SOUTHERN AFRICA ENERGY PROGRAM MEGA SOLAR WHITE PAPER – DRAFT

March 29, 2019

DISCLAIMER This report is made possible by the support of the American People through the United States Agency for International Development (USAID). The contents of this report are the sole responsibility of Deloitte Consulting LLP and do not necessarily reflect the views of USAID or the United States Government. This report was prepared under Contract Number AID-674-C-17-00002. ACRONYMS

Acronym Definition BEE Black Economic Empowerment BERA Botswana Energy Regulatory Authority BPC Botswana Power Corporation CAGR Compound Annual Growth Rate CSP Concentrating Solar Power DBN Development Bank of Namibia DFI Development Finance Institution DNI Direct Normal Irradiance EAPP East Africa Power Pool ECB Namibia's Electricity Control Board EE Energy Efficiency EPC Engineering, Procurement, and Construction GHI Global Horizonal Irradiance GIPF Government Institutions Pensions Fund GoB Government of Botswana GoN Government of Namibia GW Gigawatts GWh Gigawatt-hour ha Hectares IFC International Finance Corporation IPP Independent Power Producer IRENA International Renewable Energy Association IRP Integrated Resource Plan km kilometers kV kilovolt LCOE Levelized Cost of Energy MW Megawatts NEST Namibia Electricity Support Tariff PA Power Africa PPA Power Purchase Agreement PPP Public-Private Partnership PV Photovoltaic RE Renewable Energy REFIT Renewable Energy Feed-In Tariff REIPPPP South Africa Renewable Energy Independent Power Producer Programme RFP Request for Proposal SAEP Southern Africa Energy Program

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | i SAPP Southern Africa Power Pool SPV Special Purpose Vehicle SRMC Short-Run Marginal Costs US United States USAID US Agency for International Development USG US Government WACC Weighted Average Cost of Capital ZESA Zimbabwe Electricity Supply Authority

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | ii TABLE OF CONTENTS EXECUTIVE SUMMARY ...... 1 1 INTRODUCTION ...... 10 1.1 POWER AFRICA AND THE SOUTHERN AFRICA ENERGY PROGRAM ...... 10 1.2 MEGA SOLAR IN SOUTHERN AFRICA ...... 10 1.2.1 WHAT IS MEGA SOLAR? ...... 10 1.2.2 WHY SOUTHERN AFRICA? ...... 11 1.3 PURPOSE OF THIS DOCUMENT ...... 12 1.3.1 CONCEPT STUDY APPROACH ...... 12 2 COUNTRY AND SITE ANALYSIS ...... 14 2.1 SAPP COUNTRY ANALYSIS ...... 14 2.1.1 BOTSWANA AND NAMIBIA ENERGY SECTORS ...... 15 2.2 MEGA SOLAR SITE ANALYSIS ...... 15 2.2.1 BOTSWANA MEGA SOLAR SITES ...... 16 2.2.2 NAMIBIA MEGA SOLAR SITES ...... 17 3 ECONOMIC ANALYSIS ...... 19 3.1 LEVELIZED COST OF ENERGY ANALYSIS ...... 19 3.1.1 CURRENT STATE OF ENERGY LCOE ...... 19 3.1.2 CONDITIONS FOR LOW-COST SOLAR IN BOTSWANA AND NAMIBIA ...... 21 3.1.3 SITE-SPECIFIC LCOE ESTIMATES FOR PV AND CSP ...... 21 3.2 ENERGY SECTOR ECONOMIC ANALYSIS ...... 22 3.2.1 BOTSWANA ENERGY SECTOR ANALYSIS ...... 22 3.2.2 NAMIBIA ENERGY SECTOR ANALYSIS ...... 22 3.2.3 JOB CREATION IMPACT ...... 23 4 DEMAND ANALYSIS ...... 25 4.1 DEMAND ANALYSIS APPROACH ...... 25 4.1.1 CALCULATING ADDRESSABLE DEMAND ...... 25 4.1.2 DATA INPUTS AND ASSUMPTIONS ...... 27 4.2 DEMAND ANALYSIS FINDINGS ...... 29 4.2.1 ADDRESSABLE DEMAND ...... 29 4.2.2 TRANMISSION CONSIDERATIONS ...... 30 4.2.3 GENERATION COST CONSIDERATIONS ...... 31 4.2.4 SCALING MEGA SOLAR TO MEET ADDRESSABLE DEMAND ...... 33

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | iii 5 SUCCESS CONDITIONS ANALYSIS ...... 35 5.1 SUCCESS CONDITIONS CATEGORIES ...... 35 5.2 COUNTRY ANALYSIS ...... 36 5.3 BOTSWANA...... 37 5.4 NAMIBIA ...... 39 5.4.1 RENEWABLE ENERGY INTEGRATION IN NAMIBIA ...... 43 5.4.2 MEETING LOCAL CONTENT IN NAMIBIA ...... 43 6 POTENTIAL PROGRAM STRUCTURE ...... 45 6.1 PROGRAM STRUCTURE FRAMEWORK ...... 45 6.2 POTENTIAL BOTSWANA PROGRAM STRUCTURE ...... 46 6.3 POTENTIAL NAMIBIA PROGRAM STRUCTURE ...... 47 CASE STUDIES ...... 48 A.1 UPINGTON SOLAR PARK, SOUTH AFRICA ...... 48 OVERVIEW ...... 48 LEADING PRACTICE ANALYSIS ...... 49 A.2 CERRO DOMINADOR, CHILE ...... 49 OVERVIEW ...... 50 LEADING PRACTICE ANALYSIS ...... 50 FINANCIAL ANALYSIS ...... 51 A.3 SOLAR START PROJECTS, USA ...... 52 OVERVIEW ...... 52 LEADING PRACTICE ANALYSIS ...... 52 FINANCIAL ANALYSIS ...... 53 A.4 NOOR POWER PROJECT, MOROCCO ...... 54 OVERVIEW ...... 54 LEADING PRACTICE ANALYSIS ...... 55 FINANCIAL ANALYSIS ...... 57 A.5 SHAKTI STHALA SOLAR PARK, INDIA ...... 58 OVERVIEW ...... 58 LEADING PRACTICE ANALYSIS ...... 59 FINANCIAL ANALYSIS ...... 60 A.6 LONGYANGXIA DAM SOLAR PROJECT, CHINA ...... 61 OVERVIEW ...... 61

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | iv LEADING PRACTICE ANALYSIS ...... 61 – DETAILED DEMAND ANALYSIS ...... 64 B.1 ANGOLA ...... 64 B.2 BOTSWANA ...... 65 B.3 DRC ...... 66 B.4 ESWATINI ...... 67 B.5 LESOTHO ...... 68 B.6 MALAWI ...... 69 B.7 MOZAMBIQUE ...... 70 B.8 NAMIBIA ...... 71 B.9 SOUTH AFRICA ...... 72 B.10 TANZANIA ...... 73 B.11 ZAMBIA ...... 74 B.12 ZIMBABWE ...... 75 – TRANSMISSION ANALYSIS DATA ...... 76 C.1 LETLHAKANE, BOTSWANA ...... 76 C.2 JWANENG, BOTSWANA ...... 79 C.3 GERUS, NAMIBIA ...... 82 C.4 KOKERBOOM, NAMIBIA ...... 83 C.5 ARANDIS, NAMIBIA ...... 84

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | v LIST OF TABLES Table 1: Botswana Site Analysis ...... 2 Table 2: Namibia Site Analysis ...... 3 Table 3: LCOE of PV and CSP in Botswana and Namibia Sites ...... 4 Table 4: Success Conditions Overview ...... 6 Table 5: Potential Mitigation Options for Consideration in Mega Solar Program Design ...... 7 Table 4: LCOE of PV and CSP in Botswana and Namibia Sites ...... 21 Table 5: Namibia Electricity Support Tariff ...... 23 Table 6: Comparison of Potential Demand Analysis Approaches ...... 26 Table 7: 2017 SAPP Pool Plan Component Assumptions ...... 28 Table 8: SAPP Forecasted Peak Demand Growth, 2020-2040 ...... 28 Table 9: SAPP Addressable Demand (MW), 2020-2040 ...... 29 Table 10: SAPP Addressable Demand (MW) with Namibia and Botswana Transmission Constraints, 2020-2040 ...... 30 Table 11: Success Conditions Overview ...... 36 Table 12: Botswana Detailed Success Conditions Analysis ...... 37 Table 13: Namibia Detailed Success Conditions Analysis ...... 39 Table 14: Financial Position of Cerro Dominador Stakeholders ...... 51 Table 15: Financial Position of Solar Star Stakeholders ...... 53 Table 16: Noor Project Funding ...... 56 Table 17: Financial Position of Noor Stakeholders ...... 57 Table 18: Pavagada Solar Park Charges ...... 59 Table 19: Pavagada Solar Projects by Private Developer Bid ...... 59 Table 20: Financial Position of Shaki Sthala Stakeholders ...... 60

LIST OF FIGURES Figure 1: Addressable Regional Demand, 2025 - 2040 ...... 5 Figure 2: Illustrative Mega Solar Program Development Phases ...... 6 Figure 3: Program Structure for Mega Solar in Botswana ...... 9 Figure 5: Mega Solar Programs Around the World ...... 11 Figure 6: GHI and DNI Levels in SAPP Countries ...... 14 Figure 7: Botswana and Namibia Generation Capacity ...... 15 Figure 8: Potential Mega Solar Sites in Botswana ...... 16 Figure 9: Potential Mega Solar Sites in Namibia ...... 17 Figure 10: 2018 LCOE Range Estimates ...... 19 Figure 11: Tariff Price Reductions for Phased Procurements ...... 20 Figure 12: WACC Sensitivity Analysis ...... 21 Figure 13: Job Creation Estimates ...... 23 Figure 14: Example Zambia Medium-Term Addressable Demand Calculation ...... 27 Figure 15: Forecasted Short-Run Marginal Costs ...... 32 Figure 16: Forecasted SAPP Import / Export Balance (GWh) ...... 32 Figure 17: South Africa Annual Coal Decommissioning (GW) ...... 33 Figure 18: Illustrative Mega Solar Program Development Phases ...... 34 Figure 19: Program Structure for Mega Solar in Botswana ...... 46

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | vi Figure 20: Program Structure for Mega Solar in Namibia ...... 47 Figure 25: Proposed Site for the Upington Solar Park ...... 48 Figure 26: Cerro Dominador Solar Project ...... 50 Figure 27: Solar Star PV Station ...... 52 Figure 28: Graphical Representation of Noor I-IV ...... 54 Figure 29: Noor Project Structure ...... 55 Figure 30: Blocks of Shaki Sthala Solar Park ...... 58 Figure 31: Aerial View of Longyangxia Dam ...... 61

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | vii EXECUTIVE SUMMARY The US Government launched Power Africa (PA) in June 2013 to leverage partnerships between United States (US) federal agencies, African governments, donor and development partners, and the private sector to improve access to electricity and accelerate energy transactions. PA aims to increase generation capacity by 30,000 megawatts (MW) and add 60 million new electricity connections by 2030. Today, PA has over 160 public and private partners and has made strong progress toward its goals. The U.S. Agency for International Development (USAID) is a major PA partner and the USAID Southern Africa Energy Program (SAEP) is one of several PA regional programs. SAEP focuses on increasing investment in electricity supply and access in Southern Africa by strengthening the regional enabling environment and facilitating transactions. At the request of the PA Coordinator, SAEP conducted a three-month concept stage analysis (“concept study”) for a mega solar program—a 2 – 5 GW multi- phased solar procurement program—in Southern Africa. The concept study evaluated the high-level feasibility of the program, potential host countries and sites, and the conditions and technical assistance needed to move the program forward. MEGA SOLAR IN SOUTHERN AFRICA Solar technology costs have fallen dramatically in the last decade and storage technology has improved making it possible for countries to harness solar resources to provide reliable, lower-cost energy to meet increasing demand and offset more expensive and less reliable conventional generation. Several countries have planned and implemented mega solar initiatives and multi-phased renewable procurement programs, like the South Africa Renewable Energy Independent Power Producer Programme (REIPPPP), that create economies of scale in procurement and drive down prices. As a result, these programs are able to bring online photovoltaic (PV) and concentrating solar power (CSP) projects at very low prices—often below 5c/kWh and 10c/kWh, respectively. Southern Africa has world-class solar resources and is well-positioned to host a multi-phased mega solar procurement program that brings online large-scale PV and CSP plants. South Africa’s REIPPPP and the World Bank Scaling Solar program have shown that lower solar prices are possible in sub-Saharan Africa and both programs have created procurement leading practices that a mega solar program can leverage. Southern Africa, through the Southern Africa Power Pool (SAPP), is also shifting towards an integrated, regional power system which creates the potential for a mega solar program to export low-cost power to other nearby countries and even throughout the continent. COUNTRY AND SITE ANALYSIS The concept study evaluated each country in Southern Africa and determined that Botswana and Namibia are the ideal host countries for a mega solar program. The study also identified several sites within each country that are optimized for the development of large-scale solar resources. POTENTIAL MEGA SOLAR HOST COUNTRIES The concept study determined that Botswana and Namibia have high solar availability, good land availability, and a supportive legal/regulatory environment, each of which is critical for the success of a mega solar program. Botswana and Namibia have among the highest direct normal irradiance (DNI) and global horizontal irradiance (GHI) potential of any country in Africa—two important measures of solar potential that are used to estimate the productivity of CSP and PV technology, respectively. In addition, PV and CSP installations require large amounts of relatively flat land. Both countries also have large amounts of land without human settlements or productive economic activity.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 1 Botswana and Namibia have relatively strong legal and regulatory environments that will encourage investors and project developers to participate in a large-scale competitive procurement program. Both score high, relative to other countries in Southern Africa, on the Corruption Perception Index and the Government of Botswana has the strongest credit rating in Africa. Namibia has cost-reflective electricity tariffs, which indicates the utility and developers have visibility into the true cost of supplying electricity. The current state of Botswana and Namibia’s energy sectors also present an opportunity for mega solar to improve generation reliability and reduce costs. Both countries rely heavily on imports from the SAPP market and Eskom to meet domestic electricity consumption. Poor reliability of existing generation assets forces both countries to purchase expensive emergency power at a high cost to the utility and expose both countries to regional supply disruptions. This is primarily due to low availability of existing generation assets.

POTENTIAL MEGA SOLAR SITES The concept study evaluated five sites for development under a mega solar program—two in Botswana and three in Namibia. Each site previously analyzed by the International Renewable Energy Association (IRENA) under the Clean Energy Corridor Initiative. The concept study analyzed IRENA site data including solar potential, land availability, and transmission access and routes. The study found that each site has minimum DNI and GHI levels of 2000 kWh/m2/year, has significant land availability within 5km of the nearest substation, and each site is in close proximity to a transmission line and substation with sufficient capacity to evacuate power to load centers.

Botswana Mega Solar Sites The two sites identified in Botswana were Jwaneng and Lethakane. Table 1 below depicts the major site analysis characteristics considered under the concept study. Table 1: Botswana Site Analysis

Site Selection Botswana Criteria Jwaneng Letlhakane DNI: 2700 DNI: 2400 Solar Potential GHI: 2150 GHI: 2200

Land Availability 2,788 hectares 2028 hectares

Transmission Jwaneng substation; Orapa 1 and 2 Access and 132kv line to substations; 200kv line Routes Gaborone to Selebi Phikwe

Namibia Mega Solar Sites The three sites identified in Namibia were Gerus, Arandis, and Kokerboom. Table 2 below depicts the major site analysis characteristics considered under the concept study.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 2 Table 2: Namibia Site Analysis

Site Selection Namibia Criteria Gerus Arandis Kokerboom

DNI: 2700 DNI: 2800 DNI: 3000 Solar Potential GHI: 2300 GHI: 2400 GHI: 2300

Land Availability 2,041 hectares 785 hectares 2,356 hectares

Transmission Gerus substation; Rossing substation; Kokerboom Access and Zambezi Link to 200kv line to Walvis substation; 400kv line Routes Zambia Bay to Windhoek

ECONOMIC ANALYSIS Solar energy from a mega solar program would be less expensive and more reliable than imported and peak generation, both of which Namibia and Botswana rely on heavily to meet domestic demand. DECLINING SOLAR PRICES Conventional energy sources (e.g., coal and gas) have historically had lower levelized costs of energy (LCOEs) than solar sources. However, due to improvements in technology and supportive regulatory regimes, solar energy prices have declined significantly, making solar energy a more attractive base load generation source. A 2017 IRENA report found that the average auction prices for PV and CSP coming online in 2019 were 6c/kWh and 10c/kWh, respectively, bringing solar prices in line with conventional energy generation sources. Advancements in storage technology, including utility-scale batteries and CSP thermal energy storage, now enable utilities to balance the intermittent nature of PV, which has historically limited the development of solar resources. CSP storage, in particular, has benefitted from cost reductions, allowing solar procurement programs throughout the world to take advantage of its ability to store solar energy during the day and dispatch at night or during peak times. CSP developments like Australia’s Aurora plant, Chile’s Copaipo plant, and Dubai’s Dewa plant, have used storage capabilities to provide low-cost power at night or during peak hours. Large-scale, multi-phased solar procurement programs have also been shown to drive price reductions with PV and CSP prices falling across successive procurement rounds. The REIPPPP program saw the cost of CSP decrease by 42 percent and the cost of PV decrease by 83 percent over its five bid windows. Many developers see multi-phased procurement programs as long-term investments and decide to submit low bid prices in order to capture large, stable revenue streams. The long-term timelines and large project footprints enable developers to take advantage of robust local supply chains that further reduces costs compared to single projects. Most importantly, phased procurements build confidence in developers and financiers who are evaluating a market for the first time. As they see successful projects come online they are able to reduce risk premiums and lower prices. This results in more attractive financing terms and increased competition from developers.

SITE-SPECIFIC LCOE ESTIMATES FOR PV AND CSP For each of the five sites, the study estimated the LCOE of PV and CSP based on the maximum plant sizes. In these calculations, the study made the following assumptions:

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 3 • 9.5 percent weighted average cost of capital (WACC) • 35-year power purchase agreement (PPA), providing developers a longer period to recover costs • Eight-hour storage for CSP Table 3 below depicts LCOE estimates for PV and CSP at each site. As a reference, it includes the potential maximum plant sizes by technology type based on the amount of available land within 5km of the closest transmission substation. Table 3: LCOE of PV and CSP in Botswana and Namibia Sites

Botswana Namibia Sites Jwaneng Letlhakane Gerus Arandis Kokerboom LCOE CSP: 10.0c/kWh CSP: 10.3c/kWh CSP: 11.7c/kWh CSP: 11.5c/kWh PV: 6.1c/kWh Estimates PV: 5.3c/kWh PV: 5.3c/kWh PV: 6.1c/kWh PV: 6.0c/kWh Max Plant 664 MW CSP 483 MW CSP 486 MW CSP 187 MW CSP 561 MW CSP Sizes 845 MW PV 614 MW PV 619 MW PV 238 MW PV 714 MW PV

ENERGY SECTOR ECONOMIC IMPACT A mega solar program will harness large-scale, low-cost solar energy to improve energy reliability in the host country, meet unmet and latent demand for electricity that will power new industrial activity, and create both temporary and permanent jobs. A mega solar program will improve energy reliability in the host country. Both Namibia and Botswana’s energy sectors are characterized by heavy reliance on expensive emergency imports as well as a dependence on outdated, expensive, and unreliable thermal energy. This creates an unclear price path for long-term energy planning and threatens the fiscal position of the utilities, which often must make expensive emergency power purchases to offset unreliable energy generation. In Namibia, the Ruacana power station makes up more than 90 percent of the country’s installed generation capacity and it is dependent on the flow of the Kunene River. Ruacana only operates during wet seasons, from February to May, and as climate change and droughts worsen, Namibia receives less and less energy from Ruacana. It is forced to cover this shortfall with expensive emergency generation and imports from the SAPP day ahead market. Botswana’s energy sector is heavily dependent on coal-fired plants, which are challenged with poor reliability. Morupule B, the 600 MW plant, is currently only 25 percent available due to structural defects and construction timelines for repairs are unclear. As a result, Botswana Power Corporation (BPC) must rely on imports for nearly half of domestic energy needs. A mega solar program will power industrial activity. Botswana and Namibia have existing industrial activity that could benefit from reliable energy sources. In addition, reliable power can meet unmet and latent demand for electricity that could drive new industrial activity. In Namibia, there is high demand for power in the desalination, manufacturing, and smelting industries. Reliable, low-cost power could not only improve productivity for existing companies, but also create opportunities for new energy-intensive industries. In Botswana, mining comprises the majority of domestic industrial activity. The mining sector needs a steady, reliable source of power to support 24-hour operations and, since domestic generation assets cannot supply that, many mines rely on direct PPAs with foreign utilities, such as Eskom. Reliable solar

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 4 energy through the mega solar program could reduce energy import costs for the mining industry and improve productivity. A mega solar program will create temporary and permanent jobs. Developing solar generation creates temporary and permanent jobs through construction, operations, and maintenance. The concept study analyzed six large PV and size large CSP REIPPPP projects to generate an estimate of the average number of jobs created per MW of each solar technology type, weighted by the capacity of each project. The concept study estimated that the development of a 275 MW PV and 500 MW CSP plant could create 27,000 temporary jobs and 857 permanent jobs. DEMAND ANALYSIS SAPP is driving the creation of a regional power market and the strengthening of transmission interconnections among market participants. This move toward a unified power market, as well as the growing demand for power throughout Southern Africa, creates an opportunity for a mega solar program to export power throughout the region. This study concludes that there could be up to 23.9 GW of unmet demand in the region by 2040. Figure 1 below shows the unmet demand in each of the SAPP countries for different time horizons. The addressable demand for each country was calculated by analyzing the gap between the peak capacity provided by exisiting and committed generation project and the forecasted peak demand levels in each country, as provided in the 2017 SAPP Pool Plan. Candidate generation projects were not considered in the demand analysis since many are in early development phases. Figure 1: Addressable Regional Demand, 2025 - 2040

A SCALED APPROACH TO MEGA SOLAR The demand analysis found that a mega solar program can supply power to a number of load centers in the Southern Africa region. In order to achieve reduced risk premiums for project developers and more closely align with growing addressable demand in the medium to long-term, the program should take a phased approach that scales generation capacity in the medium and long-term. Figure 2 provides an illustrative overview of this type of approach, beginning with meeting domestic demand, expanding to supplying regional load centers, and finally integrating with other power pools across the continent.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 5

Figure 2: Illustrative Mega Solar Program Development Phases

SUCCESS CONDITIONS ANALYSIS The success of a mega solar program in Botswana or Namibia will depend on the presence of institutional and regulatory conditions required to support a large solar power procurement program. The concept study identified seven success conditions for such a program and analyzed both countries’ enabling environments to determine whether each condition is currently present, could be present given the right support, or is unlikely to be present. As shown in Table 4, the analysis concluded that three of the seven success conditions are currently present in Namibia, while only one is present in Botswana. Table 4: Success Conditions Overview

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 6 Despite gaps in each country’s enabling environment, the concept study determined that all of the required conditions could ultimately be achieved using mitigation tactics that have been employed by large procurement programs in other parts of the world. Table 5 highlights these potential mitigation options in Botswana and Namibia, which should be considered in the design of the mega solar program. Table 5: Potential Mitigation Options for Consideration in Mega Solar Program Design

Potential Mitigation Options Condition Botswana Namibia

• Stand up an independent procurement • Establish an IPP Office at the Ministry of Ability to execute entity Minerals and Energy large procurements • Provide capacity building • Provide capacity building

• Provide procurement process support • Review and optimize the special purpose Ability to support vehicle (SPV) registration process independent power • Develop a cost-reflective tariff producers (IPPs) • Ensure increased local ownership by • De-risk the PPA Previously Disadvantaged Groups

• Obtain high-level political support Support from • Obain high-level political support development finance • Build confidence in program institutions (DFIs) • Build confidence in program • Apply similar project structure as REIPPPP

Supportive national • Use de-risking instruments financing • Use currency risk mitigation products environment • Structure flexible procurement terms

• Declare the project a National Priority Ability to obtain land • NamPower should manage land acquisition for private projects • Ministry of Lands should provide state- prior to the tender owned land for project development

• De-risk utility offtake • De-risk utility offtake History of purchasing power from IPPs • Explore potential for Debswana to serve • Scale up practices that were successful as the offtaker under REFIT Programme

• Clear regulations and SAPP participation Ability to export • Clear regulations and SAPP participation • Upgrade domestic network leading to electricity • Upgrade interconnection points interconnection poins

The final component of the success conditions analysis examined two additional challenges for the implementation of mega solar in Namibia that were raised during discussions with local stakeholders. First, a recent study commissioned by Namibia’s Electricity Control Board (ECB) includes a series of recommendations that would limit the total capacity, plant size, and transmission of power from variable renewable energy projects connected to the national grid to minimize the negative impact on system stability and technical losses. While a mega solar program that produces firm power using CSP technology should not be subject to these constraints, it will be important to consider the implications of this study in greater detail and investigate grid stabilization solutions that could be used to support large-scale renewable energy integration. Second, Namibian law currently requires 30 percent local equity for public-private partnerships (PPPs), which several Namibian REFIT projects have struggled to obtain. During the concept study, the Development Bank of Namibia (DBN) and the Government Institutions Pension Fund (GIPF) both

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 7 indicated that they could provide financial and institutional support to the program to help it achieve this threshold if the program were prioritized by government. Additionally, local financiers and the Renewable Energy Industry Association of Namibia expressed conceptual support for a national investment fund that would pool equity investments for power programs such as mega solar. Both of these options should be explored further as part of the mega solar program’s pre-feasibility assessment. PROGRAM STRUCTURE A mega solar program benefits from a defined program structure with clear procurement rules. The concept study used the analysis of success conditions in Botswana and Namibia to determine a program structure framework as well as outline how a mega solar program could be structured in Botswana or Namibia. PROGRAM STRUCTURE FRAMEWORK The concept study developed a general project structure framework that builds on leading practices from other mega solar programs. This consists of:

• Independent Procurement Entity. The independent procurement entity will be established by the government and will oversee the entire procurement process. The government mandate for these entities will also enable them to serve as intermediaries with development banks to bear some of the development or financial risk during the early phases of the program. • Phased Program Structure. Since Botswana and Namibia have not yet had large-scale solar programs, a phased approach will allow it to build investor confidence in the success of the program. • Multiple Project Owners through Competitive Procurements. Competitive procurements will attract a wide range of qualified vendors and keep project prices low. • Financing Arrangements. During the initial phases, the procurement authority could secure and package concessional financing from DFIs. Previous procurement programs, including REIPPPP, have seen higher prices during initial phases as developers price in risk premiums to account for uncertainty. Concessional financing helps reduce prices during these early phases. The government-mandated procurement entity could back these loans on behalf of the government. In the later phases of the program, there will be a shift from concessional financing to private financing secured directly by the developers. • Land Arrangements. The government will provide land for solar development during the initial phases to incentivize developers and eliminate the costly burden of developers securing land themselves. BOTSWANA PROGRAM STRUCTURE The Botswana program structure incorporates each of the provisions of the program structure framework above. Since Botswana does not currently have a procurement entity with the capacity to support large-scale renewable energy procurements, the government should establish one either within BPC or the Ministry of Energy. Figure 3 shows the program structure for a mega solar program in Botswana.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 8 Figure 3: Program Structure for Mega Solar in Botswana

NAMIBIA PROGRAM STRUCTURE The Namibia program structure similarly follows the program structure framework. The Ministry of Mines and Energy’s IPP Office already oversees all procurements and should oversee and approve all mega solar procurements as well. The program is required by Namibian law to have a SPV for IPPs to ensure that there is 30 percent local equity in the program. Error! Reference source not found. shows the program structure for a mega solar program in Namibia.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 9 1 INTRODUCTION 1.1 POWER AFRICA AND THE SOUTHERN AFRICA ENERGY PROGRAM Power Africa (PA) was launched in June 2013 by the United States Government (USG) to leverage partnerships between United States (US) federal agencies, African governments, donor and development partners, and the private sector to improve access to electricity and accelerate energy transactions. PA aims to increase generation capacity by 30,000 megawatts (MW) and add 60 million new electricity connections by 2030. Today, PA has over 160 public and private partners and has made strong progress toward its goals. The US Agency for International Development (USAID) is one of the key PA partners and the USAID Southern Africa Energy Program (SAEP) is a part of the suite of PA initiatives. SAEP kicked off in March 2017 and focuses on increasing investment in electricity supply and access in Southern Africa by strengthening the regional enabling environment and facilitating transactions. SAEP addresses five key constraints to energy sector investment, including (1) ineffective regulation, planning and procurement for energy, (2) low commercial viability of utilities, (3) limited regional harmonization and cross border electricity trade, (4) lack of demonstrated and scaled clean and renewable energy (RE) and energy efficiency (EE) technologies and practices, and (5) weak institutional and human resource capacity for energy sector management. Over the course of the program, SAEP will contribute to PA goals by adding: • 3,000 MW of new power generation • 1,000 MW of new transmission capacity • 3 million new connections 1.2 MEGA SOLAR IN SOUTHERN AFRICA Solar energy was once thought to be an expensive, inherently intermittent resource. However, the solar industry is now experiencing a changing paradigm under which solar has become cost-competitive with traditional generation and, through advancements in storage technology, can be dispatchable (i.e., deployed whenever it is needed throughout the day). Many countries and regions around the world are noticing this changing perspective on solar power and are increasing efforts to bring more solar generation online.

1.2.1 WHAT IS MEGA SOLAR? Solar generation is increasing in popularity partially due to mega solar initiatives and multi-phased renewable procurement programs, like the South Africa Renewable Energy Independent Power Producer Programme (REIPPPP). These programs are promoting large-scale solar generation by taking advantage of supportive renewable policies and leveraging economies of scale to reduce photovoltaic (PV) and concentrating solar power (CSP) project prices, often to below 5c/kWh and 10c/kWh, respectively. Figure 4 below shows mega solar programs around the world and the energy prices associated with each program.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 10 Figure 4: Mega Solar Programs Around the World

Longyangxia Benban Solar Shakti Sthala Solar Star, Dam, China Park, Egypt Solar Park, USA India PV (850 MW) PV (2.5 GW) Price unknown PV (579 MW) 8.4c/kWh** PV (2 GW) 8c/kWh 7.3c/kWh Noor, Morocco PV (170 MW) 4.8c/kWh CSP (550 MW) DEWA, Solar Power 15c/kWh** UAE Platform, Chile REIPPPP*, CSP (700 MW) 7.3c/kWh *REIPPPP includes other renewable PV (2.4GW) South Africa technologies, but has deployed a CSP (350 MW) PV (2.8 GW) Aurora, large amount of solar throughout 6.3c/kWh** 4.37c/kWh** Australia South Africa CSP (1.05GW) CSP (150 MW) **represents bid prices from the 8.8c/kWh** 6c/kWh latest bid within the program

This concept study evaluates a mega solar program in Southern Africa that could bring on at least 2 – 5 Gigawatts (GW) of solar generation through a multi-phased procurement program.

1.2.2 WHY SOUTHERN AFRICA? Southern Africa has world-class solar resource potential. In particular Botswana, Namibia, and the Northern Cape region of South Africa have among the world’s highest direct normal irradiance (DNI), which is critical for CSP, and have very high global horizontal irradiance (GHI), which is critical for PV. While the region has seen an increase in solar procurements through the REIPPPPP and Namibia’s Renewable Energy Feed-In Tariff (REFIT) Programme, it lacks a large-scale, solar-only procurement program that could capitalize on the tremendous solar resource potential and deliver low-cost solar energy throughout the region. Falling solar technology costs have led to a proliferation of mega solar programs throughout the world, generating a body of lessons learned and several useful models that Southern Africa can draw on to unlock its own solar resource potential. The success of REIPPPP and the World Bank Group’s Scaling Solar have demonstrated that large-scale procurements can lead to low prices in sub-Saharan Africa and have created procurement templates that can be easily leveraged to reduce startup time and cost. Finally, the Southern African Power Pool (SAPP) has created a plan for an integrated market in the region, including existing and potential interconnected transmission projects to accelerate power trade. There are also plans to connect SAPP with the Eastern Africa Power Pool (EAPP), creating the potential for a mega solar program to export low-cost power throughout the sub-continent.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 11 1.3 PURPOSE OF THIS DOCUMENT

SAEP supported PA by analyzing the potential for a mega solar IFC Concept Stage Checklist program in Southern Africa. The SAEP team undertook a three-  Project structure outlined month concept stage analysis (“concept study”), during which it  Does the country and power sector reviewed successful mega solar programs, interviewed regional provide adequate risk reward public and private sector energy sector stakeholders, and reviewed benefits to private investors key data sources like the SAPP Pool Plan, PA Transmission  Regulatory support and tariffs, Roadmap, and integrated resource plans (IRPs) for Namibia and especially the duration and timeline South Africa. This white paper summarizes key findings and areas for any incentives for solar power for additional analysis during a follow-on pre-feasibility assessment.  Suitable site identified taking This concept stage analysis aligns with the components in the account of site constraints International Finance Corporation (IFC) Concept Stage Checklist  Grid access (proximity, capacity, and (see box to right). policy provisions for access)  Identification of off-taker and available infrastructure to take the 1.3.1 CONCEPT STUDY APPROACH power generated The concept study analysis focused on the following components: 1. Review Leading Practices. The concept study analyzed other mega solar programs in Morocco, China, Chile, US, and India. The study also reviewed the pre-feasibility study for the Upington Solar Park in South Africa, which did not move past the pre-feasibility stage. The study identified leading practices that made each program successful and lessons learned that should be considered in planning a mega solar program in Southern Africa. 2. Identify Potential Host Countries and Sites. The concept study reviewed each country in Southern Africa against a common set of criteria that included solar resource potential, land availability, and legal and regulatory environment. The study selected two countries for evaluation as potential host countries—Botswana and Namibia—which it found to have very high solar resource potential, good land availability, and stable enabling environments with generally good rule of law and governance. Moreover, in 2015 the International Renewable Energy Association (IRENA) and several other partners evaluated both countries for renewable energy zones and identified sites optimized for PV and CSP development. The study reviewed the IRENA site assessments and narrowed to three sites in Namibia and two in Botswana that had high solar potential, good land availability, and access to the backbone transmission network. Through that analysis, the study estimated the potential solar technology options and plant sizes for each site. 3. Review Energy Sectors and Analyze Economic Impact. The concept study reviewed the energy sectors of each country as well as the general sectoral and broader economic conditions that might impact a mega solar program. The economic analysis estimated the levelized cost of energy (LCOE) from each of the five sites as well as the domestic economic benefits (e.g., replace expensive peak generation, increase domestic energy security, improve generation reliability, create jobs) to the host country. 4. Review Transmission Infrastructure. The concept study reviewed each country’s transmission infrastructure to identify the potential for evacuation of power to domestic load centers, as well as the optimal transmission paths from the identified sites to each SAPP participant and identify upgrades needed for evacuation of power to each. 5. Conduct Demand Analysis. The concept study assessed the supply / demand imbalances and generation options for SAPP participants. Through this assessment, the study identified the top demand centers for different time horizons and tied that with the transmission constraints.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 12 6. Analyze Country Success Conditions. For Botswana and Namibia, the concept study identified four categories of success conditions necessary for a mega solar program— procurement, financial, operations, and offtake. The analysis identified potential constraints under each category and recommended mitigation strategies for addressing each constraint. 7. Develop Potential Program Structures. Based on the legal and regulatory environment and current state of energy sector stakeholders, the concept study developed illustrative mega solar program structures for both Botswana and Namibia. 8. Determine Next Steps. The concept study identified specific areas of analysis needed under a pre-feasibility assessment to evaluate each site and to understand the detailed system and economic impacts of a mega solar program in Southern Africa.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 13 2 COUNTRY AND SITE ANALYSIS The concept study determined that Botswana and Namibia are ideal mega solar host countries and analyzed five sites developable under a mega solar program.

CONCEPT STUDY APPROACH

Develop country evaluation criteria and determine top two SAPP countries 1 for mega solar Develop site evaluation criteria and determine top sites for mega solar, 2 confirming with in-country stakeholders

Evaluate sites for mega solar components, including transmission capacity, solar 3 capacity, and land availability

2.1 SAPP COUNTRY ANALYSIS The concept study evaluated each country in SAPP against three criteria to narrow down to two potential countries for a regional-scale mega solar program. Solar Availability: Given that solar resource availability is an important factor in assessing the viability of a mega solar program, the concept analysis Figure 5: GHI and DNI Levels in SAPP Countries reviewed the DNI and GHI potential for SAPP countries that could reasonably serve as a site for this program. Figure 6 shows the GHI and DNI ranges for each country analyzed. The study found that South Africa, Namibia, and Botswana had the highest GHI and DNI ranges. It is worth noting that South Africa has a wider range of GHI and DNI values due to the lower solar irradiance levels on the eastern side of the country and the high solar irradiance level on the western side of the country, in the Northern Cape region. Land Availability: One of the other major resource constraints to developing a mega solar program is the availability of low-cost land with Source: Global Solar Atlas, The World Bank Group, https://globalsolaratlas.info/ high solar potential. Both PV and CSP installations require large amounts of relatively flat land with the potential for development. The concept study found that Botswana and Namibia have large amounts of land without existing human settlements or economically-productive activity and are located within the regions with high DNI and GNI values. While South Africa also has land with high solar potential, much of it is economically productive and/or more expensive than land in Botswana and Namibia. Legal and Regulatory Environment: A strong legal and regulatory environment with democratic stability, rule of law, and an independent procurement entity with clear and transparent rules is critical to giving private sector participants (e.g., project developers, financiers, consultants) confidence that a mega solar program could be successful. The concept study found that Botswana and Namibia are the two best scoring Southern Africa countries on the Corruption Perception Index, which is a positive

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 14 indicator that a program in those countries could receive donor and private financing. In addition, Namibia has a cost-reflective electricity tariff giving the utility and developers a clear understanding of the utility’s cost of generation. The Government of Botswana has the strongest credit rating in Africa. After reviewing each factor, the concept study determined that Botswana and Namibia are the ideal locations for a mega solar program in Southern Africa.

2.1.1 BOTSWANA AND NAMIBIA ENERGY SECTORS Both Botswana and Namibia rely on imports to meet domestic electricity consumption. This leaves both countries exposed to supply disruptions and prices escalations. Botswana: Despite a nominal generation capacity surplus, Botswana imported approximately 43 percent of the total energy consumed during the Figure 6: Botswana and Namibia Generation Capacity year—1,678 GWh of 3,855 GWh of electricity sent out. This was primarily due to the low availability of the country’s primary 600 MW coal plant, Morupule B. Botswana plans to expand Morupule B by 300 MW, but that was recently stalled following a disagreement over power purchase agreement (PPA) terms.1 Namibia: Namibia imported 73 percent of its power supply in 2018, primarily through the day- ahead SAPP market, which depends heavily on Eskom production, and Namibia’s bilateral agreement with Eskom. The Ruacana Power Station, a hydro power asset located near the Angolan border, accounts for nearly all domestic generation but is highly susceptible to droughts. On average, Ruacana generates 1,500 GWh of electricity annually, but in FY2017/2018 it only generated 1,144 GWh, a 23 percent decrease. Namibia continues to explore domestic baseload generation options to supplement the Ruacana hydro power station. The Kudu gas-to- Source: SAPP Pool Plan 2017 Main Volume, SAPP power project is one of the leading candidates, as represented in light grey ‘candidate’ bars in the bottom bar chart in Figure 7. The project could provide up to 400 MW of capacity for domestic consumption, yet it has been stalled for years and the Minister of Energy has expressed doubts about its feasibility.2 2.2 MEGA SOLAR SITE ANALYSIS As part of its support for the African Clean Energy Corridor Initiative, IRENA conducted analysis of CSP and PV development sites in both Namibia and Botswana. Under this analysis, IRENA analyzed resource potential, distance from the transmission network, and other relevant site characteristics. The concept analysis used the IRENA data as a starting point for developing a short-list of potential mega solar sites

1“2017 BPC Annual Report,” Botswana Power Corporation, 2017. https://www.bpc.bw/about-us/Annual%20Reports/2017%20BPC%20ANNUAL%20REPORT.pdf 2 NamPower Annual Report 2018 https://www.nampower.com.na/public/docs/annual-reports/Nampower%202018%20AR_web%203.pdf

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 15 in Namibia and Botswana. Additionally, both the Government of Botswana (GoB) and Government of Namibia (GoN) have commissioned pre-feasibility assessments of CSP developments 1. Solar Potential: Minimum DNI level of 2,000 kWh/m2/year and GHI level of 2,000 kWh/m2/year. DNI is used to measure CSP potential and GHI is used to measure PV potential. The study used the World Bank Group’s Global Solar Atlas to determine average DNI and GHI levels at each of the sites 2. Land Availability: Must have significant land availability within 5 kilometers (km) of the nearest substation. The concept study used satellite images to estimate the land availability within a 5 km radius of the nearest substation to the site, removing land currently in use for other purposes 3. Transmission Access and Routes: Must be in close proximity to a transmission line and substation with sufficient capacity to evacuate power to load centers. The study conducted a separate transmission analysis (see Appendix 3) and used those results for this study

2.2.1 BOTSWANA MEGA SOLAR SITES Figure 7: Potential Mega Solar Sites in The GoB investigated developing solar assets in Botswana Botswana and focused on areas with high solar irradiance and in close proximity to the 400 kV network. The GoB commissioned a pre-feasibility study for a 200 MW CSP facility and selected five sites. In 2012, it commissioned a feasibility study. The study recommended Jwaneng as an ideal site for a 100 MW CSP plant and further recommended the installation of ground-level DNI monitoring stations at both Jwaneng and Letlahakane.3 The concept analysis chose to evaluate Jwaneng and Letlahakane as two sites for development in Botswana. Figure 8 shows the location of each.

Jwaneng Jwaneng is located in Southeastern Botswana near Gaborone. Solar Potential. The site has strong solar potential with DNI and GHI levels at 2700 kWh/m2/year and 2150 kWh/m2/year, respectively. Land Availability. Based on an analysis of satellite data using Google Earth Pro, there are 2,788 hectares (ha) of land available for development within 5 km of the Jwaneng substation. Assuming 4.2 ha per MW of CSP and 3.3 ha per MW of PV, Jwaneng could support maximum plant sizes of 664 MW for CSP and 845 MW for PV within 5 km of the Jwaneng substation. Transmission Access and Routes. The nearest substation is the Jwaneng substation which has 132 kV lines that can bring power to Gaborone.

Letlhakane Letlhakane is located in the central part of Botswana. Solar Potential. The site has strong solar potential with DNI and GHI levels at 2400 kWh/m2/year and 2200 kWh/m2/year, respectively.

3 https://www.afdb.org/fileadmin/uploads/afdb/Documents/Generic-Documents/csp%20in%20botswana.pdf

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 16 Land Availability. Based on an analysis of satellite data using Google Earth Pro, there are 2,028 ha of land available within 5 km of the Orapa 1 and 2 substations. Assuming 4.2 ha per MW of CSP and 3.3 ha per MW of PV, Lethlakane could support maximum plant sizes of 483 MW for CSP and 614 MW for PV within 5 km of the Orapa 1 and 2 substations. Transmission Access and Routes. The nearest substations are the Orapa 1 and 2 substations which have 200 kV lines to Selebi Phikwe.

2.2.2 NAMIBIA MEGA SOLAR SITES Figure 8: Potential Mega Solar Sites in Namibia The GoN and NamPower conducted studies in 2009 and 2015 of potential CSP and PV sites. These sites were close to the 400 kV backbone and had nearby load centers. The GoN and NamPower are supportive of PV generation since those tend to come below current tariff costs. While they have also shown strong interest in CSP technology, there are concerns about cost, particularly when adding in storage components. Based on the previous analysis done by NamPower, the study selected three sites for further analysis. Figure 9 shows the three sites in Namibia – Gerus, Arandis, and Kokerboom.

Gerus Gerus is located in northern central Namibia. Solar Potential. The site has strong solar potential with DNI and GHI levels at 2700 kWh/m2/year and 2300 kWh/m2/year, respectively. Land Availability. Based on an analysis of satellite data using Google Earth Pro there are 2,041 ha of land available within 5 km of the nearest substation, Gerus substation. Assuming 4.2 ha per MW of CSP and 3.3 ha per MW of PV, Gerus could support 486 MW for CSP and 619 MW for PV. Transmission Access and Routes. The nearest substation is the Gerus substation which is connected to the Zambezi HVDC Link and can evacuate electricity to the Copperbelt.

Arandis Arandis is located on the western coast of Namibia, near Walvis Bay. Solar Potential. The site has strong solar potential with DNI and GHI levels at 2800 kWh/m2/year and 2400 kWh/m2/year. Land Availability. Based on an analysis of satellite data using Google Earth Pro, there are 785 ha of land available within 5 km of the Rossing substation. Assuming 4.2 ha per MW of CSP and 3.3 ha per MW of PV, Arandis could support 187 MW for CSP and 238 MW for PV. Transmission Access and Routes. The nearest substation is the Rossing substation which has 200 kV lines to Walvis Bay.

Kokerboom Kokerboom is located in southern Namibia. Due to a lack of fresh water, CSP is not ideal at this site without collocated desalination. It would require extensive costs to install a water filtration system for

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 17 the brackish water in the area and dry cooling is not feasible in that area due to high ambient temperatures. Solar Potential. The site has strong solar potential with DNI and GHI levels at 3000 kWh/m2/year and 2300 kWh/m2/year, respectively. Land Availability. Based on an analysis of satellite data using Google Earth Pro, there are 2,356 ha of land available within 5 km of the nearest substation, Kokerboom substation. Assuming 4.2 ha per MW of CSP and 3.3 ha per MW of PV, Kokerboom could support 714 MW for PV. Transmission Access and Routes. The nearest substation is the Kokerboom substation which has 400 kV lines to Windhoek.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 18 3 ECONOMIC ANALYSIS Mega solar could have a positive economic impact on the region, creating jobs and reducing reliance on peak generators and imports.

CONCEPT STUDY APPROACH

Calculate LCOE at each site for the maximum plant sizes determined in the site 1 analysis Review energy sectors and evaluate the impact of lower cost solar generation on 2 the current generation mix and generation constraints Determine total economic impact, focusing on energy sector impacts and 3 potential job creation

3.1 LEVELIZED COST OF ENERGY ANALYSIS LCOE is the measurement of a generation asset’s lifetime cost per unit of energy production. LCOE can be interpreted as the minimum sale price for energy needed to cover the full costs of the project over its life. LCOE takes into account capital costs, operation and maintenance costs, fuel costs, and energy production / performance to understand the cost to generate one unit—typically kWh or MWh—of energy.

3.1.1 CURRENT STATE OF ENERGY LCOE LCOE is often used as the basis for comparison for different energy generation sources since it allows for comparison of various energy technologies with different lifecycles, operating capacities, capital costs, and risk structures. Conventional energy sources, such as coal and gas, have historically had lower LCOEs than solar sources. However, improvements in technology and declining costs have made solar energy cost-competitive with conventionals, though intermittency has remained a challenge. Long-term competitiveness is dependent on further technological advancements to increase production output while decreasing operating costs and capital costs, as well as address intermittency issues. The prices of PV- and CSP-generated electricity have Figure 9: 2018 LCOE Range Estimates declined significantly and are making solar a more attractive generation source. Figure 10 shows Lazard’s 2018 analysis of LCOE ranges for various generation sources, with solar PV and CSP having lower LCOE than gas and coal. In IRENA’s “Renewable Power Generation Costs in 2017” publication, it reported that average auction prices for PV coming online in 2019 are 6c/kWh and 10c/kWh for CSP.

Drivers of Low CSP Prices Many countries have adopted PV technology to harness solar resources, but some are still hesitant to adopt CSP due to concerns over high cost. Yet CSP prices have fallen rapidly in recent years and, while some of this decrease is attributable to declining technology costs, competitive procurements have also put

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 19 downward pressure on CSP costs, resulting in bid prices of less than 10c/kWh. In a competitive auction these bid prices correspond with LCOE because they are the cost per unit of energy that developers believe they can produce CSP energy. Overall, the primary drivers include: high DNI, low costs of financing, and large plant sizes to realize economies of scale. In addition, programs have been able to capture the value of CSP storage in various ways. Australia – 150 MW Aurora CSP. SolarReserve bid on a 20-year PPA to supply energy to the Southern Australian government at 6c/kWh. One of the reasons for the low price is that 25 MW of the 150 MW project is not covered by the PPA and is sold into the spot market at peak prices. This will yield a much higher price and will offset the low PPA tariff. Chile – 260 MW Copaipo CSP. SolarReserve bid 6.3c/kWh for dispatchable 24-hour solar for the Copaipo CSP. In addition to the high irradiance levels in the Atacama Desert and SolarReserve’s advancements in solar technology, the Chilean government has also been issuing bidding for time periods. Developers bid for specific time windows and CSP developers able to capture a premium for providing peak/night-time power with storage technology. Dubai – 700 MW Dewa CSP. ACWA Power bid 7.3c/kWh for the 700 MW Dewa CSP plant. The driver for this low price is high night-time demand in Dubai. There is high demand all-day due to 24/7 air conditioner use, and this also generates demand during the night. CSP storage is able to serve the night time demand and co-locating it with PV also reduced operation costs.

Phasing Large Procurements to Reduce Prices These cost decreases are also attributable to policy incentives and competitive procurement programs that lead developers to reduce prices. When looking at large solar procurements, PV and CSP tend to fall across successive procurement rounds. Figure 11 shows the tariff prices associated with each phase of the Figure 10: Tariff Price Reductions for Phased REIPPPP and Moroccan Noor program. Under REIPPPP, Procurements the cost of CSP decreased by 42 percent over the five bid windows and the cost of PV decreased by 83 percent. Under Noor, the price of CSP similarly decreased between phases, however it is worth noting that at least some of the dramatic price reduction in Noor 4 is attributable to a change in technology from CSP to PV. • Integrate technology cost savings: The multi-year timeline for large-scale procurements allows developers to take advantage of technological advancements and cost decreases across multiple bids. • Make long-term investments: A long-term procurement program encourages developers to view participation as a long-term investment and submit low bid prices. It also allows the formation of a robust local supply chain that drives cost efficiencies. • Build confidence among participants: Phased procurements build confidence in developers and financiers over time as they see tenders close, projects finish construction and come online, and utilities take the power without incident. Lenders tend to offer more attractive financing terms as procurements demonstrate success. Multiple phases also increases confidence in the

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 20 integrity of the bidding process, which increases competition amongst developers to provide lower prices.

3.1.2 CONDITIONS FOR LOW-COST SOLAR IN BOTSWANA AND NAMIBIA Though mega solar programs have seen 6-7c/kWh prices for CSP with storage and lower prices still for PV, the concept study sought to understand whether such low prices were possible in Botswana and Namibia. The study concluded that low solar prices are possible but will require support from government and donors, including the use of a tiered tariff structure, well-run competitive procurements, and concessional financing and project de-risking mechanisms. Reduce the Cost of Financing. The weighted average cost of Figure 11: WACC Sensitivity capital (WACC) reflects the cost of financing, including cost of debt, country risk, and expected return. WACC is higher in riskier markets and can drive up the cost of solar. Figure 12 shows different WACCs, the financing conditions that would make each possible, and the associated PV LCOEs. Price for Peak Hours. Namibia and Botswana must move beyond a single PPA tariff to a time-based tariff that captures the value of CSP plus storage to the system at peak hours. Scale and Build Confidence. The pipeline of transactions must be large enough to offer developers economies of scale to invest in a market. This, along with the confidence gained from a well-run procurement, leads to price premium reductions. Optimize Technology Mix. Co-locating PV to power a CSP plant can improve plant efficiency and drive down costs.

3.1.3 SITE-SPECIFIC LCOE ESTIMATES FOR PV AND CSP For each of the five sites, the study estimated the LCOE of CSP and PV based on the maximum plant sizes. In these calculations, the study made the following assumptions: • 9.5 percent WACC, indicating concessional financing for debt (see Figure 12) • 35-year PPA, providing developers a longer period to recover costs • Eight-hour storage for CSP Table 6 below depicts LCOE calculations for PV and CSP at each site. As a reference, it includes the maximum plant sizes that were previously calculated based on land availability within 5 km of the closest substation. Table 6: LCOE of PV and CSP in Botswana and Namibia Sites

Botswana Namibia Sites Jwaneng Letlhakane Gerus Arandis Kokerboom LCOE CSP: 10.0c/kWh CSP: 10.3c/kWh CSP: 11.7c/kWh CSP: 11.5c/kWh PV: 6.1c/kWh Estimates PV: 5.3c/kWh PV: 5.3c/kWh PV: 6.1c/kWh PV: 6.0c/kWh Max Plant 664 MW CSP 483 MW CSP 486 MW CSP 187 MW CSP 561 MW CSP Sizes 845 MW PV 614 MW PV 619 MW PV 238 MW PV 714 MW PV

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 21 3.2 ENERGY SECTOR ECONOMIC ANALYSIS Botswana and Namibia are both reliant on imports from Eskom and the SAPP market. Some of these needs are driven by unreliable domestic generation and others by procurement and financial challenges. A mega solar program can improve domestic generation reliability and reduce reliance on these expensive imports.

3.2.1 BOTSWANA ENERGY SECTOR ANALYSIS Botswana Energy Sector Challenges Botswana exported power to the SAPP market for the first time in 2018, but there are still major challenges with generation reliability that will require Botswana to import power again. Coal-fired plants remain the foundation of the GoB’s energy framework. The GoB awarded contracts to increase the Morupule B coal-fired plant’s production to 1,200 MW and private companies are seeking to expand coal-fired production with projects exceeding 3,000 MW for export. Morupule B has four units of 150 MW capacity each and a nominal cost of $0.48/kWh. However, only one of the four units is currently functioning at a reduced capacity of 130 MW. The other three have severe structural defects and there is no clear timeline for repair and operationalization. This shortfall has caused the Botswana Power Corporation (BPC), the national utility, to have to import expensive power and could impact BPC’s cash position. BPC has experienced challenges in procuring power, particularly holding a competitive tender for a 100 MW solar facility. Though BPC has successfully implemented infrastructure tenders, the struggles with independent power producer (IPP) tenders have created challenges in how the markets perceive BPC’s internal capacity to run procurements. The lack of a cost-reflective tariff is another challenge for BPC and private developers. Electricity tariffs in Botswana are subsidized and not cost reflective. With that, it is difficult for private developers to compete in the market and for BPC to operate as a commercially- viable entity. The Botswana Energy Regulatory Authority (BERA) was established in 2016 and has started to bring structure to the market, reducing tariff subsidies and pushing BPC toward a cost-reflective tariff. Potential Impact of Mega Solar in Botswana Mega solar can improve the economic environment for Botswana’s energy sector. It will create lower- cost domestic generation that will reduce BPC’s reliance on imports from the SAPP day-ahead market. Solar power with storage is also more reliable than Morupule B, which is currently only 25 percent available. It will also support domestic industrial activity, including the mining sector, which needs a steady, reliable source of power to support 24-hour operations.

3.2.2 NAMIBIA ENERGY SECTOR ANALYSIS Namibia Energy Sector Challenges Namibia remains challenged to meet its goal of servicing 100 percent of peak electricity demand and generating 75 percent of total production from local resources. Namibia relies heavily on imports from the SAPP day-ahead market, ZESCO, and the Zimbabwe Electricity Supply Authority (ZESA). In 2017, it imported 73 percent of its power, exposing the country to supply disruptions, foreign exchange fluctuations, and high prices. The Ruacana power station makes up more than 90 percent of the country’s installed capacity and is dependent on the flow of the Kunene River. The reservoir is small and Ruacana only operates during wet seasons, from February to May. As climate change and droughts worsen, Namibia receives less energy from Ruacana and has to increasingly rely on imports. Namibia’s ability to meet future demand is also highly dependent on the planned 442.5 MW Kudu gas project, especially considering NamPower’s plans to decommission power stations in the next few years.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 22 If the Kudu gas project does not move forward, Namibia will remain an energy importer. Overall, the variability in Namibia’s domestic energy supply creates an uncertain price path for Namibia’s energy sector planning. Potential Impact of Mega Solar in Namibia Mega solar will create a stable price path for long-term energy sector planning and reduce the financial burden of importing emergency power when hydro falls short of forecasts. In 2018, rainfall was 75 percent of its annual average, which required NamPower to purchase expensive emergency generation to cover the shortfall. Unlike rainfall, solar resources are consistently high and reliable across Namibia. Reliable, low-cost power will also be a boon to industrial activity with high demand for power like desalination, manufacturing, and smelting. Since Namibia has a cost-reflective tariff, a reduction in the overall cost of generation would create the opportunity to pass on cost savings to consumers and potentially to connect new households that were previously uneconomical to connect. Namibia subsidizes low-income consumers through the Namibia Electricity Support Tariff (NEST), as depicted in Table 7 below. As NamPower realizes generation cost savings through a mega solar program, it can boost support for the NEST. Table 7: Namibia Electricity Support Tariff Customer Usage Tariff Amount* % of Subsidization and Type of Tariff 0 – 50 kWh N$1.22/kWh (US$ 0.09/kWh) 56% (Generation only tariff) 51-200 kWh N$1.63/kWh (US$ 0.12/kWh) 76% Greater than 200 kWh N$2.16/kWh (US$ 0.16/kWh) 100% (Regular tariff) *Conversion rate of N$13.62 = US$1 (as of February 19, 2019)

3.2.3 JOB CREATION IMPACT Job creation is important throughout Southern Africa and increasingly important in Namibia, which has an unemployment rate near 40 percent. The concept study Figure 12: Job Creation Estimates estimated the job creation potential of a mega solar program in Southern Africa. Developing solar generation creates both temporary jobs and permanent jobs associated with operations and maintenance. Figure 13 shows job creation estimates for 275 MW of PV and 500 MW of CSP. Job creation estimates are typically developed on a per MW basis for different technology types. CSP projects are typically considered more labor intensive at both the construction and operations and maintenance (O&M) stages. As there was little data on PV and CSP construction in Botswana and Namibia, the concept study used job creation data from REIPPPP, which has produced a robust body of job creation statistics, as a starting point for its estimates. The study analyzed six large PV and six large CSP REIPPPP projects and estimated an average number of jobs created per MW of each technology, weighted by the capacity of each project. Direct jobs are defined as jobs that are directly related to the development and maintenance of the solar facilities. Temporary direct jobs are those created for construction. Permanent direct jobs are those created for long-term O&M. The estimate for direct jobs for PV projects is 8.43 jobs per MW (7.85 temporary jobs, 0.57 permanent jobs). The estimate for direct jobs for CSP projects is 14.41 jobs per MW (13.8 temporary jobs, 0.61 permanent jobs) Indirect jobs are defined as jobs that are within the supply chain for the project, but do not directly support constructing the facility. The study assumed a similar multiplier to the one used in South Africa

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 23 of 0.84 indirect jobs for every one direct job, and applied this to both permanent and temporary direct jobs. Induced jobs are defined as jobs created from income from direct and indirect jobs that are re-spent in the economy. The study assumed a similar multiplier to the one used in South Africa of 1.18 induced jobs for every one direct job and applied this to both permanent and temporary direct jobs.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 24 4 DEMAND ANALYSIS There is sufficient demand in both the domestic markets and regional market for a mega solar program in Southern Africa.

CONCEPT STUDY APPROACH

Analyze addressable demand for each of the SAPP countries 1 Consider transmission and generation cost constraints for Namibia and 2 Botswana to contextualize the addressable demand Determine program scale and phasing based on addressable demand and 3 corresponding constraints

4.1 DEMAND ANALYSIS APPROACH To identify potential load centers for a mega solar program in Botswana or Namibia, the concept study included an analysis of regional electricity demand from 2020-2040. The demand analysis builds on the outputs of the SAPP Pool Plan 2017, which synthesizes demand forecasts from each SAPP member country and identifies generation and transmission investments that could provide adequate electricity supply to the region under various market conditions.

4.1.1 CALCULATING ADDRESSABLE DEMAND The demand analysis focuses on the gap between the peak capacity provided by existing and committed generation projects and the forecasted peak demand levels in each country, as represented in the SAPP Pool Plan. This gap is defined as “addressable demand”, which refers to the unmet electricity demand that will need to be addressed by new generation projects over the next two decades. Unlike most peak surplus / deficit analyses that have been conducted on the SAPP market to date, the addressable demand approach excludes generation capacity associated with candidate generation projects due to the generic nature and early development phases of many of these projects. This exclusion allows for a more concrete measure of the country-level power requirements that will need to be met by competitively priced generation capacity, such as firm domestic or imported capacity provided by a mega solar program, between 2020-2040. Table 8 compares this approach to alternative methods for quantifying electricity demand and cites notable limitations for each.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 25 Table 8: Comparison of Potential Demand Analysis Approaches

Approach Description Output Key Limitations

Compares installed • Includes many candidate capacity (MW) from Forecasted capacity projects that are generic or in Peak Surplus existing, committed, and surplus and deficit figures, early development phases / Deficit candidate generation including contributions • Does not consider forecasted projects to peak demand from candidate projects consumption levels or (MW) generation costs

Compares total energy • Includes many candidate sent out (GWh) from Forecasted energy projects that are generic or in Energy existing, committed, and imports and exports, early development phases Surplus / candidate generation including contributions • Forecasted generation cost Deficit projects to total energy from candidate projects data relies heavily on consumption (GWh) assumptions

Compares installed Unmet power capacity (MW) from requirement that could • Does not consider forecasted Addressable existing and committed be addressed by consumption levels or Demand generation projects to candidate projects and/or generation costs peak demand (MW) mega solar

Compares total energy • Forecasted generation cost Unmet energy sent out (GWh) from data relies heavily on requirement that could Addressable existing and committed assumptions be addressed by Consumption generation projects to • Available SAPP Pool Plan data candidate projects and/or total energy does not allow for this mega solar consumption (GWh) analysis

The demand analysis calculates the maximum addressable demand for each SAPP member country over three distinct time periods: near-term (2020-2024), medium-term (2025-2030) and long-term (2031- 2040). In instances where the generation capacity from existing and committed projects surpasses peak demand in a country for a given time period, addressable demand is represented as 0 MW. Thus, rather than quantifying potential surplus generation capacity, the analysis exclusively highlights country and time period combinations with surplus demand. Notably, these calculations are constrained by the baseline peak demand forecast for each country as represented in the 2017 SAPP Pool Plan and therefore do not consider alternative load growth scenarios, such as higher demand resulting from expedited electrification initiatives. Figure 13 demonstrates how this calculation is applied to the forecasted supply- demand balance for each country and time period, using the example of Zambia’s medium-term addressable demand.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 26 Figure 13: Example Zambia Medium-Term Addressable Demand Calculation

4.1.2 DATA INPUTS AND ASSUMPTIONS The SAPP Pool Plan 2017 examines three different scenarios to provide both an individual country perspective that accounts for important non-cost factors and a regionally optimized plan that promotes least cost generation and transmission investments. These scenarios, which are referenced in the SAPP Pool Plan as components, are: • Component A: This is a combination of country-by-country expansion plans based on national master plans extended (where necessary) to 2040 with a consistent set of assumptions. ‘Committed’ generation projects are those identified as such by the countries, and only existing and committed regional inter-connectors are included on the transmission side. • Component B: This is a full optimization case whereby the region is treated as though it is a single country and a least cost sequence of generation and transmission expansion projects is derived. In principle, there are no constraints on regional trade and the full potential of regional power sector integration can be realized. • Component C: This is an intermediate integration case whereby certain constraints are applied to Component B to ensure that each country, at a minimum, fulfils SAPP security and reliability planning criteria. This was interpreted to mean that by 2040 each country should have sufficient installed or firm imported capacity to be able to meet its maximum demand and reserve obligations, and large thermal power plants should operate at or above minimum capacity factor levels.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 27 The demand analysis defines existing and committed generation projects based on the data and assumptions from Component C, which optimizes generation and transmission investments while considering political economy and practice constraints. This “realistic integration case” is representative of the SAPP master plan and most closely depicts the market conditions and transmission infrastructure that would need to be in place to enable a mega solar program in the region. Table 9 explains the key assumptions underlying each of the SAPP Pool Plan’s components. Table 9: 2017 SAPP Pool Plan Component Assumptions Scenario Assumptions • Committed units are defined by the countries even if projects are only at very early stages of development • Candidate units are identified by the countries and include generic plants Component A • Only existing transmission lines and projects that are likely to be (Benchmark Case) implemented in the next 3 to 4 years are considered (Zambia – Tanzania with a 200 MW transfer limit, Zimbabwe – South Africa link for the MOZISA project, and the Livingstone – Hwange for the ZIZABONA project)

• Only projects which are under construction or have reached financial close are treated as committed units (with some exceptions where there is a Component B strong commitment from more than one country and on-going fundraising (Full Integration Case) activities) • Transmission constraints and costs are introduced after optimized least cost regional generation options are identified

• Only projects which are under construction or have reached financial close are treated as committed units (with some exceptions where there is a strong commitment from more than one country and on-going fundraising activities) Component C • Transmission constraints and costs are introduced after optimized least (Realistic Integration Case) cost regional generation options are identified • Each country is required to have sufficient installed or firm imported capacity to be able to meet its maximum demand by 2040 • Large thermal plants are required to operate at or above minimum capacity factor levels

The SAPP Pool Plan considers two potential demand forecast scenarios for each component, a base forecast and a low forecast. The growth rates and resulting peak demand in 2040 for each SAPP member country under these scenarios are shown in Table 10. The demand analysis relies on the SAPP base forecast to determine the addressable demand for each country. Table 10: SAPP Forecasted Peak Demand Growth, 2020-20404

Base Peak Low Peak Peak Demand Base Growth Low Growth Country Demand in Demand in in 2016 (MW) Rate (%) Rate (%) 2040 (MW) 2040 (MW)

Angola 1,503 7.7 3.4 10,259 3,427

4 “SAPP Pool Plan 2017: Main Volume.” SAPP Planning Sub-Committee, Dec. 2017.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 28 Base Peak Low Peak Peak Demand Base Growth Low Growth Country Demand in Demand in in 2016 (MW) Rate (%) Rate (%) 2040 (MW) 2040 (MW)

Botswana 607 3.5 3.1 1,436 1,291

DRC 1,517 5.2 3.8 4,996 3,613

Lesotho 149 3.5 2.1 321 229

Malawi 377 11.1 3.4 4,620 763

Mozambique 1,872 3.1 2.7 3,840 3,479

Namibia 646 4.0 2.5 1,578 1,099

South Africa 34,017 2.5 1.9 60,213 52,350

Swaziland 248 2.3 1.6 419 331

Tanzania 1,250 11.4 4.9 14,330 3,058

Zambia 2,956 4.1 3.4 7,807 4,625

Zimbabwe 1,841 4.4 3.5 5,204 3,426

SAPP 46,983 3.3 1.9 115,025 77,688

4.2 DEMAND ANALYSIS FINDINGS 4.2.1 ADDRESSABLE DEMAND The demand analysis findings, shown in Table 11, indicate that there is significant addressable demand in the region in the near, medium, and long-term future. As expected, the region’s addressable demand grows over time due to increasing electricity demand, fewer committed generation projects in the medium and long-term, and the decommissioning of existing generation projects. Botswana and Namibia are two of the six countries in the region with near, medium, and long-term addressable demand and have a near-term capacity shortage of 300 MW and 400 MW respectively, trailing only Zambia and Malawi. These figures increase to 550 MW and 650 MW in the medium-term and 800 MW and 1,050 MW in the long-term, confirming the countries’ need for significant increases in generation capacity over the next two decades. Table 11: SAPP Addressable Demand (MW), 2020-2040

Country 2020-2024 2025-2030 2031-2040

Angola 0 0 2,650

Botswana 300 550 800

DRC 0 150 1,800

eSwatini 250 300 350

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 29 Country 2020-2024 2025-2030 2031-2040

Lesotho 100 150 200

Malawi 350 1,350 3,900

Mozambique 0 0 0

Namibia 400 650 1,050

South Africa 0 0 200

Tanzania 0 2,700 9,950

Zambia 500 600 1,600

Zimbabwe 0 100 1,400

SAPP 1,900 6,550 23,900 Note: Values are rounded to the nearest 50 MW due to approximate installed capacity data; countries with 0 MW of addressable demand have a capacity surplus in the given timeframe.

4.2.2 TRANMISSION CONSIDERATIONS When transmission constraints based on total existing and committed transfer capacity from Namibia and Botswana are applied to these findings, addressable demand decreases substantially in the medium and long-term. Yet, despite these reductions, addressable demand levels remain high enough in the medium and long-term to justify a 2-5 GW solar procurement program in either country. These transmission-constrained addressable demand figures, shown in Table 12, will likely increase over time as candidate transmission projects with regional significance are successfully developed. However, due to data limitations, these figures are based on the total transmission capacity, rather than the available capacity, of existing and committed regional interconnectors. Therefore, in practice, addressable demand will be further constrained by existing wheeling agreements and other technical factors, which should be investigated in subsequent analyses. Table 12: SAPP Addressable Demand (MW) with Namibia and Botswana Transmission Constraints, 2020-2040

2020-2024 2025-2030 2031-2040 Country Namibia Botswana Namibia Botswana Namibia Botswana

Angola 0 0 0 0 250 250

Botswana 300 300 300 550 600 800

DRC 0 0 150 150 827 827

eSwatini 250 250 300 300 350 350

Lesotho 90 90 90 90 90 90

Malawi 250 250 800 615 800 615

Mozambique 0 0 0 0 0 0

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 30 2020-2024 2025-2030 2031-2040 Country Namibia Botswana Namibia Botswana Namibia Botswana

Namibia 400 300 650 300 1,050 600

South Africa 0 0 0 0 200 200

Tanzania 0 0 0 0 600 400

Zambia 300 400 300 400 600 400

Zimbabwe 0 0 100 100 600 820

SAPP 1,590 1,590 2,690 2,505 5,967 5,352 Note: Values are rounded to the nearest 50 MW due to approximate installed capacity data; countries with 0 MW of addressable demand have a capacity surplus in the given timeframe; addressable demand values for the Namibia and Botswana sites are exclusive of one another and should not be considered together

4.2.3 GENERATION COST CONSIDERATIONS In addition to transmission constraints, generation costs will determine whether a mega solar program located in Botswana or Namibia is a competitive option for meeting domestic and regional addressable demand. While the demand analysis does not directly consider these costs in the addressable demand calculation, it examined country-level generation costs in parallel to understand the commercial viability of power supplied by a mega solar program. According to the SAPP Pool Plan, many of the countries with addressable demand from 2020-2040 are also forecasted to have high short-run marginal costs (SRMCs) in the near, medium, and long-term future. In addition to Botswana and Namibia, South Africa, Malawi, Tanzania, and eSwatini are expected to have SRMCs that are greater than the SAPP average by 2040 due to their continued dependence on more expensive thermal plants. This implies that these countries could benefit from firm electricity imports from countries with surplus generation capacity from power sources with lower or zero fuel costs, such as hydro, solar, and wind power, even if they have sufficient domestic capacity to meet maximum demand levels. The forecasted short-run marginal costs for each country are illustrated in Figure 14. This figure does not consider the impact of a mega solar program in Botswana or Namibia but does include costs associated with other candidate generation projects.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 31 Figure 14: Forecasted Short-Run Marginal Costs5

Considering these forecasted SRMCs, the SAPP Pool Plan also forecasted the total import and export balance of each SAPP member country over this time period, as shown in Figure 15. Again, this figure does not consider the impact of a mega solar program in Botswana or Namibia, but does include costs associated with other candidate generation projects. As expected, these forecasts indicate that countries with higher SRMCs will become electricity importers by 2040. This includes a notable shift for South Africa, which is expected to make the transition from exporter to importer by 2025. Figure 15: Forecasted SAPP Import / Export Balance (GWh)6

Further investigation into South Africa’s forecasted supply-demand balance shows this expected transition is also driven by the decommissioning of approximately 30 GW of coal generation by 2040,

5 “SAPP Pool Plan 2017: Main Volume.” SAPP Planning Sub-Committee, Dec. 2017. 6 Ibid.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 32 not including coal generation assets that will be uneconomical to run.7 Figure 16 illustrates the country’s expected annual coal decommissioning over this period. Combined, these factors create additional space for low cost exports from a mega solar program in Botswana or Namibia at a scale that is not clearly depicted in the country’s addressable demand figures, assuming the required transmission upgrades can be completed. Figure 16: South Africa Annual Coal Decommissioning (GW)8

0

-0.5 -0.4 -0.6 -0.6 -0.6 -0.6 -0.6 -0.6 -0.6 -0.6 -0.6 -0.7 -1 -0.9 -0.9

-1.2 -1.2 -1.2 -1.2 -1.2 -1.5 -1.4 -1.6 -1.8 -1.8 -1.8 -1.8 -2 -1.9 -1.9

-2.5 -2.3 -2.5

-3 -3.0

-3.5

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 4.2.4 SCALING MEGA SOLAR TO MEET ADDRESSABLE DEMAND The findings of the demand analysis suggest that a competitively priced mega solar program in Botswana or Namibia has the potential to supply power to a number of load centers in the region with high addressable demand and SRMCs. To achieve reduced risk premiums for project developers and more closely align with growing addressable demand in the medium to long-term, the program could employ a phased development approach that gradually scales generation capacity in the medium and long-term. Figure 17 provides an illustrative overview of this type of approach, which would involve three project phases beginning with a domestic phase designed to cover domestic demand prior to expanding the program to supply power regionally via bilateral agreements and SAPP/EAPP market participation.

7 “South Africa Integrated Resource Plan 2018: Final Draft for Public Input.” Republic of South Africa Department of Energy, August 2018. 8 Ibid.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 33 Figure 17: Illustrative Mega Solar Program Development Phases

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 34 5 SUCCESS CONDITIONS ANALYSIS Though solar resources are high in Southern Africa, the success of mega solar will hinge on the presence of the right institutional and regulatory conditions.

CONCEPT STUDY APPROACH

Identify key conditions supportive of a mega solar program 1 Review host countries against conditions through data sources, existing analyses, 2 and KIIs Determine mitigation strategies for conditions that are not currently being 3 met by each country

5.1 SUCCESS CONDITIONS CATEGORIES A critical part of the concept stage analysis for mega solar is analyzing the key conditions in Namibia and Botswana that are important for mega solar to be successful. The study identified the seven enabling environment conditions that will most impact the success of a mega solar procurement program. There are other conditions that are important (e.g., transmission capacity) but that are more a function of the technical direction of the program and less indicative of the overall enabling environment. The concept study identified the following seven success conditions: 1. Ability to execute large procurements: The mega solar procurement program will require multiple rounds of procurement that will need to be driven by the host country. Countries should have the technical capacity and institutional knowledge to tender and award these procurements. 2. Ability to support IPPs: The mega solar procurement program will have multiple owners. The host country should have an enabling environment that attracts IPP participation. 3. Support from Development Finance Institutions (DFI)s: This condition analyzes the host country’s ability to attract DFI investments for concessional financing. Having DFI support can reduce project financing costs for developments and build confidence in the mega solar program. 4. Supportive national financing environment: This condition analyzes the national financing enabling environment, including strength of national currency, financial support from national banks, and private financing mechanisms. The country should have a strong in-country financing environment. 5. Ability to obtain land for private projects: Solar development requires the acquisition and use of large areas of land, which must be obtainable for the purpose of project development. Low costs and administrative burdens of land acquisition create the conditions for low project costs. 6. History of purchasing power from IPPs: Power projects must sell power in order to recover their costs. When the project’s arrangement is the sale of power to a single utility,

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 35 developers want to see a history of that utility successfully purchasing power from an IPP on a timely basis and without curtailment. 7. Ability to export electricity: As the domestic demand of either Botswana or Namibia is relatively small, power exports are critical to developing a mega solar program. If the country has unrestricted access to sell into the regional market and the ability to sell into bilateral contracts, then the conditions are supportive of power sector exports. 5.2 COUNTRY ANALYSIS The concept study evaluated both Botswana and Namibia against each of the seven conditions. Table 13 below includes a summary analysis of each condition for both countries using a stoplight analysis to indicate whether the condition is present (positive), could be present given the right support (neutral), or is unlikely to be present (negative). Sections 5.3 and 5.4 include a detailed analysis of the conditions in each country. Table 13: Success Conditions Overview

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 36 5.3 BOTSWANA Table 14: Botswana Detailed Success Conditions Analysis Condition Key Questions Analysis Status Potential Mitigation Options

Ability to execute Does the country have Botswana does not currently have a strong enabling Stand up an independent procurement large a successful track environment for energy procurements and IPPs. There entity. Using top-down political support, procurements record implementing were several prior attempts to create energy generation establish an independent procurement entity large procurements? IPPs, but these have not been successful. It may be similar to the IPP Office in South Africa to difficult for BPC or the Energy Ministry to operate a manage procurements Does the country have large-scale solar procurement program. Condition is not a successful track currently Provide capacity building. USAID could record implementing present, but support exchanges between the new entity and procurement programs could be made the SA IPP Office or Masen in Morocco to with multiple projects? possible institutionalize leading practices for renewable energy IPP procurement

Ability to support Does the country allow GoB regulations allow for IPPs, but there has only been Provide procurement process support. By IPPs IPPs? one known successful IPP in Botswana (a project partnering with an experienced organization to developed through a grant from the Japanese guide the procurement, GoB can take advantage Does the country have government, not a public procurement). The utility, of the regulations allowing IPPs, and successfully a history of successful BPC, has limited experience developing procurements implement an IPP IPPs? for IPPs, and, in the past, released procurement Condition is not documents that lacked critical information, such as currently Develop a truly cost- reflective tariff. project details, bidder requirements, and financial and present, but BERA is working with BPC to develop a cost- technical information. One of the barriers to IPPs could be made reflective tariff, but markets are unlikely to have reaching financial close is the lack of financial support possible confidence in the project if BPC’s tariff remains from the GoB for PPAs. highly subsidized Both the Citizen Economic Empowerment Policy and the De-risk the PPA. DFIs could consider Economic Diversification Drive policies would apply to providing a guarantee on BPC’s PPA, especially if ownership within the program. However, application of it could demonstrate an ability to sell that these requirements is at the discretion of each agency. power at cost reflective prices BPC has released procurements both with and without specific requirements regarding local content of the contractor.

Support from Does the country have GoB has a history of obtaining World Bank financing for Obtain high-level political support. By DFIs a history of working infrastructure projects which have later been developed obtaining political support from the top-down— by independent contractors. starting at the Ministry-level—concerns about

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 37 Condition Key Questions Analysis Status Potential Mitigation Options

with DFIs to execute However, GoB may resist the strict oversight required Condition is not DFIs can be addressed and mitigated early in the procurements? by lending facilities, such as DFIs, for concessional currently process financing to bidders (i.e., to “staple” the financing to the present, but procurement). could be made Build confidence in program. A phased possible approach allows for offtakers to build creditworthiness and for others to have more confidence in these offtaker. This will help open the program to private financing in the later phases

Supportive Is private financing The Pula has generally performed well against the dollar, Use currency risk mitigation products. national financing available in the country? so it is unlikely that Pula risk will pose a major constraint Despite the relatively low Pula risk, a project environment Are banks willing to to a large project, especially considering the country has this size may require a currency risk mitigation match the terms of the a 50 percent stake in diamond exports. product like that offered by OPIC PPA? What is the currency risk of the Condition is not Pula? currently present, but could be made possible

Ability to obtain Does the country have Debswana is the most successful public-private Manage land acquisition during the land for private a history of providing partnership (PPP) in Botswana and, in that arrangement, planning phase. Despite the flexible projects land for privately- GoB granted DeBeers with land rights. Additionally, GoB arrangement offered by a Debswana-style land owned infrastructure has provided land in many of its own generation structure, the government must package the projects? procurements (though these procurements have not site to reduce the land acquisition burdens to been successful, it was not due to land issues). The GoB can developers provide land In later phases, developers can purchase land directly, or and/or facilitate Declare the project a National Priority. lease from state or tribal owners. There are restrictions land acquisition The Ministry of Lands indicated it has allocated around foreign ownership of land; however, there are state-owned land for projects, mostly in the processes to allow for leases of land. mining sector, which requires much more land than solar developments. This requires the GoB to declare the project a National Priority

History of Does the country have Botswana currently does not have a large demand gap, De-risk utility offtake. There are several purchasing power a history of successful but it does rely on expensive generation and imports. options other than government support that from IPPs purchases from in-

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 38 Condition Key Questions Analysis Status Potential Mitigation Options

country IPPs to serve This program can provide lower cost, domestic Condition is not could de-risk the utility as an offtaker (e.g., risk in-country demand? generation to meet demand needs. currently insurance, prepayment) present, but Debswana as the offtaker. By tying the first GoB does not have a history of successful purchases could be made possible rounds of procurement specifically to Debswana from IPPs. While GoB has a high credit rating (A2), BPC demand, the offtaker and PPA signatory is is not rated. Additionally, GoB has not provided Debswana. This creates a creditworthy offtaker government support to PPAs and this has caused many that is a parastatal, which will help build IPPs to fail. confidence in GoB as offtaker, and potentially BPC as well

Ability to export Does the country have GoB is contributing member of SAPP. The current Establish clear regulations and SAPP electricity a history of successful BERA regulations are unclear regarding direct sales of participation. The lack of clear regulation power export? power to anyone other than BPC. provides an opportunity to craft regulations that allow cross-border trade within the SAPP The BERA Act – S 35 Licensing of electricity sector structure activities – defines that a person may not generate Condition is not electricity, be a single buyer, be a transmission operator, currently be a distribution operator, own transmission works, present, but own distribution works, sell electricity to consumers and could be made customers, or export or import electricity, “except in possible terms of a license issue by the Authority”. However, the processes to obtain a license – for any activity – is not described in the BERA Act.

5.4 NAMIBIA Table 15: Namibia Detailed Success Conditions Analysis Condition Key Questions Analysis Status Potential Mitigation Options

Ability to execute Does the country have Namibia and NamPower have successfully executed smaller IPPs Establish an IPP Office at the large a successful track but nothing at the scale of the mega solar project. A 37 MW Ministry of Minerals and Energy. The procurements solar project completed in 2018 is largest IPP in the country. SA IPP Office has a strong reputation in the region and a similar entity would give

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 39 Condition Key Questions Analysis Status Potential Mitigation Options

record implementing The REFIT Programme has developed multiple small (<5MW) Condition is not the markets confidence. The Ministry is large procurements? projects. currently seen as open-minded and forward present, but thinking and the Ministry of Minerals and Does the country have NamPower is not seen as an honest broker or competent could be made Energy is seen as an independent entity a successful track procurement authority by developers and others in the sector. possible without corruption challenges record implementing procurement programs Provide capacity building. The new with multiple projects? entity will need extensive capacity building on preparing and conducting a tender. These should be benchmarked against leading practices from the South Africa IPP Office and Masen in Morocco

Ability to support Does the country allow Namibia’s regulations do allow for IPPs, though they must be Review and optimize the SPV IPPs IPPs? structured as Special Purpose Vehicles. The utility, NamPower, registration process. By partnering has successfully developed procurements for IPPs. Projects with an experienced organization to guide Does the country have larger than 5 MW must go through a competitive tender the procurement, the Namibian a history of successful process. government could build capacity in its IPPs? Condition is not procurement process to ensure that it There are standard PPA documents for PV and CSP projects currently can meet the needs of the size of a mega available on NamPower’s website, so the basic terms are clear present, but solar program to all parties. could be made possible Ensure local ownership. In line with Meeting local content requirements and Black Economic BEE policies, national law requires 30 Empowerment (BEE) is highly challenging. Two REFIT projects percent local equity by previously are currently stalled because they were not able to obtain disadvantaged groups for PPPs. The sufficient local equity to meet the project’s requirement. programs should identify areas where it can leverage local industry and employment opportunities. Note: the government has been flexible on a sector by sector basis on meeting BEE requirements

Support from Does the country have There are no known restrictions to DFIs providing concessional Obtain high-level political support. DFIs a history of working financing for projects in Namibia. Namibian government will Crucial for moving projects forward,

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 40 Condition Key Questions Analysis Status Potential Mitigation Options

with DFIs to execute only provide guarantees to projects that are 100% government Namibia has political support needs to be given and procurements? owned. financially should come from the highest levels supported small Build confidence in program. A Through the REFIT Programme, small PPAs have been scale renewable generation to phased approach allows for offtakers to completed, with some support from local banks. There are still build creditworthiness and for others to concerns regarding the limited capital base, available funds, and meet in-country demand have more confidence in these offtaker. the size of the market. This will help open the program to private financing in the later phases Similar project structure as REIPPPP. Early phase procurement would guarantee indiscriminate access to transmission, and other necessary conditions

Supportive Is private financing There is currency risk since the Namibian dollar is pegged to Use de-risking instruments. OPIC has national financing available in the country? the South African rand. Domestic loan tenors are unlikely to a currency risk product and will receive environment Are banks willing to match the PPA life. an increase in the funding available for match the terms of the obligation PPA? What is the currency risk of the Condition is not Structure flexible procurement Pula? currently terms. The procurement could allow present, but developers to refinance mid-PPA to could be made match domestic loan tenors to the PPA possible life

Ability to obtain Does the country have The 2017 IPP policy set out to standardize land procedures for NamPower should provide land for private a history of providing land acquisition for energy projects. In Namibia, land rights are resolution to land acquisition issues. projects land for privately- vested in three distinct categories of owners: private land During the initial stages of the owned infrastructure owners, the state (predominantly conservation areas), and procurement, NamPower should resolve projects? communities. Though land reform is an ongoing process in all land acquisition issues so the Namibia, smaller renewable IPPs have successfully arranged NamPower can developers do not have to arrange for long-term (25+ year) land leases. facilitate land land purchase or leases and negotiate the acquisition terms themselves. NamPower should be aware that the lower the land costs, the lower the tariff of power generated from the project History of Does the country have Low demand: Namibia alone does not have high demand (652 Increase demand. Namibia can increase purchasing power a history of successful MW - 2017); additionally, the timing of the demand may impact electricity demand by working with from IPPs purchases from in- the economics of large-scale solar projects, especially CSP. government to package new power generation with anchor offtakers to meet

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 41 Condition Key Questions Analysis Status Potential Mitigation Options

country IPPs to serve Utility creditworthiness: Fitch rates for both Namibia and Condition is not industry or (e.g., B2 mine) or desalination in-country demand? NamPower are BB+. There are concerns about the close ties to currently needs for domestic agriculture or in the South African economy, particularly with the Namibian present, but Botswana dollar pegged to the South African rand. The Namibian could be made government only provides guarantees to its 100% owned possible De-risk utility offtake. There are projects. several options other than government support that could de-risk the utility as an Successful REFIT Programme: Small PPAs have been offtaker (risk insurance, prepayment, etc.). completed. The size of the mega solar program, even in early MIGA guarantees provide risk insurance phases is much larger than anything that has been completed in against: expropriation, transfer restriction Namibia. There are standard PPA agreements for PV and CSP and inconvertibility, breach of contract, solar projects that can provide a basis for contracts under the and war and civil disturbance mega solar program. Scale up practices that were successful under REFIT Programme. These successful practices include using standard PPA and contractual documents, building local capacity related to IPP projects (particularly to meet the 30% local ownership threshold), and use phasing to build confidence in the program

Ability to export Does the country have Namibia is contributing member of SAPP. The Electricity Conduct optimization study for electricity a history of successful Control Board (ECB) approved a modified single buyer model power system exports. Namibia should power export? that allows IPPs to export power. undertake an optimization study, focused on exports from the power system. This Given the current power shortfalls in Namibia, the country is a study will evaluate the long-term potential net importer of power. Namibia has and to export power in the market and then can export identify needed upgrades to transmission power into the interconnectors in order to realize that regional market export potential

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 42 5.4.1 RENEWABLE ENERGY INTEGRATION IN NAMIBIA An ECB-commissioned study on vRE grid integration scenarios presents several challenges to a mega solar program that should be addressed through the pre-feasibility assessment. Below are the four conclusions and recommendations for further analysis under a pre-feasibility assessment: 1. Total RE capacity should not exceed minimum load of 350MW. Recommendation: Analyze and compare the economic costs and benefits of the current generation mix, including imports, with the potential to develop low-cost solar generation and upgrade transmission infrastructure to evacuate it. Analysis: This recommendation assumes that importing power from SAPP is preferable to developing low-cost domestic power and that such power is always intermittent and will reduce grid stability. 2. RE plant size should be 10MW or less so as not to overload the grid with intermittent energy. Recommendation: Analyze the impact on grid stability of introducing large-scale CSP + thermal energy storage, which has beneficial impacts for grid stability and can provide other balancing services. Compare the economic costs and benefits to Namibia of using this approach to balance the grid rather than the current arrangement under which Eskom serves as the balancing authority. Analysis: This recommendation assumes that all new RE capacity will be intermittent. 3. Any RE investments should serve local load, due to high losses on transmission lines. Recommendation: Compare the savings achieved by developing large projects with the costs of upgrading transmission infrastructure to reduce losses necessary to deliver power from large generation assets or with actual line losses themselves. Analysis: This recommendation assumes that the economies of scale achieved through developing large generation assets are valued less than the costs of upgrading transmission infrastructure needed to deliver power to load centers without losses. 4. Cross-border transmission should not be considered, due to high interconnection constraints. Recommendation: Analyze SAPP market demand and the potential for Namibia to meet that demand under multiple scenarios that consider the cost of Namibian solar generation, the supply-demand imbalance in the SAPP market and the current price of power on the market. Analysis: This recommendation assumes that the revenues available to NamPower or a developer from selling power in the SAPP market are less than the costs of upgrading transmission lines to support cross-border power sales with minimal losses and constraints.

5.4.2 MEETING LOCAL CONTENT IN NAMIBIA As highlighted in Table 15, Namibian law requires 30 percent local equity for PPPs, which several REFIT projects have struggled to obtain. Mega solar must develop creative solutions to meet 30 percent local equity requirements. Below are a few options: 1. Development Bank of Namibia (DBN) Investment: Preliminary conversations with DBN indicate it could commit N $0.4 billion (US $30 million) toward mega solar initially. If this is a project with top-down political support and a priority for the government, DBN would consider increasing its commitment considerably 2. Government Institutions Pensions Fund (GIPF) Investment: Preliminary conversations with GIPF indicate institutional support for a mega solar program. There is the perception that

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 43 even 30 percent local ownership of a large solar program is preferable to heavy reliance on electricity imports. GIPF has authorized three investment houses to provide up to N $1.8 billion (N $134.4 million, cumulative). 3. National Investment Fund (conceptual): Following discussions with financiers (Baobab Capital) and the Renewable Energy Industry Association of Namibia, there is conceptual support for a national investment fund that would pool equity investments for power programs. This option is conceptual only, and would require conversations and support from the government.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 44 6 POTENTIAL PROGRAM STRUCTURE Building on the conditions and constraints analysis, the study developed separate program structures for Botswana and Namibia that will allow for a phased approach, moving from meeting domestic demand in the short-term to exporting to regional markets in the long-term.

CONCEPT STUDY APPROACH

Develop program structure framework, which includes the core functions 1 and entities needed for the mega solar program Tailor the framework for Botswana and Namibia. This incorporates the 2 findings from the conditions and constraints analysis

6.1 PROGRAM STRUCTURE FRAMEWORK The study developed a general framework for the program structure of this mega solar program. Based on a review of leading practices from other mega solar programs, the study determined that three components would lay out the foundation of the program: 1) a phased program structure, 2) a government-created procurement entity, and 3) multiple project owners. Phased Program Structure. As discussed in Section 3.1.1, phasing provides a range of benefits to a large solar procurement. Developers are able to improve their technology, leverage economies of scale, and generally increase efficiency. In addition, multiple phases can build investor confidence in the success of the program and result in more attracting financing arrangements. Particularly for Botswana and Namibia, where large-scale solar programs have not been proven successful yet, this phased approach will be important to attracting successful developers and concessional financing. Independent Procurement Entity. The program also needs an entity to oversee the procurement process. Morocco took this same approach when developing its Noor Solar Park and established Masen as the sole procurement entity. The procurement entity should be established by the government to run the entire procurement process. The entity will require legal, financial, and technical advisors to assist in structuring the procurement program, assessing responses from developers, and completing the transactions. In some cases, these authorities would also bear some of the development or financial risk during the earlier phases by serving as intermediaries for those agreements. Competitive Procurements. The program should feature competitive procurements structured to attract wide participation by qualified vendors. The procured solar generation assets should be wholly- owned by independent power producers (IPPs) that bid for solar capacity in each phase of the program. A transparent and competitive tender process with broad participation will keep project prices low. Other critical aspects of the project structure include financing arrangements, land arrangements, and offtakers. The structure of these aspects will change between the initial and later phases of the program (the initial phases focus on domestic demand and the later phases focus on regional demand). Financing Arrangements. During the initial phases, the procurement authority will secure and package concessional financing from DFIs that will be included in the RFP. Bidders will have full

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 45 transparency on the exact financing terms, leading to lower PPA prices. Since the loan signatory is the procurement entity and government is supporting the procurement entity, the government essentially guarantees these loans. In the later phases of the program, there will be a shift from concessional financing to private financing. As investor confidence grows in the later phases of the programs, developers will be required to bring in their own private financing for projects. Land Arrangements. The government will provide land for the program during the initial phases to encourage and incentivize developers to bid in the earlier rounds. This will reduce the burden of developers to negotiate land contracts and navigate regulatory constraints surrounding land access. In the later phases, IPPs will be responsible for securing their own land, either through ownership or lease agreements with landowners in the country. Offtakers. Given the focus on domestic demand in the initial phase, the offtakers should be either the domestic utility or large anchor offtakers, such as mining companies. As the program shifts toward meeting regional demand and adds more generation capacity, offtakers will expand to include SAPP and cross-border offtakers. 6.2 POTENTIAL BOTSWANA PROGRAM STRUCTURE The Botswana program structure follows the framework laid out in the previous section, with the program structure shifting between the initial and later stages. Since Botswana does not currently have a procurement entity with the capacity to support large-scale renewable energy procurements, Botswana will need to establish one either within BPC or the Ministry of Energy. In the initial phases, the procurement entity will work with DFIs to secure concessional financing and work with the GoB to finalize land arrangements. These will be incorporated into the RFP package that the procurement entity tenders to IPPs. In later phases, developers will be responsible for coordinating directly with private financiers and landowners to secure financing and land for the RFPs developed by the procurement entity. Figure 19 shows the change in program structure between the different phases. Figure 18: Program Structure for Mega Solar in Botswana

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 46 6.3 POTENTIAL NAMIBIA PROGRAM STRUCTURE The mega solar program in Namibia will similarly follow the framework laid out in Section 6.1. Throughout the life of the program, the Ministry of Mines and Energy’s IPP Office will serve as the procurement entity, receiving technical guidance from NamPower. The IPP Office will coordinate with the Namibian Central Procurement Board who needs to oversee and approve the procurement process. Unlike in Botswana—where the procurement entity served as an intermediary in the initial phases—the IPP Office in Namibia will serve more in a coordination and oversight role. Since Namibia has a history of successful IPP tenders, the GoN and DFIs will work directly with the SPV to provide land and concessional financing during the initial phases. In later phases, this changes to private landowners and private financiers providing land and financing. The program is required by Namibian law to have a special purpose vehicle (SPV) for IPPs. This SPV will ensure that there is 30 percent local equity in the program. Figure 19 shows this program structure with the appropriate Namibian government entities. Figure 19: Program Structure for Mega Solar in Namibia

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 47 CASE STUDIES

SIX CASE STUDIES

UPINGTON SOLAR PARK NOOR POWER STATION Northern Cape, South Africa Draa-Tafilalet, Morocco

CERRO DOMINADOR SHAKTI STHALA SOLAR PARK Atacama Desert, Chile Karnataka, India

SOLAR STAR LONGYANGXIA DAM SOLAR PARK California, USA Qinghai, China

Appendix A shows the six mega solar programs from around the world that the study analyzed to understand leading practices and lessons learned that the Southern Africa Mega Solar Program should consider.

A.1 UPINGTON SOLAR PARK, SOUTH AFRICA9 Upington Solar Park was intended to be a 5 GW solar park in Northern Cape, South Africa. The solar park was designed to be a test bed for various solar technology, however it never moved past the pre- feasibility stage. The project was eventually abandoned due to political conflicts.

OVERVIEW Technology: Various types (including PV and Figure 20: Proposed Site for the Upington Solar Park CSP). For the initial phases, the park was intended to be technology neutral and a test bed to understand optimal technology Proposed Location: Farm 451 Klip Kraal and Farm 442 Droogehout, Khara Hais, Northern Cape (for Phase 1 – 1GW) Project Rationale: The solar park would leverage South Africa’s natural solar resources to increase power on the national grid Key Stakeholders: South Africa Department of Energy, Eskom (national utility) Project Cost: Not applicable since the project never passed the pre-feasibility stage

9 “South African Solar Park Indicative Mast Plan,” Fluor. 18 February 2011. http://www.energy.gov.za/SPark/SA%20SOLAR%20PARK%20Indicative%20Master%20Plan.pdf

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 48 LEADING PRACTICE ANALYSIS

Site Selection The site for the Upington Solar Park was selected based on three factors: solar potential; land terrain; accessibility to services. The Northern Cape region has high solar irradiance, which is deal for testing various solar technologies. In addition, the land in the Northern Cape is relatively flat and sparsely populated. Certain technologies, such as CSP parabolic troughs, need flat land and the lower population density reduces human settlement impact. Another critical aspect to selecting the site was accessibility to services. The Upington area has a few access points to the national grid. There is also an adequate supply of water near the chosen location since it was in close proximity to the Orange River and there is a developed highway system that runs through the region.

Landlord Approach The Upington Solar Park was intended to be managed and operated by the Solar Park Authority (SPA). The SPA would serve the following responsibilities: • Serve as a landlord. The SPA would serve in a “landlord” function to developers that want to install solar plants on the sites. The SPA would operate the office complex • Install and develop services. The SPA would be responsible for installing and extending access to utility and other services that developers need for their generation assets (e.g., road access, water, waste, park electrical system) • Oversee data collection. Since Upington would have been a testing site, the SPA would oversee solar data testing and collection, which was going to be supported by the Department of Science and Technology and Stellenbosch University • Coordinate with Eskom. The SPA would be responsible for managing and phasing the development of sites to ensure it was aligned with Eskom’s timeline for developing its substation and upgrading the transmission network This SPA approach was developed to better operate the park and coordinate with different stakeholders.

Transmission Considerations The area that was chosen for the solar park did not have existing transmission infrastructure that could accommodate the newly generated power. There were plans for Eskom to install a substation that would receive power from the various sites within the park at 132 kV and transmit that to the national grid at 400 kV. Eskom would also be responsible for developing those new 400 kV lines. In order for this to be successful, the Upington Solar Park developer(s) and Eskom would have needed coordinate to make sure the generation and transmission asset development timelines are synchronized.

A.2 CERRO DOMINADOR, CHILE Cerro Dominador is a 220 MW solar facility located in the Atacama Desert. It consisting of a 110 MW CSP plant and 100 MW PV plant. This project was developed as a result of the Chile’s Power Supply

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 49 Tender (Tender Process SIC 2013/03-2º Llamado), which awarded Abengoa (initial developer) with a 15-year PPA.

OVERVIEW10 11 Figure 21: Cerro Dominador Solar Project Technology: The 110 MW CSP tower has 17.5 hours of molten salt storage, which is locally sourced from the desert. The 100 MW PV plant consists of 392,000 solar panels Location: Camala, María Elena, II Región de Antofagasta, Atacama Desert, Chile Project Rationale: Chile has a national goal to produce 20 percent of its electricity from clean energy sources by 2025 Key Stakeholders: CORFO (subsidies), Ministry of Energy (subsidies and financing support), Sistenmo Interconectado Central (transmission), Abengoa (developer), ACCIONA, (developer), EIG Global Energy Partners LLC (owner) Project Cost: US $1.4 billion

LEADING PRACTICE ANALYSIS12 13 14

Creditworthiness of Developer Abengoa, a Spanish engineering firm, was the original developer of the Cerro Dominador Solar Project (formerly known as Atacama 1). In 2016, Abengoa filed for Chapter 11 and 15 bankruptcy and the project was put on hold. Following an internal restructuring in 2017, Abengoa resumed the project, transferring 51 percent of its developer stake to Acciona, a Spanish engineering firm, and transferring 100 percent ownership to EIG Global Energy Partners. The project was seeking US $800 million of debt financing and could not do that with Abengoa as the sole EPC contractor. Acciona’s role as co-EPC helped attract US $800 million of debt financing because of its strong balance sheet and track record in building CSP facilities.

Government Support Abengoa successfully bid on a tender issued by the National Energy Commission (NEC) to provide 950 GWh/year of electricity to the Chilean grid. The PPA terms were 15-years at US $.11482/kwh. Cerro Dominador was one of the projects developed by Abengoa that fell under the PPA. The Government of Chile passed the Law 20/25 in 2013, which aims to have 20 percent renewable energy generation by 2025. As a result, the government was incentivized to create support structures for bringing these projects online. Chile does not have a feed in tariffs or feed in premium for RE

10 “Atacama I (Cerro Dominador) 210MW Solar Park,” Inframation Deals. https://www.inframationnews.com/deals/1690531/atacama-i-cerro- dominador-210mw-solar-park.thtml 11 “Cerro Dominador.” https://cerrodominador.com/?lang=en 12 “EIG Atacama 1 PV Plant,” BloombergNEF. https://www.bnef.com/Projects/97946. 13 “EIG Atacama 1 STEG Plant,” BloombergNEF. https://www.bnef.com/Assetfinancing/31182. 14 “Atacama-1,” National Renewable Energy Laboratory. 1 July 2015. https://solarpaces.nrel.gov/atacama-1.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 50 project; however, through the CORFO, the government agreed to provide a subsidy of up to US $20 million and facilitate land access for Cerro Dominador.15 The government also worked with the Inter-American Development Bank (IDB) and German Devleopment Bank (KfW) to negotiate a concessional financing package. This included a US $66.12 million loan from the IDB Clean Technology Fund, a US $30 million loan from the IDB Canadian Climate Fund, a €100 million credit line backed by KfW for commercial banks, and a €15 million grant from the European Union’s Latin-American Investment Facility. These loans were subject to due diligence review by the banks.16

FINANCIAL ANALYSIS Below is our analysis on the financial positions of the main stakeholders—Government of Chile, Abengoa, and Acciona. Table 16: Financial Position of Cerro Dominador Stakeholders

Entity Rating Comments The Government of Chile has had good credit ratings over the last 20 years. These ratings are at the time of Aa3 (Moody’s) – 07/2018 Government of financial close (July 3, 2018). A+ (S&P) – 07/2018 Chile17 A (Fitch) – 07/2018 Moody’s downgraded the Government of Chile on July 26, 2018 to A1due to an increase in debt levels and a decline in Chile’s financial position. Abengoa filed for Chapter 11 and 15 bankruptcy in Ca (Moody’s) – 2/2016 2016. This put the project on hold until their internal Selective Default (S&P) – financial restructuring in 2017. Abengoa18 12/2015 Restricted Default (Fitch) – By that point, ownership transferred to EIC Global 12/2015 Energy Partners, who included Acciona as a co-EPC (with a 51 percent stake) to attract debt financing. In 2013, the company underwent a major financial turnaround following a financial hit from the Spanish government’s regulatory changes around renewable energy and a contraction in European government’s RE

19 spending. The turnaround focused on mitigating the Acciona Unrated effects of regulatory changes, reducing bank debt, and moving towards becoming a developer rather than an owner. By 2016, Acciona’s EBIDTA had rebounded to its level prior to the regulatory changes by the Spanish

15 Mattia Baldini and Christian Cabrera. “Innovative Configuration for a Fully Renewable Hybrid CSP Plant: Analysis of regulation and economic incentives,” Danmarks Tekniske Universitet. July 2016. 16 “Atacama Desert’s concentrated solar power plant,” IDB. 10 May 2015. https://blogs.iadb.org/sostenibilidad/en/atacama-deserts- concentrated-solar-power-plant/ 17 “Rating Action: Moody's downgrades Chile's ratings to A1, changes outlook to stable from negative,” Moody’s Investors Service, Inc. 26 July 2018. https://www.moodys.com/research/Moodys-downgrades-Chiles-ratings-to-A1-changes-outlook-to-stable--PR_386103 18 “Credit Ratings,” Abengoa S.A. http://www.abengoa.com/web/en/accionistas_y_gobierno_corporativo/ratings_y_perfil_deuda/ratings_crediticios/. 19 “Rating,” Acciona. https://www.acciona.com/shareholders-investors/financial-information/rating/. “Acciona: Resetting After a Disruption,” BCG. 13 November 2017. https://www.bcg.com/publications/2017/transformation-value-creation- strategy-acciona-resetting-after-disruption.aspx.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 51 Entity Rating Comments government and, by 2017, Acciona’s market capitalization had increased by 135 percent since 2012.

A.3 SOLAR START PROJECTS, USA20 21 A 579 MW PV plant located in Rosemund, California that consists of two projects—Solar Star 1 and Solar Star 2—and over 1.7 million solar panels spread over 3,200 acres. The project came online on July 1, 2015 and delivers electricity to the Southern California Edison service territory under a 20-year PPA agreement.

OVERVIEW Technology: 1.7 million solar panels, single-axis tracking and Figure 22: Solar Star PV Station crystalline silicone PV units Location: Rosamond, California (across Kern and Los Angeles counties) Project Rationale: California mandated that by December 31, 2030, 50 percent of electricity must come from renewable sources Key Stakeholders: CISO (transmission), Southern California Edison (utility), BHE Energy (owner), SunPower (operator and developer) Project Cost: US $2.5 billion

LEADING PRACTICE ANALYSIS

Financing Solar Star reached financial close on June 24, 2013. The project had a total capital cost of US $2.795 billion, with a 47:53 D/E ratio. BHE provided US $1.47 billion in equity. Solar Star Funding, LLC issued US $1 billion in bonds to finance the construction of the plants. The bonds have a June 30, 2035 maturity date with a coupon of 5.375 percent. In March 2015, Solar Star Funding LLC issued US $325 million in additional bonds to finalize the construction of the plants. The bonds have a June 30, 2035 maturity date with a coupon of 3.95 percent. 22 23 24

20 “Fact Sheet | Solar Star Projects,” SunPower Corporation. 2016. https://us.sunpower.com/sites/sunpower/files/media-library/fact-sheets/fs- solar-star-projects-factsheet.pdf. 21 “California Clean Energy Tour – Solar Star Projects,” California Energy Commission. https://www.energy.ca.gov/tour/solarstar/. 22 “SunPower Solar Star PV Plant,” BloombergNEF, https://www.bnef.com/FundsCommitted/AssetFinancing/39776. 23 “Solar Star 579MW Solar Facility,” Inframation Deals. https://www.inframationnews.com/deals/1310647/solar-star-579mw-solar-facility.thtml. 24 “Solar Star (2015) Follow-on Bond Issuance,” Inframation Deals. https://www.inframationnews.com/deals/1495487/solar-star-2015-followon- bond-issuance.thtml.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 52 Due to the creditworthiness of all stakeholders, the project did not encounter any barriers in securing financing.

PPA Terms and Transmission Solar Star PV plant was built in two phases. Each phase signed a 20-year PPA with Southern California Edison with a base price of US $0.08/kWh that rises annually by 2.5%.The PPA required approval from the California Public Utilities Commission (CPUC), which was given in January 2012.25 Solar Star connected to the California Independent Systems Operator (CSIO) grid in 2013. It was interconnected with the Southern California Edison Whirlwind substation, which was constructed as a part of the Tehachapi Renewable Transmission Project. There has been an increase in solar PV plants in California. Solar Star was building on that momentum and also leveraged the political and regulatory support from the State of California to secure its PPAs.

Site Selection Kern County is supportive of solar development and was also a favorable location due to its large solar resource and the presence of strong energy infrastructure.

FINANCIAL ANALYSIS Below is our analysis on the financial positions of the main stakeholders—the BHE Energy, Solar Star, SunPower, and Southern California Edison.

Table 17: Financial Position of Solar Star Stakeholders

Entity Rating Comments A3 (Moody’s) – 3/2015 BHE, as the owner, was committed to providing as much BHE Energy26 BBB+ (S&P) – 2014 YE equity as needed to sufficiently fund the project. BBB+ (Fitch) – 4/2015 Rating is for: US $1 billion senior secured Series A notes US $325 million senior secured series B notes “Solar Star's Baa3 rating is driven by the predictable nature Solar Star Funding, Baa3 (Moody’s) - 03/2015 of its contracted cash flows - though they are dependent LLC (subsidiary of BBB- (S&P) – 03/2015 on a variable solar resource, its importance as a renewable BHE Energy and owns BBB- (Fitch) – 03/2015 generating facility in the environmentally conscious Solar Star)27 California market, the experience and reputation of SunPower as the contractor and equipment provider, a relatively straightforward construction program that is nearing completion, a low operating risk profile, and a manageable leverage position. The rating is anchored by

25 “MidAmerican Solar Star PV 1,” BloombergNEF. https://www.bnef.com/Projects/47796. 26 “Berkshire Hathaway Energy 2015 Fixed-Income Investor Conference,” Berkshire Hathaway Energy. 2015. http://www.berkshirehathawayenergyco.com/assets/pdf/2015%20Investor%20Conference%20Presentation%20vFinal.pdf. 27 “Fitch Places Solar Star Funding, LLC's 'BBB-' Senior Notes on Rating Watch Negative,” BusinessWire, A Berkshire Hathaway Company. 2016 July 21. https://www.businesswire.com/news/home/20160721006432/en/Fitch-Places-Solar-Star-Funding-LLCs-BBB-.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 53 Entity Rating Comments BHE's experience and financial strength as the Project sponsor.”28 During Solar Star’s construction, SunPower was financially strong. However, recently it has faced financial problems SunPower Unrated due to falling solar panel prices and increases in import tariffs. SunPower is providing long-term O&M for Solar Star. Southern A3 (Moody’s) California Edison BBB+ (S&P) These ratings are as of 12/2018. Company29 BBB+ (Fitch)

A.4 NOOR POWER PROJECT, MOROCCO The Noor Power Station, also known as the Ouarzazate Solar Power Station (OSPS), is a solar power complex located in the Draa-Tafilalet region. OSPS was developed over three stages: Noor I (commissioned 2016); Noor II and III (commissioned 2018) and Noor IV (financial close 2017).

OVERVIEW Figure 23: Graphical Representation of Noor I-IV Technology: Noor I - 160MW CSP; Noor II - 200MW parabolic trough power plant; Noor III - 150MW solar tower power plant; Noor IV - 170 MW for three PV facilities30 Location: Draa-Tafilalet Region, 10 km from Ourzazate, sparsely populated land area Project Rationale: National goal of 2000 MW of solar (total of 42 percent of RE) by 2020; new capacity to meet growing energy demand Key Stakeholders: Masen (public authority for preparation, land owners, debt financing, tendering, contracts etc); ONEE (Public utility and power purchaser); Government of Morocco (debt guarantee); Private developers (BOO, equity finance, O&M); MDBs (loan guarantees, grants, concessional financing) 31 Project Cost: Noor 1 – US $809.4 million; Noor II and III – US $2 billion; Noor IV – US $216.7 million

28 “Rating Action: Moody's assigns Baa3 to Solar Star Series B secured notes,” Moody’s Investors Service, Inc. 3 March 2015. https://www.moodys.com/research/Moodys-assigns-Baa3-to-Solar-Star-Series-B-secured-notes--PR_319255 29 “Fitch Affirms 54 U.S. Utility, Power & Gas Companies’ Ratings,” Fitch Ratings, Inc. 24 April 2015. https://www.fitchratings.com/site/re/865163. “Credit Ratings,” Edison International. December 2018. 30 “Showcase Project: Noor Ouarzazate I Concentrated Solar Power Plant, Morocco” Global Infrastructure Hub. https://www.gihub.org/resources/showcase-projects/noor-ouarzazate-i-concentrated-solar-power-plant/ 31 “Showcase Project: Noor Ouarzazate I Concentrated Solar Power Plant, Morocco” Global Infrastructure Hub. https://www.gihub.org/resources/showcase-projects/noor-ouarzazate-i-concentrated-solar-power-plant/

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 54 LEADING PRACTICE ANALYSIS

Project Structure

The Noor project had a successful Figure 24: Noor Project Structure project structure that shared the risk between applicable parties and had one entity coordinating the various project development responsibilities. The Moroccan Agency for Sustainable Energy (Masen) is the public procurement authority created by the Government of Morocco (GoM) to oversee and manage the Noor procurement—primarily serving as the borrower/lender to DFI loans, landowner, and off-taker. The private developers bear the construction, technology, and O&M risks, but once the technology is up and running and the plant is functional, Masen (and the GoM) bear the majority of the market and revenue risk by agreeing to buy the electricity. Figure 29 shows the project structure of the Noor project, including the agreement flows.32

Financing Financing for the Noor Projects varied across the different phases, relying on a variety of concessional debt financing, equity contributions, grant funding and subsidies from the GoM. The mix of financing sources have allowed the different phases of the Noor project to secure favorable long-term PPA terms over 25-year tenors. Table 18 below shows a breakdown of the financial plan across all four phases of the Noor project. Project debt is almost entirely sourced through concessional terms from development finance institutions. The Noor projects used concessional finance across all four phases of the project from sources including the World Bank (IBRD), Clean Technology Fund (CTF), KfW, European Investment Bank (EIB) and the African Development Bank (AfDB). The ability to access these sources of concessional finance contributed to the ability of the Noor projects to be more bankable and provide a lower PPA term to the Moroccan off-taker. The concessional finance, which passed through Masen and onto the project, allowed for overall costs to be reduced and led to an approximate 25-30 percent reduction in LCOE.33 For Noor IV, Masen issued the first-of-its-kind US $113 million in green bonds to help finance the project. Project equity was provided mostly by ACWA Power (approximately US $445 million across all four of the projects) and by Masen. Additionally, Masen provided guarantees across the Noor Projects, which is backed by the GoM. 34

32 “Norton Fulbright Rose advises Masen on solar programme and first green bond in Morocco” Norton Fulbright Rose https://www.nortonrosefulbright.com/en/news/adba8c0a/norton-rose-fulbright-advises-masen-on-solar-programme-and-first-green-bond-in- morocco 33 Based on conversations with Noor Project team. 34 “Masen selects the developer of the 3 NOOR PV I solar power plants and signs contracts securing finance” Masen http://www.masen.ma/media/uploads/documents/2016_11_16_Masen_selects_the_developer_of_the_3_Noor_PVI_solar_power_p_r5TA5W3 .pdf

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 55 The cumulative effect of favorable concessional financing and supporting GoM policies has led to attractive and affordable PPA terms across stable tenors, as seen in the PPA terms in Table 18 below. Table 18: Noor Project Funding35

Concessional CAPEX Debt Equity Technology Financing PPA Term (US $M) (US $M) (US $M) Source 25 years Noor I CSP IBRD, CTF 809.4 666.33 ~166.6 $0.189/kWh Noor II CSP AfDB, AFD, 25 years CSP Solar CTF, EC/EIB, 2000 1600 400 Noor III $0.150/ kWh Tower IBRD, KfW KfW 25 years Noor IV PV 216.7 113* + 63.7 40 $0.048/ kWh Source: Masen *Masen issued $113 million in green bonds

Government Support The success of the Noor Projects is largely due to the strong support it received from the GoM. Politically, the high-level support given from King Mohammed VI for renewable energy development enabled his government to pass supportive legislation and create a favorable regulatory environment for solar projects. 36 In particular, the Moroccan Renewable Energy Strategy in Action Plan, and the various bills to implement renewable energy plans, helped create Masen which has been the cornerstone in the country’s favorable development framework. Masen was created in 2010 to coordinate the solar development strategy of Morocco’s renewable energy plan. It is publicly-backed, yet structured similar to a private venture. Through Masen, the GoM is involved in the design, construction, operation, maintenance and financing of all large-scale solar development projects in Morocco. Based on its structure, Masen serves multiple functions throughout the Noor Projects, acting as the equity investor and provider of GoM guarantees, as the off-taker and energy supplier to the state utility company, ONEE, and as the land-owning entity that procures requisite land leases for the projects. Masen’s range of roles and flexibility has allowed the GoM to dynamically support the development of the Noor projects and scale renewable energy in Morocco. 37

Land Selection The Noor-Ouarzazate Solar Complex is located on 2,500 hectares of collective land, acquired by Masen in 2010 for the purposes of developing the solar plants. In 2013, Masen subsequently acquired an additional 543 hectares of collective land. The site is located in central Morocco, near the town of Ouarzazate.

35 “Showcase Project: Noor Ouarzazate I Concentrated Solar Power Plant, Morocco” Global Infrastructure Hub. https://www.gihub.org/resources/showcase-projects/noor-ouarzazate-i-concentrated-solar-power-plant/ 36 Based on conversations with Noor Project team. 37 “Masen selects the developer of the 3 NOOR PV I solar power plants and signs contracts securing finance” Masen http://www.masen.ma/media/uploads/documents/2016_11_16_Masen_selects_the_developer_of_the_3_Noor_PVI_solar_power_p_r5TA5W3 .pdf

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 56 The site was selected based on the high long-term annual average DNI (2,636 kWh/m2/year), which is optimal for solar technology. 38 Additionally, the site is close to a body of water, with the nearby reservoir having a capacity of 480 million m3 and located approximately 10 km south of the city of Ourzazate. The availability of water helps service any water needs rising from the project. Land acquisition was carried out following Moroccan standard procedures for similar types of voluntary transactions between a local community and a public agency. The purchase of land followed a willing- buyer, willing-seller arrangement.

Staged Approach The Noor Projects took a staged approach to procuring large-scale renewable energy. Noor I reached financial close in 2013 and completed construction in 2016, while Noor II and Noor III closed in 2015, and Noor IV closed in 2017. The intervals between each of the projects allowed for Masen to apply lessons learned from previous procurement rounds to subsequent rounds. This also allowed the projects to benefit from a declining project technology costs. Since the development of Noor IV, Masen has also undertaken development of additional Noor projects in a different site. Having now developed a solid foundation of procurement solar energy, Masen continues to scale Morocco’s renewable energy resources. In 2018, Masen issued a competitive tender for the next stage of Noor Projects in the Midelt site, with the first phase of Noor Midelt expected to consist of two 400 MW hybrid CSP and PV plants. The staged approach to developing solar energy has allowed Masen to test and shift towards a hybrid technology model.

FINANCIAL ANALYSIS Below is our analysis on the financial positions of the main stakeholders—the GoM, Masen, ONEE, and ACWA Power.

Table 19: Financial Position of Noor Stakeholders

Entity Rating Comments

Government of Ba1 (Moody’s) Morocco (debt GoM has maintained these ratings since 2010. guarantor) 39 BBB - (S&P)

Private Masen issued a Green Bond on behalf of the GoM to finance the Masen (public placement at 10 construction of the project for 106 million Euros. The bond was sold procuring bps risk in private placement at a low risk premium because it was authority)40 premium underwritten with a State guarantee.

38 “Masen selects the developer of the 3 NOOR PV I solar power plants and signs contracts securing finance” Masen http://www.masen.ma/media/uploads/documents/2016_11_16_Masen_selects_the_developer_of_the_3_Noor_PVI_solar_power_p_r5TA5W3 .pdf 39 “Moody’s assigned Baa3 Rating” Moodys. https://www.moodys.com/research/Moodys-assigns-PBaa3-ratings-to-finance-to-be-raised-by-- PR_358921 40 “Masen selects the developer of the 3 NOOR PV I solar power plants and signs contracts securing finance” Masen http://www.masen.ma/media/uploads/documents/2016_11_16_Masen_selects_the_developer_of_the_3_Noor_PVI_solar_power_p_r5TA5W3 .pdf

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 57 Entity Rating Comments

ONEE (public utility and power N/A No apparent credit rating separate from the GoM. purchaser)

Although the project was financed with a Masen-issued Green Bond, one of ACWA’s portfolio companies also received an investment grade credit score for a bond it issued around the time it won the ACWA Power41 Baa3 (Moody’s) Noor project. This was the first time Moody’s and S&P rated 42 IPP/IWPP holding company debt as investment grade. It was also the “largest single tranche of holding company debt issued in emerging market” (ACWA power).

A.5 SHAKTI STHALA SOLAR PARK, INDIA Shakti Sthala is a 2,000 MW solar park over 13,000 acres located in Pavagada taluk, the Tumkur district in Karnataka, India. The solar park is divided into blocks that are auctioned off to solar power developers. As of December 2018, 600 MW has been commissioned and 1,400 MW are planned.

OVERVIEW Technology: Fixed-tilt PV panels (166,668 units of Canadian Figure 25: Blocks of Shaki Sthala Solar Park Solar’s CS6X-300P panels and 499,995 units of First Solar’s FS-3100 solar PV modules) Location: Drought-prone and rural 13,000 acres in Pavagada, Karnataka, India Project Rationale: Planned as part of Karnataka’s Solar Policy 2014-2021, which aimed at moving to more environmentally friendly energy sources Key Stakeholders: Karnataka Solar Power Development Corp. Ltd. (KSPDCL); Karnataka Renewable Energy Development Corp. (KREDL); National Thermal Power Corporation (NTPC) – India’s largest power utility; Solar Energy Corporation of India (SECI) – the Government of India’s solar entity Project Cost: Solar projects – approximately $1,848 million; Infrastructure ground work for site - $127 million; Grid stations - $246 million

41 “Moody’s assigned Baa3 Rating” Moody’s. https://www.moodys.com/research/Moodys-assigns-PBaa3-ratings-to-finance-to-be-raised-by-- PR_358921 42 “Maiden Bonds is a Complex Issue” PFI. https://acwapower.com/media/257907/maiden-bond-is-a-complex-issue.pdf

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 58 LEADING PRACTICE ANALYSIS

Solar Park Strategy The 13,000 acres Shakti Sthala Pavagada Solar Park seeks to install a total of 2,000 MW of solar energy. 43 The solar park is divided into various sub-blocks that are open for auction by private developers. The park provides basic infrastructure (e.g., roads, water pipes and earthworks) and transmissions lines connecting the park to the grid, developed by KSPDCL. To develop a project and operate within the park, developers are charged upfront and annual charges. Several of the blocks that are up for auction also have domestic content requirements (DCRs), requiring developers to source a certain percentage of their overall technology from domestic sources. Table 20 below shows a breakdown of the types of charges levied on developers of the solar park. Table 20: Pavagada Solar Park Charges44

Description Charges (US $) Upfront Charges/ One-time solar Power ~$42,041/ MW Development Expenses Annual O&M Charges (Escalated at 5% every year) ~$42,085/ MW Annual Land Lease Rent per MW (Escalated at 5% ~$2,529 (5 acres per MW allocated) every 2 years) Local Area Development Fund 1% of the Project Cost Non-refundable Facilitation Fee ~$1,551/ MW

Solar Projects and Reserve Auction PPA Terms In 2016, the 2,000 MW solar park is divided into separate blocks, with 600 MW dedicated for open bidding by developers, 1,000 MW allocated to NPTC, 200 MW allocated to SECI, and 200 MW for KREDL. Of the 600 MW that was available for auction, six companies successfully bid to develop projects. Table 21 shows the breakdown of the existing solar projects connected to the grid. Table 21: Pavagada Solar Projects by Private Developer Bid45

Company/ Category Tariff Capacity Developer ($/kWh) (MW) Adani Open 0.0737 100 DCR 0.0748 50 Tata Power Open 0.0737 100 DCR 0.0745 50 Fortum Open 0.0737 100 ACME Open 0.0737 100 RattanIndia Open 0.0735 50 Renew Open 0.0738 50

43 “World’s largest solar park Shakti Sthala launched in Karnataka” https://www.livemint.com/Industry/uJx6eSuVGTwZa6Y2aE5W7I/Worlds- largest-solar-park-Shakti-Sthala-inaugurated-in-Karn.html 44 “600 MW of Solar Projects Synchronized to the Grid at Karnataka’s Pavagada Park” https://mercomindia.com/600mw-grid-sychronized- pavagada/ 45 Karnataka Solar Power Development Corporation Limited. http://kspdcl.in/

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 59 Company/ Category Tariff Capacity Developer ($/kWh) (MW) Total MW 600 MW Source: Mercom India Research; KSPDCL

Land Locations and Acquisition Strategy Selection of the project site for the solar park was supported by the World Bank. The World Bank helped the Government of India move forward on the development of Pavagada in Karnataka to be selected as the site of a mega solar project. When surveying site location, KREDL identified over 1,400 farmers in five affected villages with land on which the site was to be developed. The Government of India subsequently undertook resettlement and land acquisition, under which the government provides 25 to 30-year leases on consent basis to secure rights of operating solar projects on the land. The cost of securing this land is built into the charges levied towards solar project developers.

IFI Support Under the Shared Infrastructure for Solar Parks operation, the World Bank supported the design and planning of solar park projects in India, including the Pavagada Solar Park.46 In particular, the Ministry of New and Renewable Energy (MNRE) solar park scheme utilized IBRD funding to develop the enabling infrastructure for utility scale development of solar power, including common infrastructure such as land, power pooling substations as well as intra-park transmission infrastructure, access roads etc. IBRD funding was also allocated towards funding transmission interconnections to the Inter State Transmission System (ISTS), which connects the park to the entire national power market.

FINANCIAL ANALYSIS In addition to understanding the successful conditions of the Shakti Sthala Solar Park, we also analyzed the financial positions of each of the main stakeholders – the Government of India, NTPC, KSPDCL, the private developers and the five distribution companies. 47

Table 22: Financial Position of Shaki Sthala Stakeholders

Entity Rating Comments Baa2 (Moody’s) Government of The Government of India was recently upgraded from Moody’s Baa3 BBB- (S&P) India ratings as a result of its healthy financial practices. BBB- (Fitch) NTPC is the largest generation company in India, and it has been very successful in managing counterparty risk, with a 100 percent Baa2 (Moody’s) NTPC (project collections rate for the past 15 years, even though many of its BBB- (Fitch) owner)48 customers have poor creditworthiness. NTPC was allotted 600 MW

of installed capacity, and in the first iteration of bids claimed it was unable to supply the procured power at the agreed cost. The state

46 The World Bank Project Appraisal Document – Shared Infrastructure for Solar Parks (December 16, 2015) http://pubdocs.worldbank.org/en/688451531507613774/1844-XCTFIN210A-India-Initial-Project-Document.pdf 47 Karnataka Solar Power Development Corporation Limited. http://kspdcl.in/ 48 “Fitch affirms NTPC rating at BBB-; outlook stable” https://www.business-standard.com/article/pti-stories/fitch-affirms-ntpc-rating-at-bbb- outlook-stable-118062001023_1.html

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 60 Entity Rating Comments government ultimately had to re-bid before the project could be developed. KSPDCL (JV of This joint venture between two public agencies was established to KREDL and SECI, Unrated procure the entirety of the 2,000 MW solar park, including the 600 public procuring MW at Shakti Sthala. authority)

A.6 LONGYANGXIA DAM SOLAR PROJECT, CHINA The Longyangxia Dam Solar Project is an 850 MW solar park spread over 27 km, which supplements a 1,280 MW hydropower station on the highly irradiated Qinghai-Tibet plateau. The project was developed in two parts, Phase 1 which installed 320 MW in 2013, and Phase II, which installed an additional 530 MW in 2015.

OVERVIEW Technology: 4 million polysilicon solar panels, coupled to one of Figure 26: Aerial View of Longyangxia the hydropower station’s turbines to regulate the solar park’s Dam variable generation before dispatching Location: Gonghe County, Qinghai Province, adjacent to the Longyangxia Dam Project Rationale: The project supports Qinghai’s target of 35 GW installed renewable capacity by 2020, with minimized ancillary service needs and water use Key Stakeholders: Developers – SPIC Huanghe Hydropower Development Co. Ltd (state owned enterprise); Power Construction Corp of China (state owned enterprise). Equipment Providers – Dongfang Electric Corp (state owned enterprise); Huawei Technologies Co. Ltd (Private); JA Solar Holdings Co. Ltd (Private); State Power Investment Corp. Ltd (state owned utility) Project Cost: Total of US $1.45 billion (Phase 1 CAPEX – US $566.8 million; Phase II CAPEX – US $883.2 million)

LEADING PRACTICE ANALYSIS

Solar-Hydro Synergies The Longyangxia Dam Solar Park project is an 850 MW hydro-solar integration park situated in the high desert on the Tibetan Plateau, integrated with the 1,280 MW Longyangxia Hydropower Dam project on

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 61 the Yellow River. As of 2018, it features more than 4 million solar panels across more than 10 square miles.49 The first phase of the Longyangxia solar park was completed in 2013, with a generation capacity of 320 MW. The second phase was completed in 2015 and operates at 530 MW. The solar park is an extension of the 1,280 MW Longyangxia hydropower plant, which has four 320 MW units. The solar park is connected to the hydropower plan via a 33-mile one-circuit 330 kV line. The baseload hydropower complements the intermittent solar PV and helps smooth the output curve of PV power, particularly when solar PV output fluctuates during overcast periods.50 Furthermore, the solar plant serves to increase the operational efficiency of the hydroelectric plant. The integration of the two technologies allows the dam to be more judicious when releasing its water, particularly limited resources in the high-altitude desert – and thus allow the hydropower station to increase its annual capacity utilization. Lastly, the integration of the two technologies allows for the solar plant to take advantage of the existing transmission lines to the national grid.

China’s National Energy Policies China currently leads the world in clean energy investments. In 2018, China reach its 2020 target goal of generating 110 GW of solar power. In its Thirteenth Five-Year Plan, China pledged to generate at least 20 percent of its electricity from non-fossil fuel sources by 2030.51 The Longyangxia Dam Solar Park project aligns with China’s National Energy Administration’s (NEA’s) policy priority of spending more than US $360 billion on renewable energy projects throughout the year end of 2020. This national policy helped nurture China’s solar panel manufacturing industry, leading to drastic technology cost declines and bankability of projects. Estimates by the IEA suggest that the Chinese government has helped reduce project costs for solar developers upwards to 40 percent.52

Curtailment Due to overproduction of supply relative to transmission capacity, curtailment of electricity, particularly of those from renewable energy resources, are an increasing problem in China. Qinghai Province, where the Longyangxia Dam Solar Park project resides, reported a 12 percent curtailment of electricity produced by solar energy in 2016. This translates to an approximate 0.6 tera-watt hour (TWh) curtailed of 4.4 TWh generated.53 The Chinese government has made reducing renewable energy curtailment a central priority to its national energy policy. On a national level, the national regulators are balancing the slowing down of building new

49 China’s Renewable Strategy Shines in Massive Solar Park”, Darrel Proctor, Power Magazine. https://www.powermag.com/chinas-renewables- strategy-shines-in-massive-solar-park-2/?pagenum=1 50 “China’s Renewable Strategy Shines in Massive Solar Park”, Darrel Proctor, Power Magazine. https://www.powermag.com/chinas-renewables- strategy-shines-in-massive-solar-park-2/?pagenum=2 51 “China 13th Renewable Energy Development Five Year Plan (2016- 2020) IEA https://www.iea.org/policiesandmeasures/pams/china/name- 161254-en.php?s=dHlwZT1yZSZzdGF0dXM9T2s,&return=PG5hdiBpZD0iYnJlYWRjcnVtYiI-PGEgaHJlZj0iLyI- SG9tZTwvYT4gJnJhcXVvOyA8YSBocmVmPSIvcG9saWNpZXNhbmRtZWFzdXJlcy8iPlBvbGljaWVzIGFuZCBNZWFzdXJlczwvYT4gJnJhcXVvO yA8YSBocmVmPSIvcG9saWNpZXNhbmRtZWFzdXJlcy9yZW5ld2FibGVlbmVyZ3kvIj5SZW5ld2FibGUgRW5lcmd5PC9hPjwvbmF2Pg 52 “Trends in PV Markets” IEA http://www.iea-pvps.org/fileadmin/dam/public/report/statistics/2018_12_04_PVPS_webinar_1_.pdf 53 “Research on Reduction of Solar Power Curtailment with Grid Connected Energy Storage System Based on Time-Series Production Simulation” Ma et al. China Electric Power Research Institute. https://file.scirp.org/pdf/EPE_2017040715043769.pdf

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 62 coal projects and solar/wind projects in highly curtailed regions, with the expansion of new transmission and distribution lines.54

Experimentation and Innovation The Longyangxia Dam Solar Power project is located next to an international research station for PV modules. The research station is a testing ground for various new solar-related technologies. It houses 26 different technology components, 21 inverters, 17 brackets, 4 energy storage solutions, and 30 new materials. The research station showcases 30 different system designs altogether. The solar park, and other solar initiatives in China, benefits from the proximity to this research base.55

54 “Has Wind and Solar Curtailment Peaked in China” Liutong Zhang, Lantau Group. https://lantaugroup.com/files/ppt_pgen17_lzc.pdf 55 “Time to shine: China showcases mega solar farm size of 5 Manhattans amid might clean push” People’s Daily Online. http://en.people.cn/n3/2018/0702/c98649-9476868.html

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 63 – DETAILED DEMAND ANALYSIS

Appendix B provide additional information on the quantitative and qualitative inputs considered in the demand for each SAPP member country. These inputs were sourced from the SAPP Pool Plan 2017 and the USAID Power Africa Transmission Roadmap to 2030.

B.1 ANGOLA Demand Forecast 2016 2040 CAGR Peak Demand (MW) 1,503 10,259 7.7% Total Consumption (GWh) 9,105 58,413 7.7%

Criteria Input High demand, high demand growth expected Demand through 2040 Short-term and medium-term supply Supply surplus; potential for long-term supply deficit Generation Relatively high generation costs, at approx. Costs 0.082 $/kWh RNT, the state-owned national transmission Potential operator, does not have its own credit Offtakers rating, but Angola’s utilities are not considered creditworthy Angola is currently not connected to SAPP In most of the scenarios modelled in the SAPP Pool Plan 2017, the 400kV link Transmission between Angola and Namibia is expected to come online in 2022 with a transfer limit of 250MW

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 64 B.2 BOTSWANA Demand Forecast 2016 2040 CAGR Peak Demand (MW) 607 1,436 3.5% Total Consumption (GWh) 3,974 9,377 3.5%

Criteria Input Low demand, moderate demand growth Demand expected through 2040 Significant near, medium, and long-term supply deficit, with few legitimate candidate projects Supply planned in the near-term and medium-term Generation mix is almost entirely coal Average generation cost of approx. $0.06 Generation $/kWh; however, BPC’s average cost per unit Costs sold, including imports, in 2017 was approx. 0.12 $/kWh Debswana could serve as a creditworthy offtaker; such an agreement would likely help build confidence in the GoB due to its Potential parastatal nature Offtakers BPC would not be a creditworthy offtaker because the GoB does not have a successful track record of purchasing power from IPPs and BPC does not have a credit rating. No significant transmission upgrades are required for Phase I domestic sales The 132kV and 220kV network may require strengthening to evacuate more power from Transmission the Letlhakane and Jwaneng; in the absence of these upgrades, the three other potential sites located near existing or planned 400kV lines should be considered

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 65 B.3 DRC Demand Forecast 2016 2040 CAGR Peak Demand (MW) 1,517 4,996 5.2% Total Consumption (GWh) 10,499 31,511 4.5%

Criteria Input Moderate demand, moderate demand Demand growth expected through 2040 Near-term supply surplus, which would grow substantially upon the completion of Supply the Inga 3 & 4 hydro projects (4,800MW and 15,336MW, respectively) Generation Relatively low generation cost, at approx. Costs 0.054 $/kWh Potential SNEL is not solvent and cannot be Offtakers considered a creditworthy offtaker The DRC connects to SAPP through Zambia via three lines that run from Zambia to the DRC with a total transfer limit of 827MW; two of the lines, at 330kV and 220kV, transmit power from ZESCO and the Transmission remaining 220kV line transmits power from the Copperbelt Energy Company (CEC) There might be an opportunity to wheel power from Namibia through Zambia to the DRC but the technical feasibility would have to be assessed

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 66 B.4 ESWATINI

2016 2040 CAGR Demand Forecast Peak Demand (MW) 248 419 2.3% Total Consumption (GWh) 1,141 2,276 2.8%

Criteria Input Very low demand, low demand growth Demand expected through 2040 Growing supply deficit resulting in a Supply continued dependency on imports through at least 2038 Generation Highest generation cost in the region, at Costs approx. 0.106 $/kWh EEC has endured some financial challenges Potential over the past few years, however its current Offtakers financial health shows potential to serve as an offtaker The MOTRACO lines that run between South Africa and Southern Mozambique also Transmission delivers power to eSwatini; the capacity this line is 1000MW

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 67 B.5 LESOTHO Demand Forecast 2016 2040 CAGR Peak Demand (MW) 149 321 3.5% Total Consumption (GWh) 645 2,096 4.8%

Criteria Input Very low demand, moderate demand Demand growth expected through 2040 Supply deficit in the near -term, which will Supply likely remain the case in the medium-term and long-term Generation Second highest generation cost in the Costs region, at approx. 0.104 $/kWh Potential LEC appears to be in sound financial health Offtakers The line between Lesotho and South Africa Transmission only has a transfer capacity of 90MW

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 68 B.6 MALAWI Demand Forecast 2016 2040 CAGR Peak Demand (MW) 377 4,620 11.1% Total Consumption (GWh) 1,756 26,105 11.4%

Criteria Input Moderate demand, high demand growth Demand expected through 2040 Potential for significant supply deficit in near, medium, and long-term Malawi IRP identifies a number of small to Supply medium scale hydro power projects, however few of these are committed projects and most have a long expected development timelines Relatively high generation cost, at approx. Generation 0.076 $/kWh Costs The majority of candidate generation projects are coal plants ESCOM lost its credit rating in January Potential 2018 and, therefore, is not a creditworthy Offtakers offtaker Malawi currently is not connected to SAPP According to the 2017 SAPP Pool Plan, the first interconnector between Mozambique and Malawi could come online in 2021 with Transmission a transfer limit of 800MW; however, this is unlikely to make Malawi an attractive load center for solar projects in Namibia or Botswana

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 69 B.7 MOZAMBIQUE Demand Forecast 2016 2040 CAGR Peak Demand (MW) 1,872 3,840 3.1% Total Consumption (GWh) 12,686 25,885 2.9%

Criteria Input Moderate demand, low demand growth Demand expected through 2040 Growing supply surplus from committed Supply hydro, wind, and gas-to-power plants Generation Second lowest generation cost in the region, Costs at approx.. 0.054 $/kWh EDM is facing a fragile financial situation and cannot be considered a creditworthy offtaker MOTRACO, a transmission company that is Potential a joint venture between Eskom, EDM, and Offtakers EEC, is used to import electricity from South Africa. Eskom currently has two guarantees in place from the World Bank to cover loans for MOTRACO The MOTRACO line between South Africa and Southern Mozambique has a transfer capacity of 1100MW Transmission The MOTRACO line between Southern Mozambique and eSwatini has a capacity of 1000MW

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 70 B.8 NAMIBIA Demand Forecast 2016 2040 CAGR Peak Demand (MW) 646 1,578 4.0% Total Consumption (GWh) 3,871 10,085 3.9%

Criteria Input Low demand, moderate demand growth Demand expected through 2040 Significant short, medium, and long-term supply deficit and reliance on imports (73% in FY2018) Kudu CCGT is planned for 2024, however Supply Namibia’s MME has questioned its feasibility and the project was recently downsized to from 850 MW to 442.5 MW due to failed offtaker agreements Low generation cost of approx. 0.054 $/kWh, Generation however, supplemental import agreements are Costs as high as 0.16-0.20 $/kWh, according to the 2016 IRP NamPower is in strong financial standing relative to other utilities in region and is Potential supportive of IPPs Offtakers A number of step load projects are expected, including Husab Mine, NCS, and NamPort extension No significant transmission upgrades are required for Phase I domestic sales Transmission line upgrades will be required for Transmission regional and continental power trade, but some of these upgrades are already included in the transmission network development plans

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 71 B.9 SOUTH AFRICA Demand Forecast 2016 2040 CAGR Peak Demand (MW) 34,017 60,213 2.5% Total Consumption (GWh) 215,686 395,600 2.5%

Criteria Input Very high demand, low demand growth Demand expected through 2040 Steadily decreasing supply surplus that shifts Supply to supply deficit in 2040 Generation Lowest generation cost in the region, at Costs 0.053 $/kWh Eskom has a low credit rating (CCC) issued Potential by S&P in November 2018 and cannot be Offtakers considered a creditworthy offtaker Eskom has heavily invested in the transmission grid infrastructure required to support the integration of renewables and comply with SAPP’s preferred N-1 network configuration Transmission Eskom exports power to most of the region and has a total transfer capacity exceeding 4GW, therefore it is unlikely that transmission upgrades would be required for any of the project phases

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 72 B.10 TANZANIA Demand Forecast 2016 2040 CAGR Peak Demand (MW) 1,250 14,330 11.4% Total Consumption (GWh) 6,320 87,880 11.1&

Criteria Input High demand, high demand growth expected Demand through 2040 Short-term supply surplus, potential for Supply medium-term and long-term supply deficit Very high generation costs compared to Generation SAPP countries, at approx. 0.117 $/kWh Costs Candidate projects are a mix of coal and gas-to-power plants TANESCO’s poor financial health does not Potential put it in a position to be a creditworthy Offtakers offtaker Tanzania currently is not connected to SAPP An interconnector between Tanzania and Zambia has been committed for 2019; Transmission however, this is unlikely to make Tanzania and attractive load center for solar projects in Namibia or Botswana

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 73 B.11 ZAMBIA Demand Forecast 2016 2040 CAGR Peak Demand (MW) 2,956 7,807 4.1% Total Consumption (GWh) 16,764 43,086 3.8%

Criteria Input High demand, moderate demand growth Demand expected through 2040 Near-term and long-term supply deficit, with fluctuations in the medium-term Supply High reserve margin required due to recent exposure to drought conditions Average generation cost of approx. 0.063 Generation $/kWh; however total unit costs have been Costs much higher in recent years due to emergency imports for drought conditions ZESCO in poor financial standing and cannot be considered a creditworthy Potential offtaker Offtakers The Copperbelt Energy Company’s (CEC) network accounts for approx. 45% of peak demand and 50% of consumption Zambia - Namibia (ZIZABONA) is expected to add 250MW to the existing 360MW transfer capacity in 2022. The planned Transmission Caprivi converter station upgrade from 300MW to 600MW is also expected between 2032 – 2040, according to SAPP Pool Plan

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 74 B.12 ZIMBABWE Demand Forecast 2016 2040 CAGR Peak Demand (MW) 1,841 5,204 4.4% Total Consumption (GWh) 9,557 22,270 3.4%

Criteria Input Moderate demand, moderate demand Demand growth expected through 2040 Medium-term supply surplus; potential for near-term and long-term supply deficit Supply Committed and candidate projects are a mix of hydro and coal plants Generation Moderate generation cost of approx. 0.057 Costs $/kWh ZESA is not in a strong financial position ZETDC, which is part of ZESA, is the Potential singular IPP offtaker in the country; Offtakers ZETDC’s debt recently reached $1.5B, due partly to issues with consumers defaulting on their payments A maximum transfer capacity of 420MW exists between Zimbabwe and Botswana, including 220MW on the 400kV line that connects Eastern Botswana to Bulawayo A 400kV line between Zimbabwe and Transmission Zambia has been committed for 2019 and will add 250MW evacuation capacity; this transmission project, in addition to an accelerated upgrade of the Caprivi connector, would also allow Zimbabwe to purchase power from Namibia

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 75 – TRANSMISSION ANALYSIS DATA

Appendix C provides a more detailed analysis of the transmission routes from each of the sites analyzed in Namibia and Botswana to nearby offtakers, including the cost of upgrades needed to evacuate large- scale power from the sites to nearby off-takers. The analysis is organized by site to nearby countries.

C.1 LETLHAKANE, BOTSWANA Routes to Zambia

Route Type Shortest Route Longest Route Letlhakane to Serule (223km) Letlhakane to Morupule A/B (230km) Serule to Francistown (92km) Morupule A/B to Phokoje (102km) Tx Route Francistown to Dukwe to Pandamatenga Phokoje to Pandamatenga (495km) (250km) Pandamatenga to Victoria (27km) Pandamatenga to Victoria (27km)

New line upgrade dates TBD New line upgrade dates TBD 2019 for internal line upgrades Timeline Planned Victoria to Pandamatenga line Planned Victoria to Pandamatenga line between 2024 and 2028 between 2024 and 2028

The Letlhakane site is situated near a 220kV The Letlhakane site is situated near a 220kV network. There is, however, no existing line network. It is unclear what the current between Letlhakane and Morupule A/B, even evacuation capacity is on the line. Adding a though a 220kV line has been proposed. 220kV line to support the existing line can Adding a 220kV line along this route can ensure that at least 490MVA can be ensure that at least 490MVA can be evacuated from Letlhakane through a evacuated from Letlhakane through a Status dedicated line. If the existing line can carry dedicated line. half of the new line's capacity, then it is A 400kV a line from Morupule B to Phokoje possible for 700MVA to be evacuated. exists The Francistown to Dukwe and Dukwe to The Francistown to Dukwe and Dukwe to Pandamatenga 400kV lines are committed Pandamatenga 400kV lines are committed and are expected to be constructed by 2019, and are expected to be constructed by 2019, according to the SAPP Pool Plan 2017 according to the SAPP Pool Plan 2017

Total Capacity 700MVA 490MVA

Interconnector Planned Victoria to Pandamatenga line Planned Victoria to Pandamatenga line Capacity between 2024 and 2028 - 400MW between 2024 and 2028 - 400MW

New 220kV Pelican line: New 220kV Pelican line: Letlhakane to Serule (223km) Letlhakane to Morupule B (230km) Serule to Francistown (92km) Upgrades

New 400kV Tern line: New 400kV Tern line: Pandamatenga to Victoria (27km Pandamatenga to Victoria (27km)

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 76 Route Type Shortest Route Longest Route Estimate Cost US$ 77M US$ 59M

Routes to Zimbabwe

Route Type Shortest Route Longest Route Letlhakane to Serule (223km) Letlhakane to Morupule A/B (230km) Tx Route Serule to Phokoje (51km) Morupule A/B to Phokoje (102km) Phokoje to Bulawayo, Zimbabwe (160km) Timeline New line upgrade dates TBD New line upgrade dates TBD The Letlhakane site is situated near a 220kV The Letlhakane site is situated near a 220kV network. There is, however, no existing line network. It is unclear what the current between Letlhakane and Morupule A/B, even evacuation capacity is on the line. Adding a though a 220kV line has been proposed. 220kV line to support the existing line can Adding a 220kV line along this route can ensure that at least 490MVA can be ensure that at least 490MVA can be Status evacuated from Letlhakane through a evacuated from Letlhakane through a dedicated line. If the existing line can carry dedicated line. half of the new line's capacity, then it is

possible that 700MVA can be evacuated. A 400kV a line from Morupule B to Phokoje

exists and the Phokoje to Bulawayo 400kV The Phokoje to Bulawayo 400kV line exists line exists Total Capacity 700MVA 490MVA 420MW current capacity 420MW current capacity Interconnector

Capacity 400MW planned between 2024 and 2028 400MW planned between 2024 and 2028 New 220kV Pelican line: New 220kV Pelican line: Upgrades Letlhakane to Serule (223km) Letlhakane to Morupule B (230km) Serule to Phokoje (51km) Estimate Cost US $60M US $51M

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 77 Routes to South Africa

Route Type Shortest Route Longest Route Letlhakane to Serule (223km) Letlhakane to Morupule A/B (230km) Tx Route Serule to Phokoje (51km) Morupule A/B to Gaborone (262km) Phokoje to Matimba, South Africa (200km) New line upgrade dates TBD Timeline New line upgrade dates TBD Watershed to Isang - 2032 The Letlhakane site is situated near a 220kV network. There is, however, no existing line between Letlhakane and Morupule A/B, even though a 220kV line has been proposed. Adding a 220kV line along this route can ensure that at least 490MVA can be evacuated from The Letlhakane site is situated near a Letlhakane through a dedicated line. 220kV network. It is unclear what the A 220kV line exists between Morupule A current evacuation capacity is on the line. and Gaborone. Adding a 220kV line to Adding a 220kV line to support the support the existing line can ensure that at existing line can ensure that at least least 490MVA can be evacuated from 490MVA can be evacuated from Letlhakane through a dedicated line. If the Status Letlhakane through a dedicated line. If the existing line can carry half of the new line's existing line can carry half of the new line's capacity, then it is possible that the entire capacity, then it is possible that 700MVA 490MVA can be evacuated to Gaborone. can be evacuated. The Gaborone to South Africa line will The Phokoje to South Africa 400kV line have to be upgraded to evacuate the exists power to South Africa. However, if a phased approach that starts with domestic consumption, this upgrade is left out of cost estimations (evacuate using existing infrastructure). A line between Isang Power Station and Watershed in South Africa could assist withthis evacuation, if it is constructed in 2032, as proposed Total Capacity 700MVA 490MVA 615MW current capacity 615MW current capacity Interconnector 700MW planned in 2031/32 (low 700MW planned in 2031/32 (low Capacity probability) probability) New 220kV Pelican line: New 220kV Pelican line: Upgrades Letlhakane to Serule (223km) Letlhakane to Morupule A/B (230km) Serule to Phokoje (51km) Morupule A/B to Gaborone (262km) Estimate Cost US $60M US $108M

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 78 Routes to Namibia

Route Type Preferred Route Letlhakane to Serule (223km) Serule to Francistown (92km) Tx Route Francistown to Dukwe to Pandamatenga (250km) Pandamatenga to Katima (178km) Timeline 2019 for internal line upgrades The Letlhakane site is situated near a 220kV network. It is unclear what the current evacuation capacity is on the line. Adding a 220kV line to support the existing line can ensure that at least 490MVA can be evacuated from Letlhakane through a dedicated line. If the Status existing line can carry half of the new line's capacity, then it is possible that 700MVA can be evacuated. The Francistown to Dukwe and Dukwe to Pandamatenga 400kV lines are committed and are expected to be constructed by 2019, according to the SAPP Pool Plan 2017 Total Capacity 700MVA Interconnector Unclear what transfer capacity the proposed Katima - Pandamatenga line will have. Currently Capacity no HV transmission capacity to evacuate according to SAPP Pool Plan New 220kV Pelican: Letlhakane to Serule (223km) Upgrades Serule to Francistown (92km) New 400kV Tern line: Pandamatenga to Katima (178km) Estimate Cost US$ 123M

C.2 JWANENG, BOTSWANA Route to Zambia

Route Type Preferred Route Jwaneng to Thamaga (85km) Thamaga to Isang (86km) Isang to Morupule B (215km) Tx Route Morupule B to Phokoje (102km) Phokoje to Pandamatenga (495km) Pandamatenga to Victoria (27km) Timeline 2019 for Phokoje to Pandamatenga line 400kV Lines from Isang to Morupule B and Morupule B to Phokoje exist

Status The Phokoje to Dukwe and Dukwe to Pandamatenga 400kV lines are committed and are expected to be constructed by 2019, according to the SAPP Pool Plan 2017 Total Capacity ~2000MVA Interconnector Planned Victoria to Pandamatenga line between 2024 and 2028 - 400MW Capacity

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 79 Route Type Preferred Route New 400kV Tern line: Jwaneng to Thamaga (85km) Upgrades Thamaga to Isang (86km) Pandamatenga to Victoria (27km) Estimate Cost US $59M

Route to Zimbabwe

Route Type Preferred Route Jwaneng to Thamaga (85km) Thamaga to Isang (86km) Tx Route Isang to Morupule B (215km) Morupule B to Phokoje (102km) Timeline N/A 400kV Lines from Isang to Morupule B and Morupule B to Phokoje exist Status 400kV line to Bulawayo, Zimbabwe, exists Total Capacity ~2000MVA

Interconnector 420MW current capacity Capacity 400MW planned between 2024 and 2028 New 400kV Tern line: Upgrades Jwaneng to Thamaga (85km) Thamaga to Isang (86km) Estimate Cost US $51M

Routes to South Africa

Route Type Shortest Route Longest Route Jwaneng to Thamaga (85km) Thamaga to Isang (86km) Jwaneng to Thamaga (85km) Isang to Morupule B (215km) Tx Route Thamaga to Gaborone (52km) Morupule B to Phokoje (102km) Phokoje to Matimba Power Station, South Africa (200km) 2032 for Botswana to South Africa 400kV Timeline N/A line The line between Jwaneng and Gaborone 400kV Lines from Isang to Morupule B and is currently a 132kV line. We assume that Morupule B to Phokoje exist it has to be upgraded to a 400kV line if a Status CSP/PV plant is sited in Jwaneng 400kV line from Phokoje to Matimba

Power Station, South Africa, exists The Gaborone - Spitzkop line may have to

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 80 Route Type Shortest Route Longest Route be upgraded if more power is to be evacuated to South Africa. A line between Isang Power Station and Watershed in South Africa could assist withthis evacuation, if it is constructed in 2032, as proposed Total Capacity ~2000MVA ~2000MVA 615MW current capacity 615MW current capacity Interconnector 700MW planned in 2031/32 (low 700MW planned in 2031/32 (low Capacity probability) probability) New 400kV Tern line: New 400kV Tern line: Upgrades Jwaneng to Thamaga (85km) Jwaneng to Thamaga (85km) Thamaga to Gaborone (52km) Thamaga to Isang (86km) Estimate Cost US$ 41M US$ 51M

Route to Namibia

Route Type Preferred Route Jwaneng to Thamaga (85km) Thamaga to Isang (86km) Isang to Morupule B (215km) Tx Route Morupule B to Phokoje (102km) Phokoje to Pandamatenga (495km) Pandamatenga to Katima (178km) Timeline 2019 for Phokoje to Pandamatenga line 400kV lines from Isang to Morupule B and Morupule B to Phokoje exist The Phokoje to Dukwe and Dukwe to Pandamatenga 400kV lines are committed and are expected to be constructed by 2019, according to the SAPP Pool Plan 2017 Status The Pandamatenga to Katima line does not appear in near-term plans and has been included in the infrastructure upgrage requirements that will accompany new solar plants Total Capacity ~2000MVA

Interconnector Unclear what transfer capacity the proposed Katima - Pandamatenga line will have. Capacity Currently no HV transmission capacity to evacuate according to SAPP Pool Plan New 400kV Tern line: Jwaneng to Thamaga (85km) Upgrades Thamaga to Isang (86km) Pandamatenga to Katima (178kV) Estimate Cost US $94M

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 81 C.3 GERUS, NAMIBIA Route to Zambia

Route Type Preferred Route Tx Route Via Caprivi/Zambexi link and ZIZABONA Timeline 2032 - 2040 - Caprivi link upgrade The Zambia - Namibia link that's part of ZIZABONA is expected in 2022, according to Status NamPower (but SAPP Pool Plan expects the line in 2032) Total Capacity 600MW

Interconnector 360MW current capacity Capacity 250MW committed planned upgrade and 150MW planned upgrade Zambia - Namibia (ZIZABONA) expected in 2022 Upgrades Planned Caprivi converter station upgrade for 300MW to 600MW expected between 2032 - 2040 according to SAPP Pool Plan Estimate Cost N/A (Grid upgrades already part of Namibia Transmission plans and pool plan)

Route to Zimbabwe

Route Type Preferred Route Tx Route Via Caprivi/Zambexi link and ZIZABONA 2022 - ZIZABONA (Namibia to Zambia) Timeline 2032 to 2040 - Caprivi link upgrade The Zambia - Namibia link that's part of ZIZABONA is expected in 2022, according to NamPower (but SAPP Pool Plan expects the line in 2032) Status The Livingstone (Zambia) to Hwange (Zimbabwe) link is already committed and expected online in 2019 Total Capacity 600MW

Interconnector 360MW current capacity Capacity 150MW planned upgrade Zambia - Namibia (ZIZABONA) expected in 2022

Upgrades Planned Caprivi converter station upgrade for 300MW to 600MW expected between 2032 - 2040 according to SAPP Pool Plan Estimate Cost N/A (Grid upgrades already part of Namibia Transmission plans and pool plan)

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 82 Route to South Africa

Route Type Preferred Route Connection via Windhoek and border of SA; connection between Gerus and Auas (within Tx Route Namibia) planned for 2019/2020 400kV line between Auas and Kokkerboom exists, a second line is planned for 2021 Gerus to Auas - 2019/2020 Timeline Auas to Kokkerboom - 2021 Status Status unknown, but all dates provided were included in the 2017 Transmission Master Plan Total Capacity ~2000MVA Interconnector 575MW current capacity Capacity 350MW planned upgrade Upgrades Planned Namibia - South Africa link expected between 2020 and 2037 Estimate Cost N/A (Grid upgrades already part of Namibia Transmission plans and pool plan)

Route to Botswana

Route Type Preferred Route Connection via Windhoek and border of SA; connection between Gerus and Auas (within Tx Route Namibia) planned for 2019/2020 400kV line between Auas and Kokkerboom exists, a second line is planned for 2021 Gerus to Auas - 2019/2020 Timeline Auas to Kokkerboom - 2021 Status Status unknown, but all dates provided were included in the 2017 Transmission Master Plan Total Capacity ~2000MVA Interconnector 575MW current capacity Capacity 350MW planned upgrade Upgrades Planned Namibia - South Africa link expected between 2020 and 2037 Estimate Cost N/A (Grid upgrades already part of Namibia Transmission plans and pool plan)

C.4 KOKERBOOM, NAMIBIA Route to South Africa

Route Type Preferred Route Tx Route Connection via Windhoek and border of SA Timeline Exists Status N/A Total Capacity

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 83 Interconnector 575MW current capacity Capacity 350MW planned upgrade Upgrades Planned Namibia - South Africa link expected between 2020 and 2037 Estimate Cost No internal grid upgrades planned or proposed for this route For Kokerboom to connect to Botswana, Zambia, and Zimbabwe, it will similarly need to go through Windhoek.

C.5 ARANDIS, NAMIBIA For routes to Zambia, Zimbabwe, Botswana, and South Africa, Arrandis will need to be connected to Windhoek to access ZIZABONA / links to South Africa.

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) SOUTHERN AFRICA ENERGY PROGRAM | 84