and generation in the region and the short-term operation, it is absolutely necessary to take into account the interaction of each system with the rest. For this, computerized tools that are capable of modeling multiple systems are needed. The problem to be solved is to decide on the investments needed in generation and interconnections and the corresponding dispatch of these resources, so that the least cost at a regional level is attained. Moreover, due to the large proportion of hydro
  • 166. Final Master Plan Report 1-2 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study energy, a dispatching algorithm representing individually the main reservoirs and run-of-river plants in the region is required that considers the stochastic nature of the inflows and their geographical and time (season, monthly) interdependencies. For the optimization of the expansion of interconnections and generation and corresponding dispatching of resources the OPTGEN and SDDP tools have been chosen. SNC-Lavalin has a vast experience with the use of these tools in developing regional master plans as well as national master plans. A brief description of the OPTGEN and SDDP follows. (More details about the models can be viewed on the publishing company’s website: PSR http://www.psr-inc.com.br). 1.2.1 OPTGEN OPTGEN is a computational tool for determining the least-cost expansion (generation and interconnections) of a multi-regional hydrothermal system, with a detailed representation of system operation. It takes into account constraints such as: 1. Investment decisions: earliest and latest dates, mandatory projects, mutually exclusive projects, minimum total installed capacity per year 2. Inflow uncertainties 3. Emission constraints Generation and interconnection capacity expansion planning is a complex problem of decision-making under uncertainty. OPTGEN integrates the investment decision and operational analysis as shown in the Figure 1-1 below Figure 1-1 OPTGEN investment and operation coordination Typical inputs and outputs for OPTGEN are shown in the Table 1-1 below investment decision operational analysis candidate plan operation cost investment cost optimality check feedback SDDP OPTGEN
  • 167. Final Master Plan Report 1-3 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 1-1 OPTGEN typical inputs/outputs Inputs Outputs • Existing system data • Candidate plants / interconnectors costs and technical characteristics • Retirement (existing plants) • Demand projection • Fuel cost projection • Obligatory and optional projects • Minimum installed capacity constraints • Environmental constraints • Generation and interconnections least cost expansion plan • Benefits of coordinated vs. isolated expansion/operation • All other outputs form SDDP (see below) 1.2.2 SDDP SDDP (Stochastic Dual Dynamic Programming) is a probabilistic multi-area hydro-thermal production costing model. It permits to optimize multiple reservoirs simultaneously. SDDP allows the optimal coordination of hydro and thermal resources. Key modeling capabilities include: • Reservoir operation and optimization (turbining, spillage, irrigation, filtration, etc.) along complex cascades • Inflow uncertainty through stochastic inflow models which represent both spatial and time dependence • Thermal plant operation (efficiency curves, fuel limits, multiple fuels, etc.) Typical inputs and outputs for SDDP are shown in the Table 1-2 below Table 1-2 SDDP typical inputs/outputs Inputs Outputs • Plant technical characteristics. • Interconnector capacities • Demand shape’s projections • Fuel cost projection • Reservoir constraints • Minimum generation constraints • Fuel consumption constraints • Generation by plant and by load block • Marginal costs (demand, interconnection capacity, plant capacity, reservoir storage, etc) • Opportunity cost of water in each hydro plant • Locational Marginal Prices • Inter-system flows 1.3 Methodology The first step consists of adjusting the available national master plans with OPTGEN. In the case were a recent plan was not available (Burundi, Rwanda, Eastern DRC), a new plan was developed. Then the national surpluses are evaluated with SDDP. All these national plans are developed using a common criteria:
  • 168. Final Master Plan Report 1-4 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study • Revised demand forecast (see section 2). • Common generation reliability criteria (see Module 1C-1200) • Supply covers only national demand. • Update of the status of projects that were assumed to be under construction, or that were supposed to be in operation by 2013. The next step is to consider a coordinated regional operation (through a regional power exchange or regional pool dispatch) in order to maximize profitable power exchanges among the members of the pool and reduce as much as possible unserved energy. To this end, the existing interconnections plus future interconnection projects are considered. The new projects are identified based on the least cost regional development. Those projects that have been recently under study (i.e. Egypt-Sudan 500kV HVDC; Sudan-Ethiopia 500kV; Ethiopia-Kenya 500kV HVDC; Kenya-Tanzania 400kV; Tanzania-Uganda 220-kV and the Rusumo system) are analyzed to confirm their inclusion in the least cost regional plan. In addition, other new interconnection options are analyzed. The least cost master plan thus obtained balances the additional investments in interconnections with the saving due to fuel-displacement and operation cost savings via the regional exchanges. An increased level of regional coordination would involve the consideration of generation plans. This next level represents a maximum level of cooperation in the development of both interconnection projects and large generation projects with regional scope. In this scenario the national generation master plans are re-optimized to exploit potential savings due to the advance of a cheap generation option in one country (e.g., Ethiopia hydro) to delay installation of more expensive options (e.g. steam plants) in other countries (e.g., Sudan ) Finally an analysis of the main factors of perceived risk is undertaken. One source of risk is the potential impact that a decision of a large importer can have in the regional exchanges. We consider in this case the impact on the regional plan of Egypt deciding to limit the imports only to the capacity of the (already planned) 500kv HVDC interconnection (2000MW). Another risk is the potential increase on the capital cost of interconnections, which is a distinct possibility if recent trends are considered (the cost of building material for transmission lines, associated equipments and substation showed a peak recently in 2008, and is now in 2010 almost at half the level then). The Figure 1-2 below summarizes the methodology used for this part of the study
  • 169. Final Master Plan Report 1-5 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 1-2 Methodology for developing regional plans Adjustment of National  Plans •Revise (if necessary) with OPTGEN existing national generation master plans •Based on: •Revised demand forecast •Common generation reliability criteria •Update of status of commited projects •Self‐sufficiency (building only for local demand) •Evaluation of national surpluses (SDDP) Regional Planning of  interconnections •First level of regional coordination •New interconnections are built to maximize profitable exchanges of surpluses of  national plans •National Generation master plans are not modified •Analysis of net economic benefits Regional Planning  Interconnections and  large Generation projects •Second level of regional coordination •New interconnections are built to maximize profitable exchanges of surpluses of  national plans •National Generation master plans are coordinated so that advancing or delaying  a large generation project may provide additional regional benefits •Analysis of net economic benefits Risk analysis •Variables/Policies that could have significant impact on the regional plan •Limited participation of large importers (eg. Egypt) in regional exchanges •Increase of investment cost of interconnections projects (double the base cost) •Analysis of impacts on net economic benefits
  • 170. Final Master Plan Report 1-6 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 1.4 Main Results • A national generation master plan has been updated for each of the ten countries in the region and this is presented in section 4. These revised plans are all based on consistent demand forecasts developed as part of this study (see Module 1A-1100). The plans also are subject to a set of common reliability criteria (see Module 1C-1200) and were adjusted so that the supply is developed to meet only the local needs. The status of projects under construction has been also updated according to the findings of the Inception Mission (see Inception Report). These revisions of the national generation master plans allow making a meaningful comparison of the benefits of the regional plans. • National generation plans present some exploitable surplus due to the fact that the projects are of large size as compared to the local demand. This analysis is detailed in section 5.1. The following Table 1-3 shows the annual average potential surplus by country taken over the entire study period. The countries with greatest exportable surplus in relation to their local demand are Ethiopia, Uganda and Tanzania; followed by the region formed by (Burundi, Eastern DRC, Rwanda), then Sudan and then Kenya. Table 1-3 Annual Average Potential Surplus by Country Country Load (GWh) Surplus (GWh) Surplus/Load Ethiopia 28,386 12,557 44% Uganda 7,768 2,636 34% Tanzania 18,455 5,059 27% Rwanda, Burundi, East DRC 3,369 840 25% Sudan 46,707 7,824 17% Kenya 39,975 6,003 15% • As discussed in sections 5.3 and 5.6, the first level of regional coordination, through the coordinated operation of the pool using the existing and a selected group of new regionally planned interconnections, bring a significant benefit to the region (25,188 MUSD) when compared to the national plans for the study horizon (2013-38). This represents an annual benefit of 969 MUSD with an annual equivalent investment of only 172 MUSD. In this scenario, all the interconnection projects that are currently being studied were selected in their corresponding earliest date: in 2015 the Tanzania-Uganda and the Tanzania-Kenya are needed, and in 2016, the Egypt-Sudan, the Ethiopia-Sudan and the Ethiopia-Kenya were selected. These interconnections are also selected as part of the least cost plan under the two sensitivities performed for this scenario and are therefore recommended for fast-track implementation. • The second level of regional coordination (see sections 5.4 and 5.6) corresponds to an integrated interconnection and generation regional plan. This is the theoretical optimum that can be achieved. When compared to the national plans the regional net benefit amounts to 32,451 MUSD equivalents to 1,248 MUSD per year. 7,143MW of new generation capacity are saved in this scenario. • The risk to a limitation of the import capacity of the Egyptian system (to a maximum of 2000MW) represents an impact of a reduction of 7,687 MUSD in regional net benefit
  • 171. Final Master Plan Report 1-7 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study (296 MUSD/year) when compared to the second level of regional coordination and 6,852 MUSD (263 MUS/year) when compared to the first level of coordination. • The risk to an increase in capital cost of interconnection and associated equipment/substations represent an impact of a reduction of 4,427 MUSD in regional net benefit (170 MUSD/year) when compared to the second level of regional coordination and 4,332 MUSD (167 MUSD/year) when compared to the first level of regional coordination.
  • 172. Final Master Plan Report 2-1 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 2 DEMAND FORECAST The demand forecasts for all countries, for the entire study horizon, are presented in-depth in Module 1A-1100. For each country, several scenarios were created based on different criteria. In this chapter, the scenarios selected for the SDDP simulations are highlighted. This chapter also presents the manipulation done to these forecasts to render their format acceptable by the model. 2.1 Demand Scenarios 2.1.1 Selecting the adequate scenario In Module 1A-1100, two sets of forecasts were proposed for each country, the national plan forecast and the PB forecast, each having a base, low and high case. Hence 6 scenarios were available to choose from for the supply-demand analysis in this module. The most adequate scenario was chosen. Table 2-1 summarizes the forecast scenarios chosen, referring to the names used in Module 1A-1100: Table 2-1 Demand Forecast Scenarios Selected Country Forecast Scenario Selected Burundi Extended NELSAP Demand Forecast – Base Case Djibouti LCEMP Demand Forecast – Base Case Eastern DRC Extended NELSAP Demand Forecast – Base Case Egypt Extended EEHC Demand Forecast – Base Case Ethiopia Extended EEPCo Demand Forecast – Moderate I – Base Case Kenya Extended 2008 LCPDP Demand Forecast – Base Case Rwanda Extended NELSAP Demand Forecast – Base Case Sudan PB Demand Forecast – Base Case Tanzania Extended PSMP Demand Forecast – Base Case Uganda PSIP Demand Forecast – Base Case The forecasts listed above in Table 2-1 are in majority taken from the most recent available national master plan. This study starts on a national level, preparing new national plans that meet this study’s reliability criteria for each country and then compare them to the regional plan to assess the benefits of a regional expansion plan. However, these plans needed to be compared to the existing national expansion plans to highlight differences hence using the same forecast was more reasonable. This was the case for Djibouti, Egypt, Ethiopia, Kenya, Tanzania and Uganda. For Burundi, Rwanda and Eastern DRC, with no national plan available, the NELSAP report was considered. Finally in the case of Sudan, the national plan’s forecast starts in 2006 and demand for the years 2006-2009 did not match the forecast. Hence the PB forecast, which takes as a starting point the 2009 demand, was considered. The full analysis and data behind these forecasts can be found in the report of Module 1A- 1100 and its appendices.
  • 173. Final Master Plan Report 2-2 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 2.1.2 Summary of forecast results In this report, a brief summary of the forecasts for each country are presented in the form of: • Tables with the values for the peak demand, sent out generation and growth rates; • Graphs showing the evolution of the peak demand. Table 2-2 Demand Forecast Chosen Scenarios - Peak Demand and Generated Energy Year  Burundi  Djibouti  Energy   (Gwh)  Annual   Growth  Demand   (MW)  Annual  Growth  Energy  (Gwh)  Annual  Growth  Demand   (MW)  Annual  Growth  2009          379 68  2010  134    43  421 10.9% 74  9.5% 2011  135  0.7% 44  1.6% 476 13.1% 84  12.5% 2012  143  5.9% 47  6.3% 573 20.4% 100  18.9% 2013  170  18.9%  56  19.8% 663 15.7% 116  16.7% 2014  200  17.6%  66  17.8% 727 9.7% 128  10.3% 2015  231  15.5%  77  16.5% 775 6.7% 138  7.3% 2016  265  14.7%  89  15.4% 833 7.4% 149  8.0% 2017  301  13.6%  102  14.4% 859 3.2% 153  3.2% 2018  339  12.6%  116  13.6% 886 3.1% 158  3.1% 2019  381  12.4%  131  13.1% 907 2.3% 162  2.3% 2020  425  11.5%  147  12.4% 928 2.3% 165  2.2% 2021  472  11.1%  165  12.0% 944 1.7% 168  1.6% 2022  522  10.6%  184  11.6% 961 1.8% 171  1.6% 2023  576  10.3%  204  11.3% 978 1.8% 173  1.7% 2024  633  9.9% 227  10.9% 996 1.8% 176  1.7% 2025  695  9.8% 251  10.7% 1016 2.1% 180  2.0% 2026  760  9.3% 274  9.3% 1036 2.0% 183  2.0% 2027  827  8.9% 300  9.4% 1057 2.0% 187  2.0% 2028  898  8.5% 327  9.0% 1078 2.0% 191  2.0% 2029  972  8.2% 355  8.7% 1100 2.0% 195  2.0% 2030  1049  7.9% 385  8.3% 1122 2.0% 198  2.0% 2031  1129  7.7% 415  8.0% 1144 1.9% 202  1.9% 2032  1213  7.4% 448  7.7% 1166 1.9% 206  1.9% 2033  1299  7.2% 481  7.5% 1189 2.0% 210  1.9% 2034  1389  6.9% 516  7.2% 1212 2.0% 214  2.0% 2035  1482  6.7% 552  7.0% 1236 2.0% 218  2.0% 2036  1579  6.5% 589  6.8% 1260 1.9% 224  2.3% 2037  1679  6.3% 628  6.6% 1284 1.9% 228  1.9% 2038  1781  6.1% 667  6.4% 1308 1.9% 232  1.9%
  • 174. Final Master Plan Report 2-3 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Year  Eastern DRC  Egypt  Energy   (Gwh)  Annual   Growth  Demand   (MW)  Annual  Growth  Energy  (Gwh)  Annual  Growth  Demand   (MW)  Annual  Growth  2009  251    59  137056 22330  2010  262  4.5% 62  4.4% 145756 6.3% 23729  6.3% 2011  275  5.0% 65  5.0% 154910 6.3% 25200  6.2% 2012  289  5.0% 68  5.0% 164532 6.2% 26753  6.2% 2013  303  5.0% 72  5.0% 174638 6.1% 28383  6.1% 2014  318  5.0% 75  5.0% 185231 6.1% 30089  6.0% 2015  334  5.0% 79  5.0% 196334 6.0% 31880  6.0% 2016  352  5.5% 83  5.4% 207993 5.9% 33760  5.9% 2017  372  5.5% 88  5.4% 220214 5.9% 35651  5.6% 2018  392  5.5% 93  5.4% 233024 5.8% 37630  5.6% 2019  413  5.5% 98  5.4% 246470 5.8% 39703  5.5% 2020  436  5.5% 103  5.4% 260589 5.7% 41874  5.5% 2021  461  5.7% 109  5.6% 275416 5.7% 44149  5.4% 2022  487  5.7% 115  5.6% 290992 5.7% 46534  5.4% 2023  515  5.7% 121  5.7% 307358 5.6% 49034  5.4% 2024  545  5.8% 128  5.7% 324553 5.6% 51654  5.3% 2025  576  5.8% 136  5.7% 342626 5.6% 54402  5.3% 2026  610  5.8% 143  5.7% 361623 5.5% 57284  5.3% 2027  645  5.8% 152  5.7% 381288 5.4% 60213  5.1% 2028  682  5.8% 160  5.7% 401991 5.4% 63311  5.1% 2029  722  5.8% 169  5.7% 423651 5.4% 66541  5.1% 2030  764  5.8% 179  5.7% 446301 5.3% 69909  5.1% 2031  808  5.8% 189  5.7% 469972 5.3% 73417  5.0% 2032  855  5.8% 200  5.6% 494693 5.3% 77071  5.0% 2033  904  5.7% 211  5.6% 520498 5.2% 80874  4.9% 2034  955  5.7% 223  5.6% 547416 5.2% 84832  4.9% 2035  1009  5.7% 235  5.5% 575478 5.1% 88947  4.9% 2036  1066  5.6% 248  5.5% 604717 5.1% 93224  4.8% 2037  1125  5.6% 262  5.5% 635162 5.0% 97668  4.8% 2038  1187  5.5% 276  5.4% 666846 5.0% 102282  4.7% Year  Ethiopia  Kenya  2009  4828  1201  8140 1313  2010  5620  16.4%  1398  16.4% 8954 10.0% 1445  10.0% 2011  6325  12.5%  1573  12.5% 9847 10.0% 1589  10.0% 2012  7083  12.0%  1762  12.0% 10830 10.0% 1747  10.0% 2013  7897  11.5%  1964  11.5% 12134 12.0% 1958  12.0% 2014  8816  11.6%  2193  11.6% 13739 13.2% 2193  12.0% 2015  9823  11.4%  2443  11.4% 15390 12.0% 2456  12.0% 2016  10917  11.1%  2715  11.1% 16743 8.8% 2672  8.8% 2017  12038  10.3%  2994  10.3% 17988 7.4% 2871  7.4% 2018  13182  9.5% 3279  9.5% 19327 7.4% 3085  7.4% 2019  14374  9.0% 3575  9.0% 20765 7.4% 3314  7.4% 2020  15610  8.6% 3883  8.6% 22310 7.4% 3561  7.4% 2021  16888  8.2% 4201  8.2% 24187 8.4% 3860  8.4% 2022  18265  8.2% 4543  8.2% 26222 8.4% 4185  8.4% 2023  19750  8.1% 4912  8.1% 28428 8.4% 4537  8.4% 2024  21351  8.1% 5311  8.1% 30723 8.1% 4919  8.4% 2025  23079  8.1% 5741  8.1% 33307 8.4% 5333  8.4% 2026  24944  8.1% 6204  8.1% 35936 7.9% 5753  7.9% 2027  26958  8.1% 6705  8.1% 38786 7.9% 6210  7.9% 2028  29134  8.1% 7247  8.1% 41831 7.9% 6697  7.9% 2029  31486  8.1% 7832  8.1% 45217 8.1% 7227  7.9% 2030  34030  8.1% 8464  8.1% 48775 7.9% 7795  7.9% 2031  36787  8.1% 9150  8.1% 52412 7.5% 8393  7.7% 2032  39766  8.1% 9891  8.1% 56402 7.6% 9037  7.7% 2033  42987  8.1% 10692  8.1% 60651 7.5% 9723  7.6% 2034  46469  8.1% 11558  8.1% 65170 7.4% 10453  7.5% 2035  50233  8.1% 12495  8.1% 69968 7.4% 11229  7.4% 2036  54302  8.1% 13507  8.1% 75058 7.3% 12053  7.3% 2037  58701  8.1% 14601  8.1% 80450 7.2% 12927  7.2% 2038  63455  8.1% 15783  8.1% 86154 7.1% 13852  7.2%
  • 175. Final Master Plan Report 2-4 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Year  Rwanda  Sudan  Energy   (Gwh)  Annual   Growth  Demand  (MW)  Annual  Growth  Energy  (Gwh)  Annual  Growth  Demand   (MW)  Annual  Growth  2009  305  59  6118 1151  2010  330  8.1% 63  7.5% 7211 17.9% 1357  17.9% 2011  386  17.0%  73  16.5% 8264 14.6% 1555  14.6% 2012  442  14.6%  84  14.2% 9436 14.2% 1775  14.2% 2013  499  12.7%  94  12.4% 10733 13.7% 2019  13.7% 2014  555  11.3%  105  11.0% 12161 13.3% 2288  13.3% 2015  611  10.1%  115  9.9% 13723 12.8% 2582  12.8% 2016  697  14.1%  132  14.6% 15426 12.4% 2902  12.4% 2017  784  12.4%  149  12.7% 17273 12.0% 3250  12.0% 2018  870  11.0%  165  11.3% 19270 11.6% 3626  11.6% 2019  957  9.9% 182  10.2% 21421 11.2% 4030  11.2% 2020  1043  9.0% 199  9.2% 23731 10.8% 4465  10.8% 2021  1162  11.4%  225  13.0% 26204 10.4% 4930  10.4% 2022  1281  10.2%  251  11.5% 28845 10.1% 5427  10.1% 2023  1399  9.3% 276  10.3% 31657 9.7% 5956  9.7% 2024  1518  8.5% 302  9.3% 34844 10.1% 6556  10.1% 2025  1637  7.8% 328  8.5% 38248 9.8% 7196  9.8% 2026  1780  8.8% 356  8.5% 41874 9.5% 7878  9.5% 2027  1922  8.0% 386  8.4% 45731 9.2% 8604  9.2% 2028  2071  7.7% 417  8.1% 49825 9.0% 9374  9.0% 2029  2225  7.5% 450  7.8% 54164 8.7% 10190  8.7% 2030  2385  7.2% 484  7.6% 58754 8.5% 11054  8.5% 2031  2552  7.0% 519  7.3% 63603 8.3% 11966  8.3% 2032  2725  6.8% 556  7.1% 68718 8.0% 12929  8.0% 2033  2904  6.6% 594  6.9% 74105 7.8% 13942  7.8% 2034  3089  6.4% 634  6.7% 79773 7.6% 15009  7.6% 2035  3280  6.2% 675  6.5% 85727 7.5% 16129  7.5% 2036  3477  6.0% 717  6.3% 91976 7.3% 17304  7.3% 2037  3680  5.9% 761  6.1% 98525 7.1% 18537  7.1% 2038  3890  5.7% 806  5.9% 105383 7.0% 19827  7.0% Year  Tanzania  Uganda  2009        2877 561  2010  5293  895  3026 5.2% 596  6.2% 2011  5773  9.1% 981  9.6% 3188 5.4% 633  6.2% 2012  6439  11.5%  1103  12.4% 3371 5.7% 673  6.5% 2013  7081  10.0%  1213  10.0% 3560 5.6% 715  6.2% 2014  7489  5.8% 1285  6.0% 3788 6.4% 764  6.9% 2015  8135  8.6% 1398  8.7% 4030 6.4% 816  6.8% 2016  8987  10.5%  1542  10.3% 4288 6.4% 871  6.7% 2017  9895  10.1%  1698  10.1% 4561 6.4% 929  6.6% 2018  10704  8.2% 1839  8.3% 4851 6.4% 990  6.6% 2019  11326  5.8% 1945  5.8% 5123 5.6% 1045  5.5% 2020  11994  5.9% 2061  5.9% 5362 4.7% 1091  4.4% 2021  12701  5.9% 2182  5.9% 5685 6.0% 1158  6.1% 2022  13440  5.8% 2311  5.9% 6056 6.5% 1233  6.5% 2023  14398  7.1% 2479  7.3% 6434 6.3% 1310  6.3% 2024  15245  5.9% 2628  6.0% 6821 6.0% 1389  6.0% 2025  16145  5.9% 2783  5.9% 7216 5.8% 1470  5.8% 2026  17112  6.0% 2953  6.1% 7620 5.6% 1552  5.6% 2027  18116  5.9% 3131  6.0% 8031 5.4% 1636  5.4% 2028  19379  7.0% 3353  7.1% 8450 5.2% 1722  5.2% 2029  20536  6.0% 3558  6.1% 8878 5.1% 1809  5.1% 2030  21745  5.9% 3770  6.0% 9313 4.9% 1898  4.9% 2031  23042  6.0% 4002  6.1% 9754 4.7% 1978  4.2% 2032  24449  6.1% 4254  6.3% 10203 4.6% 2069  4.6% 2033  26164  7.0% 4532  6.6% 10659 4.5% 2162  4.5% 2034  27917  6.7% 4838  6.7% 11123 4.4% 2257  4.4% 2035  29854  6.9% 5168  6.8% 11594 4.2% 2353  4.3% 2036  31978  7.1% 5527  6.9% 12073 4.1% 2450  4.1% 2037  34311  7.3% 5918  7.1% 12559 4.0% 2549  4.0% 2038  36873  7.5% 6344  7.2% 13025 3.7% 2650  3.9%
  • 176. Final Master Plan Report 2-5 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study The peak demand data in Table 2-2 is plotted next in graphs to visualize the trend. Countries with close levels of demand were grouped together in one graph. Figure 2-1 Peak Demand Forecasts - Burundi, Djibouti, Eastern DRC and Rwanda Figure 2-2 Peak Demand Forecasts - Ethiopia, Kenya, Sudan, Tanzania and Uganda 0 100 200 300 400 500 600 700 800 900 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 MW Burundi Djibouti Eastern DRC Rwanda 0 5000 10000 15000 20000 25000 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 MW Ethiopia  Kenya Sudan Tanzania Uganda
  • 177. Final Master Plan Report 2-6 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 2-3 Peak Demand Forecasts - Egypt 2.2 Demand Forecast in SDDP Format The forecasts presented above are given in a yearly format. In the model’s database however, the forecast for each country has to be entered in a different format. The simulation runs in predefined stages and the model has to be provided with the peak load for every stage. For this study, the stage is one month hence the demand has to be on a monthly basis. More so, for every stage (month) the demand has to be split into three load blocks: The peak period, the middle period and the base period. Therefore, for every system, one year’s energy and peak demand forecasts are manipulated to generate 36 load values (3 blocks x 12 months). Using the hourly load historical data, a continuous load duration curve (LDC) for every month is drawn. Then it is rendered into a discrete curve of three blocks, with the following conventions: • The peak block accounts for 10% of the month’s time (e.g. January: 10% x 24 hrs x 31 days = 74.4 hrs) and the load level is the peak demand in the month’s continuous LDC. (The energy in this block can therefore be calculated by a straight calculation) • The middle block accounts for 50% of the time and has 60% of the total energy of the continuous LDC. The load level is then calculated through dividing the energy by the time. • The base block accounts for 40% of the time and has the remaining energy in the LDC, from which the load level can be calculated in a similar way. Finally, these LDCs are scaled for every year of the forecast through multiplying the load values by a factor equal to the rate of increase of the forecast from the year the LDC was drawn to the forecast year. The 36 values for each of the 26 years (936 values) are then entered into the model’s database. An in depth explanation and example on this manipulation is provided in Appendix A. 0 20000 40000 60000 80000 100000 120000 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Egypt
  • 178. Final Master Plan Report 3-1 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 3 STUDY DATABASE For the present study, the power systems of the ten countries were simulated on the models SDDP and OPTGEN. In order to get as close as possible to the real systems and have the simulations mirror their daily operations, it was essential to gather all the data available on the technical specs of every power plant, be it thermal, hydro, wind or solar. The numbers would then be entered into the database, along with the demand forecast for the entire study horizon, and used by the models to generate the desired results. Having the right characteristics for the plants adds a degree of credibility to the expansion plans generated by the model. Even though both models work cooperatively, each has its own list of required data. Scanning through the references listed in Table 2-2 of Module 1C-1200, the database for both models was completed and each country’s power system was adequately simulated. In this chapter, the various data required by both models are presented briefly. The full set of data is provided in Appendix B in the form of two tables per country: one for the hydro plants and one for the remaining plants. 3.1 Data required by SDDP 3.1.1 Thermal, Wind and Solar Plants For the simulation of thermal plants, SDDP mainly requires the following data: • Plant name, fuel type, and status (Existing/Future); • Installed potential (MW), minimum and maximum generation (MW), number of units; • Composite outage rate (COR) (%), variable operation & maintenance (O&M) cost ($/MWh), heat rate (GJ/MWh). Fuels are separately defined in the model for each system, with the forecasted prices compliant with Section 6.4 in Module 1C-1200. Then when defining a new plant, the corresponding fuel type is selected from the fuels database. Heat rates and variable costs also comply with the values in Module 1C-1200. Due to the difficulty of obtaining all the required characteristics for all the plants of every system, some assumptions were made for the simplification of the database building, when the required numbers were not found: • Number of units was set at 1; • Minimum generation was set at 0; • Maximum generation was set equal to installed potential; • FORs and CORs were set equal to the ones from a similar plant in the system, or the next closest system; • For nuclear plants, COR = 10%, with variable O&M cost = 0; • Generic plants took similar characteristics to other plants of the same type in the system or plants from the closest system. In the model, wind farms were modeled as thermal plants, with no fuel cost and 70% COR. Solar plants were also modeled as thermal plants, with no fuel costs and 55% COR. Both wind and solar plants had 0 variable O&M costs.
  • 179. Final Master Plan Report 3-2 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 3.1.2 Hydro Plants For the simulation of hydro plants, SDDP mainly requires the following data: • Plant name, type (Storage/Run-of-River) and status (Existing/Future); • Hydro site, plant to turbine to, plant to spill to; • Installed potential (MW) and number of units; • Minimum and maximum turbining (m3 /s) , production coefficient (MW/m3 /s); • Minimum and maximum storage (Hm3 ) Hydro sites refer to the ones presented in Appendix C of Module 1C-1200. The complete hydrology data is entered into the model. And each storage plant is linked to one of these hydro sites to simulate their water intake. For run-of-river (ROR) plants, no hydro site is required, thus a dummy zero-inflow hydro site was created and ROR plants were linked to that site. Downstream plants (“Turbine to”) and “Spill to” plants were obtained from the study of the geographical layouts of the hydro plants on the rivers. Plants at the end of the stream turbine and spill to the river, with no other plant benefiting from that flow. Due to the difficulty of obtaining all the required characteristics for all the plants of every system, some assumptions were made for the simplification of the database building, when the required numbers were not found or information was not available: • The “hydro site” was set as the zero-inflow one. • The “turbine to” and “spill to” entries were left blank. • Number of units set at 1 • Minimum Turbining set at 0 • Minimum Storage set at 0 When the storage was mentioned as being only used for daily regulation, minimum storage was set equal to maximum storage. Finally when a plant was described as a storage plant in a reference but the storage level was not found, the plant was set as ROR instead i.e. with 0 storage. 3.1.3 Fuels As mentioned earlier, fuels are separately defined. For every system, the fuels are entered into the fuel database with their name, preferred consumption unit and fuel price in $/unit. The unit was set as GJ for all fuels for consistency. For the fuel prices, Section 6-4 of Module 1C-1200 defined forecasts for most of them (Oils, NG, Coal, Geothermal), while the rest (Methane Gas, Cogen, Bagasse, Nuclear) had one price for the entire study horizon, taken from the references in Table 2-2 of Module 1C-1200. 3.1.4 Demand Forecast As mentioned in the introduction to this chapter, the demand forecast for the entire study horizon is required. However SDDP requires it in the form of load blocks for every stage of the study. It was explained in the previous section that the load in the study is split into three blocks (peak, mid and low) and the simulations are run for every month. Appendix A explains how the forecast was obtained for every block of every month of the study horizon. The forecast in SDDP format (3 blocks x 12 months x 26 years = 936 values) is thus entered in the model’s database for every system.
  • 180. Final Master Plan Report 3-3 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 3.2 Data Required for OptGen OptGen deals with future plants primarily, and both hydro and thermal future plants need the same types of data: • Investment cost in MUSD or $/KW • Fixed O&M Cost in $/KW • Plant Lifetime in years • Plant entrance schedule • Investment Payment schedule • Minimum and Maximum entrance in operation date • Decision type: Optional or Obligatory Investment costs, Fixed O&M costs and plant lifetimes are compliant with the data in Module 1C-1200 Tables 5-12 and 6-16. For entrance schedule, the default setting for most plants was to install all units at once, except when advised otherwise by the already existing national plans. The payment schedule was set as one single payment in the first year since the investments considered come from Tables 5-12 and 6-16 where the interest during construction was already calculated and included in the total cost. The Minimum and Maximum entrance dates were initialized at 2013 and 2038 respectively and the decision type was selected as Optional for all candidates. These settings would then be modified depending on the first iterations of the model to generate the final expansion plan. 3.3 References The references used to gather the required data are all listed in Table 2-2 of module 1C- 1200. In most cases, the main source was the most recent available master plan for the country in question. However, in some cases, more in-depth research had to be done, looking at feasibility studies for select hydro projects or annual reports from the utilities of the countries. Regional studies like the SSEA [1,2] or the ENPTPS [10] were of great help. Finally, internet research and email communications with the utilities clarified any discrepancy. The references used for each system are listed in the tables in Appendix B.
  • 181. Final Master Plan Report 4-1 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4 NATIONAL EXPANSION PLANS Although the latest national master plans are taken as a starting point for the elaboration of the regional master plan, it is important to realize that these available national plans were not consistent among each other. Different study horizons and reliability criteria were used in their elaboration. For the purpose of the regional master plan and the assessment of benefits of an increased level of regional coordination in operation and planning, it is necessary to have national master plans with consistent criteria for: • study horizon: 2013-2038; • reliability criteria; • an update of the status of planned and committed projects; and, • covering the local demand with national resources only. Exports and imports are considered later in the regional master plan. For that purpose, the latest existing master plan was considered and, when needed, was modified to fit the new demand forecast as well as to meet the reliability criteria. Also in some cases, projects that were supposed to come online prior to 2013 but experienced major delays and have yet to get commissioned, were considered as candidates in the modified plan, instead of counting them as existing in 2013. Note: In the presentation of the master plan results in the form of bar charts, three categories are used in order to group plants running on similar types of fuel: • Renewable Energy: Hydro, Wind, Solar and Biomass plants. • Clean Energy: Geothermal, Natural Gas, Methane Gas, Nuclear and Cogeneration plants. • Conventional Energy: Diesel, Fuel Oil, Crude Oil, Gasoil and Coal plants. Each category’s aggregate installed capacity (MW) will form one single bar with the total capacity of the system in any given year consisting of the stacked bars from the three categories. The same repartition will be used when presenting energy generation results (GWh) from the SDDP simulations of each individual system with the addition of a category for net exchange. 4.1 Tanzania 4.1.1 Existing national expansion plan The national plan considered for Tanzania is the 2009 PSMP done by SNC-Lavalin for TANESCO [3]. The study period in that plan is from 2009 to 2033. Figure 4-1 presents the expansion plan in a bar chart showing the evolution of the Tanzania generation capacity by plant category:
  • 182. Final Master Plan Report 4-2 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-1 Tanzania Existing National Expansion Plan by Plant Category The system has a huge proportion of hydro generation (up to 64% in 2023) and the reliability criteria used in the 2009 PSMP was to meet the energy demand with the firm energy of hydro plants plus the available thermal production. This produced an expansion plan that was driven primarily by energy needs. This resulted in a reserve margin that is quite high from the first year of this study horizon: 46% in 2013. The reserve increases to 59% by 2033. 4.1.2 Modified national expansion plan The load considered in the present study is the same as the one from the PSMP, with an expansion on the forecast to cover the remaining 5 years. The two main goals of the modified plan are: • Adjust the generation additions to take into account the new reliability criteria. • Taking care of the generation expansion for the years 2034-2038. The chart for the modified plan is presented hereafter in Figure 4-2: 0% 10% 20% 30% 40% 50% 60% 70% 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 6,500 7,000 7,500 8,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 183. Final Master Plan Report 4-3 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-2 Tanzania Modified National Expansion Plan by Plant Category The reserve at the end of the horizon settles a little above 15%, which is enough for the system to meet the load within the adopted reliability criteria. The main changes as will be seen in the next section, affected the new CCGT and Coal STPP plants: the orange bar representing the clean thermal plant additions (i.e. CCGTs running on NG) grows in small steps between 2033 and 2038 in the new plan instead of coming in as a one shot addition in 2033. It’s also possible to see that red bars representing conventional thermal plants (Coal STPPs) follow a similar trend. The capacity additions in the new plan are more evenly distributed and it takes 4 more years to cross the 7,000 MW mark (2037 vs. 2033). The complete set of tabulated values for the data behind these charts can be found in Appendix C. 4.1.3 Existing Vs. Modified national expansion plan Both the existing and modified plans are displayed next in Table 4-1 to compare and inspect the changes. Those changes, whether in the date of entry of a plant, or when a totally new plant is introduced to the plan, are highlighted in bold, whereas any retirement is in italic: 0% 10% 20% 30% 40% 50% 60% 70% 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 6,500 7,000 7,500 8,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 184. Final Master Plan Report 4-4 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 4-1 Tanzania Existing Vs. Modified National Expansion Plan Year Existing Plan (EP) Modified Plan (MP) Plant Name Type MW S/T (MW) Plant Name Type MW S/T (MW) 2013 Kiwira TPP 200 490 Kinyerezi TPP 240 240 Kinyerezi TPP 240 Wind WPP 50 2014 0 Kiwira TPP 200 200 2015 Rusumo HPP 63 63 Rusumo HPP 63 113 Wind WPP 50 2016 Ruhudji HPP 358 358 Ruhudji HPP 358 358 2017 Mnazi Bay TPP 300 300 Mnazi Bay TPP 300 300 2018 Rumakali HPP 222 222 Rumakali HPP 222 222 2020 Stieglers 1 HPP 300 300 Stieglers 1 HPP 300 300 2022 Tegeta IPTL TPP -100 -100 Mchuchuma TPP 200 100 Tegeta ITPL TPP -100 2023 Stieglers 2 HPP 600 560 Stieglers 2 HPP 600 560 Songas 1 TPP -40 Songas 1 TPP -40 2024 Ngaka TPP 400 253 Ngaka TPP 200 53 Songas 2 TPP -110 Songas 2 TPP -110 Songas 3 TPP -37 Songas 3 TPP -37 2025 Mchuchuma TPP 400 400 0 2026 Stieglers 3 HPP 300 300 Stieglers 3 HPP 300 300 2027 Nyasa Coal TPP 200 253 Kakono HPP 53 53 Kakono HPP 53 2028 Local Gas TPP 200 462 Local Gas TPP 200 462 Masigira HPP 118 Masigira HPP 118 Mpanga HPP 144 Mpanga HPP 144 2029 Ikondo HPP 340 240 Ikondo HPP 340 240 Ubongo_T TPP -100 Ubongo_T TPP -100 2030 Coastal Coal I TPP 300 404 Taveta HPP 145 104 Taveta HPP 145 Tegeta GT TPP -41 Tegeta GT TPP -41 2031 Coastal Coal II & III TPP 600 440 Ngaka TPP 200 40 New Cogen TPP 40 New Cogen TPP 40 Mwanza TPP -100 Mwanza TPP -100 Cogen TPP -40 Cogen TPP -40 Ubongo_E TPP -60 Ubongo_E TPP -60 2032 Coastal Coal IV & V TPP 600 600 Coastal Coal I TPP 300 300 New Wind WPP 50 New Wind WPP 50 Wind WPP -50 Wind WPP -50 2033 CC LNG (I-IV) TPP 696 456 CC LNG I TPP 174 234 Kinyerezi TPP -240 Coastal Coal II TPP 300 Kinyerezi TPP -240 2034 0 Tegeta IPTG TPP 100 724 CC LNG II TPP 174 Coastal Coal III TPP 300
  • 185. Final Master Plan Report 4-5 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Year Existing Plan (EP) Modified Plan (MP) Plant Name Type MW S/T (MW) Plant Name Type MW S/T (MW) Songwe Sofre HPP 150 2035 0 Songwe Manolo HPP 156 456 Coastal Coal IV TPP 300 2036 0 Songwe Bigupu HPP 34 208 CC LNG III TPP 174 2037 0 Coastal Coal V TPP 300 300 2038 0 DSM CCGT TPP 174 348 CC LNG IV TPP 174 Total Existing Plan 6001 Modified Plan 6215 The total additions are almost the same with only around 200 MW of difference. In 2033 the modified plan has only 4,174 MW of additions which is almost 2,000 MW less than the original expansion plan. The main changes to the existing national plan were: • 400 MW of coal STPP (200 from Mchuchuma and 200 from Nyasa) were removed. • 200 MW each from Ngaka and Mchuchuma Coal STPP were displaced. • Coastal Coal and CC LNG generic plants had their units displaced into the future. • Hydro plants from the Songwe river were selected. 4.1.4 Investment net present value The investment costs of all future plants in the modified national expansion plan are listed in Tables 5-12 and 6-16 of Module 1C-1200. Using a 10% interest rate, Tanzania’s investment net present value in 2013 is split into: • Hydro: 1,976.33 MUSD; and, • Thermal: 2,916.19 MUSD. For a total of 4,892.51 MUSD, which means thermal investments make up 60% of the total against 40% for the hydro investments. Investments will be compared in the next section to the ones in the regional plan, in order to highlight the benefits of interconnections. 4.1.5 Interconnections and energy generation The new expansion plan was simulated with SDDP in order to obtain the generation by fuel type. The following existing and committed interconnections were considered in the simulation: • 132 KV double-circuit AC transmission line between Tanzania and Uganda with a capacity of 59 MW. • 220 KV single-circuit AC transmission line between Tanzania, Rwanda and Burundi, through the Rusumo Falls project with a capacity of 350 MW from the project towards Tanzania, with a 280 MW portion from the project to Rwanda and a 320 MW portion to Burundi. The energy generation by fuel category for Tanzania, including net exchanges with neighbouring countries, is shown below in Figure 4-3:
  • 186. Final Master Plan Report 4-6 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-3 Tanzania Generation by Fuel Category - Modified National Expansion Plan It is observed that the generation is mostly comprised of renewable energy (blue bar) under the form of hydro power, with coal accounting for the majority of the thermal generation as well, under the conventional fuels label (red bar). Renewable energy (hydro, wind) makes up about 40% of the generation in the initial year but increases to about 80% in 2030. That proportion drops to around 55% by 2038 as very few new renewable plants are introduced. There is a corresponding increase in conventional thermal generation (Coal, Diesel, HFO) from as little as 2% in 2013 to 40% in 2038. The clean thermal energy (NG, Cogen) observes an opposite trend starting at 60% in 2013 and dropping to 5% in 2038. The main reason for that is that coal is a cheaper source of energy than NG and the reserve of NG in Tanzania will be reduced at the end of the study period. With the expansion plan involving a large amount of new Coal STPPs, the generation will shift from NG to coal for a least cost operation. Finally, the exchange with Uganda, Rwanda and Burundi represented by the green bar is a very small portion of the load (3% on average), which means the expansion plan put in place for Tanzania is self-sufficient. The complete set of tabulated values for the data behind this chart can be found in Appendix C. 0 2,500 5,000 7,500 10,000 12,500 15,000 17,500 20,000 22,500 25,000 27,500 30,000 32,500 35,000 37,500 40,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean Renewable
  • 187. Final Master Plan Report 4-7 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.2 Kenya 4.2.1 Existing national expansion plan The national plan considered for Kenya is the 2008 Least Cost Power Development Plan (LCPDP) done for the Kenya Ministry of Energy in collaboration with the power utility corporations KenGen and KPLC [27]. The study period in that plan is from 2009 to 2030. Figure 4-4 presents the expansion plan in a bar chart showing the evolution of the Kenya generation capacity by plant category: Figure 4-4 Kenya Existing National Expansion Plan by Plant Category The reserve margin in 2030 is close to 15%. With the load considered in the present study being the same as the one used in the LCPDP, the main reasons behind the need for a new national expansion plan are: • The system looks to be over-installed in 2013, with more than 50% reserve margin. The existing system needs to be inspected for any delayed or un-commissioned projects. • The plan includes around 1,700 MW of import capacity. It was explained that the study requires a national plan that is self-sufficient i.e. can meet its load from within its own generation. These 1,700 MW need to be replaced by local generation. • The plan includes 1,200 MW of nuclear development. As discussed in the Inception Report, nuclear plants are only considered in Egypt. Hence these 1,200 MW also need to be replaced by another type of local generation. • Additional generation might be needed to cover the load for the years beyond the study horizon of the LCPDP (2031-2038), with the forecasted growth around 8% in 2030 and the reserve in 2030 only 15%. 0% 10% 20% 30% 40% 50% 60% 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 17,000 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Reserve MW Imports Conventional Clean Renewable Load (MW) Reserve Margin
  • 188. Final Master Plan Report 4-8 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.2.2 Modified national expansion plan With the objectives of this modified plan highlighted in the previous sub-section, the following measures have been taken: • Some wind developments with a total capacity close to 350 MW, present in the original plan with a date of entry between 2011 and 2013, were used as candidates for after 2013 instead as no additional information was available. This will decrease the capacity of the existing system in 2013. • Imports have been taken out of the expansion plan. • Nuclear development has been taken out as well. It was directly replaced by the most available thermal resource in Kenya: Coal. 1,200 MW of Coal STPP were fixed in the plan with the same entry schedule as the NPPs from the LCPDP (600 MW in 2025 and 600 MW in 2028). • The LCPDP mentions a large resource of geothermal and the desire to develop that resource at the rate of around two (140 MW) plants per year. That guideline was considered by the new plan. • Additional generic Coal STPPs (300 MW plants) were added. Other generics were also considered: OCGTs (200 MW) and CCGTs (348 MW) running on imported NG. • Hydro projects highlighted in Module 1C-1200 but unselected by the LCPDP were also considered (Karura, Ewaso Ngiro and Magwagwa). The new national expansion plan is shown in Figure 4-5 in the form of a bar chart representing the yearly system configuration by plant category: Figure 4-5 Kenya Modified National Expansion Plan by Plant Category 0% 10% 20% 30% 40% 50% 60% 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 17,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 189. Final Master Plan Report 4-9 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study At first glance, the issues highlighted previously look to be resolved. The reserve is close to 40% in 2013 (with a smaller existing system) but drops slowly to stabilize a little under the 15% mark without any NPP or imports. With this expansion plan, Kenya should now have a self-sufficient future system. The mix of different types of generic thermal plants creates an extra degree of reliability as the system is not dependant on one type of generation and will not deplete Kenya of its coal reserve. The complete set of tabulated values for the data behind these charts can be found in Appendix C. 4.2.3 Existing Vs. Modified national expansion plan Both the existing and modified plans are displayed next in Table 4-2 to compare and inspect the changes. Those changes, whether in the date of entry of a plant, or when a totally new plant is introduced to the plan, are highlighted in bold, whereas any retirement is in italic: Table 4-2 Kenya Existing Vs. Modified National Expansion Plan Year  Existing Plan (EP) Modified Plan (MP)  Plant Name  Type MW S/T (MW) Plant Name Type MW  S/T (MW)                 2013  Geothermal   TPP 140 440 Geothermal TPP 140  440  Import  IMP 300 Turkana Wind WPP 300                2014       0 Cogen Future TPP 126  406       Geothermal TPP 280                2015  Geothermal  TPP 140 185 Generic Coal TPP 300  245  Import  IMP 100 Nairobi Fiat  TPP ‐10  Nairobi Fiat   TPP ‐10 Olkaria 1 TPP ‐45  Olkaria 1  TPP ‐45                  2016   Geothermal  TPP 280 280 Geothermal TPP 140  140                2017   Geothermal  TPP 140 140 Geothermal TPP 280  280                2018   Geothermal  TPP 280 280 Mutonga HPP 60  200       Geothermal TPP 140                2019  Import  IMP 100 40 Generic CCGT NG TPP 348  288  Kipevu Diesel  TPP ‐60 Kipevu Diesel TPP ‐60                2020  Low Grand Falls  HPP 140 220 Low Grand Falls HPP 140  340  Geothermal  TPP 140 Aeolus Wind WPP 60  IberAfrica 1  TPP ‐60 Generic OCGT NG TPP 200       IberAfrica 1 TPP ‐60                2021  Mutonga  HPP 60 360 Generic CCGT NG TPP 348  348  Import  IMP 300                  2022  Geothermal  TPP 280 203 Magwagwa HPP 120  391  Tsavo IPP  TPP ‐77 Generic CCGT NG TPP 348       Tsavo IPP TPP ‐77                        2023  Import  IMP 900 900 Geothermal TPP 140  340       Generic OCGT NG TPP 200                2024  Geothermal  TPP 140 290 Ewaso Ngiro HPP 180  430  LSD 150  TPP 150 Osiwo Wind WPP 50       Generic OCGT NG TPP 200                2025  Nuclear  NPP 600 600 Mombasa Coal TPP 600  600 
  • 190. Final Master Plan Report 4-10 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Year  Existing Plan (EP) Modified Plan (MP)  Plant Name  Type MW S/T (MW) Plant Name Type MW  S/T (MW)                2026  LSD 150  TPP 150 290 Geothermal TPP 280  280  Geothermal  TPP 140                  2027  Geothermal  TPP 420 420 Geothermal TPP 140  488       Generic CCGT NG TPP 348                2028  Nuclear  NPP 600 530 Momnasa Coal TPP 300  530  Olkaria 2  TPP ‐70 Generic Coal TPP 300       Olkaria 2 TPP ‐70                2029  LSD 150  TPP 150 404 Generic CCGT NG TPP 696  670  Geothermal  TPP 280 Cogeneration TPP ‐26  Cogeneration  TPP ‐26                  2030  Geothermal  TPP 280 730 Karura HPP 56  476  LSD 150  TPP 150 Geothermal TPP 420  Coal 300  TPP 300                  2031       0 Geothermal TPP 140  836       Generic CCGT NG TPP 696                2032       0 Geothermal TPP 420  420                2033       0 Geothermal TPP 280  628       Generic CCGT NG TPP 348                2034       0 Geothermal TPP 280  880       Generic OCGT NG TPP 600                2035       0 Geothermal TPP 280  880       Generic OCGT NG TPP 600                2036       0 Geothermal TPP 280  680       Generic OCGT NG TPP 400                2037       0 Geothermal TPP 280  880       Generic Coal TPP 600                2036       0 Geothermal TPP 280  1180       Generic Coal TPP 900                Total  Existing Plan  6312 Modified Plan 13276  The modified plan adds around 7,000 MW more than the existing plan by 2038. 6,400 of those additions are installed after the LCPDP’s final year (2030). This means that with the new modified plan, the 2030 total additions would be around 6,900 MW, 600 MW more than the original plan. The nuclear plants were adequately replaced by Coal STPPs, while the required import capacity was mainly substituted by Generic CCGTs running on NG, albeit in a different schedule. What can also be observed in Table 4-2 is the extra amount of renewable energy in the form of Hydro (356 MW) and wind (410 MW; 350 of which have been displaced into the future from the 2013 existing system). The Geothermal expansion follows a 280 MW/year trend for the extended period (2031- 2038). It is accompanied by a combination of Generic CCGTs, OCGTs and Coal STPPs for the required additional 6,400 MW of capacity.
  • 191. Final Master Plan Report 4-11 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study In conclusion, from a capacity point of view, in the LCPDP horizon, there is not much difference as the new plan proposes a system with only 200 MW more of capacity in 2030 for reliability purposes. The difference is in the type and schedule of additions, with the new plan projecting a system that is more diverse, feasible and self-sufficient. 4.2.4 Investment net present value The investment costs of all future plants in the modified national expansion plan are listed in Tables 5-12 and 6-16 of Module 1C-1200. Using a 10% interest rate, Kenya’s investment net present value in 2013 is split into: • Hydro: 713.74 MUSD; and, • Thermal: 9,815.83 MUSD, For a total of 10,529.58 MUSD, which means thermal investments make up 93% of the total against 7% for the hydro investments. Investments will be compared in the next section to the ones in the regional plan, in order to highlight the benefits of interconnections. 4.2.5 Interconnections and energy generation The new expansion plan was simulated with SDDP in order to obtain the generation by fuel type. The following existing and committed interconnections were considered in the simulation: • 132 KV double-circuit AC transmission line between Kenya and Uganda with a capacity of 118 MW. • 220 KV double-circuit AC transmission line between Kenya and Uganda with a capacity of 300 MW. The energy generation by fuel category for Kenya, including net exchanges with neighbouring countries, is shown below in Figure 4-6:
  • 192. Final Master Plan Report 4-12 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-6 Kenya Generation by Fuel Category - Modified National Expansion Plan In Kenya, renewable generation represents a small proportion of the total generation. It decreases from 45% in 2013 to under 10% by the end of the study period, as more thermal plants are introduced. The rest of the generation is split between clean and conventional thermal generation with clean energy, consisting of NG, geothermal and cogeneration, accounting for more than 50% starting in 2017 and reaching as high as 70% in the final years. Conventional generation from Coal mostly, varies around an average of 23%. This is a cheap source of energy and is used for economic purposes and for peak load periods when clean generation alone is insufficient. Finally imports from Uganda are worth around 5% of the total load. Therefore with around 80% of the total generation consisting of clean energy while satisfying the load with little need for imports, the expansion plan proposed is then considered to be a good option both from reliability and environmental viewpoints. The complete set of tabulated values for the data behind this chart can be found in Appendix C. 4.3 Uganda 4.3.1 Existing national expansion plan The national plan considered for Uganda is the Generation Plan included in the 2009 Power Sector Investment Plan (PSIP) done for the Uganda Ministry of Energy and Mineral Development by Parsons Brinckerhoff [37]. The study period in that plan is from 2009 to 2030. Figure 4-7 presents the expansion plan in a bar chart showing the evolution of the Uganda generation capacity by plant category: 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 55,000 60,000 65,000 70,000 75,000 80,000 85,000 90,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean Renewable
  • 193. Final Master Plan Report 4-13 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-7 Uganda Existing National Expansion Plan by Plant Category In the final 5 years (2026-2030) the existing expansion plan has a reserve problem as it drops below 10 % and even goes negative in 2027 and 2030. The main reason is that the present study considers a new load forecast, defined in Module 1A-1100, about 10% higher than the one used in the plan. With the original load forecast, the reserve oscillated between 10 and 20% in these 5 years. However it was necessary to simulate the original plan with the new load to highlight any deficiencies since the plan required for Uganda has to be self- sufficient with the new load. The problems that need to be dealt with by the new plan are: • Re-optimize the future system for the years 2013-2030 since this study is dealing with a different load. • Extend the plan to cover for the remaining 8 years of this present study’s horizon (2031- 2038). • The original plan involves generic plants called Base Load (assumed to be similar to an STPP) and Peak Load (similar to an OCGT), in addition to some small hydro generics. The choice of generics in the plan has to be changed to be consistent (type, fuel, size, costs) with the planning criteria presented in Module 1C-1200 and used throughout this study. 4.3.2 Modified national expansion plan With the objectives of this modified plan highlighted in the previous sub-section, the following measures have been taken: 0% 10% 20% 30% 40% 50% 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2,400 2,600 2,800 3,000 3,200 3,400 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 194. Final Master Plan Report 4-14 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study • The hydro plant Murchisson Falls, with the large capacity development (750 MW) has been included as a candidate for the extended period (2031-2038). • Generic STPPs (53 MW and 56 MW) OCGTs (57 MW) CCGTs (185 MW) and MSDs (10 MW) that were listed in Module 1C-1200 were added as candidates in the plan. • Additional CCGT generics were also included to meet the demand adhering to the reliability criteria. The new national expansion plan is shown in Figure 4-8 in the form of a bar chart representing the yearly system configuration by plant category: Figure 4-8 Uganda Modified National Expansion Plan by Plant Category The chart is a visual indication that the system is hydro-dominated with blue bars representing renewable capacity (hydro and 17 MW of Biomass) forming the better part of the capacity bars in every year of the study horizon. The modified future system has enough reserve to be self-sufficient. The reserve margin oscillates mainly around the 20% mark. When it does drop to 10% the large hydro project Murchisson Falls (750 MW) comes into operation (2032) shooting the reserve up to 40%. The system then does not require any more new plants as the reserve is dropping down towards 20%. In the final two years thermal generics are added to increase the reserve again towards the 20% mark. The complete set of tabulated values for the data behind these charts can be found in Appendix C. 0% 10% 20% 30% 40% 50% 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2,400 2,600 2,800 3,000 3,200 3,400 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 195. Final Master Plan Report 4-15 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.3.3 Existing Vs. Modified national expansion plan Both the existing and modified plans are displayed next in Table 4-3 to compare and inspect the changes. Those changes, whether in the date of entry of a plant, or when a totally new plant is introduced to the plan, are highlighted in bold, whereas any retirement is in italic: Table 4-3 Uganda Existing Vs. Modified National Expansion Plan Year Existing Plan (EP) Modified Plan (MP) Plant Name Type MW S/T (MW) Plant Name Type MW S/T (MW) 2013 Base Load TPP 100 105 Tallow CCGT TPP 185 125 Small Hydros HPP 65 Electromaxx TPP -10 Electromaxx TPP -10 Invespro TPP -50 Invespro TPP -50 2014 Peak Load TPP 25 25 Tallow GT TPP 57 57 2016 Small Hydros HPP 32 32 0 2016 Karuma HPP 250 250 Karuma HPP 250 250 2018 Isimba HPP 100 100 Isimba HPP 100 100 2020 Geothermal TPP 30 30 Geothermal TPP 30 30 2021 Geothermal TPP 30 30 Geothermal TPP 30 30 2022 Geothermal TPP 30 30 Geothermal TPP 30 30 2023 Ayago HPP 250 250 Ayago HPP 250 250 2025 Small Hydros HPP 7 7 CCGT Generic TPP 250 250 2028 Ayago HPP 300 250 Ayago HPP 300 250 Namanve TPP -50 Namanve TPP -50 2030 Small Hydros HPP 20 20 0 2031 0 CCGT Generic TPP 50 50 2032 0 Murchisson Falls HPP 750 750 2037 0 CCGT Generic TPP 50 50 2038 0 Kampala Steam TPP 56 169 Tallow Steam TPP 53 Tallow Diesel TPP 10 CCGT Generic TPP 50 Total Existing Plan 1129 Modified Plan 2391 From the comparison of the two totals in the last row in Table 4-3, it is shown that the new plan adds 1,250 MW more generation to the future system than the original plan. However 1,000 of this amount is in the final 8 years. There is a 250 MW increase to the additions in the existing study’s horizon. Looking at the plan, for the period 2013-2030, the base load, peak load and small hydro plants (249 MW) were replaced by CCGT and OCGT generics (492 MW). With the load forecast in 2030 being 200 MW higher in the new plan, the conclusion that can be made is that the modifications made to the plan were only brought to replace the generics from the existing plan and to cover for the increase in the load forecast.
  • 196. Final Master Plan Report 4-16 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.3.4 Investment net present value The investment costs of all future plants in the modified national expansion plan are listed in Tables 5-12 and 6-16 of Module 1C-1200. Using a 10% interest rate, Uganda’s investment net present value in 2013 is split into: • Hydro: 1,516.43 MUSD; and, • Thermal: 520.98 MUSD, For a total of 2,037.40 MUSD, which means thermal investments make up 25% of the total against 75% for the hydro investments. Investments will be compared in the next section to the ones in the regional plan, in order to highlight the benefits of interconnections. 4.3.5 Interconnections and energy generation The new expansion plan was simulated with SDDP in order to obtain the generation by fuel type. The following existing and committed interconnections were considered in the simulation: • 132 KV double-circuit AC transmission line between Uganda and Kenya with a capacity of 118 MW. • 132 KV double-circuit AC transmission line between Uganda and Tanzania with a capacity of 59 MW. • 220 KV double-circuit AC transmission line between Uganda and Kenya with a capacity of 300 MW. • 220 KV double-circuit AC transmission line between Uganda and Rwanda with a capacity of 250 MW. The energy generation by fuel category for Uganda, including net exchanges with neighbouring countries, is shown below in Figure 4-9:
  • 197. Final Master Plan Report 4-17 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-9 Uganda Generation by Fuel Category - Modified National Expansion Plan The system in Uganda is dominated by hydro generation with renewable energy making up more than 90% of the total in the system. This had to be expected since the expansion plan shown in Figure 4-8 was also dominated by hydro capacity additions. With the water in Uganda being abundantly available for electricity generation year-long in the Victoria Lake, all hydro plants operate at more than 90% capacity factor (Module 1C-1200), given that the lake is the natural reservoir used by all the plants located downstream on the river. Uganda has a great potential to export and utilizes the four interconnections it has with Kenya, Rwanda and Tanzania to good effect. The net exchange is represented in Figure 4-9 by a negative generation in green, peaking at 4,500 GWh in (2032-2034). It does import slightly in the early years (170 GWh in 2015) but on average it exports an amount close to 30 % of its own load. This means that the proposed future Uganda power system is not only self-sufficient but profitable to Uganda and beneficial to the region by providing cheap energy to its neighbours. In addition it is a clean system with close to 98% of its energy made up from renewable generation (Hydro, Biomass) and clean thermal generation (Geothermal). The small remaining portion (2-3%) consists of the conventional thermal resources (Gasoil, Diesel and HFO). The complete set of tabulated values for the data behind this chart can be found in Appendix C. ‐4,500 ‐3,000 ‐1,500 0 1,500 3,000 4,500 6,000 7,500 9,000 10,500 12,000 13,500 15,000 16,500 18,000 19,500 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean Renewable
  • 198. Final Master Plan Report 4-18 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.4 Ethiopia 4.4.1 Existing national expansion plan The national plan considered for Ethiopia is part of the highlights on the power sector development program done by EEPCo in 2008 [47]. The study period in that plan is from 2009 to 2030. Figure 4-10 presents the expansion plan in a bar chart showing the evolution of the Ethiopia generation capacity by plant category: Figure 4-10 Ethiopia Existing National Expansion Plan by Plant Category Ethiopia’s future system is almost entirely renewable. The expansion plan is based only on hydro power plants as no clean or conventional type of capacity is introduced to add to the very small proportion of thermal energy from the existing system (1% in 2030). The reserve is quite high in the system starting at 130%. It does drop to about 40% and a high reserve is always expected in a hydro system for reliability purposes. A power system with a mix of hydro and thermal is more robust and would require a smaller amount of reserve when less hydro-dependant. Finally, that plan was developed with the desire for Ethiopia to export. Some plants may have been selected for the sole purpose of selling cheap power to the neighbours which is the main reason why the local reserve is high. That is not in accordance with the required national plan criteria set in this study as national plans have to be developed irrespective of the exchange possibilities, be it exports or imports. Hence the main targets of the modified plan are: 0% 20% 40% 60% 80% 100% 120% 140% 160% 0 1,500 3,000 4,500 6,000 7,500 9,000 10,500 12,000 13,500 15,000 16,500 18,000 19,500 2013 2015 2017 2019 2021 2023 2025 2027 2029 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 199. Final Master Plan Report 4-19 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study • Re-optimize the entrance decision and schedule of large hydro projects neglecting the possibility to export. Some plants are likely to get postponed while others may be taken out completely. • Reduce the level of reserve of the system. This may automatically follow from meeting the previous target. • Add thermal generics to create a more robust system, less hydro dependant. • Plan the generation expansion for the remaining years of the study horizon (2031-2038) 4.4.2 Modified national expansion plan In the present study the same load forecast is used. In order to treat the issues highlighted in the existing national expansion plan, the following measures have been taken: • The large hydro plants (Mandaya, Karadobi and Border) had their entrance schedule carefully studied. There should be at least 5 years separating each plant. Also the need for all three of them has been put in question. Border was deemed unnecessary, being the most expensive of the three in terms of levelized cost. (see Table 5-12 in Module 1C-1200) • Geothermal developments presented in Module 1C-1200 were introduced to the plan to add thermal capacity to the hydro system • Additional Geothermal generics (400 MW) and OCGT generics running on diesel (140 MW) were also included to cover for the period 2031-2038 and to solve small deficit issues without adding large hydro plants. • Hydro plants that were not considered in the original plan were included as candidates. The new national expansion plan is shown in Figure 4-11 in the form of a bar chart representing the yearly system configuration by plant category:
  • 200. Final Master Plan Report 4-20 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-11 Ethiopia Modified National Expansion Plan by Plant Category As observed, the system is still hydro dominated (Renewable energy in blue) but now clean and conventional additions have a bigger share, especially in the last period (2031-2038). Clean energy comprising of geothermal developments, in orange, accounts for 17% of the total capacity in 2038, while conventional energy (Diesel OCGTs) in red, provides 11% of the total system installation. The 28% combined share replaces the 1% share from the original plan, helping to drive the reserve level below 20% with the system now less hydro dependant. The system looks to be self-sufficient and still has a great potential to export in the first half of the study horizon (2013-2026) where its reserve is above 40%, even though exchanges were not considered. The complete set of tabulated values for the data behind these charts can be found in Appendix C. 4.4.3 Existing Vs. Modified national expansion plan Both the existing and modified plans are displayed next in Table 4-4 to compare and inspect the changes. Those changes, whether in the date of entry of a plant, or when a totally new plant is introduced to the plan, are highlighted in bold, whereas any retirement is in italic: 0% 20% 40% 60% 80% 100% 120% 140% 160% 0 1,500 3,000 4,500 6,000 7,500 9,000 10,500 12,000 13,500 15,000 16,500 18,000 19,500 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 201. Final Master Plan Report 4-21 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 4-4 Ethiopia Existing Vs. Modified National Expansion Plan Year  Existing Plan (EP) Modified Plan (MP)  Plant Name  Type MW S/T (MW) Plant Name Type MW  S/T (MW)                2013  Gibe III  HPP 1870 2572 Gibe III HPP 1870  2712  Chemoga Yeda  HPP 280 Chemoga Yeda HPP 280  Halele Worabesa  HPP 422 Halele Worabesa HPP 422       OCGT Generic TPP 140                2015  Genale 3D  HPP 258 258 Genale 3D HPP 258  258                2016  Gibe IV  HPP 1468 1468 Gibe IV HPP 1468  1468                2017  Geba I & II  HPP 372 372 Geba I & II HPP 372  372                2018       0 Tekeze 2 HPP 275  350       Langano Geo TPP 75                2019       0 OCGT Generic TPP 140  140                2020  Mandaya  HPP 2000 2000    0                2021  Baro I  HPP 200 862 Baro I HPP 200  300  Gibe V  HPP 662 Tendaho Geo TPP 100                2022  Baro II  HPP 510 720 Baro II HPP 510  720  Genji  HPP 210 Genji HPP 210                2023       0 Gibe V HPP 662  662                2025  Karadobi  HPP 1600 1600    0                2028       0 Awash 4 HPP 38  38                2029  Border  HPP 1200 1200 Geo Generic TPP 800  800                2030       0 Geo Generic TPP 400  400                2031       0 Mandaya HPP 2000  2000       Abaya Geo TPP 100                2033       0 Corbetti Geo TPP 75  355       OCGT Generic TPP 280                2034       0 Genale 6D HPP 246  846       Geo Generic TPP 600                2035       0 Aleltu East HPP 186  881       Aleltu West HPP 265       Gojeb HPP 150       OCGT Generic TPP 280                2036       0 Karadobi HPP 1600  1700       Tulu Moye Geo TPP 40       Dofan Geo TPP 60                2037       0 OCGT Generic TPP 560  960       Geo Generic TPP 400                2038       0 OCGT Generic TPP 560  960       Geo Generic TPP 400                Total  Existing Plan  11052 Modified Plan 16022 
  • 202. Final Master Plan Report 4-22 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study The new plan adds 5,000 MW more power to the future system. However, the additions in the previously uncovered period (2031-2038) total 7,800 MW with the remaining 8,200 MW coming in the earlier years. Therefore the modified plan reduced the additions before 2031 by 2,800 MW which is 25% of the original additions to the future system. This represents huge savings for the Ethiopians since the new plan adheres to the reliability criteria as well. Changes include: • Mandaya and Karadobi, with a total of 3,600 MW, pushed 11 years into the future, out of the original horizon. • Gibe V (600 MW) postponed 2 years. • Border (1,200 MW) taken out of the plan. • Geothermal and OCGT generics (a total of 1,500 MW) distributed throughout the study horizon to fill deficit gaps and meet reserve requirements. For the uncovered period, previously unused hydro projects were selected in parallel with more thermal generics. The 7,800 MW are just enough to meet the demand within the criteria and maintain a level of reserve between 15% and 20%. 4.4.4 Investment net present value The investment costs of all future plants in the modified national expansion plan are listed in Tables 5-12 and 6-16 of Module 1C-1200. Using a 10% interest rate, Ethiopia’s investment net present value in 2013 is split into: • Hydro: 4,073.17 MUSD; and, • Thermal: 4,718.05 MUSD, For a total of 8,791.21 MUSD, which means thermal investments make up 53% of the total against 47% for the hydro investments. Investments will be compared in the next section to the ones in the regional plan, in order to highlight the benefits of interconnections. 4.4.5 Interconnections and energy generation The new expansion plan was simulated with SDDP in order to obtain the generation by fuel type. The following committed interconnections were considered in the simulation: • 220 KV double-circuit AC transmission line between Ethiopia and Sudan with a capacity of 200 MW. • 220 KV single-circuit AC transmission line between Ethiopia and Djibouti with a capacity of 180 MW but a transfer limit of 700 GWh/year. The energy generation by fuel category for Ethiopia, including net exchanges with neighbouring countries, is shown below in Figure 4-12:
  • 203. Final Master Plan Report 4-23 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-12 Ethiopia Generation by Fuel Category - Modified National Expansion Plan Just like the expansion plan was hydro dominated, the energy generation is almost entirely renewable (hydro, wind). The blue bars representing the renewable sources provide 99% of the energy in the early years. This proportion drops as more geothermal generics are added but it still remains above 90%. Clean energy (geothermal) makes up most of the remaining 10% while Conventional thermal plants (Diesel OCGTs) produce only 1%. The system is self-sufficient, clean and even beneficial to the region as Ethiopia exports more than 2,300 GWh (3% of its load) in 2038 to Djibouti and Sudan. This is almost 95% of the maximum energy it can export with the existing interconnections. The complete set of tabulated values for the data behind this chart can be found in Appendix C. 4.5 Sudan 4.5.1 Existing national expansion plan The national plan considered for Sudan is the Long-Term Power System Planning Study (LTPSPS) conducted by Parsons Brinckerhoff for the Sudan National Electricity Corporation (NEC) in 2007 [30]. The study period in that plan is from 2007 to 2030. Figure 4-13 presents the expansion plan in a bar chart showing the evolution of the Sudan generation capacity by plant category: ‐5,000 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 55,000 60,000 65,000 70,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean Renewable
  • 204. Final Master Plan Report 4-24 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-13 Sudan Existing National Expansion Plan by Plant Category The expansion plan focuses mostly on conventional types of thermal plants. The red bar grouping Crude STPPs, Coal STPPs and Gasoil CCGTs and OCGTs, is around 70% of the total capacity throughout the horizon. The remaining 30% are all hydro, i.e. renewable energy in blue. Due to the new updated demand forecast, the system is over-installed from the start with close to 230% of reserve in 2013. It does drop almost continuously but it is still at 50% in 2030 which is an elevated margin for a system that is thermally dominated. Finally, the load forecast used in the available plan is a much higher figure than the one used in the present study and drawn in Figure 4-13. This further emphasizes the need for a new plan. The new plan needs to treat the following issues: • Review the construction progress and status of committed projects to get the correct picture for the existing system in 2013. This will help reduce the starting reserve margin. • Re-optimize the entrance schedule of the hydro plants and the thermal generic additions to further reduce the reserve, accounting for the new demand forecast. • Plan the generation for the period 2031-2038, using unselected projects and, if needed, more generics. 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% 220% 240% 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 17,000 18,000 19,000 20,000 21,000 22,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 Reserve MW Conventional Renewable Load (MW) Reserve Margin
  • 205. Final Master Plan Report 4-25 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.5.2 Modified national expansion plan After consulting the power system profile on the NEC website [68], it was discovered that the following projects, proposed for the period leading up to January 2013 by the LTPSPS were not even commissioned yet: • Port Sudan STPP 405 MW • El Bagair STPP 540 MW • Garri 3 STPP 540 MW • New GT 60 MW • New LSD 272 MW • New Coal STPP 143 286 MW • New Coal STPP 380 380 MW • Rumela HPP 30 MW These plants combine for a total of 2,513 MW. The existing national plan considers them as existing in the year 2013, which creates an over-installed system when considering the new reduced load forecast. In the modified plan, these plants have been considered as candidates starting from 2013. The hydro plants entrance schedule was also reshuffled adequately. Additional CCGT and STPP generics were introduced to the plan in the same proportion as proposed in the LTPSPS, to cover for the load in 2031-2038. The new national expansion plan is shown in Figure 4-14 in the form of a bar chart representing the yearly system configuration by plant category:
  • 206. Final Master Plan Report 4-26 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-14 Sudan Modified National Expansion Plan by Plant Category With the 2013 existing system now corrected, there is a noticeable drop in the starting reserve from 230% to 90%. The reserve then decreases even further to settle around 5% in 2038, resolving the issue of over-instalment. The system is still thermally dominated, though now the proportion of conventional sources in 2013 is smaller, with the postponement of some project. In that year the system is 55% made up of conventional thermal capacity (Gasoil OCGTs and CCGTs, Crude and Coal STPPs, LSDs) but that share increases to 78% in 2038 since the expansion plan has much more thermal options than hydro options. Renewable energy constitutes the other half of the capacity and drops from 45% 2013 to 22% in 2038. With a low proportion in hydro, the system can meet the reliability criteria with only 5% reserve. That reserve being 1,180 MW in 2038, it is more than twice the size of the biggest thermal plant used (570 MW Coal STPP). The complete set of tabulated values for the data behind these charts can be found in Appendix C. 4.5.3 Existing Vs. Modified national expansion plan Both the existing and modified plans are displayed next in Table 4-5 to compare and inspect the changes. Those changes, whether in the date of entry of a plant, or when a totally new plant is introduced to the plan, are highlighted in bold, whereas any retirement is in italic: 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% 220% 240% 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 17,000 18,000 19,000 20,000 21,000 22,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Conventional Renewable Load (MW) Reserve Margin
  • 207. Final Master Plan Report 4-27 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 4-5 Sudan Existing Vs. Modified National Expansion Plan Year Existing Plan (EP) Modified Plan (MP) Plant Name Type MW S/T (MW) Plant Name Type MW S/T (MW) 2013 Shereiq HPP 315 315 0 2014 New CCGT 208 TPP 208 208 0 2015 New Coal STPP 380 TPP 380 631 Khartoum STPP U1-2 TPP -55 -89 Low Dal HPP 340 Khartoum GT U1-2 TPP -34 Khartoum STPP U1-2 TPP -55 Khartoum GT U1-2 TPP -34 2016 Kajbar HPP 300 300 Rumela HPP 30 173 New Coal STPP 143 TPP 143 2017 New CCGT 208 TPP 208 446 Sabaloka HPP 90 233 New Crude STPP 238 TPP 238 New Coal STPP 143 TPP 143 2018 New Coal STPP 380 TPP 380 380 Port Sudan TPP 405 405 2019 New CCGT 208 TPP 208 731 New Coal STPP 380 TPP 380 380 New Crude STPP 238 TPP 238 Dagash HPP 285 2020 New Crude STPP 475 TPP 950 1670 Shukoli HPP 210 690 Fula I HPP 720 Lakki HPP 210 El Bagair U1-2 TPP 270 2021 New Coal STPP 570 TPP 570 570 El Bagair U3-4 TPP 270 270 2022 Shukoli HPP 210 210 Fula I HPP 720 1125 Garri 3 STPP U1-3 TPP 405 2023 New CCGT 342 TPP 342 240 Bedden HPP 400 433 Khartoum STPP U3-4 TPP -102 Garri 3 STTP U4 TPP 135 Khartoum STPP U3-4 TPP -102 2024 New GT 60 TPP 60 270 Shereiq HPP 315 1035 Lakki HPP 210 Low Dal HPP 340 New Coal STPP 380 TPP 380 2025 New Crude STPP 475 TPP 475 475 Dagash HPP 285 617 New GT 60 TPP 60 New LSD 272 TPP 272 2026 New CCGT 342 TPP 342 742 Kajbar HPP 300 850 Bedden HPP 400 New CCGT 208 TPP 208 New CCGT 342 TPP 342 2027 New CCGT 342 TPP 684 1254 New Coal STPP 570 TPP 570 778 New Coal STPP 570 TPP 570 New CCGT 208 TPP 208 2028 Garri 1 CCGT TPP -164 -164 New CCGT 208 TPP 208 1070 New CCGt 456 TPP 456 New Coal STPP 570 TPP 570 Garri 1 CCGT TPP -164 2029 New CCGT 456 TPP 912 912 New CCGT 456 TPP 456 798 New CCGT 342 TPP 342 2030 New CCGT 456 TPP 912 912 New CCGT 456 TPP 456 456 2031 0 New GT 60 TPP 60 991 New CCGT 456 TPP 456 New Crude STPP 475 TPP 475
  • 208. Final Master Plan Report 4-28 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Year Existing Plan (EP) Modified Plan (MP) Plant Name Type MW S/T (MW) Plant Name Type MW S/T (MW) 2032 0 New Crude STPP 238 TPP 238 713 New Crude STPP 475 TPP 475 2033 0 New Coal STPP TPP 570 1501 New CCGT 456 TPP 456 New Crude STPP 475 TPP 475 2034 0 New Coal STPP 380 TPP 380 1386 New CCGT 208 TPP 208 New CCGT 342 TPP 342 New CCGT 456 TPP 456 2035 0 New Coal STPP 570 TPP 570 778 New CCGT 208 TPP 208 2036 0 New CCGT 208 TPP 208 550 New CCGT 342 TPP 342 2037 New Crude STPP 238 TPP 238 1625 New CCGT 456 TPP 456 New CCGT 456 TPP 456 New Crude STPP 475 TPP 475 2038 0 New Crude STPP 475 TPP 475 475 Total Existing Plan 10,102 Modified Plan 17,243 The new plan adds 7,000 MW more than the original plan. However, it introduces 8,000 MW in the period 2031-2038. Hence the existing plan adds 1,000 MW more in the period 2013- 2038. Taking into consideration that the existing system in the modified plan is 2,500 MW smaller, there is a reduction of 3,500 MW in capacity by 2030. This is a good indicator of the over-instalment present in the original plan and of the savings this new plan would bring to the Sudanese system. The entire plan has been reshuffled, for both hydro and thermal projects. In addition, extra generic plants were added, using the same types and sizes and keeping the proportion of STPPs to CCGTs almost intact. The old plan would have probably been less changed had the demand forecast been kept the same. However the new forecast was the main driver behind this re-optimization. 4.5.4 Investment net present value The investment costs of all future plants in the modified national expansion plan are listed in Tables 5-12 and 6-16 of Module 1C-1200. Using a 10% interest rate, Sudan’s investment net present value in 2013 is split into: • Hydro: 3,281.57 MUSD; and, • Thermal: 2,819.11 MUSD, For a total of 6,100.68 MUSD, which means thermal investments make up 46% of the total against 54% for the hydro investments. Investments will be compared in the next section to the ones in the regional plan, in order to highlight the benefits of interconnections. 4.5.5 Interconnections and energy generation The new expansion plan was simulated with SDDP in order to obtain the generation by fuel type. The following committed interconnection was considered in the simulation:
  • 209. Final Master Plan Report 4-29 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study • 220 KV double-circuit AC transmission line between Sudan and Ethiopia with a capacity of 200 MW. The energy generation by fuel category for Sudan, including net exchanges with Ethiopia, is shown below in Figure 4-15: Figure 4-15 Sudan Generation by Fuel Category - Modified National Expansion Plan Renewable energy (hydro) in Sudan is more accentuated in the early years (83% in 2013). However with the development of more STPPs and CCGTs, Conventional thermal energy (Oil, Coal) starts taking over as renewable generation’s proportion drop to 25% while the conventional generation increases from 17% to 75%. There are no clean thermal sources in Sudan. Exports from Ethiopia do not play a big part as they constitute only 1.5% of the load of Sudan in 2038. This proves the self-sufficiency of the system. However, with only 25% of renewable generation and no clean thermal generation that plan would have environmental issues in the future. The possibility of importing NG needs to be studied, especially with their neighbours Egypt having a big reserve of that commodity. The complete set of tabulated values for the data behind this chart can be found in Appendix C. 4.6 Egypt 4.6.1 Existing national expansion plan The national plan considered for Egypt is the national generation expansion plan done by the Egypt Electricity Holding Company (EEHC) in 2009 [59]. The study period in that plan is 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Renewable
  • 210. Final Master Plan Report 4-30 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study from 2009/2010 to 2026/2027. Figure 4-16 presents the expansion plan in a bar chart showing the evolution of the Egypt generation capacity by plant category: Figure 4-16 Egypt Existing National Expansion Plan by Plant Category Renewable energy has a minor role in Egypt’s expansion plan. In the proposed future system, it makes up about 15% of the total capacity. New wind farms are included in the expansion plan (Zafarana) and some solar development as well. However, only one small hydro plant is added (Assiut). The plan focuses on a mix of HFO STPPs and NG CCGTs. The clean energy is a little less than 40% of the future system while the conventional thermal plants are a little over 45% of the total capacity in 2038. Nuclear energy plays a part with 5,000 MW being included in the plan to form 15% of the clean thermal energy. The nuclear development follows a [1,000 MW / 2 years] trend. The EEHC desires to continue this trend after the expiration of this plan. The reserve margin is low in the first few years of the expansion (less than 10%). It does however grow to exceed 25% by 2027. With the load forecast in the present study being almost the same as the one used in the existing national plan, the only issues that need to be dealt with by the new plan are: • Add capacity in the form of generic thermal plants in the early years to increase the reserve in 2013. • Cover the remaining 11 years of the expansion using more thermal generics, similar to the ones used in the existing plan. • Continue the development of nuclear plants following the same trend. 0% 5% 10% 15% 20% 25% 30% 35% 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 120,000 130,000 140,000 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 211. Final Master Plan Report 4-31 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.6.2 Modified national expansion plan The expansion plan was subject to the following modifications and additions to solve the issues highlighted in the existing one: • A CCGT plant running on NG (1,500 MW) was added in 2013 to solve the reserve problem. • NG CCGTs (250 MW units) and HFO STPPs (650 MW units) were employed to meet the load for the period (2028 – 2038). • Nuclear generics (1,000 MW units) were added every other year to follow the desired nuclear development trend, with Egypt having the capability to introduce Nuclear plants to its system. The new national expansion plan is shown in Figure 4-17 in the form of a bar chart representing the yearly system configuration by plant category: Figure 4-17 Egypt Modified National Expansion Plan by Plant Category The issue of low reserve in 2013 has been resolved with the reserve now above 10% in that year and exceeds 20% by 2014. The added CCGT has done the required effect. The renewable proportion is still small with no new renewable projects introduced to the plan. And now with only thermals added after 2027, the proportion drops from 14% to 9%. The big change in proportions has been the increase in clean energy which is now at 50% in 2038 while conventional energy is at 41%. 0% 5% 10% 15% 20% 25% 30% 35% 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 120,000 130,000 140,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 212. Final Master Plan Report 4-32 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study The expansion plan uses to great effect Egypt’s resources in NG and its capability to install NPPs, in order to reduce the system’s dependence on expensive polluting fuel oils. And with a reserve of more than 25% of the system load, the future system is deemed self-sufficient. However with 40% of its generation coming from expensive fuels, it may decide to import cheaper power if connected to Ethiopia through Sudan, especially during peak-load periods. The complete set of tabulated values for the data behind these charts can be found in Appendix C. 4.6.3 Existing Vs. Modified national expansion plan Both the existing and modified plans are displayed next in Table 4-6 to compare and inspect the changes. Those changes, whether in the date of entry of a plant, or when a totally new plant is introduced to the plan, are highlighted in bold, whereas any retirement is in italic. Table 4-6 Egypt Existing Vs. Modified National Expansion Plan Year Existing Plan (EP) Modified Plan (MP) Plant Name Type MW S/T (MW) Plant Name Type MW S/T (MW) 2013 Giza North TPP 1000 1676 Giza North TPP 1000 3176 Abu Kir TPP 650 Abu Kir TPP 650 Banha TPP 750 Banha TPP 750 Wind Farms WPP 320 Wind Farms WPP 320 Solar Units SPP 50 Solar Units SPP 50 Shabab TPP -100 CCGT Generic TPP 1500 Sharm El Sheikh TPP -178 Shabab TPP -100 El Huraghda TPP -143 Sharm El Sheikh TPP -178 Mahmoudia TPP -50 El Huraghda TPP -143 Karmouz TPP -23 Mahmoudia TPP -50 Kuriemat 3 TPP -300 Karmouz TPP -23 Nubaria 3 TPP -300 Kuriemat 3 TPP -300 Nubaria 3 TPP -300 2014 Ain Sokhna TPP 1300 4150 Ain Sokhna TPP 1300 4150 Qassasen TPP 1250 Qassasen TPP 1250 Giza North TPP 500 Giza North TPP 500 Suez TPP 650 Suez TPP 650 Wind Farms WPP 450 Wind Farms WPP 450 2015 Qassasen TPP 250 2702 Qassasen TPP 250 2702 Helwan South TPP 1300 Helwan South TPP 1300 Qena TPP 650 Qena TPP 650 Assiut HPP 25 Assiut HPP 25 Wind Farms WPP 700 Wind Farms WPP 700 Solar Units SPP 50 Solar Units SPP 50 Port Said TPP -73 Port Said TPP -73 El Seiuf TPP -200 El Seiuf TPP -200 2016 Qena TPP 650 2500 Qena TPP 650 2500 Damietta West 1,2 TPP 1250 Damietta West 1,2 TPP 1250 Wind Farms WPP 700 Wind Farms WPP 700 Wadi Hof TPP -100 Wadi Hof TPP -100 2017 Helwan South TPP 1300 3400 Helwan South TPP 1300 3400 Damietta West 1,2 TPP 250 Damietta West 1,2 TPP 250 Safaga TPP 650 Safaga TPP 650 Wind Farms WPP 1200 Wind Farms WPP 1200 2018 Damietta West 1,2 TPP 1000 3160 Damietta West 1,2 TPP 1000 3160 Safaga TPP 650 Safaga TPP 650 Dabaa Nuclear NPP 1000 Dabaa Nuclear NPP 1000 Wind Farms WPP 600 Wind Farms WPP 600 Assiut TPP -90 Assiut TPP -90
  • 213. Final Master Plan Report 4-33 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Year Existing Plan (EP) Modified Plan (MP) Plant Name Type MW S/T (MW) Plant Name Type MW S/T (MW) 2019 Damietta West 1,2 TPP 500 2250 Damietta West 1,2 TPP 500 1750 Steam Units TPP 650 Steam Units TPP 650 Combined Cycle TPP 500 Wind Farms WPP 600 Wind Farms WPP 600 2020 Steam Units TPP 1950 3105 Steam Units TPP 1950 3105 Combined Cycle TPP 750 Combined Cycle TPP 750 Wind Farms WPP 600 Wind Farms WPP 600 Damanhour TPP -195 Damanhour TPP -195 2021 Steam Units TPP 650 3500 Steam Units TPP 650 3500 Combined Cycle TPP 1250 Combined Cycle TPP 1250 Dabaa Nuclear TPP 1000 Dabaa Nuclear TPP 1000 Wind Farms WPP 600 Wind Farms WPP 600 2022 Steam Units TPP 1300 2400 Steam Units TPP 1300 2400 Combined Cycle TPP 1000 Combined Cycle TPP 1000 Wind Farms WPP 100 Wind Farms WPP 100 2023 Steam Units TPP 1300 3650 Steam Units TPP 1300 3650 Combined Cycle TPP 1250 Combined Cycle TPP 1250 Dabaa Nuclear TPP 1000 Dabaa Nuclear TPP 1000 Wind Farms WPP 100 Wind Farms WPP 100 2024 Steam Units TPP 3250 4350 Steam Units TPP 3250 4350 Combined Cycle TPP 1000 Combined Cycle TPP 1000 Wind Farms WPP 100 Wind Farms WPP 100 2025 Steam Units TPP 1950 3950 Steam Units TPP 1950 3950 Combined Cycle TPP 1250 Combined Cycle TPP 1250 Dabaa Nuclear TPP 1000 Dabaa Nuclear TPP 1000 Wind Farms WPP 100 Wind Farms WPP 100 Cairo West TPP -350 Cairo West TPP -350 2026 Steam Units TPP 2600 3700 Steam Units TPP 2600 3700 Combined Cycle TPP 1000 Combined Cycle TPP 1000 Wind Farms WPP 100 Wind Farms WPP 100 2027 Steam Units TPP 2600 2910 Steam Units TPP 2600 2910 Combined Cycle TPP 250 Combined Cycle TPP 250 Dabaa Nuclear TPP 1000 Dabaa Nuclear TPP 1000 Wind Farms WPP 100 Wind Farms WPP 100 Abu Sultan TPP -600 Abu Sultan TPP -600 Kafr El Dawar TPP -440 Kafr El Dawar TPP -440 2028 Ataka TPP -900 -900 Ataka TPP -900 3800 CCGT Generic TPP 2750 Steam Generic TPP 1950 2029 Shoubra El Kheima TPP -1260 -1260 Shoubra El Kheima TPP -1260 4440 CCGT Generic TPP 2750 Steam Generic TPP 1950 Nuclear Generic NPP 1000 2030 Talkha TPP -290 -290 Talkha TPP -290 4410 CCGT Generic TPP 2750 Steam Generic TPP 1950 2031 0 CCGT Generic TPP 2750 5700 Steam Generic TPP 1950 Nuclear Generic NPP 1000 2032 Damanhour Ext. TPP -300 -1211 Damanhour Ext. TPP -300 3489 Abu Kir TPP -911 Abu Kir TPP -911 CCGT Generic TPP 2750
  • 214. Final Master Plan Report 4-34 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Year Existing Plan (EP) Modified Plan (MP) Plant Name Type MW S/T (MW) Plant Name Type MW S/T (MW) Steam Generic TPP 1950 2033 0 CCGT Generic TPP 2750 5700 Steam Generic TPP 1950 Nuclear Generic NPP 1000 2034 Damietta TPP -1200 -1200 Damietta TPP -1200 3500 CCGT Generic TPP 2750 Steam Generic TPP 1950 2035 0 Combined Cycle TPP 500 6200 CCGT Generic TPP 2750 Steam Generic TPP 1950 Nuclear Generic NPP 1000 2036 Cairo West Ext. TPP -660 -2228 Cairo West Ext. TPP -660 2722 Cairo South 1 TPP -510 Cairo South 1 TPP -510 Cairo South 2 TPP -165 Cairo South 2 TPP -165 Talkha 210 TPP -420 Talkha 210 TPP -420 Mahmoudia TPP -316 Mahmoudia TPP -316 Damanhour TPP -157 Damanhour TPP -157 CCGT Generic TPP 3000 Steam Generic TPP 1950 2037 0 CCGT Generic TPP 3000 5950 Steam Generic TPP 1950 Nuclear Generic NPP 1000 2038 0 CCGT Generic TPP 3000 4950 Steam Generic TPP 1950 Total Existing Plan 40314 Modified Plan 99264 As already mentioned, the plan was not modified in 2013-2027. Only a small addition was brought to the system in the form of a generic CCGT of 1,500 MW. The remaining 57,000 MW additions were introduced in the uncovered period. The trend used is 2,750 MW of CCGT and 1,950 MW of STPP every year with 1,000 MW of nuclear every other year. All the retirements were respected. 4.6.4 Investment net present value The investment costs of all future plants in the modified national expansion plan are listed in Tables 5-12 and 6-16 of Module 1C-1200. Using a 10% interest rate, Egypt’s investment net present value in 2013 is split into: • Hydro: 142.59 MUSD; and, • Thermal: 73,156.10 MUSD, for a total of 73,298.69 MUSD, which means thermal investments make up 99.9% of the total against 0.1% for the hydro investments. Investments will be compared in the next section to the ones in the regional plan, in order to highlight the benefits of interconnections. 4.6.5 Interconnections and energy generation The new expansion plan was simulated with SDDP in order to obtain the generation by fuel type. The following existing interconnections were considered in the simulation: • A 400 KV bipolar HVDC transmission line between Egypt and Jordan, going all the way to Syria, with a capacity of 600 MW.
  • 215. Final Master Plan Report 4-35 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study • A 220 KV double-circuit AC transmission line between Egypt and Libya with a capacity of 240 MW. However, based on historical data from the latest annual report produced by the EEHC, a total of 700 GWh of net yearly exports were simulated since the Jordanian, Syrian and Libyan systems were not simulated individually. The energy generation by fuel category for Egypt, including net exports to Jordan, Syria and Libya, is shown below in Figure 4-18: Figure 4-18 Egypt Generation by Fuel Category - Modified National Expansion Plan It is clear from Figure 4-18 that the system’s generation is dominated by clean thermal energy. From 58% in 2013, the proportion increases to 73% in 2038. Conventional fuels produce 30% in 2013 but their output is only 21% of the total generation in 2038. Renewable energy makes up the rest. These proportions are caused by the low price of nuclear and NG generation compared to HFO and the unavailability of enough renewable energy. The system is nevertheless clean with up to 80% coming from clean thermals and renewable energy combined. Net exchanges don’t appear on the graph as the 700 GWh exports to neighbouring countries are too small to be visible with a much higher scale. With the available energy not completely used (conventional sources are working at a 30% CF only) the system has proven to be self-sufficient, a conclusion that was expected given the level of reserve attained with the expansion plan. The complete set of tabulated values for the data behind this chart can be found in Appendix C. 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000 500,000 550,000 600,000 650,000 700,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean Renewable
  • 216. Final Master Plan Report 4-36 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.7 Burundi, Eastern DRC and Rwanda 4.7.1 Regional coordination In this present study, the modified national expansion plans were developed for isolated systems for reasons defined previously such as having a self-sustained system. However in the case of Burundi, Eastern DRC and Rwanda, the national plans were developed in coordination with each other for the following reasons: ‐ There was no recently available master for individual countries. Studies in the past few years proposed regional plans. ‐ The three countries share the generation from four hydro plants (the Ruzizi plants), with two of them being future projects (Ruzizi 3 and 4). ‐ The three countries share the generation from a future thermal plant, the second installment of the Lake Kivu methane gas project (200 MW). ‐ The countries have a history of cooperation and power transfer that is preferred to be respected. Hence the new national expansion plan for Burundi, Eastern DRC and Rwanda presented in this section takes into account exchanges between the three countries throughout the study period. 4.7.2 Shared Projects The three countries have an agreement to share the generation from several projects located near the borders: • Ruzizi hydro plants There are currently 2 existing hydro plants on the Ruzizi river: ‐ Ruzizi 1: 30 MW; It is equally shared between Eastern DRC and Rwanda (15 MW each) ‐ Ruzizi 2: 36 MW; It is equally shared between the three countries (12 MW each) In addition there are two projects which are expected to get selected in the national expansion plan: ‐ Ruzizi 3: 147 MW; It will be equally shared between the three countries (49 MW each) ‐ Ruzizi 4: 288 MW; It will be equally shared between the three countries (96 MW each) Geographically, the Ruzizi projects are located in Eastern DRC. However, Ruzizi 2, (and in the future Ruzizi 3 and 4), are not directly connected to the Eastern DRC network. These plants are connected to a bus (Mururu 2) in Rwanda, and from there, the shares of Eastern DRC and Burundi are exported. Hence the transfer capacities from Rwanda to Burundi and Eastern DRC are effectively deducted by the reserved shares for the Ruzizi projects. • Lake Kivu Methane gas project In Rwanda, there are plans to develop Methane gas plants on Lake Kivu. The first part of the project (100 MW) is entirely reserved for Rwanda. However, the second part is of 200 MW and is equally shared between the three countries (66.67 MW each). Again, the transfer capacities from Rwanda to Burundi and Eastern DRC are effectively deducted by the reserved shares for the Lake Kivu projects.
  • 217. Final Master Plan Report 4-37 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.7.3 New national expansion plans As explained previously, the national plans for the three countries were developed in a coordinated manner. When needed, thermal generic plants (100 MW Diesel plants) were added to the systems. It should be noted that each Ruzizi plant had only one commissioning date and its three portions were added to each country’s expansion plan at the same date. The same was done for the Lake Kivu project. The new national expansion plans are shown next in Figures 4-19 to 4-21 in the form of bar charts representing the available capacity by plant category: Figure 4-19 Burundi New National Expansion Plan by Plant Category As shown in Figure 4-19 the future system in Burundi observes two main trends: The Renewable share is high in 2013 (hydro system) making up 89% of the generation. This share drops along the study horizon to 25% by 2038 as very few hydro additions are introduced. In contrast, the share of conventional fuel plants (diesel) increases from 11% to 67% by 2038 with the addition of about 600 MW of generics. The Lake Kivu share of Burundi added in 2033 and representing Burundi’s only source of clean thermal capacity, constitutes only 8% of the 2038 system. The system’s reserve is negative from the start of the study horizon but experiences a drastic increase in 2016 with the first 100 MW of generic diesel being added. It then oscillates around 60% to finally settle at 35%. With the plans of the three countries being developed cooperatively, the negative reserve in the beginning is not a major problem as it was deemed preferable to use imports from Eastern DRC’s new projects instead of having Burundi start adding generics in the first couple of years. ‐50% ‐40% ‐30% ‐20% ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 1,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 218. Final Master Plan Report 4-38 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-20 Eastern DRC New National Expansion Plan by Plant Category As shown in Figure 4-20, the future system in Eastern DRC is dominated by renewable plants (Hydro). Hydro capacity makes up around 85% of the 2013 system with the remaining 15% being conventional thermal plants (diesel). The expansion plan is made up entirely of hydro plants up to 2033 which increases the portion of renewable to 96% by the end of 2032. When Eastern DRC’s share of the Kivu project is added in 2033, the system configuration changes slightly, with renewable capacity making up 83% of the system, 12% being clean energy and the remaining 4% represent the existing diesel generation (conventional thermal). The system’s reserve is high in the period 2017-2027, reaching a peak in 2027 of 197%. It then drops to about 90% (with a small surge in 2033 when the Lake Kivu plant is added). The reason behind this high reserve is the coordinated national plans with Rwanda and Burundi. Eastern DRC is seen as the main exporter and has the most resources and potential hydro projects. These projects are developed early to help the systems of Burundi and Rwanda. These two countries then start to develop generic diesels when the load in Eastern DRC increases enough to reduce substantially the capacity available for exports from the Eastern DRC (i.e. starting in 2028). 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 110% 120% 130% 140% 150% 160% 170% 180% 190% 200% 210% 0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 375 400 425 450 475 500 525 550 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 219. Final Master Plan Report 4-39 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-21 Rwanda New National Expansion Plan by Plant Category As shown in Figure 4-21, the renewable energy in Rwanda makes up close to 30% of the 2013 system. That figure drops to 20% as no new hydro plants are introduced but readjusts when Ruzizi 3 comes online in 2024 and then again Ruzizi 4 in 2027. With few other renewable additions, the system’s renewable capacity settles at around 25% by 2038. The main source of generation in Rwanda’s expansion plan is however the conventional type of thermal plants. Diesel generic are added throughout the study horizon to increase the system’s conventional fuels capacity from 20% in 2013 to 60 % in 2038, with about 600 MW of new plants. The 100 MW of methane gas from Lake Kivu representing the clean fuels in 2013 had a bigger impact (50%) but with only a further 67 MW added before 2038, the clean fuels share drops to 15% of the Rwanda capacity. The system’s reserve experiences a huge drop in the period (2013-2021) from 120% to - 10% but then readjusts and settles around 35%. Since the plans of the three countries were developed cooperatively, the negative reserve is not a major issue; no new plants were added in that period because other plants were added in Eastern DRC at the same time and imports from Eastern DRC were preferred to generation additions. The complete set of Tabulated values behind these charts can be found in Appendix C. The following tables show the capacity additions for Burundi, Eastern DRC and Rwanda: ‐20% ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 110% 120% 130% 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 1,000 1,050 1,100 1,150 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Conventional Clean Renewable Load (MW) Reserve Margin
  • 220. Final Master Plan Report 4-40 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 4-7 Burundi New National Expansion Plan Year New Plan (NP) Plant Name Type MW S/T (MW) 2016 Kabu 16 HPP 20 120 Generic Diesel TPP 100 2021 Generic Diesel TPP 100 100 2024 Ruzizi III (1/3 Share) HPP 49 149 Generic Diesel TPP 100 2027 Ruziz IV (1/3 Share) HPP 96 96 2029 Jiji 03 HPP 16 16 2030 Generic Diesel TPP 100 100 2032 Generic Diesel TPP 100 100 2033 Mpanda HPP 10 77 Kivu Gas 2 (1/3 Share) TPP 67 2036 Generic Diesel TPP 100 100 Total New Plan 858 Table 4-8 Eastern DRC New National Expansion Plan Year New Plan (NP) Plant Name Type MW S/T (MW) 2014 Piani Mwanga HPP 34 34 2017 Babeda I HPP 50 78 Semliki HPP 28 2018 Bengamisa HPP 48 48 2023 Mugomba HPP 40 40 2024 Ruzizi III (1/3 Share) HPP 49 49 2027 Ruziz IV (1/3 Share) HPP 93 93 2033 Kivu Gas 2 (1/3 Share) TPP 67 67 Total New Plan 409
  • 221. Final Master Plan Report 4-41 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 4-9 Rwanda New National Expansion Plan Year New plan (NP) Plant Name Type MW S/T (MW) 2013 Kivu Gas 1 TPP 100 100 2022 Generic Diesel TPP 100 100 2024 Ruzizi III (1/3 Share) HPP 49 49 2025 Generic Diesel TPP 100 100 2027 Ruziz IV (1/3 Share) HPP 96 96 2028 Generic Diesel TPP 100 100 2030 Generic Diesel TPP 100 100 2033 Nyabarong HPP 28 95 Kivu Gas 2 (1/3 Share) TPP 67 2035 Generic Diesel TPP 100 100 2037 Biomass (peat) TPP 50 150 Generic Diesel TPP 100 Total New Plan 989.8 4.7.4 Investment Net Present Value The investment costs of all future plants in the new national expansion plans are listed in Tables 5-12 and 6-16 of Module 1C-1200. Using a 10% interest rate, the investments net present value (NPV) of the three countries in 2013 are: Table 4-10 2013 Investment NPV for Burundi, Eastern DRC and Rwanda Country Total NPV Hydro NPV Thermal NPV MUSD MUSD % of Total MUSD % of Total Burundi 474.87 134.28 28.3% 340.59 71.7% Eastern DRC 395.18 377.14 95.4% 18.04 4.6% Rwanda 680.18 90.64 13.3% 589.55 86.7% Region 1,550.23 602.06 38.8% 948.17 61.2% From Table 4-10, It can be seen that the bulk of the investment in Eastern DRC is in hydro projects (95%) while for Rwanda and Burundi the money goes in thermal projects (86% and 71% respectively). 4.7.5 Interconnections and energy generation The new expansion plans were simulated with SDDP in order to obtain the generation by fuel category. For that purpose, all the existing interconnections of those countries with each other as well as interconnections with other countries in the present study were considered. In addition, committed interconnections were included. These existing and committed interconnections are: • 70 KV Existing double-circuit AC transmission line between Rwanda and Eastern DRC with a capacity of 52 MW.
  • 222. Final Master Plan Report 4-42 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study • 110 KV Existing double-circuit AC transmission line between Rwanda and Eastern DRC with a capacity of 100 MW. • 70 KV Existing double-circuit AC transmission line between Burundi and Eastern DRC with a capacity of 45 MW. Will be upgraded to to 110 KV double circuit AC, with a capacity of 100 MW. • 110 KV Existing double-circuit AC transmission line between Rwanda and Burundi with a capacity of 100 MW. • 220 KV Committed double-circuit AC transmission line between Rwanda and Uganda with a capacity of 250 MW, to come online in 2014. • 220 KV Committed single-circuit AC transmission line between East DRC and Rwanda with a capacity of 370 MW, to come online in 2014. • 220 KV Committed single-circuit AC transmission line between East DRC and Burundi with a capacity of 330 MW, to come online in 2014. In addition to those existing and committed interconnections, and for the purpose of providing enough transfer capacity to channel the power from the shared future projects to the 3 countries, interconnections projects proposed in other studies were considered and interconnection planning was conducted to get these lines online when needed: • 220 KV single-circuit AC transmission line connecting Burundi and Rwanda to Tanzania, through the Rusumo Falls project with a capacity of 350 MW from the project towards Tanzania, a 280 MW portion from the project to Rwanda and a 320 MW portion to Burundi. Will be needed in 2016. • 220 KV Committed single-circuit AC transmission line between Rwanda and Burundi with a capacity of 330 MW, Will be needed in 2016. The following figure shows all the interconnections considered: Figure 4-22 Interconnections in the Burundi. Eastern DRC, Rwanda Region
  • 223. Final Master Plan Report 4-43 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study The energy generation by fuel category for the three countries, including net exchange in between them, as well as with Uganda and Tanzania, is shown next. It should be noted that the exchanges in the three figures below do not include the shared projects as these are considered as part of the generation for the three countries. Figure 4-23 Burundi Generation by Fuel Category - New National Expansion Plan As shown in Figure 4-22, Burundi’s generation is mostly renewable in the first 8 years, where more than 80% of the energy fed to the system is from hydro plants. However as diesel generics are developed and hydro development is minimal (except for the Ruzizi projects), the share of hydro slowly drops to 33% by 2038 while generation from conventional fuel plants reaches its peak in 2032 at 51% and provides 36% in 2038. That drop in conventional fuels in the last 5 years from 51% to 36% coincides with the introduction of the clean fuel plant in Lake Kivu in 2033. The Generation from that plant is around 30% in 2038. The Burundi system is therefore highly dependent on thermal energy however half of that energy is from clean fuels, which when added to the renewable gives Burundi two thirds of its energy from clean sources. The system of Burundi imports a substantial amount of energy, making up 40% of the load in 2015 and is constantly around the 25% mark until 2032. In 2033 Burundi’s share of the Lake Kivu project is added to its system and its dependence on imports drops. Its 2038 imports are only 10% of its load. ‐100 0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 1,900 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean Renewable Load
  • 224. Final Master Plan Report 4-44 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-24 Eastern DRC Generation by Fuel Category - New National Expansion Plan As shown in Figure 4-23, Eastern DRC is highly dependent on hydro generation. The renewable energy’s share of the generation is above 95% and even close to 100% up until the end of 2032. It drops to 80% in the latter years when the lake kivu project comes online and takes about 20% of the generation in Eastern DRC. The system is totally clean with almost 0% generation from conventional fuels throughout the study horizon. Eastern DRC is a major exporter in the region as can be observed by the net exchange values in the negative part of the chart. The exports peak at more than double the load in 2018 and stay above 150% of the load until 2028. Then with no new additions in the system until the Lake Kivu project is added in 2033, the exports drop to 75% of the load in 2038. In absolute terms however, they stay close to their peak of 1000 GWh. ‐1,200 ‐1,000 ‐800 ‐600 ‐400 ‐200 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean Renewable Load
  • 225. Final Master Plan Report 4-45 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-25 Rwanda Generation by Fuel Category - New National Expansion Plan As shown in Figure 4-24, in Rwanda the generation is almost equally shared between renewable (hydro and biomass), clean fuels (methane) and conventional fuels (Diesel). In the first few years there is almost no diesel generation, but as the development of generics is progressing, the share of conventional generation increases from 7% in 2022 to 36% in 2038, peaking at 46% in 2031. For the clean fuels, with Rwanda the sole benefactor of the first Kivu project (100 MW), 68% of the generation is from methane in 2013. This figure drops to 39% in 2038, with a late surge to 55% in 2033 when the second Kivu project is added. Renewable energy takes up the rest of the country’s generation with 31% in 2013 and hovering around 25%, until 2038. Just like in Burundi, the system has two thirds of its generation from clean sources. Rwanda exports some energy in the first 4 years but then starts to import from Eastern DRC, Uganda and Tanzania at around 30% of its load in 2017. The imports are still substantial at the end of the study period, even after all the generics are added. In 2038, Rwanda imports 20% of its load. The complete set of tabulated values for the data behind the charts can be found in Appendix C. ‐250 0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750 4,000 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean Renewable Load
  • 226. Final Master Plan Report 4-46 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 4.8 Djibouti 4.8.1 Existing national expansion plan The national plan considered for Djibouti is the Least Cost Electricity Master Plan (LCEMP) conducted by Parsons & Brinckerhoff for the World Bank in 2009 [30]. The study period in that plan is from 2009 to 2035. Figure 4-26 presents the expansion plan in a bar chart showing the evolution of the Djibouti generation capacity by plant category: Figure 4-26 Djibouti Existing National Expansion Plan The Plan is made up of thermal plants only with conventional thermal capacity being dominant. It makes up 100% of the future system in 2013 but drops to 76% by 2038. That drop is met by an increase in clean thermal capacity (from 0 to 24%) due to the introduction of geothermal plants. The reserve is oscillating and settles around 20% which is acceptable for a thermal system. With the load practically unchanged in this present study, there doesn’t seem to be any issue to deal with, except for the expansion till 2038. The system might not need any extra generation. The existing national plan can be examined year by year, plant by plant in the following table: 0% 10% 20% 30% 40% 0 15 30 45 60 75 90 105 120 135 150 165 180 195 210 225 240 255 270 285 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 Reserve MW Clean Conventional Load (MW) Reserve Margin
  • 227. Final Master Plan Report 4-47 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 4-11 Djibouti Existing National Expansion Plan Year Existing Plan (EP) Plant Name Type MW S/T (MW) 2013 Diesel HFO 12 MW TPP 24 24 2014 Diesel HFO 7 MW TPP 7 7 2015 Diesel HFO 7 MW TPP 7 22 Gas Turbine 15 MW TPP 15 2016 Geothermal 20 MW TPP 20 20 2019 Geothermal 20 MW TPP 20 20 2022 Geothermal 20 MW TPP 20 20 2030 Diesel HFO 12 MW TPP 24 24 2031 Diesel HFO 7 MW TPP 7 -3 Diesel HFO 12 MW TPP 12 Boulaos TPP -22 2032 Boulaos TPP -9 -9 2033 Diesel HFO 12 MW TPP 12 12 2034 Diesel HFO 12 MW TPP 12 6 Boulaos TPP -7 2035 Diesel HFO 7 MW TPP 7 -6 Boulaos TPP -13 Total Existing Plan 137 A total of 137 MW of additions are introduced to the plan between 2013 and 2035. The most notable of those additions are the three 20 MW Geothermal plants (2016, 2019 and 2022) that provide some amount of clean energy to the system. The rest are all HFO Diesel plants bar one 15 MW OCGT running on Gasoil in 2015. The Boulaos plant’s retirement schedule has been observed. 4.8.2 Additional 3-year Period The system’s expansion plan was left unchanged and the criteria were still met in the additional 3-year period (2036-2038). The existing national expansion plan with the study horizon extended by 3 years is shown in Figure 4-27 in the form of a bar chart representing the yearly system configuration by plant category:
  • 228. Final Master Plan Report 4-48 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-27 Djibouti Existing National Expansion Plan with Extended Study Horizon The configuration is still the same. The reserve drops to 10% but that is still acceptable for a thermal system. The complete set of tabulated values for the data behind these charts can be found in Appendix C. 4.8.3 Investment net present value The investment costs of all future plants in the existing national expansion plan are listed in Tables 5-12 and 6-16 of Module 1C-1200. Using a 10% interest rate, Djibouti’s investment net present value in 2013 is a total of 418.54 MUSD all of it as thermal. Investments will be compared in the next section to the ones in the regional plan, in order to highlight the benefits of interconnections. 4.8.4 Interconnections and energy generation The existing expansion plan was simulated with SDDP in order to obtain the generation by fuel type. The following committed interconnection was considered in the simulation: • 220 KV single-circuit AC transmission line between Djibouti and Ethiopia with a capacity of 180 MW but a transfer limit of 700 GWh/year. The energy generation by fuel category for Djibouti, including net exchanges with Ethiopia, is shown below in Figure 4-28: 0% 10% 20% 30% 40% 0 15 30 45 60 75 90 105 120 135 150 165 180 195 210 225 240 255 270 285 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 Reserve MW Clean Conventional Load (MW) Reserve Margin
  • 229. Final Master Plan Report 4-49 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 4-28 Djibouti Generation by Fuel Category – Existing National Expansion Plan The dominant source of energy for Djibouti is the net import from Ethiopia, shown in green. It is around 83% of the load in 2013. With the development of the geothermal plants and the additional new diesel generics, that proportion drops to 50% by 2038. For the local generation, clean energy is preferred, in the form of geothermal plants. Clean thermal plants represented in orange constitute around 58% of the local generation by 2038. Clean generation even reaches a peak of 81% in 2022 when the last geothermal plant is added. But as the remaining years of the plan only include diesel additions, that share drops while the proportion of conventional thermals increases to 42 %. It was shown through the system’s reserve that it is self-sufficient. However with no renewable energy and with the only source of cheap and clean power being the 60 MW geothermal developments, Djibouti tends to overuse the possibility to import from Ethiopia where the generation is mostly hydro, thus much cheaper than its own diesel. The complete set of tabulated values for the data behind this chart can be found in Appendix C. 0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 GWh Net Exchange Conventional Clean
  • 230. Final Master Plan Report 5-1 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 5 REGIONAL SUPPLY-DEMAND ANALYSIS 5.1 Introduction The coordination in the planning of the expansion and operation of electric power systems brings important benefits for the systems involved because they could share reserve, replace high investment costs and save O&M costs. According to the terms of reference, the main objective of the study is to identify power generation and interconnection projects, at Master Plan level, to interconnect the power systems of EAPP countries in short-to-long term in order to reduce the future investment and operating cost for the whole region. The previous section showed the analysis of the least cost generation expansion plan for each country (Case NGP_EIC), to supply the national load considering only the existing interconnections. The main criteria for the optimization, in each case, was to produce a least cost generation expansion plan while meeting the reliability criteria defined in the Module IC- 1200. In general the national generation plan has surplus during certain periods of the year where the load is smaller or during certain years when a new big project enters in operation. That surplus could be exported to other country if there’s interconnection between both systems. The methodology used for this study consisted, as a first step, in the identification of potential surplus of the generation national plans assuming that there was infinite capacity of interconnection between countries (case NGP_UIC). With these results it was possible to identify potential interconnection projects, in addition to the ongoing/committed interconnection projects. As a second step, an interconnection expansion plan was optimized using as a base the national generation plans, in order to identify interconnection projects and to evaluate the benefits of a first level of regional coordination (case NGP_RIP) using OPTGEN/SDDP generation and interconnections planning software (the details about the models can be viewed on the publishing company’s website: PSR http://www.psr-inc.com.br). The main results of this scenario are presented below. As a third step, both a generation and an interconnection expansion plans were optimized in order to identify interconnection projects and to coordinate the on-power date for regional generation projects. This allowed also to evaluate the benefits of a second level of regional coordination (Case RGP_RIP) related with the reduction in investment generation cost and the saving in operating cost, mainly associated with the reduction in fuel cost. This analysis is called also Regional Planning. In a fourth step, four sensitivity analyses were done, two over the national generation plans case and two over the regional generation plans case, to evaluate the impact of important variables which could deeply affect the interconnections projects. The first sensitivity is related with the possible limitation to only one interconnection of 2000 MW from Egypt to Sudan (cases NGP_RIP_S1 and RGP_RIP_S1), and the second case considers a doubling of the capital costs of the interconnection projects (NGP_RIP_S2 and RGP_RIP_S2). The following Table 5-1 presents the definition and description of the different scenarios analyzed.
  • 231. Final Master Plan Report 5-2 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 5-1 Definition and description of the scenarios analyzed Cases Name Description NGP_EIC National Generation Plans and Existing Interconnection Capacity National generation plans for each country to supply national load. The existing interconnections were considered only to save operating cost NGP_UIC National Generation Plans and Unlimited Interconnection Capacity National generation plans for each country to supply national load and infinite capacity of interconnections between countries to evaluate maximum surplus NGP_RIP National Generation Plans and Regional Interconnection Plans National generation plans for each country and regional interconnection plan for a first level of regional coordination, to maximize profitable power exchanges NGP_RIP_S1 National Generation Plans and Regional Interconnection Plans Sensitivity 1 Similar to the case NGP_RIP considering limitation to only 2000 MW of interconnection capacity between Egypt and Sudan NGP_RIP_S2 National Generation Plans and Regional Interconnection Plans Sensitivity 2 Similar to the case NGP_RIP considering a doubling of the capital costs of all interconnections projects RGP_RIP Regional Generation Plans and Regional Interconnection Plans Regional generation plans considering simultaneous Interconnection plans to supply in the most economical way the national load, independent of the location of the generation plants. In this case it was possible to displace, delay or advance generation in each country. RGP_RIP_S1 Regional Generation Plans and Regional Interconnection Plans Sensitivity 1 Similar to the case RGP_RIP considering limitation to only 2000 MW of interconnection capacity between Egypt and Sudan RGP_RIP_S2 Regional Generation Plans and Regional Interconnection Plans Sensitivity 2 Similar to the case RGP_RIP considering a doubling of the capital costs of all interconnection projects 5.2 Proposed Interconnections projects As was done in the generation planning, interconnection projects had to be proposed to the planning software for optimization of the regional interconnection plans. These interconnections are categorized as: - Existing: Will not be subject to any optimization - Committed: i.e. under construction or with Funds Secured. Will not be subject to any optimization. The planned date of operation will be used - Studied: These projects have been studied. Their selection and schedule will be optimized by the planning software. - Generic: These are additional lines that are similar in characteristics to the above defined lines. They are proposed to the planning software which can choose multiple
  • 232. Final Master Plan Report 5-3 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study instances of the same generic line. Hence the quantity of each generic project chosen and the dates are outputs of the planning software. The generic projects were proposed by studying results of the preliminary runs of the optimization software seeing where the regional interconnection plan might require additional projects, and comparing different configurations for interconnections between any two neighbouring countries to choose the type of generics to feed to the model. Table 5-2 Interconnection Projects Name From To Voltage Distance Capacity Losses Status Comm. dateKm MW % Existing Lines UG-KY_132E Uganda Kenya 132 kV- AC 117 118 3.00 Existing DC-RW_70E DRC Rwanda 70 kV-AC 0.2 52 3.00 Existing DC- RW_110E DRC Rwanda 110 kV- AC 16 100 3.00 Existing DC-BR_70E DRC Burundi 70 kV-AC 14.5 45 3.00 Existing RW- BR_110E Rwanda Burundi 110 kV- AC 115 100 3.00 Existing TZ-UG_132E Tanzania Uganda 132 kV- AC 85 59 3.00 Existing Committed Lines ET-SD_2C Ethiopia Sudan 220 kV- AC 321 200 5.24 Construction 2010 ET-DB_2C Ethiopia Djibouti 220 kV- AC 283 180 4.90 Construction 2011 UG-KY_2C Uganda Kenya 220 kV- AC 254 300 4.56 Construction 2014 DC-RW_2C DRC Rwanda 220 kV- AC 68 370 3.00 Construction 2014 DC-BR_2C DRC Burundi 220 kV- AC 105 330 3.00 Construction 2014 UG-RW_2C Uganda Rwanda 220 kV- AC 172 250 3.55 Committed 2014 Studied Lines ET-SD_5S1 Ethiopia Sudan 500 kV- AC 544 1600 4.60 Studied ET-SD_5S2 Ethiopia Sudan 500 kV- AC 544 1600 4.60 Studied RW-BR_2S Rwanda Burundi 220 kV- AC 103 330 3.00 Studied TZ-UG_2S Tanzania Uganda 220 kV- AC 85 700 2.29 Studied
  • 233. Final Master Plan Report 5-4 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Name From To Voltage Distance Capacity Losses Status Comm. dateKm MW % TZ-KY_4S Tanzania Kenya 400 kV- AC 260 1520 3.11 Studied TZ-RW_2S Tanzania Rwanda 220 kV- AC 115 320 2.87 Studied TZ-BR_2S Tanzania Burundi 220 kV- AC 158 280 3.51 Studied ET-KY_5dS Ethiopia Kenya 500 kV- DC 1120 2000 1.53 Studied EG-SD_6dS Egypt Sudan 600 kV- DC 1665 2000 1.55 Studied Generic Lines ET-SD_5G Ethiopia Sudan 500 kV- AC 544 1600 4.60 Future UG-KY_2G Uganda Kenya 220 kV- AC 254 440 4.56 Future UG-KY_4G Uganda Kenya 400 kV- AC 254 1620 3.25 Future UG-RW_2G Uganda Rwanda 220 kV- AC 172 520 3.55 Future ET-KY_5dG Ethiopia Kenya 500 kV- DC 1120 2000 1.53 Future EG-SD_6dG Egypt Sudan 600 kV- DC 1665 2000 1.55 Future Note: Interconnections under study are identified by one “S” in the last part of their name. In the same way, existing and under construction Interconnections are identified with an “E” and “C” respectively. Generic Lines are identified by a “G”. A “d” identifies DC lines while numbers identify the voltage level (i.e. 6 600 KV). 5.3 National Generation Plans and Regional Interconnection Plans (NGP_RIP) This scenario was developed to evaluate which interconnection projects can be justified as a result of only operating cost saving, without any changes in the national generation expansion plan. The Figure 5-1 shows the map of the Region with the interconnections projects and their in-service date (the map also includes the existing and committed lines)
  • 234. Final Master Plan Report 5-5 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 5-1 EAPP Interconnections Case NGP_RIP
  • 235. Final Master Plan Report 5-6 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study The Interconnection projects already studied: Tanzania-Kenya (1520 MW), Ethiopia-Kenya (2000 MW), Ethiopia-Sudan (2x1600 MW) and Egypt-Sudan (2000MW) entered in operation in the earliest date (2015 and 2016). A second line of 2000 MW from Egypt to Sudan, a second line of 2000 MW from Ethiopia to Kenya as well as a line from Ethiopia to Sudan (1600 MW) enter into operation in 2020. A third line of 2000 MW from Egypt to Sudan enters into operation in 2025 with a final line from Ethiopia to Sudan (1600 MW). The Interconnection Tanzania-Uganda (700 MW) entered in 2023 as well as the 440 MW Uganda-Kenya Line. The interconnection Uganda-Rwanda (520 MW) and the 1620 MW Interconnection Uganda-Kenya were not selected. The new interconnection projects are justified because there’s cheaper generation surplus (e.g., hydro, geothermal, natural gas and Coal) in Ethiopia, Kenya and Tanzania, to replace mainly more expensive heavy fuel oil (HFO) based generation in Egypt (Figure 5-2). It’s important to note that the natural gas based generation in Egypt was limited at the same level observed in its national plan. However, an important quantity remains of generation based in HFO. The increase of the hydro production in Ethiopia is a consequence of better use of the water available in the hydro plants (reduction in spillage). The interconnection Tanzania- Burundi/Rwanda is required for the Rusumo HPP which is committed in 2015. Figure 5-2 Variation of some energy sources Case NGP_EIC vs Case NGP_RIP
  • 236. Final Master Plan Report 5-7 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study The Figure 5-3 presents the net flows every five years between countries and the respective balance. It’s clear that the main flows go from south to north. Detailed balances for each country are in Appendix E. Bi-directional flows can be found in Appendix F. In addition, Diagrams in WBS 1500 show the maximum power transfer in both directions in MW for the years 2013; 2018; 2023; 2028; 2033 and 2038.
  • 237. Final Master Plan Report 5-8 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 5-3 Balance and net flow between countries Case NGP_RIP Balance Case NGP_RIP in GWh Net Exchange NGP_RIP in GWh Year Tanzania Uganda Burundi Eastern DRC Djibouti Gen Load Net Gen Load Net Gen Load Net Gen Load Net Gen Load Net 2013 6,819 7,093 -273 3,575 3,575 0 205 170 35 472 303 169 107 663 -555 2018 11,866 10,722 1,144 5,428 4,874 554 394 339 55 1,806 392 1,414 306 886 -580 2023 18,501 14,422 4,079 7,129 6,465 665 470 576 -106 2,727 515 2,212 547 978 -431 2028 25,069 19,414 5,655 8,807 8,490 317 855 898 -43 4,839 682 4,157 595 1,078 -483 2033 30,263 26,207 4,056 11,315 10,708 607 1,693 1,299 394 8,887 904 7,984 663 1,188 -525 2038 40,910 36,935 3,975 14,296 13,086 1,210 1,626 0 1,626 6,316 1,187 5,129 740 1,308 -569 Year Kenya Ethiopia Sudan Egypt Rwanda Gen Load Net Gen Load Net Gen Load Net Gen Load Net Gen Load Net 2013 11,527 12,149 -622 9,055 7,973 1,082 10,231 10,758 -527 175,491 174,790 701 1,190 499 691 2018 19,775 19,349 426 25,043 13,308 11,735 16,342 19,313 -2,971 221,462 233,210 -11,748 1,543 870 673 2023 31,883 28,460 3,423 32,349 19,939 12,410 34,525 31,729 2,796 282,846 307,530 -24,684 1,735 1,399 336 2028 48,697 41,880 6,817 37,478 29,412 8,066 64,812 49,938 14,874 363,644 402,130 -38,486 1,898 2,071 -173 2033 63,921 60,724 3,197 60,190 43,397 16,793 71,917 74,273 -2,356 492,080 520,720 -28,640 2,095 2,904 -809 2038 90,541 86,292 4,249 83,606 64,063 19,543 100,088 105,620 -5,532 641,228 666,800 -25,572 2,313 3,890 -1,577 Year UG->RW UG->TZ UG->KY TZ->KY KY->ET ET->SD ET->DB 2013 -895 273 622 0 0 527 555 2018 -934 428 1,060 2,779 4,265 15,420 580 2023 -1,890 481 2,074 5,112 10,609 22,588 431 2028 -2,718 179 2,856 7,056 16,729 24,312 483 2033 -6,291 574 6,324 5,907 15,429 31,696 525 2038 -3,577 730 4,057 4,525 12,830 31,805 569 Year RW->TZ BR->TZ RW->BR DC->BR DC->RW SD->EG EG->OT 2013 0 0 -35 0 169 0 701 2018 604 604 -141 690 724 12,449 701 2023 276 276 -195 577 1,636 25,385 701 2028 611 611 -1 655 3,501 39,186 701 2033 639 639 -402 647 7,337 29,340 701 2038 -90 -90 66 0 5,129 26,273 701
  • 238. Final Master Plan Report 5-9 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 5.4 Regional Generation and Interconnection Plans (RGP_RIP) This scenario considers the possibility to optimize both the generation and interconnections in order to minimize the investment and operating cost for the whole Region. In that way the most expensive generation plants could be displaced or delayed and the cheaper projects could be advanced. As a result of the optimization, 7,143 MW of thermal projects were displaced in relation with the national plans, while cheaper hydro projects were advanced, mainly in Ethiopia, like Mandaya HPP (2000 MW) and Karodobi HPP (1200 MW), which are advanced from 2031 and 2036 in the NRP to 2020 and 2025 in the RGP_RIP, respectively; also Border HPP (1200 MW) which is not included in the NGP but is included in the RGP_RIP in 2032. The following Table 5-3 shows the thermal capacity displaced by country and the most important projects advanced with their respective levelized cost. The detailed expansion plan of this case, compared with the national plans, is included in the Appendix D. Table 5-3 Generation capacity displaced or advanced Case RGP_RIP Country Thermal Capacity Displaced in MW Type of Fuel Levelized Cost US$/MWh Ethiopia 1,960 Diesel Oil 237 Djibouti 112 Diesel Oil 189 Rwanda 550 Diesel Oil 176 Burundi 600 Diesel Oil 176 Sudan 1,821 Crude/Gasoil 112/140 Tanzania 2,300 Coal 104 Uganda 300 Gasoil 162 Total 7,143 Project Hydro Capacity Advanced in MW From -> To Levelized Cost US$/MWh Mandaya (Ethiopia) 2000 2031 -> 2020 29 Karadobi (Ethiopia) 1600 2036 -> 2025 30 Border (Ethiopia) 1200 Out -> 2030 34 The Figure 5-4 shows the interconnection projects included in this scenario as a result of the optimization of the regional plan and the Figures 5-5 shows the net flows of energy between countries for every five years, including also the balance for each country. The detailed balances for each country are included in the appendix E. The Bi-directional flows are included in appendix F.
  • 239. Final Master Plan Report 5-10 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 5-4 EAPP Interconnections Case RGP_RIP Note: Rusumo Falls has a capacity of 58 MW and shares its production between the three countries indicated in the figure. However, the transmission lines shown are not for the sole purpose of this transfer but for further exchanges among the countries involved, hence the capacity of the lines is much bigger than that of Rusumo Falls which acts as a substation/injection at that point.
  • 240. Final Master Plan Report 5-11 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Figure 5-5 Balance and net flow between countries Case RGP_RIP Balance Case RGP_RIP in GWh Net Exchange RGP_RIP in GWh Year UG->RW UG->TZ UG->KY TZ->KY KY->ET ET->SD ET->DB 2013 -663 272 625 0 0 475 547 2018 -46 409 1,126 3,370 5,921 13,863 579 2023 5 945 1,652 3,477 8,041 22,409 426 2028 48 1,278 1,627 4,456 10,530 27,813 477 2033 680 4,225 1,662 229 5,352 27,709 525 2038 895 3,614 401 -5,905 2,989 22,186 562 Year RW->TZ BR->TZ RW->BR DC->BR DC->RW SD->EG EG->OT 2013 0 0 -31 0 130 0 701 2018 618 618 84 504 542 12,334 701 2023 286 286 -46 540 540 24,054 701 2028 678 678 -198 773 773 38,833 701 2033 1,143 1,143 -66 916 916 23,878 701 2038 555 555 -177 843 843 19,246 701 Year Tanzania Uganda Burundi Eastern DRC Djibouti Gen Load Net Gen Load Net Gen Load Net Gen Load Net Gen Load Net 2013 6,820 7,093 -272 3,810 3,575 235 201 170 31 433 303 130 115 663 -547 2018 12,446 10,722 1,724 6,363 4,874 1,489 369 339 30 1,438 392 1,046 307 886 -579 2023 16,382 14,422 1,960 9,066 6,465 2,601 368 576 -208 1,595 515 1,080 552 978 -426 2028 21,237 19,414 1,823 11,443 8,490 2,953 1,001 898 103 2,228 682 1,546 601 1,078 -477 2033 19,925 26,207 -6,282 17,274 10,708 6,566 1,592 1,299 293 2,735 904 1,832 663 1,188 -525 2038 26,307 36,935 -10,628 17,996 13,086 4,910 1,670 -843 2,513 2,874 1,187 1,687 747 1,308 -562 Year Kenya Ethiopia Sudan Egypt Rwanda Gen Load Net Gen Load Net Gen Load Net Gen Load Net Gen Load Net 2013 11,524 12,149 -625 8,995 7,973 1,022 10,283 10,758 -475 175,491 174,790 701 1,000 499 502 2018 20,773 19,349 1,424 21,829 13,308 8,521 17,784 19,313 -1,529 221,577 233,210 -11,633 1,078 870 208 2023 31,373 28,460 2,913 34,733 19,939 14,794 33,374 31,729 1,645 284,177 307,530 -23,353 1,094 1,399 -305 2028 46,327 41,880 4,447 47,172 29,412 17,760 60,959 49,938 11,021 363,997 402,130 -38,133 1,730 2,071 -341 2033 64,186 60,724 3,462 66,279 43,397 22,882 70,442 74,273 -3,831 497,543 520,720 -23,177 2,385 2,904 -519 2038 94,785 86,292 8,493 83,821 64,063 19,758 102,680 105,620 -2,940 648,255 666,800 -18,546 2,529 3,890 -1,361
  • 241. Final Master Plan Report 5-12 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study The Table 5-4 presents the interconnection projects for the case RGP_RIP with the optimal date to enter in operation, compared with the case NGP_RIP. The main differences between both cases are the projects UG-KY_2G1 (440 MW) and KY-ET_5dG1 (2000 MW) which enter in the case NGP_RIP but not in the case RGP_RIP. The main reason is because in the NGP there are more generation plants in Uganda and Kenya to export to the north, and then these interconnections are attractive in term of benefits for the whole Region. Table 5-4 Schedule of the interconnection projects selected Cases RGP_RIP and NGP_RIP Name From To Voltage Capacity Invest Year in-operation MW M$ RGP_RIP NGP_RIP TZ-KY_4S Tanzania Kenya 400 kV-AC 1520 117.0 2015 2015 TZ-UG_2S Tanzania Uganda 220 kV-AC 700 30.4 2015 2023 TZ-RW_2S Tanzania Rwanda 220 kV-AC 320 37.6 2015 2015 TZ-BR_2S Tanzania Burundi 220 kV-AC 280 47.9 2015 2015 ET-KY_5dS Ethiopia Kenya 500 kV-DC 2000 845.3 2016 2016 ET-SD_5S1 Ethiopia Sudan 500 kV-AC 1600 255.4 2016 2016 ET-SD_5S2 Ethiopia Sudan 500 kV-AC 1600 255.4 2016 2016 EG-SD_6dS Egypt Sudan 600 kV-DC 2000 1,033.9 2016 2016 UG-RW_2G1 Uganda Rwanda 220 kV-AC 520 51.3 2016 OUT ET-KY_5dG1 Ethiopia Kenya 500 kV-DC 2000 845.3 OUT 2020 ET-SD_5G1 Ethiopia Sudan 500 kV-AC 1600 255.4 2020 2020 EG-SD_6dG1 Egypt Sudan 600 kV-DC 2000 1,033.9 2020 2020 UG-KY_2G1 Uganda Kenya 220 kV-AC 440 71.0 OUT 2023 ET-SD_5G2 Ethiopia Sudan 500 kV-AC 1600 255.4 2025 2025 EG-SD_6dG2 Egypt Sudan 600 kV-DC 2000 1,033.9 2025 2025 5.5 Sensitivity analysis Four sensitivity analyses were done, two over the national generation plan and two over the regional generation plan, to evaluate the impact of important variables which could affect the interconnections projects. The first sensitivity is related with the possible limitation to only one interconnection of 2000 MW from Egypt to Sudan (cases NGP_RIP_S1 and RGP_RIP_S1), and the second case considers a doubling of the capital costs of the interconnection projects (NGP_RIP_S2 and RGP_RIP_S2). 5.5.1 National Generation Plans The Table 5-5 shows the schedule of the interconnection projects for the sensitivity analysis of the case NGP_RIP. In general there are no important variations in the schedule of the new interconnections projects for the different scenarios; the interconnections UG-KY_4G1 (1620 MW) is selected in 2016 for the scenario NGP_RIP_S1 and in 2023 for NGP_RIP_S2. UG-RW_2G1 (520 MW) is selected in 2016 for both scenarios NGP_RIP_S1 and
  • 242. Final Master Plan Report 5-13 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study NGP_RIP_S2. TZ-UG_2S is advanced to 2015 in both sensitivities. All interconnections projects already studied enter in service in the earliest available date. Table 5-5 Schedule of the interconnection projects selected Cases NGP_RIP (Base, S1, S2) Name From To Voltage Capacity Invest Year in-operation MW M$ NGP_RIP NGP_RIP_S1 NGP_RIP_S2 TZ-KY_4S Tanzania Kenya 400 kV-AC 1520 117.0 2015 2015 2015 TZ-UG_2S Tanzania Uganda 220 kV-AC 700 30.4 2023 2015 2015 TZ-RW_2S Tanzania Rwanda 220 kV-AC 320 37.6 2015 2015 2015 TZ-BR_2S Tanzania Burundi 220 kV-AC 280 47.9 2015 2015 2015 ET-KY_5dS Ethiopia Kenya 500 kV-DC 2000 845.3 2016 2016 2016 ET-SD_5S1 Ethiopia Sudan 500 kV-AC 1600 255.4 2016 2016 2016 ET-SD_5S2 Ethiopia Sudan 500 kV-AC 1600 255.4 2016 2016 2016 EG-SD_6dS Egypt Sudan 600 kV-DC 2000 1,033.9 2016 2016 2016 UG-RW_2G1 Uganda Rwanda 220 kV-AC 520 51.3 OUT 2016 2016 UG-KY_4G1 Uganda Kenya 400 kV-AC 1620 114.6 OUT 2016 2023 ET-KY_5dG1 Ethiopia Kenya 500 kV-DC 2000 845.3 2020 2020 2020 ET-SD_5G1 Ethiopia Sudan 500 kV-AC 1600 255.4 2020 2020 2020 EG-SD_6dG1 Egypt Sudan 600 kV-DC 2000 1,033.9 2020 OUT 2020 UG-KY_2G1 Uganda Kenya 220 kV-AC 440 71.0 2023 2023 2023 ET-SD_5G2 Ethiopia Sudan 500 kV-AC 1600 255.4 2025 2025 2025 EG-SD_6dG2 Egypt Sudan 600 kV-DC 2000 1,033.9 2025 OUT 2025 Note: Interconnections under study are identified by one “S” in the last part of their name. In the same way, existing and under construction Interconnections are identified with an “E” and “C” respectively. 5.5.2 Regional Generation Plans The Table 5-6 shows the schedule of the interconnection projects for the sensitivity analysis of the case RGP_RIP. For this case the variations are more important in relation with the changes observed in the case NGP_RIP. The main reason for that situation is because in the Regional Plans the generation projects could change simultaneously with the changes in the interconnections projects, while in the national plans all generation projects are fixed in the sensitivity analysis in relation with the base case. The main changes in the interconnections projects are the following: • The project TZ-KY_4S is delayed in the case RGP_RIP_S2 from 2015 to 2020 • The project UG-RW_2G1 is displaced in both sensitivities • The project UG-KY_4G1 is included in 2016 for the sensitivity 1 and in 2023 for the sensitivity 2. • The project ET-KY_5dG1 is included in 2020 in both sensitivities • The projects ET-SD_5G1 and ET-SD_5G2 are delayed from 2020 and 2025 to 2032 for the sensitivity 1 • The project UG-KY_2G1 is included in 2016 in the sensitivity 1 and in 2023 for the sensitivity 2.
  • 243. Final Master Plan Report 5-14 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 5-6 Schedule of the interconnection projects selected Cases RGP_RIP (Base, S1, S2) Name From To Voltage Capacity Invest Year in-operation MW M$ RGP_RIP RGP_RIP_S1 RGP_RIP_S2 TZ-KY_4S Tanzania Kenya 400 kV-AC 1520 117.0 2015 2015 2020 TZ-UG_2S Tanzania Uganda 220 kV-AC 700 30.4 2015 2032 2015 TZ-RW_2RS Tanzania Rwanda 220 kV-AC 320 37.6 2015 2015 2015 TZ-BR_2RS Tanzania Burundi 220 kV-AC 280 47.9 2015 2015 2015 ET-KY_5dS Ethiopia Kenya 500 kV-DC 2000 845.3 2016 2016 2016 ET-SD_5S1 Ethiopia Sudan 500 kV-AC 1600 255.4 2016 2016 2016 ET-SD_5S2 Ethiopia Sudan 500 kV-AC 1600 255.4 2016 2016 2020 EG-SD_6dS Egypt Sudan 600 kV-DC 2000 1,033.9 2016 2016 2016 UG-RW_2G1 Uganda Rwanda 220 kV-AC 520 51.3 2016 OUT OUT UG-KY_4G1 Uganda Kenya 400 kV-AC 1620 114.6 OUT 2016 2023 ET-KY_5dG1 Ethiopia Kenya 500 kV-DC 2000 845.3 OUT 2020 2020 ET-SD_5G1 Ethiopia Sudan 500 kV-AC 1600 255.4 2020 2032 2020 EG-SD_6dG1 Egypt Sudan 600 kV-DC 2000 1,033.9 2020 OUT 2020 UG-KY_2G1 Uganda Kenya 220 kV-AC 440 71.0 OUT 2016 2023 ET-SD_5G2 Ethiopia Sudan 500 kV-AC 1600 255.4 2025 2032 2025 EG-SD_6dG2 Egypt Sudan 600 kV-DC 2000 1,033.9 2025 OUT 2025 Note: Interconnections under study are identified by one “S” in the last part of their name. In the same way, existing and under construction Interconnections are identified with an “E” and “C” respectively. 5.6 Benefit-Cost analysis In this section, an analysis of the net benefits of the different levels of regional coordination is performed. For the computation of the benefits each case is compared with the references case where there is no regional coordination (NGP_EIC). The gross benefit is defined as the savings in generation costs (investment and variable O&M including fuel) and the net benefit subtracts from this value the investment and O&M of the interconnections. The present value (as of January 2013) of benefits and costs are evaluated using a discount rate of 10%. The Table 5-7 and the Figure 5-6 show the benefits for each scenario analyzed.
  • 244. Final Master Plan Report 5-15 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study Table 5-7 Benefit-Cost Analysis Present Values in MUS$ Cases  Generation Cost  Intercon Total  Benefit  Invest  O&M  Total  Cost  Cost  Gross 1 Net 2   Yearly 3   NGP_EIC  107,318  247,666  354,984 0 354,984 0 0  0 NGP_RIP   107,318  218,006  325,325 4,465 329,790 29,659 25,194  969 NGP_RIP_S1  107,318  225,872  333,190 3,458 336,648 21,794 18,336  705 NGP_RIP_S2  107,318  217,998  325,316 8,812 334,128 29,668 20,856  802 RGP_RIP  100,980  217,758  318,738 3,795 322,533 36,246 32,451  1,248 RGP_RIP_S1  103,593  223,929  327,522 2,698 330,220 27,462 24,764  952 RGP_RIP_S2  101,267  218,382  319,649 7,311 326,960 35,335 28,024  1,078                           1   Total generation cost of each scenario less scenario NGP_EIC           2   Gross benefit less Interconnection Cost                  3    Net benefit divided by 26 years                    Figure 5-6 Benefit-Cost Analysis As expected, the maximum benefit is obtained for the case where there’s coordination in the generation and interconnection expansion plans of the systems (RGP_RIP). The net benefit for this case amount to 32,451 MUS$ (equivalent to 1,248 MUS$/year) The lowest benefit is for the case NGP_RIP_S1 where there is no coordination in the generation expansion plan and the import capacity of Egypt is limited to only 2000 MW, for this case the net benefit
  • 245. Final Master Plan Report 5-16 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study amounts to 18,336 MUS$ (equivalent to 705 MUS$/year). The second higher net benefit is for the case RGP_RIP_S2, in which the capital costs of all interconnection projects double in relation with the base case; for this case the net benefit amount 28,024 MUS$ (equivalent to 1,078 MUS$/year). It is worth noting that the first level of regional coordination of interconnection projects potentially gives a sizable regional benefit (969 MUS$/year) as compared to the reference case while the second level of coordination (generation and interconnections) increase this benefit only marginally (to 1,248 MUS$/year).
  • 246. Final Master Plan Report 6-1 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 6 IDENTIFIED PROJECTS FOR FURTHER ANALYSIS IN PHASE II After the analysis for the national and regional plans in the preceding sections, a group of generation and interconnection projects have been identified that will be analyzed in further detail in phase II of this study. Projects which have been identified for the first five years of the study horizon (2013 – 2017) will undergo a more detail analysis. 6.1 Generation projects The potential list of regional generation projects was identified in section 7 of the WBS 1200 report: Generation Supply Study and Planning Criteria. Based on the analysis of the national plans and the regional plans in the present report (sections 4 and 5), the list of identified generation projects is shown in Table 6-1 below. These generation projects were selected because they have regional scope (identified as the best options either in the national and or regional plans). In some cases their on-power date is advanced in the regional plans (earlier than in the national plan), indicating that they are providing additional regional benefits. Table 6-1 Identified Generation Projects for Phase II Country Plant Name Type Installed Cap (MW) Eastern DRC Ruzizi III Hydro 145 Ruzizi IV Hydro 287 Piana Mwanga Hydro 29 Bengamisa Hydro 48 Babeda I Hydro 50 Semliki Hydro 28 Mugomba Hydro 40 Ethiopia Mandaya * Hydro 2000 Gibe III Hydro 1870 Border * Hydro 1200 Gibe IV Hydro 1468 Karadobi * Hydro 1600 Rwanda Kivu I Diesel 100 Kivu II Diesel 200 Tanzania Stieglers Gorge (I, II, III) * Hydro 1200 Uganda Karuma Hydro 700 Ayago Hydro 550 Murchison Falls Hydro 750 (*) projects with regional benefits: benefits increase when these are advanced with respect to the on-power date in the national plans.
  • 247. Final Master Plan Report 6-2 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study 6.2 Interconnection Projects Several interconnection projects have been identified after the analysis of the national and the regional plans. These are indicated in Table 6-2 below. Table 6-2 Identified Interconnection Projects for Phase II From To Type / Length Capacity (MW) Year in Operation Status Comments Tanzania Kenya 400 kV 2 circuits 260 Km 1520 2015* Ongoing FS, detailed design and tender documents preparation In the initial years helps to improve regional dispatch (reducing costs and deficits) and later makes possible trade in and out of Tanzania, taking advantage of hydro surpluses in Ethiopia and surpluses created by new projects in Tanzania’s national plan such as Ruhudji HPP (2016), Mnazibay NG (2017), Rumakali HPP (2018) and later from the Stieglers Gorge project (phase 1, 2 and 3). The advance of this interconnection to 2015 is to improve the regional dispatch. In general the flows go from Tanzania to Kenya, except in 2015. Bidding for line construction may start at the end of 2011. Tanzania Uganda 220 kV 2 circuits 85 Km 700 2023* Future In the initial years helps to improve regional dispatch (reducing costs and deficits) and later makes viable the export of surpluses in Uganda from hydro projects in the national plan such as Karuma HPP (2016) and Ayago HPP (2023/28). Rusumo Rwanda 220 kV 1 circuit 115 Km 320 2015* FS completed Lines associated to the Rusumo Falls HPP connecting the project with the grids of Tanzania, Rwanda and Burundi. Rusumo Burundi 220 kV 1 circuit 158 Km 280 2015* Rusumo Tanzania 220 kV 1 circuit 98 Km 350 2015*
  • 248. Final Master Plan Report 6-3 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study From To Type Capacity (MW) Year in Operation Status Comments Ethiopia Kenya 500 kV-DC bipole 1120 Km 2000 2016* Design and tender document preparation study to start early 2011 Allows for exports of hydro surplus in Ethiopia to the south and makes viable trade of surpluses in Kenya from the large Geo-thermal developments in the nation al plan. New design study aims at highly optimistic completion of phase I (1000 MW) of the project by 2013 and phase II upgrade to 2000 MW by 2019. Ethiopia Kenya 500 kV-DC bipole 1120 Km 2000 2020* Future Allows for exports of hydro surplus in Ethiopia to the south and makes viable trade to the north from large hydro developments in Tanzania (Stieglers Gorge phases 1,2, and 3) Ethiopia Sudan 500 kV 4 circuits 570 Km 3200 2016* FS completed Allows exports to the north from surplus hydro in Ethiopia. Several projects in the Ethiopian national plan contribute to the surplus: Gibe III HPP (1870 MW), Chemoya Yeda HPP (280 MW), and Halele Worabesa HPP (422 MW) which are expected to be completed by 2013. Ethiopia Sudan 500 kV 2 circuits 544 Km 1600 2020* Future Allows exports to the north from additional surplus hydro in Ethiopia. Several projects in the Ethiopian national plan contribute to the surplus: Baro I, II HPP (500 MW) and Genji HPP (200 MW) in 2020 and Mandaya HPP (2000 MW) in 2021. Ethiopia Sudan 500 kV 2 circuits 544 Km 1600 2025* Future Allows exports to the north from additional surplus hydro in Ethiopia. Several projects in the Ethiopian national plan contribute to the surplus: Karadobi HPP (1600 MW) in 2025 eventually Border HPP (1200 MW) in 2030. Egypt Sudan 600 kV-DC bipole 1665 Km 2000 2016* FS completed Allows imports from Ethiopian hydro surplus. Several projects in the Ethiopian national plan contribute to the surplus: Gibe III HPP (1870 MW), Chemoya Yeda HPP (280 MW), and Halele Worabesa HPP (422 MW) which are expected to be completed by 2013.
  • 249. Final Master Plan Report 6-4 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study From To Type Capacity (MW) Year in Operation Status Comments Egypt Sudan 600 kV-DC bipole 1665 Km 2000 2020* Future Allows imports from Ethiopian hydro surplus. Several projects in the Ethiopian national plan contribute to the surplus: Baro I, II HPP (500 MW) and Genji HPP (200 MW) in 2020 and Mandaya HPP (2000 MW) in 2021. Egypt Sudan 600 kV-DC bipole 1665 Km 2000 2025* Future Allows imports from Ethiopian hydro surplus. Several projects in the Ethiopian national plan contribute to the surplus: Karadobi HPP (1600 MW) in 2025 eventually Border HPP (1200 MW) in 2030. Uganda Kenya 220 kV 2 circuits 254 Km 440 2023 Future Allows for exports from hydro surpluses in Uganda associated with the Ayago HPP (550 MW) in 2023/28. Uganda Kenya 220 kV 2 circuits 254 Km 300 2014 Under construction Runs from Lessos substation in Kenya to Bujagali substation passing through Tororo substation in Uganda, duplicating the existing 132kV line. Uganda Rwanda 220 kV 2 circuits 172 Km 250 2014 Detailed and Tender Documents preparation study starts in 2011 Line from Mbarara to Mirama (border Uganda) to Birembo/Kigali (Rwanda) Rwanda DRC 220 kV 1 circuit 68 Km 370 2014 Under construction Line between new substation at Kibuye Methane Gas plant in Rwanda and Goma (DRC), thus completing the loop around lake Kivu.
  • 250. Final Master Plan Report 6-5 WBS 1300 Supply Demand Analysis May 2011 & Project Identification EAPP/EAC Regional PSMP & Grid Code Study From To Type Capacity (MW) Year in Operation Status Comments DRC Burundi 220 kV 1 circuit 105 Km 330 Expected in 2014 FS, detailed engineering and tender documents preparation study to start early 2011 Line from future substation Kamanyola/Ruzizi III (DRC) to Bujumbura (Burundi). Study Includes 220kV line between a new substation in Bujumbura to Kiliba (DRC). Burundi Rwanda 220 kV 330 2016 FS update to start early 2011 Line Rwegura (Burundi) – Kigoma (Rwanda), previous FS recommended 110kV. Feasibility Study update to re-examine 220kV option and re-route line to feed intermediate locations. Notes: (*) Project enters in the earliest on power date.
  • 251. www.snclavalin.com SNC-LAVALIN Inc. T&D Division 1801 McGill College Ave. Montreal, Quebec Canada H3A 2N4 Tel.: (514) 393-1000 Fax: (514) 334-1446

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