Planning Parameters and Generation Options Report

The World Bank Group & Electricity Control Board of Namibia - National Integrated Resource Plan Planning Parameters and Generation Options Draft Report – 16 July, 2012

The World Bank Group & Electricity Control Board of Namibia National Integrated Resource Plan

Planning Parameters and Generation Options Draft Report

Prepared by: 16 July , 2012 Anibal Carias, Guangbin Lian Date

Approvals

Hatch

Approved by: 16 July , 2012 Bob Griesbach Date

The World Bank Group & Electricity Control Board of Namibia

Approved by: Date

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The World Bank Group & Electricity Control Board of Namibia - National Integrated Resource Plan Planning Parameters and Generation Options Draft Report – 16 July, 2012

Disclaimer This report has been prepared by Hatch Ltd. (Hatch) for the sole and exclusive use of The World Bank Group & Electricity Control Board of Namibia (the “Clients” or “WBG & ECB”) for the purpose of assisting the Clients in developing the National Integrated Resource Plan and shall not be (a) used for any other purpose, or (b) provided to, relied upon or used by any third party.

Notwithstanding the foregoing, Hatch acknowledges that the Clients may make this report available electronically to interested third parties through internet web access, provided that all such parties shall rely upon this report at their own risk and shall (by virtue of their use of this report) be deemed to have (a) acknowledged that Hatch shall not have any liability to any party other than the Clients in respect of the report and (b) waived and released Hatch from any liability in connection with the report.

This report contains opinions, conclusions and recommendations made by Hatch, using its professional judgment and reasonable care. Use of or reliance upon this report by the Clients is subject to the following conditions:

i) the report being read in the context of and subject to the terms of the Agreements between Hatch and the Clients dated 24 June, 2011 (the “Agreements”), including any methodologies, procedures, techniques, assumptions and other relevant terms or conditions that were specified or agreed therein; ii) the report being read as a whole, with sections or parts hereof read or relied upon in context; iii) the conditions may change over time (or may have already changed) due to natural forces or human intervention, and Hatch takes no responsibility for the impact that such changes may have on the accuracy or validity or the observations, conclusions and recommendations set out in this report; and iv) the report is based on information made available to Hatch by the Clients or by certain third parties; and unless stated otherwise in the Agreement, Hatch has not verified the accuracy, completeness or validity of such information, makes no representation regarding its accuracy and hereby disclaims any liability in connection therewith.

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The World Bank Group & Electricity Control Board of Namibia - National Integrated Resource Plan Planning Parameters and Generation Options Draft Report – 16 July, 2012

Table of Contents

Disclaimer ...... ii List of Acronyms and Abbreviations ...... xi 1. Introduction ...... 1 1.1 Background ...... 1 1.2 Purpose of the Planning Parameters and Generation Options Report ...... 2 1.3 Report Contents ...... 3 1.3.1 Report Outline ...... 3 1.3.2 Reference Scope of Work ...... 4 1.4 Information Collection ...... 5 2. Existing Electricity Sector ...... 7 2.1 Introduction ...... 7 2.2 Institutional Framework ...... 7 2.3 Electricity Demand ...... 9 2.4 Existing and Committed Supply Facilities ...... 13 2.4.1 Local Generation Facilities ...... 13 2.4.2 Imports ...... 17 2.5 Transmission and Distribution ...... 21 2.6 Interconnections ...... 24 2.7 Electricity Supply Licences ...... 24 2.8 Other Generation Included in the Short Term Critical Supply Program ...... 25 3. Supply and Demand Situation ...... 27 3.1 Introduction ...... 27 3.2 The Energy Policy White Paper ...... 27 3.3 Demand Forecast ...... 29 3.4 Short Term Demand and Supply Situation ...... 32 4. Planning Parameters and Criteria ...... 40 4.1 Introduction ...... 40 4.2 General and Economic Parameters ...... 40 4.2.1 National Focus...... 40 4.2.2 Planning Horizon ...... 41 4.2.3 Cost and Present Worth Datum ...... 41 4.2.4 Escalation ...... 41 4.2.5 Currency ...... 41 4.2.6 Discount Rate ...... 42

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4.2.7 Foreign Exchange Rate...... 42 4.2.8 Insurance and Interim Replacement ...... 42 4.2.9 Cost of Expected Unsupplied Energy ...... 42 4.2.10 Cost of Losses ...... 42 4.2.11 Duties and Taxes ...... 43 4.2.12 Interest during Construction (IDC) ...... 43 4.3 Generation ...... 43 4.3.1 Committed Generation Additions...... 43 4.3.2 Retirement of Existing Generating Facilities ...... 44 4.3.3 Reliability Criteria ...... 44 4.3.4 Emissions Criteria ...... 45 4.3.5 Candidate Thermal Generation Resources ...... 46 4.4 Fuel Price Forecast ...... 48 4.4.1 Fuel Background in Namibia...... 48 4.4.2 Underlying Assumptions ...... 49 4.4.3 Crude Oil Forecast ...... 50 4.4.4 Price Forecast for Kudu Natural Gas ...... 53 4.4.5 Estimate of Natural Gas Price from Liquefied Natural Gas ...... 55 4.4.6 Coal Price Forecast ...... 57 4.4.7 Price Forecast of Other Fuels ...... 58 4.4.8 Heat Content of Fuels and Unit Prices of Energy ...... 58 4.5 Transmission ...... 59 4.5.1 Study Area and Horizon ...... 60 4.5.2 Technical Criteria ...... 60 4.5.3 Capital Costs and Economic Criteria ...... 62 5. Generation Resources and Technologies ...... 63 5.1 Introduction ...... 63 5.2 Primary Generation Resources ...... 63 5.2.1 Coal Fired Power Plants ...... 63 5.2.2 Natural Gas Including LNG Fueled Power Generation ...... 68 5.2.3 Fuel Oil Fired Power Generation...... 73 5.2.4 Nuclear Power Generation ...... 76 5.2.5 Hydro Electric Power Generation ...... 80 5.2.6 Wind Power Plant ...... 86 5.2.7 Solar PV Power Plant ...... 89 5.3 Imports from SAPP ...... 90 5.3.1 Imports Likely to be Pursued ...... 91 5.3.2 Imports Unlikely to be Pursued ...... 92 5.3.3 Expected Costs of Imports ...... 93

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5.4 Demand Side Management and Energy Efficiency ...... 95 5.4.1 CFL Program in the Residential Sector ...... 96 5.4.2 Residential Solar Waters Heaters Dissemination ...... 96 5.4.3 Commercial and Institutional Buildings SWH Dissemination ...... 97 5.4.4 Subsidized Energy Audits ...... 97 5.4.5 Commercial and Institutional Energy Efficient Lighting ...... 98 5.4.6 Ripple Control of Electrical Water Heaters in Large Cities ...... 98 5.4.7 Commercial and Institutional Air Conditioning Systems ...... 99 5.4.8 Information Dissemination and Public Awareness ...... 99 5.4.9 Energy Audit and Implementation in Large Industry ...... 100 5.4.10 Use of Customer Generation to Reduce Grid Peak ...... 100 5.4.11 Summary of Selected DSM Programs ...... 101 5.5 Secondary Generation Options with Quantified Resources but Non-mature Technology ...... 102 5.5.1 Small Modulated Nuclear Reactor Power Generation ...... 102 5.6 Secondary Generation Options with Mature Technology but Non-quantified Resources ...... 104 5.6.1 Wind Power Generation ...... 105 5.6.2 Solar PV Power Generation ...... 106 5.6.3 Solar Thermal Power Generation ...... 108 5.6.4 Power Generation Using Municipal Solid Waste ...... 110 5.6.5 Bio-fuels Power Generation ...... 112 5.6.6 Biomass ...... 114 5.6.7 Geothermal Power Generation ...... 117 6. Grid Integration ...... 135 6.1 Introduction ...... 135 6.2 The 800 MW Kudu Gas Power Station ...... 136 6.2.1 Transmission Grid Connections ...... 137 6.3 The 600 MW Baynes Hydro Power Station ...... 138 6.3.1 Grid Connection Using 400 kV Lines and Substations Only (Option 1) ...... 140 6.3.2 Grid Connection Using 400 kV Lines and Substations but also Recycling an AC Line to DC (Option 2) ...... 141 6.4 2 x 200 MW Nuclear Power Station Units near Walvis Bay ...... 142 6.5 The 300 MW Erongo Coal Power Station near Walvis Bay ...... 144 6.5.1 Transmission Grid Connections ...... 145 6.6 The 300 MW Combined Cycle Gas Turbine near Walvis Bay ...... 146 6.6.1 Transmission Grid Connections ...... 147 6.7 The 60 MW INNOWIND Wind Farm near Walvis Bay ...... 148 6.7.1 Transmission Grid Connections ...... 149

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6.8 The 44 MW Diaz Wind Farm near Luderitz ...... 149 6.8.1 Transmission Grid connections ...... 150 6.9 The 10 MW Keetmanshoop Solar Farm ...... 151 6.9.1 Transmission Grid connections ...... 152 6.10 Summary of Capital Cost for Grid Integration ...... 152 7. Environmental and Social Assessment of Generation Options ...... 163 7.1 Introduction ...... 163 7.2 Generation Options ...... 163 7.3 Assumptions and Limitations ...... 165 7.4 Approach ...... 166 7.5 Environmental and Social Issues Assessment ...... 170 7.5.1 Generic Issues Assessment ...... 170 7.5.2 Generation Options Issues Assessment ...... 174 7.6 Discussion...... 201 8. Evaluation of the Generation Options ...... 201 8.1 Least Cost Supply Options ...... 201 8.1.1 Unit Cost of Energy for Hydroelectric ...... 202 8.1.2 Unit Cost of Demand Side Management and Energy Efficiency Projects ...... 203 8.1.3 Unit Cost of Energy for Base Load Plants ...... 203 8.1.4 Unit Cost of Energy for Peaking Plants ...... 206 8.1.5 Unit Cost of Energy for Renewable Energy Resources ...... 209 8.1.6 Other Resources ...... 212 8.1.7 Summary of Analysis ...... 212 8.2 Optimal Mix of Imports and Domestic Sources ...... 217 8.3 Next Steps ...... 217

List of Tables

Table 2-1 Ruacana Generating Capacity Table 2-2 Characteristics of the van Eck Coal Power Plant Table 2-3 Characteristics of the Walvis Bay Diesel Plants Table 2-4 ZESCO and ZESA Blended Import Tariffs Table 2-5 Imports of Energy Over the Last 7 Years Table 2-6 List of Conditional IPP Generation Licences

Table 3-1 Reference Scenario Demand Forecast Table 3-2 Energy and Capacity Balance for the Namibian System – 2012

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Table 3-3 Comparison of 2015 Energy Balance

Table 4-1 Candidate Plants Characteristic Life and Outages Table 4-2 Economic Price of Kudu Natural Gas Table 4-3 Heat Content of Fuels – HHV Table 4-4 Unit Price of Fuels (HHV)

Table 5-1 Coal Power Generation Table 5-2 Natural Gas Fired Power Generation Table 5-3 Fuel Oil Fired Power Generation Table 5-4 Nuclear Power Generation Table 5-5 Hydro Electric Power Generation Table 5-6 Wind Power Generation Table 5-7 Solar PV Power Generation Table 5-8 Potential Imports from SAPP Table 5-9 Cost of Likely Imports Table 5-10 Summary of DSM Program Impacts and Costs Table 5-11 Small Modulated Nuclear Reactor Power Generation Table 5-12 Solar Thermal Power Generation Table 5-13 Power Generation Using Municipal Solid Waste Table 5-14 Bio-Fuel Power Generation Table 5-15 Biomass Power Generation Table 5-16- Geothermal Power Generation

Table 6-1 Summary of Equipment Required for Kudu Integration Table 6-2 Transmission Integration Requirements for Bayne Power Station – Option 1 Table 6-3 Transmission Integration Requirements for Bayne Power Station – Option 2 Table 6-4 Summary of Equipment Required for Erongo Coal Power Station Integration Table 6-5 Summary of Equipment Required for the Walvis Bay CCGT Integration Table 6-6 Summary of Equipment Required for the Innowind Wind Farm Grid Integration Table 6-7 Summary of Equipment Required for the Diaz Wind Farm Integration Table 6-8 Summary of Equipment Required for the Keetmanshoop Solar Grid Integration Table 6-9 Summary of Estimated Costs for Grid Connection

Table 7-1 Primary and Secondary Generation Options Indentified in the Project Table 7-2 Criteria for Rating Scales Table 7-3 Consequence Rating Table 7-4 Significance Rating Table 7-5 Generic Issues Assessment Table 7-6 Issues Assessment Rating for Coal Generation Options

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Table 7-7 Issues Ratings for Natural Gas Table 7-8 Issues Ratings for Uranium Table 7-9 Issues Ratings for Light Oil and Heavy Fuel Oil Table 7-10 Issues Ratings for Hydro Table 7-11 Issues Ratings for Wind Table 7-12 Issues Ratings for Solar Table 7-13 Issues Ratings for Municipal Solid Waste Table 7-14 Issues Ratings for Biofuel Table 7-15 Issues Ratings for Biomass

Table 8-1 Unit Cost of Energy for Hydroelectric Plants Table 8-2 Unit Cost of Energy Savings from DSM and Energy Efficiency Programs Table 8-3 Unit Cost of Energy for Base Load Generation (N$/kWh) Table 8-4 Unit Cost of Energy for Base Load plants at 80% Capacity factor Table 8-5 Unit Cost of Energy for Peaking Plants (N$/kWh) Table 8-6 Unit Cost of Energy for Renewable Energy Plants (N$/kWh) Table 8-7 Unit Cost of Energy for Wind and Solar Generation Table 8-8 Unit Cost of Energy for Options Retained (N$/kWh)

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The World Bank Group & Electricity Control Board of Namibia - National Integrated Resource Plan Planning Parameters and Generation Options Draft Report – 16 July, 2012

List of Figures

Figure 2-1 The Electricity Supply Industry in Namibia Figure 2-2 Annual Load Duration Curves Figure 2-3 Monthly Peak Demand Figure 2-4 Monthly Energy Figure 2-5 Time of Use Schedule Figure 2-6 Transmission System in Namibia

Figure 3-1 Reference Scenario Demand Forecast Including Historical Values Figure 3-2 Monthly Capacity Balances for 2012 to 2015 Figure 3-3 Monthly Energy Balances for 2012 to 2015

Figure 4-1 Crude Oil Price Forecast Figure 4-2 Unit Energy Price – Distillate Fuel Figure 4-3 Unit Energy Price – Residual Fuel Figure 4-4 Natural Gas Price Forecast Figure 4-5 Coal Price Forecast

Figure 6-1 Namibia Power Network Figure 6-2 The Proposed Kudu Gas Power Station Integration Options Figure 6-3 Network Diagram for Kudu Gas Integration Figure 6-4 Baynes Hydro Integration – Option 1 Figure 6-5 Baynes Hydro Integration – Option 2 Figure 6-6 Option 1 for the Proposed Network Connection for Baynes Power Station Figure 6-7 Option 2 for the Proposed Network Connection for Baynes Power Station Figure 6-8 Immediate Network Upgrades Required for Operating Nuclear Facilities Figure 6-9 The Erongo Power Station Grid Interconnection Figure 6-10 The Erongo Coal Power Station Grid Integration SLD Figure 6-11 The Walvis Bay CCGT Grid Integration Figure 6-12 Walvis Bay CCGT Grid Integration SLD Figure 6-13 The Innowind Wind Farm Grid Integration SLD Figure 6-14 Innowind Wind Farm Grid Integration Figure 6-15 The Diaz Wind Farm Grid Integration near Luderitz Figure 6-16 Diaz Wind Farm Grid Integration SLD Figure 6-17 The Keetmanshoop Solar Farm Grid Integration Figure 6-18 The Keetmanshoop Solar Farm Grid Integration SLD

Figure 8-1 Unit Cost of Energy for Base Load Plants Figure 8-2 Total Annual Costs of Base Load Plants

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Figure 8-3 Unit Cost of Energy for Peaking Plants Figure 8-4 Total Annual Costs of Peaking Plants Figure 8-5 Unit Cost of Energy for Renewable Energy Resources Figure 8-6 Total Annual Costs of Renewable Energy Resources Figure 8-7 Unit Cost of Energy for Options Retained Figure 8-8 Total Annual Costs of Options Retained

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The World Bank Group & Electricity Control Board of Namibia - National Integrated Resource Plan Planning Parameters and Generation Options Draft Report – 16 July, 2012

List of Acronyms and Abbreviations

AC Alternating Current AGR Advanced Gas Cooled Reactor BATNEEC Best Available Technology Not Entailing Excessive Cost BBL Barrel BFB Bubbling Fluidized Bed BPC Botswana Power Corporation BWR Boiling Water Reactor CBEND Combating Bush Encroachment for Namibia Development CCGT Combined Cycle Gas Turbine CCS Carbon Capture Sequestration CEC Copperbelt Energy Corporation in Zambia CFB Circulating Fluidized Bed CFL Compact Fluorescent Lamp CNG Compressed Natural Gas COUE Cost of Unserved Energy CSP Concentrated Solar Power DC Direct Current DOE Department of Energy (USA) DRC Democratic Republic of Congo DRFN The Desert Research Foundation of Namibia DSM Demand Side Management ECB Electricity Control Board of Namibia EDM Electricidade de Moçambique EIA The U.S. Energy Information Agency EMD Electro-Motive Diesel EPA The U.S. Environmental Protection Agency

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The World Bank Group & Electricity Control Board of Namibia - National Integrated Resource Plan Planning Parameters and Generation Options Draft Report – 16 July, 2012

EPC Engineering, Procurement and Construction EPRI Electric Power Research Institute ESEIA Environmental and Socio-Economic Impact Assessment ESI Electricity Supply Industry Eskom Electricity Supply Commission of South Africa ESP Electrostatic Precipitator EUE Expected Unserved Energy EWH Electric Water Heater FGD Flue Gas Desulphurization FPS Floating Process Station FOA Funding Opportunity Announcement F.O.R. Forced Outage Rate GCR Gas Cooled Reactor GDP Gross Domestic Product GHG Greenhouse Gas GJ Giga Joule GRN Government of the Republic of Namibia GT Gas Turbine GTL Gas To Liquid HAWT Horizontal Axis Wind Turbine HFO Heavy Fuel Oil HHV Higher Heating Value HRSG Heat Recovery Steam Generator HVDC High Voltage Direct Current IAEA International Atomic Energy Agency IDC Interest During Construction IEA International Energy Agency IGCC Integrated Gasification Combined Cycle

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IRP Integrated Resource Plan IPP Independent Power Producer KBF Kavango Bio-Fuels Km Kilometer, i.e. One Thousand Meters kW Kilowatt, i.e. One Thousand Watts LDC Load Duration Curve LFO Light Fuel Oil LHV Lower Heating Value LNG Liquefied Natural Gas LOHEPS Lower Orange Hydro Electric Power Stations LOLP Loss of Load Probability LWGR Light Water Cooled Graphite Moderated Reactor MCR Maximum Continuous Rating MMA McLennan Magasanik Associates MME Ministry of Mines and Energy MSD Medium Speed Diesel MSW Municipal Solid Waste MW Megawatt, i.e. One Million Watts MWAF Ministry of Water Affairs N$ Namibian Dollar NAMCOR National Petroleum Corporation of Namibia NEPC Namibia Energy Planning Committee NER National Electricity Regulator NERC North American Electric Reliability Corporation NG Natural Gas NIRP National Integrated Resource Plan NPP Nuclear Power Plant NRC The U. S. Nuclear Regulatory Commission

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O&M Operation & Maintenance PC Pulverized Coal PHWR Pressurized Heavy Water Moderated Reactor PJ Peta Joule, i.e. 1,000 trillion joules PPA Power Purchase Agreement PV Solar Photovoltaic PWR Pressurized Water Reactor RDF Refuse Derived Fuel RED Regional Electricity Distributor REEEI Renewable Energy and Energy Efficiency Institute RBS Revised Balanced Scenario SA South Africa SACU Southern Africa Customs Union SAPP Southern African Power Pool SAPP STEM SAPP Short Term Energy Market SC Steering Committee SNEL Société Nationale d'Electricité SMR Small Modular Nuclear Reactor

SO2 Sulphur Dioxide SST Sub Synchronous Resonance STCS Short Term Critical Supply SWH Solar Water Heater TCF Trillion Cubic Feet TCM Trillion Cubic Meters TOR Terms of Reference US The United States of America US$ The United States of America Dollar USTDA United States Trade and Development Agency

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VSI Voltage Source Inverter W Watt WBG The World Bank Group WNA World Nuclear Association ZESA Zimbabwe Electricity Supply Authority ZESCO Zambia Electricity Supply Corporation WTE Waste to Energy

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1. Introduction Hatch was retained by The World Bank Group (WBG) and the Electricity Control Board (ECB) of Namibia to assist in developing a National Integrated Resource Plan (NIRP) for Namibia focusing on electricity. As part of the work associated with the NIRP, Hatch is required to generate several deliverables. This document, the Planning Parameters and Generation Options Report, focuses on meeting the deliverables for Task 3 of the overall assignment and deals principally with the definition and evaluation of the generation options and corresponding transmission requirements to meet present and future electricity demand in Namibia.

The report also addresses other items not specifically included in the Task 3 deliverables but which are essential to carry out the analysis of the various system expansion alternatives when considering the various supply/generation/transmission resources.

1.1 Background As background information it is helpful to introduce the general concept of the NIRP. The NIRP is a 20 year electricity sector development plan. It aims to provide an indication of Namibia’s electricity demand, how this demand could be supplied and the cost of supply. The NIRP does not deal explicitly with the overall energy needs for the country but focuses on electricity. The plan is expected to be dynamic and be continuously revised and updated to incorporate the latest available information and technologies.

In the recent past, Namibia has relied on imports of electricity from outside sources to meet a large portion of its electricity demand requirements. The imports have been obtained mainly from South Africa, Zimbabwe and Zambia with contributions from Mozambique and the Democratic Republic of Congo. However, some of the traditional sources for the imports are suffering supply constraints themselves to meet increasing internal demand and cannot guarantee continuation of firm energy supply to Namibia.

An Energy Policy White Paper was introduced in 1998 establishing certain goals in the electricity sector; some of these goals included:

 Security of supply  Improving electricity sector efficiency through restructuring  Electricity pricing reform  Improved access to electricity in both urban and rural areas  Promotion of investment in the electricity sector

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The World Bank Group & Electricity Control Board of Namibia - National Integrated Resource Plan Planning Parameters and Generation Options Draft Report – 16 July, 2012

 Improved sector governance. Unfortunately some of the goals are facing some challenges in being implemented and lack champions to drive them through some of the difficult implementation stages. A new Energy Policy is being developed but is not expected to be available for stakeholder input until May or June 2012 at the earliest. In view of this it has been agreed that this NIRP should thus follow the guidelines outlined in the existing Policy as the new policy guidelines are expected only after the analysis and evaluation required to arrive at the recommended NIRP are completed or near completed.

NamPower operates three main businesses - generation, trading and transmission of electricity. NamPower's main domestic sources of power are the coal-fired Van Eck Power Station outside Windhoek (120 MW), the hydroelectric plant at Ruacana Falls in the Kunene Region (240 MW), the standby diesel-driven Paratus Power Station (24 MW) at Walvis Bay and the diesel plant at Anixas (22.5 MW). A fourth unit at Ruacana (92 MW) was commissioned on May 31, 2012 adding approximately 92 MW to the plant’s installed capacity.

With a peak demand of 511 MW (without the Skorpion load) in July, 2011, the above internal resources are clearly not sufficient to meet the demand and Namibia has limited options for using existing resources to meet the increasing demand and cater for diminishing firm imports. Yet there are opportunities to develop other resources. Namibia has one of the highest insolation levels, there are locations with attractive wind regimes, in the north there are thousands of hectares of invader bush which could be used as a source of fuel and the Kunene River has additional potential for hydroelectric development. In addition, there is a major offshore natural gas field that could support upwards of 800 MW of combined cycle generation. The present report will examine the suitability of these resources to meet the increasing demand.

It is recognized that the development of the NIRP requires the input of all stakeholders in the Electricity Supply Industry (ESI) in Namibia and these are to be involved as participants in the NIRP development process and several workshops have been held with more planned to obtain their input.

1.2 Purpose of the Planning Parameters and Generation Options Report The principal goal of the NIRP is to identify the supply mix of resources to meet the near and long-term electric power needs in Namibia in a sustainable, efficient, safe and reliable manner at the lowest reasonable cost. The NIRP is to be focused on electricity supply, but should also take into account the impact of developing other energy sources

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and demand side management measures capable of reducing electricity demand in Namibia.

The Planning Parameters and Generation Options Report has been prepared to identify the need for new generation additions taking into account the increase in demand, the aging of the existing generation fleet, the possibility of curtailment of imports from other networks and the implementation of the security of supply aspects outlined in the 1998 White Paper on Energy Policy.

The report also elaborates further on some of the parameters presented in the Key Assumptions Report (October 2011) to provide revised values for some parameters presented in that report and presents additional parameters required to carry out the overall analysis in the development of the alternative expansion sequences.

The planning procedures to be used in formulating, developing and analysing each of the expansion alternatives are presented in order to obtain a general consensus on the methodology to be used in the next phase of the work from amongst all the stakeholders.

1.3 Report Contents This subsection outlines the contents of each main report sections and provides a brief overview of the Scope of Work as outlined in the Terms of Reference.

1.3.1 Report Outline This report has eight sections which are as follows:

Section 1 Introduction, presents the project background, the purpose of the report, reference to the required work and data collection activities

Section 2 Existing Electricity Sector, provides a summary of the electricity sector in Namibia including the institutional framework, the use of electricity, the existing and committed generation facilities and the transmission and interconnection facilities

Section 3 Supply and Demand Situation, summarizes the existing energy policy, presents the likely demand in Namibia for the next 20 years and presents the short term demand/supply balance based on the existing facilities and the committed additions

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Section 4 Planning Parameters and Criteria, presents the parameters to be used throughout the study related to economics, including expected GDP, discount rate, exchange rates and shadow prices, generation including reliability criteria, committed additions and candidate generation resources, fuel prices and transmission

Section 5 Generation Resources and Technologies, presents a list of primary and secondary generation resources along with imports and DSM measures that could be available to meet the increased resource requirements. The section defines the resources, presents their costs and identifies any potential environmental and social issues

Section 6 Grid Integration, discusses the equipment required to connect various generation options to the grid and provides order of magnitude costs for this equipment

Section 7 Environmental and Social Assessment of Generation Options, presents the environmental and social issues identified for each applicable generation option

Section 8 Evaluation of the Generation Options – presents an economic evaluation of the generation options outlined in Section 5 and considering the fuel costs developed in Section 4.

1.3.2 Reference Scope of Work The integrated resource planning work is to be built on principles of a comprehensive and holistic analysis taking into consideration the country’s overall goals, resource base, demand structure, and its regional and international setting.

The scope of work for Task 3 – Definition and evaluation of generation options, import sources and demand management options is listed in the terms of reference Section 4.3 and is summarized below.

1) Review coal, gas, hydro, wind, solar and nuclear amongst other possible generation options in Namibia 2) List all known possible options to import electricity to Namibia 3) List all known possible demand management and energy efficiency options in Namibia, including options that could substitute electricity use, such as biofuels, gas and solar heating

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4) Assess and quantify each prime generation option 5) Assess and quantify each demand management option 6) Assess and quantify each import option 7) Assess and estimate each secondary generation option with quantifiable resource but non-mature technology (at an appropriately lower accuracy and confidence level as prime options) 8) Assess and estimate each secondary generation option with non-quantified resource but mature technology (at an appropriately lower accuracy and confidence level as prime options).

As part of Task 3, the Consultant is to deliver the following:

Draft data tables listing primary and secondary generation options and their detailed characteristics:

1) Draft data tables listing import options and their detailed characteristics 2) Draft data tables listing demand side management options and their detailed characteristics 3) Determine the least cost supply options to the country 4) Determine the optimal mix for imported and domestically produced electricity in Namibia and its impact on security of supply of electricity in the country 5) A stakeholder workshop where the options are presented and discussed and where stakeholder inputs regarding the options are solicited 6) Final data tables taking into account stakeholder input, to be approved by the NIRP- SC.

1.4 Information Collection The contract for this project was signed by all parties on 24 June, 2011 with an effective date of 1 July, 2011. The Inception Mission took place during the period 17 July, 2011 through 29 July, 2011 during which time a team of three Hatch consultants visited Namibia and were complemented by representatives of the local sub consultant, EMCON. During that period several meetings were held with some relevant authorities to collect information and discuss the NIRP. During the Inception Mission key stakeholders were identified to be contacted during the next stage of the project.

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A system data collection mission was undertaken from 18 September to 7 October, 2011. During this period meetings were held in Windhoek with several departments at NamPower including demand forecasting, transmission planning, generation, development planning, finance and trading. Meetings were also held with the National Planning Commission (NPC) to collect information on GDP and population forecasts as well as with NAMCOR to discuss the development of the Kudu gas field. Very few reports and data files were collected with the information assembled being mainly of the verbal type.

A second system data collection mission was undertaken from 27 November to 8 December, 2011, to conduct additional meetings and collect additional data. NamPower made available several reports for review, at their offices, addressing the principal resources to be considered in the NIRP. During this second mission, Hatch also visited the developer of the Kudu gas field.

Hatch’s DSM and Energy Efficiency specialists visited Namibia from February 20 to February 29 and from February 19 to March 2 respectively to collect data and meet the relevant key stakeholders. During the period February 27 to March 29 work was carried out in Namibia to produce this report and additional data collection was carried out.

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2. Existing Electricity Sector 2.1 Introduction This section provides a summary of the electricity sector in Namibia including the institutional framework, the electricity demand, the existing and committed generation facilities and the transmission and interconnection facilities. It also identifies other generation available to meet the short term requirements.

The Namibian power sector has been undergoing sector reform in the last several years and progress has been made in restructuring the Electricity Supply Industry (ESI). Work is ongoing on the sector’s structure and framework and some recommendations for modifications are being studied by ECB, Ministry of Mines and Energy (MME) and relevant stakeholders.

Presently there are several entities active in the power sector in the generation and distribution field but there are no large scale independent power producers (IPP). However, the ECB has issued 10 conditional licenses for generation using both renewable energy and conventional technologies.

Currently, Namibia imports the majority of its electricity from ZESA in the Republic of Zimbabwe, Eskom in South Africa (SA) ZESCO in Zambia with smaller amounts from other countries in the region.

2.2 Institutional Framework The ESI is regulated by the ECB subject to the powers vested in the regulator under the Electricity Act of 2007. Under the Act, any person engaged in the generation, transmission, distribution, supply, import or export of electricity must obtain a license from the ECB for such operations. Individual licenses are required for each of these activities. There are well-defined processes for such license applications; the general license conditions have been developed by the ECB and are generally well understood.

It is important to note that the ECB’s independence is limited by the fact that the final decision on licensing matters rests with the Minister of Mines and Energy. The ECB’s role is to evaluate the applications and make recommendations to the Minister. Licenses are valid up to 50 years and can be renewed for an additional 50 years. Licenses can be amended and ministerial approval is required for the transfer of a license.

Trading of electricity is to be done through the electricity market but NamPower is the only trader as well as the system operator and a vertically integrated power utility.

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Under the Electricity Act, transmission and distribution companies must provide access to all existing and potential users of these systems (open access) at a fee.

An overview of the industry’s major players is given in Figure 2-1.

Figure 2-1 - The Electricity Supply Industry in Namibia The MME is the policy maker in the ESI. The MME has developed the Energy Policy that has, since 1998, been the overall guiding document for the ESI. The Electricity Act was developed under guidance from this policy, as have the restructuring actions that have taken place. The Energy Policy to this day serves as the baseline for policy in the ESI. The Energy Policy is currently being revised and an updated policy could be published before the end of 2012.

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The ECB is the regulator in the ESI. The ECB has a non-executive board and is staffed with a chief executive officer supported by various staff members who perform technical and administrative functions. The ECB deals with the day-to-day administration of the ESI, which principally amounts to the management of licenses, management of tariffs and interactions with licensees. The ECB is also instrumental in developing regulations under the Act.

The Government of Namibia has made a decision to change the role of the ECB from an electricity regulator to an energy regulator. Implementation is targeted for mid-2012.This decision is expected to have far-reaching implications for Namibia’s energy sector as a whole.

The electricity market is basically a single buyer market where all generators have to sell their production and where all consumers have to buy their demand. NamPower is the single buyer. There are developments under way for the establishment of a modified single buyer market where generators could sell directly to large users and distribution companies.

The main licensees in Namibia are NamPower, the Regional Electricity Distributors (REDs) and local and regional authorities that distribute electricity. Conditional licenses have also been issued to several IPPs for the development of renewable energy resources. NamPower encompasses three main ring-fenced businesses, namely generation, trading and transmission. There is currently also a distribution component within transmission, but NamPower is gradually pulling out of direct distribution.

NamPower in its role as system operator and trader currently has the important role of balancing supply and demand, and it is the contracting party for imports, primarily from Eskom, ZESA and ZESCO. As such, NamPower seeks to optimally balance its own generation with imports and thereby obtain the best possible cost scenario. In essence, NamPower is responsible, as the Single Buyer, to buy electricity outside Namibia and sell inside the country.

2.3 Electricity Demand The power sector in Namibia is dominated by NamPower, which is responsible for most generation, transmission and a portion of the distribution business. The remainder of the distribution sector is served by several REDs (Nored, Cenored, Erongo Red), local and regional authorities and other distributors. As far as the development of the NIRP is concerned, some of the important demand aspects include the energy and peak demand

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that has to be sent to the system, the individual distribution of the peak demand throughout the various high and medium voltage substations in the country, the distribution of individual monthly peaks and the distribution of monthly energy requirements.

Most official demand data is available on a financial year basis but since the NIRP is using a calendar year approach some conversion took place. Based on hourly system data from 2008 to 2011 the following historical peak demand and energy were determined.

Historical Peak Demand and Energy

Item 2008 2009 2010 2011 System Demand (MW) 443.7 470.1 477.0 511.7 Energy Demand (GWh) [*] 2,763.0 2,802.4 2,976.3 3,230.8 Load Factor (%) 71.1 68.1 71.2 72.1 Note: [*] Based on the addition of the average capacity hourly demand

Figure 2-2 presents the annual load duration curves (LDC) for the period 2008 to 2011. It should be noted that for the period of a few days in September 2008 the system hourly load data was very low and often negative while the values attributed to the various generation sources were as expected. For annual load duration curves, 120 points of data were removed (out of 8784).

As may be observed, the load duration curves for the years 2008 to 2011 have a similar shape. The curves for 2008 and 2010 have virtually the same shape. . The LDC for 2011 indicates an increase in the valley loads since it is higher than the others for 20% of the time and again this could be expected by examining the growth for energy versus that for peak demand.

For the analysis of generation expansion planning in Task 4, the NIRP will use the shape of the load duration curves for 2010 adjusted at 5 year intervals to take into account the changes in the load composition.

For planning, the monthly peak demand variation throughout the year is also important and based on the peak demand for the period 2008 to 2011 a monthly peak demand variation has been derived and is shown in Figure 2-3.. From this Figure it can be seen that the peak demand usually occurs in July (winter peak) with the months on either side having a peak of the order of 97% of annual demand. The peak demand is at the 87- 91% of annual peak level from December to the end of March when it then starts to

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increase. During the lower peak demand period it is then possible to carry out maintenance in some of the generating equipment, especially thermal generation.

The monthly energy variation for the demand is also very much relevant for system planning especially in cases where there are energy constrained generators (Ruacana can generate very little during the dry season) as is the case in Namibia. The monthly energy variation was derived from system hourly demand for the period 2008 to 2011.

Annual Load Duration Curves 100

Demand (%) Demand 40

0 0 20 40 60 80 100 Time (%)

2011 2010 2009 2008

Figure 2-2: Annual Load Duration Curves

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Monthly Peak Demand, % of Annual 97.0 100.0 96.7 92.4 93.0 95.4 93.1 93.4 100.0 87.3 87.0 87.8 90.8 80.0

60.0

40.0

Demand (%) 20.0

0.0

Month

F igure 2-3: Monthly Peak Demand Figure 2-4 presents a synthesized monthly energy variation for the system demand in Namibia which is close to the monthly averages for the individual months of the 2008 to 2011period. Monthly Energy, % of Annual 10.00 8.40 8.69 8.47 8.37 8.65 8.57 8.60 8.26 8.00 8.10 8.30 8.00 7.59

6.00

4.00

2.00 Energy Demnd (% of Annual) 0.00

Month

Figure 2-4: Monthly Energy

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The greatest energy demand occurs in July (8.69% of the annual energy demand) which coincides with the system peak demand but later periods in the year (October to December) also have a particularly large demand when compared to other months.

2.4 Existing and Committed Supply Facilities The electricity demand of the national grid is supplied by the local electric power stations and imports from the Southern African Power Pool (SAPP) member countries, , South Africa, Zambia and Zimbabwe as well as others. As of December, 2011, the country had in total four major power stations interconnected to the national grid, the 240 MW Ruacana hydropower plant, the 120 MW Van Eck coal fired power plant, the 24 MW Paratus diesel fired power plant and the 22.5 MW Anixas diesel fired power plant.

2.4.1 Local Generation Facilities a) Ruacana Hydropower Station The Ruacana hydro power station is located on the Kunene River, in the north of Namibia, where the Kunene River becomes the border between Namibia and Angola. The station was commissioned in 1978 and consists of three 80 MW hydro generators for a total of 240 MW. The station has black start up diesel generators and a 330 kV transmission line running from Ruacana to the Omburu substation which is some 570 km in length. The civil works for addition of a fourth turbine were completed with the original installation allowing a fourth unit to be added when required.

The Ruacana station is mainly operated as a run-of-river power plant as its upstream storage dams are either not completed or were damaged in the Angolan civil war. The output of the hydro power station depends on the amount of water available in the river. A small diversion weir just upstream of Ruacana allows the power station to produce at its full capacity for eight hours. During the rainy season (from February to May) the station is run at full output level and operated as a base load power plant, while for the remainder of the year it is operated predominately as a peaking power plant.

On May 31, 2012, NamPower commissioned a fourth turbine at the Ruacana power station, which is capable of generating an additional 92 MW when sufficient water is available.

NamPower has identified the need to repair the runners in the turbines of units 1 to 3. Since the repair of the runner structure is required, NamPower has considered a major refurbishment of the turbines including replacing runners with more efficient design. This refurbishment will increase efficiency by approximately 5% for each unit. This increase will provide 4 MW of additional peaking capacity per unit. In addition, on

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average, the plant’s generation will increase by about 60 GWh on an annual basis. Once the refurbishment is completed, the total plant capacity will be approximately 344 MW (3x84 + 92).

With a total installation of 343 MW, the plant’s operation mode is likely to change to mid merit and peaking operation particularly in the dry months.

The monthly energy production for Ruacana, once the fourth unit is commissioned and the refurbishment is completed is shown in Table 2-1 for average and firm conditions. In this case “firm” energy is that energy that is associated with a hydrology of 90% probability of exceedance. The 90% level was selected due to the existing interconnections of the Namibian network with other networks in the region. For planning and in order to determine reliability indices for the network, the 95% probability level of exceedance is usually selected in order to ensure a reliable supply level in case that a dry hydrology is encountered during any particular year.

For planning purposes and in order construct a system model, the plant will be modelled with a forced outage rate of 4% and planned maintenance of 2 weeks for each unit will be modeled by derating monthly capacities.

Table 2-1: Ruacana Generating Capability

Month Firm Energy Average (GWh) Energy (GWh) January 91.0 97.4 February 57.9 96.7 March 117.5 226.3 April 211.7 240.5 May 125.8 200.4 June 83.3 117.6 July 50.2 102.7 August 46.2 83.8 September 43.7 68.6 October 26.7 57.9 November 19.3 52.1 December 37.3 150.0 Total 910.6 1,494.0

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b) Van Eck Coal Power Plant The Van Eck coal-fired power plant is situated on the outskirts of Windhoek. It has a total rating of 120 MW using four 30 MW generators and was commissioned in 1973. The station needs external power for start-up. Due to water constraints in Windhoek the plant was designed as a dry cooled station. The coal used is imported from South Africa, transported by ship to Walvis Bay and then by rail or road to Windhoek. This is a costly exercise and the plant is normally operated as a standby and peaking power station. During the recent regional constraints, it has been run at mid-merit to base load. The power station has very limited emission control equipment and thus emits high levels of air pollutants. The station is therefore limited to burning 3,500 tonnes of coal each week, although it may use emergency stockpiles if necessary.

These aging units are becoming less and less reliable as they approach the end of their technical life. The maximum output the plant can reach is only some 50 MW due to various constraints.

A study on the rehabilitation options for the plant funded by the US Trade and Development Agency (USTDA) has recently been completed. The study examined several rehabilitation options which would result in different output, extension of life and capital costs. The options studied included:

 Rehabilitate boilers and obtain a firm capacity of 84 MW (76 MW net) even though the plant would be capable of 4x 28 MW  Refurbish plant to run up to 10 years and have an output of 112 MW (4x28)  Replace boilers and refurbish plant to have an additional life of 20 to 30 years.

If a new coal fired power plant is built in the Erongo Region , then it would very likely share the port’s coal handling infrastructure with Van Eck which would limit the output at the existing plant. The rehabilitation options for Van Eck are thus dependent on the long term development of the generation mix in Namibia.

At this time it appears that the first rehabilitation option will be selected considering only a 5 year life extension with the possibility of a 10 year life extension and an output of 112 MW. In view of the principal generation options in Namibia, it appears that a 5 year extension is the most appropriate since if the rehabilitation was to be completed by August 2014, a new base load plant could be in place before the beginning of 2020.

Table 2-2 presents the parameters to be used in modelling Van Eck before and after the rehabilitation.

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Table 2-2: Characteristics of the Van Eck Coal Power Plant

Item Existing Refurbished Net Capacity (MW) 50 76 F.O.R. (%) 5.4 <1[1] Planned Maintenance 1 month/unit 0 [2] Heat Rate (kJ/kWh) 20,000 15,400 Fixed O&M (N$/kW-Yr) 499 415 Variable O&M (N$/MWh) 1,013 35 [3]

Notes: [1] Based on a 3 unit equivalent of 4 units – [2] The 4th unit can replace the unit on maintenance – [3] Based on 70% capacity factor

c) Paratus Diesel Power Station The Paratus diesel power station is located in Walvis Bay. It has a total rating of 24 MW using four 6 MW (nominal) diesel generators. The rating of each unit is dependent on the ambient temperature, with a rating of approximately 5 MW at low temperatures and 4 MW at high temperatures. The station has a black start up diesel generator and was commissioned in 1976. It is used mainly as a standby and peaking power station respectively but it is also contractually bound as an emergency standby plant for the city of Walvis Bay. Paratus is in good workable condition although it runs at very high marginal cost but can only generate a maximum of 17 MW.

The power station uses light fuel oil (LFO) to start-up and shut down, switching to heavy fuel oil (HFO) once a unit is generating more than 2.7 MW.

There is an opportunity to replace the existing machines with the same 7.5 MW HFO fired Caterpillar units that are installed at Anixas. This would increase the peak capacity of Paratus to a total of 30 MW (an increase of 13 MW). NamPower has included this replacement in their plans and the new units could be on line in late 2013. The capital cost would be of the order of N$ 275 million.

Table 2-3 presents the characteristics for the existing and replacement units at Paratus.

d) Anixas Power Station The Anixas power station is located near the Paratus diesel power station in Walvis Bay. This station benefits from new and proven technology which has a higher efficiency and reliability, and less emissions and noise than older power stations of its type. There are 3 Caterpillar V16 cylinder diesel generator sets, each with a net electrical capacity of 7.5

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MW, for a total of 22.5 MW. The power station started operations at the end of July, 2011 with the official inauguration in November 2011.

The three generator sets are housed in a building with its own control room, offices and a black start generator of 810 kVA capacity. The generators use LFO for starting and stopping and HFO once they have reached a certain output. The station has fuel offloading facilities and a fuel treatment system.

Radiators are used for cooling. A high exhaust stack disperses emissions high up, reducing ambient concentration of any pollutants. Noise attenuation and control conform to international standards. Care was also taken to select materials capable of withstanding the extreme corrosive environment of Walvis Bay.

Consideration has been given to an additional 5x7.5 MW installation on the same site with a capital cost of about N$340 million. Construction of any new generation at Paratus/Anixas could bring forward the construction of a new transmission substation on adjacent land. This second project could be on line as early as July 2014 but no decision has been taken as of yet and as such it s not considered a committed project.

Table 2-3 presents the characteristics for the Diesel units at Walvis Bay.

Table 2-3: Characteristics of the Walvis Bay Diesel Plants

Item Paratus Existing Paratus Replace Anixas Net Sent Capacity (MW) 17 30 22.5 F.O.R. (%) 18.0 5.0 5.0 Planned Maintenance 6 weeks/unit 3 weeks/unit 3 weeks/unit Heat Rate (kJ/kWh) 10,600 8,500 8,500 Fixed O&M (N$/kW-Yr) 138 372 372 Variable O&M (N$/MWh) 100 32.5 32.5

2.4.2 Imports Imports account for a large proportion of the electricity requirements in Namibia. According to NamPower’s Annual Report for 2011, of the 3,910 GWh (including Skorpion’s demand) required by the system in FY 2011, some 2,480 GWh were brought into the Namibian grid from external sources. These imports were obtained from several electricity markets as described below.

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a) Non-Firm Supply Agreement with Mozambique NamPower has a short-term supply contract with Electricidade de Moçambique (EDM) for 30 MW of supply from hydro generation. The contract does not have any capacity charges and has only energy prices for three time periods, Peak, Standard and Off-Peak. The contract is to be reviewed on an annual basis. NamPower is pursuing further trading opportunities with Mozambique.

As indicated in NamPower’s annual report for FY 2011, the import from Mozambique amounted to only 2 GWh and this small import relative to the levels of previous years was probably due to the increase of imports from Zambia.

b) Imports from South Africa There are two contracts in place between NamPower and Eskom. The Bilateral contract and the supplemental contract. These contracts are renewed on an annual basis. The imports associated with the bilateral contract can only be used during off peak periods which are defined by Time of Use schedule as shown in Figure 2-5.

Peak Standard Off-peak

Figure 2-5: Time of Use Schedule

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A supply contract with up to 200 MW of Special Assistance or the Supplemental contract was negotiated with Eskom with the provision that it will be reviewed annually. Due to power supply shortages within South Africa, this supply option can only be requested by NamPower after all local supply options have been exhausted, including any active demand management programs within Namibia. There is no capacity charge on the import and energy prices are specified by season (high and low demand seasons) and time period (Peak, Standard and Off-Peak).

Based on the contract clauses, NamPower must also shed its load if there is load shedding in South Africa due to generation shortages. The load to be curtailed in Namibia is equal to the Eskom load shedding ratio multiplied by the amount of Special Assistance.

This agreement is vital to Namibia’s security of supply as depicted in the percentage of Eskom’s share of the total imports over the last few years.

The tariffs associated with these contracts are complex and require intelligent meters to be in place to be able to keep the accounting straight. For the present study the model to be used is unable to correctly model the complexity of seasonal and three daily tariffs and as such it was decided to blend the tariffs into a single value taking into account the duration of each time of use value. For the NIRP the imports from Eskom are to be taken to have a cost of 0.75 N$/kWh. This value is heavily dependent on the number of hours assumed for each time period. The lower the number of hours of import during the off peak period the higher the blended price.

c) Power Supply Agreement with Zambia The power supply agreement with the Zambia Electricity Supply Corporation Limited (ZESCO) came into effect on 16 January 2010. The agreement has a 10 year duration and a firm capacity of 50 MW.

There is also a non firm agreement with ZESCO for 50 MW which would be confirmed on a daily basis but this agreement has not been executed. This could be partially due to transmission constraints in the ZESCO system and could be executed once the constraints are resolved.

The ZESCO import has a two part tariff, a demand charge and an energy charge. The import has a very high capacity factor and has been identified as being close to 92%. The capacity charge has to be paid regardless of the amount of energy being withdrawn.

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The blended tariff is presented in Table 2-4 for different capacity factors. At 92% capacity factor the blended cost of energy is 0.35 N$/kWh.

d) Power Supply Agreement with Zimbabwe NamPower has a power supply agreement with the Zimbabwe Electricity Supply Authority (ZESA) for the supply of 150 MW by a base load coal-fired generator in Zimbabwe (Hwange). The contract is for 5 years from October 2008. This take-or-pay contract has both capacity and energy charges.

Although it is a firm contract, this capacity is assumed to be available 80% of the time as a number of factors may result in disruptions of supply, including plant or transmission interruptions in Zimbabwe, or network problems in South Africa. As can be seen from NamPower’s last annual report, the energy imported from ZESA has been at capacity factors lower than 80%. It is our understanding that if the full complement of the energy allocated to Namibia is not imported the remaining energy can be banked for later use. Taking into account the statistics for the last 3 fiscal years as published in NamPower’s annual reports it can be determined that there is sufficient banked energy for supply from ZESA until October 2014. ZESA has already expressed that it would not be renewing the contract.

The blended tariff is presented in Table 2-4 for different capacity factors. At 75% capacity factor the blended cost of energy is 0.36 N$/kWh including 0.028 N$/kWh for wheeling charges in Botswana and South Africa as well as losses in the Eskom system.

Table 2-5 presents the imports by source over the last seven years. It should be noted that over the last three years there have been no purchases on SAPP’s short term energy market (STEM). From the table it can also be noted that once the imports from ZESA and ZESCO started, the imports from Eskom decreased.

Table 2-4: ZESCO and ZESA Blended Import Tariffs

Capacity Blended Cost of Import N$/kWh Factor (%) ZESCO ZESA 50 0.46 0.47 70 0.39 0.37 75 0.38 0.36 85 0.36 0.33 90 0.35 0.32

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Table 2-5: Imports of Energy Over the Last 7 Years

Import Imports in Fiscal Year (GWh) Source 2011 2010 2009 2008 2007 2006 2005 Eskom 1,522 1,429 1,427 1,961 1,733 1,620 1,514 ZESCO 319 47 29 27 24 78 23 ZESA 637 891 648 85 104 162 158 EDM 2 95 24 52 69 6 - SAPP STEM - - - 22 115 82 8 Total 2,480 2,462 2,128 2,147 2,045 1,948 1703

e) Other Power Supply Agreements There are no other existing agreements regarding power imports into Namibia. There are negotiations for other future imports but these are addressed in Sections 4 and 5.

2.5 Transmission and Distribution As shown in Figure 2-6, the Namibian transmission system extends from Ruacana close to the Angolan border in the North to the border of the Republic of South Africa in the South, where it joins with the ESKOM interconnected grid. In the North, the system also reaches the Caprivi corridor where it borders with the Zambian system. In the East the system extends to the border of Botswana.

The NamPower transmission backbone consists of transmission running at 330 kV from the Ruacana power station to the Omburu substation and from there at 220 kV to the South Africa border for a total length of 1,518 km. There is a 220 kV transmission ring connecting the Van Eck power station to Walvis Bay with the link between Van Eck and Omburu having two 220 kV transmission lines.

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Figure 2-6: Transmission System of Namibia

The transmission system consists of several transmission voltages including 66 kV, 132 kV, 220 kV, 330 kV and 400 kV as well as 350 kV HVDC.

The first stage of the Caprivi Link Interconnection project was officially commissioned on November 12, 2010, which comprises a 951 km 350 kV HVDC line with converter stations at Zambezi and Gerus substations. The Zambezi substation is located in Katima Mulilo, the Capital of the Caprivi Strip at the border between Namibia and Zambia. The Gerus substation is situated outside Otjiwarongo in central Namibia.

The Caprivi Link Interconnection was built in monopole mode with capability of transmitting 300 MW of power. It could be upgraded to 600 MW in bi-pole mode as

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demand increases and as trading opportunities evolve in the region. The link is an important component of the future ZIZABONA connection.

Recent developments in the transmission system include:

 West Coast Developments: Completion of the first phase, of the 220 kV West Coast developments and upgrades, initiated by the need to supply power to the new Trekkopje Uranium Mine. The new Khan Substation, 220 kV line to Trekkopje, Trekkopje Transmission Station and 132 kV line and substations related to the desalination plant near Wlotzkasbaken, were commissioned. Commissioning of the second 220 kV line between Omburu and Khan Substations, 220 kV line feeder bay development and upgrades at Omburu, and 220 kV 40 MVAr capacitor filter bank at Omburu Substation  Ohorongo Cement Plant: The power supply to the new Ohorongo Cement plant near Otavi was recently completed. In addition, upgrades were also required at Otjikoto Transmission Station near Tsumeb – 220 kV 20 MVAr capacitor filter bank and replacement of the two 220/132 kV 40 MVA transformers with 120 MVA units  Auas Van Eck 220 kV Transmission Line Capacity Upgrade: This upgrade was required due to the load growth, especially driven by the mushrooming uranium mines at the coast. The upgrade comprised the replacement of the single goat conductor on the Auas/Van Eck 3 line with a high thermal conductor of similar dimensions as goat, as well as Optical Ground Wire (OPGW) retrofitting for increased communication requirements  Ondjiva Cross-Border Supply: ENE, the Angolan Power Utility, applied for an upgrade to the existing cross-border supply to Ondjiva from 33 kV to 132 kV. To facilitate this upgrade a new 132/66 kV Transmission Station (called Efundja) just south of the existing Onuno Transmission Station is to be constructed, as well as a dedicated 132 kV line from Efundja to the border with Angola will be established  Naruchas: a construction of a 132/66 kV Transmission Station just north of Rehoboth town lands, supplied from Auas Transmission Station through an 80km 132 kV line, thus splitting the load between Auas and Van Eck was considered to be technically the most feasible option. The 132 kV line has been commissioned and energized, and the new Naruchas 132/66 kV Transmission Station is expected to be completed by mid 2012  Otjikoto 20 MVAR 220 kV Filter bank: Commissioned in the later part of 2010  Omburu 40 MVAR 220 kV Filter bank: This project was commissioned in April 2011

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 Rössing – Walmund 220 kV line: Rössing – Walmund 220 kV line: Due to the age of the line and the harsh environmental conditions, a project has been launched to replace the entire line section with a twin circuit 220 kV line to cater for future load growth in the West Coast.

ZESA of Zimbabwe, ZESCO of Zambia, BPC of Botswana and NamPower of Namibia signed an Inter-Utility Memorandum of Understanding (IUMOU) for co-operation in new transmission infrastructure investment. The project is planned to be commissioned in two phases, namely the Hwange/Livingstone (Phase 1) and Victoria Falls – Pandamatenga – Zambezi Transmission Station s (Phase 2). Due to challenges encountered with regards to the financing of the ZIZABONA Project, it was decided to engage a consultant to repackage the project. The scope of the consultant is to conduct market studies, transmission pricing and system studies in support of the realization of the project.

Distribution lines with the voltage 33 kV and below extend radially from the main substations for further dispersion of power to the consumption areas along the coast and inland. As great parts of the country are rather sparsely populated, the area served by the distribution network covers quite a small portion of the total area.

The REDs and certain local and regional authorities are responsible for the distribution and supply of electricity to end consumers within their respective areas. They serve approximately 190,000 end consumers, the vast majority of which are domestic users.

2.6 Interconnections With the construction of the Caprivi link, the high voltage transmission system connects the electrical grids in Namibia and neighbouring Zambia, providing a new route for power imports.

As can be seen from Figure 2-6, the other interconnections are at 220 kV and at 400 kV and are located in the south of Namibia connecting the system to that of Eskom. These interconnections are used to bring in the imports from Eskom and the 150 MW from the power produced at Hwange (Zimbabwe).

2.7 Electricity Supply Licences One of the principal responsibilities of ECB is issuing licenses and monitoring licensee performance to ensure compliance with licensee conditions and requirements. Entities engaged in distribution and supply of electricity, generation, import, export and transmission of electricity must obtain licences for those purposes.

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Table 2-6 presents a list of the conditional licences that have been granted to IPPs for generation of electricity.

Table 2-6: List of Conditional IPP Generation Licences

Licensee Type Size CBEND Biomass 250 kW Vizion Energy Resources (Pty) Ltd Coal (CFB) 300 MW Namibia International Mining Co. Diesel CCGT 210 MW VTB Capital Small Hydro 30 MW Atlantic Coast Energy Co. Coal 700 MW Arandis Diesel 120 MW Diaz Wind Power (Pty) Ltd Wind 44 MW Electrawinds (Pty) Ltd) Wind 50 MW Innowind (Pty) Ltd Wind 60 MW GreenNam Electricity Solar 3x10 MW

CBEND is the only one of these licensees that has a signed PPA with NamPower. Its power plant is already operational and is expected to be connected to the grid during 2012. There are ongoing discussions with NamPower regarding the respective PPAs with Diaz Wind Power (Pty) Ltd, Innowind (Pty) Ltd and GreenNam Electricity.

2.8 Other Generation Included in the Short Term Critical Supply Program As part of the Short Term Critical Supply (STCS) program, NamPower has undertaken studies to define how best to meet the deficit in the supply in the short term and has identified several possibilities including the rehabilitation of Van Eck and the Paratus Extension which have already been described.

In addition to the options described in Section 2.4, NamPower has identified the leasing of diesel units to be located at either Swakupmund or Luderitz as a potential short term option that may tie NamPower over until the preferred base load option is commissioned. This would involve bringing in 70 MW by October of 2012 and an additional 80 MW by September 2014. Once new base load generation is commissioned these units could then be decommissioned from the Namibian system and used elsewhere where required. These diesels units will be a common option for all supply alternatives analyzed in the preparation of this NIRP and thus their fixed costs can be considered as sunk costs. The units are assumed to be of the 20 MW and 10 MW size with a heat rate of the order of 9,800 kJ/kWh, use HFO and have a fixed O&M of some 675 N$/kW-yr and a variable O&M of 75 N$/MWh.

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As shown in Section 2.7 there are several companies with conditional licenses to install renewable generation (wind and solar) at various locations in Namibia. According to NamPower, some of these licensees are expected to go ahead and install the generation under their respective license.

Diaz Wind Power (Pty) Ltd. is expected to install 44 MW in the Luderitz area and start generating by November 2014. Innowind‘s conditional license is for a 60 MW wind power plant in the Walvis Bay area and this plant is expected to start generating by August 2014. The GreenNam Electricity conditional license is for 3 solar PV sites each with a capability of 10 MW. It is expected that it will start generating the first 10 MW by January 2014 and the remaining 20 MW by August 2014.

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3. Supply and Demand Situation 3.1 Introduction This section presents a summary of the existing situation and that of the short term regarding the demand and supply situation in Namibia. The values used were derived from publicly available information, synthesized hourly system data, the NIRP demand forecast and values discussed during various meetings.

By examining the capacity and energy balances or deficits obtained it is possible to determine the extent of the surplus or shortages and the timing and size of the required new generation additions.

In order to understand the supply and demand situation in Namibia one has to understand the energy policy in place and this is briefly addressed in the section following this short introduction.

To carry out the balance both the supply and the demand are required. The supply in Namibia is described in Section 2 and the demand is addressed in the NIRP Load Forecast Report dated March 30, 2012.

Finally, the short term supply and demand balance is presented in Section 3.4 in terms of both capacity and energy.

3.2 The Energy Policy White Paper The Namibia Energy Policy Committee (NEPC) of MME published the Energy Policy White Paper in May 1998. This is quite a comprehensive document consisting of an executive summary and five principal sections. Section 1 provides the rational for the white paper and the sector’s profile, Section 2 focuses on energy demand for the productive sectors, urban energy needs and rural energy needs. Section 3 addresses energy supply and deals with electricity, gas, liquid fuels and renewable energy. Section 4 deals with cross cutting themes including economic empowerment, environment, health and safety, energy efficiency and conservation and regional energy trade. Section 5 points to the way forward.

This section addresses primarily the issues and policies dealing with electricity and its supply even though the White Paper addressed several other matters. It should be noted that the Energy Policy White Paper is currently being revised by MME and its consultants, with modelling training, for MME personnel, being envisaged for April 2012 and some disclosure of the revised policy targeted by the end of 2012. Unfortunately the NIRP has to be completed before then and MME and several other entities have

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suggested that in the absence of a revised policy, the NIRP should be guided by the existing policy.

The following goals served as a framework for the energy policies;

 Effective governance - Systems were to be in place to provide stable policy, legislative and regulatory frameworks for the sector  Security of supply – To be achieved through an appropriate diversity of competitive and reliable sources, with emphasis on the development of local resources  Social upliftment – Consumers to have access to appropriate, affordable energy supplies  Investment and growth - The sector to expand through local and foreign fixed investment, resulting in economic benefits for the country. Attention to be given to black economic empowerment  Economic competitiveness and efficiency - The sector to be economically efficient and to contribute to Namibia’s economic competitiveness  Sustainability - The sector to move towards the sustainable use of natural resources for energy production and consumption.

As part of the energy policy, Government was to promote the use of renewable energy through the establishment of an adequate institutional and planning framework, the development of human resources and public awareness and suitable financing systems.

The energy policy goal of sustainability was to be promoted through a requirement for environmental impact assessments and project evaluation methodologies which incorporate environmental externalities. While energy efficiency was to be promoted through policies on better information collection and dissemination, and particularly with respect to energy efficiency and conservation practices in households, buildings, transport and industry. Security of supply was to be achieved through an appropriate diversification of economically competitive and reliable sources, but with particular emphasis on Namibian resources.

As part of one of the policy statements, the white paper outlines the amounts of generation to be from internal sources. The white paper outlines “Duly considering associated risks, it is the aim of government that 100% of the peak demand and at least 75% of the electric energy demand will be supplied from internal sources by 2010. Risk

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mitigation measures will be pursued, including the possibility of regional equity participation in, and guarantees for, Namibian generation projects.”

As of the time of writing, the targets for internal supply specified in the policy have not been realized. Generation resources located within Namibia’s territory can supply up to only approximately 421 MW (even though the installed capacity is now approximately 500 MW with the commissioning of Ruacana 4) to meet a peak demand of 511 MW (in July 2011). On the other hand, according to NamPower’s annual report, imports from sources outside Namibia have accounted for over 60% of the energy requirement over the last three years.

In meetings with MME discussion took place on the definition of “internal resource” as there could be a situation in which a Namibian entity has an equity participation and guaranteed output share in a plant located outside Namibian territory. It was noted that due to reduced control of the delivery of the Namibian share to Namibia, this situation could have an impact on the ability to meet the Namibian system demand and energy requirements in a reliable and secure manner.

In this case the policy does not address system reserve or required reliability or even the amount of unserved energy. These items are addressed in Section 4 as part of the NIRP considerations and criteria.

3.3 Demand Forecast The Reference load forecast scenario from the NIRP Load Forecast Report is shown in Table 3-1 in terms of both peak demand (capacity) and energy generation. The initial values in Table 3-1, from 2008 to 2011, are historical values and are shown for reference only.

The values shown in Table 3-1 are presented graphically in Figure 3-1 from which the growth in both peak demand and energy can be visualized. Of particular interest in the short-term is the significant increase projected in the 2014 to 2016 period which is due to new mining loads coming on stream as well as loads of other projects and the decrease in demand in 2025 which is associated with the ending of operations of one of the uranium mines.

Table 3-1 also presents the load factor. The load factor increases from an existing value of 72% to a high of 79% and decreases to a value of 75% by the end of the forecast period. These values are somewhat high and indicate a large industrial component in the overall demand, the increase in the load factor can be explained by the addition of significant industrial loads in the 2014 to 2018 period and then the decrease by the

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change in the load mix by the gradual increase in the share of commercial and domestic demand.

The overall demand growth for the first ten years, 2011 to 2021, is expected to be an average annual growth of 5.8% for the demand and 6.7% for the energy component. For the 2011 to 2031 period, average annual growth rates of 4% for demand and 4.3% for energy have been projected. The peak demand is expected to grow from an observed peak demand of 511.7 MW in 2011 to a peak demand of close to 900 MW in 2021 and 1,124 by 2031. Similarly, the energy requirement is expected to grow from a value of 3,231 GWh in 2011 to 6,173 in 2021 and 7,433 in 2031.

Table 3-1: Reference Scenario Demand Forecast

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Peak Energy Load Year Demand Generation Factor (MW) (GWh) (%) 2008 443.7 2,763.0 71.1 2009 470.1 2,802.4 68.1 2010 477.0 2,976.3 71.2 2011 511.7 3,230.8 72.1 2012 525.7 3,315.8 72.0 2013 562.8 3,601.3 73.0 2014 614.0 4,010.6 74.6 2015 710.6 4,829.3 77.6 2016 774.9 5,356.9 78.9 2017 806.9 5,593.3 79.1 2018 828.4 5,725.8 78.9 2019 853.2 5,878.4 78.6 2020 878.9 6,036.1 78.4 2021 901.3 6,173.2 78.2 2022 924.3 6,314.0 78.0 2023 947.9 6,458.7 77.8 2024 972.3 6,607.5 77.6 2025 962.8 6,451.9 76.5 2026 988.5 6,608.4 76.3 2027 1,014.9 6,769.4 76.1 2028 1,041.7 6,932.1 76.0 2029 1,068.9 7,096.8 75.8 2030 1,096.5 7,263.7 75.6 2031 1,124.4 7,432.5 75.5

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Figure 3-1: Reference Scenario Demand Forecast Including Historical Values

3.4 Short Term Demand and Supply Situation Based on the demand forecast and the available supply described in Section 2, a capacity and energy balance was carried out on a monthly basis for the Namibian system for 2012 to 2015. The monthly capacity and energy demands were determined by multiplying the annual values by the monthly percentages outlined in Section 2.3.

The monthly supply capacity was determined by using the values presented in Section 2 with some adjustments. For Ruacana it was assumed that the plant could supply its full capacity output at any given time (but not on a continuous basis) and that for this calculation planned maintenance would not be taken into account. Also for Ruacana it was assumed that runner upgrades are committed and that the necessary works would be in place by July 2013. The monthly energy for Ruacana was assumed to have a probability of exceedance 90% of the time on an annual basis and the total P90 energy would be 910.6 GWh per year. The reason for taking the P90 energy for Ruacana and not the P50 or even a combination of hydrologies is quite simple and entails the fact that any system should have sufficient energy to meet its demand with a high degree of

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probability in which case only hydrologies with a probability of exceedance of 90% or higher can do. Systems with a large hydro generation component that do not use similar criterion usually have difficulty meeting the demand in some dry years.

In order to simplify the calculations, it was assumed that the plant would continue generating on an individual unit basis during the period that upgrades are being carried out.

The Van Eck capacity was taken as 50 MW up to the time that the unit is assumed to have its 5 year life extension completed. Due to environmental constraints the plant would generate only at 50% capacity factor up to the time of its rehabilitation. The Van Eck rehabilitation was assumed to allow some 76 MW (instead of 50 MW) to be connected to the system which would then generate at a 70% capacity factor. This changeover would take place in October 2013.

The Parartus plant and Anixas would generate at a 70% capacity factor with Paratus assumed to have a committed expansion by late 2013 to 30 MW which includes the retirement of the existing units and the commissioning of new units similar to those at Anixas. NamPower is planning to contract 70 MW of power in the form of emergency diesels to be in service by October of 2012 and an additional 80 MW to be in service by September 2014. All diesels are assumed to operate at a capacity factor of 70%.

It is understood that NamPower is negotiating PPAs with two wind IPPs and one solar IPP and according to NamPower, the Innowind 60 MW project, to be located near Walvis Bay, is intended to be connected to the system by August 2014 with 60 MW while the Diaz Wind project to be located in the Luderitz area and have a capacity of 44 MW is expected to be connected by November 2014. There are three GreenNam Electricity solar PV projects each rated 10 MW with the first project expected to be in service by January 2014 and the other two by August 2014. For simplicity it was assumed that these wind and solar projects would have a combined capacity factor of 30%.

It is recognised that the 150 MW contract with ZESA is to be terminated by October 2013 but as previously mentioned it appears that there is sufficient banked energy to run the contract one more year and as such this contract was assumed to be terminated by the end of September 2014.

Table 3-2 (located at the end of this section) presents the capacity and energy balance for the Namibian system for the year 2012. The expected peak demand is 525.7 MW in July and the greatest monthly energy demand is 288.1 GWh also in July. Table 3-2 also

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shows the capacity and energy values required to meet the domestic supply criteria specified in the 1998 White Paper on Energy Policy.

The supply/demand balances considered are as follows: 1. Balance comparing the supply capability from domestic sources with the domestic supply requirements of the 1998 White Paper applied to the projected demand 2. Balance comparing the total system supply capabilities with the projected total system demand

For these balances, the bilateral agreement with Eskom for 100 MW is included only in determining the energy capability for the Namibian system. The capacity under this agreement is not included in the capacity capability because under the agreement the contracted capacity is not firm.

As shown in Table 3-2, the largest deficits in the year 2012 are those for the 1998 White Paper balance. In this case, the monthly capacity deficit reaches 104 MW and there is an annual energy deficit of 1,007 GWh which implies that 1,007 more GWh would have to be imported than the quantities established by the criteria of the 1998 White Paper.

Looking at the total system demand (without taking into account the criteria of the 1998 White Paper), the system appears to have the required capacity but is energy constrained lacking the energy to meet the system needs in the dryer part of the year (July to November). For the year 2012, five of the 12 months would have an energy deficit under a P90 hydrology with the largest deficit probably occurring in the months of July and November. The results presented in Table 3-2 clearly indicate that the system has peaking capability but lacks a base load plant to allow for the generation costs to decrease or the imports to also decrease.

A similar exercise was carried out for 2013 to 2015 and the results for the period 2012- 2015 are presented in Figure 3-2 for the capacity balance and Figure 3-3 for the monthly energy balance. These figures do not include the impacts of the 1998 White Paper requirements.

The capacity values shown in Figure 3-2 indicate an increase in generation in March 2012 corresponding to the addition of the fourth unit at Ruacana. In October 2012 the planned addition of the 70 MW of emergency diesels can also be seen in the figure and the increase in capacity due to the additions described previously in mid to late 2014 is clearly shown by the large blip (80 MW emergency diesels, rehabilitation of Van Eck, addition of solar plants). With the termination of supply from ZESA in October 2014

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there is a significant drop in capacity availability (contract expired in October 2013 but was assumed to continue until 2014 due to availability of banked energy). With the significant capacity additions in 2012 through 2014, the system has a positive capacity balance in the period of study. However, if the 150 MW of emergency diesels are removed and the 134 MW of renewable resources are discounted, the system capacity balance would be negative.

Monthly Capacity Balance 1000

900

800

700

600

500

400

300 Demand and Generation Capacity (MW)

200

100

0 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15 Jan-16 Month

Balance Demand Generation

Figure 3-2: Monthly Capacity Balances for 2012 to 2015

The energy values shown in Figure 3-3 indicate that under a P90 hydrology for Ruacana, there would be slight energy deficits until mid 2014 with most of these occurring in the dry season. For the same period, the values in Figure 3-3 also show periods of excess energy which in reality would not occur as the system operator would scale back on the diesel operation.

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Figure 3-3 shows a significant drop in the energy capability in October 2014 which corresponds to the termination of supply from ZESA (contract expires in October 2013 but was assumed to continue until 2014 due to availability of banked energy). This compounded with load growth produces an energy deficit after September 2014 reaching a maximum deficit in November 2015 of 142 GWh for a total deficit in 2015 of 843 GWh or 17 % of the demand (see Table 3-3). As can be seen from Figure 3-3, significant energy deficits start around September 2014 (if a P90 hydrology occurs) and would continue until a base load plant is added to the system. Taking into account that a P90 hydrology is not very likely to occur every year and given a P50 energy generation of close to 1,500 GWh (some 600 GWh more than under P90 hydrology), the system would require a base load plant capable of producing at least 300 MW by the year 2016 and preferably before to replace energy generated by the emergency and other diesel plants as well as by Van Eck and imports. However, the lead times required to bring base load plant on line are likely to be more than the three and half years remaining before the start of 2016. Thus the Namibian system is most likely to have to rely on additional import sources to meet the demand.

Table 3-3 indicates that in 2015 there would also be significant energy deficits relative to the domestic energy supply requirements of the 1998 White Paper. The annual energy deficit is shown to be about 650 GWh. In order to meet the Energy Policy requirement of at least 75% of the Namibian energy demand being supplied by internal resources under a P50 hydrology and allow the emergency diesels to be decommissioned, a base load plant producing at least 200 MW would be required and in order to meet a few years of load growth the plant should be at least 300 MW which is in line with the requirement outlined in the previous paragraph considering the overall system requirements.

Table 3-3: 2015 Energy Balances

Energy Balance Type (GWh) Month Energy Policy Demand [1] Balance[2] January 33.2 -46.6 February 59.0 -72.6 March 11.8 -26.9 April 91.3 78.2 May 7.4 -4.1 June 48.0 -64.7 July 89.6 -108.3 August -85.6 -101.6

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September -90.2 -107.7 October -111.7 -129.8 November 121.8 -141.8 December 99.3 -116.8 Annual -651.5 - 842.7 Note: [1] Considering internal resources only [2] Considering 100% of demand and all resources

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Monthly Energy Balance 500

400

300

200

100

0 Demand or Supply (GWh) Supply or Demand

-100

-200 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15

Month Balance Demand Supply

Figure 3-3: Monthly Energy Balances for 2012 to 2015

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Year 2012 January February March April May June July August Sept. October Novem. Decem. Annual

Peak Demand (MW) 440.4 457.2 461.8 485.5 469.2 509.9 525.7 508.6 501.6 489.3 491.1 477.4 525.7 Energy (GWh) 273.9 251.7 278.5 265.3 268.6 275.2 288.1 280.8 277.5 286.8 284.2 285.2 3,315.8 Energy Policy Requirement Demand (MW) 440.4 457.2 461.8 485.5 469.2 509.9 525.7 508.6 501.6 489.3 491.1 477.4 525.7 Energy (GWh) 205.4 188.8 208.9 198.9 201.4 206.4 216.1 210.6 208.1 215.1 213.1 213.9 2,486.9 Existing Capacity (MW Ruacana 240 240 332 332 332 332 332 332 332 332 332 332 332.0 Van Eck 50 50 50 50 50 50 50 50 50 50 50 50 50.0 Paratus 17 17 17 17 17 17 17 17 17 17 17 17 17.0 Anixas 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 22.5 Subtotal Internal 329.5 329.5 421.5 421.5 421.5 421.5 421.5 421.5 421.5 421.5 421.5 421.5 421.5 Emergency Diesels ------70 70 70 70.0 Renewables ------Eskom [4] 0 0 0 0 0 0 0 0 0 0 0 0 0.0 ZESCO 50 50 50 50 50 50 50 50 50 50 50 50 50.0 ZESA 150 150 150 150 150 150 150 150 150 150 150 150 150.0 Total 529.5 529.5 621.5 621.5 621.5 621.5 621.5 621.5 621.5 691.5 691.5 691.5 691.5 Existing Energy Generation Capability (GWh) Ruacana [1] 91.0 57.9 117.5 211.7 125.8 83.3 50.2 46.2 43.7 26.7 19.3 37.3 910.6 Van Eck [2] 18.6 16.8 18.6 18.0 18.6 18.0 18.6 18.6 18.0 18.6 18.0 18.6 219.0 Paratus [5] 8.9 8.0 8.9 8.6 8.9 8.6 8.9 8.9 8.6 8.9 8.6 8.9 104.2 Anixas 11.7 10.6 11.7 11.3 11.7 11.3 11.7 11.7 11.3 11.7 11.3 11.7 138.0 Subtotal Internal 130.2 93.3 156.7 249.6 165.0 121.2 89.3 85.4 81.6 65.8 57.2 76.4 1,371.8 Emergency Diesels [5] ------36.5 35.3 36.5 108.2 Renewables [6] Eskom [4] 52.1 47.0 52.1 50.4 52.1 50.4 52.1 52.1 50.4 52.1 50.4 52.1 613.2 ZESCO 34.2 30.9 34.2 33.1 34.2 33.1 34.2 34.2 33.1 34.2 33.1 34.2 403.0 ZESA 89.3 80.6 89.3 86.4 89.3 86.4 89.3 89.3 86.4 89.3 86.4 89.3 1,051.2 Total 305.8 251.9 332.3 419.6 340.6 291.2 264.9 261.0 251.5 277.9 262.4 288.5 3,547.4 Energy Policy Balance [3] Capacity Excess (Deficit) (MW) -110.9 -127.7 -40.3 -64.0 -47.7 -88.4 -104.2 -87.1 -80.1 2.2 0.4 14.1 -127.7 Energy Excess (Deficit) (GWh) -75.2 -95.4 -52.2 50.7 -36.4 -85.2 -126.8 -125.2 -126.6 -112.8 -120.7 -101.0 -1,006.8 Demand Balance with Internal Sources and Contracts [4] Capacity Excess (Deficit) (MW) 89.1 72.3 159.7 136.0 152.3 111.6 95.8 112.9 119.9 202.2 200.4 214.1 72.3 Energy Excess (Deficit) (GWh) 31.9 0.2 53.8 154.3 72.0 15.9 -23.2 -19.9 -26.0 -8.9 -21.8 3.3 231.6 Notes: [1] Ruacana energy considers 90% probability of exceedance [2] Energy capability of Van Eck limited to 50% plant factor prior to refurbishment & 70% thereafter [3] Balance considering the Energy Policy [4] Eskom contracts excluded fromthe capacity balance as they are not firm but included in the energy capacility @70% CF [5] Paratus, Anixas and Emergency Diesels plant factor limited to 70% to account for planned and unplanned maintenance [6] Renewable energy plants assumed with an overall capacity factor of 30% ISO 9001 H338829-0000-90-124-0004, Rev. B, Page 39

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4. Planning Parameters and Criteria 4.1 Introduction This section presents a brief overview of the planning parameters and criteria to be used in the study. The parameters addressed herein have been divided into general and economic, generation, fuels and transmission parameters and criteria. The parameters were developed from several sources including discussion with Namibian entities, previous planning reports, the long term planning procedures document by SAPP, in- house cost and technical performance data and international best practices.

4.2 General and Economic Parameters As outlined previously in the Key Assumptions Report, the NIRP study will initially carry out its analysis using economic costs rather than financial costs. Financial costs are to be used to evaluate the best two options going forward when these have been selected based on several key factors. This implies that the principal analysis is based on economic values that do not take into account such factors as the imposition of taxes or royalties by government or any risk premium that may be charged by private sector investors. Government taxes and royalties are not included in the calculation of economic costs, as these are a transfer payment between one group in the economy and another, rather than a cost to the economy as a whole. Economic costs are used to determine what the right choices would be from the point of view of the Namibian economy and society as a whole.

The analysis is carried out using a social discount rate, that is, the rate of return on capital expected by society, rather than the investment criteria that may be used by the private sector. Thus, it is difficult to translate the economic costs of projects into the actual cost of projects when they are implemented. For one thing, government will expect royalties or taxes to be paid on labour, materials and resources.

4.2.1 National Focus The Terms of Reference specify that the NIRP is to identify the mix of resources for meeting electricity energy needs in an efficient and reliable manner at the lowest reasonable cost.

The NIRP is to arrive at an expansion strategy that reduces the vulnerability of the electricity supply to disruptions caused by events outside Namibia’s borders while increasing the use of local resources to generate the needed energy.

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The development of the NIRP is to be carried out from a national perspective by maximizing the benefits to all Namibians and not being concerned with particular interests of individual individuals or entities. The NIRP is to cover the entire territory of Namibia and take into account existing policies and the national development strategy of Vision 2030.

4.2.2 Planning Horizon As per the requirement outlined in the Terms of Reference, the plan is to cover a development period of 20 years and it is intended to model the system from 2012 to 2031.

At the end of the simulation period, the various expansion scenarios have different plant mixes with different remaining lives and different operation and maintenance costs as well as different investment costs. In order to measure all benefits of the plants that are commissioned in the planning period and take into account different plant lives, it is a common practice to extend the planning period by a period ranging from 10 to 15 or more years. For the extended period, demand and supply are maintained at the same level as at the end of the simulation period. An extended period of 15 years will be used in this study.

It is understood that the extended period analysis could be a new concept for the evaluation of generation expansion scenarios in Namibia. In order to simplify the overall analysis and for ease of understanding the overall concept, the reports will show the cumulative present worth of costs to the end of the simulation period for each generation expansion scenario and the cumulative present worth of costs for the extended period.

4.2.3 Cost and Present Worth Datum It is proposed that all costs be expressed at January 2012 prices. All present worth and discounting calculations would also use January 2012 as their reference point.

4.2.4 Escalation The economic analysis will be based on real costs expressed at January 2012 price levels omitting projections for general price inflation during the planning period.

4.2.5 Currency It is suggested that all monetary values be expressed in constant Namibian Dollars, in border prices or equivalence. All economic costs and benefits will exclude all local duties

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and taxes. The Namibian Dollar is pegged at parity to the South African Rand thus a border price to South Africa would be equivalent to the Namibian border price with the addition of an appropriate transportation cost.

4.2.6 Discount Rate Typical practice for World Bank studies is to set the discount rate for economic analysis at 10 percent. This rate was agreed to be the base discount rate at the first Steering Committee meeting which took place on 23 September, 2011.

The study will also consider discount rates of 8% and 12% as part of the sensitivity analysis.

4.2.7 Foreign Exchange Rate The exchange rate used to convert US dollars into Namibian dollars has been set at 7.5 Namibian dollars to one US dollar. This exchange rate takes into account the Standard Conversion Factor (SCF) as outlined in the Key Assumptions Report.

4.2.8 Insurance and Interim Replacement The annual costs associated with insurance and interim replacement are assumed to be 0.25% of the total capitalized cost for each of these components.

4.2.9 Cost of Expected Unsupplied Energy . A customer survey of the market sectors of the ESI in South Africa indicated that the cost of unserved energy could be in the order of 20,000 N$/MWh. Recent surveys in South Africa have suggested even higher values, as high as 75,000 N$/MWh.

An economic expression for the cost of unserved energy is to divide the country’s GDP by the total electricity consumption. Considering Namibia’s GDP of N$ 90 billion and a generation of 3,230 GWh this would result in a value of about 27,864 N$/MWh.

Based on this information, a value of 28,000 N$/MWh or 28 N$/kWh will be used for the cost of unserved energy in this NIRP.

4.2.10 Cost of Losses To evaluate the different transmission expansion plans it will be necessary to compare and cost losses between the different plans. The energy value of losses are to be

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evaluated using the most expensive cost of energy import while capacity losses are to be evaluated based on the cost of gas turbines.

4.2.11 Duties and Taxes Duties and taxes are not included in this economic study.

4.2.12 Interest during Construction (IDC) Interest is a financial cost and as such is excluded from the economic evaluations. The impact of construction periods of different lengths will be taken into account by distributing the capital over the entire construction period. In order to align the distributed investment flow and present value calculation, the rate used will be equal to the discount rate.

4.3 Generation Section 2 of the present report provides details about the existing generation. This section provides criteria for the selection of future generation additions and some of the data for these units. System reliability is also addressed, as well as fuel costs.

4.3.1 Committed Generation Additions The committed/close to committed system additions have already been mentioned in Section 2 but are repeated here for ease of access.

The upgrade/replacement of all runners at Ruacana has been committed and the work is supposed to be completed by July 2013. This replacement will improve efficiency by 5% and could provide 4 MW of additional peaking capacity per unit for a total additional capacity of 12 MW which would bring the station total to 344 MW (3 x 84 + 92).

Paratus diesel station is old (commissioned in 1976 - 35 years old) and unreliable. The replacement of the plant with 4 x 7.5 MW units similar to those at Anixas is expected to allow the existing units to be retired and 30 MW to be added to the system for a net gain of 13 MW. The replacement is assumed to take place by July 2013 but could be delayed due to a variety of reasons.

A study on the potential for rehabilitation of the Van Eck plant has been completed with three options being examined. It appears that the preferred option is rehabilitation with a life extension of 5 years. The plan is to have the rehabilitation work completed by May 2015.

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Presently NamPower is negotiating PPAs with two wind IPPs and one solar IPP. It appears that there are some issues to be addressed before the next stages of the projects are started (finance procurement, EPC bid documents, contract award and construction) and these plants could perhaps only be in-service past 2015.

There are also on-going negotiations with an IPP for the construction of a HFO fired diesel generating plant at Arandis. This plant is very much conditional on the go ahead of either the Erongo Coal plant or the Kudu gas fired plant and as such was not considered as committed.

No other generation commitments have been communicated to Hatch.

4.3.2 Retirement of Existing Generating Facilities The only physical plant considered to retire within the planning horizon is the rehabilitated Van Eck plant which is expected to be retired by the end of April 2020.

The 150 MW contract with ZESA expires in October 2013 but as there is banked energy, the NIRP assumes that supply from ZESA will continue until the end of September of 2014.

The 50 MW contract with ZESCO is assumed to expire by mid January 2020.

4.3.3 Reliability Criteria The primary objective of generation expansion planning is to find the least cost long- term expansion scenario that supplies the forecast demand at an acceptable or specified level of reliability. In any given year it is essential to verify that the generation capacity reserve is sufficient so that the system can meet the load demand even if one or more units are out of service and/or, for systems with significant hydroelectric capacity, unexpected hydrological conditions are encountered. The reliability criteria are usually the deciding factor in scheduling the addition of new generating plants. There are usually two types of reliability criteria used in generation expansion planning: deterministic and probabilistic.

a) Deterministic Criteria There are a number of ways to define deterministic reliability criteria. The core part of these criteria is, however, generation capacity. Depending on the application, these criteria could be measured using the values calculated using generator gross MCR (maximum continuous rating), net MCR (gross MCR less station services), or seasonal MCR (MCR less seasonal derating and/or energy limitation). Some utilities/systems

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apply the deterministic criteria prior to allowing for generating unit planned maintenance outage while others apply them after.

The deterministic reliability criteria are normally expressed in three different ways: (1) a fixed amount of capacity in MW to account for the random outage of one, two or more largest units, (2) a percentage of annual peak demand, or (3) a percentage of annual peak demand plus a fixed amount of capacity.

b) Probabilistic Criteria The probabilistic reliability criteria include both the loss of load probability (LOLP) and the expected unsupplied energy (EUE), which are obtained from the convolution of the load demand and available generation.

LOLP is used to measure the risk associated with having insufficient generation capacity to meet the forecast load demand, which is normally expressed in days per year or hours per year, or as a percentage. For example, a 1% LOLP indicates that the installed generation will not be able to meet the forecast demand in a given year for 3.65 days or 87.6 hours. It is important to understand that a simple LOLP value may have different implications as it could be calculated based on either a daily peak load duration curve or an hourly load duration curve. In the case of the daily peak load duration curve, each day is represented by one point, the highest hourly demand during the day.

EUE is the quantity of expected energy that a system would not be able to serve with the planned generation system in a given year. It is expressed either in MWh or as a percentage in which case it is equal to the expected unsupplied energy divided by the annual energy demand and multiplied by 100.

In this study, it is intended to adopt the LOLP reliability criterion with such a value as to be determined from studies to be carried out as part of the project using historical supply and demand. In addition the capacity policy outlined in the 1998 Energy policy will be taken into account to allow for the requirement that there be sufficient capacity installed within Namibia’s border to meet the expected demand peaks. The EUE and generation capacity reserve will be used as companion criteria with EUE not to exceed a certain value to be determined with the benchmark LOLP studies but it is unlikely that it will be less than 1% in a calendar year.

4.3.4 Emissions Criteria The development of any power plant would need to take full account of the environmental impact of the chosen plant type irrespective of its location. Due

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consideration should be taken of both the indirect and direct environmental effects and, where appropriate, suitable mitigation measures should be put in place.

Environmental considerations for power plants are addressed in Section 5 of this report. One of the environmental considerations for the thermal plants is the likely emissions from the stacks of those plants (sulphur dioxide, nitrous oxides, carbon dioxide and other greenhouse gases, particulate matter, etc.).

In today’s practice it is common when comparing different forms of generation to apply an economic levy on thermal plants to take account of the cost to society of emissions that, while within the legal limits, do create costs that society as a whole must bear. This

is normally done on the basis of the level of emissions such as CO2, SO2 and NOx expected to be emitted by the relevant plant type. Some studies levy a cost in terms of US$ per tonne for the emissions to represent the societal cost for these emissions. For the present study a penalty of 40 N$ per tonne of emissions, representing a societal cost, will be levied against thermal options.

4.3.5 Candidate Thermal Generation Resources The types of plants considered to meet the growing demand and account for the existing plants and contracts that retire during the study period are described in Section 5.

These plants consist of:

1) Primary options with quantified resource and commercially available and proven technologies for which the cost and timing of deploying the technology in Namibia can be quantified with reasonable confidence. These would include coal, natural gas including LNG, uranium, fuel oil, hydro, wind and solar 2) Secondary options with quantified resource but non-mature technology. Small module nuclear reactors fall into this group 3) Secondary options with mature technology but non-quantified resource. A few examples of these are wind, solar, hydro (with sites with less information than for those considered primary options), municipal solid waste, biofuels, biomass, and geothermal.

It should be noted that the output of some resources such as hydro, wind and solar resources is site specific and projects with studies quantifying these resources fall under the primary options while the others without quantifiable values fall under the third category.

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Under the primary options, there are three plants for which considerable amounts of work have been carried out to date.

 The Bi-National Baynes Hydro project with a potential for 600 MW has a feasibility study near completion with both the governments of Angola and Namibia providing support for its development.

 The Kudu 800 MW natural gas fired plant has had several studies carried out and has been presented to the Government of Namibia (GRN) for approval of certain guarantees for both the upstream and the downstream developers.

 Studies and preparations for bids for the Erongo 2 x 150 MW Coal Project are progressing with the environmental and socio-economic impact assessment (ESEIA) scoping study being issued in December 2011 and the technical scoping report also issued in December, 2011. The ESEIA is nearing completion. Prequalification of bidders for the construction of the plant is on-going. The project can be financed by NamPower without GRN guarantees or other strategic partners.

These projects are described in Section 5 and their characteristics even though sometimes very project specific are provided in conjunction with other generic projects using the same technology.

For studies such as the NIRP there are certain values that are required for each of the generation resources including economic life, construction period, commonly used values, outage rates, both planned and unplanned and cash flows. Table 4-1 presents the values for these items which follow commonly applicable industry standards.

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Table 4-1 - Candidate Plants Characteristic Life and Outages

Economic Construction Planned Unplanned Cash Flow Plant/Unit Life Period Outages Outages (%) (%/year) (years) (Years) (%) Coal 30 3 8 7 30%, 40%, 30% CCGT 25 3 6 6 30%, 40%, 30% Gas Turbine 20 2 4 5 60%, 40% Large Hydro 50 6 4 4 10%,15%, 20%, 25%, 20%, 10% Small Hydro 50 3 4 4 30%, 40%, 30% Nuclear 40 6 8 5 10%,15%, 20%, 25%, 20%, 10% Wind 20 2 - - 60%, 40% Solar PV 20 2 - - 60%, 40% Solar Thermal 25 2 - - 60%, 40% MSW 25 3 8 10 30%, 40%, 30% Biomass 25 3 8 7 30%, 40%, 30% Diesel 25 2 4 5 60%, 40% Transmission 30 2 - - 60%, 40% Note: Wind and solar plants were not assigned outage values due to the intermittent nature of the resource

4.4 Fuel Price Forecast This section presents price assumptions in January 2012 US dollars for the fuels to be included in development of the NIRP. The fuels considered include diesel (light fuel oil- LFO), residual (heavy fuel oil (HFO)), natural gas, coal, uranium and other fuels. These fuel prices have previously been presented in the Key Assumptions Report. In this section, the price of fuels are converted from their native and usually used units into US $/GJ and subsequently into N$/GJ.

4.4.1 Fuel Background in Namibia Liquid fuels, mainly in the form of petrol and diesel, dominate the Namibian energy sector. In terms of quantity of net energy consumed, these fuels currently account for over 63% of the total. The sector is controlled by five private oil companies, although the price and distribution of fuel is regulated by government. All liquid fuels are imported.

Coal accounts for, on average, 5% of Namibia’s net energy consumption. As Namibia does not have economically exploitable coal reserves, most coal is imported. The industry is small, and privately owned.

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Biomass is the main fuel of households in the North where most of the population resides.

Namibia has yet to experience a commercial oil discovery, but it is endowed with largely undeveloped energy resources in the form of hydro-power and natural gas (Kudu field). It also has an excellent solar resource, and fair wind resources. The gas and hydro-power resources could prove difficult to reach the operational stage but may offer significant opportunities.

Namcor, the state oil and gas parastatal was established under the Petroleum Act. Although this Act empowers Namcor to operate widely (exploration and production, refining, and liquid fuels marketing), it has limited its activities thus far to promotion of Namibian acreage, including data gathering and marketing exercises, technical management of exploration activities and the rendering of advice to the MME.

Exploration licenses for offshore and onshore drilling have been granted to a few major companies. The exploration is for both oil and natural gas.

Namibia has significant deposits of uranium bearing ore. Further development of this sector could one day result in the production of nuclear fuel for use in Namibian nuclear generating plants.

4.4.2 Underlying Assumptions The liquid fuels used in Namibia are imported and obtained in the world market; therefore for the NIRP the price for these fuels will follow closely international prices for crude oil. As such it was decided to investigate the publicly available forecasts for crude as they could provide a good indication of the most likely future price trends.

Similarly, the coal used in Namibia is also imported and as such new generation sources using this fuel would have to obtain coal in the international markets for which there are a few long range price forecasts.

Finally, it was judged that the base case price forecast for the Kudu natural gas would follow closely the price of internationally traded natural gas i.e. LNG. It was assumed that natural gas available in the international market would be a good proxy for the price of the Kudu gas and in this case the cost of re-gasification would have to be considered. It was concluded that over time the price for Kudu gas could never be greater than the delivered price for internationally traded natural gas plus re-gasification cost as any generation facilities to be built in Namibia using that fuel could be switched over to LNG.

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The forecast prices were collected from four well known institutions, the EIA (Energy Information Administration), WBG (World Bank Group), Sproule and Citi financial company.

The U.S. EIA collects, analyzes, and disseminates independent and impartial energy information to promote sound policymaking, efficient markets, and public understanding of energy and its interaction with the economy and the environment.

Sproule is a diversified, world-wide petroleum consulting firm with 60 years of experience in all aspects of the energy sector throughout North America and the World.

Citi is a global financial services company and provides consumers, corporations, governments and institutions with a broad range of financial products and services.

The forecasts produced by each of the four institutions are recent and are dated as of: 1) The EIA forecast was released in April 2011 2) The WB forecast was released on June 2, 2011 3) The Sproule forecast was released in July 2011 4) The Citi forecast was released on July 6, 2011.

4.4.3 Crude Oil Forecast Crude oil price forecasts were collected from three institutions, the EIA, WB and Sproule. Figure 4-1 shows the forecast prices for crude oil over the next 10 years, i.e. from 2011 to 2020. The EIA price is for imported crude delivered to U.S. refiners. The WB price is for the average spot price around the world and the Sproule price is for UK Brent crude oil.

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(US$/BBL) Crude of Price 40

0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year

EIA WB Sproule

Figure 4-1: Crude Oil Price Forecast The following could be observed from Figure 4-1: 1) The EIA forecast price is expected to increase over the forecast period, i.e. from some $85/BBL in 2011 to some $110/BBL in 2020 2) The WB forecast predicts that the crude price would decrease over the forecasted period, i.e. from some $107/BBL in 2011 to some $80/BBl in 2020 3) The Sproule forecast shows some decreases followed by constant crude price. The lowest price over the forecast period is some $90/BBL.

By comparing the three forecasts, it appears that the Sproule forecast is more applicable to the NIRP study. The reasons for this conclusion include the following:

1) The diesel fuel prices in Namibia will most likely be based on the UK Brent price, instead of the international average price 2) As the developing economies will continuously require more oil to fuel their economic growth, a sharp drop in oil price would be less likely except if the global economy slows down significantly.

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25.00

Diesel Price Forecast

20.00

15.00 (US$/GJ) 10.00

5.00

0.00 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year

EIA WB Sproule

Figure 4-2: Unit Energy Price – Distillate Fuel

Figure 4-2 and Figure 4-3 show the forecasted prices for distillate fuel oil (light fuel oil – LFO) and residual fuel oil (heavy fuel oil – HFO380), which were calculated based on the crude oil price forecasts and the distillate/crude ratio and residual/crude ratio used by the EIA.

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25.00 HFO Price Forecast

20.00

15.00

(US$/GJ) 10.00

5.00

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EIA WB Sproule

Figure 4-3: Unit Energy Price – Residual Fuel It is important to note that the prices shown in Figure 4-1, Figure 4-2 and Figure 4-3 are based on the crude oil prices delivered to the refiners and do not include refining cost and delivery cost of the refined products.

To account for transportation, handling, insurance and losses an additional cost of US$ 20/BBL will be added. It is recognized that existing diesel power stations in Namibia use a lighter HFO which is a mixture of HFO380 and LFO. For the NIRP the average cost of the two fuels is used.

For forecasts beyond 2020, it is assumed that the trend of say from 2015 to 2020 would be followed from 2021 to 2030.

4.4.4 Price Forecast for Kudu Natural Gas The forecast prices for natural gas were collected from the EIA, WBG and Sproule. As previously mentioned, it is assumed that these forecasts would serve as a proxy for the expected prices for the Kudu natural gas. Figure 4-4 shows two groups of forecasted prices, for Henry Hub (U.S.) and Europe. It can be seen from this figure that the Henry Hub prices are lower than the European prices. Similar to its oil price forecast, the WB predicted a decrease in price for the European gas. For Britain, Sproule forecasts a price

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increase over the next couple of years with a large dip in 2014. Other forecasts predict increases in natural gas prices. 12

4 Price of Natural Gas (US$/GJ) Gas Natural of Price

0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year EIA--Henry Hub WB--Henry Hub Sproule--Henry Hub WB--Europe Sproule--Britain

Figure 4-4: Natural Gas Price Forecast In view of the above values it is difficult to forecast a proxy price for the Kudu natural gas. From the values shown in Figure 4-4 it appears that Henry Hub prices will increase significantly over the 10 year period (from 2011 to 2020) and that European and Henry Hub prices could become closer in the future.

Given the physical location of Namibia and its likely LNG sources, one could argue that a modified Sproule’s price forecast for the European gas could be more reasonable for use in this NIRP study. It is also important to note that the prices presented in Figure 4-4 are the ones at main hubs and they do not include the component required to transmit the gas to its final destinations. Given the above it is assumed that the delivered cost of natural gas would be in the order of 10.0 US$/GJ.

For natural gas price forecasts beyond 2020, it is assumed that the trend from 2015 to 2020 would be followed from 2021 to 2030.

At the first Steering Committee meeting, Hatch was requested to also consider the economic price of gas given the cost of developing the field and its operation and

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maintenance. In order to carry out this calculation it is required to consider that the guaranteed recoverable amount of gas is 588 PJ as opposed to the 1.3 tcf (and thus 1,300 PJ) that has been reported as the Kudu gas field potential for delivery to the gas plant. This amount of gas is sufficient to run the Kudu 800 MW power plant for about 15 years at a capacity factor of about 85% and using very efficient gas turbines.

Assuming a total capital cost of US$1,100 million which includes the EPC contract, contingencies, capital alignment (IDC), owner’s costs and financing charges this can be converted to an annuity at the desired discount rate. The annual operation costs which include the lease cost of a FPS (floating processing station) could amount to US$ 100 million per year. Taking into account the total annual costs (annuity plus OPEX) and a base discount rate of 10%, the cost of natural gas would be 6.19 US$/GJ or 46.35 N$/GJ.

Table 4-2 provides a summary of the economic cost of the Kudu gas at different discount rates over either 15 or 20 years but assuming always the same quantity of gas (588 PJ).

Table 4-2 - Economic Price of Kudu Natural Gas

Discount Life of Field Economic Price of Kudu Rate (%) (Years) Gas (US$/GJ) (N$/GJ) 5 15 5.20 39.00 8 15 5.77 43.28 10 15 6.19 46.43 12 15 6.61 49.58 15 15 7.29 54.68 5 20 6.33 47.48 8 20 7.14 53.55 10 20 7.72 57.90 12 20 8.33 62.48 15 20 9.30 69.75

4.4.5 Estimate of Natural Gas Price from Liquefied Natural Gas Natural gas transported as LNG needs to go through the LNG chain from its production at a well to the use for electricity generation in a power plant, i.e. production, liquefaction, transportation, regasification and transmission. The price of gas delivered at a power plant should therefore include all cost contributions from these five processes.

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Although LNG supply under spot and short term contracts (with a duration of four years or less) has increased over recent years, LNG transactions have mainly been based on long-term contracts lasting for 20 or more years. The terms and conditions of the long- term contracts will include at least several key clauses such as annual supply quantity, price, delivery format (such as FOB – free on board and destination) and price adjustment mechanism. The LNG FOB price usually covers two components in the LNG chain, production and liquefaction. As an LNG contract is subject to many factors, its price therefore varies widely, from a couple of US dollar per GJ to some US$ 20 per GJ, i.e. from N$15 to N$ 150 per GJ. An LNG FOB price of US$ 6/GJ (N$ 45/GJ) is assumed in this study.

A transportation cost of US$ 50/Tonne will convert to a rate of US$ 1/GJ based on the assumption that the heating value of LNG is 50 GJ/Tonne. In this estimate it was assumed that the lease fee of one LNG vessel with a capacity of 135,000 cubic meters would be some US$ 100,000 per day and each LNG delivery trip would require the ship for some 30 days.

In order to estimate the costs associated with the other two processes, i.e. regasification and transmission, it is necessary to estimate the LNG requirements of the CCGT power plant. Presuming natural gas with a heating value of 1,050 GJ/MMCF (million cubic feet) or 50 GJ/Tonne and a 150 MW CCGT unit with a heat rate of 7.4 GJ/MWh (HHV) and an annual capacity factor of 85%, the daily and annual gas consumption of two 150 MW units will be some 43 MMCF (906 tonnes of LNG) and 15,743 MMCF (330,600 Tonnes of LNG) respectively.

As per commercially available technologies, regasification of LNG could be processed via either an on-shore based LNG receiving terminal or a floating storage and regasification unit (FSRU). An on-shore terminal needs a very large amount of capital investment and could handle some 6 to 12 million tonnes of LNG per year. For this project, a small scale FSRU is adequate to deliver the required amount of natural gas and it can be leased as opposed to a permanent land based facility. It is estimated that the capital cost of the FSRU will be some US$ 250 to US$ 350 million. With an assumption of 15 years of capital repayment period, 15% return requirement on capital and operation and maintenance (O&M) cost of 3% capital investment, the annual rental and O&M cost of the FSRU will be some US$ 50 to US$ 70 million, or US$ 3.04/GJ to US$ 4.26/GJ.

By assuming the pipeline from the floating terminal to the CCGT power plant to be 20 km long, the unit capital cost of US$ 2.5 million per kilometer, a capital repayment period of 15 years, 15% return requirement and O&M cost of 3% capital investment, the

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annual capital repayment and O&M cost of the pipeline will be some US$ 10 million per year, i.e. US$0.61/GJ.

Based on the above calculations, the estimated unit cost of the natural gas will be some US$ 11.65/GJ to US$ 12.86/GJ. Taking into account 10% allowance for losses and other contingency factors, the unit cost will be some US$ 12.81/GJ to US$ 14.15/GJ. An LNG gas price of US$ 13.5/GJ (N$ 101.25/GJ) is assumed in this study.

4.4.6 Coal Price Forecast The coal prices shown in Figure 4-5 were obtained from forecasts by the EIA, WB and Citi financial company and are for the FAS (free alongside ship) or FOB (free on board) prices and do not include the fees and costs for internal unloading, loading and transportation. It is noted that the price from the EIA is for exported coal produced in the U.S., the WB forecast is for Australian coal and the Citi forecast is for thermal coal. It is possible that the higher EIA price has a significant portion of coking coal.

As can be seen from Figure 4-5 there is a wide range of prices by 2020 with forecasted prices ranging from about 85 US$/tonne to 150 US$/tonne. It must be noted that energy prices are relative amongst themselves and this can be seen by comparing the WB forecasts for crude oil and coal. The EIA forecast appears to be quite high and its starting point is some 20 US$ tonne higher than prevailing prices which suggests use of Citi’s coal price forecast would be most appropriate.

160

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0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Year

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Figure 4-5 - Coal Price Forecast

The NIRP will use an average coal price of 130 US$/tonne for the entire period plus 25 US$/tonne for shipping, handling (including expansion facilities at a given port) and delivery to a power plant close to a major power port.

4.4.7 Price Forecast of Other Fuels In addition to the fuels mentioned above, the NIRP considers generation technologies that use other fuels such as uranium, municipal solid waste, biofuels and biomass and as such a fuel price forecast for these is needed.

There are several ways of quoting prices for uranium but the ultimate measure, like for any other fuel, is the unit price per GJ or other energy measuring unit. For the NIRP, uranium is to be priced at US$ 1/GJ.

Several studies in the US and Europe have been carried out to determine the cost of collecting and delivering municipal solid waste taking account that in this case the tipping fees for normal refuse would be saved. The estimated cost of collecting and delivering the municipal solid waste to a plant using this fuel is 135 US$/tonne in the United States. As no specific information was located for Namibia it is assumed that the cost would probably be half that amount in Namibia or 67.5 US$/tonne or 506.25 N$/tonne.

Biofuels especially biodiesel from jatropha have increased in production significantly in the last decade. Presently, biodiesel is a reality in many parts of the world and large plots of land are dedicated to crops that can produce this type of fuel. Presently it is possible to produce and bring to market biodiesel at 3.0 US$ per US gallon or 0.79 US$/liter (5.93 N$/l).

Invader bush has tremendous potential in Namibia to fuel small biomass plants. Given that this fuel is labor intensive and requires machinery to cut the bush and transportation to a central plant it is assumed based on limited information that this would cost about 500 N$/tonne.

4.4.8 Heat Content of Fuels and Unit Prices of Energy The previous sections have provided prices of fuels in various units. This sections converts all these prices to a common unit of which the GJ has been selected. In order

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to do this one requires the different values of heat content of each fuel. Table 4-3 provides the heat content of the various fuels previously mentioned.

Table 4-3 - Heat Content of Fuels (HHV) Fuel Heat Content Units LFO 5.90 MBtu/BBL HFO380 6.25 MBtu/BBL HFO150 6.1 MBtu/BBL Natural Gas 1,000 Btu/scf Coal 12,000 Btu/lb MSW 4,300 Btu/lb Biofuel 33.3 MJ/l Biomass 2,000 Kcal/kg

Taking into account the prices of the fuels provided in the above section and the heat content of these, the unit prices of energy are given in Table 4-4.

Table 4-4 - Unit Price of Fuels (HHV) Fuel Fuel Price (US$/GJ) (N$/GJ) LFO 20.00 150.00 HFO380 16.00 120.00 HFO150 18.00 135.00 Natural Gas 10.00 75.00 Economic price NG 6.18 46.35 NG from LNG 13.5 101.25 Coal 5.55 41.65 Uranium 1.00 7.50 MSW 6.75 50.63 Biofuel 23.72 177.93 Biomass 7.96 59.71 Geothermal 0.1 0.75

4.5 Transmission This section presents a brief overview of the planning parameters to be used for the transmission planning studies which will assist in developing an expansion plan capable of delivering the load requirements from the expected generation locations to the load centers in a reliable and economic manner throughout the 20-year timeframe of the study.

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One of the principal objectives of electrical system planning is to develop a power system with a certain performance level within acceptable degrees of adequacy and security based on a trade-off between costs and risks. In order to develop a power system, certain performance measures or criteria are adopted and these measures depend on factors such as availability of generation, voltage levels, size and configuration of the system, control and communication facilities and resource constraints. Practices vary from system to system and the common theme in the various approaches is the acceptable system performance.

Planning criteria are a set of rules or parameters which must be adhered to in carrying out analysis of generation and transmission system expansion alternatives. It is sometimes permissible to have slight deviations when it makes good technical and/or economic sense.

Study criteria are usually developed by experienced personnel with several years of participation in the sector and these are system planners, system operators, economists and other specialists involved in the electricity sector. Planning criteria can be divided into three main areas; Study area and horizon, technical criteria and capital costs and economic criteria. The following subsections address each of these areas with emphasis on the technical criteria and it should be noted that in Namibia there are already established guidelines for the transmission planning criteria. The existing criteria are indicated as well as providing proposed values for the parameters that have not yet been identified by the responsible entities.

4.5.1 Study Area and Horizon The study area to be considered is comprised of the interconnected electrical system of the Republic of Namibia. Neighboring networks could be represented by equivalents. A system model is to be made available by NamPower to be used at their offices.

The study horizon is the same as for the generation studies i.e. 2012 to 2031. In order to analyze the existing system performance, studies will be carried out for the 2011 system.

4.5.2 Technical Criteria a) Bus Voltages The acceptable voltage variation under normal and contingency conditions is summarized below:

System Voltage Variations

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Variation (%, of nominal) Condition Max Min Normal +5% -5% Contingency +10% -10%

b) Thermal Loading The acceptable loading limit for the transmission equipment is summarized below:

Equipment Loading

Normal Contingency Equipment Condition (%) Condition (%) Transmission Lines 100% 110% Transformers 100% 110%

The above values are expressed as a percentage of the equipments’ continuous rating. For transmission lines using ACSR conductor their current carrying capability is to be established at 90°C while for those with other conductors the capability will be established at 75°C.

c) System Security Criteria It is common for systems to adopt contingency criteria to allow satisfactory system operation to be maintained during outage conditions. For the Namibian system, the transmission system should be adequate to supply all load and evacuate all generation with the outage of any single transmission line or transformer (N-1) whenever possible. In addition, the system should also maintain satisfactory system performance for a double contingency consisting of a generator plus a transmission line emanating from the generating station.

d) Spinning Reserve Modern power systems usually have sufficient spinning reserve to allow for the loss of the largest unit on line or a significant portion of it. The greater the spinning reserve the larger the costs but the more security a system has. Presently, the system has a spinning reserve of 17 MW as stipulated by the SAPP rules but this will increase once larger generators are brought in-service.

e) Load Power Factor The system will be planned for a load power factor of 0.90 at the 66 kV voltage level. Individual load buses may have a lower or higher power factor.

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f) Fault Levels The maximum fault levels in the system should be below 80% of the rated interrupting capacity of the circuit breakers determined using the generators’ transient impedances.

g) Frequency Criteria A range of +/- 0.5 Hz is considered acceptable for frequency variation. In case of outage of some elements, the system may resort to the under frequency load shedding scheme to control the frequency.

h) Network Stability The system should remain stable following a 3 phase fault resulting in the tripping of a single faulted element.

4.5.3 Capital Costs and Economic Criteria The economic criteria to be used for comparing alternatives in the transmission studies are shown above in Section 4.12.

In order to compare overall costs of transmission alternatives, the capital costs of new equipment additions and its associated operation and maintenance costs are required. In addition, the cost of losses should also be incorporated into the overall analysis as different alternatives have different levels of losses.

a) Capital Costs In order to be able to estimate the capital cost of each transmission alternative, unit costs of equipment are required. The transmission equipment costs will be developed based on the latest costs in Namibia for transmission lines at different voltages and for substations.

b) Operation and Maintenance Costs For the present studies, it is assumed that the annual operation and maintenance charges would be equal to 1.5% of the total capital investment for each item of equipment. It is recognized that transmission lines require a lower percentage for operation and maintenance but substation equipment requires a higher percentage thus the selected value represents an average value for all transmission equipment.

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5. Generation Resources and Technologies 5.1 Introduction This section provides brief descriptions on the generation resources and their associated technologies which will be taken into account in the preparation of the NIRP. The generation resources include both domestic and imported resources such as coal, natural gas including LNG, uranium, fuel oil, hydro, wind, solar, municipal solid waste, biofuels, biomass and geothermal. In order to assess the quantity of these resources and evaluate the maturity of the generation technologies using these resources at appropriate levels, Hatch has divided them into the following groups:

1) Primary options with quantified resource and commercially available and proven technologies for which the cost and timing of deploying the technology in Namibia can be quantified with reasonable confidence. These would include coal, natural gas including LNG, uranium, fuel oil, hydro, wind and solar 2) Secondary options with quantified resource but non-mature technology. Small module nuclear reactors fall into this group 3) Secondary options with mature technology but non-quantified resource. A few examples of these are potential sites for hydro, wind, solar for which no detailed studies have been completed, municipal solid waste, biofuels, biomass and geothermal.

5.2 Primary Generation Resources This section of the report presents a brief outline of each of the primary resources selected to meet the growing demand in Namibia. The sources of the resources include publically available information from various web sites, published study reports as well as Hatch’s in-house data base.

5.2.1 Coal Fired Power Plants Coal reserves are available in almost every country around the world, with recoverable reserves in some 70 countries. It has been estimated that the proven coal reserves are enough to last us well in excess of 120 years at the current rates of production. In contrast, the proven oil and gas reserves are equivalent to some 50 and 60 years respectively at the current production levels.

Coal deposits in Namibia have not been commercially exploited. All coal used in the country is imported from South Africa and other countries. Coal deposits in Namibia are stratigraphically confined to the Ecca Group of the Karoo Sequence. Coal potential exists in extensive sedimentary basins like the Owambo, Huab, Waterberg and Aranos basins.

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The Aranos basin has been investigated in detail for coal. The Aranos coal basin, which contains in situ resources of about 350 million tonnes of high-quality metallurgical coal at a depth of up to 300 m, is the largest known coal deposit in the country. At this time, most of these coal resources can’t be economically developed when comparing with development of coal mines in other Southern Africa countries, especially South Africa, Botswana and Mozambique. Coal resources in these Southern Africa countries are considered to be more than sufficient to supply a large power plant in Namibia over the course of its normal life.

In South Africa, more than 75% of primary energy needs are provided by coal. In addition to the extensive use of coal in its domestic economy, about 30% of the country’s production is exported, mainly through the Richards Bay Coal Terminal, making South Africa one of the top coal exporting countries in the world. Coal supply to a power plant in Namibia could be secured through a long term coal supply agreement with one or more coal mines in that country or in the region. In general, regional coal mines should prove to be the most economic sources due to shorter transport routes and lower transport cost. However, this may be offset by anticipated increasing transport cost, supply risks and increasing handling costs due to political and economic instability.

Power generation using coal normally involves three major stages, coal mining, transportation of coal to the power plant and conversion of the coal into electricity. It is understood that cost reduction in any of the three stages could eventually reduce the cost of unit electricity production. When selecting a coal fired power plant site, quite a few important factors need to be taken into account including land availability, fuel source, fuel transportation, electricity transmission, water availability, ash disposal, environmental and socio-economic impacts.

A conventional coal fired generating unit is comprised of a coal-fired boiler to convert the energy contained in the coal into heat and high pressure steam which is then used to drive a steam turbine coupled to an electricity generator. Due to its high initial investment cost and technical constraints, a coal fired generating unit is normally used to supply base load in order to reduce the unit energy cost. This implies that a coal-fired generating unit should be dispatched at its highest available output most of the time in order to achieve economies of scale. As the primary fuel for electric power generation, generation technologies using coal have experienced a long development process and some of them are well established and proven.

The commonly used coal-fired power generation technologies in the modern power industry include pulverized coal (PC) combustion with/without installation of flue gas

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desulphurization (FGD) equipment and circulating fluidized bed (CFB) combustion, which are technically proven and have very well defined cost estimates. The PC with FGD and CFB combustion technologies would also reduce SO2 emissions. One of the main advantages of the CFB combustion against PC combustion is that the former could use a variety of fuels and does not require FGDs.

Coal is becoming more controversial due to its high level of greenhouse gas (GHG) and other emissions (if they can’t be abated in a cost effective manner) when compared to other primary energy options. The most advanced technologies for coal power generation are integrated gasification combined cycle (IGCC) and carbon capture and sequestration (CCS), which could significantly reduce emission of GHG into the atmosphere. These two technologies will of course increase the initial capital investment significantly as well as operation and maintenance cost and therefore increase the unit cost of electricity. It has been estimated that the CCS could increase the capital cost of a coal-fired power station by around 35%. As understood, construction of a CCS is subject to geographical and geological constraints and such a facility could only be built at limited locations.

The size of a coal fired generating unit can range from 10 MW to over 1,000 MW. The typical service life of a coal fired generating unit could vary from 30 to 50 years. However in economic and financial analysis, an economic life of 20 to 30 years is normally used. Based on the potential electric load growth over the next 20 years, the unit size of around 150 MW would be suitable to the Namibia electric system. Larger sized units could result in excessive base load generation capacity and higher operating reserve obligations as determined by SAPP. Excessive based load generation implies that internal customers could not consume all energy generated over the off-peak periods and, if the unit could not be economically curtailed or shut down during this period, part of the output must be sold to the external markets at much lower prices than the average generation cost. In some cases, the base load energy prices could be negative, i.e. the generators must pay the customer to consume electricity. This situation has already occurred in some electricity markets.

The higher operating reserve obligations (due to larger unit size) means that the Namibian electric system must operate and maintain other units to provide spinning reserve and quick start reserve which normally have high incremental generation cost. The Namibian electric system operator can, of course, purchase a certain amount of spinning and quick reserves from other SAPP countries depending on the SAPP rules.

The lead time to develop the 150 MW coal generating unit could be six to seven years if a standard (or off-the-shelf) technology is selected, which includes scoping study,

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feasibility study, environmental impact assessment, tendering documents, EPC (engineering, procurement and construction) documentation and bid evaluation, procurement of financing and financial closing, construction and commissioning. Larger sized units, new technologies or sea water cooling may have a longer lead time. Fast tracking could of course reduce the lead time considerable especially if some of the steps outlined above are bypassed by using balance sheet financing and carrying out some of the steps on a concurrent basis.

In Namibia, the existing Van Eck coal fired power station located in Windhoek uses coal imported mainly from South Africa. This plant has been used as standby over the last several years due to environmental constraints, high coal transportation cost, low efficiency and low cost of power imports from other SAPP countries.

A scoping study for development of a coal fired power plant in Namibia was recently completed and the plant could be located in the Erongo province and is often referred to as the Erongo Coal Power Plant. Such a plant would first be constructed with two 150 MW units and could be expanded with more units up to a total capacity of 800 MW when required.

For the NIRP study, the candidate coal-fired power plant with a unit size of 150 MW using either CFB or PC technology has been selected as it fits well with system demand requirements for the near future. The following is a short description of the factors for a standard CFB power plant and a PC power plant without installation of FGD equipment and explanations to the parameters presented in Table 5-1:

1) The CFB and PC technologies for the 150 MW unit size have been utilized in many power plants around the world and are commercially available and technically proven 2) For the Erongo Coal Power Plant, the CFB combustion was recommended against the PC combustion due to the fact that the CFB could use a variety of fuels including invader bush which is available in Namibia, have a minimum loading requirement as low as some 35% of its full output and remove most sulfur in the coal during the combustion. The low minimum loading requirement of the CFB technology could have advantages to the Namibian electric system 3) Due to environmental and social issues including community opposition, with a coastal location, an inland site was selected 4) The coal required by the plant could be supplied from Richards Bay, South Africa as both resources and infrastructure are in place at that location. The coal could also

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be imported from Mozambique and Botswana if necessary. Part of the required coal could also be substituted by locally harvested invader bush 5) With a total net capacity of 300 MW for the first phase, the annual coal consumption has been estimated at some 1 million tonnes. The current unloading facilities at Walvis Bay harbor and rail transport of the coal to the coal power plant site would need moderate upgrades and investments 6) The fuel price used in the study is the price for fuel to be delivered to the plant site, i.e. including all transportation and handling costs 7) Several alternatives had been investigated for the plant cooling technology in the scoping study of the Erongo coal power plant, of which a dry air-cooled condenser had been identified as the optimum solution. Its main advantages are the low water consumption, low investment cost and ease of operation 8) A list of potential EPC contractors had been identified in the Erongo power plant scoping study. Most of them are from India, China and Korea and only one is from Japan. It is noted that the EPC bidding prices from these contractors could be much lower than those from Western economies based contractors 9) The lead time would be some six to seven years, including scoping study, feasibility study, EPC contract document preparation as well as tendering and awarding, financing closure, construction and commissioning. A fast track approach could be used to shorten the lead time to 4 years 10) It is expected that the equivalent availability of a unit would be around 85%, which is based on the information available in the NERC database. Its capacity factor could, therefore, only be up to this value as the unit might not produce at its full capacity all the time due to various reasons such as low load demand, contribution to spinning reserve obligation, etc. 11) The EPC costs for CFB and PC technologies have been estimated at US$1,900 (N$14,250) per net unit capacity (kW) and US$1,700 (N$12,750) respectively plus 10% contingency 12) Owner’s cost has been estimated at 5% of the total EPC cost 13) The construction time for a 150 MW coal fired plant would be some three years, with a cash disbursement of 30%, 40% and 30% in year 1 to year 3 of construction respectively. In order to align the capital expenditure to the in-service date, the base discount rate is used to calculate the interest during construction (IDC) 14) 1.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees.

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15) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation. 16) Fixed operation & maintenance (O&M) cost was calculated based on 2.5% of the unit’s total capitalized cost. 17) Variable O&M cost was calculated based on 3% of the unit’s total capitalized cost and 83% capacity factor. 18) Annual insurance cost is assumed to be 0.25% of the total capitalized cost. 19) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost. 20) Emission rates of CO2, NOx, SO2 and particulate matter are the uncontrolled factors calculated based on the parameters for CFB, PC and ESP (electrostatic precipitator), collected from the U.S. EIA and EPA. The SO2 emission factor was calculated based on 1% sulfur coal. The PC combustion will have higher emission factors of NOx and SO2.

5.2.2 Natural Gas Including LNG Fueled Power Generation Natural gas is a naturally occurring hydrocarbon gas mixture consisting primarily of methane, with up to 20 percent concentration of other hydrocarbons (usually ethane) as well as small amounts of impurities such as carbon dioxide. Natural gas is widely used and is an important energy source in many applications including heating buildings, generating electricity, providing heat and power to industry and vehicles and is also a feedstock in the manufacture of products such as fertilizers.

Natural gas is commercially extracted from oil fields and natural gas fields. Gas extracted from oil wells is called casing head gas or associated gas. The natural gas industry is extracting gas from increasingly more challenging resource types: sour gas, tight gas, shale gas, and coal bed methane.

Total world proven natural gas reserves, as of the end of 2010, were 187 trillion cubic meters (TCM; or 6609 trillion cubic feet - TCF). At current production rates, this would last some 59 years. Reserves have grown about 2% per year. With production also growing, the reserve-to-production ratio has stayed within the range of 58 to 68 years since 1985. The four nations with the largest reserves are Russia (45 TCM), Iran (30 TCM), Qatar (25 TCM) and Turkmenistan (8 TCM).

The efficient and effective movement of natural gas from producing regions to consumption regions requires an extensive and elaborate transportation system. In many instances, natural gas produced from a particular well will have to travel a great

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distance to reach its point of use. The transportation system for natural gas consists of a complex network of pipelines, designed to quickly and efficiently transport natural gas from its origin to areas of high natural gas demand. Transportation of natural gas is closely linked to its storage. Should the natural gas being transported not be immediately required, it can be put into storage facilities for use when it is needed.

Because of its low density, it is not easy to store natural gas or transport it by vehicle. Natural gas pipelines are impractical across oceans. In these cases, gas can be turned into liquid at a liquefaction plant, and is returned to gas form at a re-gasification plant at the terminal. Ship borne re-gasification equipment can also be used. LNG carriers transport LNG across oceans, while tank trucks can carry liquefied or compressed natural gas (CNG) over shorter distances. Sea transport using CNG carrier ships that are now under development may be competitive with LNG transport in specific conditions. As per the industrial practice, LNG is the preferred form for long distance, high volume transportation of natural gas, whereas pipeline is preferred for transport for distances up to 4,000 km over land and approximately half that distance offshore.

The number of LNG producing countries steadily continues to grow, from 8 in 1996 to 15 at the beginning of 2008, with four more (Yemen, Angola, Peru, Russia) by around 2012. The number of consuming countries is also growing; currently 16 countries have re- gasification terminals, forcing the LNG trade to become more competitive and market driven. A recent IEA (International Energy Agency) estimate calculates more than $250 billion of new investment, in all parts of the LNG chain, will be required to meet demand up to 2030. This includes more than $67 billion spent during the period 2006–2010. It is widely predicted that global LNG trade will grow by at least 10% - 15% over the next few years.

Two distinct LNG trade regions have developed over the past few decades, the Atlantic and the Pacific regions. Until Qatar, and to a lesser extent, Oman, began to export LNG to both regions in the mid-1990s, the two regions were largely separate, with unique suppliers, pricing arrangements, project structures, and terms. There were occasional spot sales with suppliers from the Pacific region selling to the Atlantic region customers. However, long-term contracts between the regions began with Qatar and Oman selling to Europe and North America. Future plants in Australia, Indonesia (potentially exporting to western North America) and Yemen are all looking at exporting to both the Atlantic and Pacific markets, further blurring the distinction between the regions. The growth of the LNG spot market, though small in absolute terms, has proved that LNG can be economically exported from Trinidad to Japan, and from Australia to Eastern US.

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In Namibia, the Kudu gas field is situated approximately 130 km off-shore to the southwest of the city of Oranjemund in the south western corner of Namibia. The gas field is located about 4.5 km underground and would require an under-sea pipeline of around 130 km to reach the shore. Water depth at the site is around 170 meters.

The Kudu offshore gas field was discovered in 1974 and the license has been held by a number of companies including Royal Dutch Shell, Chevron Texaco and Energy Africa. In 2004, Tullow Oil acquired Energy Africa and with it its interest in the license. Presently the rights are held by Tullow Oil with 31% of the shares, Itochu Corp. with 15% and the rest (54%) are held by a consortium formed by the Namibian state oil company Namcor and Gazprombank of Russia. Tullow Oil is the developer.

The Kudu offshore gas field is estimated to contain 1.3 trillion cubic feet (37 billion cubic meters) of proven natural gas reserves. However more recent exploration and analysis suggests that reserves could reach 3 trillion cubic feet (85 billion cubic meters) with a potential much higher than the suggested reserves. These figures though are dependent on further work that is yet to be carried out by Tullow Oil on different parts of the field with other geological settings.

The gas from the Kudu gas field is a sweet gas requiring little cleaning and processing and is available at a certain pressure and temperature. At the present time it is envisaged that the gas would be processed on a floating plant system (FPS) to be contained in a permanently moored large ship and from the FPS an undersea 170 km long pipeline would be constructed to bring the gas to Namibian soil at Uubvlei (close to Oranjmund) where it would be used to supply a 800 MW power plant. The field would be crucial in meeting Namibia's growing energy demand in the near future.

Various gas turbine technologies have been developed and used around the world by using natural gas or diesel fuel to generate electricity. In this case, instead of heating steam to turn a turbine, hot gases from combusting fossil fuels are used to turn the turbine and generate electricity. Gas turbine plants are traditionally used primarily for peak-load demands, as it is possible to quickly and easily turn them on. These plants have increased in popularity due to advances in technology and the availability of natural gas. Gas turbines can be combined with a steam turbine to form a combined cycle unit. In combined-cycle plants, the waste heat from the gas-turbine process is directed toward a heat recovery steam generator (HRSG) which in turn supplies steam to a steam turbine to turn an electric generator. Because of this efficient use of the heat energy released from the natural gas, combined-cycle plants are much more efficient than steam units or gas turbines alone.

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The size of a single gas turbine could range from a few MW to some 400 MW. Selection of the single unit/plant size is determined by such important factors as regulations/policies, location, load requirements, fuel availability, cost and transmission/distribution access. For the NIRP study, the net sizes selected for CCGTs are 150 MW and 400 MW and the net sizes for GTs are 50 and 100 MW. In the case of a 400 MW unit, it is expected that there would be two GTs, each rated at some 134 MW and one steam turbine rated at 134 MW. It is noted that two 400 MW units were recommended by the Kudu Gas-to-Power Project Study although this size is relatively high to the Namibia electric system and it would increase the Namibia system’s operating reserve obligation from the current 34 MW (17 MW of spinning reserve plus 17 MW of quick start reserve) to some 120 MW as per the current SAAP operating reserve allocation rules.

Based on the Kudu Gas-to-Power Project Study, the power station near Oranjemund is being designed for a 800 MW net capacity, one half of which (400 MW) would be sold to utilities outside Namibia through long tern power sale contracts. The total amount of gas available to the Kudu project is contractually limited to 588 PJ (petajoule). This amount of available gas is insufficient for continuous year round operation of the Kudu power plant at its full capacity. It has been estimated that the 588 PJ could provide fuel to the power plant for 15 years.

Studies have determined that the power station and an 18 inch gas pipeline from the gas field to the power station would be designed and constructed in such a way that the power station could be operated in a more flexible manner targeting mid merit/peak periods. Studies to date have concluded that the resulting plant capacity factor would be around 87%. The additional cost in the design of Kudu power plant and the pipeline for creating operating reserves for mid merit/peaking is not significant relative to the benefits of operational flexibility, risk management and potential commercial advantages. The operational flexibility is particularly valuable to NamPower as its other major supply option is the run-of-the-river Ruacana hydro power station. Ruacana cannot run at its full capacity for a large part of a year due to low storage capacity.

In this study, two sizes for each of CCGT and GT candidates are taken into account in development of generation expansion sequences. The CCGT sizes are 150 MW and 400 MW while the GT sizes are 50 MW and 100 MW. The following is a short description of the factors for the selected CCGT and GT sizes and explanations to the parameters presented in Table 5-2:

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1) The CCGT and GT technologies for the selected size ranges are technically proven and commercially available and have been widely used in electric power generation around the world 2) The CCGTs and GTs could be fueled by either Kudu natural gas or imported LNG. In the case of Kudu gas, a pipeline from the gas field would be required while in the case of LNG, LNG would be shipped from the LNG production countries and then be re-gasified in Namibia. It is important to note that all natural gas prices are assumed to be the delivered prices to the plant 3) The infrastructure for natural gas transportation and/or re-gasification is at present not in place. This may take a relatively long time to build and need government support to bring this on line 4) Similar to the EPC contract for a coal plant, it is expected most EPC contractors for a CCGT or GT plant would come from India, China and Korea and the EPC bidding prices from these contractors would be lower than those estimated using the developed economy standard. The major equipment for a plant could still be procured from the manufacturers located in the developed economy countries 5) The lead time for a CCGT plant could be some five to six years while it could be one year shorter for a GT plant, including scoping study, feasibility study, EPC contract document preparation as well as tendering and awarding, financing closure, construction and commissioning. Given the studies already carried out, the progress made to date in project structuring and the status of the negotiations with the upstream developer this could probably be reduced by one year 6) It is expected that the equivalent availability of a plant would be from 87% to 90%, based on the information from the NERC database. Its capacity factor could, therefore, be only up to this range as the plant might not produce at its full capacity at all times due to various reasons such as low load demand, contribution to spinning reserve obligation, etc. 7) Supply of natural gas or LNG could be by a take-or-pay contract. This means that the monthly payment would be fixed no matter if the fuel would be consumed by the power plant or not 8) The EPC costs for CCGT 150 MW, CCGT 400 MW, GT 50 MW GT 100 MW have been estimated at US$950 (N$7,125) per net unit capacity (kW), US$900 (N$6,750), US$700 (N$5,250) and US$650 (N$4,875) respectively plus 10% contingency 9) Owner’s cost has been estimated at 10% of the total EPC cost 10) The construction time for a CCGT unit would be some three years, with a cash disbursement of 30%, 40% and 30% for year 1 to year 3 respectively, while the

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construction time for a GT unit is two years with a cash disbursement of 60% and 40%. In order to align the capital expenditure to the in-service year, the base discount rate is used to calculate the interest during construction (IDC) 11) 1.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 12) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 13) Fixed operation & maintenance (O&M) cost was calculated based on 2.5% of the unit’s total capitalized cost 14) Variable O&M cost was calculated based on 5% of the unit’s total capitalized cost and 85% capacity factor for CCGTs and 25% capacity factor for GTs 15) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 16) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost 17) Emission rates of CO2, NOx, SO2 and particulate matter are the uncontrolled factors calculated based on the factors collected from the US EIA and EPA. It is expected the current CCGT and GT technologies would reduce the NOx by 90%. The SO2 emission factor was calculated based on 1% sulfur natural gas.

5.2.3 Fuel Oil Fired Power Generation The total proven oil reserves in the world were estimated at some 1.5 trillion barrels at the end of January 2011. The three countries with most oil reserves around the world are Venezuela with 297 billion barrels, Saudi Arabia with 267 billion barrels and Canada with 178 billion barrels.

Because the geology of the subsurface cannot be examined directly, indirect techniques must be used to estimate the size and recoverability of the resource. While new technologies have increased the accuracy of these techniques, significant uncertainties still remain. In general, most early estimates of the reserves of an oil field are conservative and tend to grow with time. Many oil-producing nations do not reveal their reservoir engineering field data and instead provide unaudited claims for their oil reserves. The numbers disclosed by some national governments are suspected of being manipulated for political reasons.

Future reserves growth will depend, to a large extent, on increases in the recovery factor, which is estimated to average about 35% worldwide today. Such increases, through

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secondary and enhanced oil recovery techniques and other factors, could make a big difference to recoverable reserves, prolonging the production life of producing fields and postponing the peak of conventional oil production.

There are ongoing oil exploration activities both off shore and on shore in Namibia. It appears that the geological formations off the coast of Namibia are very similar to those of pre-salt fields in Brazil and thus the prospects of finding commercial exploitable oil resources are very attractive. Unverifiable reports in the local media place the crude oil reserves in Namibia close to 11 billion barrels.

Crude oil is extracted from oilfields located on land or offshore and is then converted to more refined products in large oil refineries. Several petroleum products emerge from the refining process including gasoline, diesel oil, heavy fuel oil (or Bunker C) and with today’s new cracking processes petcoke. Most of the liquid petroleum products can be used to generate electricity by using a variety of technologies. Four main technologies are used to convert petroleum products (including both light fuel oil (LFO) and heavy fuel oil (HFO)) into electricity:

1) Conventional steam – Heavy Fuel Oil or Petcoke is burned to heat water to obtain steam to drive a turbine which in turn drives an electrical generator 2) Combustion turbine -- Oil is combusted under pressure to produce hot exhaust gases, which spin a turbine to generate electricity 3) Combined-cycle technology -- Oil is first combusted in a combustion turbine and then the exhaust gases of the turbine are fed to a HRSG which produces steam that is used to drive a steam turbine and subsequently an electrical generator 4) Diesel Engine - an internal combustion engine that uses the heat of compression to initiate ignition to burn the fuel, which is injected into the combustion chamber. The output of the diesel engine is then used to drive an electrical generator

Conventional steam technology using HFO was not considered as a candidate generation alternative because other technologies are more economic. The use of Petcoke was not considered for use on conventional steam technology due to serious environmental considerations as well as emissions associated with this fuel. This fuel appears to be more commonly used when blended with coal.

Diesel engines can use a variety of fuels including light fuel oil (LFO) (diesel oil or No. 2), HFO or various degrees of viscosity including HFO 380 and a variety of biofuels (biodiesel and fats). There are 3 principal types of diesel engines; high sped, medium speed and low speed. Each offers its advantages and comes in different sizes. For large amounts of power production it appears that the most commonly used engine is the

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medium speed with some installations using low speed engines. The largest diesel engine to date is about 83 MW.

For the NIRP the 20 MW medium speed diesel (MSD) gensets burning HFO have been considered as well as the LFO fueled 150 MW CCGTs, 50 MW GTs and 100 MW GTs. MSD engines used in large electrical generators run at approximately 400 to 800 rpm and are optimized to run at a set synchronous speed depending on the generation frequency (50 or 60 hertz) and provide a rapid response to load changes. The largest medium-speed engines in production are in sizes of up to approximately 20 MW supplied by companies like MAN B&W, Wärtsilä, and Rolls-Royce. Most MSD engines produced are four-stroke machines, however there are some two-stroke medium speed engines manufactured by others.

The parameters presented in Table 5-3 for CCGT and GT technologies are similar to those given in Table 5-2, except for heat rate, fuel cost and emission factors. Therefore the following presents only the descriptions and explanations to the differences:

1) The MSD, CCGT and GT technologies using fuel oil for the selected size ranges are technically proven and commercially available and have been widely used in electric power generation around the world 2) The cost for infrastructure required for fuel oil transportation is included in the estimated fuel cost 3) It was assumed that the EPC contract would be awarded to contractors from the developing economy countries. The bidding prices of the bidders from the developing economy countries would be lower than those estimated using the developed economy standard. The major equipment for a plant could still be procured from the manufacturers located in the developed economy countries 4) It is expected that the equivalent availability of an MSD, CCGT and GT would be some 90%, 87% and 90% respectively based on the information from the NERC database. Their capacity factors could, therefore, be only up to these values as the plant might not produce at its full capacity at all times due to various reasons such as low load demand, contribution to spinning reserve obligation, etc. 5) The EPC costs for MSD 20 MW, CCGT 150 MW, GT 50 MW GT 100 MW have been estimated at US$1,100 (N$8,250) per net unit capacity (kW), US$950 (N$7,125), US$700 (N$5,250) and US$650 (N$4,875) respectively plus 10% contingency 6) The construction time for a MSD would be some two years with a cash disbursement of 60% and 40%. In order to align the capital expenditure to the in-service date, the base discount rate is used to calculate the interest during construction (IDC)

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7) Variable O&M cost was calculated based on 5% of the unit’s total capitalized cost and 85% capacity factor for MSDs and CCGTs and 25% capacity factor for GTs 8) Emission factors of CO2, NOx, SO2 and particulate matter were calculated based on the information obtained from the EIA and EPA. It is recognized that the emission factors for GT and CCGT using LFO would be different from those using natural gas.

5.2.4 Nuclear Power Generation It is estimated that some 5.5 million metric tonnes of uranium ore reserves are economically viable around the world while 35 million metric tonnes are classified as mineral resources (reasonable prospects for eventual economic extraction). The worldwide production of uranium in 2010 amounted to 53,663 metric tonnes, of which 33.2% was mined in Kazakhstan. The five next most important uranium mining countries are Canada (18.2%), Australia (11.0%), Namibia (8.4%), Niger (7.8%) and Russia (6.6%). This shows Namibia the fourth largest producer of uranium ore in the world. It is noted that five new uranium mining licenses and numerous exploration licenses have been issued for the Erongo Region. Indications are that the area could contain large deposits of yet untapped uranium. Exploitation of these resources will depend on the trend in international prices for uranium and other factors.

In Namibia all uranium mines to date are open cast and use either heap leaching or tank leaching for the on-site processing of the ore.

As nuclear power generation has become established since the 1950s, the size of reactor units has grown from 60 MW to some 1,600 MW, with corresponding economies of scale in operation. At the same time there have been many smaller power reactors built both for naval use and as neutron sources, yielding enormous expertise in the engineering of small units. As per the definitions from the International Atomic Energy Agency (IAEA), the generating units are divided in three size groups. The “small” group includes those units less than 300 MW, the “medium” group is for those between 300 and 700 MW and the “large” group has the unit size over 700 MW. The last two groups include most operational units from the 20th century. The most common types of nuclear power plants include pressurized water reactor (PWR), boiling water reactor (BWR), gas cooled reactor (GCR) and advanced gas cooled reactor (AGR), light water cooled graphite moderated reactor (LWGR), and pressurized heavy water moderated reactor (PHWR).

As per the information collected from the World Nuclear Association (WNA), there are at present some 435 operable reactors producing electricity for power grids with a total net capacity of 372,158 MW, 61 reactors under construction with a total gross capacity of 61,554 MW, 162 planned reactors with a total gross capacity of 180,945 MW and 329

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proposed reactors with a total gross capacity of 376,255 MW. Based on the information collected from the International Atomic Energy Agency (IAEA), the gross unit size of the operable reactors ranges from 12 MW located in Russia to 1,561 MW located in France. Except for the four smallest units, each at 12 MW, the next smallest sizes are in the 200 MW to 300 MW range, which are located in Argentina, Armenia, China, India, Japan, Pakistan, Russia, Switzerland, United Kingdom and Ukraine. India alone has 17 reactors with net capacity ranging from some 150 MW to 200 MW, 15 of which belong to the PHWR type and other two are the BWR type. Most of these generators have been in operation for quite some time and apart from those in India no recent medium size generators have been built.

As per international practice, nuclear power generation is relatively expensive and requires a good national technological base and a well trained human resource to run and maintain such power plants. In deciding if and when a nuclear power plant should be constructed in Namibia, a number of factors such as those listed below must first be taken into account:

1) Grid load demand including export. It is noted that from both economic and technical aspects, nuclear power units should be dispatched to supply base load although advanced technologies could adapt a nuclear power unit with relatively flexible output. The appropriate time to build a nuclear power unit is when the system off-peak load could consume all the unit output. At present, almost all small reactor technologies have not been licensed and approved by relevant authorities as they are for naval use and as neutron sources, for which economics are normally not an important factor in the decision making process 2) Establishment of a national nuclear regulatory commission (NRC) in Namibia which formulates policies, develops regulations governing nuclear reactors and nuclear material safety, issues orders to licensees, and adjudicates legal matters. The NRC or a similar body would also have to put in place suitable procedures to guard against theft of fuel or waste from the plant and other possible forms of terrorism. It is expected that from establishment of the NRC to licensing reactors could take at least seven to ten years. The establishment of a nuclear regulatory commission can also take quite a few years as expertise has to be gathered to be part of such body 3) Selection of potential power plant site(s) and conduct of site environmental and social impact assessment. In the advanced economy, such assessment for a nuclear power plant could take from five to ten years. It is our understanding that pressure groups are already in place in Namibia and are trying to sway popular opinion 4) Financing has to be obtained regardless of the intended ownership, private, public or private public partnership. This could be a long and difficult road especially for

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investors outside Namibia and would require full GRN back up, support and participation especially with guarantees 5) Construction of a nuclear power generating unit could take at least five years after environmental and required approvals 6) A nuclear power plant should have access to water and other infrastructures as it requires very large amounts of water for cooling 7) The output from a nuclear power plant should be evacuated through reliable transmission lines without interruptions in order to minimize the risk of overheating. A nuclear power plant is normally connected to several transmission lines to obtain the desired redundancy. In order to avoid a bottleneck and other operational issues, these transmission lines would have to be connected to a strong point in the grid with several evacuating routes 8) Maintenance and operation of a nuclear power plant requires considerable technical expertise and a technology base in order to be able to supply the specialist skills and products to a nuclear power station, to which Namibia has never been exposed and may need to import at considerable costs in the initial years of operation 9) Unless the company operating the nuclear power station also operates a uranium mine and a uranium processing plant, the company will have to import the enriched uranium for electric power generation from the international market and thus pay the international price. This is a factor that needs to be considered by investors 10) In most jurisdictions, nuclear power generation option requires considerable government interventions with regards to stipulations contained in international conventions, safety regulations, funding and technical facilitations, identification of countries from where safe and proven technologies and initial human expertise can be sourced, as well as establishment of a plan to train Namibians in nuclear physics and nuclear engineering 11) The Government should also play a sustainable role in negotiating power purchase agreements with countries within the region or within the SAPP. Regional cooperation is required as the generation capacity of even a small nuclear power plant may exceed Namibia’s ability to absorb the full generation capacity 12) It is noted that after Japan’s Fukushima nuclear disaster caused by the 8.9 magnitude earthquake on March 11, 2011, the German government announced that the nation will close its all nuclear power plants by 2022 and this may influence other governments to do the same 13) Programs for radioactive waste handling and final disposition including spent fuel considerations.

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In this study, parameters for two reactor sizes, 200 MW and 600 MW are estimated and shown in Table 5-4. The following is a short description of the factors for a 200 MW to 600 MW nuclear power plant and explanations to the parameters presented:

1) The nuclear technologies for the selected size ranges are technically proven and commercially available but have not been widely used in the recent past and may require to be redesigned to incorporate the latest technological advances 2) Unlike the EPC contract for coal, gas and fuel oil fired technologies, it is strongly recommended that the first nuclear plant should be built by a highly experienced contractor from the developed economy countries with proven nuclear power technologies but at the present time there are only a very limited number of such contractors 3) The lead time for a nuclear plant could be fifteen or more years. Taking into account the fact that the country does not have a nuclear regulatory commission in place, and there are no licensed reactors for the sizes considered, the total lead time for the first nuclear unit in Namibia should be at least 20 years 4) It is expected that the equivalent availability of a nuclear plant would be around 88%, based on the information from the NERC database. Its capacity factor could, therefore, be only up to this number as the plant might not produce at its full capacity at all times due to various reasons such as low load demand, contribution to spinning reserve obligation, etc. 5) The EPC costs for 200 MW and 600 MW have been estimated at US$8,000 (N$60,000) per net unit capacity (kW), and US$7,000 (N$52,500) respectively plus 10% contingency 6) Owner’s cost has been estimated at 3% of the total EPC cost 7) The construction time for a nuclear unit would be some six years, with a cash disbursement of 10%, 15%, 20%, 25%, 20% and 10%. In order to align the capital expenditure to the in-service date, the base discount rate is used to calculate the interest during construction (IDC) 8) 0.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 9) 5% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 10) Fixed operation & maintenance (O&M) cost was calculated based on 1.5% of the unit’s total capitalized cost 11) Variable O&M cost was calculated based on 0.5% of the unit’s total capitalized cost and 85% of capacity factor 12) Annual insurance cost is assumed to be 0.25% of the total capitalized cost

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13) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost.

5.2.5 Hydro Electric Power Generation The 2007 Survey of Energy Resources published by the World Energy Council indicates that Namibia’s only perennial rivers are the Kunene, Kavango (forming borders with Angola and Zambia in the north) and the Orange River bordering South Africa in the south. It appears that any plans to develop hydro power are subject to lengthy bilateral negotiations. Another problem leading to limited exploitation of hydro resources is the scarcity of rain and the extensive droughts.

Namibia’s hydropower resources have been mapped and studied in the past. It was estimated, in 1992, that Namibia’s gross theoretical hydropower potential would be approximately 9,000 GWh per year. In 1990, it was assessed that the country’s technically and economically feasible potential would be approximately 8,645 GWh per year. The Kunene River, a shared river with Angola, has a hydropower potential of 1,600 MW and was studied in depth during the 1990’s. The potential large-scale hydropower projects identified for further study were the Epupa and Baynes schemes, and were studied in detail at feasibility level in 1997. Both these schemes were originally envisaged as 360 MW plants aimed at ensuring security of base load supply for Namibia (in competition with natural gas and continued imports from the region). The study found both schemes to be financially viable with Epupa having some negative environmental impacts but being self sufficient as far as water reservoir capacity is concerned, conversely the environmental impact of the Baynes option was much more acceptable but it relied heavily on the regulation of water to be released from the Gove Dam situated deep inside Angola. The project was shelved and NamPower, in dire need of electricity supply, opted to build a 400 kV power line connecting Namibia to South Africa which facilitated the import of inexpensive electricity from South Africa to Namibia.

Several studies have been carried out in Namibia with regard to the development of small hydro power plants. Small hydro potential can be found mostly on the Kavango and Orange Rivers, since the Kunene is situated in a remote area. The waters of the Orange River are dedicated to irrigation projects and mining activities.

It was reported that Namibia had developed a hydro power Master Plan for the country but this has not been made available for review. A study on all perennial rivers had been performed. The aim of the study was to identify and estimate cost and production for all potential hydro power projects on the Lower Kunene, Kavango and Lower Orange rivers.

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Baynes Hydroelectric Power Plant The Baynes hydro project on the Kunene River was first considered in 1997 after plans to build the scheme east of Namibia’s Epupa Falls received fierce opposition due to concerns regarding the impact on the environment and on the nomadic community in northern Namibia. After carefully considering all options, the Namibian and Angolan governments decided to give the green light for the Baynes development to be studied. This change came about mainly because of the following two factors:

 The changed peace situation inside Angola which made it possible for the Angolans to rehabilitate the damaged Gove Dam inside Angola and to regulate the river flow from the dam which is of vital importance for the success of the Baynes Hydropower development  The 400 kV interconnecting power line between South Africa and Namibia that can provide a long-term capacity opportunity for regional power trading.

The potential duty cycle of a Kunene hydropower plant therefore needs to be revisited, particularly as potential exports from Namibia would primarily be targeting peaking and mid-merit opportunities in the Southern African market. Designed for peaking and mid- merit operations, a Kunene power plant at Baynes could potentially provide about 600 MW of additional peaking generation capacity.

It needs to be mentioned that present and future hydropower developments in the Lower Kunene River would benefit considerably from the completion of two initiatives in the Upper Kunene River inside Angola, i.e. further repair of the Gove Dam and the completion of the Calueque Dam. Both these initiatives would improve the upstream flow-regulation of the Kunene River and enhance the performance and cost- competitiveness of a Kunene hydropower plant.

The exploration and exploitation of hydropower developments on a river shared by two countries requires considerable intervention from the concerned governments. In this case, the Namibian and the Angolan Governments were closely involved in laying the foundation for a considerable cross-border investment. Good cooperation between these two governments must continue for the Kunene hydropower plant(s) to be realized. The project also requires considerable regional collaboration on securing the constant flow of water from the hinterland, on bilateral power purchasing arrangements and on joint operations and maintenance programs. The clarification of existing documents regarding water rights for both countries is essential to the development of any hydroelectric project on the Kunene.

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The last phase of the technical and economic feasibility study of the Baynes Hydro Power Plant is almost completed by a consultant retained by the Joint Permanent Technical Committee of Angola and Namibia for the Kunene River Basin. The study includes three phases. The first phase consisted of review of the previous studies, field inspection and critical assessment of the existing data for next two phases. Phase 2 was characterized by preliminary engineering studies, pre-dimensioning, modeling, energy economic and financial analysis, analysis of alternatives and selection of the most attractive solution. The last phase, i.e. Phase 3 has been focused on the improvement of energy, motorization and reservoir depletion, as well as the breakdown of the general arrangement and structure of the plant. The main characteristics of the proposed hydro plant would be as follows:

1) The coordinates of the hydro plant location will be 17002’44” S and 12053’22”E 2) A total of five units with a net maximum generating capacity of some 600 MW. 3) The live storage of the upstream reservoir would have a capacity of approximately 1,300 million cubic meters, which could provide water to the station at its full output for more than 800 hours 4) The total EPC cost for the plant was estimated about US$1.2 billion excluding contingency, i.e. US$2,000 (N$15,000) per kW of net capacity 5) The expected annual generation under the average hydrologic condition (50% of exceedance probability) would be some 1,600 GWh, i.e. an annual capacity factor of approximately 30%. Comparing with other hydroelectric plants built in the world, this value is relatively low. This means that the unit energy cost of the hydro station would be relatively high.

It is expected that with appropriate methods of inflow forecasting, the reservoir would be filled up during wet season (summer) and then be discharged during dry season (winter). The monthly energy output over the dry season could be maintained at reasonable levels as per system load demands.

The studies for the 600 MW Baynes hydroelectric plant did not take into account the power evacuation from the plant to the Namibian and Angolan systems. The costs associated with the power evacuation could be considerable and an order of magnitude estimate is provided in another section of this report. Conversations with NamPower indicate that the preferred evacuation route would be to build two 400 kV transmission lines from the plant to a new substation just south of the Ruacana plant and convert the output of Ruacana to 400 kV (from 330 kV) and convert the existing 520 km long 330 kV transmission line from Ruacana to Omburu to 400 kV operation. In addition, there would be another 400 kV from just south of Ruacana to Otjikoto and transmission lines to

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Angola. There are some issues with this concept in that the Angolan representatives have expressed their desire to be supplied directly from the power plant and the other large issue is that the conversion of the existing 330 kV transmission line from Ruacana to Omburu to 400 kV operation could be problematic. Thus the evacuation of power to the final consumers could become quite expensive.

Kavango River Hydro Electric Power Generation In May 2004, NamPower commissioned a prefeasibility study on the viability of a 20 MW hydroelectric plant to be located on the Kavango River in the vicinity of Popa Falls. This development would be a run-of-the-river project and would be connected to the NamPower grid via a 200 km long 132 kV power line. The pre-feasibility study has shown the project to be viable but there are still some environmental issues that need to be resolved such as avoiding the entrapment of sediment in the dam basin, before the development may go ahead. The development plan was rejected by NamPower due to the following main reasons:

1) Concerns over possible damage to the Kavango Delta, located downstream from the falls in neighboring Botswana. The costs of environmental management of the project would be very high 2) The power output will be only 20 MW 3) The hydro matrix turbines were found to be not ideal for the purpose for which they were proposed. Bulb turbines could be used as an alternative 4) Heavy financial commitments to develop the Kudu gas project.

However, NamPower has not ruled out the possibility of this proposal being revisited at some future date. The Namibian Government could actively assist in obtaining funding on concessionary conditions. The Namibian Government’s role in this project is limited to ensuring that environmental concerns are addressed and that the resource, set in a prime tourism area, is used in the best interest of Namibia.

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Lower Orange River Hydroelectric Power Station The Orange River catchment area is divided into three catchment subdivisions: the upper, middle and lower catchment areas. Clackson Power Company (Pty) Ltd (“Clackson Power”) together with NamPower have been pursuing the possibility of developing several distributed hydro-electric power stations which would be situated in the lower Orange River catchment, more specifically between the Fish River junction to the west and the Molopo River junction to the east. It would begin slightly upstream of the Onseepkans settlement and end just after the Vioolsdrift Weir. The Lower Orange Hydro Electric Power Stations (LOHEPS) project consists of the development of up to 9 small hydro-electric power stations, varying in size from 6 MW to 12 MW with an anticipated total installed capacity of some 100 MW. The potential annual output from these hydro stations would be as much as some 650 GWh. The concept of the project is to divert the flow (run-of-river) of the Orange River through canals and tunnels into turbines which in turn would drive an electric generator. By placing the turbines at strategic derivation points along the river, the kinetic and potential energy of the river would be converted into electrical energy. Recent hydrological studies along the Orange River indicate a potential generation capacity of between 80 MW and 120 MW.

The first phase of the feasibility study for the development of a small-scale hydro-power plant along the lower Orange River has been completed. The next step is for the conclusion of environmental and technical studies that would enable decisions on the project site and cost. There is a possibility that NamPower could earn carbon credits from the hydro-power plant, as there would be no use of water abstraction or water regulation but this would depend on the ability to satisfy the additionality criteria

Due to the fact that the project is an environmentally clean project but with several issues, and could help alleviate the power shortage in Namibia and SADC region, support for the project has been given by the Namibian and South African Heads of State, the Namibian Ministry of Agriculture, Water and Forestry as well as the Namibian MME.

As with most projects of this nature, considerable licenses and regulatory permits are required. However, it is expected that there will be minimal risk to the investor/lender in terms of legislation and regulatory impacts on the project as the projects have received government support from both Namibia and South Africa. The following permits are currently being obtained from the relevant authorities:

1) Operational agreement and water usage permit from the Ministry of Water Affairs (MWAF) of Namibia 2) Generation license agreement from ECB 3) Mining permit from MME

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4) EIA clearance from Namibia and South Africa.

Furthermore, as all power stations would be situated on the Namibian side of the border (note that there is an ongoing dispute with Republic of South Africa on the location of the border in this immediate area) and above the 100 year flood line, any issue regarding border uncertainty should not impact this project. The LOHEPS projects are presently at a standstill as both NamPower and Clarkson Power can’t agree on a method to pursue a way forward. The likelihood of any further development on progress of this progress in the short to medium term is very unlikely especially if other projects under consideration are further developed.

Table 5-5 summarizes the main technical and economic parameters for the three hydro electric power stations described above, i.e. Baynes, Kavango River and Lower Orange River. The following gives short descriptions and explanations to the parameters presented in this table:

1) Generation technologies for all sizes of hydro electric power units (from less than one megawatt to several hundred megawatts) are commercially available and technically proven in the world. However, due to the nature of a hydro electric power plant, its capital cost is site dependent, which is a function of several key parameters such as geographical location, geological conditions, reservoir volume or dam requirements, generating station, resettlement, road access, transmission access as well as environmental and social impact management 2) The economic life of a hydro electric power station is assumed to be 50 years 3) The lead time for Baynes, Kavango River and Lower Orange River would be nine, six and six years respectively. The expected construction time for the three stations would be six, three and three years respectively 4) The availability of a hydro electric power station could be very high (taking away the forced outage and planned maintenance) if the availability of water is not taken into account 5) The daily production profile of the run-of-river projects is dependent on water in- flows and daily peaking storage. Without a daily peaking storage, the station’s output is totally dependent on its in-flows. It generates power when water flows and stops generation if there is no water. With a daily peaking storage, the water could be stored when the system demand is low and the station generates when the system demand is high 6) Similar to the explanation to the daily production profile, the seasonal production would be controlled if there is a relatively large reservoir. A small reservoir such as daily peaking storage would have little control of the station’s seasonal output. As

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per the average in-flows analyzed for the Baynes power plant, the in-flows in Summer (wet) months are relatively high while they are very low in Winter (dry) months 7) The EPC costs for the hydro electric stations are based on the assumption that the EPC contracts would be awarded to experienced companies from developing economies as they normally offer much lower prices than those from developed economies 8) The EPC costs for Baynes, Kavango River and Lower Orange River power stations were estimated at US$2,000 (N$15,000) per net unit capacity (kW), US$2,500 (N$18,750) and US$2,500 (N$18,750) respectively plus 10% contingency. These costs do not include the funds required for road access and transmission connection. The cost estimates are based on the fact that Baynes station would have a seasonal reservoir constructed, Kavango River station would need a large amount of funds for environmental management and the Lower Orange stations would need construction of canals and tunnels 9) Owner’s cost has been estimated at 5% of the total EPC cost 10) The construction time for the Baynes station would be some six years, with a cash disbursement of 10%, 15%, 20%, 25%, 20% and 10%. The construction time for the other two stations would be some three years, with a cash disbursement of 30%, 40% and 30%. In order to align the capital expenditure to the in-service date, the base discount rate is used to calculate the interest during construction (IDC). 11) 1.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 12) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 13) Fixed operation & maintenance (O&M) cost was calculated based on 1.5% of the station’s total capitalized cost 14) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 15) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost.

5.2.6 Wind Power Plant The Namibian Government has recognized the importance of having renewable energy as part of the country’s generation portfolio. However, a required minimum level of renewable power generation has not been established and mechanisms have not been put in place to require the ESI to install renewable power generation and to guarantee that the costs of such generation can be recovered from electricity consumers.

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The potential of solar, wind and bio-mass (firewood, wood charcoal and encroachment bushes) in Namibia is substantial. Although various studies have shown in the past that renewable energy such as wind and solar cannot compete with conventional types of power generation in Namibia, the costs of these options are becoming more competitive.

Except for one small wind generator around 220 kW near Walvis Bay, a solar-diesel hybrid system around 26 kW at Gobabeb with 2 x 50 kVA diesel generators, a solar- diesel hybrid system near Tsumkwe with a 200 kW solar PV plant and 2 x 350 kVA diesel units, a 34 kW grid-connected solar PV system at the northern UNAM campus and the 250 kW CBEND biomass project (using gasification of invader bush), there are no larger scale renewable energy projects installed in Namibia.

Since solar power is localized and the output of the plant can be relatively accurately predicted, regional cooperation is not required beyond the possible exchange of knowledge, best practices and experience among SADC countries. Wind power, however, requires a large measure of regional co-operation since wind volumes and speeds are difficult to predict.

The Namibian west coast has good wind resources, with annual average wind speeds ranging from 6 to 12 meters per second with a potential capacity factor between 15% to 30%. There is little doubt that areas of Namibia are well suited to produce electricity from wind energy, but the potential maximum capacity is debatable. It is generally recognized that wind power is a valuable addition to a country’s electricity generation mix. The level of renewable power which the Namibian grid could accommodate can be examined through a renewable power integration study. It is important to note that there is no general rule of thumb on a higher level of renewable power integration as it is subject to many factors such as load variation patterns, renewable power generation patterns, technical characteristics of the generation fleet, energy storing capability, interconnection strength and power interchange rules/policies with neighboring utilities, etc.

According to an investigation and pre-feasibility study conducted in 1996/1997 by MME, the Lüderitz area has one of the best potentials to develop a sizeable wind farm with total potential capacity of up 65 MW. The other area with great potential for wind power generation is Oranjemund, which is located in the southern part of the country and has an average wind speed of up to 10 meters per second. This area has a total potential capacity of approximately 15 MW.

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The Walvis Bay area has also been identified as having considerable wind potential, with average wind speeds ranging from 7 to 12 meters per second and an estimated total potential capacity of 25 MW. The north corridor between Walvis Bay and Henties Bay has considerable wind potential for power generation. This could be extended further north from Henties Bay to Terrace Bay, and even up to Mowe Bay located further north. However, these areas need further investigation to determine their full potential. Nevertheless, the information obtained from the National Weather Service and supported by the Namibia wind map indicates that the wind regime along this section is between 7 and 10 meters per second, which is still attractive for wind power generation. The total potential of the Walvis Bay corridor up to Mowe Bay could reach 45 MW.

As per the information from the ECB, three wind power projects currently have conditional licenses issued by the ECB and these include one at Luderitz (44 MW) and two at Walvis Bay (50 MW and 60 MW respectively). It was assumed that these three wind power plants would have similar technical and economic parameters as summarized in Table 5-6. The following provide simple explanations for these parameters:

1) The lead time would be from three to five years depending on permitting requirements, including resource quantification, scoping study, feasibility study, EPC contract document preparation as well as tendering and awarding, financing closure, construction and commissioning 2) It is expected that the equivalent availability of the projects would be around 95% 3) Due to the lack of storage capacity, it is expected that the wind power will be variably dispatched as wind energy is available 4) The EPC costs for the three projects are estimated at US$1,530 (N$11,475) per net unit capacity (kW) plus 10% contingency. These estimates do not include land acquisitions 5) Owner’s cost has been estimated at 5% of the total EPC cost 6) The construction time would be approximately two years with an annual cash disbursement flow of 60% and 40% 7) 1.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 8) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation

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9) Total operation & maintenance (O&M) cost was calculated based on 2.5% of the project’s total capitalized cost 10) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 11) Interim replacement cost is assumed to be 0.25% of the total capitalized cost.

5.2.7 Solar PV Power Plant Namibia has one of the highest solar radiation regimes in Africa and the world. Sunshine is available throughout the year and there are minimal interruptions even during the rainy season. The radiation is utilized by solar panels of a photovoltaic energy conversion technology, i.e. the conversion of light into electricity. This is achieved through photovoltaic (PV) modules. Namibia has promoted solar energy for many years, focusing on providing households, rural clinics, rural schools, community centers and churches with lighting and other important electrical applications. Although Namibia has not yet invested in large-scale generation, there are excellent sites for this, especially in the southern part of the country where there are vast tracks of open land with very high insolation rates.

Generation of electricity from solar energy is therefore enjoying support from government and the private sector but currently this technology produces electricity with direct costs that are higher than those for other options. But with grid parity approaching (depending on the costs of an individual solar PV facility and the tariff structure) and the fact that solar energy is environmentally clean, acceptable and renewable, electricity based on PV technology is expected to play a role in Namibia’s electricity supply in the future.

There are currently three solar PV projects with conditional generator licenses issued by the ECB, which are Keetmanshoop (10 MW), Rehoboth (10 MW) and Arandis (10 MW). These three projects have similar technical and economic parameters as presented in Table 5-7. The following notes provide simple explanations for these parameters:

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4) The EPC costs for the three projects are estimated at US$2,850 (N$21,375) per net unit capacity (kW) plus 10% contingency. These estimates do not include land acquisitions 5) The estimated EPC costs include a 20% overbuild on the DC (direct current) side. For example, a 10 MW AC (alternating current) system will have a 10 MW inverter capacity but 12 MW of DC capacity 6) Owner’s cost has been estimated at 3% of the total EPC cost 7) The construction time would be approximately two years with an annual cash disbursement flow of 60% and 40% 8) 1% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 9) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 10) Total operation & maintenance (O&M) cost was calculated based on 1.5% of the project’s total capitalized cost 11) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 12) Interim replacement cost is assumed to be 0.25% of the total capitalized cost.

5.3 Imports from SAPP It is understood from NamPower that discussions have been held with many entities to address the possibility of these entities supplying power to Namibia under long-term agreements. Table 5-8 shows the source/entity, the fuel to be used, the amount of capacity that would be imported and the earliest possible in-service date.

Table 5-8 - Potential Import Sources

Source/Entity Country Fuel Import Earliest Capacity Date (MW) Extension of Hwange Zimbabwe Coal 150 Oct. 2013 Contract Lunsemfwa Zambia Hydro 150 2017 African Energy Botswana Coal 150 2018 Resources Moropule non-firm Botswana Coal 150 2012 Kariba North Zambia Hydro Unknown 2014

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Source/Entity Country Fuel Import Earliest Capacity Date (MW) Benga Mozambique Coal Unknown 2018 Moatize Mozambique Coal Unknown 2018 Maamba Zambia Coal 250 2018 Bothakgo Burrow Botswana Coal Unknown 2018 SNEL DRC Hydro 50-250 2013

As previously mentioned, sources located outside Namibia would not qualify as Internal Resources, regardless of type of participation (including ownership), to meet the requirements outlined in the 1998 Energy White Paper for both capacity and energy contributions.

There are several coal projects in Table 5-8 with an “earliest date” of 2018 and this was determined by assuming a 5 year lead time for each project as none of them are yet under construction. 5.3.1 Imports Likely to be Pursued The purchase of power from a hydro project to be developed on the Lunsemfwa River in Zambia is being pursued by NamPower. This would entail the purchase of 150 MW (some base and some peak energy) from a 250 MW hydro project that is expected to be in-service sometime in 2016. The financial closing was recently completed and a 4 year construction period is expected. Sources in Zambia may have a greater negotiating power than those in Namibia but other, larger, hydro plants may be coming on line about the same time in which case there could be competition for lower prices.

The Moropule non-firm import would bode well with some of the expansion plans being envisaged for Namibia. The Moropule B 4 x 150 MW coal plant is under construction and is expected to be on line shortly. This import would consist of off peak power as available and would decrease on a timely manner and dependent upon the load growth in Botswana. The interchange amounts of power will be made available to the NIRP at the end of April. The generation expansion plans in Namibia could demonstrate the need for a base load plant as soon as possible to meet the load demand and the Energy Policy requirement of at least 75% of energy from internal sources. Presently this could be achieved by constructing either the Erongo coal plant (300 MW) or the Kudu gas fired CCGT plant. In either case the plants will take time to come on line and with the passage of Ruacana to operating at peak this energy could be used to fill the demand valleys.

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The African Energy Resources plant would be a mine mouth plant located in Botswana about 50 km south of Francistown and within 20 km of a 220 kV transmission line and water pipeline. The coal could have a heating value of 5,100 to 5,500 kCal/kg. The power plant would be a replica of Moropule but only 2x150 MW of which Namibia would take 150 MW and be built on an EPC basis by either Chinese or Indian contractors.

The transmission network to bring imported power into Namibia is already in place as there are two transmission links into Namibia in place; the ties with Eskom and the Caprivi link with Zambia. In either case, the limiting factor would be transmission capability outside Namibia and in particular in Zambia and South Africa. With the commissioning of new power plants in Zambia, the transmission network is expected to be reinforced and presently as the flow is South to North, the addition of the Lunsemfwa hydro projects would alleviate that flow thus allowing power to flow to the Caprivi link or through to the Zimbabwe, Botswana and South African networks.

The principal transmission bottleneck could be the Eskom system due to the operating requirements for the nuclear power plant. The requirements are very stringent and the imports could be limited only in situations that do not occur that often.

5.3.2 Imports Unlikely to be Pursued Of the import projects listed in Table 5-8 there are several that are unlikely to be pursued due to a variety of reasons.

The import from the Société Nationale d'Electricité (SNEL), of the Democratic Republic of Congo (DRC) is presently on hold even though a term sheet has already been signed for the import of a firm 50 MW but tariff negotiations were not finalized and a PPA was never signed. At the time of negotiations, up to 250 MW was indicated by SNEL as being available, but transmission constraints in the ZESCO network would probably not allow any firm import. Moreover, the DRC is presently rehabilitating several of its hydro generators and many transmission lines in order to be able to export power to SAPP. However, given the rapid load growth in the mining sector in DRC in the next 5 to 10 years, especially in the Katanga province, it is unlikely that any power will be available for export to SAPP.

An integrated coal mine is proposed at Bothakga Burrow in Botswana with the construction of a power plant either in Botswana or Namibia. Should the power plant be built in Namibia then there would be the issue of coal transportation and the need for the construction of a very long and costly rail link from the mine to a port and power plant in Namibia. At this time the size of the power plant is unknown and the likelihood of developing such a power station appears small.

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A 300 MW plant is proposed in the initial phase of the project development at the Maamba coal field located in Southwest Zambia. The configuration proposed is 2X150 MW units which offers better availability and flexibility of operation. Based on the assessment of the reserves of thermal grade coal at Maamba coal field and demand for power, the capacity of the power plant could be increased to 600 MW. The colliery selected SEPCO Electric Power Construction Corp, China as contractor to establish a mine mouth, 300 MW Coal Fired Power Plant (in 2x150 MW unit configuration) on an EPC basis and issued the Letter of Intent to SEPCO on 19th October 2011 at Lusaka. The first Unit is scheduled to be completed within 30 months and the second Unit in 33 months from January 2012. To the best of our knowledge, a contract has not been signed yet for the first phase of the plant and it appears that all 300 MW of the first phase have been committed. Commitments for the output of the second phase are being sought from potential off-takers. Given the delays encountered for this project it is unlikely that the second phase will proceed in the short to the medium term.

In recent years large quantities of coal have been found in the central province of Tete in Mozambique. Two large coal mines have been in development under the ownership of major international mining companies. It is believed that both mines are either operational or close to start operations. There are also other coal projects coming on line soon with the intention of building coal fired power plants. As part of the mines’ development plans it was intended to develop large coal power stations and at the present the total development is planned to be close to 5,600 MW (2,000 MW Moatize, 2, 000 MW Benga and 2,640 MW JSPL). All of this power is to supply Mozambique and sell into the Southern Africa market. The principal issue with this is that Mozambique is also building hydro projects and the intended market (South Africa) has expressed that it is only interested in importing clean renewable energy as they have coal to supply their own power plants. As there is close to no publically available information on these projects, they are treated as having a commissioning date in 2018.

The extension of the existing contract for the power from the rehabilitated units at Hwange is not under consideration as entities in Zimbabwe have expressed their desire not to renew the contract with NamPower.

5.3.3 Expected Costs of Imports Power is usually imported to meet shortfalls is a system or because it is more economic than the system’s own production cost. In Namibia, it appears that both conditions are met.

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The cost of future power imports is difficult to forecast but present cost of imports could be used as a proxy and assuming that costs will increase since the last contract was signed.

The cost for power from Lunsemfwa is estimated based on the current contract price escalated at 3% for 4 years and assuming a 10% premium as well as 5% for losses. The fixed price or price per capacity is estimated at 14 US$/kW-month or 105 N$/kW-month and 0.04 US$/kWh or 0.3 N$/kWh.

The cost of non-firm power from Moropule should be similar to that of the supplemental contract with Eskom plus wheeling charges and cost of losses. This type of contract usually does not have capacity charges or it has a small capacity charge. For this case it has been assumed that there would not be any capacity charges. The blended supplemental contract tariff for standard and off peak power has been determined to be about 0.45 N$/kWh. The wheeling charges in both Botswana and South Africa amount to 21.22 N$/MWh and the losses in the Eskom system amount to 5.39 N$/MWh. The total cost of off-peak power from Moropule would be 476.6 N$/MWh or 0.48 N$/kWh which is equivalent to 6.36 US¢/kWh.

The cost of Power from African Energy Resources has been estimated by using a proxy new coal plant and a mine mouth cost of coal of 50 US$/tonne for 5,100 kCal/kg coal (2.34 US$/GJ). It should be noted that such low amount price for coal is due to the stranded location of the coal mine. The cost of fuel (coal) would be about 2.6 US¢/kWh and variable O&M about 0.97 US¢/kWh for a total variable cost of about 3.57 US¢/kWh or 0.27 N$/kWh. The capacity cost is dependent upon the capital cost for the plant, discount rate and project life. For simplicity it is assumed that there would be a 20 year PPA and that the capital cost should be amortized during that period and a discount rate of 15% is used for a capital recovery factor of 0.134. If a capital cost of 2,500 US$/kW is used, the resulting monthly payment would be 27.89 US$/kW-month and adding fixed O&M of 58.8 US$/kW-yr, a total monthly fixed cost of 32.79 US$/kW-month or 245.9 N$/kW-month.

These likely imports would be dispatched as per system requirements and contracted agreements.

Table 5-9 summarizes the cost of the likely imports.

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Table 5-9: Cost of Likely Imports

Import Capacity Cost Energy Cost (N$/kW- (N$/kWh) month) Lunsemfwa 105.0 0.30 Moropule Non-firm - 0.48 African Energy Resources 245.9 0.27

5.4 Demand Side Management and Energy Efficiency For the analysis of demand side management (DSM) and energy efficiency opportunities, Hatch has considered a long list of programs in various electricity end-uses with several programs addressing energy efficiency and others addressing, load shifting, creation of market awareness and use of customer generation. The information in this section draws on previous studies in Namibia on these subjects and available information on the results of initial programs carried out in the country. As part of the next stage of the NIRP, a survey will be sent to REDs and other distributors to obtain further input on the results of programs implemented to date and the characteristics of the electrical equipment used by their customers. The DSM and energy efficiency programs that have been examined include:

1. Compact fluorescent lamp (CFL) roll out program in the residential sector 2. Residential solar water heaters (SWH) dissemination 3. Commercial and institutional buildings SWH dissemination 4. Subsidized energy audits 5. Commercial and institutional energy efficient lighting 6. Ripple control of electrical water heaters 7. Commercial and institutional air conditioning systems 8. Information dissemination and public awareness 9. Energy audit and implementation in large industry 10. Use of customer generation to reduce grid peak The programs examined, from those of the several options analyzed, considered not only the amount of energy they could save but also their impact on the evening peak demand, their relative ease of implementation and the number of stakeholders involved.

The next subsections present an overview of each DSM and energy efficiency program examined.

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5.4.1 CFL Program in the Residential Sector The CFL program would promote the installation of 13 to 15 W CFLs for the replacement of 60 W incandescent bulbs. The CFLs would be provided to residential customers in exchange for operating incandescent bulbs to ensure that each CFL installed replaces an operating bulb. All incandescent lamps retired from the market would be destroyed.

The program is expected to reach 121 500 residential customers nationwide, each with an expected requirement of approximately 6 CFLs per household for a total of about 729 000 CFL units.

CFL prices have significantly dropped in the last years and CFLs are available in most retail stores countrywide. Economic and marketing drivers are still the main considerations for purchasing CFLs in the residential sector since the initial cost of an incandescent bulb is much less than the initial cost of a CFL.

For Namibia, this program would have the greatest impact on reducing the evening peak, at which time household lighting has a large load. It has been estimated that a peak reduction of 22.9 MW could be achieved by this program along with a potential savings of 41.9 GWh per year.

5.4.2 Residential Solar Waters Heaters Dissemination This program aims at promoting the installation of solar water heaters (SWH) in non- equipped and new houses or to replace existing electric water heaters (EWH). According to previous DSM studies, there are approximately 130,000 residential EWHs installed in Namibia, which could make this market significant in terms of energy savings. Using a conservative penetration rate of 30%, roughly 40,000 SWHs could be installed to provide domestic hot water in lieu of existing EWHs.

Promoting the installation of SWHs in the residential sector could be achieved through:

 Providing rebates for the purchase of SWHs, either to the residential customers or directly to the SWH suppliers  Adopting standards that promote SWH installation into the residential building code  Conducting information and awareness campaigns  Expanding the revolving solar fund to handle larger quantities of funding.

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It is estimated that when the program is fully implemented there could be a peak demand reduction of close to 15.3 MW and the displacement or reduction in energy consumption could be as much as 52.4 GWh per year. The program’s total duration would be approximately 10 years and would have a cost of about 72.8 N$ million.

5.4.3 Commercial and Institutional Buildings SWH Dissemination This program aims at promoting the installation of SWHs to replace EWHs in the commercial and institutional buildings requiring hot water. The penetration of SWHs in rural public buildings is significant, particularly in clinics and hostels but only a few urban commercial buildings have a SWH system installed.

Promoting the installation of SWHs in the commercial and institutional sectors could be achieved through:

 Providing rebates or subsidies for the purchase of SWHs  Adopting standards that promote SWH installation into applicable building codes  Conducting information campaigns  Expanding the solar revolving fund to allow small institutions and commercial buildings access to preferential financing.

Based on 2010/2011 figures gathered from ECB Annual Reports, the commercial, industrial and institutional market in Namibia was estimated to be 18,413 consumers. The annual increase in the number of costumers for these sectors is around 7%.

It is estimated that when the program is fully implemented there could be a peak demand reduction of close to 4.7 MW and the reduction in energy consumption could be of the order of 16.6 GWh per year.

5.4.4 Subsidized Energy Audits Energy audits are a well-known and efficient way of identifying DSM and energy efficiency opportunities in a facility. The implementation of a subsidized energy audit program may be an effective tool to overcome both financial and awareness barriers and to demonstrate the viability of energy efficiency. Such a program could involve the following elements:

 Financial support for energy audits  Information (and possibly training of entrepreneurs) on how to conduct energy audits

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 Promotion of the establishment of energy service companies (ESCOs)  Facilitation of commercial loans for consumers to enable investments in energy saving measures identified during energy audits  Provision of subsidies to co-fund investments or buy down the cost of loans  Capacity building for conducting measurement and verification (M&V) of energy efficiency measure performance.

Various pieces of equipment could be retrofitted under this audit program and could involve the installation of new systems which aim at reducing energy consumption or electricity demand.

The potential savings arising from this program could amount to a peak demand reduction of close to 2.3 MW and annual reduction of energy consumption of 20.5 GWh. It should be noted that the demand savings are larger during the off peak period and thus the large energy savings.

5.4.5 Commercial and Institutional Energy Efficient Lighting Lighting usually accounts for a large share of electricity consumption in commercial and institutional buildings. It can also have significant impacts on the space cooling and heating requirements.

This commercial and institutional energy-efficient lighting program should promote the installation of energy-efficient fluorescent tubes instead of old and inefficient fixtures. This program could involve approximately 16,676 consumers and could result in a peak demand decrease of 3.1 MW and an energy reduction of 20.5 GWh per year.

5.4.6 Ripple Control of Electrical Water Heaters in Large Cities Ripple control of electric water heaters is a well-established means for utilities to shift electricity consumption from peak to off-peak times. This program has already been implemented in two large cities and is thus well understood.

The proposed program aims to expand the previous program to all households as well as commercial and institutional customers. Most of Namibia’s larger towns have the potential to beneficially implement ripple control on EWH (and SWH with electric back- up) to control billing demand peaks, as well as national demand peaks and the timing of peak consumption.

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The estimated reduction in peak demand is of the order of 23.1 MW without energy reduction as the program is intended to shift the time of the demand.

5.4.7 Commercial and Institutional Air Conditioning Systems In Namibia, it has been estimated that air conditioning systems account for up to 70% of commercial buildings’ electricity consumption. Since the electricity consumption of HVAC systems in the industrial and commercial sectors accounts for close to 10% of the national electricity consumption, energy efficient air conditioning systems could present a relevant potential for energy savings.

This program focuses on promoting and providing financial incentives for the purchase of energy-efficient air conditioners in the commercial and institutional sectors. The focus is on split AC systems that are more common in Namibia. The program would involve both a promotional campaign targeting commercial and institutional AC buyers and the provision of rebates to the suppliers of approved energy-efficient split system models. The rebates would be expected to be passed on to the retail buyers in the form of discounted AC prices.

The estimated peak demand reduction potential is of the order of 2.5 MW and an energy reduction of 3.1 GWh per year.

5.4.8 Information Dissemination and Public Awareness A public awareness and promotion campaign is an essential component for the success of all the other programs. It is recommended to implement a public awareness and promotion program that will aim to sensitize the general public and other energy efficiency market actors about all the DSM and energy efficiency programs as well as to inform the public on branded energy-efficient products. Such a program may include:

• General energy efficiency awareness raising and consumer information about energy • Promotion of energy efficient appliances • Promotion of renewable energy sources • Information on rising regional tariffs, tariff options, how to save on the electricity bill • Information on the energy supply situation and how consumers can change their energy usage to help address local and/or national supply constraints.

All electricity consumers would be impacted by such a campaign which could result in a peak demand reduction of the order of 2.5 MW and an energy reduction of 16.1 GWh per year.

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5.4.9 Energy Audit and Implementation in Large Industry This program would provide incentives to large industrial firms to undertake energy audits and to implement the audit’s recommendations. The audit incentive would fund half the cost of an energy audit and the implementation incentive would fund a certain amount of annualized electricity savings per project.

An energy audit incentive program would help the large industrial companies gain a more detailed understanding of how they are using energy and identify specific opportunities for improvement. It is recognized that some of the mining operations have identified energy saving opportunities that they may be in a position to implement if there was some incentive funding available.

The energy audit could cover the entire operation or focus on a specific system that might represent a significant savings opportunity (i.e. compressed air system, material handling system). Participating companies could hire local or international technical experts to complete the energy auditing process. The implementation incentive would be based on the MWh of annualized energy savings for an approved project. Projects would have to deliver at least a certain annualized savings from an agreed baseline.

The expected peak reduction is of the order of 7.5 MW and 45.0 GWh per year.

5.4.10 Use of Customer Generation to Reduce Grid Peak Two of the larger mines in Namibia have an installed on-site generating capacity of 32.5 MVA. The estimated existing on-site generating capacity at the larger industrial complexes is about 55 MW (65 MVA). This generation could be used during the peak period to reduce the overall peak demand. From an economic perspective it could become attractive for some of the industrial customers to meet some of their demand if considering only the variable costs since the fixed costs can be deemed as being sunk costs.

From the utility’s side, several issues can arise when having customers’ generation operating in parallel with the system as they would not have control over the generation. Many times the utility requires significant additions to the equipment at the customer’s substation before permitting parallel operation of other generation and these modifications could in some cases be so expensive as to make the program unattractive.

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This aspect is not considered further in this report due to the need for site specific assessment. .However, this opportunity could be investigated further by establishing a dialogue between the customers with on-site generation and NamPower.

5.4.11 Summary of Selected DSM Programs Table 5-10 provides a summary of the individual programs considered along with their estimated benefits and costs. The implementation period for the individual programs ranges from 3 to 8 years with the average requirement for full implementation of a given program being about 4 years.

The individual programs provide benefits from 10 to 24 years depending on the life of the equipment and the duration of the program. The annual energy savings shown in Table 5-10 are those for the period when the program is fully implemented and there is a build up to this value as well as draw down of the value as can be seen by examining the total energy savings for the program and the period over which the program is expected to yield benefits.

The capital costs shown for the individual programs are indicative costs and were obtained from other projects in Africa and from in-house data. The unit cost per kW is obtained by dividing the total cost by the potential peak demand reduction while the unit cost of energy is obtained by dividing the total program cost by the total energy savings.

As shown in Table 5-10, most of the programs have a very economic unit cost of energy compared to other supply options which indicates that their implementation should be given further consideration. As seen from Table 5-10, commercial and institutional air conditioning systems and commercial and institutional energy efficient lighting have higher costs than the other programs and could prove difficult to finance in view of the benefits offered by the other programs and are thus not considered further. In the same way, it could be considered that the subsidized energy audit program should also be excluded but this program has impacts on other programs which cannot easily be translated into benefits to the program and thus should be retained.

The potential savings for the DSM and energy efficiency programs retained amounts to 78 MW and 225 GWh per year which represents 11% of the peak demand and 4.7% of the expected energy requirements by 2015. This may be considered to be a high value but 60% of the peak demand savings arise from the CFL roll out and the ripple control of EWH and both of these programs have been initiated in Namibia and carried out successfully in other locations.

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5.5 Secondary Generation Options with Quantified Resources but Non-mature Technology This section provides a brief description of the options with quantified resources but non mature technologies which we considered to include small nuclear reactors.

5.5.1 Small Modulated Nuclear Reactor Power Generation Due partly to the high capital cost of large nuclear reactors generating electricity via the steam cycle and partly to the need to service small electricity grids under about 4,000 MW, there is a move to develop smaller nuclear power units. These may be built independently or as modules in a larger complex, with capacity added incrementally as required. There are also moves to develop small units for remote sites. Small units are seen as a much more manageable investment than big ones whose cost rivals the capitalization of the utilities concerned. However, safety and security issues would have to be addressed to satisfy national and international requirements before such power plants could move forward.

The four 12 MW EGP-6 nuclear reactors located in Bilibino nuclear power plant, Chukotka Autonomous Okrug, Russia, are the smallest and the northernmost operating nuclear power units in the world. The EGP-6 reactors are a scaled down version of the RBMK reactor design. Notably, these reactors along with the RBMK designs are some of the few active reactors which still use light water cooled graphite as a neutron moderator. It is noted that construction of the plant began in 1966 and the first two units started operation in 1973, the third one in 1975 and the last one in 1976. Under the International Nuclear Safety Program, the U.S. Department of Energy (DOE) assisted with safety improvements at Bilibino NPP, particularly focusing on improving the safety of day-to-day operations. Activities included an analytical simulator project, safety and maintenance training, and the provision of monitoring and communications equipment, among others.

The RBMK is an early Generation II reactor and the oldest commercial reactor design still in wide operation. It features a number of design and safety flaws (such as graphite- tipped control rods, a dangerous positive void coefficient and instability at low power levels) that have since been rectified in newer designs. The reactor's flaws contributed to the 1986 Chernobyl disaster in which an RBMK exploded during an unsafe test and spread radioactivity over a large portion of Eastern Europe. The disaster prompted worldwide calls for the reactors to be completely decommissioned, although there is still considerable reliance on RBMK facilities for power in Russia and the post-Soviet republics. The last RBMK at Chernobyl was not shut down until 2000, and as of 2010 there were still at least 11 RBMK reactors operating in Russia alone.

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In 2007, the Government of Namibia, through the MME, identified nuclear energy as an option to be considered for electricity generation, which has obtained interests from foreign investors in this regard. A series of discussions/negotiations between the Namibian and Russian governments took place from mid 2007 for the development of a nuclear power plant with 50 MW units to be located offshore Namibia. There are, however, serious concerns related to the safety and environmental risks of the proposed floating nuclear power plant technology as it is a new technology which has not been commercially available and has not been used in other countries. On the other hand, a French company has been investigating possibilities of investing in nuclear power generation in Namibia based on the technology that has been proven to be technologically sound in developed countries. As per the information collected from the IAEA, there are around 58 operational nuclear reactors in France, each producing a net output of 880 MW or more.

In early 2012, the DOE announced its first step toward manufacturing small modular nuclear reactors (SMRs) in the United States. Through the draft Funding Opportunity Announcement (FOA), the Department will establish cost-shared agreements with private industry to support the design and licensing of SMRs. The draft FOA is a working document soliciting input from industry to promote leading edge design certification, licensing and engineering.

As per the NIRP load forecast, the national grid peak demand will grow to some 1,100 MW by 2030, which implies a minimum load of some 440 MW if the minimum load would continue to be around 40% of the system annual peak. By taking into account unit economies of scale, availability, reliability, operational flexibility, maintenance and forced outage of generating units, it is expected that the size of the largest unit in an electric system should not be larger than 15% of the system peak demand. Based on these assumptions and other factors, the system may have one nuclear power plant with a unit size around 100 MW and a total of four units when the system peak load demand reaches around 1,100 MW. Selection of the actual unit size will be dependent on the small nuclear reactor technologies available at that time. It is suggested that the small nuclear reactor power generation could be taken into account in the future NIRP development only when they are commercially available and technically proven. The lead time should, of course, include all of those items outlined in Section 5.2.4 including requirements for personnel training, establishment of national nuclear regulatory commission and associated laws, regulations and codes, feasibility study, environmental and social impact assessment, construction and commissioning.

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Table 5-11 summarizes the technical and economic parameters estimated for the small modular nuclear reactors which could be applicable to the Namibia electric system in the future. The following are some additional notes to this table:

1) The lead time for a small modular nuclear power plant could be from six to eight years following the approval and commercialization of the reactors 2) The earliest on-line time of a SMR is subject to future technology development and commercialization 3) It is expected that the equivalent availability of a nuclear plant would be around 88%, based on the information from the NERC database. Its capacity factor could, therefore, be only up to this value as the plant might not produce at its full capacity at all time due to various reasons such as low load demand, contribution to spinning reserve obligation, etc. 4) The EPC costs for 50 MW and 100 MW have been estimated at US$10,000 (N$75,000) per net unit capacity (kW), and US$9,500 (N$71,250) respectively plus 10% contingency 5) Owner’s cost has been estimated at 3% of the total EPC cost 6) The construction time for a small modular nuclear unit would be some four years, with a cash disbursement of 15%, 35%, 35%, and 15%. In order to align the capital expenditure to the in-service date, the base discount rate is used to calculate the interest during construction (IDC) 7) 0.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 8) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 9) Fixed operation & maintenance (O&M) cost was calculated based on 1.5% of the unit’s total capitalized cost 10) Variable O&M cost was calculated based on 0.5% of the unit’s total capitalized cost and 85% capacity factor 11) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 12) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost.

5.6 Secondary Generation Options with Mature Technology but Non-quantified Resources This section provides a brief description of the options with mature technology but non- quantified resources which we consider to include wind power generation, solar PV

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power generation, solar thermal power generation, generation using municipal solid waste, bio-fuels, biomass and geothermal generation.

5.6.1 Wind Power Generation There are a number of different wind power technologies on the market, but they operate on the same principle that involves the conversion of the kinetic energy in the wind to produce electricity using wind turbine-generators. The most common technology on the market today is the horizontal axis wind turbine (HAWT). The HAWTs have a rotor and a nacelle that houses the main rotor shaft and electrical generator at the top of a tower. Computer controlled yaw motors and pitch mechanisms allow the nacelle to turn and pitch with changes in wind direction. Most have a gearbox, which controls the rotational speed of the blades and many new models are available with direct drive systems that eliminate the need for a gearbox.

Turbines used in wind power plants for commercial production of electric power are usually three-bladed with high tip speeds of up to 320 km per hour, high efficiency, and low torque ripple, which contribute to reasonable reliability. The blades are usually coloured light gray to blend in with the clouds and range in length from 20 to 50+ metres. The tubular steel towers range from 50 to 100+ metres tall. Modern technologies are equipped with protective features to avoid damage at high wind speeds, by feathering the blades into the wind which ceases their rotation, supplemented by brakes.

A wind power plant can produce significant amounts of electricity ranging from a few MW for a single tower to a few hundred MW for a large wind farm with many towers and the technology is mature. Within the Namibian context, wind power projects can be effectively integrated into the power portfolio. The energy from the wind resource is available and free, but highly variable. As a result, the transmission and distribution system operator must consider reregulation measures using other dispatchable quick response generating stations to deliver power to meet firm demand requirements. Significant initial capital investment and large areas for the installation of the wind turbines are required. This could make this technology less affordable and accessible currently, but with possible further increases in the price of fossil fuels, and the need for safer and cleaner energy sources, the cost of wind power technology could keep on decreasing and make these technologies readily available and affordable in the near future. Namibia has potential for large scale electricity generation from wind power.

It is expected that the following essential steps are required to quantify wind resources at a reasonably accurate level:

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1) Review of previous and current studies on wind energy potentials, wind resource data monitoring campaigns, and critical assessment of the available data 2) Based on the review work of the previous studies, select four to eight representative sites for wind resource monitoring and assessment 3) Installation of monitoring equipment at the selected sites and collection of required data for at least one year and analysis of the data collected 4) Wind power plant site selection will require detailed wind resource maps, and transmission and distribution maps 5) Carry out prefeasibility studies for the selected sites to estimate the potential output, required investment and O&M costs 6) The total period for this resource quantification would be two years or longer 7) The total funds required for this could be from US$500,000 (N$3,750,000) to US$1,000,000 (N$7,500,000) but it is dependent of the level of accuracy, degree of complexity, size of the project, and requirements of the wind monitoring campaign.

As noted in Section 5.2.6, there are several wind power projects with conditional licenses from ECB. It is not clear at this point the extent to which the developers have completed the above steps.

The technical and economic parameters of a wind power plant with a size ranging from 30 to 100 MW have been presented in Table 5-6.

5.6.2 Solar PV Power Generation There are a number of different solar PV power technologies on the market, but they operate on the same principle that involves the utilization of irradiance from the sun for producing electricity using solar panels. Due to the low voltage of an individual solar cell, several cells are wired in series in the manufacture of a "laminate". The laminate is assembled into a protective weatherproof enclosure, thus making a photovoltaic module or solar panel. Modules are then strung together into a photovoltaic array. Most PV arrays use an inverter to convert the DC power produced by the modules into AC power that can be transmitted via transmission or distribution systems to load centres to meet electricity demands.

The most common solar panel technologies on the market today are crystalline silicon modules, and thin-film modules. Sun tracking technology is available and can be implemented to improve the overall energy conversion efficiencies of a solar PV project.

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Trackers and sensors that optimize the performance are often seen as optional, and tracking systems can increase output by up to 50%.

Solar PV power projects can produce significant amounts of electricity ranging from a few kW to several MW and the technology is mature. Within the Namibian context, solar PV power projects can be effectively integrated into the power portfolio. The energy from the solar resource is available and free. Typically power production is higher at mid-day than the morning and afternoon, with no production at night, and tends to match well with diurnal demand profiles.

Significant initial capital investment and sizeable areas for the installation of solar PV projects are required. The direct costs of generation using this technology currently exceed those of other generation options, but with the need for safer and cleaner energy sources, the cost of solar PV power technology could keep decreasing and make these technologies readily available and affordable in the future. In recent years there has been over 100% year-on-year growth in PV system installation around the world, and PV module suppliers significantly increased their shipments of solar panels in 2010. Namibia has an excellent resource and environment for large scale electricity generation from solar PV power.

It is expected that the following essential steps are required to quantify solar PV power potential at a reasonably accurate level:

1) Review of previous and current studies on solar energy potentials, solar resource data monitoring campaigns, and critical assessment of the available data 2) Selection of four to eight representative sites for resource quantification studies 3) Resource measurement campaigns using satellite derived solar resource data at the selected sites to determine the long term solar resource. The installation of monitoring equipment may be used to calibrate / validate the satellite derived data. It is suggested that at least one year data be collected for analysis 4) Site selection will require detailed solar resource maps, and transmission and distribution maps 5) Carry out prefeasibility studies for the selected sites to estimate the potential output, required investment and O&M costs 6) The total period for this resource quantification could be approximately two years if using monitoring equipment to calibrate the data 7) The total funds required for this could be from US$400,000 (N$3,000,000) to US$800,000 (N$6,000,000) but it is dependent of the level of accuracy, degree of

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complexity, size of the project, and requirements of the solar monitoring campaign.

As noted in Section 5.2.7, these are three solar PV projects with conditional licenses from the ECB. It is not clear at this point, the extent to which the developers have completed the above steps.

The technical and economic parameters of a solar PV power plant with a size ranging from 5 to 20 MW have been presented in Table 5-7.

5.6.3 Solar Thermal Power Generation Solar thermal power involves the utilization of the sun’s heat for power generation. There are a number of different technologies on the market, but they operate on the same principle. Solar heat is trapped and concentrated by mirrors and reflected onto a heat- transfer medium (gas or liquid) contained in pipes. This medium then transfers the heat to water, producing steam, which drives a turbine. Solar thermal power stations can produce significant amounts of electricity ranging from a few MW to several hundred MW and they, through heat storage mechanisms (such as salt reservoirs) can produce electricity, albeit at a reduced capacity, for almost 24 hours.

Until recently, a lot of research and development has been conducted into the most cost effective solar thermal technologies, to the detriment of marketing the technology. Consequently there has not been a comprehensive roll-out of solar thermal collectors and a high degree of customization still exists.

Within a Namibian context, solar thermal power stations can be very effectively integrated with CCGT or other thermal fuel plants. It is possible that the Kudu CCGT station at Oranjemund could be operated with solar thermal energy, at the very latest when the gas reserves are nearing depletion. Namibia, south from Mariental, is generally highly suitable for solar thermal power generation.

Solar thermal collectors for electricity generation require massive initial capital investment and large surface areas for the installation of the solar collectors. This could make this technology less affordable and accessible currently, but with possible ongoing increases in the prices of fossil fuels, and the need for safer and cleaner energy sources, the relative cost of solar technology could keep decreasing and make these technologies more readily available and affordable in the future. Namibia has the high insolation rates and open space needed for installation of solar thermal collectors for large scale electricity generation.

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It is expected that the following essential steps are required to quantify solar thermal power resources at a reasonably accurate level:

1) Review of previous studies on solar energy potentials, critical assessment of the available data and selection of two to five sites for potential solar thermal power plants, each with a capacity of some 25 MW or 50 MW 2) Installation of monitoring equipment at the selected sites and collection of required data for at least one year and analysis of the data collected 3) Carry out prefeasibility study for the selected sites to estimate the potential output, required investment and O&M costs 4) The total period for this resource quantification would be about two years 5) The total funds required for this work could be from US$500,000 (N$3,750,000) to 2,000,000 (N$15,000,000).

The estimated technical and economical parameters for the solar thermal power plants are summarized in Table 5-12. The following notes provide simple explanations for these parameters:

1) Two sizes, 25 MW and 50 MW are selected for this study. They could be changed based on the future study results 2) The lead time would be from five to seven years including resource quantification, scoping study, feasibility study, EPC contract document preparation as well as tendering and awarding, financing closure, construction and commissioning 3) It is expected that the equivalent availability of a unit would be around 90%. Due to the limited energy and storage capacity, it is expected that most energy will be dispatched during day time and evening hours when system experiences its daily peak demand 4) The EPC costs for the 25 MW and 50 MW are estimated at US$5,500 (N$41,250) per net unit capacity (kW) and US$5,000 (N$37,500) respectively plus 10% contingency. These estimates include land acquisitions 5) Owner’s cost has been estimated at 3% of the total EPC cost 6) The construction time would be some three years, with a cash disbursement of 30%, 40% and 30% 7) 0.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees

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8) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 9) Fixed operation & maintenance (O&M) cost was calculated based on 1.5% of the unit’s total capitalized cost 10) Variable O&M cost was calculated based on 0.5% of the unit’s total capitalized cost and 35% capacity factor 11) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 12) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost.

5.6.4 Power Generation Using Municipal Solid Waste Electricity can be produced by burning municipal solid waste (MSW) as a fuel. MSW power plants, also called waste to energy (WTE) plants, are designed to dispose of MSW and to produce electricity as a byproduct of the incinerator operation. The term MSW describes the stream of solid waste generated by households and apartments, commercial establishments, industries and institutions. MSW consists of everyday items such as product packaging, grass clippings, furniture, clothing, bottles, food scraps, newspapers, appliances, paint and batteries. It does not include medical, commercial and industrial hazardous or radioactive wastes, which must be treated separately.

MSW is managed by a combination of disposal in landfill sites, recycling, and incineration. MSW incinerators often produce electricity in WTE plants. The U. S. EPA recommends, "The most environmentally sound management of MSW is achieved when these approaches are implemented according to EPA's preferred order: source reduction first, recycling and composting second, and disposal in landfills or waste combustors last. In the United States, there are currently two main WTE facility designs:

 Mass Burn is the most common waste-to-energy technology, in which MSW is combusted directly in much the same way as fossil fuels are used in other direct combustion technologies. Burning MSW converts water to steam to drive a turbine connected to an electricity generator  Refuse-derived fuel (RDF) facilities process the MSW prior to direct combustion. The level of pre-combustion processing varies among facilities, but generally involves shredding of the MSW and removal of metals and other bulky items. The shredded MSW is then used as fuel in the same manner as at mass burn plants.

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In addition to the two main WTE facilities designs mentioned above, there are also two other technologies, pyrolysis and thermal gasification, under the development stage with a limited number of units in operation. Pyrolysis and thermal gasification are related technologies. Pyrolysis is the thermal decomposition of organic material at elevated temperatures in the absence of gases such as air or oxygen. The process, which requires heat, produces a mixture of combustible gases (primarily methane, complex hydrocarbons, hydrogen and carbon monoxide), liquids and solid residues.

Thermal gasification of MSW is different from pyrolysis in that the thermal decomposition takes place in the presence of a limited amount of oxygen or air. The producer gas which is generated can then be used in either boilers or cleaned up and used in combustion turbine/generators. The primary area of research for this technology is the scrubbing of the producer gas of tars and particulates at high temperatures in order to protect combustion equipment downstream of the gasifier and still maintain high thermal efficiency.

A couple of technologies for generating electricity using MSW are well developed internationally. Namibia could not support large MSW generation facilities as it only has modest amounts of waste resources available with which to generate electricity due to its relatively low population. A study performed by Stewart and Scott in 1997 indicated that Windhoek did not generate sufficient amounts of refuse to support an economically sized power plant.

There are, however, small scale technologies available that are able to generate electricity from refuse, in particular those based on gasification. Due to the relatively small size of these technologies, it is possible that they could be applied in Namibia’s medium-sized towns. However, it should be emphasized that refuse gasification technologies have not been fully proven internationally.

It is expected that the following essential steps are required to quantify municipal solid waste plants at a reasonably accurate level:

1) Review of previous studies on solid waste energy, collection of the current MSW disposal quantity, critical assessment of the available data and selection of one to four large cities for potential MSW power plants, each with a capacity of some 10 MW or 20 MW 2) Analysis of the MSW samples for each selected city and assessment of the energy available to fuel a power plant 3) Carry out prefeasibility study for the selected sites to estimate the potential output, required investment and O&M costs

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4) The total period for this resource quantification would be one year 5) The total funds required for this work could be from US$200,000 (N$1,500,000) to 1,000,000 (N$7,500,000).

The estimated technical and economic parameters for the MSW power plants are summarized in Table 5-13. The following notes provide simple additions to these parameters:

1) Two sizes, 10 MW and 20 MW are selected for this study. They could be changed based on the future study results 2) The lead time would be from five to seven years including resource quantification, scoping study, feasibility study, EPC contract document preparation as well as tendering and awarding, financing closure, construction and commissioning 3) It is expected that the equivalent availability of a unit would be around 80% 4) The EPC costs for the 10 MW and 20 MW plants are estimated at US$9,000 (N$67,500) per net unit capacity (kW) and US$8,500 (N$63,750) respectively plus 10% contingency 5) Owner’s cost has been estimated at 2% of the total EPC cost 6) The construction time would be some three years, with a cash disbursement of 30%, 40% and 30% 7) 0.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 8) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 9) Fixed operation & maintenance (O&M) cost was calculated based on 1% of the unit’s total capitalized cost 10) Variable O&M cost was calculated based on 0.5% of the unit’s total capitalized cost and 80% capacity factor 11) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 12) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost.

5.6.5 Bio-fuels Power Generation

Large scale bio-fuel initiatives could potentially materialize in the long-term depending on technology development, government land use policies, prices of other fuels etc. It is

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expected that the following essential steps are required to quantify bio-fuels at a reasonably accurate level:

1) Review of previous studies on bio-fuels, particularly the Kavango Bio-Fuel project, collection of the information related to the bio-fuel resources, critical assessment of the available data and selection of one to two sites for potential bio-fuel power plants. As CCGT could use bio-fuels as fuel, it is suggested that CCGT should be used and each CCGT plant could have a capacity of either 75 MW (two 25 MW GTs and one 25 MW ST) or 150 MW (two 50 MW GTs and one 50 MW ST) 2) Collection of crop samples and analysis of bio-fuel production rates 3) Analysis of the potential bio-fuel resources and estimate of the total bio-fuels available to each selected site to fuel a power plant 4) Carry out prefeasibility study for the selected sites to estimate the potential output, required investment and O&M costs 5) The total period for this resource quantification would be one year 6) The total funds required for this work could be from US$200,000 (N$1,500,000) to 500,000 (N$3,750,000).

The estimated technical and economic parameters for the bio-fuel power plants are summarized in Table 5-14. The following notes provide simple explanations to these parameters:

1) Two CCGT sizes, 75 MW and 150 MW are selected for this study. They could be revised based on the future study results 2) The lead time would be from six to seven years including resource quantification, scoping study, feasibility study, EPC contract document preparation as well as tendering and awarding, financing closure, construction and commissioning 3) It is expected that the equivalent availability of a unit would be around 88% 4) The EPC costs for the 75 MW and 150 MW are estimated at US$1,000 (N$7,500) per net unit capacity (kW) and US$950 (N$7,125) respectively plus 10% contingency 5) Owner’s cost has been estimated at 10% of the total EPC cost 6) The construction time would be some three years, with a cash disbursement of 30%, 40% and 30% 7) 1.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 8) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation

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9) Fixed operation & maintenance (O&M) cost was calculated based on 2.5% of the unit’s total capitalized cost 10) Variable O&M cost was calculated based on 5% of the unit’s total capitalized cost and 85% capacity factor 11) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 12) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost.

5.6.6 Biomass Namibia has abundant biomass resources in the form of invader bush, which is located primarily in the north-central and central regions. It has been estimated that there are approximately 26 million hectares of thick, bush-encroached land in Namibia. Invader bush prevents the growth of useful grass species, resulting in the compaction of soils in the bush encroached areas and reduction in the grazing area for livestock. Another worrying factor is that the extensive root network - up to 40 meters long - of some invader bush species robs the soil of moisture. Soil also gets compacted, which prevents rainwater from penetrating the soil and replenishing the underground water table.

It appears that invader bush represents a nearly unlimited resource with which to generate electricity. Use of the invader bush for energy production is assumed to have excellent side benefits such as increased water infiltration, increased biodiversity, and improved business and employment opportunities in the agricultural sector. The scale of biomass combustion power plants typically varies from 5 MW to 50 MW, but smaller plant sizes are also possible.

Namibia has an average farm size of 5,000 hectares. It was estimated that each farm could provide sufficient fuel for approximately 1 MW power plant by assuming a 60% sustainable bush clearing approach, harvesting cycle of seven years, production rate of 10 tonnes per hectare, energy conversion rate of 1MWh per tonne and 80 operation hours per week. It is important to highlight that the bush should be harvested in an environmentally sustainable manner to be of real benefit to the environment. However, it is not clear whether this is achievable, given the desert conditions prevailing in most parts of Namibia.

In 1997, the Ministry of Agriculture employed a team of consultants from Finland to undertake a study to determine the technological and economic feasibility of using invader bush to produce electricity. While using invader for electricity generation option appears plausible, more ecological studies and environmental impact assessment are needed before a green light could be given for investment in this sector. Large scale

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removal of bushes may trigger other unforeseen ecological processes that may hinder or slow down re-growth and make this project not sustainable. Many of the plant species under consideration may take very many years to regenerate due to the dry and arid climate of Namibia. Furthermore, the massive ground area over which the bush is spread would make transport costs of the raw material very high as these will have to be transported to the location of the generating plants over difficult and previously inaccessible locations.

The Combating Bush Encroachment for Namibia’s Development (CBEND) initiative is a proof-of-concept project implemented by the Desert Research Foundation of Namibia (DRFN) in partnership with the Namibia Agricultural Union and the Namibia National Farmers Union and funded by the European Commission at an amount of N$ 14 million through the National Planning Commission Secretariat’s Rural Poverty Reduction Programme.

The CBEND Project has installed a 250 kW bush-to-electricity power plant on a commercial farm (in one of the most bush infested areas) in the Otavi area in Namibia, which is fueled with invader bush and will feed electricity directly into the national grid. This demonstration project is Namibia’s first independent power producer and could be used to assess the financial feasibility of this approach and evaluate the technical robustness of the technology.

In order to quantify the invader bush resource for utility scale power production, the following essential steps will be required to assess the invader bush resources around a power plant at a reasonably accurate level:

1) Review of previous studies on invader bush, particularly the existing CBEND demonstration project, collection of the information related to the invader bush resources, critical assessment of the available data and selection of five to ten sites for potential invader bush power plants 2) Study of the invader bush growth cycle and the harvest approach. It is important to note that a longer than the expected growth cycle could jeopardize fuel supply chain to a operational power plant 3) Analysis of the contents of invader bush and estimate of the invader bush available to each selected site to fuel a power plant 4) Carry out prefeasibility study for the selected sites to estimate the potential output, required investment and O&M costs 5) Carry out environmental and social impact assessment with particular emphasis of impacts on endangered species.

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6) The total period for this resource quantification would be two to three years. However it would be better if the assessment could be carried out over a full invader bush growth and harvest cycle. In this case the total time required will be eight to ten years 7) The total funds required for this work could be from US$500,000 (N$3,750,000) to 5,000,000 (N$37,500,000).

Table 5-15 provides a summary of the estimated technical and economical parameters for the invader bush fired power projects. The following are some simple explanations to these parameters:

1) The bubbling fluidized bed (BFB) technology is selected for the invader bush power plants with size of either 5 MW or 20 MW 2) The lead time would be from six to 10 years including resource quantification, scoping study, feasibility study, EPC contract document preparation as well as tendering and awarding, financing closure, construction and commissioning 3) It is expected that the equivalent availability of a unit would be around 88% 4) The EPC costs for the 5 MW and 20 MW projects are estimated at US$4,000 (N$30,000) per net unit capacity (kW) and US$3500 (N$26,250) respectively plus 10% contingency 5) Owner’s cost has been estimated at 5% of the total EPC cost 6) The construction time would be some three years, with a cash disbursement of 30%, 40% and 30% 7) 1.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees 8) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 9) Fixed operation & maintenance (O&M) cost was calculated based on 2.5% of the unit’s total capitalized cost 10) Variable O&M cost was calculated based on 3% of the unit’s total capitalized cost and 85% capacity factor 11) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 12) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost.

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5.6.7 Geothermal Power Generation In 2004, the University of the Witwatersrand advised the Namibian Geological Survey on aspects of terrestrial heat flow and the potential of geothermal energy in Namibia. Heat flow maps of Namibia and the region surrounding Namibia would suggest that the potential is high compared with most of the rest of the subcontinent, but there are large areas, particularly in the west where there is little information. There are only 12 heat flow measurements in Namibia, mostly from the Damara Belt, and this and the scarcity of data in adjacent regions results in an incomplete heat flow pattern. The average heat flow for the Damara Belt (69±10mW m-2) is the highest in the region but the heat flow does not attain the extremely high values observed in geologically more active regions. The high heat flow is not associated with thermal transients and is probably due to an enhanced radioactive contribution from the upper crust.

Despite the relatively high heat flow, the thermal gradients are not exceptionally high and exceed 25 K km-1 at only three localities. Regional subsurface temperature maps obtained by one dimensional modeling of the heat flow data indicate that temperatures exceeding 100°C are only reached at 2 – 3 km. This modeling is preliminary and a detailed analysis, based on more complete heat flow coverage and variations in geological structure may reveal local temperature anomalies.

Hot water or thermal springs in Namibia are known in Warmbad, Rehoboth, Omburo (near Omaruru) and Gross Barmen (near Okahandja). These are used for recreational and tourism purposes. The occurrence of thermal springs has possible implications for geothermal energy. Those at Windhoek and Omburo are of particular interest as the temperatures of the surface waters were originally 70 - 80°C. These temperatures are however lower than those observed in active geological regions and the origins of the springs appear to be heating of meteoric water under the normal geothermal gradient. Preliminary calculations indicate that the springs probably rise from depths of 2 – 3 km. Drilling into the springs at Grosse Windhoek in the 1920s caused them to dry up, so the recharge rate of the springs is also of concern. These comments are based on little information and more work is required to establish the depth, size and temperature of the reservoirs giving rise to the springs and whether the rainfall and permeability of the aquifers feeding the reservoirs are sufficient to recharge them.

Currently there is insufficient data relating to geothermal gradients, heat flow patterns and other information relating to hot spring reservoirs to make a sound scientific assessment of the geothermal potential. This would be possible if there were a better coverage of heat flow data and more in-depth knowledge of thermal springs based on well coordinated scientific research.

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Reconnaissance level heat flow coverage over the entire country would be desirable and this would take at least two years to achieve because heat flow determination is time consuming. Particular attention should also be paid to the following: (i) areas where hot springs exist, especially Windhoek and Omburo, (ii) sedimentary basins such as the Owambo and Nama Basins, where deep-seated aquifers might house geothermal reservoirs, (iii) localities like Rössing near Arandis and Valencia where highly radioactive rocks may have potential for "hot dry rock" energy generation. Opportunities for heat flow determination include (i) making use of commercial offshore heat flow measurements and bottom hole temperature measurements in offshore and onshore oil wells which would require collaboration with the Namibian Petroleum Corporation, (ii) conducting surveys in mineral exploration boreholes and stratigraphic holes that might be drilled by the Geological Survey, (iii) collaborating with the Department of Water Affairs which conducts routine geophysical surveys in water exploration wells.

Further investigations of the hot springs in Windhoek and Omburo should be aimed at establishing the depth and extent of the reservoirs, their temperatures and water content and the recharge rates. A first step towards determining the temperature would be to survey some boreholes into the Windhoek springs that are currently being planned by the Windhoek Municipality. It may also be worth collaborating with the Municipality with a view to having one of these holes deepened. If the permeability of the reservoirs and the aquifers feeding them and the rainfall in the catchment areas are found to be inadequate to recharge the reservoirs, the use of artificial methods of enhancing these parameters (including hydraulic fracturing and injection of waste water) should be investigated. Finally, if the temperatures of the reservoirs are not high enough to use conventional turbines, the viability of binary-cycle turbines, which can operate at temperatures as low as 85°C, should be investigated.

High Government engagement would be required to finance, coordinate and evaluate the research as suggested above. Should sufficient data be obtained to ascertain the availability of sustainable geothermal energy, the Government of Namibia would strongly be advised to support investments in geothermal electricity generating plants. Geothermal electric plants do not have very high installation capital costs. Such plants could therefore be funded through a government-private sector initiative or by an IPP. Once running, the only major running cost of such electric plants is maintenance of the hot water pipes and the steam turbines. If appropriate corrosion prevention methods are incorporated at the design stage, the cost of maintenance becomes minimal.

Based on the success of existing geothermal electric plants in Naivasha Kenya, one could foresee a scenario in which Namibia would establish several generating plants in the future if sustainable geothermal energy sources are confirmed. Such electric plants

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would then be connected to the national grid and provide a clean, affordable and environmental friendly energy source. With such a scenario, regional and international cooperation is not critical because power generation from geothermal plants can be varied or even shut down in times of excess power in the grid.

It is expected that the following essential steps are required to quantify the geothermal resources at a reasonably accurate level:

1) Review of previous studies on geothermal resources, collection of the information related to the geothermal energy resources, critical assessment of the available data and selection of two to five sites for potential geothermal power plants 2) Investigation of the geothermal potential for each of the selected sites through reconnaissance, drill, testing, etc. 3) Analysis of the potential geothermal resources and estimate of the total resources available to each selected site to fuel a power plant 4) Carry out prefeasibility study for the selected sites to estimate the potential output, required investment and O&M costs 5) The total period for this resource quantification would be two to four years 6) The total funds required for this work could be from US$1,000,000 (N$7,500,000) to 3,000,000 (N$22,500,000).

The estimated technical and economic parameters for the geothermal power plants are summarized in Table 5-16. The following notes provide abbreviated explanations to these parameters:

1) Two plant sizes, 5 MW and 20 MW are selected for this study. They could be revised based as per the resources available 2) The lead time would be from eight to ten years including resource quantification, scoping study, feasibility study, EPC contract document preparation as well as tendering and awarding, financing closure, construction and commissioning 3) It is expected that the equivalent availability of a plant would be around 85% 4) The EPC costs for the 5 MW and 20 MW are estimated at US$6,500 (N$48,750) per net unit capacity (kW) and US$6,000 (N$45,000) respectively plus 10% contingency 5) Owner’s cost has been estimated at 3% of the total EPC cost 6) The construction time would be some three years, with a cash disbursement of 30%, 40% and 30% 7) 0.5% of the sum of EPC, owner’s cost and IDC is assumed to be the financing charges including commitment fees

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8) 2% of the sum of EPC, owner’s cost and IDC is assumed to be the decommissioning costs, which is allocated at the beginning of the unit’s operation 9) Fixed operation & maintenance (O&M) cost was calculated based on 1.5% of the unit’s total capitalized cost 10) Variable O&M cost was calculated based on 1% of the unit’s total capitalized cost and 85% capacity factor 11) Annual insurance cost is assumed to be 0.25% of the total capitalized cost 12) Annual fund contribution to the interim replacement cost is assumed to be 0.25% of the total capitalized cost.

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Table 5-1 - Coal Fired Power Generation

Generation Technology CFB PC Comment Fuel Coal Plant Gross Capacity (MW) 336 324 Plant Net Capacity (MW) 300 300 Number of Units 2 2 Economic Life (Year) 30 30 Lead Time (Year) 6-7 6-7 Earliest On-Line Year 2019/2020 2019/2020 Equivalent Availability (%) 85 85 Based on NERC database Equivalent Forced Outage Rate (%) 7 7 Planed Outage Rate (%) 8 8 Four weeks per year Production Profile (Daily) Dispatched as per system requirements Production Profile (Seasonal) Dispatched as per system requirements Net Heat Rate (KJ/kWh, HHV) 11,600 11,000 Primary Fuel Cost ($/GJ) 41.65 41.65 Overall Capitalized Cost ($M) 6,782.9 6,160.6 Plant EPC ($M) 4,702.5 4,207.5 Based on Net capacity and 10% contingency Owner's Cost ($M) 235.1 210.4 5% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 30%, 40%, 30% Plant IDC ($M) 774.4 693 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 688.1 688.1 Owner's Cost for Grid Integration ($M) 68.8 68.8 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% Grid Integration IDC ($M) 84.6 84.6 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 98.3 89 1.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 131.1 119 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 22,610 20,535 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 565.2 513.4 2.5% of total capitalized cost Variable O&M Cost ($/MWh) 93.3 84.7 3% of the total capitalized cost and 83% CF. Insurance Cost ($M/Year) 17.0 15.4 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 17.0 15.4 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) 88.387 88.387 Uncontrolled factors calculated as per the NOx Emission Rate (kg/GJ) 0.089573 0.21498 parameters from the US EIA and EPA. CFB, PC SO2 Emission Rate (kg/GJ) 0.068076 0.68076 and ESP are assumed. SO2 emission factor was Particulate Matter Emission Rate (kg/GJ) 0.025801 0.02580 calculated based on 1% sulphur content. Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options Note: All Costs expressed in N$

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Table 5-2 - Natural Gas Fired Power Generation

Generation Technology CCGT CCGT GT GT Comment Fuel Natural Gas or Liquefied Natural Gas Plant Gross Capacity (MW) 156 416 51 102 Plant Net Capacity (MW) 150 400 50 100 Number of Units 1 1 1 1 Economic Life (Year) 25 25 20 20 Lead Time (Year) 5-6 5-6 4-5 4-5 Earliest On-Line Year 2017/2018 2017/2018 2016/2017 2016/2017 Equivalent Availability (%) 87 87 90 90 Based on NERC database Equivalent Forced Outage Rate (%) 6.0 6.0 5.0 5.0 Planed Outage Rate (%) 6.0 6.0 4.0 4.0 Three/Two weeks per year Production Profile (Daily) Dispatched as per system requirements Production Profile (Seasonal) Dispatched as per system requirements Net Heat Rate (KJ/kWh, HHV) 7,400 7,200 11,200 11,000 Primary Fuel Cost ($/GJ) 75 75 75 75 Overall Capitalized Cost ($M) 1,983.8 5,139.0 644.9 958.2 Plant EPC ($M) 1,175.6 2,970.0 288.8 536.3 Based on Net capacity and 10% contingency Owner's Cost ($M) 117.6 297.0 28.9 53.6 10% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 30%, 40%, 30% 60%, 40% Plant IDC ($M) 202.8 512.4 35.5 65.9 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 344.1 969.7 220.8 220.8 Owner's Cost for Grid Integration ($M) 34.4 97.0 22.1 22.1 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% 60%, 40% Grid Integration IDC ($M) 42.3 119.2 27.1 27.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 28.8 74.5 9.3 13.9 1.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 38.3 99.3 12.5 18.5 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 13,226 12,848 12,899 9,582 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 330.6 321.2 322.5 239.6 2.5% of total capitalized cost Variable O&M Cost ($/MWh) 88.8 86.3 294.5 218.8 5% of the total capitalized cost and 85% and 25% CF. Insurance Cost ($M/Year) 5.0 12.8 1.6 2.4 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 5.0 12.8 1.6 2.4 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) 50.338 50.338 50.338 50.338 Uncontrolled factors calculated as per the NOx Emission Rate (kg/GJ) 0.141024 0.141024 0.141024 0.141024 parameters from the US EIA and EPA. About 90% of SO2 Emission Rate (kg/GJ) 0.000026 0.000026 0.000026 0.000026 NOx could be reduced by GT. SO2 emission factor Particulate Matter Emission Rate (kg/GJ) 0.002834 0.002834 0.002834 0.002834 was calculated based on 1% sulphur content. Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options

Note: All Costs expressed in N$

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Table 5-3 - Fuel Oil Fired Power Generation

Generation Technology MSD CCGT GT GT Comment Fuel HFO LFO Plant Gross Capacity (MW) 20.8 156 51 102 Plant Net Capacity (MW) 20 150 50 100 Number of Units 1 1 1 1 Economic Life (Year) 25 25 20 20 Lead Time (Year) 4-5 5-6 4-5 4-5 Earliest On-Line Year 2016/2017 2017/2018 2016/2017 2016/2017 Equivalent Availability (%) 90 87 90 90 Based on NERC database Equivalent Forced Outage Rate (%) 5.0 6.0 8.0 8.0 Planed Outage Rate (%) 4.0 6.0 4.0 4.0 Three/Two weeks per year Production Profile (Daily) Dispatched as per system requirements Production Profile (Seasonal) Dispatched as per system requirements Net Heat Rate (KJ/kWh, HHV) 8,860 6,980 10,570 10,380 Primary Fuel Cost ($/GJ) 120 150 150 150 Overall Capitalized Cost ($M) 302.3 1,983.8 644.9 958.2 Plant EPC ($M) 181.5 1,175.6 288.8 536.3 Based on Net capacity and 10% contingency Owner's Cost ($M) 18.2 117.6 28.9 53.6 10% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 60%, 40% 30%, 40%, 30% 60%, 40% Plant IDC ($M) 22.3 202.8 35.5 65.9 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 57.3 344.1 220.8 220.8 Owner's Cost for Grid Integration ($M) 5.7 34.4 22.1 22.1 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% 60%, 40% Grid Integration IDC ($M) 7.0 42.3 27.1 27.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 4.4 28.8 9.3 13.9 1.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 5.8 38.3 12.5 18.5 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 15,115 13,226 12,899 9,582 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 377.9 330.6 322.5 239.6 2.5% of total capitalized cost Variable O&M Cost ($/MWh) 101.5 88.8 294.5 218.8 5% of the total capitalized cost and 85% and 25% CFs. Insurance Cost ($M/Year) 0.8 5.0 1.6 2.4 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 0.8 5.0 1.6 2.4 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) 69.336 69.336 69.336 69.336 NOx Emission Rate (kg/GJ) 0.000569 0.000569 0.000569 0.000569 SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options

Note: All Costs expressed in N$

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Table 5-4 - Nuclear Power Generation

Generation Technology Nuclear Nuclear Comment Fuel Uranium Plant Gross Capacity (MW) 224 672 Plant Net Capacity (MW) 200 600 Number of Units 1 1 Economic Life (Year) 40 40 Lead Time (Year) 8-10 8-10 Earliest On-Line Year 2035 2035 Equivalent Availability (%) 88 88 Based on NERC database Equivalent Forced Outage Rate (%) 5.0 5.0 Planed Outage Rate (%) 8.0 8.0 Five weeks per year Production Profile (Daily) Dispatched as per system requirements but with very long start up and shut down time. Production Profile (Seasonal) Dispatched as per system requirements but with very long start up and shut down time. Net Heat Rate (KJ/kWh, HHV) 10,000 10,000 Primary Fuel Cost ($/GJ) 7.5 7.5 Overall Capitalized Cost ($M) 19,096.2 50,127.5 Plant EPC ($M) 13,200.0 34,650.0 Based on Net capacity and 10% contingency Owner's Cost ($M) 396.0 1,039.5 3% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 10%, 15%, 20%, 25%, 20%, 10% Plant IDC ($M) 4,504.7 11,824.7 Rate of 10% to align the cost to service year Grid Integration EPC ($M) [1] Owner's Cost for Grid Integration ($M) Grid Integration CAPEX Disbursement Flow (%) 60%, 40% 60%, 40% Grid Integration IDC ($M) Financing Charges including Commitment ($M) 90.5 237.6 0.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 905.0 2,375.7 5% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 95,481 83,546 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 1,432.2 1,253.2 1.5% of total capitalized cost Variable O&M Cost ($/MWh) 64.1 56.1 0.5% of the total capitalized cost and 85% CF. Insurance Cost ($M/Year) 47.7 125.3 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 47.7 125.3 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options Note: [1] Grid connection has not been costed because of complexity and extremely large project scope Note: All Costs expressed in N$

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Table 5-5 - Hydro Electric Power Generation

Hydro Power Plant Name Baynes Kavango Orange Comment Fuel Water Plant Gross Capacity (MW) 612 20.4 102 Plant Net Capacity (MW) 600 20 100 Number of Units 5 Economic Life (Year) 50 50 50 Lead Time (Year) 9 6 6 Earliest On-Line Year 2022 2019 2019 Equivalent Availability (%) 90 90 90 Equivalent Forced Outage Rate (%) 4.0 4.0 4.0 Based on the NERC data Planed Outage Rate (%) 4.0 4.0 4.0 Three/Two weeks per year Production Profile (Daily) Dispatchable if there is a daily peaking storage. Otherwise non-dispatchable as it depends on in-flows. Production Profile (Seasonal) Dispatchable only if there is a relatively large reservoir, comparing with the station's rated discharge flow. Net Heat Rate (KJ/kWh, HHV) Primary Fuel Cost ($/GJ) Overall Capitalized Cost ($M) 18,272.7 550.2 2,872.4 Plant EPC ($M) 9,900.0 412.5 2,062.5 Site dependent, no road access and grid connection. Owner's Cost ($M) 495.0 20.6 103.1 5% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) Baynes:10%, 15%, 20%, 25%, 20% and 10%. Others: 30%, 40% and 30%. Plant IDC ($M) 3,444.1 67.9 339.6 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 3,120.2 25.0 220.8 Owner's Cost for Grid Integration ($M) 312.0 2.5 22.1 Grid Integration CAPEX Disbursement Flow (%) 60%, 40% 60%, 40% 60%, 40% Grid Integration IDC ($M) 383.5 3.1 27.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 264.8 8.0 41.6 1.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 353.1 10.6 55.5 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 30,455 27,512 28,724 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 456.8 412.7 430.9 1.5% of total capitalized cost Variable O&M Cost ($/MWh) Insurance Cost ($M/Year) 45.7 1.4 7.2 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 45.7 1.4 7.2 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options Note: All Costs expressed in N$

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Table 5-6 - Wind Power Generation

Generation Technology Wind Comment Fuel Wind Plant Gross Capacity (MW) 50 Plant Net Capacity (MW) 50 Number of Units 25 Economic Life (Year) 20 Lead Time (Year) 3-5 Earliest On-Line Year 2015 Equivalent Availability (%) 95 Equivalent Forced Outage Rate (%) 3.0 Planed Outage Rate (%) 2.0 One week per year Production Profile (Daily) Non-dispatchable Production Profile (Seasonal) Non-dispatchable Net Heat Rate (KJ/kWh, HHV) - Primary Fuel Cost ($/GJ) - Overall Capitalized Cost ($M) 1,042.0 Plant EPC ($M) 631.1 Based on Net capacity and 10% contingency Owner's Cost ($M) 31.6 5% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 60%, 40% Plant IDC ($M) 74.0 Rate of 10% to align the cost to service year Grid Integration EPC ($M) [1] 220.8 Owner's Cost for Grid Integration ($M) 22.1 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% Grid Integration IDC ($M) 27.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 15.1 1.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 20.1 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 20,840 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 521.0 2.5% of total capitalized cost Variable O&M Cost ($/MWh) - Insurance Cost ($M/Year) 2.605 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 2.605 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options Note: All Costs expressed in N$

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Table 5-7 - Solar PV Power Generation

Generation Technology Solar Comment Fuel Sun Light Plant Gross Capacity (MW) 10 Plant Net Capacity (MW) 10 Number of Units Economic Life (Year) 20 Lead Time (Year) 3-5 Earliest On-Line Year 2015 Equivalent Availability (%) 95 Equivalent Forced Outage Rate (%) 3.0 Planed Outage Rate (%) 2.0 One week per year Production Profile (Daily) Non-dispatchable, generates during day time Production Profile (Seasonal) Non-dispatchable, generates during day time Net Heat Rate (KJ/kWh, HHV) - Primary Fuel Cost ($/GJ) - Overall Capitalized Cost ($M) 307.8 Plant EPC ($M) 235.1 Based on Net capacity and 10% contingency Owner's Cost ($M) 7.1 3% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 60%, 40% Plant IDC ($M) 27.1 Rate of 10% to align the cost to service year Grid Integration EPC ($M) [1] 24.2 Owner's Cost for Grid Integration ($M) 2.4 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% Grid Integration IDC ($M) 3.0 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 3.0 1% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 6.0 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 30,780 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 461.7 1.5% of total capitalized cost Variable O&M Cost ($/MWh) - Insurance Cost ($M/Year) 0.769 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 0.769 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options

Note: All Costs expressed in N$

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Table 5-10: Summary of DSM Program Impacts and Costs

Program Savings Cost per Launch Duration Peak Annual Total Period Total Cost per kW Program Description Target Group Date (years) Demand Energy Energy (Years Cost (N$ kWh (N$/kW (MW) (GWh/year (GWh) ) million) (N$/kWh) ) ) 1 CFL Roll Out Program Residential Year 1 3 22.9 41.9 335.0 10 23.8 1,040 0.071 Residential SWH 5 2 Residential 15.2 52.4 1,048.0 24 72.8 4,780 0.069 Dissemination Year 1 C&I Buildings SWH Commercial & 5 3 4.7 16.6 332.0 24 23.0 4,890 0.069 Dissemination Institutional Year 2 Commercial & Subsidized Energy Audits 4 2.3 20.5 308.0 18 4 Industrial Year 2 40.3 17,450 0.131 C & I Energy-Efficient Commercial & 4 5 3.1 8.9 71.0 11 9.6 3,080 0.135 Lighting institutional Year 3 6 Ripple Control of EWH Residential Year 1 4 23.1 0.0 0.0 23 101.8 4,420 N/A Commercial & C&I Air Conditioning 4 2.5 3.1 31.0 13 7 Institutional Year 3 21.6 8,700 0.696 Information Dissemination & 8 8 All consumers 2.5 16.1 155.0 12 9.8 3,870 0.063 Public Awareness Year 1 9 Energy Audit – Large Industry Large Industry Year 2 4 7.5 40.5 675.0 17 33.9 4,520 0.050 Total 83.8 237.0 2,955 336.6 4,017 0.114

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Table 5-11 - Small Modulated Nuclear Reactor Power Generation

Generation Technology Nuclear Nuclear Comment Fuel Uranium Plant Gross Capacity (MW) 56 112 Plant Net Capacity (MW) 50 100 Number of Units 1 1 Economic Life (Year) 40 40 Lead Time (Year) 6-8 6-8 Earliest On-Line Year Per technology development Equivalent Availability (%) 88 88 Based on NERC database Equivalent Forced Outage Rate (%) 3.0 3.0 Planed Outage Rate (%) 8.0 8.0 Four weeks per year Production Profile (Daily) Dispatched as per system requirements but with very long start up and shut down time. Production Profile (Seasonal) Dispatched as per system requirements but with very long start up and shut down time. Net Heat Rate (KJ/kWh, HHV) 11,000 11,000 Primary Fuel Cost ($/GJ) 7.5 7.5 Overall Capitalized Cost ($M) 5,289.9 10,050.8 Plant EPC ($M) 4,125.0 7,837.5 Based on Net capacity and 10% contingency Owner's Cost ($M) 123.8 235.1 3% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 15%, 35%, 35%, 15% Plant IDC ($M) 912.1 1,733.0 Rate of 10% to align the cost to service year Grid Integration EPC ($M) [1] Owner's Cost for Grid Integration ($M) Grid Integration CAPEX Disbursement Flow (%) 60%, 40% 60%, 40% Grid Integration IDC ($M) Financing Charges including Commitment ($M) 25.8 49.0 Rate of 10% to align the cost to service year Decommissioning Cost ($M) 103.2 196.1 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 105,798 100,508 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 1,587.0 1,507.6 1.5% of total capitalized cost Variable O&M Cost ($/MWh) 71.0 67.5 0.5% of the total capitalized cost and 85% CF. Insurance Cost ($M/Year) 13.2 25.1 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 13.2 25.1 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options Note: [1] Grid connection has not been costed because of complexity and extremely large project scope

Note: All Costs expressed in N$

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Table 5-12 - Solar Thermal Power Generation

Generation Technology Solar Thermal Solar Thermal Comment Fuel Sun Light Plant Gross Capacity (MW) 26 52 Plant Net Capacity (MW) 25 50 Number of Units 1 1 Economic Life (Year) 20 20 Lead Time (Year) 5-7 5-7 Earliest On-Line Year 2018/2020 Equivalent Availability (%) 90 90 Equivalent Forced Outage Rate (%) 5.0 5.0 Planed Outage Rate (%) 4.0 4.0 Two weeks per year Production Profile (Daily) Dispatched as per system requirements but with a limited amount of energy each day. Production Profile (Seasonal) Dispatched as per system requirements but with a limited amount of energy each day. Net Heat Rate (KJ/kWh, HHV) Primary Fuel Cost ($/GJ) Overall Capitalized Cost ($M) 1,416.8 2,795.8 Plant EPC ($M) 1,134.4 2,062.5 Based on Net capacity and 10% contingency Owner's Cost ($M) 34.0 61.9 3% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 30%, 40%, 30% Plant IDC ($M) 183.2 333.2 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 25.0 220.8 Owner's Cost for Grid Integration ($M) 2.5 22.1 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% 60%, 40% Grid Integration IDC ($M) 3.1 27.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 6.9 13.6 0.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 27.6 54.6 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 56,671 55,915 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 850.1 838.7 1.5% of total capitalized cost Variable O&M Cost ($/MWh) 92.4 91.2 0.5% of the total capitalized cost and 35% CF. Insurance Cost ($M/Year) 3.5 7.0 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 3.5 7.0 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options Note: All Costs expressed in N$

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Table 5-13 - Power Generation Using Municipal Solid Waste

Generation Technology WTE WTE Comment Fuel MSW Plant Gross Capacity (MW) 10.6 21.2 Plant Net Capacity (MW) 10 20 Number of Units 1 1 Economic Life (Year) 25 25 Lead Time (Year) 5-7 5-7 Earliest On-Line Year 2018/2020 Equivalent Availability (%) 80 80 Equivalent Forced Outage Rate (%) 10.0 10.0 Planed Outage Rate (%) 8.0 8.0 Four weeks per year Production Profile (Daily) Dispatched as per system requirements. Production Profile (Seasonal) Dispatched as per system requirements. Net Heat Rate (KJ/kWh, HHV) 20,000 19,500 Primary Fuel Cost ($/GJ) 50.63 50.63 Overall Capitalized Cost ($M) 929.4 1,727.6 Plant EPC ($M) 742.5 1,402.5 Based on Net capacity and 10% contingency Owner's Cost ($M) 14.9 28.1 2% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 30%, 40%, 30% Plant IDC ($M) 118.8 224.4 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 25.0 25.0 Owner's Cost for Grid Integration ($M) 2.5 2.5 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% 60%, 40% Grid Integration IDC ($M) 3.1 3.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 4.5 8.4 0.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 18.1 33.7 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 92,937 86,381 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 929.4 863.8 1% of total capitalized cost Variable O&M Cost ($/MWh) 66.3 61.6 0.5% of the total capitalized cost and 80% CF. Insurance Cost ($M/Year) 2.3 4.3 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 2.3 4.3 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Depending upon the waste compositions. NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options

Note: All Costs expressed in N$

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Table 5-14 - Bio-Fuel Power Generation

Generation Technology CCGT CCGT Comment Fuel Bio-fuel Plant Gross Capacity (MW) 78 156 Plant Net Capacity (MW) 75 150 Number of Units 1 1 Economic Life (Year) 25 25 Lead Time (Year) 6-7 6-7 Earliest On-Line Year 2018/2019 2018/2019 Equivalent Availability (%) 88 88 Based on NERC database Equivalent Forced Outage Rate (%) 6.0 6.0 Planed Outage Rate (%) 6.0 6.0 Three weeks per year Production Profile (Daily) Dispatched as per system requirements Production Profile (Seasonal) Dispatched as per system requirements Net Heat Rate (KJ/kWh, HHV) 7,200 6,980 Primary Fuel Cost ($/GJ) 177.93 177.93 Overall Capitalized Cost ($M) 1,026.3 1,971.2 Plant EPC ($M) 618.8 1,175.6 Based on Net capacity and 10% contingency Owner's Cost ($M) 61.9 117.6 10% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 30%, 40%, 30% Plant IDC ($M) 106.7 202.8 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 167.0 334.1 Owner's Cost for Grid Integration ($M) 16.7 33.4 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% Grid Integration IDC ($M) 20.5 41.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 14.9 28.6 1.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 19.8 38.1 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 13,684 13,141 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 342.1 328.5 2.5% of total capitalized cost Variable O&M Cost ($/MWh) 91.9 88.2 5% of the total capitalized cost and 85% CF. Insurance Cost ($M/Year) 2.6 4.9 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 2.6 4.9 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options Note: All Costs expressed in N$

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Table 5-15 - Biomass Power Generation

Generation Technology BFB BFB Comment Fuel Invader Bush Plant Gross Capacity (MW) 5.6 22.4 Plant Net Capacity (MW) 5 20 Number of Units 1 1 Economic Life (Year) 25 25 Lead Time (Year) 6-10 6-10 Earliest On-Line Year 2019/2023 2019/2023 Equivalent Availability (%) 88 88 Based on NERC database Equivalent Forced Outage Rate (%) 7.0 7.0 Planed Outage Rate (%) 8.0 8.0 Four weeks per year Production Profile (Daily) Dispatched as per system requirements Production Profile (Seasonal) Dispatched as per system requirements Net Heat Rate (KJ/kWh, HHV) 15,000 14,500 Primary Fuel Cost ($/GJ) 59.71 59.71 Overall Capitalized Cost ($M) 239.1 757.7 Plant EPC ($M) 165.0 577.5 Based on Net capacity and 10% contingency Owner's Cost ($M) 8.3 28.9 5% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 30%, 40%, 30% Plant IDC ($M) 27.2 95.1 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 25.0 25.0 Owner's Cost for Grid Integration ($M) 2.5 2.5 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% Grid Integration IDC ($M) 3.1 3.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 3.5 11.0 1.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 4.6 14.6 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 47,816 37,884 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 1,195.4 947.1 2.5% of total capitalized cost Variable O&M Cost ($/MWh) 192.7 152.6 3% of the total capitalized cost and 85% CF. Insurance Cost ($M/Year) 0.6 1.9 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 0.6 1.9 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options

Note: All Costs expressed in N$

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Table 5-16 - Geothermal Power Generation

Generation Technology Geothermal Geothermal Comment Fuel Geothermal Plant Gross Capacity (MW) 5.6 22.4 Plant Net Capacity (MW) 5 20 Number of Units 1 1 Economic Life (Year) 25 25 Lead Time (Year) 8-10 8-10 Earliest On-Line Year 2021/2023 2021/2023 Equivalent Availability (%) 86 86 Based on NERC database Equivalent Forced Outage Rate (%) 8.0 8.0 Planed Outage Rate (%) 6.0 6.0 Three weeks per year Production Profile (Daily) Dispatched as per system requirements Production Profile (Seasonal) Dispatched as per system requirements Net Heat Rate (KJ/kWh, HHV) 11,500 11,000 Primary Fuel Cost ($/GJ) 0.75 0.75 Overall Capitalized Cost ($M) 358.8 1,240.5 Plant EPC ($M) 268.1 990.0 Based on Net capacity and 10% contingency Owner's Cost ($M) 8.0 29.7 3% of Plant's EPC cost Plant CAPEX Disbursement Flow (%) 30%, 40%, 30% Plant IDC ($M) 43.3 159.9 Rate of 10% to align the cost to service year Grid Integration EPC ($M) 25.0 25.0 Owner's Cost for Grid Integration ($M) 2.5 2.5 10% of Integration cost Grid Integration CAPEX Disbursement Flow (%) 60%, 40% Grid Integration IDC ($M) 3.1 3.1 Rate of 10% to align the cost to service year Financing Charges including Commitment ($M) 1.8 6.1 0.5% of sum of all EPC, Owner's cost and IDC Decommissioning Cost ($M) 7.0 24.2 2% of sum of all EPC, Owner's cost and IDC Overall Plant Capital Unit Capacity Cost ($/kW) 71,761 62,023 Based on the Net capacity Fixed O&M Cost ($/kW-Year) 1,076.4 930.3 1.5% of total capitalized cost Variable O&M Cost ($/MWh) 96.4 83.3 1% of the total capitalized cost and 85% CF. Insurance Cost ($M/Year) 0.9 3.1 0.25% of the total capitalized cost Interim Replacement Cost ($M/Year) 0.9 3.1 0.25% of the total capitalized cost CO2 Emission Rate (kg/GJ) Not applicable NOx Emission Rate (kg/GJ) SO2 Emission Rate (kg/GJ) Particulate Matter Emission Rate (kg/GJ) Environmental Issues Refer to Environmental and Social Assessment of Generation Options Social Issues and Impacts Refer to Environmental and Social Assessment of Generation Options

Note: All Costs expressed in N$

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6. Grid Integration This section addresses the requirements for grid connection and provides cost estimates for the facilities identified for that purpose.

6.1 Introduction As described in Section 5.2, a number of generation projects have been proposed, based on the review performed on the energy resources available for power generation, and are located throughout Namibia as can be seen in Figure 6-1. The same figure also shows where areas where the existing NamPower generation is located.

Figure 6-1 - Namibian Power Network A high level grid connection investigation was carried out for the following different identified power generation options:

 The 800 MW Kudu Gas Power Station, located on the border between Namibia and South Africa

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 The 600 MW Baynes Hydro Power Station near Ruacana Power Station  A 400 MW Nuclear Power Station, comprising of two units near Walvis Bay  The 300 MW Erongo Coal Power Station near Walvis Bay  A 300 MW Combined Cycle Gas Turbine Power Station near Walvis Bay  A 60 MW IPP Wind Farm near Walvis Bay  A 44 MW IPP Wind Farm near Luderitz  A 10 MW Solar PV farm near Keetmanshoop.

It is recognized that other generation options exist but the cost of their integration into the system can be deduced from those presented herein.

The objective of these grid integration screening studies was to determine the transmission works that would be required to integrate and absorb the power being generated by the aforementioned power stations. It must also be noted that these are screening studies and detailed network integration studies will be required to determine the performance of each of the generation sources by reviewing the impact on the system voltages, load flows within the networks, network losses, system stability, possible sub-synchronous resonance concerns and overall network reliability under various network operating contingencies.

The following subsections provide a high level review of the grid connection requirements for each of the generation options, with each generation source being treated as a standalone facility and not in conjunction with the other generation facilities.

6.2 The 800 MW Kudu Gas Power Station The Kudu power station would be situated on the Namibian side of the border with South Africa on the West coast of Africa. The power station is planned to have a total generating capacity of 800 MW (net). To evacuate this amount of power, a 400 kV connection is required with n-1 reliability. The remote location of the generation, in terms of the load centres, means that should one line trip, then the second power line will be able to evacuate the power while the other power line is being returned to service.

To ensure this n-1 operation, two 400 kV lines are required from the Kudu power station. One to both the Namibian and South African 400 kV networks respectively. Figure 6-2 below shows the Kudu power station and the substations into which it is planned to integrate the generation. The new lines being proposed are the dotted lines, while existing lines are solid lines.

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Figure 6-2 - The Proposed KUDU Gas Power Station Integration Options One transmission line is routed to the Kokerboom substation via Obib substation in Namibia and the other to Juno substation in South Africa. Besides the 400 kV lines a 220 kV line to the Oranjemond substation, which is just across the Orange River in South Africa, is also planned. This is primarily because Oranjemond supplies Namibian loads close to where Kudu power station is proposed.

This integration of Kudu power station allows it to feed into the Namibian or the South African grid. It is to be noted that the series capacitors at Juno and also those further in the South African network will make it prudent to assess whether a sub-synchronous resonance (SSR) problem exists with the Kudu generators. In addition to this, because of size of the generation and the very long 400 kV line, between Kudu and Juno substations, a 400 kV series capacitor bank could be required. The most suitable placing would be near Gromis substation, which can supply the auxiliary supplies to the capacitor bank.

6.2.1 Transmission Grid Connections To realize the network connections shown in Figure 6-2, it is necessary to review the single line diagram schematic shown in Figure 6-3.

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Figure 6-3 - Network Diagram for Kudu Gas Integration As shown above, a double bus bar configuration for both the 400 kV and the 220 kV yards is recommended. Because of the generation on the 400 kV bus bars, a double bus bar with two bus couplers and two bus sections is required. On the 220 kV side, a double bus bar configuration with only one bus coupler would be sufficient.

This is only an estimate for the equipment required for connecting to the grid. Detailed network studies must be performed to determine what impact the generation would have on the utility networks.

Table 6-1, at the end of this Section 6, is a summary of the transmission network equipment, needed at the relevant substations, to integrate the 812 MW being generated at Kudu.

6.3 The 600 MW Baynes Hydro Power Station As can be seen from Figure 6-1, the Baynes Hydro Power Station is situated on the Kunene River which forms the border between Namibia and Angola. It is envisaged that its 600 MW output would be shared equally between Namibia and Angola. Angola is expected to take its share of power from Ruacana by means of a 400 kV line to Matala substation, located approximately 350 km’s inside the border of Angola.

For the integration of the Baynes Hydro Power Station, two grid connection options are reviewed. The first option can be seen in Figure 6-4, with the dotted lines being the new 400 kV power lines being proposed.

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Figure 6-4 - Baynes Hydro Integration – Option 1 The second proposal is similar to the first, however the difference is the proposal to recycle the existing 330 kV AC line to a 350 kV HVDC Light connection, as shown in

Figure 6-5 below.

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Figure 6-5 - Baynes Hydro Integration – Option 2 This option has the added cost of the converter stations but does not have the cost of a long DC line, as was the case for the Gerus-Zambezi HVDC line, since the power line will be recycled.

6.3.1 Grid Connection Using 400 kV Lines and Substations Only (Option 1) The first of the proposed connections can be seen in Figure 6-4. The connection is via a 400 kV line, from Baynes to Ruacana. The option exists to only use two 400 kV lines, providing a connection that is capable of withstanding an n-1 contingency. However the Namibian grid code states that for power stations with output capacities of less than 1000 MW a single line is sufficient, provided the line has full transfer capabilities on both sides of the line.

At Ruacana a 400 kV /330 kV step down substation will be required to connect to the existing 330 kV Ruacana yard. This will allow some of the power being generated at Ruacana power station to be transported on the 400 kV network. The proposal also requires a 400 kV line, approximately 420 km’s long, between the Ruacana 400 kV yard to the 400 kV yard at Gerus substation. There is some indication that NamPower is considering a 400 kV line to Ruacana via Otjikoto substation, but this will result in a power line that has a length in excess of 620 km’s.

Figure 6-6 - Option 1 for the Proposed Network Connection for Baynes Hydro Power Station

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To get the bulk of the power to the load centres of the NamPower network, a 400 kV line from Ruacana to Gerus is required because the existing Ruacan-Omburu 330 kV line is not capable of moving the additional 300 MW of power through it. The preferred line route is a direct line to Gerus substation to minimize the line lengths.

At Gerus substation a 400 kV bus bar, with a 400 kV line to Auas, has been planned, as can be seen in Figure 6-1. Auas is well situated to supply Windhoek and South Africa via the 400 kV and 220 kV lines to Kokerboom. Gerus is chosen as it will be the nearest 400 kV substation to Ruacana. To ensure the output of Ruacana and all of Baynes, the 400 kV line Ruacana-Gerus should be 50% series compensated and SVCs installed at Gerus and Auas. At Ruacana, two 630 MVA 400/330 kV transformers are required. This integration does not provide an n-1 capability in all instances. However, the clearing of line faults by single phase auto-reclosing and live line maintenance should give an acceptable availability of electricity supply cost effectively.

Table 6-2, at the end of this Section 6, provides a summary of the plant required for the connection of Baynes Hydro Power station to the NamPower network.

6.3.2 Grid Connection Using 400 kV Lines and Substations but also Recycling an AC Line to DC (Option 2) The second option available for connecting the Baynes hydro power station involves a similar solution as option 1, with the only exception being the recycling of the existing 552 km long Ruacana-Omburu 330 kV line to a HVDC Light link, which makes use of Voltage Source Inverter (VSI) technology, identical to that used on the Gerus-Zambezi 350 kV DC link. This alternative proposal can be seen in Figure 6-7.

Converting the line to DC will enable more power to be sent down to Omburu substation. Currently the line is being operated at 330 kV AC and it is fairly weak. Omburu substation however does have a number of 220 kV lines connecting it to the rest of the NamPower network.

This alternative connection option has the benefit of not constructing a 420 km long 400 kV power line, but has the added cost of the converter stations on either side.

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Figure 6-7 - Option 2 for the Proposed Network Connection for Baynes Hydro Power Station Table 6-3, at the end of this Section 6, provides a summary of the equipment required for the connection of the Baynes Power station to the southern part of the NamPower network through Omburu substation. The benefit of this solution is that all the 400 kV line strengthening is mitigated and very little changes have to be made to the existing network in the immediate vicinity of Omburu. Omburu currently has four 220 kV lines leaving the substation, connecting it to the major load centres.

What is evident is that the HVDC Light solution, which is far more flexible, costs 10% less than the 400 kV network upgrades.

6.4 2 x 200 MW Nuclear Power Station Units near Walvis Bay The installation of a nuclear power station in Namibia is not recommended at this point in time. The reason for this is security of the off-site electricity supply to the nuclear power station in the Walvis Bay area would be insufficient to allow for the safe shut down of a nuclear reactor following the loss of all generation at that power station. The off- site supply would come from the main sources of generation in Namibia namely Ruacana and Eskom, both of which have a single transmission line connection. This is not sufficient since both off site supplies need redundancy in the transmission networks to the generation sources and the cost of realising this would be extremely high.

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The Namibian Grid Code does not include requirements for nuclear generation. However, the South African Grid Code does and it can be expected that the Namibian Grid code would include a similar clause when nuclear generation is envisaged. The South African Grid Code requires the following:

The System Operator shall provide secure off-site supplies, as requested and specified by the relevant nuclear generators and facilities in accordance with the National Nuclear Regulatory Act (Act 47 of 1999), to all TS-connected nuclear power stations and facilities. A written agreement, as per section 2.1.3 of the System Operation Code, shall be drawn up and indicators of performance are to be developed and implemented to illustrate the integrity of supply.

The NamPower System Operator would not be able to comply with the above with the present NamPower generation and transmission configuration.

Besides the redundancy required on the existing lines to the generation sources, local generation will also be required as an additional back up. In addition to this, two more 400 kV lines would be required to realize the connection to the current NamPower network. Figure 6-8 provides an indication of the shallow (immediate vicinity) network upgrades for operating the nuclear units. The deep network reinforcing would mean providing a second 400 kV connection to South Africa and second 330 kV connections to the Ruacana and Van Eck power stations.

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Figure 6-8 - Immediate Network Upgrades Required for Operating Nuclear Facilities Because of the complexity and extremely large project scope, this grid connection option has not been costed.

6.5 The 300 MW Erongo Coal Power Station near Walvis Bay The grid connection required to successfully transport the generated power to the various load centres requires upstream network strengthening. The proposed grid strengthening can be seen in Figure 6-9 and consists of a new substation, called Arandis East, at the proposed generation site. Two 220 kV lines, to Khan Substation, and one line back to Walmund substation are suggested. In addition to this, an additional 220 kV line to Omburu is also shown. This has been selected because of the long network path to Van Eck down past Kuiseb.

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Figure 6-9 - The Erongo Coal Power Station Grid Integration

6.5.1 Transmission Grid Connections To realize the network connections shown in Figure 6-9, it is necessary to review the single line diagram schematic shown in Figure 6-10.

It must be qualified that this is only an estimate for the equipment required for connecting to the grid. Detailed network studies must be performed to determine what impact the generation would have on the utility networks.

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Figure 6-10 - The Erongo Coal Power Station Grid Integration SLD

Table 6-4, at the end of this Section 6, is a summary of the transmission network equipment, needed at the relevant substations, to integrate the 300 MW being generated by Erongo Coal Power Stations at Arandis East substation, feeding into the 220 kV network.

6.6 The 300 MW Combined Cycle Gas Turbine near Walvis Bay It must be noted that this grid connection option is identical to that used for the ERONGO Coal Power Station grid connection in the previous section. Both sites will generate the same amount of power and both site locations still have not been finalised. Subsequently the cost for grid integration for both of generation options is identical.

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Figure 6-11 - The Walvis Bay CCGT Grid Integration 6.6.1 Transmission Grid Connections To realize the network connections, shown in Figure 6-11, it is necessary to review the single line diagram schematic shown in Figure 6-12.

Figure 6-12 - Walvis Bay CCGT Grid Integration SLD

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Table 6-5, at the end of this Section 6, is a summary of the transmission network equipment, needed at the relevant substations, to integrate the 300 MW being generated by the CCGTs at Arandis East substation, feeding into the 220 kV network.

6.7 The 60 MW INNOWIND Wind Farm near Walvis Bay The INNOWIND Wind Farm (IPP) is located approximately 29 km’s from the Kuiseb 220 kV/66 kV step down station. There is a 66 kV line running near the proposed wind site but it is not capable of transporting 60 MW of power to Kuiseb substation. Furthermore, the line route to the substation is approximately 45 km’s, further complicating the ability of the 66 kV network to carry the power to the grid. The optimal grid connection solution is to connect directly to the 220 kV network via a 45 km long 220 kV line (see Figure 6-13).

Figure 6-13 - The INNOWIND Wind Farm Grid Integration

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6.7.1 Transmission Grid Connections To realize the network connections shown in Figure 6-13 it is necessary to review the single line diagram schematic shown in Figure 6-14.

Figure 6-14 - INNOWIND Wind Farm Grid Integration SLD

Table 6-6, at the end of this Section 6, is a summary of the transmission network equipment, needed at the relevant substations, to integrate the 60 MW being generated at Walvis Bay at 220 kV.

6.8 The 44 MW Diaz Wind Farm near Luderitz The Diaz Wind Farm (IPP) is located approximately 19 km’s from the Namib 132 kV/66 kV step down station. There is a 66 kV Hare line running near the proposed wind site but it is not capable of transporting 44 MW of power, on its own to Namib substation. Furthermore, the line route to the substation is approximately 25 km’s, further complicating the ability of the 66 kV network to carry the power to the grid. The optimal grid connection is to connect directly, via a dedicated purpose built 25 km long 132 kV power line to the 132 kV bus bar at the Namib substation, as can be seen in Figure 6-15.

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Figure 6-15 - The Diaz Wind Farm Grid Integration near Luderitz

6.8.1 Transmission Grid connections To realize the network connections shown in Figure 6-15, it is necessary to review the single line diagram schematic shown in Figure 6-16.

Figure5-16 - DIAZ Wind Farm Grid Integration SLD

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Table 6-7, at the end of this Section 6, is a summary of the distribution network equipment, needed at the relevant substations, to integrate the 44 MW being generated at the DIAZ wind farm into the 132 kV network.

6.9 The 10 MW Keetmanshoop Solar Farm The Keetmanshoop Farm (IPP) is located approximately 2.5 km from the Keetmanshoop 66 kV substation. The proposal is to construct a dedicated 66 kV power line to Keetmanshoop substation and to extend the 66 kV yard at Keetmanshoop substation for the generation bay. The line route to the substation is approximately 5 km’s. The proposed route can be seen in Figure 6-17.

Figure 6-17 - The Keetmanshoop Solar Farm Grid Integration

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6.9.1 Transmission Grid connections To realize the network connections shown in Figure 6-17, it is necessary to review the single line diagram schematic shown in Figure 6-18.

Figure 6-18 - The Keetmanshoop Solar Farm Grid Integration SLD

Table 6-8, at the end of this Section 6, is a summary of the transmission network equipment, needed at the relevant substations, to integrate the 10 MW being generated at Keetmanshoop onto the 66 kV network.

6.10 Summary of Capital Cost for Grid Integration Table 6-9 provides a summary of the estimated costs to integrate the various generation projects into the grid.

Table 6-9 - Summary of Estimated Costs for Grid Integration Project Cost of Grid Integration (N$, million) Kudu Gas Power Station 1,939.4 Baynes, Option 1 3,454.4 Baynes, Option 2 3,120.2 Nuclear [1] - 300 MW Erongo Coal 688.1

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300 MW CCGT 688.1 60 MW Innowind 220.8 44 MW Diaz wind 49.3 10 MW Keetmanshoop 24.2 Note: [1] This has not been costed because of the complexity and extremely large project scope

From the above values, the cost of integration for other generation namely MSW, biofuel and biomass can be derived. Projects of the order of 50 MW or 60 MW would have a transmission cost of 220 N$ million while projects of the order of 10 to 20 MW would have a cost of 25 N$ million.

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Table 6-1 - Summary of Equipment Required for Kudu integration Unit Cost Total Cost Substation Equipment Number Voltage/Length/Rating (N$ x 1,000) (N$ x 1,000) Kudu Feeder bays 2 400 kV 14,000 28,000 Transformer bays 4 400 kV 14,000 56,000 400/220 kV Transformers 2 180 MVA 25,000 50,000

Generator bay 2 400 kV 12,000 24,000 Bus coupler bays 2 400 kV 9,500 19,000 Bus section bays 2 400 kV 10,500 21,000 Reactor bay 1 400 kV 10,000 10,000

Line Reactor 1 400 kV,100 Mvar 18,000 18,000 Busbars & Busbar VTs (LOT) 1 400 kV 14,000 14,000 Feeder bays 1 220 kV 8,000 8,000 Transformer bays 2 220 kV 6,000 12,000 Buscoupler bays 1 220 kV 5,500 5,500 Busbars & Busbar VTs (LOT) 1 400 kV 9,000 9,000 Protection, Metering, Control & Telecoms (LOT) 1 400 kV & 220 kV 14,000 14,000 Substation Civils & Architectural Works (LOT) 1 75,000 75,000 Construction & Commissioning (LOT) 1 65,000 65,000 Total 428,500 Obib Feeder bay 1 400 kV 14,000 14,000 Busbar Extension 1 400 kV 3,500 3,500 Protection, Metering, Control & Telecoms (LOT) 1 400 kV 2,000 2,000 Construction & Commissioning (LOT) 1 400 kV 3,500 3,500 Total 23,000 Oranjemond Feeder bays 1 220 kV 8,000 8,000 Busbar Extension 1 220 kV 1,500 1,500 Protection, Metering, Control & Telecoms (LOT) 1 220 kV 1,400 1,400 Construction & Commissioning (LOT) 1 220 kV 2,500 2,500 Total 13,400 Gromis 400 kV bank providing 30% Series Capacitor (1 lump sum in line) 1 45,000 45,000 compensation Construction & Commissioning (LOT) 1 400 kV series cap bank 7,000 7,000 Total 52,000 Juno Feeder bays 1 400 kV 14,000 14,000 Busbar Extension 1 400 kV 3,500 3,500 Reactor bay 1 400 kV 10,000 10,000

Line Reactor 1 400 kV,100 Mvar 18,000 18,000

Protection, Metering, Control & Telecoms (LOT) 1 400 kV 2,000 2,000 Construction & Commissioning (LOT) 1 400 kV 4,500 4,500 Total 52,000 Power Lines Kudu-Oranjemond 7 1x Zebra 220 kV, approx 7 1,909 13,363 km long Kudu-Obib 80 4x Pelican 400 kV, approx 2,763 221,040 80 km long

Kudu-Juno 430 4xPelican 400 kV, approx 2,763 1,188,090 430 km long Total 1,422,493 Grand Total 1,991,393 ISO 9001 H338829-0000-90-124-0004, Rev. B, Page 154

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Table 6-2 - Transmission Integration Requirements for Baynes Power Station – Option 1 Baynes Hydro 600 MW (2x300 MW) Option 1 Unit Cost Total Cost Substation Equipment Number Voltage/Length/Rating (N$ x 1,000) (N$ x 1,000) Baynes Feeder bays 1 400 kV 14,000 14,000 Gen Transformer bays 2 400 kV 12,000 24,000

Bus coupler bays 2 400 kV 9,500 19,000 Total 57,000 Cunene Feeder bays 3 400 kV 14,000 42,000 Transformer bays 2 400 kV 14,000 28,000 400/330 kV Transformers 2 630 MVA 400/330 kV 70,000 140,000

Bus coupler bays 1 400 kV 9,500 9,500 Reactor bays 2 400 kV 10,000 20,000

Line Reactor 1 400 kV,100 Mvar 18,000 18,000 Busbar Reactor 1 400 kV,100 Mvar 18,000 18,000 Busbars & Busbar VTs (LOT) 1 400 kV 14,000 14,000

Busbar Extension 1 330 kV 4,500 4,500 Feeder bays 2 330 kV 10,000 20,000 Transformer bays 2 330 kV 8,000 16,000 Buscoupler bays 1 330 kV 6,500 6,500 Protection, Metering, Control & Telecoms (LOT) 1 400 kV & 330 kV 14,000 14,000 Substation Civils & Architectural Works (LOT) 1 75,000 75,000 Construction & Commissioning (LOT) 1 65,000 65,000 Total 490,500 Gerus Feeder bay 2 400 kV 14,000 28,000 Transformer bays 2 400 kV 14,000 28,000

400/330 kV Transformers 2 315 MVA 400/220 kV 41,000 82,000 Bus coupler bays 1 400 kV 9,500 9,500 Busbars & Busbar VTs (LOT) 1 400 kV 9,000 9,000 Reactor bays 2 400 kV 10,000 20,000 Line Reactor 1 400 kV,100 Mvar 18,000 18,000 Busbar Reactor 1 400 kV,100 Mvar 18,000 18,000 SVC Bay 1 400 kV 9,500 9,500

SVC 1 ±250 Mvar, 400 kV 145,000 145,000 Transformer bays 2 220 kV 6,000 12,000 Substation Civils & Architectural Works (LOT) 1 45,000 45,000 Protection, Metering, Control & Telecoms (LOT) 1 400 kV & 220kV 14,000 14,000 Construction & Commissioning (LOT) 1 400 kV 55,000 55,000 Total 493,000 Auas Feeder bays 1 400 kV 14,000 14,000 Busbar Extension 1 400 kV 3,500 3,500 SVC Bay 1 400 kV 9,500 9,500

SVC 1 ±250 Mvar, 400 kV 145,000 145,000 Protection, Metering, Control & Telecoms (LOT) 1 220 kV 1,400 1,400 Construction & Commissioning (LOT) 1 220 kV 2,500 2,500 Total 175,900 Power Lines Baynes-Ruacana 130 4xPelican 400 kV, 130 km 2,763 359,190 Ruacana-Gerus 400 4xPelican 400 kV 400 km 2,763 1,105,200 Gerus-Auas 280 4xPelican 400 kV 280 km 2,763 773,640 Total 2,238,030 ISO 9001 H338829Grand-0000-90 Total-124-0004,3,454,430 Rev. B, Page 155

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Table 6-3 - Transmission Integration Requirements for Baynes Power Station – Option 2 Baynes Hydro 600 MW (2x300 MW) Option 2 Voltage/Length/Rati Unit Cost Total Cost Substation Equipment Number ng (N$ x 1,000) (N$ x 1,000) Baynes Feeder bays 1 400 kV 14,000 14,000 Gen Transformer bays 2 400 kV 12,000 24,000

Bus coupler bays 2 400 kV 9,500 19,000 Total 57,000 Cunene Feeder bays 2 400 kV 14,000 28,000 Transformer bays 2 400 kV 14,000 28,000 400/330 kV Transformers 2 630 MVA 400/330 kV 70,000 140,000

Bus coupler bays 1 400 kV 9,500 9,500 Reactor bays 0 400 kV 10,000 -

Line Reactor 0 400 kV,100 Mvar 18,000 - Busbar Reactor 0 400 kV,100 Mvar 18,000 - Busbars & Busbar VTs (LOT) 1 400 kV 14,000 14,000

Busbar Extension 1 330 kV 4,500 4,500 Feeder bays 1 330 kV 10,000 10,000 Transformer bays 2 330 kV 8,000 16,000 Buscoupler bays 1 330 kV 6,500 6,500 800 MW Voltage HVDC Light Converter Station (VSI) 1 960,000 960,000 Source Inverter Protection, Metering, Control & Telecoms (LOT) 1 400connecting kV & 330 to 330kVkV 14,000 14,000 Substation Civils & Architectural Works (LOT) 1 75,000 75,000 Construction & Commissioning (LOT) 1 65,000 65,000 Total 1,370,500 Omburu Busbar Extension 1 220 kV 1,500 1,500 800 MW Voltage 960,000 HVDC Light Converter Station (VSI) 1 Source Inverter 960,000 Substation Civils & Architectural Works (LOT) 1 connecting to 220 kV 45,000 45,000

Protection, Metering, Control & Telecoms (LOT) 1 400 kV & 220kV 14,000 14,000 Construction & Commissioning (LOT) 1 400 kV 55,000 55,000 Total 1,075,500 Auas Busbar Extension 1 400 kV 3,500 3,500 SVC Bay 1 400 kV 9,500 9,500

SVC 1 ±250 Mvar, 400 kV 145,000 145,000 Total 158,000 Power Lines Baynes-Cunene 130 4xPelican 400 kV, 130 2,763 359,190 km Ruacana-Omburu 1 Refurbishment of line 100,000 100,000 for 350kV DC Total 459,190

Grand Total 3,120,190 ISO 9001 H338829-0000-90-124-0004, Rev. B, Page 156

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Table 6-4 - Summary of Equipment Required for Erongo Coal Power Station Integration

ERONGO (Coal - 2x150 MW) Unit Cost Total Cost Substation Equipment Number Voltage/Length/Rating (N$ x 1,000) (N$ x 1,000) Arandis Feeder bays 3 220 kV 8,000 24,000 Generator bay 2 220 kV 8,000 16,000 Bus coupler bays 2 220 kV 5,500 11,000 Bus section bays 1 220 kV 6,600 6,600 Busbars & Busbar VTs (LOT) 1 220 kV 14,000 14,000 Protection, Metering, Control & 1 220 kV 13,500 13,500 Telecoms (LOT) Substation Civils & 1 220 kV 25,000 25,000 Architectural Works (LOT) Construction & Commissioning 1 220 kV 31,000 31,000 (LOT) Total 141,100 New Khan Feeder bay 1 220 kV 8,000 8,000 Busbar Extension 1 220 kV 1,500 1,500 Protection, Metering, Control & 1 220 kV 1,400 1,400 Telecoms (LOT) Construction & Commissioning 1 220 kV 2,500 2,500 (LOT) Total 13,400 Omburu Feeder bays 1 220 kV 8,000 8,000 Busbar Extension 1 220 kV 1,500 1,500 Protection, Metering, Control & 1 220 kV 1,400 1,400 Telecoms (LOT) Construction & Commissioning 1 220 kV 2,500 2,500 (LOT) Total 13,400 Walmund Feeder bays 1 220 kV 8,000 8,000 Busbar Extension 1 220 kV 1,500 1,500 Protection, Metering, Control & 1 220 kV 1,400 1,400 Telecoms (LOT) Construction & Commissioning 1 220 kV 2,500 2,500 (LOT) Total 13,400 Power Lines

Arandis - New Khan 70 2 x Chickadee 220 kV, OPGW earth w ire, 35 km 1,909 133,630

New Khan - Omburu 120 2 x Chickadee220 kV, OPGW earth w ire 120 km 1,909 229,080

Arandis - Walmund 65 2 x Chickadee 220 kV, OPGW earth w ire, 65 km 1,909 124,085

Total 486,795 Grand Total 668,095

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Table 6-5 - Summary of Equipment Required for the Walvis Bay CCGT Integration

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Walvis Bay CCGT (2x150 MW) Unit Cost Total Cost Substation Equipment Number Voltage/Length/Rating (N$ x 1,000) (N$ x 1,000) Arandis Feeder bays 3 220 kV 8,000 24,000 Generator bay 2 220 kV 8,000 16,000 Bus coupler bays 2 220 kV 5,500 11,000 Bus section bays 1 220 kV 6,600 6,600 Busbars & Busbar VTs (LOT) 1 220 kV 14,000 14,000 Protection, Metering, Control & 1 220 kV 13,500 13,500 Telecoms (LOT) Substation Civils & 1 220 kV 25,000 25,000 Architectural Works (LOT) Construction & Commissioning 1 220 kV 31,000 31,000 (LOT) Total 141,100 New Khan Feeder bay 1 220 kV 8,000 8,000 Busbar Extension 1 220 kV 1,500 1,500 Protection, Metering, Control & 1 220 kV 1,400 1,400 Telecoms (LOT) Construction & Commissioning 1 220 kV 2,500 2,500 (LOT) Total 13,400 Omburu Feeder bays 1 220 kV 8,000 8,000 Busbar Extension 1 220 kV 1,500 1,500 Protection, Metering, Control & 1 220 kV 1,400 1,400 Telecoms (LOT) Construction & Commissioning 1 220 kV 2,500 2,500 (LOT) Total 13,400 Walmund Feeder bays 1 220 kV 8,000 8,000 Busbar Extension 1 220 kV 1,500 1,500 Protection, Metering, Control & 1 220 kV 1,400 1,400 Telecoms (LOT) Construction & Commissioning 1 220 kV 2,500 2,500 (LOT) Total 13,400 Power Lines

Arandis - New Khan 70 2 x Chickadee 220 kV, OPGW earth w ire, 35 km 1,909 133,630

New Khan - Omburu 120 2 x Chickadee220 kV, OPGW earth w ire 120 km 1,909 229,080

Arandis - Walmund 65 2 x Chickadee 220 kV, OPGW earth w ire, 65 km 1,909 124,085

Total 486,795 Grand Total 668,095

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Table 6-6 - Summary of Equipment Required for the INNOWIND Wind Farm Grid Integration Walvis Bay (INNOWIND - 60 MW) Unit Cost Total Cost Substation Equipment Number Voltage/Length/Rating (N$ x 1,000) (N$ x 1,000) INNOWIND Feeder bays 1 220 kV 8,000 8,000 Generator bay 1 220 kV 8,000 8,000 Busbars & Busbar VTs (LOT) 1 220 kV 7,000 7,000 Protection, Metering, Control & 1 220 kV 5,500 5,500 Telecoms (LOT) Substation Civils & 1 220 kV 8,000 8,000 Architectural Works (LOT) Construction & Commissioning 1 220 kV 85,000 85,000 (LOT) Total 121,500 Walmund Feeder bay 1 220 kV 8,000 8,000 Busbar Extension 1 220 kV 1,500 1,500 Protection, Metering, Control & 1 220 kV 1,400 1,400 Telecoms (LOT) Construction & Commissioning 1 220 kV 2,500 2,500 (LOT) Total 13,400 Power Lines

Innow ind - Walmund 45 2 x Chickadee 220 kV, OPGW earth w ire, 45 km 1,909 85,905 Total 85,905 Grand Total 220,805

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Table 6-7 - Summary of Equipment Required for the Diaz Wind Farm Integration

Luderitz (Diaz 44 MW)

Unit Cost Total Cost Substation Equipment Number Voltage/Length/Rating (N$ x 1,000) (N$ x 1,000) Diaz Feeder bays 1 132 kV 2,500 2,500 Generator bay 1 132 kV 2,500 2,500

Busbars & Busbar VTs (LOT) 1 132 kV 2,000 2,000 Protection, Metering, Control & 1 132 kV 3,000 3,000 Telecoms (LOT) Substation Civils & 1 132 kV 2,900 2,900 Architectural Works (LOT) Construction & Commissioning 1 132 kV 3,720 3,720 (LOT) Total 16,620 Koichab Feeder bay 1 132 kV 2,500 2,500 Busbar Extension 1 132 kV 1,000 1,000 Protection, Metering, Control & 1 132 kV 1,100 1,100 Telecoms (LOT) Construction & Commissioning 1 132 kV 1,400 1,400 (LOT) Total 6,000 Power Lines Diaz - Koichab 25 2 x Chickadee 132 kV, OPGW earth w ire, 45 km 1,068 26,700 Total 26,700 Grand Total 49,320

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Table 6-8 - Summary of Equipment Required for Keetmanshoop Solar Grid I Keetmanshoop (Keetsmanshoop Solar 10 MW) Unit Cost Total Cost nSubstation Equipment Number Voltage/Length/Rating t (N$ x 1,000) (N$ x 1,000) Keetmanshoop Solar e Feeder bays 1 66 kV 1,800 1,800 g Generator bay 1 66 kV 1,800 1,800 r Busbars & Busbar VTs (LOT) 1 66 kV 1,700 1,700 Protection, Metering, Control & a 1 66 kV 2,500 2,500 Telecoms (LOT) Substation Civils & t 1 66 kV 2,900 2,900 Architectural Works (LOT) i Construction & Commissioning 1 66 kV 3,720 3,720 o (LOT) n Total 14,420 Keetmanshoop Feeder bay 1 66 kV 1,800 1,800 Busbar Extension 1 66 kV 850 850 Protection, Metering, Control & 1 66 kV 1,100 1,100 Telecoms (LOT) Construction & Commissioning 1 66 kV 1,400 1,400 (LOT) Total 5,150 Power Lines Keetmanshoop - Keetmanshoop solar 5 1 x Rabbit 66 kV, OPGW earth w ire, 5 km 890 4,452 Total 4,452 Grand Total 24,022

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7. Environmental and Social Assessment of Generation Options 7.1 Introduction This section discusses the key environmental and social aspects identified for each of the generation options identified in Section 5.

7.2 Generation Options As discussed in Section 5 the generation options have been divided into primary and secondary options. These options cover a suite of conventional (including coal, oil and gas) and renewable technologies (hydro, wind, solar, biomass, and biofuel) as summarized in Table 7-1.

Table 7-1 - Primary and Secondary Generation Options Identified in the Project

Primary Options Net Unit Capacity Technology Specifics (Quantified resources and mature technology) Coal  150 MW  Coal Fluidized Bed technology  150 MW including green coal (invader bush)  Pulverized coal including flue gas desulphurisation Natural gas  150 MW  Combined Cycle Gas Turbine (CCGT)  400 MW  CCGT  50 MW and 100  Gas turbine (GT) MW Uranium  200 MW  Nuclear  600 MW Fuel oil  20 MW  Diesel (i.e. heavy fuel oil)  150 MW  CCGT (i.e. light fuel oil)  50 MW and 100  GT (i.e. light fuel oil) MW Hydro  71 MW (x 2) +  Baynes 157 MW (x 3) Wind  50 MW  Wind Turbines Solar  10 MW  Solar PV

Secondary Options (Quantified resources but non-mature technology) Uranium  50 MW  Small Modular Reactor  150 MW

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Secondary Options Net Unit Capacity Technology Specifics (Non quantified resources but mature technology) Wind  50 MW  Wind turbines

Solar  10 MW  Photovoltaic Plant  50 MW  Concentrated Solar Plant (CSP) Municipal Solid Waste  5 MW  Steam Turbines  10 MW Biofuel  10 MW  Diesel or Gas Turbines Biomass  10 MW  Invader Bush Hydro  10 MW – 20 MW  Lower Orange River Hydroelectric Stations

7.3 Assumptions and Limitations The following assumptions and limitations apply to the environmental and social assessment of generation options:

 Except for the hydro generation options, no site specific information was available. The identification of potential environmental and social issues was therefore broad- based  In assigning an intensity rating, it was assumed that greenfield sites (undeveloped/untransformed) will be used for the development of the primary and secondary generation options. Should brownfields (developed) sites be utilized, the intensity rating will be reduced. The intensity rating in the assessment methodology can therefore be regarded as conservative  For the generation options that require cooling (i.e. coal, solar CSP, gas etc.) it has been assumed that no preference has been made as to whether wet or dry cooling will be used. Accordingly, the assessment of issues does not address these technology-specific choices. The potential impacts associated with these different issues vary significantly and is discussed further in Section 7.5.1 (Assessment of Generic Issues)  All the generation options will require grid integration via either the transmission or distribution network. The environmental and social issues associated with these power lines have not been assessed  The issues associated with the sourcing of and transportation of the fuel resource to the generation site have not been assessed. This would include the mining required for generation options such as uranium or the piping required for natural gas or liquid fuel transportation

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 Technology specific information was available for some of the generation options; however, for others assumptions were made in terms of what specific technology options will be used: . For hydro it has been assumed that the large plants will have storage and the smaller plants will be run-of-river plants . For concentrating solar power it has been assumed that both parabolic trough technology and tower technology will be considered . For biomass it has been assumed that combustion rather than gasification technologies will be considered  Each generation option will have a suite of similar issues and therefore only issues relevant to a specific generation option have been assessed in terms of their significance. Generic issues have been discussed but no significance rating has been assigned (refer to Table 7-2)  Within a site and project specific context, different issues will have different weightings (e.g. the weighting of potential visual issues may be less important to a development decision than human health concerns). Therefore, although the same significance ratings have been assigned for issues in this report, the true significance of their impact may be considerably different if considered within a specific site and project context  For all of the generation options considered, the application of the Best Available Technology Not Entailing Excessive Cost (BATNEEC) principle was assumed  For all of the issues, application of environmental best practice in the implementation of an Environmental Management Program was assumed.

7.4 Approach The following approach was used to identify and assess the significance of environmental and social issues associated with the primary and secondary generation options:

 Limited literature review of relevant project documentation  An internal workshop was held to identify the range of environmental and social issues associated with each generation option. A broad based approach was used based on the limited information available. The workshop attendees were environmental and social consultants experienced in undertaking assessments of impacts associated with conventional and renewable generation options  An assessment methodology was developed. In terms of the methodology, each generation option was assessed in terms of its status, extent, duration, intensity and probability (refer to Table 7-2). Thereafter the consequence and then the

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significance ratings were assigned (refer to Table 7-3 and 7-4). Each generation option was described with subsections aimed at dealing with specific technology related issues where applicable  Generic issues triggered by either the construction / operational phase across the suite of generation options were discussed qualitatively. No significance ratings were assigned; however where any generic issue is likely to hold more weighting for a specific generation option, this is stated as such and explained  It was not the purpose of the environmental and social assessment to compare the different generation options. Accordingly, the assessment ratings were not assigned in a comparative manner between different generation options and the specifics of existing Namibian environmental legislation were not taken into account  Site specific information is necessary for meaningful consideration of cumulative and residual impact issues. Consequently, these issues were not considered in any detail in the assessment  Some generation options are included in both the primary and secondary categories. For these generation options, only one assessment has been undertaken. However, it should be noted that although the issues are similar, their significance may change with the different scale or specific technology type associated with the primary versus the secondary options.

Table 7-2 explains the extent, duration, intensity, and probability of a potential issue and the different rating scales employed. Table 7-2 - Criteria and Rating Scales

Criteria Rating Scales

Status  Positive; Negative; or Neutral

Extent (the spatial  Local (site-specific and/or immediate surrounding areas); limit) Regional; or National (greater than the region, may include international spatial extent) Duration (the  Short-term (0 to 5 years); Medium term (6 to 15 years); or Long predicted lifetime of term (16 years or more) the impact) Intensity/severity (the  Low - where the impact affects the environment in such a way severity of the that natural, cultural and social functions and processes are impact) minimally affected  Medium - where the affected environment is altered but natural, cultural and social functions and processes continue albeit in a modified way; and valued, important, sensitive or vulnerable systems or communities are negatively affected

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Criteria Rating Scales

 High - where natural, cultural or social functions and processes are altered to the extent that it will temporarily or permanently cease; and valued, important, sensitive or vulnerable systems or communities are substantially affected Probability (the  Improbable – where the possibility of the impact occurring is likelihood of the very low impact occurring)  Probable – where there is a good possibility (<50% chance) that the impact will occur  Highly probable – where it is most likely (50-90% chance) that the impact will occur  Definite – where the impact will occur regardless of any prevention measures (>90% chance of occurring) Table 7-3 uses the above rating scales (excluding probability) to determine the Consequence rating as either Low, Medium, or High.

Table 7-3 - Consequence Rating

Consequence Intensity, Extent and Duration Rating Rating

 High intensity at a regional level and endure in the long term  High intensity at a national level and endure in the medium term  Medium intensity at a national level and endure in the long term HIGH  High intensity at a regional level and endure in the medium term  High intensity at a national level and endure in the short term Consequence  Medium intensity at a national level and endure in the medium

term  Low intensity at a national level and endure in the long term  High intensity at a local level and endure in the long term  Medium intensity at a regional level and endure in the long term  High intensity at a local level and endure in the medium term  Medium intensity at a regional level and endure in the medium term  High intensity at a regional level and endure in the short term MEDIUM  Medium intensity at a national level and endure in the short term Consequence  Medium intensity at a local level and endure in the medium term  Medium intensity at a local level and endure in the long term  Low intensity at a national level and endure in the medium term  Low intensity at a regional level and endure in the long term

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Consequence Intensity, Extent and Duration Rating Rating

 Low intensity at a regional level and endure in the medium term  Low intensity at a national level and endure in the short term  High intensity at a local level and endure in the short term LOW  Medium intensity at a regional level and endure in the short term  Low intensity at a local level and endure in the long term Consequence  Low intensity at a local level and endure in the medium term  Low intensity at a regional level and endure in the short term  Low to medium intensity at a local level and endure in the short term

Table 7-4 uses the Consequence rating assigned from Table 7-3 multiplied by the probability of the issue occurring to give the Significance rating as either Low, Medium, or High.

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Table 7-4 - Significance Rating

Significance Consequence x Probability Rating

 High x Definite HIGH  High x Highly Probable Significance  High x Probable  High x Improbable  Medium x Definite MEDIUM  Medium x Highly Probable

Significance  Medium x Probable

 Medium x Improbable

LOW  Low x Definite  Low x Highly Probable Significance  Low x Probable  Low x Improbable

7.5 Environmental and Social Issues Assessment 7.5.1 Generic Issues Assessment A range of generic issues exist that would typically be associated with the development of any medium to large scale electricity generation facility. These issues typically occur during the construction phase (e.g. loss of habitat through land clearing) but may also occur during the operational phase (e.g. noise and visual impacts). The type of generic issues applicable to the various generation options under consideration is briefly considered hereunder.

Table 7-5 - Generic Issues Assessment

Issue Status Description Biophysical Issues – Construction Phase Biodiversity Negative Flora and fauna may be directly affected through land and ecosystem clearing activities (i.e. loss of individuals) and indirectly services through the loss of habitat, breeding / foraging ground and through habitat fragmentation. This is particularly relevant where large tracts of land are required to be cleared or where large expanses of habitat will be affected (i.e. coal,

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Issue Status Description hydro, solar, biofuel). This impact may be exacerbated where an endangered species is affected. Geology, Negative The underlying geology / parent rock may be affected soils and during construction activities. This is particularly relevant agricultural where excavation / blasting activities are required. potential General construction activities and poor site management may lead to soil erosion / pollution and the creation of dust. The latter will, in turn, have associated health impacts as well as impacts on agricultural activities. Ambient air Negative Construction activities may lead to the proliferation of dust quality due to land clearing, excavation and road usage (i.e. traffic). This will have associated health impacts on construction crews and on local communities in proximity to the construction sites. This is particularly relevant for large scale generation options requiring clearing over large footprints and the construction of numerous roads (i.e. access and internal haul roads). Water quality Negative During construction water quality of groundwater or surface water systems may be affected through increased siltation (i.e. due to soil erosion and run-off), and spillages of pollutants such as hydrocarbons and cement. Siltation/sedimentation can affect the functioning of aquatic ecosystems by burying benthic organisms, obstructing light penetration and interfering with the oxygen absorption of some species. Siltation can also decrease the availability of clean water for human consumption. Aquatic ecosystems may also be directly affected due to the construction of infrastructure within or in proximity to oceans, rivers, wetlands, or watercourses. This may in turn change the functioning of these systems by altering their flow and / catchments. Water Negative During construction, water will be required for, among quantity others, dust suppression and the production of cement. This water is likely to be sourced from groundwater or surface water systems. Abstraction of water from these systems may lead to depletion or draw down which will impact on downstream

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Issue Status Description water users including ecosystems. Biophysical Issues – Operational Phase Biodiversity Negative Flora and fauna may be directly affected through and maintenance activities, disturbance, and mortalities due to ecosystem vehicle or power line/substation interactions, services hunting/poaching activities, increased fire risk, and the proliferation of alien invasive species. Geology, Negative Inefficient storm water management / spills remediation soils and measures / waste storage may lead to continued soil agricultural erosion / pollution. potential In turn this will affect the fauna and flora and the functioning of the ecosystem as well as surrounding agricultural activities. Ambient air Negative Direct impacts will occur through emissions including but quality not limited to:  Particulate matter (dust fraction which may affect human health and agricultural activities).  Sulphur oxides, nitrogen oxides, VOCs (gasses affecting human health)

 Greenhouse gases (SO2, NOx, CO2, and CH4) (these gases have been linked to climate change which has its own suite of environmental issues including changes in temperature and rainfall). This is particularly relevant to any activity emitting at a large scale (e.g. combustion-based generation options, and where local communities live within the area influenced by the generation facility). Water Negative Direct impacts will occur where water is consumed for quantity process purposes. The required volume is likely to be extracted either from ground or surface water systems. Generation options that make use of wet cooling are likely to have a bigger impact than dry or evaporative cooling which require less water. Water abstraction, especially in water scarce areas may impact downstream users / habitats in terms of water availability. Abstraction may also lead to groundwater depletion/drawdown etc. Water quality Negative Disposal of treated process water into the receiving environment may affect the water quality through potential

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Issue Status Description changes in the ambient temperature and chemical composition. Surface or groundwater catchments may be affected due to run-off or seepages of pollutants such as hydrocarbons from fuel storage areas or waste / tailings dams. Poor site management whereby clean and dirty water streams are not kept separated may also lead to surface water pollution. Social Issues – Construction Phase Noise Negative Construction noise may include the use of heavy machinery, vehicles, blasting, excavation and the noise associated with construction crews. The change in noise may affect communities living in sufficiently close proximity to the noise source. Increased noise may lead to changes in ones quality of living. Cultural / Negative Excavation activities as well as the construction of roads heritage may lead to the unearthing of / damage to cultural artefacts. Direct impact will results through the disturbance of the heritage resource itself or the context within which it is found. Influx of job Negative Direct impacts may lead to stress on existing infrastructure seekers and (health, housing, food, and sanitation) due to an influx of construction both authorized construction crews and jobseekers. This crews influx may also threaten existing livelihoods and increase problems associated with debt, disease, poverty and costs of living, and an increase in accidents. Indirect impacts may lead to safety and security issues (domestic violence, rape, crime, breakdown of law and order, and violence), and cultural / political issues (e.g. inter- group jealousies, ethnic tension, vulnerability of marginal groups), due to the increasing population size. Job creation Positive Direct impacts for local communities will result from the and skills creation of primarily unskilled and semi-skilled labour. development Skills development will also directly benefit members of the local communities, both during and after construction. Increased spending in the project area will lead to indirect opportunities from spin-off business opportunities (i.e. accommodation, and recreation). Social Issues – Operational Phase

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Issue Status Description Land use Negative Direct impacts may result from land use compatibility compatibility issues. Available land may no longer be viable for other / loss of land activities (e.g. agriculture). Noise Negative Direct changes in the baseline ambient noise may change due to the introduction of a variety of components such as generators, turbines, substations, power line noise (i.e. corona), cooling facilities, vehicular noise, and maintenance activities in a previously quiet / quieter environment. The change in noise may affect communities living in sufficiently close proximity to the noise source. Increased noise may lead to changes in ones quality of living. Visual Negative Direct impacts result from the potential change in the visual character or aesthetic appeal of an area. This is particularly relevant where an industrial activity is of a large scale or is located in a pristine or undeveloped area. This is often the case for renewable generation options such as wind. Indirect issues may result from socio-economic impacts where the tourism potential of an area is affected. Job creation Positive Direct impacts for local communities will result from the and skills creation of primarily unskilled and semi-skilled labour. development Infrastructure Positive Direct socio-economic impacts will result from the development development of long term access and infrastructure (i.e. sanitation, and education).

7.5.2 Generation Options Issues Assessment 7.5.2.1 Coal The following table identifies and assesses key issues for the generation of electricity using coal. The issues that have been included occur primarily at the operational phase.

Table 7-6 - Issues Assessment Ratings for Coal Generation Options

Issue Extent Duration Intensit Probabilit Significance y y

Biophysical Issues

Large site footprint / land use Local Long Medium Definite High

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Issue Extent Duration Intensit Probabilit Significance y y compatibility (Negative Issue) term The required site footprint is large and includes the area required for the power station itself, roads, water storage dams, ash dams/dumps, and infrastructure associated with cooling (i.e. cooling towers or area required for evaporative cooling fans). Fauna and flora within this footprint will be removed / cleared. As a result, the biodiversity of the area will be affected. Flora will be affected directly as they cannot move; whereas fauna are able to do so. However the loss of foraging, breeding habitat will negatively impact on faunal species. The significance of this loss will increase should endangered species be affected. Sensitive land uses such as residential areas, hospitals and certain agricultural crops are generally not compatible land uses with coal-fired power stations. This generation option can therefore result in restrictions on land use in close proximity to the power plant. Solid and liquid waste (Negative Local Long Medium Definite High Issue) term The primary solid and liquid waste streams are coal ash (bottom ash and fly ash) and wastewater. The fly ash waste stream has high sulphate

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Issue Extent Duration Intensit Probabilit Significance y y and calcium loadings in the leachate as well as other potential trace elements. This leachate can impact on the soil and groundwater. The waste product also remains on site after the lifetime of the plant and the impact is thus long-term in duration. Water released to the natural environment from the cooling process may be warmer than the ambient temperature which may negatively affect aquatic ecosystems. Water Quantity (Negative Issue) Local/ Long Medium Probable High term Large quantities of water are Regional typically required for cooling purposes. This water is likely to be removed from natural surface and/or groundwater resources thereby impacting on downstream users in terms of water availability and potential allocation for other purposes. Once through (i.e. wet cooling) would have a bigger impact than dry or evaporative cooling as lower volumes of water would be required. Atmospheric Emissions (Negative Regional Long Medium Highly High Issue) term probable Human health and agricultural impacts occur through emissions including but not limited to particulates (especially PM10 and PM2.5), sulphur oxides, nitrogen oxides and VOCs.

Greenhouse Gas Emissions (Negative National Long Medium Definite High

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Issue Extent Duration Intensit Probabilit Significance y y

Issue) term Coal-fired power stations generally have a high GHG emission intensity and are regarded as significant contributors to global warming. Carbon budgets, carbon tax and other market-based instruments may have a negative financial impact on this generation option in the future. Social Issues Visual (Negative Issue) Local Long Low Probable Low term The aesthetic appeal of a landscape or viewshed may be affected due to the introduction of large scale infrastructure (i.e. stacks, cooling towers, etc.). This may affect a resident or tourist’s perception of the area which in turn may affect tourism related businesses (i.e. decreased revenue if tourists decide not to visit the area).

7.5.2.2 Natural Gas The following table identifies and assesses key issues for the generation of electricity using natural gas (delivered by pipeline or as LNG) in combined cycle gas turbines and conventional gas turbines. The issues that have been included occur primarily at the operational phase.

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Table 7-7 - Issues Ratings for Natural Gas

Issue Exten Duration Intensit Probability Significance t y

Biophysical Issues Water Quantity (Negative Issue) Local Long Medium Probable Medium term Process water is likely to be removed from natural surface and/or groundwater resources thereby impacting on downstream users in terms of water availability and potential allocation for other purposes. Explosion risk (Negative Issue) Local Short High Improbable Low term There may be an explosion risk associated with LNG. An explosion may cause mortalities or lead to fires. Atmospheric Emissions (Negative Regional Long Medium Probable High Issue) term Human health and agricultural impacts occur through emissions including but not limited to particulates (especially PM10 and PM2.5), sulphur oxides, nitrogen oxides and VOCs. The burning of natural gas emits significantly less carbon dioxide, particulates or sulphur dioxide than coal-fired generation facilities, however it emits nitrogen oxides and carbon monoxide in quantities comparable to coal burning.

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7.5.2.3 Uranium The following table identifies and assesses key issues for the generation of electricity using nuclear technologies (primary and secondary generation options). The issues that have been included occur primarily at the operational phase.

Table 7-8 - Issues Ratings for Uranium

Issue Extent Duratio Intensit Probabilit Significance n y y Biophysical Issues Large footprint / land use Local Long Medium Definite High compatibility (Negative Issue) term The required footprint is large and includes the area required for the power station itself, internal roads, water storage dams, areas required for storage for spent fuel, infrastructure associated with cooling and the area designated to the required exclusion zones. Fauna and flora within this footprint will be removed / cleared. As a result, the biodiversity of the area will be affected. Flora will be affected directly as they cannot move; whereas fauna are able to do so. However the loss of foraging, breeding habitat will negatively impact faunal species. The significance of this will increase should endangered species be affected. Nuclear power stations are required by international standard to have exclusion zones. These exclusion

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Issue Extent Duratio Intensit Probabilit Significance n y y zones therefore result in restrictions on land use in proximity to the power plant. Given their requirement for significant volumes of cooling water, these facilities are often placed along coastlines where tourism and other incompatible land uses are already established. Solid and Liquid Waste (Negative Local / Long Medium Definite High Issue) Regional term Nuclear generation typically has two primary waste streams:  Spent nuclear fuel at the reactor site.  Radioactive isotopes during operation. Radiation (Negative Issue) Local Long Low Probable Low term Although typically low the total amount of radioactivity released depends on the facility, the regulatory requirements, and the plant's performance. Catastrophic failure (Negative Issue) Regional Long High Improbable High term Although safety mechanisms are put in place large scale incidents can occur. This may lead to immediate mortalities or indirect cancer related mortalities or illness due to radiation poisoning. Thereafter the land and a large surrounding buffer will be sterilized to ensure human safety.

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Issue Extent Duratio Intensit Probabilit Significance n y y Social Issues Land use sterilization (Negative Regional Long Medium Definite High Issue) term A buffer zone will be implemented for public safety (i.e. the radius from the plant would likely depend on legislative requirements. This land would effectively be sterilized for other uses. Public perception (Negative Issue) National Medium Medium Definite High term The perception of nuclear amongst the public is generally poor, especially in light of historical nuclear accidents and the most recent incident at the Fukushima Nuclear Power Plant in Japan. This will have knock-on effects in terms of either mobilization of the community against the project, project delays, and risk to the implementation of the project. Visual (Negative Issue) Local Long Low Probable Low term The aesthetic appeal of the landscape may be affected due to the introduction of large scale infrastructure to the visual landscape. This may affect a resident or tourist’s perception of the area which in turn may affect tourism related businesses (i.e. decreased revenue if tourists decide not to visit the area).

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Issue Extent Duratio Intensit Probabilit Significance n y y Decommissioning (Negative Issue) National Long High Definite High term Decommissioning of nuclear reactors and uranium enrichment facilities can be time consuming and potentially hazardous. The area required for storage of the nuclear waste will be sterilized for a long period of time. During this time should any waste leak to the environment this will have significant impacts in terms of human and ecosystem health.

7.5.2.4 Fuel Oil The following table identifies and assesses key issues for the generation of electricity using either light or heavy fuel oil in diesel generators, combined cycle gas turbines, and conventional turbines (primary generation option). The issues that have been included occur primarily at the operational phase.

Table 7-9 - Issues Ratings for Light and Heavy Fuel Oil

Issue Extent Duratio Intensit Probabilit Significance n y y

Biophysical Issues Water quantity (Negative Issue) Local Long Medium Highly Medium term probable Process water is likely to be removed from natural surface and/or groundwater resources thereby impacting on downstream users in terms of water availability and potential allocation for other purposes. Soil and water pollution (Negative Issue) Local Long Medium Probable Medium Large volumes of oil will be required to

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Issue Extent Duratio Intensit Probabilit Significance n y y be stored on site. Furthermore sludge term and oil residues that are not consumed during combustion which contain toxic and hazardous wastes may became a waste burden and this may result in soil, surface water and/or groundwater pollution. Should the oils be washed into streams or rivers etc the quality of the water will be affected thereby impacting on fauna and flora as well as downstream users reliant on the water for drinking purposes. However the significance of this potential impact is low assuming best practice in terms of site management. Atmospheric Emissions (Negative Issue) Regional Long High Definite High term Human health and agricultural impacts occur through emissions including but not limited to particulates (especially PM10 and PM2.5), sulphur oxides, and nitrogen oxides. Heavy metals such as mercury and VOCs (which contribute to ground-level ozone) may all be emitted from the smoke stack of an oil-burning generation facility. Explosion risk (Negative Issue) Local Long High Improbable High term1 There may be a risk associated with the fuel storage facility. An explosion would have impacts in terms of human safety and fire risks. An explosion may cause mortalities or lead to fires.

1 The risk of an explosion will continue for the life of the plant, therefore a rating of long-term has been given.

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7.5.2.5 Hydro The following table identifies and assesses key issues for the generation of electricity using hydro power (primary and secondary generation options). It has been assumed that the hydro scheme will be storage instead of run-of-river. The issues that have been included occur primarily at the operational phase.

Table 7-10 - Issues Ratings for Hydro

Issue Extent Duratio Intensit Probabilit Significance n y y

Biophysical Issues Aquatic ecosystem (Negative Issue) Regional Long High Highly High term probable The establishment of a storage dam will disrupt the natural river flow and introduce high variability in the downstream flow. Downstream areas may experience extreme conditions, and may alternate between being completely dewatered and aquatic fauna / flora being destroyed to having surges of water resulting in erosion and siltation. The change in functionality of the river downstream will affect the associated flora and fauna as the flow and volume of water will become highly erratic thereby disturbing natural growth and reproduction cycles in many species. Inundation (Negative Issue) Local Long High Definite High term Inundation will lead to the direct loss of habitats, agricultural land and potentially cultural resources.

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Issue Extent Duratio Intensit Probabilit Significance n y y Water quality (Negative Issue) Local Medium Low Probable Low Impounding water in a dam can cause variation in temperature or the amount of dissolved gases in the river. Warmer / cooler water released from the dam can affect the habitat, growth rate, or even the survival of fish and other species. The impounding of water in a dam slows the velocity of the water which increases the potential for particulate fallout. Siltation / sedimentation can affect the functioning of aquatic ecosystems by burying benthic organisms, affect fish spawning, obstructing light penetration and interfering with the oxygen absorption of some species. Siltation can also decrease the availability of clean water for human consumption. Atmospheric Emissions (Positive Regional Long Low Improbable Low+ Issue) term Hydro power uses no fuel to operate thereby reducing its carbon footprint. This is important in terms of the suite of issues associated with climate change (e.g. changes in temperature and rainfall patterns). However the carbon input required for construction must be considered. Social Issues

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Issue Extent Duratio Intensit Probabilit Significance n y y Resettlement (Negative Issue) Regional Long High Highly High term probable Communities living in the proposed dam basin will need to be resettled which will have knock on effects socially, economically and culturally. Public resistance (Negative Issue) National Medium High Highly High term probable Primarily due to the need for resettlement and secondarily due to the wide scale loss of habitat, hydro facilities meet with public resistance. Recreational uses (Positive Issue) Local Long Low Probable Low + term Dams may attract people to the area in terms of recreational activities. This may create spin-off opportunities for local communities in term of tourism ventures. Water availability (Positive Issue) Local Long High Definite High + term The establishment of a dam will assist with water availability for surrounding communities. The significance of this is potentially high, especially for communities previously without access to clean water.

7.5.2.6 Wind The following table identifies and assesses key issues for the generation of electricity using wind generator turbines (primary and secondary generation options). The issues that have been included occur primarily at the operational phase.

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Table 7-11 - Issues Ratings for Wind

Issues Extent Duratio Intensit Probabilit Significance n y y

Biophysical Issues Bats/birds (Negative Issue) Regional Long Medium Probable High term During the operational phase wind turbines placed within avian flight paths (particularly flight paths of bird species with large wind spans) may lead to direct mortalities at a large scale. Although this is species and site specific, the potential significance is high especially if endangered species are affected. Bats are directly affected as the low pressure zones created by the turbines leads to barotrauma (i.e. the lungs are affected). Declines in bat populations have a knock-on effect on ecosystems and agriculture as bats play a significant role in terms of pest-control and pollination. Land use compatibility (Positive Local Long Low Highly Low+ Issue) term Probable The overall footprint of the wind turbines and their associated infrastructure is generally small when compared to the extent of land for the entire facility. Therefore agricultural activities can generally continue in conjunction with the power generation. Atmospheric Emissions (Positive Regional Long Low Definite Low+ Issue) term Wind power uses no fuel to operate

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Issues Extent Duratio Intensit Probabilit Significance n y y thereby reducing its human health impacts and carbon footprint. This is important in terms of the suite of issues associated with climate change (e.g. changes in temperature and rainfall patterns). However the carbon input required for construction must be considered. Social Issues Visual (Negative Issue) Regional Long Low Highly Medium term probable The aesthetic appeal may be affected due to the introduction of prominent infrastructure to the visual landscape (i.e. wind turbines). Furthermore wind turbines are often placed along high points of the landscape (e.g. ridges) in order to access the wind resource. As a result the appearance of the turbines is that much more prominent a feature in the landscape. This may affect a resident or tourist’s perception of the area which in turn may affect tourism related businesses (i.e. decreased revenue if tourists decide not to visit the area). For wind turbines placed in too close proximity to homes, this may also cause shadow flicker and/or blade glint. Public perception (Negative Issue) Regional Medium Low Highly Low term probable The public opinion of wind energy

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Issues Extent Duratio Intensit Probabilit Significance n y y facility has worsened due to the potential impacts of these facilities on visually appealing landscapes. This will have knock-on effects in terms of either mobilization of the community against the project, project delays, and risk to the implementation of the project. Aviation issues (Negative Issue) Local Long Low Improbable Low term Conventional wind turbines generally have a hub height of 80 – 120 m. This may cause issues in terms of aircraft collisions and therefore there are stringent legislative requirements that need to be adhered to. One of those requirements is the use of night lighting on every turbine or at least on those turbines on the perimeter of the entire facility. This lighting has knock-on effects in terms of visual issues (i.e. light pollution) especially in undisturbed areas.

7.5.2.7 Solar The following table identifies and assesses key issues for the generation of electricity using solar power (primary and secondary generation options, assuming both photovoltaic and concentrating solar power using either trough or tower technology). The issues that have been included occur primarily at the operational phase.

Table 7-12 - Issues Ratings for Solar

Issue Extent Duratio Intensit Probabilit Significance n y y

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Issue Extent Duratio Intensit Probabilit Significance n y y

Biophysical Issues Land clearing (Negative Issue) Local Long Medium Highly Medium term probable Parabolic trough technology makes use of oils as part of the generation process; this presents a fire risk. Therefore the site needs to be completely cleared of all vegetation, and needs to be maintained as such. As a result, the biodiversity of the area will be affected. Flora will be affected directly as they cannot move; whereas fauna are able to do so. However the loss of foraging, breeding habitat will negatively impact on faunal species. The significance of clearing will be greater where endangered species are affected (i.e. either directly or indirectly). Land use compatibility (Negative Local Long Medium Definite High Issue) term Parabolic trough technology requires the land to be cleared for the duration of the operational phase. As such the land can no longer be used for other purposes such as agriculture. However for some types of PV technology (i.e. concentrating PV which elevates the panels several meters off the ground using pedestals) the land can still be used for some agricultural purposes such as grazing.

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Issue Extent Duratio Intensit Probabilit Significance n y y Soil and water pollution (Negative Local Short Low Probable Low Issue) term Parabolic trough technology makes use of heat transfer fluids and other oils as part of the generation process. Leaks may occur either from the process pipes themselves or from the fuel storage facilities. This may pollute the soil immediately surrounding the leak or may be washed into drainage lines or rivers due to poor storm water management. Furthermore large scale spills from the fuel storage facilities may percolate to groundwater level. Should the oils be washed into streams or rivers, water quality may be affected thereby impacting on fauna and flora as well as downstream users reliant on the water for drinking purposes. Water requirements (Negative Local / Long Medium Probable Medium Issue) Regional term Cooling/cleaning water is likely to be removed from natural surface and/or groundwater resources thereby impacting on downstream users in terms of water availability and potential allocation for other purposes.

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Issue Extent Duratio Intensit Probabilit Significance n y y Atmospheric Emissions (Positive Regional Long Low Improbable Low+ Issue) term Solar power uses no fuel to operate thereby reducing its carbon footprint. This is important in terms of the suite of issues associated with climate change (i.e. changes in temperate and rainfall patterns). However the carbon input required for construction must be considered. Solid Waste Local Long Low Improbable Low term Damaged photovoltaic panels are considered hazardous if broken as they contain small amounts of cadmium, selenium, and arsenic. Waste products from the trough and tower technologies may include the heat transfer fluids and other wastes (i.e. lubricating oils, compressor oils, and hydraulic fluids).

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Issue Extent Duratio Intensit Probabilit Significance n y y Social Issues Visual (Negative Issue) Local Long Low Probable Low term Parabolic trough and tower technology make use of mirrors to reflect the heat energy from the sun onto a receiver. Glare may therefore become an issue depending on the season (i.e. the angle of the sun) and the presence of receptors (i.e. either residents or tourists in close proximity to the facility). Glare, if strong enough, may momentarily blind an individual which may lead to accidents. Aviation (Negative Issue) Local Long Low Improbable Low term The power tower can be ~ 200 m high. This may cause issues in terms of aircraft collisions and therefore there are stringent legislative requirement that need to be adhered to. One of those requirements is the use of night lighting. This lighting has knock-on effects in terms of visual issues (i.e. light pollution) especially in undisturbed areas.

7.5.2.8 Municipal Solid Waste The following table identifies and assesses key issues for the generation of electricity using municipal solid waste for either landfill gas capture or combustion purposes

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(secondary generation option). The issues that have been included occur primarily at the operational phase.

Table 7-13 - Issues Ratings for Municipal Solid Waste

Issue Extent Duratio Intensit Probabilit Significance n y y

Biophysical Issues Atmospheric Emissions (Negative Local Long Medium Definite Medium Issue) term Human health and agricultural impacts occur through emissions including but not limited to particulates (especially PM10 and PM2.5), sulphur oxides, nitrogen oxides and VOCs. Other emissions associated with the incineration of waste include heavy metals and Products of Incomplete Combustion (PICs) which have a carcinogenic risk

Social Issues

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Odour (Negative Issue) Local Long Low Probable Low term The use / incineration of waste may create odour issues (however, this was typically associated with older technologies). Odour issues may affected residents in close proximity to or downwind of the incineration facility and may affect their quality of life. Reduction/utilization of an existing Regional Long Medium Definite High+ waste stream (Positive Issue) term Landfill facilities host a range of environmental issues including increasing land use change, pollution through groundwater contamination, and odour related issues. Therefore the use of an existing waste stream not only makes use of an existing source of energy (thereby “replacing” the need for other fossil fuel) but it also mitigates the need to establish new waste disposal facilities.

7.5.2.9 Biofuel The following table identifies and assesses key issues for the generation of electricity using biofuel (secondary generation option) presumably for the production of bioethanol (from sugar or starch crops) or biodiesel (from vegetable oils or animal fats). The issues that have been included occur primarily at the operational phase.

Table 7-14 - Issues Ratings for Biofuel

Issue Extent Duratio Intensit Probabilit Significanc n y y e

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Issue Extent Duratio Intensit Probabilit Significanc n y y e

Biophysical Issues Large footprint / land use Local Long High Highly High compatibility (Negative Issue) term probable The footprint required for large scale crop production is extensive. This will entail the transformation of either virgin land or existing agricultural land. For the transformation of virgin land, fauna and flora within this footprint will be completely cleared which will affect the biodiversity of the area. Flora will be affected directly as they cannot move, whereas fauna are able to do so; however the loss of foraging, breeding habitat will negatively impact on faunal species. The significance of this will increase should endangered species be affected. The latter refers to the transformation of agricultural land from food crops to fuel crops. Soil erosion (Negative Issue) Regional Long High Highly High term probable Large scale crop plantations and repeated harvesting for biofuel may lead to the disturbance, nutrient leaching or erosion of topsoils. This will have knock on effects for future agricultural plantations (i.e. through the loss of fertile topsoil), and aquatic impacts due to

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Issue Extent Duratio Intensit Probabilit Significanc n y y e sedimentation should topsoil be washed into watercourses. Siltation/sedimentation can affect the functioning of aquatic ecosystems by burying benthic organisms, obstructing light penetration and interfering with the oxygen absorption of some species. Siltation can also decrease the availability of clean water for human consumption. Water requirements (Negative Regional Long High Definite High Issue) term Large volumes of irrigation water are likely to be required for the large scale production of crops. This is highly significant especially in water scarce areas. Abstraction of water from surface or groundwater systems for crop irrigation may affect drinking water availability or availability of water for food crops.

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Issue Extent Duratio Intensit Probabilit Significanc n y y e Atmospheric Emissions (Negative Regional Long Low Improbable Low Issue) term Biofuels do not use fossil fuels to operate thereby reducing emissions in terms of particulates and oxides of sulphur and nitrogen. However it has been postulated that biofuels produce more greenhouse gases than the fossil fuels they replace whilst also removing natural carbon sinks (i.e. grasslands and forests). This has large scale implications for Regional Long Medium Highly High environmental issues including term probable changes in temperature and rainfall patterns associated with climate change.

Social Issues

Food security (Negative Issue) National Long High Probable High term Biofuels require large scale crop production, including crop types that are also important food sources. The use of i) food crops for fuel production or ii) the use of arable land to grow fuel crops may lead to food scarcity which is a highly contentious issue.

7.5.2.10 Biomass The following table identifies and assesses key issues for the generation of electricity using biomass / invasive species (secondary generation option) via combustion rather

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than gasification. The issues that have been included occur primarily at the operational phase.

Table 7-15 - Issues Ratings for Biomass

Issue Extent Duratio Intensit Probabilit Significanc n y y e

Biophysical Issues Soil erosion (Negative Issue) Regional Long High Highly High term probable Biomass plantations and repeated harvesting may lead to the disturbance of topsoil, nutrient leaching or soil erosion. Soil erosion will have knock on effects for future agricultural plantations (i.e. through the loss of fertile topsoil), and aquatic impacts due to sedimentation should topsoil be washed into watercourses. Siltation/sedimentation can affect the functioning of aquatic ecosystems by burying benthic organisms, obstructing light penetration and interfering with the oxygen absorption of some species. Siltation can also decrease the availability of clean water for human consumption.

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Issue Extent Duratio Intensit Probabilit Significanc n y y e Waste (Negative Issue) Local Long Mediu Highly High term m probable The primary waste stream is ash from the incineration process. Releases of this ash to the environment may lead to soil or water pollution. This in turn will have health impacts, impacts on habitats as well as impacts on agricultural potential.

Use of invasive species (Positive Local Long High Definite High+ Issue) term Alien invasive species proliferate as there are no natural enemies to control their growth. As a result they out compete indigenous species for resources (i.e. space, light, water, and nutrients). The removal of alien invasive species will positively impact the local biodiversity. Atmospheric Emissions (Negative Local Long Medium Highly High Issue) term probable Direct impacts will occur through emissions including particulates and oxides of sulphur and nitrogen. Greenhouse gases have been linked to climate change which has its own suite of environmental issues including changes in temperature and rainfall patterns. Perennial biomass plantations may actually act as a carbon sink by

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Issue Extent Duratio Intensit Probabilit Significanc n y y e sequestering carbon.

7.6 Discussion The purpose of this assessment is not to compare the generation options, but rather to provide a broad based initial assessment of the potential environmental opportunities and constraints posed by these technology types. Furthermore, with no site specific information available, no detailed assessment can be made for any of the generation options.

Task 4 will use the above assessment to identify environmental and social risks in order to select the most promising generation scenarios. Each scenario should consider the constraints of the receiving environment, particularly in Namibia with issues pertaining to logistics, water scarcity, and skills shortages. Each scenario should, as applicable, also look to develop sustainable close loop systems (i.e. such as zero liquid effluent discharge systems) which are receptive to the needs of the environment and local communities.

8. Evaluation of the Generation Options This section presents an evaluation of the generation options described in Section 5 including the costs of integrating each of these options into the grid. The main purpose of this evaluation is to identify the options that are clearly not economic and as such should not be included in the formulation of generation expansion scenarios.

Socio economic aspects are not included at this time and will be included as part of the work to be carried out under Task 4, Development and Analysis of Policy Implementation Scenarios, for the generation options that pass the present analysis.

8.1 Least Cost Supply Options The supply options described in Section 5 can be divided into 5 categories, namely:

1. Hydroelectric generation including large and small projects 2. Demand Side Management and energy efficiency projects 3. Base load plants 4. Peaking plants 5. Renewable energy resources, excluding hydro

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At this stage, a reasonable way to compare generation options is to make a comparison of the unit cost of energy produced by each generation option including capital costs, operation and maintenance costs and fuel costs (if any). Socio economic aspects will be considered during Task 4.

Each of the above generation categories has its own peculiarities when comparing the unit cost of energy including life of plant and operating characteristics. The unit cost of energy for each generation category presented in the following subsections harmonizes these parameters such that realistic comparisons can be made.

8.1.1 Unit Cost of Energy for Hydroelectric The generation option presented in Section 5 included 3 hydroelectric plants, Baynes, Kvango and the Orange River plants. Except for Baynes there is little information on the capital cost and energy generated and the information shown in Table 5-5 for those plants is based on our best judgment.

The average energy for Baynes has been estimated at 1,610 GWh per year while the energy for Kavango could be of the order of 98 GWh (assuming a 55% capacity factor) and the energy for the Orange River plants (LOHEPS) could be of the order of 560 GWh (assuming a capacity factor of 63%).

Using the capital costs presented in Table 5-5 it is possible to determine the equivalent annual costs for each plant. Once these are known, the unit cost of energy can be determined and is presented in Table 8-1.

Table 8-1 - Unit Cost of Energy for Hydroelectric Plants

Plant Annual Annual Costs Unit Cost of Energy (N$, million) Energy (GWh) (N$/kWh) Baynes [1] 805 1141.1 1.42 Kavango 98 67.1 0.68 LOHEPS 560 352.4 0.63 Note: [1] Namibia’s share is 50% of the plant’s cost and output

While the unit costs of energy for Kavango and LOHEPS appear attractive, their values are based on our best judgment and considerably more information is needed before considering these plants any further.

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The annual cost for Baynes was determined based on Namibia’s contribution to the generating plant’s cost being 50% and 100% of the transmission cost in Namibia since the Angolan authorities have already expressed that they would like to be supplied from the plant’s substation.

8.1.2 Unit Cost of Demand Side Management and Energy Efficiency Projects Section 5.4 has identified a series of DSM and energy efficiency programs that could potentially be implemented in Namibia to decrease the demand. The costs associated with each of these programs are repeated in Table 8-2 for ease of access:

Table 8-2 - Unit Cost of Energy Savings from DSM and Energy Efficiency Programs

Program Cost (N$/kWh) CFL Roll Out Program 0.071 Residential SWH Dissemination 0.069 C & I SWH Dissemination 0.069 Subsidized Energy Audits 0.131 C & I EE Lighting 0.135 Ripple Control of EWH 4,420[1] C & I Air Conditioning 0.696 Information Dissemination and Public 0.063 Awareness Program Energy Audit – Large Industry 0.050 Note: [1] In N$/kW From the values shown above it appears that several of these programs should be implemented as they offer an economic alternative to either existing or new generation costs. It should be noted that the value shown for the ripple control of electrical water heaters (EWH) in large cities is shown in N$/kW since the peak demand would be reduced while energy consumption would be shifted to outside the peak demand period.

8.1.3 Unit Cost of Energy for Base Load Plants Section 5 presented several generation options that are suitable for base load duty using four fuels; coal, natural gas, petroleum based products and uranium. For each of these fuels there were one or more technologies that could be used. Based on the information provided in Section 5 and the estimated cost of fuels, this section determines the unit cost of energy for each of these options. The combination of technologies and fuels provides us with 10 possible base load plants of different sizes and technologies as shown in Table 8-3 (at the end of this section).

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When determining the unit cost of energy one has to specify the capacity factor and since, at this stage, the amount to be dispatched is unknown, the costs for a range of capacity factors or capacity factors are shown as presented in Table 8-3. Figure 8-1 presents in a graphic form the results in Table 8-3 (in N$/kWh) for selected options while Figure 8-2 presents the cost in N$/kW-Yr which represents the total cost for each kW for a year depending on the number of hours that a unit is operated (the greater number of hours, the larger the number).

Table 8-4 summarises the unit cost of energy for the different fuels and technologies for a capacity factor of 80%.

Table 8-4 - Unit Cost of Energy for Base Load Plants at 80% Capacity Factor Plant Type and Size Fuel Unit Cost of Energy, 80% Capacity Factor (N$/kWh) CFB 300 MW Coal 1.02 PC 300 MW Coal 0.94 CCGT 150 MW NG Market Price 0.91 CCGT 400 MW NG Market Price 0.88 CCGT 150 MW LFO 1.40 CCGT 150 MW NG Economic Price 0.70 CCGT 400 MW NG Economic Price 0.68 Nuclear 200 MW Uranium 1.80 Nuclear 600 MW Uranium 1.59 SMR 50 MW Uranium 2.00 SMR 100 MW Uranium 1.90 MSD (Diesel) 20 MW HFO 1.47 Note: For abbreviations refer to List of Acronyms and Abbreviations

From the above it can be clearly seen that the nuclear options present significantly higher economic costs than the other options. This can also be clearly seen in both Figure 8-1 and Figure 8-2. It should be noted that the costs considered for the nuclear plants do not include the associated transmission which in itself would be substantial.

The results presented in the Tables and Figures also indicate that a CCGT plant using either market prices (75 N$/GJ) or economic prices (46.35 N$/GJ) for natural gas could offer an economic alternative to supply the energy base needs in Namibia and at the same time assist in meeting the targets set in the 1998 Energy Policy White Paper.

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From the values shown in the Tables and Figures, the coal fired units could also present an economic alternative to meet the base energy requirements.

The diesel alternative is more expensive than other generation besides nuclear. It is clear that generation using petroleum based fuels does not provide an economic alternative to produce base load generation.

9 CFB-300 CC-G-150 CC-O-150 CC-E-150 Nuc-600 MSD-20

8 Unit Energy Cost Base Load Generation 7

3 Cost ofUnit Energy (N$/kWh) 2

0 0 10 20 30 40 50 60 70 80 90 100 Capacity Factor (%)

Figure 8-1 - Unit Cost of Energy for Base Load Plants

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14,000 CFB-300 CC-G-150 CC-O-150 CC-E-150 Nuc-600 MSD-20

12,000 Annual Total Cost

10,000

Year)

- 8,000

6,000

Cost (N$/kWUnit 4,000

2,000

0 0 10 20 30 40 50 60 70 80 90 100 Capacity Factor (%)

Figure 8-2 - Total Annual Costs of Base Load Plant

Various generation expansion scenarios will examine the best way to meet the system overall demand considering the generation options best suited to meet the demand.

8.1.4 Unit Cost of Energy for Peaking Plants Gas turbines are usually well suited for peaking duty as are diesel units. Section 5 presented generation options for peaking duty using either natural gas or petroleum products. Based on the information provided in Section 5 and the estimated cost of fuels, this section determines the unit cost of energy for peaking plants. Table 8-5 presents the unit cost of energy for the units and fuels considered.

In this case, it should be noted that peaking plants usually do not operate at annual capacity factors greater than 15 to 25%. As can be seen from the values presented in Table 8-5, the most economic option to meet peak demand would be a 100 MW gas turbine fuelled by natural gas.

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The most realistic alternative to meet peaking requirements, if natural gas is not available, would be a gas turbine using Light Fuel Oil which is shown (in Table 8-5) to be slightly higher in cost than a medium speed diesel using HFO but given the start and stop frequency of the MSDs it is possible that the use of HFO on the MSD would be very restricted and thus the running of the gas turbine would be more economic.

Table 8-5: Unit Cost of Energy for Peaking Plants (N$/kWh)

Plant Gas Turbines HFO Factor 50 MW 100 MW 50 MW 100 MW 50 MW 100 MW Diesel (%) NG Market Price LFO NG Economic Price

5.0 5.39 4.22 6.13 4.96 5.07 3.91 6.00

10.0 3.26 2.63 4.01 3.37 2.94 2.32 3.58 15.0 2.55 2.10 3.30 2.84 2.23 1.79 2.78 20.0 2.20 1.84 2.94 2.57 1.88 1.52 2.37 25.0 1.99 1.68 2.73 2.41 1.66 1.36 2.13 30.0 1.84 1.57 2.59 2.31 1.52 1.26 1.97 35.0 1.74 1.50 2.49 2.23 1.42 1.18 1.86 40.0 1.67 1.44 2.41 2.17 1.35 1.13 1.77 45.0 1.61 1.40 2.35 2.13 1.29 1.08 1.70 50.0 1.56 1.36 2.31 2.09 1.24 1.05 1.65 55.0 1.52 1.33 2.27 2.06 1.20 1.02 1.60

60.0 1.49 1.31 2.23 2.04 1.17 0.99 1.57 65.0 1.46 1.29 2.21 2.02 1.14 0.97 1.54 70.0 1.44 1.27 2.18 2.00 1.12 0.96 1.51 75.0 1.42 1.26 2.16 1.99 1.10 0.94 1.49 80.0 1.40 1.24 2.15 1.97 1.08 0.93 1.47 85.0 1.38 1.23 2.13 1.96 1.06 0.92 1.45 90.0 1.37 1.22 2.12 1.95 1.05 0.91 1.43 95.0 1.36 1.21 2.10 1.94 1.04 0.90 1.42 Note: For abbreviations refer to List of Acronyms and Abbreviations

Figure 8-3 presents in a graphic form the results in Table 8-5 (in N$/kWh) for selected options (100 MW gas turbine units and the MSD) while Figure 8-4 presents the cost in N$/kW-Yr which represents the total cost for each kW for a year depending on the number of hours that a unit is operated (the greater number of hours, the larger the number).

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7 GT-G-100 GT-O-100 GT-E-100 MSD-20

6 Unit Energy Cost Peak Generation

Cost ofUnit Energy (N$/kWh) 2

0 0 10 20 30 40 50 60 70 80 90 100 Capacity Factor (%)

Figure 8-3 - Unit Cost of Energy for Peaking Plants

18,000 GT-G-100 GT-O-100 GT-E-100 MSD-20

16,000 Peaking -- Annual Total Cost 14,000

12,000

Year) -

10,000

8,000

Cost (N$/kWUnit 6,000

4,000

2,000

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Figure 8-4 - Total annual Costs of Peaking Plants

8.1.5 Unit Cost of Energy for Renewable Energy Resources Some types of renewable energies do not lend themselves well for determining unit costs of energy as the capacity factor does not vary (i.e. these plants are not dispatchable in the traditional sense). This is particularly true of wind and solar (both PV and thermal) generation. As such, the unit costs of energy for these technologies are determined in the same manner as that of hydroelectric units. The unit costs for municipal solid waste, biomass and geothermal generation were considered in the same way as for other technologies.

The renewable energy plants under consideration can act almost as a base load plant and as such the unit costs of energy are shown for high capacity factors.

Table 8-6 presents the unit cost of energy for renewable energy plants at various capacity factors. Figure 8-5 presents in a graphic form the results in Table 8-6 (in N$/kWh) for selected options while Figure 8-6 presents the cost in N$/kW-Yr which represents the total cost for each kW for a year depending on the number of hours that a unit is operated (the greater number of hours, the larger the number).

As can be seen from the Figures, municipal solid waste plants do not appear to be competitive with the other renewable energy plants. Both the table and the figures indicate that the biomass plant is more economic than geothermal plants up to capacity factors of some 30%. Given that geothermal is not a proven resource in Namibia and the invader bush resource is well known, generation using this resource is the preferred option in this category. It is also suggested that further investigations of the geothermal potential in Namibia should be pursued by the relevant authorities.

The unit cost of energy for wind and solar generation was determined using the base discount rate and the information shown in tables 5-6, 5-7 and 5-14 (solar thermal power generation) for a range of capacity factors likely to be encountered in Namibia for each of these resources. Since there are no variable generation costs for each resource only the unit cost of energy was determined. Table 8-7 presents the unit cost of energy for wind and solar generation.

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Due to their intermittent generation capability, both wind and solar power plants cannot contribute to system security of supply as many other energy unconstrained generating units since these technologies cannot be counted upon for their capacity when required by the system. It is thus not appropriate to compare the unit cost of energy shown in Table 8-7 with those shown in Table 8-6 since both wind and solar plants do not contribute to the system requirements in the same manner as the units outlined in Table 8-6. For both wind and solar power plants, normally their contribution to the system security, in terms of capacity, is derated by their capacity factor. As an example, should a 100 MW wind power plant have a capacity factor of 25%, then when determining the plant’s contribution to meet the peak demand requirements only 25 MW should be taken into account. However, this is system dependent and in some instances this contribution can be taken as zero particularly if the system peak occurs during low wind periods or at night.

Table 8-6: Unit Cost of Energy for Renewable Energy Plants (N$/kWh)

Plant Municipal Solid Biomass Geothermal Factor Waste

(%) 10 MW 20 MW 5 MW 20 MW 5 MW 20 MW

5.0 27.74 25.79 16.39 13.14 21.57 18.56

10.0 14.41 13.42 8.74 7.08 10.84 9.33 15.0 9.97 9.29 6.19 5.06 7.26 6.25 20.0 7.74 7.23 4.91 4.05 5.47 4.71 25.0 6.41 6.00 4.15 3.44 4.40 3.78 30.0 5.52 5.17 3.64 3.04 3.68 3.17 35.0 4.89 4.58 3.27 2.75 3.17 2.73 40.0 4.41 4.14 3.00 2.53 2.79 2.40 45.0 4.04 3.80 2.79 2.37 2.49 2.14 50.0 3.75 3.52 2.62 2.23 2.25 1.94 55.0 3.50 3.30 2.48 2.12 2.06 1.77 60.0 3.30 3.11 2.36 2.03 1.89 1.63 65.0 3.13 2.95 2.27 1.95 1.76 1.51 70.0 2.98 2.82 2.18 1.88 1.64 1.41 75.0 2.86 2.70 2.11 1.83 1.54 1.32 80.0 2.75 2.60 2.04 1.78 1.45 1.25 85.0 2.65 2.50 1.99 1.73 1.37 1.18 90.0 2.56 2.42 1.94 1.69 1.30 1.12 95.0 2.48 2.35 1.89 1.66 1.23 1.06 Note: For abbreviations refer to List of Acronyms and Abbreviations

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Table 8-7: Unit Cost of Energy for Wind and Solar Generation

Capacity Cost of Energy for Wind and Solar Resources Factor (%) (N$/kWh) Wind Solar PV Solar Thermal 20 1,73 2.42 - 25 1.39 1.94 -

30 1.15 1.61 3.02 35 0.99 - 2.60 40 - - 2.29

30 MSW-20 Biomass-20 GeoT-5 GeoT-20

25 Unit Energy Cost Renewable Generation

Unit Cost Cost ofUnit Energy (N$/kWh)

0 0 10 20 30 40 50 60 70 80 90 100 Capacity Factor (%)

Figure 8-5 - Unit Cost of Energy for Renewable Energy Resources

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25,000 MSW-20 Biomass-20 GeoT-5 GeoT-20

Renewable -- Annual Total Cost 20,000

Year) - 15,000

10,000

Cost (N$/kWUnit

5,000

0 0 10 20 30 40 50 60 70 80 90 100 Capacity Factor (%)

Figure 8-6 - Total Annual Costs of Renewable Energy Resources 8.1.6 Other Resources It is recognized that biofuels form part of the renewable energy component but presently these fuels are used in a mixture with other fuels in certain percentages. Given their present price and the practice of mixing them with other fuels, the unit prices of electricity produced using biofuels were not calculated separately.

8.1.7 Summary of Analysis The previous sections outlined the generation options available to meet the demand in Namibia for the next 20 years. Several resources and technologies have been presented and each has its own characteristics, drawbacks, costs and benefits.

The DSM and energy efficiency programs (with the exception of the commercial and institutional lighting and commercial and institutional air conditioner programs) have a cost of energy far lower than the unit cost of energy from any of the new generation options analysed and it would make good economic sense to implement the DSM and energy efficiency programs.

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The results of the present analysis show that the nuclear options present higher economic costs than the other options even without taking into account the required costs of the associated transmission which in itself would be substantial.

The analysis also showed that if the Kudu gas is priced at an economic price, the resulting unit cost of energy produced by combined cycle generating units (using this gas) would be the most economic way of obtaining base load energy. Market priced gas used on a combined cycle unit also proves unit cost of energy lower than that produced by a coal fuelled CFB or PC plant.

For peaking plant generation, the most suitable technology is simple cycle gas turbines using LFO unless natural gas is available.

Baynes, with a capacity factor of 31%, has a unit cost of energy of 1.42 N$/kWh which is more economic for peaking power than that of a gas turbine using LFO. However, gas turbines can be built in stages and do not require the massive investment at once that Baynes does. The economics of Baynes have thus to be investigated in the entire context of an expansion plan.

Like many other countries in the world, Namibia has a commitment to the implementation of renewable energy projects. Presently both wind and solar PV projects are being negotiated with independent IPPs and the CBEND 250 kW biomass plant will begin service very soon. Other wind and solar projects will be investigated as part of the expansion plans to be developed in Task 4 taking into account the system’s capability to absorb energy limited projects. However, from a technical point of view, biomass fuelled generation can be treated almost as a base load plant and given the social benefits, as well as economic benefits, associated with this type of plant they will certainly play a role in any generation expansion plan.

In summary, the generation options retained to be included in the development of generation expansion plans to meet the demand in Namibia for the next 20 years in a reliable and secure manner include:

 Combined Cycle generation using natural gas (at different prices) to be located at Kudu. A location near Walvis Bay implies the need for import of LNG and building a re-gasification plant which could have a long lead time  A coal plant, initially with 2x150 MW units using CFB technology which allows the use of a variety of fuels  DSM and energy efficiency programs  Baynes hydroelectric project

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 Solar PV plants  Wind Plants  Biomass fired plants  Peaking plants with gas turbines using LFO or natural gas (in case it is available)  Medium Speed Diesels using HFO to meet short term shortfalls

Table 8-8 presents the unit costs of energy for these options.

Table 8-8: Unit Cost of Energy for Options Retained (N$/kWh)

Plant Coal CCGT 400 MW GT Bio- HFO Factor CFB Market Economic LFO Mass Diesel (%) 300 MW Price Price 100 MW 20 MW 20 MW 5.0 7.63 4.74 4.53 4.96 13.14 6.00 10.0 4.10 2.68 2.48 3.37 7.08 3.58 15.0 2.93 2.00 1.79 2.84 5.06 2.78 20.0 2.34 1.65 1.45 2.57 4.05 2.37 25.0 1.99 1.45 1.24 2.41 3.44 2.13 30.0 1.75 1.31 1.11 2.31 3.04 1.97 35.0 1.58 1.21 1.01 2.23 2.75 1.86 40.0 1.46 1.14 0.93 2.17 2.53 1.77 45.0 1.36 1.08 0.88 2.13 2.37 1.70 50.0 1.28 1.04 0.83 2.09 2.23 1.65 55.0 1.22 1.00 0.79 2.06 2.12 1.60 60.0 1.16 0.97 0.76 2.04 2.03 1.57 65.0 1.12 0.94 0.74 2.02 1.95 1.54 70.0 1.08 0.92 0.71 2.00 1.88 1.51 75.0 1.05 0.90 0.69 1.99 1.83 1.49 80.0 1.02 0.88 0.68 1.97 1.78 1.47 ISO 9001 85.0 0.99 0.87 0.66 1.96H338829-00001.73-90-124-1.450004, Rev. B, Page 214 90.0 0.97 0.85 0.65 1.95 1.69 1.43 © Hatch 2012/08 95.0 0.95 0.84 0.64 1.94 1.66 1.42 Note: For abbreviations refer to List of Acronyms and Abbreviations

The World Bank Group & Electricity Control Board of Namibia - National Integrated Resource Plan Planning Parameters and Generation Options Draft Report – 16 July, 2012

Figure 8-7 presents the unit cost of energy for the options retained while Figure 8-8 presents the total annual cost of the generation options retained.

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9 CFB-300 CC-G-400 CC-E-400 GT-O-100 Biomass-20 MSD-20

8 Unit Energy Cost Options Retained

Unit Cost Cost ofUnit Energy (N$/kWh)

0 0 10 20 30 40 50 60 70 80 90 100 Capacity Factor (%)

Figure 8-7 - Unit Cost of Energy for Options Retained

18,000 CFB-300 CC-G-400 CC-E-400 GT-O-100 Biomass-20 MSD-20

16,000 Options Retained -- Annual Total Cost

14,000

12,000 Year) - 10,000

8,000

Unit Cost Cost (N$/kWUnit 6,000

4,000

2,000

0 0 10 20 30 40 50 60 70 80 90 100 Capacity Factor (%)

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Figure 8-8 - Total Annual Costs of Options Retained

8.2 Optimal Mix of Imports and Domestic Sources In order to determine the optimal mix of imports and domestic sources one has to take into account the 1998 Energy Policy requirements and general economics. Table 5-9 provides the cost of likely imports in terms of both capacity and energy but these costs can be expressed as an equivalent unit cost of energy by assuming an 80%capacity factor.

The equivalent costs of energy for the likely imports are:

Import Blended Cost (N$/kWh) Lunsemfwa 0.48 Moropule (non-firm) 0.48 African Energy Resources 0.69

Comparing the blended costs of the Lunsemfwa and African Energy Resources offers with those of base load plants in Namibia suggests that the Namibian system should import as much as possible from these sources without exceeding the Energy Policy requirements. For the Moropule offer one has to compare its costs with the marginal cost of energy of base load plant which for coal is 0.48 N$/kWh. Since the Kudu gas contract is expected to be a take or pay contract with the gas supplier, the marginal cost can be treated as very small. Imports from Moropule on a non-firm basis are not attractive once there is a base load plant in operation in Namibia but is a very economic solution in the short term.

8.3 Next Steps The results of Task 3 as summarized in this report will form the basis of the detailed modeling analysis that will be the focus of Task 4 – Development and Analysis of Policy Implementation Scenarios. The first step in Task 4 will be the preparation of a discussion paper on the proposed set of policy implementation scenarios to use as the starting point for the modeling work.

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Table 8-3: Unit Cost of Energy for Base Load Generation (N$/kWh)

Plant Coal Combined Cycle Uranium HFO Factor CFB PC 150 MW 400 MW 150 MW 150 MW 400 MW Nuclear Nuclear SMR SMR Diesel (%) 300 MW 300 MW NG Market Price LFO NG Economic Price 200 MW 600 MW 50 MW 100 MW 5.0 7.63 6.95 4.88 4.74 5.37 4.66 4.53 26.79 23.45 29.68 28.20 6.00 10.0 4.10 3.75 2.76 2.68 3.25 2.55 2.48 13.46 11.79 14.92 14.18 3.58 15.0 2.93 2.68 2.05 2.00 2.55 1.84 1.79 9.02 7.90 10.00 9.50 2.78 20.0 2.34 2.14 1.70 1.65 2.19 1.49 1.45 6.80 5.96 7.54 7.16 2.37 25.0 1.99 1.82 1.49 1.45 1.98 1.28 1.24 5.47 4.80 6.06 5.76 2.13 30.0 1.75 1.61 1.35 1.31 1.84 1.14 1.11 4.58 4.02 5.08 4.83 1.97 35.0 1.58 1.46 1.25 1.21 1.74 1.04 1.01 3.95 3.46 4.37 4.16 1.86 40.0 1.46 1.34 1.17 1.14 1.66 0.96 0.93 3.47 3.05 3.84 3.66 1.77 45.0 1.36 1.25 1.11 1.08 1.61 0.90 0.88 3.10 2.72 3.43 3.27 1.70

50.0 1.28 1.18 1.07 1.04 1.56 0.86 0.83 2.80 2.46 3.11 2.96 1.65

55.0 1.22 1.13 1.03 1.00 1.52 0.82 0.79 2.56 2.25 2.84 2.70 1.60

60.0 1.16 1.08 1.00 0.97 1.49 0.78 0.76 2.36 2.07 2.61 2.49 1.57

65.0 1.12 1.04 0.97 0.94 1.46 0.76 0.74 2.19 1.92 2.43 2.31 1.54

70.0 1.08 1.00 0.95 0.92 1.44 0.73 0.71 2.04 1.80 2.26 2.15 1.51

75.0 1.05 0.97 0.93 0.90 1.42 0.71 0.69 1.92 1.69 2.12 2.02 1.49

80.0 1.02 0.94 0.91 0.88 1.40 0.70 0.68 1.80 1.59 2.00 1.90 1.47

85.0 0.99 0.92 0.89 0.87 1.38 0.68 0.66 1.71 1.50 1.89 1.80 1.45

90.0 0.97 0.90 0.88 0.85 1.37 0.67 0.65 1.62 1.43 1.79 1.71 1.43

95.0 0.95 0.88 0.87 0.84 1.36 0.65 0.64 1.54 1.36 1.71 1.63 1.42

Note: For abbreviations refer to List of Acronyms and Abbreviations

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