Universal Access by 2025 and Transforming the Gambia Electricity Sub-sector. Strategic Roadmap 2021-2040

1.1 A New Era for Gambia’s Electricity Sector 1 1.2 Building on Recent Improvements in the Electricity Sector 1 1.3 Roadmap for 2021-2040 Builds on Previous Sector Planning 2

1.4 Main elements of the 2021-2040 Roadmap 3 2 Demand forecast 6

2.1 Demand Forecast Assumptions 7

2.2 Demand Forecasts adopted for the Roadmap 9

2.3 Geospatial Breakdown of Forecast Demand 11

2.4 Daily Load Curves 12 3 Universal Access Strategy and T&D Master Plan 14

3.1 Universal Access and Distribution Planning 14

3.2 Transmission Planning 17 4 New Electricity Supply Options 20

4.1 Solar Photovoltaic 21

4.2 Gas to Power 23

4.3 Import Options 25 5 Generation Least Cost Plan 29

5.1 Least Cost Generation Planning 29

5.2 Existing, Committed and Candidate Power Plants 30

5.3 Fuel Price Forecasts 32

5.4 Generation Least Cost Plan Scenarios 33 5.5 2025 Universal Access Least Cost Generation Investment Plan 39

5.6 Implications for Tariffs 42

5.7 Generation Least Cost Plan Conclusions 43 iv Strategic Electricity Sub-sector Roadmap 2021 - 2040 6 Roadmap Directives and Implementation 44

6.1 Roadmap Directives 44

6.2 Financing Requirements 44

6.3 Institutional Structure and Implementation Arrangements 45

6.4 The Gambia Leading the Way in Africa 48 Annexes 49 A1 References 49 A1.1 Roadmap Technical Reports 49 A1.2 Other Reference Materials 49 A2 Detailed Demand Forecast Tables 50 A3 Implementation Matrices 52 A3.1 Policy and Legal Framework Enhancement 52 A3.2 Projects Implementation 56 Tables and Figures Tables Table 1 Electricity Sector Roadmap 2020-2040 4 Table 2 Demand Forecast Assumptions 7 Table 3 Average Consumption per Household – Demand Forecast Assumptions 8 Table 4 Current Household Monthly Consumption of Grid Electricity 9 Table 5 Revised Energy Demand Sent-out Forecast (GWh) 10 Table 6 Peak Demand Forecast (MW) 11 Table 7 Energy Demand Forecasts by Region with Universal Access in 2025 12 Table 8 Maximum Demand Forecasts by Region with Universal Access in 2025 12 Table 9 Summary of Universal Access Costs through 2025 (REM simulation results) 15 Table 10 Existing and New Customers to have Access by 2025 and by 2030 15 Table 11 Distribution of Sites by Region of the GERMP, REAP and GEAP Projects 16 Table 12 Transmission Development Plan Investment Cost per year (total $74.3 m) 19 Table 13 Examination of Candidate Power Plant Options 21 Table 14 Solar Generation Sites identified for Generation Planning Analysis 22 Table 15 Import Risk Matrix 27 Table 16 Existing and Committed Power Plants 30 Table 17 List of Candidate Power Plants 32 Table 18 Generation Least Cost Planning Scenarios 34 v Strategic Electricity Sub-sector Roadmap 2021 - 2040 Table 19 Capacity Additions by Scenario 35 Table 20 Summary Values of the Scenarios 36 Table 21 New Generation Capacity that is Selected for 2025 Universal Access 39 Table 22 Capacity Mix 2020, 2025, 2030, 2035 and 2040 – 2025 UA case 41 Table 23 Financing Requirements Summary for 2020-2030 ($ million) 45 Table 24 Revised Energy Demand Sent-out Forecast (GWh) 50 Table 25 Peak Demand Forecast (MW) 51 Figures Figure 1 GBA System-wide Blackouts (2017- May 2021) 2 Figure 2 Components of the 2021-2040 Roadmap Study 3 Figure 3 Domestic Generation and Imports Least Cost Plan 5 Figure 4 Summary of Demand Forecast Modelling 6 Figure 5 Revised Energy Demand Sent-out Forecast 10 Figure 6 Revised Peak Demand Forecast 11 Figure 7 GBA Daily Load Curves and Patterns of Dispatch 13 Figure 8 Approach to Derive the Least Cost Universal Access Plan 14 Figure 9 Electrification Projects to Achieve Universal Access by 2025 16 Figure 10 Existing and Committed Network (main lines only on MV grid) 17 Figure 11 Existing Power Plants Map 20 Figure 12 Map of Identified and Proposed Solar Sites from Solar Mapping Analysis 22 Figure 13 Gambia-Senegal Off-shore Gas Fields 24 Figure 14 LCOEs for Gas-to-Power Options 25 Figure 15 Regional Interconnectors opening Electricity Trade Opportunities 26 Figure 16 Least Cost Development Plan Methodology 29 Figure 17 Existing Available Capacity vs 2025 UA Peak Demand 30 Figure 18 Base Case Fuel Price Forecasts 33 Figure 19 High Case Fuel Price Forecasts 33 Figure 20 Comparison of Unit Costs of Policy Scenarios 37 Figure 21 Comparison of Unit Costs of Sensitivity Scenarios to 2025 Universal Access 38 Figure 22 Available Capacity vs Peak Demand – 2025 Universal Access 40 Figure 23 Available Firm Capacity vs Peak Demand – 2025 Universal Access 41 Figure 24 Average Variable Costs – 2025 Universal Access 42 Figure 25 Declining Levelised Costs of Generation, Transmission and Distribution 42 Figure 26 Institutional Structure for the Implementation of the Roadmap 47 vi Strategic Electricity Sub-sector Roadmap 2021 - 2040 Abbreviations and acronyms AAG Annual Average Growth ACD Aid Coordination Directorate (in Ministry of Finance) CAPEX Capital expenditure CCGT Combined Cycle Gas Turbines CdI / CI Cote d’Ivoire CLSG Cote d’Ivoire-Liberia-Sierra Leone-Guinea DOE Department of Energy ECA Economic Consulting Associates ECOWAS Economic Community of West African States EDG Électricité de Guinée EPC Engineering, Procurement and Construction EREAP ECOWAS Regional Electricity Access Project ERERA ECOWAS Regional Electricity Regulatory Authority EU European Union FLNG Floating liquefied natural gas FRSB Floating storage and regasification barge GBA Greater Banjul Area GDP Gross domestic product GEAP Gambia Electricity Access Project GERM Gambia Electricity Restoration and Modernization Project GHG Greenhouse gas GIEPA Gambia Investment and Export Promotion Agency GIS Geographic Information System GMD Gambian Dalasi GW Gigawatt GWh Gigawatt hours HFO Heavy fuel oil HH Household HV High voltage ICE Internal Combustion Engine IMF WEO International Monetary Fund World Economic Outlook IPP Independent Power Producer IRENA International Renewable Energy Agency kWh Kilowatt hour LCOE Levelised cost of energy vii Strategic Electricity Sub-sector Roadmap 2021 - 2040 LCPDP Least cost power development plan LED Light emitting diode LFO Light fuel oil LNG Liquefied natural gas LV Low voltage MDA Ministries, Departments, Agencies MECCNAR Ministry of Environment, Climate Change and Natural Resources MOFEA Ministry of Finance and Economic Affairs MOJ Ministry of Justice MOLGL Ministry of Local Government and Lands MOPE Ministry of Petroleum Energy MOU Memorandum of understanding MV Medium voltage MW Megawatt MWh Megawatt hour MWp Megawatt-peak NAMA Nationally Appropriate Mitigation Actions NAWEC National Water and Electricity Company NDP National Development Plan NEA National Environment Agency NEP National Energy Policy NPV Net present value O&M Operations and maintenance OCCRP Organized Crime and Corruption Reporting Project OCGT Open cycle gas turbine OMVG Gambia River Basin Development Organization (Organisation pour la Mise en Valeur du Fleuve Gambie). OP Office of the President OPEX Operating expenditure PPA Power purchase agreement PURA Public Utilities Regulatory Authority PV Photovoltaic RACI Responsible, Accountable, Consulted and Informed RE Renewable Energy REM Reference Electrification Model RES Renewable energy sources SDG Sustainable Development Goals SHS Solar home system viii Strategic Electricity Sub-sector Roadmap 2021 - 2040 T&D Transmission and distribution TOR Terms of reference TSA Transmission Service Agreement UA Universal Access USD / $ United States Dollar WACC Weighted average cost of capital WAPP West African Power Pool WB World Bank WTP Willingness to Pay ix Strategic Electricity Sub-sector Roadmap 2021 - 2040 Executive Summary The Gambia’s energy sector is in the middle of a major transition. Since The Gambia entered a new political chapter in 2017, electricity supply has been stabilized and villages in the North Bank have been connected. NAWEC has made significant strides to improve operational efficiency and financial performance, and is in the middle of a major organizational restructuring. At the same, time, the OMVG interconnector is at an advanced stage of construction bringing with it the first High Voltage network in The Gambia and the opportunity to access large quantities of cleaner and lower cost electricity from the West Africa Power Pool (WAPP). An unprecedented level of support from the international community provides The Gambia with the opportunity to transform the energy sector and emerge as one of the leading energy sectors in the sub-region and the African continent. In this context, the Electricity Roadmap has undergone its third update since 2015. It is the primary planning instrument, and a strategic reference point for all stakeholders in the sector. This update outlines what is needed to achieve the President’s ambitious 2025 Universal Access target, and at the same time to transform the electricity sector so that Gambians can in future benefit from reliable and affordable electricity, with NAWEC becoming an efficient, financially sustainable power utility. The roadmap identifies a clear set of priorities for the energy sector to achieve its vision of 24/7 affordable access to all Gambians. Key message 1: Universal access by 2025 is an achievable goal for The Gambia, which would make it one of the first countries in Africa to achieve universal access. Many large- scale access activities are already financed by existing donor projects and are under implementation. However, urgent action is required on the Eastern Backbone to prepare and implement this 225 kV line which is required to achieve universal access, and to construct the remaining medium voltage (MV) and low voltage (LV) lines. Including an allowance for design costs, these investments require an estimated $169 million of additional funding. Map showing Universal Access projects to 2025 Source: Transmission and Distribution Master Plan and Universal Access Strategy Key message 2: New sources of supply from solar energy and imports: there are two clear least cost sources of electricity supply to serve The Gambian population: x Strategic Electricity Sub-sector Roadmap 2021 - 2040 ● Solar: with dramatically falling solar and battery storage costs, and abundant solar resources in The Gambia, competitively procured solar-with-storage IPPs offer The Gambia an excellent opportunity to introduce clean and low cost energy into the mix. ● Imports: solar can be complemented with imports from the West Africa Power Pool including hydro from Guinea and gas-to-power from Senegal and the Ivory Coast. MoPE and NAWEC urgently need to start the preparation process for both opportunities. The main elements of the generation and imports least cost plan for the period up to 2025 are shown in the diagram below. These are imports from WAPP partners (140 MW) and Solar PV (80 MW), together with new thermal capacity (48 MW). Negative values over the period 2021- 2023 are the end of the Karpower contract and retirement of old plants. Domestic generation and imports least cost plan Source: Least Cost Generation Plan. Driven mainly by reduced supply costs but also by operational performances in NAWEC, the Roadmap is set to deliver lower electricity tariffs. Tariff requirements for cost recovery are likely to reduce from GMD 12 / kwh (23,5 c/kwh) in 2020 to GMDD 8-9.6 / kWh (15,7 c/kWh – 18,8 c/ kWh) by 2030. Key message 3: The institutional framework to realize the goals outlined in the roadmap require several areas of focus ● Continue to drive the reform process for NAWEC to become an operationally efficient and financially viable company. This starts with the full implementation of the 2019-25 Strategic Development Plan. xi Strategic Electricity Sub-sector Roadmap 2021 - 2040 ● A high level Task Force will drive implementation of the Roadmap: this will be chaired by MoPE, with the Office of the President (OP), Ministry of Finance and Economic Affairs (MoFEA), Ministry of Justice (MoJ), Ministry of Local Government and Lands (MoLGL), NAWEC, Public Utilities Regulatory Agency (PURA), national Environmental Agency (NEA) and Gambia Investment and Export Promotion Agency (GIEPA) as members. The Department of Energy of MoPE, with a dedicated Roadmap Implementation Coordinator, will provide the Secretariat to the Taskforce: convening meetings; taking minutes, providing briefing notes, and following up on decisions of the Task Force. Roadmap Implementation High Level task Force Source: Roadmap institutional arrangements report The main elements of the Roadmap are summarized in the table below. These include the Universal Access strategy and the accompanying transmission and distribution (T&D) and generation investments to support it, particularly Solar PV. Domestic supplies will be complemented by imports from the West African power Pool. The final key element of the Roadmap is institutional strengthening, particularly in NAWEC becoming an efficient and reliable supplier of power to the nation. xii Strategic Electricity Sub-sector Roadmap 2021 - 2040 Electricity Sector Roadmap summary 2021-2040 2021-2025 2026-2040 Sub-period Big push to achieve Electricity sector strategic Universal Access to consolidation: stable objectives electricity by 2025 supplies at lower tariffs Universal Access  Accelerate grid connection  Further densification, Strategy / DMP and grid densification building on Universal projects Access in 2025 Transmission • 225 kV Eastern Backbone for • Complete sub-stations at Master Plan Basse and strengthen Barra Bansang and Basse grid Domestic • Committed ICE & Solar PV • Continue with vigorous Solar generation projects and further 60 MW PV PV roll-out (250 MW by 20400 Importation of • Negotiate import PPAs with • Monitor imports contracts electricity Senegal and Cote d’Ivoire Institutional • NAWEC - implement Strategic • Capacity building to continue at strengthening Development Plan and meet the multiple levels within the energy Performance Contract Targets sector Roadmap • MoPE Roadmap Coordinator • Under Mope's leadership, Task implementation working with Roadmap Force to continue to provide Implementation Task Force momentum to the Roadmap AS regards financing, the main components of the Roadmap that are to be financed are the generation investments, the Universal Access projects and the associated T&D investments. The table below provides a summary broken down into 2021-2025 ($526 million) and 2026-2030 ($210 million). The overall total for the period 2020-2030 is $736 million. A large proportion of this is already financed through on-going national and regional projects sponsored by development partners. Financing Requirements Summary for 2020-2030 ($ million) Item 2020-2025 2026-2030 Total Source (1) Generation $225 m $125 m $350 m Private sector IPPs + NAWEC (2) On-going Universal $92 m $39 m $131 m GERMP, EREAP Access projects and GEAP (3) New Universal $66 m $29 m $95 m Donor and Access projects government financing (4) Gambian component $86 m $86 m Donor financing of OMVG project (5) Transmission $57 m $17 m $74 m NAWEC, donor projects financing Total $526 m $210 m $736 m Note: Generation and UA project costs are overnight capex (reported elsewhere in this report) plus 3% for design costs etc. GERMP, EREAP and GEAP financing goes beyond UA sub-components of these projects xiii Strategic Roadmap Summary Overview 1 Strategic Roadmap Summary Overview

1.1 A New Era for Gambia’s Electricity Sector The Gambia is poised to provide access to electricity for all its people. His Excellency, President Adama Barrow has stipulated that there is to be Universal Access by 2025. Given its unique geography, the country is fortunate in being able to achieve universal access almost exclusively through connections to the NAWEC grid. This Roadmap is the planning instrument designed to reach the President’s 2025 Universal Access target and at the same time to transform the electricity sector so that Gambians can in future benefit from reliable and affordable electricity, with NAWEC becoming an efficient, self-sustaining national power utility. Electricity is a catalyst for development. Universal Access will improve the lives of households which previously relied on inferior forms of energy, bringing immediate benefits in education and opening new opportunities for income-generating activities. Giving national priority to achieving Universal Access as early as 2025 is a far-sighted initiative which will enhance the country’s economic development as well as improving the quality of life of all Gambians. An important element in the overall transformation of the electricity sector during the Roadmap period (2021-2040) is the development of the regional electricity grid of the West African Power Pool (WAPP). This provides the opportunity for the Gambia’s electricity system to be reinforced with interconnections to its larger neighbours, and for the country to benefit from trade in electricity. This will deliver the following benefits: ● Technical benefits – frequency stability, security of supply through shared reserves ● Planning benefits – greater flexibility in developing generation projects ● Financial benefits – reduced investment and operational costs of meeting demand, improved utility viability and hence the opportunity for reductions in electricity tariffs. Within the wider economy, this will free up resources for investment in the productive sectors, leading to higher economic growth. Gambian industries will also be more competitive due to lower electricity tariffs.

1.2 Building on Recent Improvements in the Electricity Sector The first electricity sector Roadmap for The Gambia was produced in 2015, and partially updated in 2017. That update, together with the National Development Plan (2018-2021), helped to mobilise over $400 million in donor funding. Over the last 4 years there have been significant improvements in a number of key areas: ● More stable power supply replacing frequent blackouts (an average of 45 per month in 2018). 1 Strategic Roadmap Summary Overview ● Reduced transmission and distribution losses: technical and non-technical losses reduced from 28% in 2015 to 20% in 2020, largely through installing pre- payment meters. ● Least cost plan for orderly investments, reducing the heavy stream of unsolicited proposals. Preparations are underway for a competitive IPP process. The reduction in blackouts has been of direct benefit to NAWEC customers. The graph below shows the continuous decline in the number of system-wide blackouts in the great Banjul Area (GBA) since 2017. However, there have also been supply interruptions due to localised faults in the distribution network. Figure 1 GBA System-wide Blackouts (2017- May 2021) Source: World Bank Reduction in losses has allowed growth in sales of 8.5% per year, higher than the 7% per year growth in dispatched energy. With higher sales and improved revenue collection rate (particularly from public sector customers) NAWEC’s commercial performance has improved. NAWEC did not need direct subsidies from the Ministry of Finance & Economic Affairs (MOFEA) in 2019 or 2020. While NAWEC’s financial statements are still weak, through the NAWEC Strategic Development Plan (2019-2025) and the NAWEC / MOFEA Performance Contract (2021-2023) the basis has been laid to make progressive and sustained improvements in performance.

1.3 Roadmap for 2021-2040 Builds on Previous Sector Planning As already mentioned, the first electricity sector Roadmap for The Gambia was produced in 2015, and partially updated in 2017. This Roadmap is a thorough update, with the accompanying study having ten components that are shown in Figure 2 below. 2 Strategic Roadmap Summary Overview Figure 2 Components of the 2021-2040 Roadmap Study The different components are shown as discrete tasks, but in practice the work was often done in parallel and iteration was needed between the generation least cost planning and the T&D Master Plan to produce the final Least Cost Power Development Plan. It is important to emphasize that this update of the Roadmap is not just a consultancy output but is rather the outcome of an inclusive process involving the key Gambian institutions in establishing the assumptions to be used in the models, choosing the scenarios to be analysed and agreeing on the consultations and recommendations arising from the analysis. Particularly important in this regard are the commitments made to the implementation of the Roadmap (see Section 6.3). This Capstone Report is a synthesis of the technical work that was carried out. It includes sections describing the methodologies employed and giving the main assumptions, but the details of these are to be found in the preceding technical reports. These are listed in Annex A1.1.

1.4 Main elements of the 2021-2040 Roadmap As shown in the table below, the main elements of the Roadmap are the Universal Access strategy and the accompanying transmission and distribution (T&D) and generation investments to support it. Also significant is the development of the regional electricity grid of the West African Power Pool (WAPP), which provides the opportunity for the Gambia’s electricity system to be reinforced with interconnections to its larger neighbours, and to import low-cost bulk supplies. The final key element of the Roadmap is institutional strengthening, particularly in NAWEC becoming an efficient and reliable supplier of power to the nation. 3 Strategic Roadmap Summary Overview Table 1 Electricity Sector Roadmap 2020-2040 2021-2025 2026-2040 Sub-period Big push to achieve Electricity sector strategic Universal Access to consolidation: stable objectives electricity by 2025 supplies at lower tariffs Universal Access  Accelerate grid connection  Further densification, Strategy / DMP and grid densification building on Universal projects Access in 2025 Transmission • 225 kV Eastern Backbone for • Complete sub-stations at Master Plan Basse and strengthen Barra Bansang and Basse grid Domestic • Committed ICE & Solar PV • Continue with vigorous Solar generation projects and further 60 MW PV PV roll-out (250 MW by 20400 Importation of • Negotiate import PPAs with • Monitor imports contracts electricity Senegal and Cote d’Ivoire Institutional • NAWEC - implement Strategic • Capacity building to continue at strengthening Development Plan and meet multiple levels within the the Performance Contract energy sector Targets Roadmap • MoPE Roadmap Coordinator • Under Mope's leadership, Task implementation working with Roadmap Force to continue to provide Implementation Task Force momentum to the Roadmap The main elements of the generation and imports least cost plan for the period up to 2025 are shown in the diagram below. These are imports from WAPP partners (140 MW) and solar PV (80 MW), together with new thermal capacity (48 MW). Negative values over the period 2021- 23 are the end of the Karpower contract and retirement of old plants. 4 Strategic Roadmap Summary Overview Figure 3 Domestic Generation and Imports Least Cost Plan Source: Least Cost Generation Plan. This diagram makes cautious assumptions about commissioning dates of imports and domestic generation projects. Earlier commissioning would provide reserve capacity in 2022 but failing this the Karpower contract may have to be renewed for another year and/or retirement of antiquated domestic generation plant postponed. 5 Demand forecast 2 Demand forecast1 Statistics from NAWEC show that sent-out energy grew at an average rate of 11% per year from 2010 to 2018, reaching 341 GWh in 2018. Peak demand grew from 45 MW in 2017 to 65 MW in 2018. Historical energy and peak demand were constrained by generation and network shortages or outages. The 2025 Universal Access demand forecast in the Roadmap has energy sent out growing by 6.7% per year from 418 GWh in 2019 to 1,928 GWh in 2040. Over the same period maximum demand grows from 80 MW in 2019 to 333 MW in 2040. The Roadmap forecasts are derived from a model which forecasts demand separately for urban and rural households and for each of the major sectors of the economy. ● Household demand: is based on (1) changes in the number of electrified households, which is driven by the government’s electrification targets and (2) the consumption per household for urban and rural households. ● Other demand: Demand for the productive sectors of the economy is forecast by projecting changes in economic output for each sector and calculating energy demand using the sector energy intensity (energy use per unit of GDP). The model takes into account system losses to estimate sent-out energy and predicts peak demand by estimating a load factor for each year of the forecast using information on the load factor for each customer group and their contribution to the peak demand. Figure 4 Summary of Demand Forecast Modelling Source: Demand Forecast Report A second model provides the geographic forecast of the demand. Using GIS data, this model estimates the location of customers and forecasts the demand by area using the forecast number of customers by customer class and the forecast average consumption of each class. 1 Full details are available in the Demand Forecast Report. 6 Demand forecast

2.1 Demand Forecast Assumptions Table 2 summarises the main assumptions used to generate the demand forecast. The main drivers of the rapid growth that is forecast are GDP growth and a combination of population growth and rapid attainment of electrification targets. Average consumption per household is assumed to rise over time as higher incomes enable households to consume more electricity each month2. Table 2 Demand Forecast Assumptions Item Case F’cast: 2020 2025 2030 2035 2040 GDP growth rate Low case 4.4% 3.5% 3.5% 3.5% 3.5% (%) 2025 UA 4.4% 5.8% 5.8% 5.8% 5.8% High case 4.4% 5.8% 5.8% 5.8% 5.8% Population growth Urban 4.1% 4.0% 3.9% 3.8% 3.7% rate (%) Rural 1.4% 1.4% 1.4% 1.4% 1.4% Electrification Low case Urban 100% targets Rural 100% (% of households) 2025 Urban 100% Universal Access Rural 100% High case Urban 100% Rural 100% Average Low case Urban 124 128 129 130 131 consumption per Rural 66 68 69 69 70 household (kWh/month) 2025 Urban 124 161 175 191 207 Universal Access Rural 66 79 86 93 102 High case Urban 148 189 210 233 259 Rural 73 88 97 108 120 Network losses Low, 2025 UA case 22% 21% 18% 17% 15% (%) High case 22% 22% 20% 19% 18% Source: Least Cost Power Development Plan During the Roadmap process, there was considerable discussion about the assumptions to be used for average consumption per household. Following a sampling of customer data, the base figures agreed to by NAWEC and the MOPE for the demand forecast at the 2020 start of the projection period are shown in Table 3 below. 2 The growth in monthly household energy consumption is related to GDP growth via an elasticity. Details are provided in the Demand Forecast Report 7 Demand forecast The demand forecast takes into account the impact of COVID-19. Household consumption of electricity is expected to fall as a result of the pandemic. The primary reason for this is loss of income and lack of available cash as a result of slowing economic activity, lack of employment and a sharp reduction in remittances. A drop in average household consumption in 2020 has been factored into the forecast model. The modelling scenarios examined also reflect the range of possible post-pandemic recovery paths for household consumption: ● The low case assumes a slow recovery path with long lasting changes on the economy and the average consumption per household. ● The base case and 2025 Universal Access case assume a gradual rebound of the economy (and the average consumption per household) in 2021 and 2022 after the impact of COVID-19, with full recovery occurring in 2023. ● The high case assumes a quick rebound of the economy in 2021 after the impact of COVID-19, with full recovery occurring in 2022. The final assumptions on the average consumption per household with and without the implications imposed by COVID-19 pandemic are presented in the table above. Table 3 Average Consumption per Household – Demand Forecast Assumptions Forecast Forecast Forecast Forecast Forecast Forecast Item Unit 2020 2021 2022 2023 2024 2025 Average consum ption per household Low case - assum es a slow rebound of the econom y after the im pact of COVID-19. Average consumption per household kWh/month 119 121 122 123 123 123 Urban kWh/month 124 126 127 127 128 128 Rural kWh/month 66 67 68 68 68 68 Base case - assum es a gradual rebound of the econom y in 2021 and 2022 w ith full recovery in 2023. Average consumption per household kWh/month 119 128 138 147 149 152 Urban w ithout COVID-19 kWh/month 148 151 153 156 158 161 Rural w ithout COVID-19 kWh/month 73 74 75 76 78 79 Urban kWh/month 124 135 145 156 158 161 Rural kWh/month 66 69 73 76 78 79 High case - assum es a quick rebound of the econom y in 2021 w ith full recovery occurring in 2022. Average consumption per household kWh/month 142 155 168 171 174 177 Urban w ithout COVID-19 kWh/month 170 174 177 181 185 189 Rural w ithout COVID-19 kWh/month 79 81 82 84 86 88 Urban kWh/month 148 163 177 181 185 189 Rural kWh/month 73 78 82 84 86 88 Source: Least Cost Power Development Plan Perspectives from the Willingness to Pay Survey3 A Willingness to Pay Survey was conducted to ascertain the willingness to pay (WTP) for electricity services of different categories of present and future customers. In the survey, four groups were assessed: households connected and not connected to the grid and businesses connected and not connected to the grid. Households connected to the grid are largely urban households. Their average monthly consumption, calculated from reported monthly expenditure and the prevailing tariff of 9.9 Dalasi per kWh, is shown in Table 4 below. 3 Details are available in the Willingness to Pay Survey Report. 8 Demand forecast Table 4 Current Household Monthly Consumption of Grid Electricity Monthly electricity Monthly consumption Area expenditure (Dalasi) (kWh per month) Urban 1,784 90 Rural 1,152 58 Total 1,719 87 Source: WTP survey The monthly consumption figures for urban and rural households are lower than those agreed for the demand forecast. This was justified in terms of customers presently consuming less than they would like to due to frequent interruptions in supply. For these customers, the WTP questions were about how much more they would be willing to pay for an improved level of service from NAWEC. The survey found that household customers would be willing to pay 11% more while business would be willing to pay 16% more for an improved level of service. Households which do not currently have electricity, which are mainly rural households, were asked about their willingness to spend on average 351 Dalasi per month (3% of their income) for basic electricity services (enough for lights, phone charging, and radio) and 2,850 Dalasi (24% of their income) for additional electricity services (enough for lights, phone charging, fan, small TV and refrigerator). On a unit cost basis, WTP was similar between basic and additional levels of services. Non-connected households were willing to pay 25.0 Dalasi/kWh for basic services and 26.0 Dalasi/kWh for additional services. However, asking respondents about a hypothetical situation they are not familiar with (having access to electricity) is problematic. There may have been an upward bias in the responses, because the results for households not currently connected translating into an implausibly high proportion of mean monthly income.

2.2 Demand Forecasts adopted for the Roadmap The main output of the demand forecast that is required for the load forecast is the sent-out energy (GWh) and maximum demand (MW). The tables and graphs below summarise these figures on a five year interval (year-by-year forecasts are available in Annex A2) with the central case being the demand associated with achieving Universal Access in 2025. The annual average growth rates (AAG) are calculated from a regression formula. 9 Demand forecast Figure 5 Revised Energy Demand Sent-out Forecast 3,000 Energy demand forecast (GWh) 2,500 2,346 2,000 1,787 1,358 1,928 1,500 964 1,498 920 1,000 504 1,162 1,217 418 996 500 813 854 658 406 0 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Initial Low Initial Base Initial High COVID-19 New Low COVID-19 New Base COVID-19 New High COVID-19 2025 Universal Access Source: Demand Forecast Report Table 5 Revised Energy Demand Sent-out Forecast (GWh) Year COVID-19 New Low COVID-19 2025 UA COVID-19 New High 2020 406 451 504 2025 658 920 964 2030 813 1,162 1,358 2040 1,217 1,928 2,346 AAG 2019-2040 4.9% 6.7% 7.6% Source: Demand Forecast Report 10 Demand forecast Figure 6 Revised Peak Demand Forecast 450 411 400 Peak demand forecast (MW) 350 327 300 258 333 250 190 180 271 200 104 218 150 166 211 179 100 80 126 151 50 84 0 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Initial Low Initial Base Initial High COVID-19 New Low COVID-19 New Base COVID-19 New High COVID-19 2025 Universal Access Source: Demand Forecast Report Table 6 Peak Demand Forecast (MW) Year COVID-19 New Low COVID-19 2025 UA COVID-19 New High 2020 84 93 104 2025 126 180 190 2030 151 218 258 2035 179 271 327 2040 211 333 411 AAG 2019-2040 4.3% 5.9% 6.8% Source: Demand Forecast Report

2.3 Geospatial Breakdown of Forecast Demand The geospatial forecast allows for a granular view of demand by regional electricity systems and customer type. The tables below show our estimate of this distribution for electricity demand in 2030 in both energy and maximum demand terms. These estimations represent the final electricity sales, and do not account for losses in transmission and distribution, and hence are different to the sent out forecasts. The Greater Banjul Area (GBA) accounts for around 80% of total national demand. 11 Demand forecast Table 7 Energy Demand Forecasts by Region with Universal Access in 2025 Year Unit Barra Basse Farafenni GBA Total 2020 GWh 11 15 21 305 352 2025 GWh 22 60 41 600 724 2030 GWh 30 117 53 753 953 2020 % of total 3% 4% 6% 87% 100% 2025 % of total 3% 8% 6% 83% 100% 2030 % of total 3% 12% 6% 79% 100% AAG % pr year 11% 24% 10% 10% 11% Source: Transmission and Distribution Master Plan and Universal Access Strategy Table 8 Maximum Demand Forecasts by Region with Universal Access in 2025 Year Unit Barra Basse Farafenni GBA Total 2020 GWh 3 4 5 77 89 2025 GWh 6 15 10 149 180 2030 GWh 7 27 12 172 219 2020 % of total 3% 4% 6% 87% 100% 2025 % of total 3% 8% 6% 83% 100% 2030 % of total 3% 12% 6% 79% 100% AAG % pr year 10% 22% 9% 9% 10% Source: Transmission and Distribution Master Plan and Universal Access Strategy

2.4 Daily Load Curves For generation planning, where different types of plant are to be despatched in merit order, it is necessary to have the load profiles, that is the variation in demand for power (measured in MW) over the course of typical days. The load profiles used in this Roadmap (Figure 7) are those that presently apply in GBA. 12 Demand forecast Figure 7 GBA Daily Load Curves and Patterns of Dispatch Source: Demand Forecast Report 13 Universal Access Strategy and T&D Master Plan 3 Universal Access Strategy and T&D Master Plan

3.1 Universal Access and Distribution Planning As highlighted in Section1, The Gambia is fortunate in having the opportunity to achieve universal access to electricity by 2025. The approach adopted to derive the least cost universal access plan is summarised in Figure 8. The Reference Electrification Model (REM) is a powerful GIS- based planning tool used to determine the mix of on-grid and off-grid systems that meets the forecast electricity demand and provides access to all unelectrified customers at the lowest economic cost. The off-grid options considered are mini-grids and individual off-grid systems (solar home systems for households and stand-alone generators for productive or commercial enterprises). Figure 8 Approach to Derive the Least Cost Universal Access Plan Source: Transmission and Distribution Master Plan and Universal Access Strategy The least cost electrification results of the REM model confirm that there is a clear mandate for The Gambia to achieve universal access through grid extension projects. ● In the least cost solution, 98% of the overall unelectrified customers should be connected to the grid ● average per customer CAPEX cost for densification is $500 and for the proposed grid extensions is $1,230; off-grid costs per customer are much higher. ● electrifying all customers via grid interconnection would add only $4 million to the costs, and this small cost extension is more than compensated for by avoiding the 14 Universal Access Strategy and T&D Master Plan costs of establishing implementation mechanisms for a very small number of off- grid customers (412 individual systems and 1 mini-grid). Although the REM model was run with a 2030 time horizon, it is appropriate to anticipate 2030 requirements by adopting the same infrastructural investment plan for 2025, the Universal Access target year. The infrastructural investment costs to 2025 are shown in Table 94. The total to 2025 is $63.5 million5. To cater for population growth in the period from 2026, a further $28 million will need to be invested in grid densification up to 2030. Table 9 Summary of Universal Access Costs through 2025 (REM simulation results) Indicator New Grid Grid Unit Total Extensions Densification Number of new customers Number of 18,995 67,000 86,564 households Fraction of New Customers 0.22 0.78 1 Cost of Demand Served $/kWh 0.28 0.15 - Total CAPEX $m 30.0 33.5 63.5 Total OPEX $ m/yr 5.1 - - Avg. OPEX $/yr/customer 271 - - Avg. CAPEX $/customer 1,583 500 - Source: Transmission and Distribution Master Plan and Universal Access Strategy These results are based on estimates of the numbers of customers to be connected by 2025 to achieve Universal Access and the densification6 that will be needed between 2025 and 2030 to cater for population growth (at an estimated 2.9% per year). The cumulative existing and new customers in 2025 and 2030 are summarised in Table 10 below. Table 10 Existing and New Customers to have Access by 2025 and by 2030 Customers Estimated Estimated New New Customers Total Existing Existing Customers Grid Extension Potential Customers Customers Densification or Off-Grid Customers 2019 2020 By 2025/30 By 2025/30 (2025/30) Total - 2025 204,036 224,211 137,000* 18,995 380,206 Total - 2030 204,036 224,211 194,960* 18,995 438,166 Source: Transmission and Distribution Master Plan and Universal Access Strategy Note: *This includes 70,000 new customers to be electrified through ongoing access projects. As indicated in the table, around half of the new densification customers by 2025 are already scheduled to be connected through on-going grids access projects. These are: 4 In this report, costs are reported in USD and all references to dollars ($) and cents are USD and cents of the USD respectively. The common units used for LCOE are c/kWh and $/MWh. 5 In Table 23, an allowance of 3% is added to this base cost to cover design etc. 6 Customers who are less than 2 km away from the current infrastructure are considered for grid densification. 15 Universal Access Strategy and T&D Master Plan ● Gambia Electricity Restoration and Modernization Project (GERMP) funded through IDA, EIB and EU – completion 2022 ● The Gambia Electricity Access Project (GEAP) funded through AfDB – completion 2023 ● ECOWAS Regional Electricity Access Project (EREAP) funded through IDA – completion 2023 The distribution of sites (numbering 776 in total) across the regions for these three projects and the additional grid extensions needed to reach Universal Access in 2025 is shown in the table and map below. Table 11 Distribution of Sites by Region of the GERMP, REAP and GEAP Projects Sites electrified Sites electrified Sites electrified Sites electrified Region through GERMP through GEAP through EREAP through REM (IDA/EIB/EU 2022) (AfDB, 2023) (IDA, 2023) projects (2025) GBA - 8 95 25 Basse 208 27 56 43 Farafenni - 71 95 29 Barra 60 - 51 2 Other 5 1 - TOTAL 273 107 297 99 Source: Transmission and Distribution Master Plan and Universal Access Strategy Figure 9 Electrification Projects to Achieve Universal Access by 2025 Source: Transmission and Distribution Master Plan and Universal Access Strategy The grid extensions are to be made at the same time as multiple different MV networks are being integrated. As is elaborated in the next section, there is need for a high voltage transmission line to act as an Eastern backbone both to cater for growth in demand in Basse and to support the rapid electrification and universal access projects. 16 Universal Access Strategy and T&D Master Plan

3.2 Transmission Planning The existing electricity network in The Gambia consists of a number of separate 33 kV and 30 kV systems fed from local power plants throughout the country. On-going projects are developing the transmission grid to interconnect these systems and establish interconnections with neighbouring systems. The main project is the regional 225 kV OMVG7 grid (discussed in Section 4.3) which will interconnect The Gambia with Senegal and other countries in the region and constitutes the critical first step in the development of a full transmission grid in the country. ● The interconnection with Senegal will provide a link with a high capacity for power purchases from Senegal and other power providers throughout the region. ● The Soma 225/30 kV substation will connect to the planned 225 kV line running from north to south in the central part of The Gambia. A double circuit 225 kV line will be added from the Soma substation to a new 225/33 kV substation at Brikama. This substation will be integrated with the existing 33 kV system at Brikama and will provide support to the system in Banjul. ● An on-going NAWEC project (started in mid 2021 for completion by the end of 2022) will add a 225 kV line from Brikama to Jabang. This will feed a new, centrally located 225/33 kV substation in Banjul. It is part of a contract which will construct a National Control Centre and SCADA. The existing and committed networks are shown in the map below. Figure 10 Existing and Committed Network (main lines only on MV grid) Source: Demand forecast report An extension of the transmission network to Bansang and Basse is needed to support load growth in these centres and would also provide supply and voltage support to the extended MV network being developed in the Basse region through the Universal Access Plan. For security of supply in the region and for the 2025 Universal Access targets to be met, this Eastern transmission backbone needs to be in service by 2025. To mitigate the risk of delays, there 7 The Gambia River Basin Development Organisation (OMVG – Organisation pour la Mise en Valeur du Fleuve Gambie). 17 Universal Access Strategy and T&D Master Plan needs also to be a contingency plan involving local generation being developed to provide adequate capacity and voltage support. Different voltage levels and configurations have been discussed for the Eastern transmission backbone. An important recommendation from the Roadmap transmission study is that a full feasibility study needs to be conducted as a matter of urgency. This should consider: ● Alternative voltage levels: deploying the same voltage as the 225 kV GBA/OMVG system is the obvious option, but 132 kV should also be analysed. Previously a lower voltage has been proposed, but 66 kV is not suitable for the expected level of demand. ● Alternative configurations: assuming 225 kV is selected, small 225/30 kV substations at Bansang and Basse will be required. These could be interconnected with Soma, or with Tambacounda, or both, or could be fed from the Tambacounga- Kolda transmission line. The options involving Senegal would provide links for further integration of the power systems in the WAPP region. ● Contingency plans to ensure Universal Access in 2025:, if there are delays in developing the Eastern Backbone capacity, voltage support in Basse would need to be provided from local generators. Various options should be considered in the feasibility study, including leasing thermal generators and/or increasing the capacity and adding batteries to the solar PV plants scheduled to be developed in the Eastern part of the country by 20258. Consideration would also need to be given to the design of the PV inverters so that some reactive power support can be provided even when active power output is zero. Supply to the Barra region will also become difficult unless imports via the MV grid from Senegal are continued. Alternatives which also need to be examined by a second (or else combined) feasibility study are: ● Development of a 225 kV link from Senegal in a western corridor may provide an option for a 225/30 kV substation in the area, possibly developed to support both the MV grid in The Gambia and in areas across the border in Senegal. ● Reinforcement of the MV grid from Farafenni or via a cable across the river from Banjul are alternatives that may be considered if the western corridor does not present a viable solution. Transmission developments in The Gambia should be considered in relation to regional options. To ensure optimal regional development, it is important for there to be coordination of the on- going or proposed regional studies, which include Basse-Tambacounda, Brikama-Ziguinchor and Brikama / Jabang / Kotu-Kaolack. The detailed analysis and the timing of the transmission developments need to be confirmed through the feasibility studies, but the recommendations at this juncture are to add a 225 kV line from Soma towards Basse and build two new, small 225/30 kV substations in the east – one at 8 Solar PV projects in the base case of the least cost generation plan are Basse NAMA 6.5 MW by 2022; Bansang 2 MW in 2022 rising to 5 MW by 2026 (this could be targeted earlier if the Eastern Backbone is delayed); N’Joben 5 MW from 2022 and the IDB projects, 3 MW at Njaw and 2 MW at Nyanga Batang, both due in 2025. About 10 MW in total would be needed in Bansang and Basse by 2025 and 10-11 MW in Bansang and 15 MW in Basse by 2030. 18 Universal Access Strategy and T&D Master Plan Bansang and one at Basse. Furthermore, to increase the reliability of supply in the Banjul area, the second circuit on the 225 kV line from Brikama to Jabang should be added. The expected timing and costs of these projects are summarised in the table below. Table 12 Transmission Development Plan Investment Cost per year (total $74.3 m) Project 2024 2025 2028 2029 2030 225 kV Soma – Bansang – Basse $ 22.8 m $ 34.3 m - - - 225/30 kV substations in the Barra region - - $ 4.4 m $ 6.7 m - nd 2 circuit on the 225 kV line Soma – Bansang - - - - $ 6.1 m Source: Technical Reports. Transmission investments to be finalised via detailed feasibility studies. 19 New Electricity Supply Options 4 New Electricity Supply Options The electricity system in The Gambia is composed of four individual networks: ● GBA System - the GBA is supplied by two large power stations in Kotu and Brikama and has one common transmission and distribution network. It is also currently supplied by rented electricity generators. ● Three isolated grids (Basse, Barra and Farafenni) in the provinces – Basse and Farafenni provinces are supplied by NAWEC owned power stations and their respective microgrids. Barra is supplied via an interconnector with Senegal. An interconnector with Senegal also supplies the Farafenni region. The following map depicts the four systems in The Gambia, the location of the power stations and the existing 33kV, 30kV and 11kV networks. As described in the previous section, transmission linkages will create a unified national network by 2022-23. Figure 11 Existing Power Plants Map Source: Least Cost Power Development Plan As of mid 2021, the total net installed capacity in The Gambia is 154.5 MW of reciprocating engines, but only 97.0 MW are currently available for power generation. Of the reciprocating engines, 67.0 MW of available capacity are NAWEC owned. The remaining 30 MW are rented under a contract with Karpower that was due to expire in 2020 but has been extended for two more years. In previous electricity master plans for The Gambia, generation options have been essentially limited to investing in domestic generation plants that would use imported liquid fuels, predominantly heavy fuel oil (HFO). The update of the Roadmap represents a major departure in making it possible as candidate generation projects a number of different technologies. A variety of generation options were discussed with NAWEC and key stakeholders as candidate power plants for consideration in the generation plan. The final technologies that were selected as candidates for the least cost generation plan are summarised in the table below. 20 New Electricity Supply Options Table 13 Examination of Candidate Power Plant Options Candidate Operating Comment options fuel Generic LNG An analysis summarising candidate CCGT and OCGT options CCGT and operating with LNG is presented in Sections 4.2 and 5.2. Generic OCGT CCGT (LNG) candidate power plants were included as candidate options in the analysis with the costs of the gas infrastructure attached to the development of the candidate power plant option. Generic LFO OCGTs (LFO) were excluded from the analysis as they were OCGT considered by NAWEC inadequate technologies for The Gambia. Generic Waste The Gambia is considered to have approximately 25 MW of Biomass potential biomass capacity with the primary fuel being waste9. However, biomass candidate power plants were excluded from the analysis as they were considered by NAWEC inadequate technologies for The Gambia. Generic Wind Wind The potential of wind capacity in The Gambia is estimated to be approximately 197 MW with a capacity factor below 20% and 5 MW with a capacity factor higher than 30%10. Generic wind farms were included in the least cost planning analysis and were modelled in blocks of 3.6 MW. Generic Solar Solar The analysis of candidate Solar PV projects was summarised in PV Section 4.1. The final list of candidate Solar PV projects is shown in Section 5.2. The capacity of Solar PV presented for each project is the maximum available capacity in the identified area. The modelling approach that was followed allows the model to select the least cost capacity that should be developed in each area up to the maximum capacity available. Generic n/a Two types of batteries were considered as suitable options for The battery Gambia power system. The analysis focused on Li-on battery systems which can provide peaking capacity for at least 4-6 hours and for batteries ranging from 1-10 MW. The maximum capacity of batteries that could be developed was left unconstrained in the modelling approach. Source: Least Cost Power Development Plan The main new options are solar photovoltaic (PV), natural gas and importation options. The sub- studies on each of these options are briefly summarised in the sub-sections below.

4.1 Solar Photovoltaic11 The Gambia has significant solar energy resources which can be deployed via solar PV plants, which have become price competitive with thermal plants and attractive for advancing national renewable energy and greenhouse gas (GHG) reduction targets. IRENA (2018) has estimated national solar potential at 428 MW. The base case of the Roadmap includes 13 solar projects with a total capacity of 250 MW. 9 Source: Update of the ECOWAS revised master plan for the development of power generation and transmission of electrical energy Final Report, 2018 10 Source: Update of the ECOWAS revised master plan for the development of power generation and transmission of electrical energy Final Report, 2018 11 Details are available in Section 3 of the Least Cost Power Development Plan. 21 New Electricity Supply Options The identification of potential sites for solar PV projects started with progressively narrowing the options by considering areas which need to be excluded due to high population densities, environmental sensitivity, protected areas (such as national parks) or unsuitability (steep elevations and slopes). Solar development zones were then grouped and sites ranked using a multi-criteria analysis of key attributes (site location, land-use, generation potential, cost estimates, environmental factors, and other constraints). The costs were based on the levelised cost of energy (LCOE) approach. A total of 16 sites were identified which are shown on the map and in Table 14 below. Figure 12 Map of Identified and Proposed Solar Sites from Solar Mapping Analysis Source: NAWEC, ECA, Waya, 2020. Map produced by Waya Table 14 Solar Generation Sites identified for Generation Planning Analysis # Site Name Potential LCOE Status Comments capacity ($/MWh) (MW) 1 Z-One 10 83 On hold On hold currently. No expected (Jambur) completion date. 2 World Bank 20 83 Land Feasibility study completed and (Jambur) Reserved procurement process launched. 3 Solar Park 80 + 70 81 Land Identified Feasibility study begun in April 2020. (Soma) 4 Farafenni 4 82 Land Identified 200 m x 400 m area of land to be Project developed for solar PV. (NAMA) 5 Bansang 5 81 Land Identified Included in past land banking. Project 6 Basse Project 6.5 82 Land Identified Included in past land banking. (NAMA) 7a Islamic 5 81 Land Identified 5 MW to be split between two nearby and Development sites in Njaw and Nyanga Bantang. This 7b Bank project is designed to relieve some voltage drop in the system. 8 Bwiam 20 82 NAWEC Site selected based on multi-criteria Proposed Site scoring. 9 Barra/Essau 15-20 82 NAWEC Near the Barra generation station. Proposed Site Potentially 15-20 MW available. 22 New Electricity Supply Options # Site Name Potential LCOE Status Comments capacity ($/MWh) (MW) 10 Farfenni – 64.3 82 ECA / Waya Site selected based on multi-criteria East Proposed scoring. Site 11 Njaba Kunda 107.7 87 ECA / Waya Site selected based on multi-criteria Proposed scoring. Site 12 N’Joben 5.0 81 ECA / Waya Site selected based on multi-criteria Proposed scoring. Site 13 Soma – West 104.2 82 ECA / Waya Site selected based on multi-criteria Proposed scoring. Site 14 GBA – East 56.2 84 ECA / Waya Proposed site in GBA area due to Proposed proximity to substation. Site is Site proposed on the western outer area of the metro area. 15 Basse – 22.8 84 ECA / Waya Site selected based on multi-criteria North Bank Proposed scoring. Site Total 595 Source: NAWEC, ECA, WB, Waya, 2020. List produced by Waya The above candidate options were assessed in the least cost planning simulation to determine which of the above options are part of the least cost generation plan. Of the 16 sites, only Njaba Kunda (#11) and Soma West (#13) were not chosen for inclusion in the least cost plan. The remaining 14 sites were consistently chosen across the different scenarios and these constitute the final list of solar sites for land banking activities.

4.2 Gas to Power12 The discovery of significant deposits of natural gas off the coast of The Gambia and Senegal has opened up new opportunities to use natural gas to generate power. Although still a fossil fuel, gas has far lower GHG gas emissions per GWh generated as compared with HFO and diesel. So far the gas that has been found is all in Senegalese waters, but if in future The Gambia secures its own natural gas, there would be the added advantage of using a domestic resource. 12 Details are available in Section 4 of the Least Cost Power Development Plan. 23 New Electricity Supply Options Figure 13 Gambia-Senegal Off-shore Gas Fields Source: Least Cost Power Development Plan In the Roadmap process, four possible gas-to-power routes were explored and the LCOE for each option calculated: ● Option ❶: Gas-to-power imports from Senegal, specifically a 400 MW CCGT power plant in Senegal (LCOE = 84.5 $/MWh) ● Option ❷: Domestic gas, utilised for domestic a 50 MW CCGT power plant (LCOE = 91.9 $/MWh) ● Option ❸: LNG imports via an onshore LNG regasification terminal, the gas being used for a 50 MW CCGT power plant in The Gambia (LCOE = 123.9 $/MWh) ● Option ❹: LNG imports via a floating LNG regasification terminal, the gas being used for a 50 MW CCGT power plant in The Gambia (LCOE = 139.9 $/MWh) The LCOEs above are based on assumptions for base load power in 2030 and they show that the preferred gas to power option is imports from a medium sized CCGT plant in Senegal. This conclusion remains robust in sensitivity tests on a range of parameters. The main drivers for the cost differentials that favour Option 1 are (i) economies of scale for larger CCGTs in Senegal, (ii) greater efficiency of larger CCGTs and (ii) no gas or LNG related investment cost. 24 New Electricity Supply Options Figure 14 LCOEs for Gas-to-Power Options Source: Least Cost Power Development Plan. FSRB = Floating storage and regasification barge Besides being the least cost option, importation from Senegal is the most flexible option in terms of daily offtake and future unknown developments. It also requires the lowest levels of upfront investments. The option does however rely on Senegalese power generation policy and development, which is a risk.

4.3 Import Options13 Deepening regional power sector integration has long been an objective of the Economic Community of West African States (ECOWAS). Working with the West African Power Pool (WAPP), the Gambia River Basin Development Organization (OMVG) and the ECOWAS Regional Electricity Regulatory Authority (ERERA), the completion and synchronisation of the regional grid is now imminent. The interconnectors of relevance to The Gambia are: ● OMVG network – to be completed in 2nd half of 2022  225 kV single-circuit line running through The Gambia  350 MVA capacity; likely to become constrained by late 2030s but OMVG Loop- West added in early 2030s ● CLSG network (Cote d’Ivoire-Liberia-Sierra Leone-Guinea network which is scheduled to interconnect with OMVG in 2021) 13 Details are available in Section 5 of the Least Cost Power Development Plan. 25 New Electricity Supply Options  Opportunity for The Gambia to import from Cote d’Ivoire and other WAPP countries with low cost generation The immediate significance of the regional interconnectors is for The Gambia to import electricity, but they also open up the opportunity to export. Given its central location and excellent solar resources, The Gambia has been chosen as the first site for a regional solar PV generation facility (a feasibility study is underway of the 150 MW Soma Park project identified in Section 4.1). Figure 15 Regional Interconnectors opening Electricity Trade Opportunities Source: ECOWAS Masterplan 2018 Import options that are treated as committed or candidate options in the least cost generation modelling are as follows14: Kaleta and Souapiti hydropower plants: ● the PPA is signed – this is committed ● 204 GWh is the firm (guaranteed) annual energy available (the amount delivered to The Gambia will be less because of transmission losses) ● This is assumed to be a take-and-pay agreement ● Expected to be commissioned in the second half of 2022 ● The price per kWh is 10.7 cents/kWh rising to 15 cents/kWh by 2041 ● The energy will be supplied to NAWEC proportional to NAWEC’s annual load profile. 14 Other options considered (128 MW Sambangalou hydro in Senegal, imports from the WAPP short-term market and solar PV in other countries, possibly co-owned by The Gambia) were considered not sufficiently dependable to be treated as candidates at this juncture. 26 New Electricity Supply Options Gas-fired CCGT plant in Senegal: ● This option was shown in the previous sub-section to be the least cost Gas-to-Power option for The Gambia ● Working assumption is that the contractual arrangement would be a power purchase import contract, but a joint venture has also been suggested, with NAWEC investing in dedicated capacity of say 50-100 MW in the short to medium term. ● Available from start of 2024. Gas-fired CCGT plant in Cote de ‘Ivoire: ● Importing power from Cote d’Ivoire is characterised in the same way as for those from Senegal (i.e., similar gas price, the same capital and operating costs and the same heat rates). ● Transmission costs will be higher than imports from Senegal. ● Available from start of 2023. The main risks associated with the import options are summarised in Table 15 below. In view of import risk, the Government has set a limit of 50% on import capacity. This limit is incorporated in the Base scenario of the least cost plan, but alternative import constraint scenarios are also analysed. Table 15 Import Risk Matrix Option Planning risks Implementation risks Operational risks Kaleta / n/a n/a  Timing of Souapiti hydro commissioning of (Guinea) Souapiti  OMVG transmission capacity (potentially mitigated with terms in transport agreement)  Energy not needed by NAWEC when it is available from EDG  EDG dumping surplus on NAWEC when rains are good and reducing production in other years without penalties Sambangalou  Status unknown  When will a draft PPA be  Timing of hydro available? At what time commissioning (Senegal) of year will the energy be available?  OMVG transmission capacity (potentially  How long will it take to mitigated with terms in negotiate a PPA? transport agreement)  Will the PPA price be  Energy not needed by reasonable? NAWEC when it is available from Senegal (potentially mitigated with PPA terms) 27 New Electricity Supply Options Option Planning risks Implementation risks Operational risks Gas-fired  Will Senegal decide to  When will a draft PPA be  Gas will be prioritised for power plant move ahead with a available? alternative uses (LNG) (Senegal) feasibility study, and  How long will it take to  Grid stability in The when? negotiate a PPA? Gambia will constrain  Will Senegal or the IPP  Will the PPA price be imports wish to consider selling reasonable? some of the output to The Gambia at a price that is acceptable to The Gambia? Power from  When will the power be  Low risks in relation to  CI Energies is gas-fired available? the PPA because CI experienced at exporting power plants in  Will there be bottlenecks Energies is experienced, power and it is therefore Cote d’Ivoire on the transmission path and CI Energies should unlikely to default on to The Gambia be able to indicate an PPA obligations via CI Energies export price transparently  Grid stability in The Gambia will constrain imports Source: Least Cost Power Development Plan 28 Generation Least Cost Plan 5 Generation Least Cost Plan

5.1 Least Cost Generation Planning The objective of the generation least cost plan is to establish the long term generation plan that meets the forecast electricity demand at the lowest economic cost, given policy and reliability targets. The plan establishes the mix of import contracts and new generation capacity that results in the lowest cost in present value, real terms. The methodology that is used is illustrated in Figure 16. The least cost planning software used for the current Roadmap update is PLEXOS. Least-cost generation development plans for any power system are prepared by identifying a set of candidate plants and supply options and assessing the present value of costs (capital, fuel and operating costs) of alternative sequences and combinations of investments that satisfy demand over the planning horizon (to 2040) at a given level of reliability (15% reserve margin). Figure 16 Least Cost Development Plan Methodology Source: Least Cost Power Development Plan The Gambia’s power sector will soon need additional generation capacity to be able to cover the forecast demand. A gap between available capacity and peak demand is identified from 2022 with the expiration of the Karpower contract and by 2025 nearly 140 MW of new capacity will be needed. This is illustrated in Figure 17 below which compares the forecast peak demand for Universal access in 2025 against the total existing available capacity (after the deduction of scheduled retirement of existing units. 29 Generation Least Cost Plan Figure 17 Existing Available Capacity vs 2025 UA Peak Demand 250 Senegal imports Existing firm capacity vs Peak 200 180 Existing Basse 167 154 150 135 Existing Farafenni Karpower demand (MW) 50 86 126 139 100 85 Existing Kotu 68 50 41 41 Existing Brikama II 0 Existing Brikama I 2020 2021 2022 2023 2024 2025 Source: Least Cost Power Development Plan The addition of committed power plants to the system will provide enough capacity to meet forecast peak demand until 2023. The main risk in relation to the materialisation of committed capacity is the availability of OMVG for the imports from Guinea. The gap between existing (after the deduction of scheduled retirement of existing units) and committed available generation capacity and the forecast peak demand will still be of the order of 100 MW in 2030.

5.2 Existing, Committed and Candidate Power Plants The following tables summarise the list of existing, committed and candidate power plants that are considered in the least cost planning simulations together with their technical characteristics and assumed costs. Table 16 Existing and Committed Power Plants Assumed Commissioning Forced Outage Maintenance Power plant Available Heat rate Installed System Type Fuel decommissionin Status Unit capacity capacity Rate Outage rate g MW MW kJ/kWh % per year Year Existing power plants Rehabilitation Kotu 1 GBA ICE LFO 3.2 0.0 - - - 1981 - pending Decom- Kotu 2 GBA ICE LFO 0.0 0.0 - - - 1981 - missioned Rehabilitation Kotu 3 GBA ICE HFO 3.4 0.0 - - - 1997 - pending Kotu 4 GBA ICE HFO 6.4 5.5 8,480 11% 11% 2001 2023 Existing Kotu 5 GBA ICE HFO 12.1 11.0 8,200 16% 9% 2018 2043 Existing Kotu 6 GBA ICE HFO 6.4 5.0 8,505 16% 11% 1989 2023 Existing Kotu 7 GBA ICE HFO 6.4 5.0 8,440 7% 11% 2001 2024 Existing 30 Generation Least Cost Plan Assumed Commissioning Forced Outage Maintenance Power plant Available Heat rate Installed System Type Fuel decommissionin Status Unit capacity capacity Rate Outage rate g MW MW kJ/kWh % per year Year Kotu 8 GBA ICE HFO 6.4 5.0 9,200 16% 11% 2018 2030 Existing Decommissio Kotu 9 GBA ICE HFO 0.0 0.0 - - - - - ned in 2009 Brikama I 1 GBA ICE HFO 6.4 5.5 8,760 16% 11% 2006 2024 Existing Rehabilitation Brikama I 2 GBA ICE HFO 6.4 0.0 - - - 2006 - pending Brikama I 3 GBA ICE HFO 6.4 5.5 8,760 16% 11% 2006 2024 Existing Brikama I 4 GBA ICE HFO 6.4 5.5 9,080 16% 11% 2006 2024 Existing Brikama I 5 GBA ICE HFO 6.4 5.5 8,212 16% 11% 2013 2024 Existing Rehabilitation Brikama I 6 GBA ICE HFO 6.4 0.0 - - - 2013 - pending Brikama I 7 GBA ICE HFO 6.4 5.5 8,760 16% 11% 2018 2030 Existing Brikama II 1 GBA ICE HFO 8.9 8.5 7,360 16% 12% 2018 2038 Existing 2nd half of Existing Karpower 1 GBA ICE HFO 18.9 15.0 8,800 - - 2018 2022 Rented 2nd half of Existing Karpower 2 GBA ICE HFO 18.9 15.0 8,800 - - 2018 2022 Rented Farafenni 1 Farafenni ICE HFO 4.8 4.8 7,400 7% 15% 2018 2038 Existing Bansang 1 Bansang ICE LFO 1.2 0.3 8,610 16% 15% 2018 2038 Existing Basse 1 Basse ICE HFO 5.4 5.4 7,400 7% 15% 2016 2036 Existing Total 147 108 Source: NAWEC, the 2017 Road Map Update, the World Bank and the 2019 ECOWAS master plan. ECA analysis in consultation with NAWEC and key stakeholders. Power plant Type of Earliest Fixed O&M Available Annual Heat rate year Variable Fuel FOR MOR il bl Capex capacity O&M name power plant generation Decommis- sioning kJ/kW % per % per $/kW/ $/MW MW GWh h yr yr $/ kW yr h Committed PPA for imports with Imports Hydro 40 204 - - - 2022 - - - - EDG Brikima III ICE HFO 18.4 - 7,360 16% 12% 2021 2041 1,019 0.007 10.0 Jambur Solar Solar PV Solar 20 32.9 - - - 2022 2047 980.5 27.3 0 PV WB Jambur Battery 6 (6 Battery Li-on - - - - 2022 3037 1,937 10.7 0.3 WB MWh) ICE 30 MW ICE HFO 30 - 9,095 10% 7% 2022 2042 1,019 18.5 10.0 Source: NAWEC, the 2017 Road Map Update, the World Bank and the 2019 ECOWAS master plan. ECA analysis in consultation with NAWEC and key stakeholders. The list of candidate options was agreed after extensive discussions between NAWEC and key stakeholders. Candidate options that were considered in the analysis include solar PV, gas fired power plants and import options, generic batteries, generic internal combustion engines (HFO) and generic wind farms. 31 Generation Least Cost Plan Table 17 List of Candidate Power Plants Available Heat rate Power plant name Decommissioning Variable Capex Fixed capacity FOR MOR O&M Earliest year O&M Type Fuel MW kJ/kWh % per yr available $/ kW $/kW/yr $/MWh Candidate Soma Solar Park I+II Solar PV Solar 80 + 70 - - - 2022 2042 981 27.3 0 Farafenni NAMA Solar PV Solar 4.0 - - - 2022 2042 994 27.3 0 Bansang Solar PV Solar 5.0 - - - 2023 2043 983 27.4 0 Basse NAMA Solar PV Solar 6.0 - - - 2022 2042 984 27.3 0 Njaw IDB Solar PV Solar 3.0 - - - 2022 2042 981 27.3 0 Nyanga Bantang Solar PV Solar 2.0 - - - 2023 2043 981 27.5 0 Bwiam Solar PV Solar 20.0 - - - 2023 2043 981 27.3 0 Barra-Essau Solar PV Solar 15.0 - - - 2023 2043 985 27.3 0 Farfenni East Solar PV Solar 64.3 - - - 2023 2043 1,002 27.3 0 Njaba Kunda Solar PV Solar 107.7 - - - 2023 2043 1,077 27.3 0 N’Joben Solar PV Solar 5.0 - - - 2023 2043 981 27.4 0 Soma West Solar PV Solar 104.2 - - - 2023 2043 1,000 27.3 0 GBA East Solar PV Solar 56.2 - - - 2023 2043 1,003 27.3 0 Basse North Bank Solar PV Solar 22.8 - - - 2023 2043 1,017 27.3 0 CCGT Cote d’Ivoire Imports NG 400.0 6,926 8% 4% 2023 2047 866 6.2 5.51 CCGT Senegal Imports NG 400.0 6,926 8% 4% 2024 2050 866 6.2 5.51 CCGT Gambia CCGT LNG 50.0 6,952 8% 4% 2024 2049 1,484 37.1 6.51 ICE Gambia ICE HFO 20.0 9,095 10% 7% 2022 2042 1,019 18.5 6.5 OCGT Gambia OCGT LNG 20.0 11,310 8% 2% 2024 2049 890 17.4 4.68 Generic wind Wind Wind 3.6 - - - 2023 2043 1,364 13 7 1 MW efficiency: Generic battery (4h) Li-on - - - - 2022 2037 1,395 (4 MWh) 87% 1 MW efficiency: Generic battery (6h) Li-on - - - - 2022 2037 2,218 (6 MWh) 87% Source: ECA analysis. Note: Capital costs of Solar PV and Wind are for 2020, model has these reducing over time. Battery costs also decrease. Details are in the Least Cost Power Development Plan.

5.3 Fuel Price Forecasts Another important set of assumptions for the generation modelling is the evolution of fuel prices. The following approach was used: ● Oil products – prices for HFO and LFO were linked to the international price of crude oil. The international crude oil price forecast was obtained from the World Bank Commodities Price Forecast. ● Natural gas and LNG – the World Bank forecasts were adopted. Pipeline costs were added to deliver the gas to the power station. 32 Generation Least Cost Plan Figure 18 Base Case Fuel Price Forecasts Sources: Least Cost Power Development Plan A high fuel price scenario was also developed. This adopts the high case forecast of the International Energy Agency 2019 World Economic Outlook. The high case prices are higher than the base case by different percentages (in 2030/2040 11%/0% for natural gas, 26%/30% for oil distillates and 13%/12% for LNG). Figure 19 High Case Fuel Price Forecasts Sources: Least Cost Power Development Plan

5.4 Generation Least Cost Plan Scenarios The least cost plan included policy positions on security of supply and renewable energy targets from the National Renewable Energy Action Plan: 33 Generation Least Cost Plan ● Security of supply target – Available domestic firm capacity should be at least 50% of the peak demand (energy imports can be more than 50%). ● Renewable energy targets – Renewable capacity (including imports) should be at least 30% of the total installed capacity (including imports) by 2030. Renewable energy generation (including imports) should be at least 26% of total generation (including imports) by 2030. Overall, 11 scenarios and 6 sensitivity analysis were simulated to identify the implications of variations in the demand forecast, the risks associated with each candidate option and the impacts from policy decisions. The scenarios are shown below. Table 18 Generation Least Cost Planning Scenarios No Scenario name Demand Supply scenario scenario Scenarios 1a Base case COVID-19 Available domestic capacity able to deliver at least 50% of updated base demand, but energy imports can be more than 50% if lower case demand cost imports are available. 1b 2025 Universal Above modified Same assumptions as the original base case, but with Access for UA in 2025 increased supply needed to deliver UA by 2025. The target (higher demand for achieving UA in the urban areas remains at 2025, but 2020-25) rural UA is also to be achieved by 2025. 2 High imports COVID-19 Reduced constraint on domestic capacity to 25% of peak updated base demand, which then allows more low cost imports. case demand 3 Imports COVID-19 Imports from Senegal prove to be unavailable or extremely excluding updated base costly. Senegal case demand 4 Delayed COVID-19 Imports from Cote de ’Ivoire are available at the same time imports from updated base as imports from Senegal (i.e. 2024, which is two years later Cote de ’Ivoire case demand than the base case). 5 CCGT in The COVID-19 Forcing the building of an economic sized gas-fired CCGT Gambia updated base in The Gambia using imported LNG (with the option of using case demand domestic Gambian gas in the future). 6 Regional-scale COVID-19 Forcing the development of a regional-scale solar PV plant solar PV plant updated base in The Gambia and exporting to the regional market. in The Gambia case demand 7 Full COVID-19 Available domestic capacity able to deliver 100% of independence updated base demand (peak demand and energy demand). case demand 8 Unrestricted COVID-19 No restrictions on imports and RES targets. updated base case demand 9 Delayed COVID-19 Imports from Cote de ’Ivoire and Senegal are available from imports from updated base 2026. Cote de ’Ivoire case demand and Senegal 34 Generation Least Cost Plan No Scenario name Demand Supply scenario scenario 10 Domestic COVID-19 Domestic energy generation should be at least 50% of total energy >=50% updated base generation including imports. case demand 11 Assumed COVID-19 What if cost of imports are higher than expected? import costs updated base ($110/MWh) case demand Sensitivity analysis 1 High demand COVID-19 Available domestic capacity able to deliver at least 50% of updated high demand, but energy imports can be more than 50% if lower case demand cost imports are available. 2 Low demand COVID-19 Available domestic capacity able to deliver at least 50% of updated low demand, but energy imports can be more than 50% if lower case demand cost imports are available. 3 High fuel COVID-19 Base case with a high fuel price forecast. prices updated base case demand 4 WACC 8% COVID-19 Base case with 8% WACC. updated base case demand 5 WACC 12% COVID-19 Base case with 12% WACC. updated base case demand 6 Investment COVID-19 Base case with a rapid decrease in battery, wind and Solar costs updated base PV investment costs. case demand Source: Least Cost Power Development Plan The least cost capacity additions for six key scenarios selected by NAWEC are summarised in Table 19 below in five year intervals. Table 19 Capacity Additions by Scenario Scenario Selected MW by scenario by type for the candidate power plants in 5-year intervals CCGT Cote CCGT in CCGT in The Generic d'Ivoire Senegal Gambia (LNG) ICE (HFO) Solar PV Wind Battery 2025 2030 2035 2040 2025 2030 2035 2040 2025 2030 2035 2040 2025 2030 2035 2040 2025 2030 2035 2040 2025 2030 2035 2040 2025 2030 2035 2040 Base 40 0 0 0 60 20 40 40 0 0 0 0 0 0 0 40 54 89 23 84 0 4 0 0 0 40 11 17 2025 universal 40 0 0 0 60 20 40 40 0 0 0 0 0 0 0 40 61 83 23 82 0 4 0 0 0 40 11 17 access Unrestricted 80 0 0 60 20 80 60 0 0 0 0 0 0 0 0 0 13 5 37 15 0 0 0 4 0 0 0 0 Full independence 0 0 0 0 0 0 0 0 100 0 50 50 0 0 0 20 57 86 23 84 0 4 0 0 3 35 0 27 Domestic 40 0 0 0 20 20 60 40 0 50 0 50 0 0 0 0 62 81 71 36 0 4 0 0 0 0 1 7 generation >=50% High import costs 0 0 0 0 0 0 40 80 100 0 0 0 0 0 0 0 56 87 23 84 0 4 0 0 3 28 16 18 ($110/MWh) Source: Least Cost Power Development Plan 35 Generation Least Cost Plan The NPV of costs and the average cost of the least cost plan for each scenario are presented in Table 20 below. The 2025 UA total costs are 3% higher than the original base case, but it is notable that the additional energy sent out under 2025 UA results in a slightly lower average cost ($107.8/MWh for 2025 UA vs. $108/MWh for the original base case). Table 20 Summary Values of the Scenarios Scenario NPV NPV NPV NPV NPV NPV CO2 Aver- Capex Fix- variable Wheeling total Unserved emissions age ed costs costs energy costs O&M (m$) (m$) (m$) (m$) (m$) (GWh) (Mt) ($/MWh) Scenarios Unrestricted 212 21 585 104 921 2 10 101.5 High imports (25% 271 33 577 98 979 2 8 107.8 domestic capacity) Base 283 38 591 88 1,000 2 8 108.0 2025 UA base case 287 39 609 91 1,026 2 8 107.8 Delayed imports 283 39 605 78 1,006 2 8 108.1 from Cote de ’Ivoire Force regional-scale 310 45 579 83 1,016 2 8 110.1 Solar PV in the Gambia Imports from 286 37 573 126 1,022 2 8 110.2 Senegal are not available Force CCGT in the 321 44 608 71 1,045 2 8 115.0 Gambia Delayed imports 298 42 659 64 1,063 2 8 115.1 from CdI and Senegal Domestic energy 338 46 621 57 1,062 2 8 117.2 >=50% Assumed import 331 55 739 19 1,144 2 8 124.4 costs ($110/MWh) Full independence 390 60 713 11 1,175 2 8 127.5 Sensitivity analysis WACC 8% 353 52 645 106 1,155 2 8 106.3 WACC 12% 230 29 531 78 869 2 8 109.6 Low demand 193 26 461 60 741 1 6 109.0 High demand 341 44 682 116 1,184 3 9 109.3 High fuel prices 293 40 777 102 1,212 2 8 130.9 Investment costs 273 39 590 88 990 2 8 107.1 Source: Least Cost Power Development Plan 36 Generation Least Cost Plan As illustrated by the graphs in Figure 20, there are significant differences between the scenarios. The extreme cases around the 2025 Universal Access and base cases are the unrestricted scenario and the full independence scenario: ● The scenario with the lowest NPV of costs is the unrestricted scenario where there are no restrictions on the amount of capacity that has to be developed domestically. In the unrestricted scenario, the model chooses imports and Solar PV as the least cost options to satisfy the demand. The unrestricted scenario has a unit cost that is 6% less that the 2025 UA and base cases. ● When the constraint to develop 50% of capacity domestically is applied in combination with the renewable energy targets, the NPV of costs increase. The least cost option with 50% of capacity available domestically and renewable energy targets is incorporated in both 2025 UA and the base case scenarios. Higher amounts of Solar PV are selected to satisfy the renewable energy targets and batteries are also selected as least cost options after 2025. In the later years of the analysis ICE are also selected to satisfy the 50% of domestic capacity policy constraint. As noted above the unit costs of the two scenarios is almost the same (~$108.0 per MWh or 10.8 c/kWh). ● The full independence scenario quantifies the impact of the Gambia cutting itself off from imports. The resulting unit cost would be 18% above the base case. This provides a measure of the benefits for The Gambia of regional power sector integration. Imports are mainly replaced by domestic CCGT capacity operating with LNG. High import prices (>$110/MWh) would also justify the development of domestic CCGT (LNG) as a least cost option after 2025. Figure 20 Comparison of Unit Costs of Policy Scenarios 140 127.5 20% 124.4 Costs relative to 2025 UA (%) 117.2 Average costs (US$/MWh) 120 107.8 108.0 18% 15% 101.5 100 15% 10% 80 9% 5% 60 0% 40 0% 0% 20 -5% -6% 0 -10% Average costs Relative to 2025 UA Source: Least Cost Power Development Plan. Unit cost is NPV of total costs divided by NPV of served demand. 37 Generation Least Cost Plan The generation planning results provide a clear picture of the centrality of imports for the Roadmap in all scenarios. As illustrated in Figure 20 above, the level of imports has a significant impact on the unit costs of generation (NPV of total costs divided by NPV of served energy). The 2025 UA and base cases incorporate the policy stipulation that domestic capacity (MW) should be sufficient to deliver at least 50% of peak demand, but imports of energy (GWh) may exceed this limit if lower cost imports are available. Figure 21 below is a graphical presentation of the results of the other scenarios. Notable points are as follows: Figure 21 Comparison of Unit Costs of Sensitivity Scenarios to 2025 Universal Access Source: Least Cost Power Development Plan. ● The low and high demand cases are higher in unit cost terms than the base case. ● The high fuel costs scenario significantly increases unit costs by 21%. ● Forcing the development of a CCGT (LNG) in The Gambia and the delayed import scenario (which results in the development of CCGT (LNG) in The Gambia early on) increase unit costs by 7%. ● Forcing the development of a regional scale Solar PV in 2022 increases the unit costs by 2%15 and the same result is observed in the scenario with no available imports from Senegal. ● A delay in available imports from Cote d ‘Ivoire has a minor impact on unit costs (0.1%) and so does the high imports scenario (-0.2%). ● Finally, a steeper decrease in battery costs would result in higher amounts of batteries being selected as least cost options in the system and would reduce unit costs by 1%. 15 The regional solar PV is costly because countervailing export revenues from a facility that is far too large for The Gambia’s needs have not been fully factored into the analysis. 38 Generation Least Cost Plan 5.5 2025 Universal Access Least Cost Generation Investment Plan The least cost generation investment plan for the 2025 Universal Access central case is summarised in Table 21 below. This incorporates the requirement that domestic capacity should be at least 50% of peak demand and follows the renewable energy targets of the National Renewable Energy Action Plan. The NPV of the investment costs of the 2025 UA case is $287 million, the NPV of fixed O&M costs $39 million, the NPV of variable costs $609 million (in 2020 terms). Table 21 New Generation Capacity that is Selected for 2025 Universal Access Name Year Capacity (MW) Overnight capital cost commissioned (mUS$) Brikama III 2021 18.4 18.7 ICE 30 MW (HFO) 2022/23 30 30.6 World Bank - Jambur Solar 2022 20 19.9 PV World Bank Jambur Battery 2022 6 11.6 CCGT Cote d'Ivoire 2023 40 34.6 CCGT in Senegal 2024 60 52 2026 20 17.3 2032 20 17.3 2034 20 17.3 2036 20 17.3 2038 20 17.3 Bansang Solar PV 2022/23 2 2 2025 3 2.6 Barra-Essau Solar PV 2022/23 1 1.1 2025 5 4.6 2028 3 2.7 2031 3 2.4 2035 3 2.1 Basse NAMA Solar PV 2022/23 6 5.9 Basse North Bank Solar PV 2031 1 1.6 2035 16 23.9 2036 5 7.5 2037 1 1.5 Bwiam Solar PV 2022/23 20 19.6 Farafenni - NAMA Solar PV 2025 4 3.6 Farafenni East Solar PV 2040 20 39.7 GBA East Solar PV 2038 19 37.1 2040 37 69.5 Njaw - IDB Solar PV 2022/23 3 2.9 N'Joben Solar PV 2022/23 5 4.9 39 Generation Least Cost Plan Name Year Capacity (MW) Overnight capital cost commissioned (mUS$) Nyanga Bantang Solar PV 2025 2 1.7 Soma Solar Park I+II 2030 80 57.2 Z-One - Jambur 2022/23 10 10.0 Generic Wind 2030 4 4.1 Generic battery 4h 2027 2 2.0 2028 4 3.8 2029 5 4.6 2030 29 25.6 2034 6 5.0 2035 5 4.1 2037 9 7.2 2039 2 1.5 2040 6 4.6 Source: Least Cost Power Development Plan With the selected investments in the 2025 UA case of the least cost plan the total available capacity increases from 115 MW in 2020 to 680 MW in 2040. The main source of energy is imports and domestic Solar PV. The total domestic capacity reduces from 97% in 2020 to 65% in 2040. The renewable energy capacity target is met in 2025 and stays above 30% in all years after 2025. The corresponding RE energy target is met in 2030 and is maintained thereafter. Figure 22 below shows the total available capacity of the 2025 UA least cost plan broken down by technology and compares the total available capacity with the peak demand. Figure 22 Available Capacity vs Peak Demand – 2025 Universal Access Source: Least Cost Power Development Plan 40 Generation Least Cost Plan Table 22 shows the capacity mix in 2020, 2025, 2030, 2035 and 2040. Domestic thermal comprises all capacity in 2020 but quickly declines to 28% in 2025 and stays at low levels thereafter. It is replaced largely by imports and Solar PV capacity. Capacity from renewable energy technologies grows from 0% in 2020 to 50% of available capacity in 2040. Table 22 Capacity Mix 2020, 2025, 2030, 2035 and 2040 – 2025 UA case 2020 2025 2030 2035 2040 Domestic thermal 95% 28% 17% 15% 15% Domestic RES and Batteries 0% 27% 47% 47% 50% Senegal imports (CCGT) 5% 19% 18% 23% 24% Cote d'Ivoire imports (CCGT) 0% 13% 9% 8% 6% Guinea imports (Hydro) 0% 13% 9% 8% 6% Total (MW) 115 316 452 526 680 Source: Least Cost Power Development Plan The capacity available at the time of peak demand is compared with the level of peak demand in Figure 23. The reserve margin, including import capacity, is well above 15% in all years. The main difference between the levels of available and firm capacity is that solar PV contributes to available capacity but not firm capacity, as it does not produce power at times of peak demand. Figure 23 Available Firm Capacity vs Peak Demand – 2025 Universal Access Source: Least Cost Power Development Plan Figure 24 shows the annual average variable costs. Average costs fall from initially high levels of $119/MWh to a lower value of $49/MWh in 2024 as current sources of generation are replaced by cheaper imports and solar generation. 41 Generation Least Cost Plan Figure 24 Average Variable Costs – 2025 Universal Access Source: Least Cost Power Development Plan

5.6 Implications for Tariffs The steep decline over the planning period in average variable costs will in due course translate into welcome tariff reductions for Gambian electricity consumers. A tariff model has been developed for NAWEC, but the full range of data that is required for this is not currently available and it is thus not possible to make an accurate estimate of the potential tariff reductions. However, a levelised cost approach, in which annualised capital costs are added to operational, fuel and maintenance costs, suggests that the total costs by 2030 will be of the order of $120/MWh (12 c/kWh), which in Dalasi is GMD 6,120/MWh or close to GMD 6/kWh. The graph below shows how the levelised cost is made up. The reduction arises primarily from the decline in generation charges, which more than offsets the higher transmission and distribution charges associated with Universal Access. Figure 25 Declining Levelised Costs of Generation, Transmission and Distribution 42 Generation Least Cost Plan The levelized cost does not include return on assets, existing loan repayments, administrative staff costs and other expenses, so the cost recovery tariff in 2030 would be higher than this. The present cost recovery tariff is approximately GMD 12/kWh and reductions of 20% to GMD 9.6/kWh or 33% to GMD 8/kWh are likely to be possible (the US $ equivalents are present cost recovery level of 23.5 c/kWh reducing to between 18.8 c/kwh and 15.7 c/kWh). This would be an initial reduction and further tariff reductions should follow over the remainder of the Roadmap period to 2040.

5.7 Generation Least Cost Plan Conclusions The most important conclusion from the generation planning is that the least cost option for The Gambia is to import electricity from Senegal and/or Cote d’Ivoire. This conclusion is robust in all scenarios considered. The main risk associated with imports from Senegal is the availability of large CCGTs in the short term and for imports from Cote d’Ivoire the level of the wheeling charge. Imports from Guinea have a role early on, but are hardly utilised after the commissioning of alternative import options due to the PPA’s high price. Solar PVs are a central part of the least cost plan, but they cannot provide peak capacity. At least 70 MW of solar PV is in the category of ‘no regret’ investments as 70 MW of solar PV is part of the least cost plan in all scenarios. Batteries are selected after 2025 when built costs are expected to reduce. The total installed capacity of batteries varies from 8 MW to 108 MW in all scenarios. Similar to the import contract with Guinea, the new Brikama III and committed 30 MW ICE plants are important in the short run, but are not utilised after the commissioning of CCGT imports (2023) due to their higher operating costs. Even in the scenario of imports at $110/MWh from Cote d’Ivoire and Senegal, the Brikama III and 30 MW ICE plants are hardly used at all (extremely low capacity factors). Similar levels of underutilisation are observed even in >=50% energy from domestic sources. Domestic thermal generation capacity is chosen mainly to satisfy the 50% domestic capacity constraint – CCGT (LNG) for base load, ICE (HFO) for peaking. The scenario with import costs at $110/MWh brings CCGT (LNG) into the least cost solution (100 MW in 2025), but at a high cost for The Gambia. 43 Roadmap Directives and Implementation 6 Roadmap Directives and Implementation

6.1 Roadmap Directives Key elements of the Roadmap are the grid extension projects to achieve Universal Access by 2025, domestic investment in solar PV projects and the imperatives of negotiating import arrangements and strengthening the institutional framework: ● Universal access: to attain the President’s target of achieving universal coverage by 2025 is a major challenge. Concerted efforts are required by all of the agencies and contractors involved. ● Solar PV: 70 MW of Solar PV are ‘no regret’ investments in all scenarios. The role of PV will be enhanced with batteries when their cost becomes competitive (expected after 2030). ● Import contracts: PPA negotiations with Senegal and Côte d’Ivoire are to be initiated immediately. Imports from Senegal’s CCGT plants should be the least, cost but may not be available in the short term. ● Institutional strengthening: the reform process for NAWEC is to be intensified. With the full implementation of the 2019-25 Strategic Development Plan, NAWEC is to become an operationally efficient and financially viable company. The institutional arrangements for the implementation of the Roadmap are discussed in Section 6.3 below. The import contract negotiations will have to consider the costs of gas-based imports against the costs of the next best alternative for The Gambia over time (e.g. ICE (HFO) or Solar PV + Batteries or CCGT (LNG)). The PPAs should avoid take-or-pay provisions that force The Gambia to use expensive energy. Where possible PPAs should be structured with capacity and energy components that would allow less costly options to be deployed in the future. The outcome of the PPA negotiations has a bearing on what priority thermal capacity should be developed in the Gambia. High PPA prices (above ~11c/kWh) would indicate that CCGT using LNG should be developed, a major step for The Gambia which has not deployed this technology before. The familiar technology of ICE generators using HFO would otherwise be indicated.

6.2 Financing Requirements The main components of the Roadmap that are to be financed are the generation investments, the Universal Access projects and the associated T&D investments. Table 23 provides a summary broken down into 2021-2025 ($526 million) and 2026-2030 ($210 million). The overall total for the period 2020-2030 is $736 million. A large proportion of this is already financed through on-going national and regional projects sponsored by development partners. 44 Roadmap Directives and Implementation Table 23 Financing Requirements Summary for 2020-2030 ($ million) Item 2020-2025 2026-2030 Total Source (1) Generation $225 m $125 m $350 m Private sector IPPs + NAWEC (2) On-going Universal $92 m $39 m $131 m GERMP, EREAP Access projects and GEAP (3) New Universal $66 m $29 m $95 m Donor and Access projects government financing (4) Gambian component $86 m $86 m Donor financing of OMVG project (5) Transmission $57 m $17 m $74 m NAWEC, donor projects financing Total $526 m $210 m $736 m Note: Generation and UA project costs are overnight capex (reported elsewhere in this report) plus 3% for design costs etc. GERMP, EREAP and GEAP financing goes beyond UA sub-components of these projects.

6.3 Institutional Structure and Implementation Arrangements16 The electricity sector in The Gambia is governed by a policy framework that provides incentives, direction and guidance to sector operators through the National Development Plan (NDP) and the National Energy Policy (NEP). The key legal and regulatory instruments, include the Electricity Act 2005, the Renewable Energy Act 2013, the National Environment Management Act 1994, the Public Enterprises Act 1990 and the PURA Act 2001, together with their associated regulations. The main institutions are: ● NAWEC, a public utility, continues to be the dominant operator providing electricity, water and sewerage services throughout the country. ● Ministry of Petroleum and Energy (MoPE) provides overall policy direction and guidance for the sector and issues licenses. ● Ministry of Finance and Economic Affairs (MoFEA) makes budgetary provisions for the sector and coordinates donor interventions. ● Public Utilities Regulatory Authority (PURA), a multi-sector regulatory agency, regulates the activities of electricity service providers, including tariff guidelines and advises on the issuance of licences. ● National Environment Agency (NEA) ensures compliance with environmental standards and regulations. Other public institutions involved in the electricity sector are the Office of the President (OP), the Ministry of Justice (MoJ), the Ministry of Local Government and lands (MoLGL) and The Gambia Investment and Export Promotion Agency (GIEPA). 16 Details are available in the Roadmap Institutional Arrangements Report 45 Roadmap Directives and Implementation In addition to chronic under-investment, the electricity sector in the past has suffered from weak corporate governance practices, including unfettered government interference in purely operational matters. Several efforts have been initiated to address this weakness, in particular through collaboration with donors like the World Bank, which has to date approved four different projects aimed at enhancing NAWEC’s governance, efficiency, creditworthiness and viability: and ultimately attracting more investors into the sector. In December 2019, NAWEC signed a Performance Contract with Government setting out the agreed range of NAWEC’s business profile and responsibilities along with the reciprocal undertakings by Government and NAWEC with regard to each other. It is expected that the full implementation of NAWEC’s 2019-25 Strategic Development Plan and a pro-active response to the Performance Contract will consolidate the process of NAWEC management meeting the company’s objectives, which will in turn have important implications for the electricity sector. For the coordination and monitoring of the implementation of the Roadmap it has been decided that: ● The Ministry of Energy and Petroleum (MoPE) will provide strong leadership and will drive the whole process. ● The implementation will be facilitated by the establishment of the High Level Taskforce, chaired by MoPE, with the OP, MoFEA, MoJ, MoLGL, NAWEC, PURA, NEA and GIEPA as members. ● The Department of Energy of MoPE, with a dedicated Roadmap Implementation Coordinator, will provide the Secretariat to the Taskforce: convening meetings; taking minutes, providing briefing notes, and following up on decisions of the Taskforce. To be successful, the Taskforce needs to have a dedicated membership, with consistency of presence at a senior level. The Task Force members and other important stakeholders are shown in the diagram below. 46 Roadmap Directives and Implementation Figure 26 Institutional Structure for the Implementation of the Roadmap Two annexes to this report provide summaries of the key tasks and responsibilities in relation to the policy and legal framework (Annex A3.1) as well as envisaged projects (Annex A3.2) required for the implementation of the Roadmap. The Matrices incorporate the RACI framework, showing the responsible, accountable, consulted and informed institutions for each task and sub-task. Critical path items are as follows: ● Initiation of electricity import negotiations with Senegal and Cote d’Ivoire ● Execution of transmission feasibility studies ● Acceleration of Universal Access grid connection projects ● Completion of on-going generation expansion projects and continuation of preparations for subsequent projects, particularly in solar PV ● Intensification of institutional strengthening, particularly through the implementation of NAWEC’s 2019-25 Strategic Development Plan. 47 Roadmap Directives and Implementation

6.4 The Gambia Leading the Way in Africa Within the African continent, achieving universal electrification by 2025 will be a significant achievement in which The Gambia will be able to be justifiably proud. To remain on track for this, it is imperative that the structures for implementing the Roadmap are put in place immediately and the critical path items vigorously pursued. 48 Annexes Annexes A1 References A1.1 Roadmap Technical Reports 1. Demand Forecast Report 2. Willingness to Pay Survey Report 3. Least Cost Power Development Plan (incorporating sub-reports on Solar mapping, Gas-to- power Options and Import Analysis) 4. Transmission and Distribution Master Plan and Universal Access Strategy 5. NAWEC Financial Model Report 6. Roadmap Institutional Arrangements A1.2 Other Reference Materials IRENA (2018): Planning and prospects for renewable power: WEST AFRICA. Abu Dhabi. Government of The Gambia: National Renewable Energy Action Plan NAWEC, Update to the Electricity Sector Roadmap, Final Report, 2017 World Bank, ESMAP, SolarGIS, 2015 INTEC. Feasibility Study for Grid Connected PV, March 2019 (Jambur, Gambia) ECOWAS Masterplan for the development of regional power generation and transmission infrastructure, 2019-2033, Final Report, Volume 0-5, Tractebel, December 2018 Population and Housing Census in The Gambia, Burke, P. and Csereklyei, Z. (2016), SE4ALL and NAWEC Lazard’s Levelized Cost of Storage Analysis, Lazard and Enovation Partners estimates, 2018 Cost Projections for Utility-Scale Battery Storage, National Renewable Energy Laboratory (NREL) 2018 Battery Capital Cost Projections, Australian Energy Market Operator (AEMO), 2019 European Space Agency, 2016 49 Annexes GBA T&D upgrade feasibility study WB, Tractebel, 2019 - NCC A2 Detailed Demand Forecast Tables Table 24 Revised Energy Demand Sent-out Forecast (GWh) Year COVID-19 New Low COVID-19 2025 UA COVID-19 New High 2019 418 418 418 2020 406 451 504 2021 497 562 617 2022 568 681 746 2023 599 775 814 2024 631 849 888 2025 658 920 964 2026 687 964 1,033 2027 717 1,010 1,107 2028 748 1,058 1,186 2029 780 1,109 1,269 2030 813 1,162 1,358 2031 847 1,223 1,435 2032 882 1,287 1,516 2033 919 1,354 1,602 2034 957 1,424 1,692 2035 996 1,498 1,787 2036 1,037 1,576 1,887 2037 1,080 1,658 1,993 2038 1,124 1,743 2,104 2039 1,169 1,833 2,222 2040 1,217 1,928 2,346 AAG 4.9% 6.7% 7.6% Source: Demand Forecast Report 50 Annexes Table 25 Peak Demand Forecast (MW) Year COVID-19 New Low COVID-19 2025 UA COVID-19 New High 2019 80 80 80 2020 84 93 104 2021 98 113 125 2022 110 135 149 2023 115 154 162 2024 121 167 176 2025 126 180 190 2026 130 187 202 2027 135 195 215 2028 140 202 228 2029 145 210 243 2030 151 218 258 2031 156 228 271 2032 162 238 284 2033 167 248 297 2034 173 259 312 2035 179 271 327 2036 186 283 342 2037 192 295 359 2038 199 308 376 2039 205 321 394 2040 211 333 411 AAG 4.3% 5.9% 6.8% Source: Demand Forecast Report 51 Annexes A3 Implementation Matrices A3.1 Policy and Legal Framework Enhancement Main Action/Activity Tasks Sub-tasks Responsible Accountable Consulted Informed Elements Policy and Elaborate a new All MDAs, Recruit consultant to revise Legal Energy Policy to general public, General Policy review and update NEP if in-house DoE MoPE Framework succeed NEP 2014- private sector, public capacity is insufficient 2020 NGOs, donors Quarterly meetings between DoE (MoPE) and ACD DoE MoPE N/A N/A (MoFEA) Minister- Quarterly briefing to Ministers PS-MoPE, MoPE, Strengthen DoE, ACD NAWEC, donors of Energy and Finance PS-MoFEA Minister- Sector coordination coordination with MoFEA and resource MoFEA regarding mobilisation donor interventions in Embark on vigorous resource MoPE, PS-MoPE, Donors, private General energy sector mobilisation for roadmap MoFEA PS-MoFEA sector, NAWEC public implementation All MDAs, Conduct annual sector PS-MoPE, general public, General DoE, ACD coordination forums PS-MoFEA private sector, public NGOs, donors 52 Annexes Main Action/Activity Tasks Sub-tasks Responsible Accountable Consulted Informed Elements Recruit additional staff in DoE PMO MoPE, PMO MoPE N/A (MoPE) if necessary 1. Build MoPE staff capacity to engage in Train DoE staff in power policy and technical sector planning, investment discourse with analysis and decision making, MoPE, PMO, NAWEC and other IPP structuring, PPA MoPE, PMO PS-MoPE Staff staff operators negotiation, energy efficiency techniques and regulatory compliance Ensure high level Heads of Driving Roadmap Minister- representation from member PS-MoPE PS-MoPE member implementation and MoPE institutions institutions monitoring 2. Establish Hold quarterly meetings (DoE DoE Taskforce comprising to provide Secretariat with a Minister- Roadmap PS-MoPE Taskforce MoPE as chair, OP, dedicated Roadmap MoPE Coordinator MoFEA, MoJ, Coordinator) MoLGL, NAWEC, Minister- PURA, NEA, GEIPA Publish quarterly progress DoE MoPE, Heads to oversee and report reports on roadmap Roadmap PS-MoPE Taskforce of member on progress implementation Coordinator institutions DoE Provide quarterly updates to Roadmap PS-MoPE Minister-MoPE Cabinet Cabinet Coordinator 53 Annexes Main Action/Activity Tasks Sub-tasks Responsible Accountable Consulted Informed Elements Set up and recruit staff to the NAWEC-BoD, Projects and Planning NAWEC-M NAWEC-MD N/A NAWEC-HR Directorate Strengthen Legal Unit with NAWEC-M NAWEC-MD NAWEC-HR N/A additional staff Set up an environmental unit NAWEC-BoD, NAWEC-M NAWEC-MD N/A to liaise with NEA NAWEC-HR 3. Strengthen Train staff in power sector NAWEC staff planning, investment analysis capacity Heads of and decision making, energy NAWEC-HR NAWEC-MD NAWEC-BoD departments efficiency techniques and regulatory compliance Specialised training in technical and negotiating Heads of skills, monitoring and NAWEC-HR NAWEC-MD NAWEC-BoD departments evaluation of regional arrangements Pursue and finalise ongoing Sector restructuring NAWEC- 1. Sanitise NAWEC separation of NAWEC NAWEC-M MoPE, MoFEA NAWEC-BoD and promotion of Finance balance sheet (short accounts private sector term) Ensure NAWEC viability as a NAWEC-MD, MoPE, MoFEA, participation NAWEC-M going concern NAWEC-BoD donors 54 Annexes Main Action/Activity Tasks Sub-tasks Responsible Accountable Consulted Informed Elements Split NAWEC services into 3 NAWEC, MoPE, MoPE, entities (electricity, water, Cabinet general MoFEA MoFEA sewerage) public Hand over sewerage services MoPE, MoPE, General 2. Unbundle NAWEC to municipalities Municipalities MoFEA MoFEA public services (medium to long term) MoPE, MoPE, Invite private sector in various General MoFEA, MoFEA, Private sector forms including IPP public GIEPA GIEPA If privatisation is pursued, General MoFEA MoFEA General public float shares to the public public Remove environmental MoJ, NEA, General monitoring role from MoPE MoPE MoPE Cabinet, NA public mandate 1. Amendment of the Review of legal Electricity Act 2005 Clarify MoPE and MoFEA role MoJ, MoFEA, General framework in restructuring and MoPE MoPE Cabinet, NA public privatisation of NAWEC 2. NAWEC legal Clarify legal regime governing MoPE, General MoPE MoJ, NAWEC status NAWEC MoFEA public 55 Annexes A3.2 Projects Implementation Main Elements Action / Activity Tasks Sub-tasks Responsible Accountable Consulted Informed Overall Implementation Initiation, Public information coordination of responsibility coordination of MoFEA, MoJ, Roadmap coordinated by a donor projects and MoPE, Office MoLGL, General activities Secretariat in DOE national initiatives, MoPE of the NAWEC, public with full time monitoring and President PURA, NEA, Roadmap reporting GEIPA Coordinator Financing Secure resources for Present applications Identify different all activities in the for financing to financing sources Donor MoFEA, roadmap not yet fully potential financers for different DoE, ACD community, NAWEC MoPE financed activities; prepare banks etc applications Generation Procurement of IPP Prospective Projects generation projects Feasibility study DoE MoPE NAWEC IPP investors Qualification of Prospective RFQ DoE MoPE NAWEC bidders IPP investors Tender package RFP DoE MoPE NAWEC Draft Implementation DoE MoPE NAWEC Agreement Draft PPA Draft ICA NAWEC NAWEC Legal MoPE Draft TSA if Management Shortlisted applicable IPP investors Draft Land Access and Community DoE MoPE MLRG Engagement Agreement Draft Environmental DoE MoPE NEA and Social Plan 56 Annexes Main Elements Action / Activity Tasks Sub-tasks Responsible Accountable Consulted Informed Selection of IPP Finalised and signed versions of DoE MoPE NAWEC Selected IPP above Foreign IPP Work permits for GID MoPE GIEPA MoPE expat staff Licensing NAWEC, Generation licence PURA MoPE MoPE Construction DPPH MoPE NAWEC MoPE licence Construction stage RFP for EPC Prospective Contracting EPC Process managed by IPP MoPE, PURA EPC Supervision of EPC contractors Interconnection and Interconnection NAWEC, IPP NAWEC MoPE, PURA MLRG commissioning Testing & Equipment NAWEC MoPE, PURA commissioning supplier, IPP Monitoring and PURA PURA NAWEC MoPE reporting Procurement of Licensing NAWEC, Generation license PURA MoPE NAWEC generation MoPE projects Construction DPPH MoPE NAWEC MoPE licence Construction phase RFP for EPC NAWEC Prospective NAWEC Contracting EPC Projects & MoPE, PURA EPC Management Supervision of EPC Planning contractors Interconnection and Interconnection NAWEC, IPP NAWEC MoPE, PURA MLRG commissioning Testing & Equipment NAWEC MoPE, PURA commissioning supplier, IPP Monitoring and PURA PURA NAWEC MoPE reporting 57 Annexes Main Elements Action / Activity Tasks Sub-tasks Responsible Accountable Consulted Informed Import and Guinea, Senegal, Identify import and Negotiate PPAs NAWEC NAWEC MoFEA PURA Export Cote d'Ivoire and export opportunities Management & Contracts other ECOWAS Legal Dept, members MoPE, MoJ Monitoring and NAWEC MoPE MoFEA PURA reporting Transmission Procurement of Licensing Construction DPPH NAWEC MoPE projects NAWEC transmission licence projects Construction phase RFP for EPC NAWEC Prospective NAWEC Contracting EPC Projects & MoPE, PURA EPC Management Supervision of EPC Planning contractors Interconnection and Interconnection NAWEC, IPP NAWEC MoPE, PURA MLRG commissioning Testing & Equipment NAWEC MoPE, PURA commissioning supplier, IPP Monitoring and PURA PURA NAWEC MoPE reporting Distribution / Gambia Electricity Restoration and on-grid Modernisation Project (GERMP - IDA, EIB, electrification Implementation of EU) MoPE, MLRG, projects The Gambia Electricity Access Project NAWEC Local existing donor PIU MoFEA, (GEAP - AfDB) Management communities projects donors ECOWAS Regional Electricity Access Project (EREAP - IDA) Grid extension and Contracting of the already pre-qualified NAWEC NAWEC MoPE, MLRG Local densification projects local contractors, plus deployment of Projects & Management communities identified in Universal additional contractors if needed using the Planning Access Strategy above framework for NAWEC projects 58 Strategic Electricity Roadmap 2021-2040