ACHIEVING UNIVERSAL ACCESS IN THE KEDCO SERVICE AREA Africa Renewable Energy and Access Program (AFREA) This is a publication by the African Renewable Energy Access Program (AFREA), a World Bank Trust Fund Grant Program funded by the Kingdom of the Netherlands. The report was prepared by staff of the Inter- national Bank for Reconstruction and Development / The World Bank. The findings, interpretations, and conclusions expressed in this report are entirely those of the author(s) and should not be attributed in any manner to the World Bank, or its affiliated organizations, or to members of its board of executive directors for the countries they represent. The World Bank does not guarantee the accuracy of the data included in this publication and accepts no responsibility whatsoever for any consequence of their use. 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Preface This Volume was produced under the Nigeria Electrification Access Program Development (NEAPD) Tech- nical Assistance project for the Kano Electricity Distribution Company (KEDCO), which provides electricity services to the States of Kano, Katsina and Jigawa in North West Nigeria. The Volume is combined by two re- ports: a GIS-based Least-Cost Plan and a related Investment Prospectus. Together, they present a technically sound electrification and investment plan for the achievement of universal access to electricity services in the Kano service area by 2030. Both the Geospatial Plan and the Investment Prospectus were produced in close collaboration with KEDCO, and the NEAPD project also strengthened the utility’s capacity through train- ing for the geospatial mapping of the electricity infrastructure and for distribution planning with GIS tools. The Least-Cost Plan provides a geospatial and quantitative frame for the design and detailing of a well-co- ordinated and harmonized implementation program for grid and off-grid electrification over a fifteen-year timeframe (2015–2030). Building on the findings of the geospatial plan and a rapid readiness assessment, the Investment Prospectus proposes a year-by-year electrification program up to 2030 (including connections for schools and clinics) and details the investment needs, financing gaps and possible sources of funding with a focus on the first five years of implementation. The Prospectus also identifies key sector obstacles (related to the policy, institutional and financing frameworks) for the implementation of an access rollout plan and suggests possible areas requiring capacity strengthening through Technical Assistance. As demonstrated by best practices in international experience, investments alone will not be sufficient to achieve universal access by 2030. They must be complemented by timely and effective enabling actions on several other fronts, especially the establishment of an enabling policy, targeted fixes to the institutional framework, and capacity strengthening of the key agents and institutions whose effective engagement is essential. Besides KEDCO, the Federal Government of Nigeria (Ministry of Power and of Finance, and the Office of the Vice President), the Regulator, and several other key stakeholders have a key role to play if elec- tricity services are to be provided to over 80 million Nigerians currently living in the dark and ensure shared well-being across the country. While the analysis and recommendations presented in this Volume reflect and respond to the operating context and specific characteristics of the KEDCO utility, they also provide an input for the completion of the bold sector reform launched by the Federal Government of Nigeria in 2010. While highlighting the make or break challenges for scaling up access in the Kano service area, the Volume also provides a roadmap for expanding access across the country in an efficient, effective, and timely manner. i ii Acknowledgements This work could not have been possible without financial support from the Africa Renewable Energy and Ac- cess Program (AFREA), funded through the World Bank’s Energy Sector Management Assistance Program (ESMAP)—a global knowledge and technical assistance program that assists low- and middle-income coun- tries to increase their know-how and institutional capacity to achieve environmentally sustainable energy solutions for poverty reduction and economic growth. ESMAP is funded by Australia, Austria, Denmark, Finland, France, Germany, Iceland, Japan, Lithuania, the Netherlands, Norway, Sweden, Switzerland, the United Kingdom, and the World Bank Group. AFREA’s mandate is to help meet the energy needs and widen access to energy services in Sub-Saharan African countries in an environmentally responsible way. AFREA is funded by the Netherlands. The report also benefited from funding from the Sustainable Energy for All (SE4All) global initiative. Under the overall guidance of Rahul Kitchlu (Senior Energy Specialist), the Least Cost Geospatial Imple- mentation Plan for Grid and Off-Grid Rollout (2015–2030) for the KEDCO Electric Service Area was prepared by the Earth Institute at Columbia University School of Engineering and Applied Sciences whereas the In- vestment Prospectus for the electrification of the KEDCO service area by Economic Consulting Associates. Arun Sanghvi (Consultant) and Chiara Rogate (Consultant) supervised and coordinated the preparation of this Volume. The team is grateful for the guidance provided by Rachid Benmessaoud (Country Director), Meike van Ginneken (Practice Manager, Africa Energy), Wendy Hughes (Practice Manager, Africa Energy), Rohit Khanna (Practice Manager, Energy Strategy and Operations), Erik Fernstrom (Practice Manager, Energy MENA) and Kyran O’Sullivan (Lead Energy Specialist). The team is also grateful to Sudeshna Banerjee (Lead Energy Specialist), Dana Rysankova (Senior Energy Specialist), and Yann Tanvez (Energy Specialist) for peer reviewing the reports and providing insightful comments, and to Jon Exel (Senior Energy Specialist) and Muhammad Wakil (Energy Specialist) for their valuable inputs. We would also like to thank Siet Meijer (Operations Officer) and the ESMAP team, particularly Heather Austin (Publishing Officer), Chita Obinwa (Program Assistant), Joy Medani (Team Assistant), and the colleagues in the World Bank Abuja Office for their support in preparing this Volume. The team and the contractors would also like to thank the Management and staff of the Kano Electric Dis- tribution Company (KEDCO) who provided strong and appreciated commitment, support and cooperation in the preparation of these reports. PART 1 LEAST COST GEOSPATIAL IMPLEMENTATION PLAN FOR GRID AND OFF-GRID ROLLOUT (2015–2030) FOR THE KEDCO SERVICE AREA ADVISORY SERVICE DOCUMENT CONSULTANT SUMMARY REPORT Contents ix Executive Summary x ES1.  Grid Electrification Program xiii ES2.  Off-Grid Electricity Access xiv Notes 1 Introduction 1 Note 2 Chapter 1: Input Data and Parameters 2 1.1  Mapping Medium Voltage Grid Line 5 1.2  Geo-located Populated Places 5 Polling Unit Data: A Proxy for Village-level Population Data 6 Corrections and Estimates Related to Polling Unit Data 10 1.3  Components of a Universal Electrification Program 10 Grid Extension Program 13 Off-Grid Electrification Program 13 1.4  Model Parameters and Other Data Inputs 13 Gathering Modelling Parameters from Local Sources 14 Poverty Mapping 14 Notes 17 Chapter 2: Cost and Technical Results 17 2.1  Overview: Grid Extension Program 17 Geo-Spatial Factors in Grid Extension 20 Prioritization of Grid Roll-Out 23 Per Household Costs and Grid Prioritization 24 2.2  Results Overview: Off-Grid Program 25 2.3  Electricity Access for Social Infrastructure 28 Notes 29 Chapter 3: Conclusions and Next Steps 30 Annex A – Pre-processing of Electricity Demand Point Data 35 Annex B – Model Parameters 40 Annex C – Sensitivity Test – Variation in Household Demand 42 Annex D – Least-Cost Electrification Modeling 45 Notes v vi Contents Figures viii Figure 1 Existing grid lines and the prioritized grid expansion plan based on average cost per household for the KEDCO service area, 2015–2030 3 Figure 2 MV grid line and transformers coverage in the KEDCO service area, July 2015 4 Figure 3 Left: KEDCO engineers labeling and correcting data for MV grid infrastructure using JOSM editor. Right: A KEDCO engineer in training to map MV line infrastructure using a smartphone 5 Figure 4 INEC polling sites throughout the three state KEDCO service area, 2015 6 Figure 5 Satellite imagery (Google) for part of Jigawa state shows correspondence be- tween INEC polling sites (green points) and clustered structures indicating locations of communities 7 Figure 6 Population density at LGA level (2006 Census) combined with urban boundar- ies as defined by the “night lights” satellite dataset shows correspondence of high density and urban areas 8 Figure 7 One polling site (yellow point, left) serves a widely dispersed population (house- holds marked with blue points). Some of these are clustered into neighboring villages that lack a polling site (upper center of image); others are “isolated” households, more than 100 meters from their nearest neighbor (periphery of image) 9 Figure 8 Estimated frequency of “isolated” households (suitable for off-grid technologies) for all polling unit areas in the KEDCO service area 10 Figure 9 Solid blue lines show MV needed to reach villages represented by polling sites (yellow points); the dotted blue line shows the extra MV line needed to reach villages without polling sites 15 Figure 10 Poverty rate (% of poor households) for the KEDCO service area based on geospatial data recent research from Oxford University (Gething & Molini) 19 Figure 11 Areas served by improved connections and LV intensification near the existing grid connect 69% of the projected population (2030) 20 Figure 12 MV extensions can bring grid access to another 27% of the projected (2030) population that is targeted for grid (with 3–4%, mostly isolated homes, for off-grid) 21 Figure 13 NetworkPlanner recommendations for electrification with grid (blue), mini- grid (red) and off-grid/SHS (green). Left: Enlarged portion of Katsina State. Right: Full KEDCO service area 22 Figure 14 Prioritized grid roll-out for the KEDCO service area (2015–2030) 23 Figure 15 Prioritization of grid roll-out in an enlarged area of the Jigawa State, 2015– 2030 24 Figure 16 Detail of rising MV costs per household throughout the grid roll-out in the KEDCO service area, 2015–2030 26 Figure 17 Social infrastructure (education and health) facilities with grid access (2015) 26 Figure 18 Social Infrastructure (education and health) facilities without grid access (2015) 27 Figure 19 Social infrastructure (education and health) facilities planned for grid connec- tion (2015–2030) 27 Figure 20 Social infrastructure (education and health facilities) beyond the 1.5 km range of grid (2015–2030) 31 Figure 21 Dwellings (blue) identified in satellite imagery; red lines indicate inter-house- hold distances greater than 100 meters (yellow points represent polling places; yellow polygons illustrate estimated “coverage areas” for polling places) 32 Figure 22 Rural area of Kano state where visual identification of dwellings (blue points) in satellite imagery was repeated for many polling unit areas (yellow polygons) 33 Figure 23 The correlation between household density and percent of isolated dwellings identified using satellite imagery in ~90 polling units belonging to the KEDCO service area Contents vii 34 Figure 24 Two trend-lines show the relationship between MV per household recom- mended by NetworkPlanner and polling unit density for two datasets: clustered house- hold locations identified from satellite imagery and locations of polling sites. Comparison of these trendlines yields a rough estimate of the difference to be approximately a factor of 2 37 Figure 25 Predicted map of poverty headcount rates in Nigeria in 2012/13. The continu- ous surface is the posterior mean prediction at 5x5 km resolution 38 Figure 26 Polling unit locations in the KEDCO service area shown with poverty values extracted from the raster pixels 43 Figure 27 NetworkPlanner map with magnitude of electricity demand for each point shown by circle size (left), 2030; and algorithmically specified least-cost electricity grid network (right) (example is from a rural area in southwestern Uganda) 43 Figure 28 Model summaries (data and maps) presented through a web browser format 44 Figure 29 Sequential versus algorithmic approaches to grid extension planning Tables vii Table 1 Electricity access in 2015 and grid extension program for the KEDCO service area, 2015–2030 ix Table 2 Technical summary for the LV Intensification & MV grid extension components of the universal access program for the KEDCO service area, 2015–2030 8 Table 3 Population estimates for “isolated” households through the KEDCO service area (2015–2030) 11 Table 4 Electricity access status and four components of grid electrification program for the KEDCO service area (2015) 12 Table 5 Estimates of population in various categories (in range of current grid, requiring grid extension, and “isolated”) in the KEDCO service area (2015 projected data) 12 Table 6 Electricity access in 2015 and grid extension program for the KEDCO service area, 2015–2030 14 Table 7 Nigerian Electricity Regulatory Commission (NERC) residential retail tariff classes, Multi-Year Tariff Order (MYTO), 2014 18 Table 8 Electricity access in 2015 and grid extension program for the KEDCO service area, 2015–2030 18 Table 9 NetworkPlanner model recommendations for grid and off-grid (SHS) electrifica- tion in the KEDCO service area, 2015–2030 19 Table 10 Projected electricity demand and grid extension metrics for the KEDCO service area, 2015–2030 21 Table 11 Proposed household grid-connections with related MV Line extension and New Generation, for each State in the KEDCO service area, 2015–2030 23 Table 12 Fixed and variable costs per household grid connection (KEDCO service area, 2015–2030) 25 Table 13 Electrification status (2015) and proposed connections through both LV inten- sification and MV grid extension (2015–2030) for educational facilities (KEDCO service area) 25 Table 14 Electrification status (2015) and proposed connections through both LV intensi- fication and MV grid extension (2015–2030) for health facilities (KEDCO service area) 30 Table 15 Estimated percentage of isolated dwellings in polling unit areas based on house- hold density 40 Table 16 Variation in recommended electricity type and MV/HH with changing house- hold electricity demand Executive Summary This report for the first part of the Nigeria Electrifica- gram is estimated to require ~5–5.5 million new con- tion Access Program Development (NEAPD) sum- nections over the next 15 years, using a combination marizes results of geo-spatial least-cost planning for of grid and non-grid technologies. universal electricity access by 2030 throughout the This analysis provides a “planning grade” esti- service area for the Kano Electricity Distribution mate of total costs and technical needs for universal Company (KEDCO), Nigeria. This work has been electrification based on best available data. It is in- undertaken by the Earth Institute, Sustainable En- tended to support high-level planning and decision- gineering Lab, working in close collaboration with making, including discussions among government KEDCO, supported by the World Bank under the agencies, utilities, and funding partners regarding Sustainable Energy for All (SE4ALL) initiative. This budgets, policies, capacity building programs and program emphasizes electricity access, the first of other components of a multi-year electrification pro- the three SE4ALL focal areas, the others being ef- gram. This analysis is not intended as an engineering ficiency and integration of renewable energy tech- design or construction program. Key uncertainties, nologies. The resulting access plan covers the whole particularly the completeness and accuracy of popu- of the KEDCO service area, combining grid and off- lation datasets, limit the accuracy of modeling out- grid technologies, for the 2015–2030 timeframe. A puts. Furthermore, this analysis focuses on the total key feature of geospatial least-cost plans is that they costs and technical needs for universal electricity reflect local actual conditions. Their accuracy and ef- access over the 2015–2030 period as an aggregate. fective implementation therefore requires the update The rate of implementation of this program, includ- of plans over time, as illustrated by international best ing the annual pace of household grid connections practices. The update of GIS-based plans also pro- or solar home system provision, will depend upon vides a powerful monitoring system to track prog- yearly investments, capacity within the utility to ress over the implementation of access programs. implement large-scale grid roll-out, and other issues KEDCO, headquartered in Kano City, has a cover- that are beyond the scope of this assignment. These age area including three states (Kano, Jigawa, Katsina) factors are addressed in the investment prospectus, comprising a projected population for 2015 of rough- also supported by the World Bank. ly 24 to 25 million1 in an area of approximately 67,500 The least-cost geospatial plan for scale up of elec- km2 (~26,050 mi2). This access planning occurs with- tricity access in KEDCO’s service area broadly out- in the context of KEDCO’s recent privatization and lines a program for achieving universal electricity related challenges, including: the long-standing need access in a systematic, efficient and least-cost man- for additional electricity supply, the urgent need to ner. Furthermore, the analysis and results of this re- improve revenue by distinguishing paying customers port provide a geospatial and quantitative frame for from non-paying electricity “consumers”, and to pro- the design and detailing of a well-coordinated and vide grid access to large portions of the service area. harmonized implementation program for grid and Meanwhile, current growth estimates suggest that the off-grid electrification over a fifteen-year timeframe total population of the three states will reach 34 to 35 (2015–2030). million by 2030, adding around 2 million homes to Overall, the analysis confirms that—given the the KEDCO service area. Considering these needs— demographic settlement patterns and relevant tech- connections for current and future homes without nical, economic and financial parameters provided grid access, and improvements to informal or unme- primarily by domestic, Nigerian sources—a grid roll- tered connections—a universal electrification pro- out-based strategy is the least-cost means to provide ix x Executive Summary access to the vast majority of the population by 2030. a. Customers: KEDCO estimates that it has The analysis in this report also indicates the potential ~400,000 pre-existing residential customers, rep- and scope for an off-grid program—designed, har- resenting 7% of the households projected for the monized and coordinated with the grid rollout pro- service area in 2030. While these households al- gram, with both geospatial and temporal targeting. ready have KEDCO accounts and pay for service, Both components of the access scale up and roll- 63% lack meters and pay a monthly flat rate. Me- out program are discussed in the following sections ters for these homes will require an additional in- of the Executive Summary. vestment of around $40 million (~250,000 house- holds at ~$160 per household3). Enumeration of all customers, including creation of a geo-located ES1. Grid Electrification customer database, is among KEDCO’s highest Program priorities as the utility works to improve revenue. Over the long term, grid extension is the least-cost b. Consumers: KEDCO also has many grid-con- electrification option for virtually the entire popula- nected “consumers” which receive service but are tion (~97%) within the KEDCO service area. Table neither billed nor pay for electricity use. KEDCO 1 below summarizes the components and costs for a does not know the size of this component, so it ~$3.3 billion2 grid extension program that will reach has been estimated here using Living Standards about 5.3 million households, resulting in nearly Measurement Survey (LSMS) data to be about universal grid coverage, by 2030. 840,000 households. This represents 22% of cur- This fifteen-year grid extension program in- rent households (2015) and will be 15% of service cludes four components: area households in 2030. In parallel with the effort Table 1  Electricity access in 2015 and grid extension program for the KEDCO service area, 2015–2030 Electricity access status (2015) Grid extension program (2015–2030) Components of grid Total CAPEX Type Populationa program Populationa,b CAPEX per HH of (Type of grid access (M access (Households) Percent planned) (Households) Percent USD) (USD) Grid 7,430,000 31% A) Customers: 2,400,000 7% $40 $160 access KEDCO has ~400K customers (2015); 63% need meters ($160/HH) (400,000) (1,240,000) B) Consumers: 5,030,000 15% $150 $180 ~840K HHs (2015 est.) consume power but do not pay KEDCO; (840,000) all need meters & improved connections (~$180 per HH) No grid 16,480,000 69% C) LV Intensification: 15,680,000 47% $1,670 $625 access By 2030, ~2.7 M HHs near the grid will need LV line, meter, connection (2,670,000) (~$630 per HH) (2,750,000) D) MV grid extension: 10,560,000 31% $1,470 $835 By 2030 ~1.8 M more distant HHs (>1.5 km from transformer) will need (1,760,000) MV and LV line, connection, meter (~$840 per HH) Total 23,910,000 100% Total 33,670,000 100% $3,330 $590c (3,990,000) (5,670,000) a Based on census data, rural households have 6.1 persons on average vs. 5.8 for urban households. For simple computations and where the ratio of urban and rural households is unknown, 6 persons per household is assumed. b It is assumed that population growth from 2015–2030 among those who currently have grid access (components A and B) will lead to net formation of new households that will need new connections requiring LV intensification (component C), MV grid extension (component D) or off-grid access. c Average household costs are calculated by summing all CAPEX costs across all program components and dividing by the total number of households served. Executive Summary xi Figure 1   Existing grid lines and the prioritized grid expansion plan based on average cost per household for the KEDCO service area, 2015–2030 to enumerate paying customers, KEDCO is also from $730–1,100 (average ~$840) per house- working to identify and convert these “consum- hold. This is the second-largest component of the ers” into customers by improving connections electrification program, connecting ~1.8 million and adding meters and accounts at a cost of ~$180 homes (~30% of projected households by 2030) per household4 (~$150 million total). for ~$1.5 billion. c. LV Intensification: This analysis estimates that, by 2030, 45% of projected homes will reside in Costs for homes that will be on the grid by 2030 locations that are currently within 1.5 km 5 of an can be summarized as follows:6 Components A and existing transformer. KEDCO can connect these B (Customers and Consumers) require only small ex- with LV extensions, service drops and meters, at penditures for equipment like meters and improved an estimated average cost of ~$630 each, for a to- connections, and so will likely cost less than $200 per tal of ~$1.7 billion for ~2.7 million households. household. Households connected through LV Inten- This is the single largest component of the over- sification (Component C) require ~ $660 most for the all electrification program, both in number of meter, service drop, and LV line. These three compo- households served and total costs. The accuracy nents (A-C) target a total of nearly 4 million homes, of this estimate is likely to improve as KEDCO which represents between 65 and 70% of the universal learns more about its customer database as it access program, all of which is expected to occur with works to quantify components A and B. little or no extension of MV line. Homes reached by d. MV Grid Extension: Households beyond 1.5 km component D) MV Grid Extension have the same lo- range of a transformer will require extension of cal connection and low voltage costs as component KEDCO’s MV line at an estimated cost ranging C, plus the additional cost of medium voltage line xii Executive Summary Table 2   Technical summary for the LV Intensification & MV grid extension components of the universal access program for the KEDCO service area, 2015–2030 New generation needed Number household grid Grid length proposed (MW) for residential connections proposed (km) connections LV MV grid LV MV grid extension intensification extension intensification MV grid LV MV/HH State extension intensification MV LV (avg, m) LV Jigawa 510,000 482,400 6,600 15,200 12.9 13,200 120 120 Kano 640,000 1,523,200 5,600 18,700 8.7 34,800 170 400 Katsina 610,000 664,400 7,000 18,200 11.4 17,000 150 160 Sub-total 1,760,000 2,670,000 19,200 52,100 10.8 65,000 440 680 Total 4,430,000 136,300 1,120 extensions spanning distances between villages. This the remaining ~30% of grid-targeted households introduces substantial variation in per household that are beyond the range of the existing grid. connection costs in this component (D) due to geo- Table 2 below is a technical summary of the grid spatial factors such as the size and spacing between extension program by state, including number of communities, resulting in a range of between about connections, MV and LV line length, and new gen- $700–$1,100 per household for only those house- eration required.7 holds in the MV grid extension component. These data illustrate a few key conclusions of this This analysis includes a cost-benefit prioritiza- analysis. The bulk of the new grid customers and 60% tion of MV grid extension based on the objective of of the ~1.1 GW of new electricity demand will result meeting the most electricity demand with the least from LV intensification—the process of connecting investment. In practice, this means prioritizing con- homes that are near existing transformers with only nections to larger communities closer to the grid LV line—and the majority of this intensification will first, then moving out to reach smaller, more distant, target Kano state, the most urbanized state within the and more dispersed communities. High priority grid KEDCO service area. The proportions are roughly extensions in dense areas require less MV line per reversed for MV network extension: about 70% of household on average (~5–10 meters) at a cost of the MV extension is targeted for Katsina and Jigawa. $700–850 per household. For latter parts of the MV Similarly, the estimated MV line needed per house- grid extension program that target increasingly rural hold is higher in Jigawa and Katsina (11–13 m) than and remote areas, a greater MV line investment per in Kano (8–9 m). The vast majority—over 115,000 of connection will be required (15–25 meters on aver- the 136,000 km—of new grid line will be low voltage. age), leading to household connection costs averag- In fact, the overwhelming majority (>90%) of the ing $900–1,200. Figure 1 above illustrates this pri- total grid extension program costs are low-voltage, oritization, based on household connection costs, of local investments: Over $3 billion of the ~$3.3 bil- grid roll-out for the KEDCO service area. While this lion total program cost will be for LV distribution map is not a construction design, it nonetheless pro- lines, service drops, meters, and other costs of this vides insight into how grid extensions can be broadly “last mile” for access. In contrast, the medium volt- prioritized and budgeted in a manner that responds age investments—the construction of 19,200 km of to cost-benefit considerations. Note that the major- MV line spanning distances between communities— ity (~70%) of the KEDCO area homes lie within 1.5 is estimated to cost only ~$310 million ($16/m), less km of the existing grid and can be connected to grid than 10% of the of grid electrification program cost. with no MV extension. The colored lines in this fig- This grid extension program also implies a sub- ure show MV grid extensions required to reach only stantial increase in generation for the KEDCO area. Executive Summary xiii The program would add 5–5.5 million new residen- systems and diesel or hybrid mini-grids—during a tial customers to the KEDCO grid. It is estimated that more detailed future program design. each new household connection of average income would add about 1,200 kWh of electricity demand Off-grid electrification for areas where B.  per household per year (requiring an additional ~ 400 grid is not the recommended least-cost peak Watts of capacity), while poor homes would add option about half this, 600 kWh/year (~200 Wp). Poverty This component is likely to be smaller than the pre- mapping data from an Oxford University study8 com- electrification component described above, and missioned by the World Bank was used to estimate comprises two types of beneficiaries: the distribution of this range of household demand throughout the KEDCO service area and resulted in i. Very small and/or remotely situated villages a weighted average household demand of ~840 kWh/ that are unlikely to be cost-effectively served by year. It is assumed that each new KEDCO residential grid connectivity within the next 15 years. These customer will add, on average, around 250–300 W “long-term off-grid communities” represent a of peak demand to the system (the weighted average very small percentage of the total KEDCO ser- is ~260 W). This will require about 1.1 GW of new vice area (<1%) which will need non-grid power. generation,9 nearly 700 MW of which would be due As with the pre-electrification program described to new connections near the existing transformers above, these would be served by a mix of solar (“intensification”), while the other ~450 MW would home systems and appropriately sized mini-grids. result from MV grid expansion. ii. Homes and small loads that are “isolated,” mean- ing that they are more than around 100 m from any neighboring structure. These may, or may ES2.  Off-Grid Electricity Access not, be far from the exiting grid, but their local In parallel with and complementing the MV-grid isolation from neighboring structures raises the extension program, this analysis provides a broad cost of grid connectivity greatly. These are ex- technical and geospatial plan that can serve as the pected to be most cost-effectively served by solar basis for the future development of more locally home systems, since the homes are too distant specific and technically detailed designs for imple- from neighbors to be connected to mini-grids. mentation of off-grid electrification. Broadly, this targets two types of beneficiaries: Together, these two types of households tar- geted for off-grid electrification—those located in Pre-electrification for communities that A.  communities that will be reached by grid exten- will wait several years for grid access sion after many years, and those that are “isolated” Potentially, the largest component of the off-grid households—represent ~3% of the projected 2030 electrification program consists of households and population or about 165,000 households which are communities10 which are targeted for grid connec- expected to be served by off-grid technologies for tions in the latter part (beyond the medium-term) the foreseeable future. of the 15-year MV grid extension plan and thus An off-grid “pre-electrification” program tar- will be required to wait potentially for several years geting transitional off-grid areas—to provide basic (5–10, if not longer) for electricity access. This could power supply for essential needs to those households, be a large group of beneficiaries, although, the size, communities, and institutions that would likely have target areas, cost and timing of a pre-electrification to wait beyond the medium-term for a grid connec- program will eventually depend upon the actual tion—merits consideration. It is also noteworthy that implementation and sequencing of the rollout plan. a transitional off-grid plan (segment A above) would These communities could be provided access in the require investment and related program cost that is interim with sufficient power for essential electricity additional to the overall least-cost grid rollout plan. services such as household lighting, and charging of For this reason, it is appropriately considered only mobile phones and other batteries and devices, and following completion of the Investment Financing basic connectivity for schools and clinics to power Prospectus (2015–2020), and following KEDCO’s computers, vaccine cold chain, and other services. determination of its five-year rollout implementation Specific electrification technologies can be evalu- plan, which will include geographically specific, an- ated and selected—from options such as solar home nual rates of new connections. For example, if KED- xiv Executive Summary CO elect to undertake the lower costs extensions and 3. Estimates of customer numbers and costs ($125 connections in areas close to the existing grid first— for single-phase meter and other small costs) were those needing meters and/or LV intensification in- provided by KEDCO, October 2015. vestments only—this would imply that the majority 4. These connections are expected to require more of the homes and communities that are potential tar- technical improvement in addition to meters. geted for “transitional” off-grid connections would 5. KEDCO estimates 1.5 km as the radius within occur within the MV Grid extension portion of which customers can be connected without addi- the program (component D in Table 1 above). In a tional MV line. scenario targeting service for those for whom grid 6. A cost-buildup for household grid connections is service would be most delayed, the areas initially provided in Table 12 on page 23. targeted for transitional “pre-electrification” would 7. This table reports the grid extension plan results likely be among those with the highest unit cost per with an “MV Correction Factor” which approxi- connection (marginal unit costs form a rising curve, mately doubles the length of MV line needed per as presented in Figure 16). On the other hand, KED- household, adding about 15% to the total and per CO’s strategy for access scale up could well respond household costs of MV grid extension. This “cor- to other key drivers, as of yet undecided. Some of rection factor” is described in Section 1.3 and Ap- the key considerations include a target for the an- pendix A3. nual implementation rate of new connections over 8. Gething, P., Molini, V. (2015, June 10) Developing the period 2015–2020, to be geospatially identified an Updated Poverty Map for Nigeria. Final Report. and approved by NERC. This and other determining [No web address available] factors would need to be defined before the develop- 9. Ensuring adequate electricity supply to all custom- ment of detailed local off-grid rollout plans. Another ers served by KEDCO is an urgent and important key consideration is the technical standards to which concern. As of 2015, peak supply to KEDCO was transitional systems would be built, since this would typically around 250 MW with occasional higher affect whether investments in mini-grid generation, peaks. This is well below the 1 GW that KEDCO distribution and metering equipment would be pre- estimates to be its total current demand. The 1.1 served or recovered once the grid arrives. GW demand forecast here would be a) only for residential needs, and b) in addition to any unmet current need. Endnotes 10. The total number of households or communities 1. 2011 population projections are by the National targeted for pre-electrification will depend upon Population Commission of Nigeria; these are then several factors that cannot be known at the time projected forward to 2015 and beyond in this of this study, including the pace of grid expansion analysis. year-to-year, and the total funds available for these 2. All costs throughout the text and tables of this additional electricity systems. document are in constant 2015 US dollars, unless otherwise noted. Introduction This document presents the final results for the homes (>100 meters from the nearest neighbor); c) geo-spatial electrification planning for the Nigeria an “MV correction factor” to address the fact that Electricity Access Program (NEAP) – Technical locations of INEC polling units do not represent all Assistance (TA) conducted by the Earth Institute’s rural towns and villages. (For details, see section 1.2. Sustainable Engineering Lab (SEL/EI), supported by Geo-located Populated Places). the World Bank under the Sustainable Energy for Investigating and estimating a range of techni- All program.1 The partnership between SEL/EI and cal and cost parameters related to factors such as KEDCO has now completed task 6 as outlined in population and related growth, costs of electrifica- the initial proposal. The primary output will be this tion equipment, and electricity demand, incorporat- final report which discusses two broad activities: ing patterns of poverty and wealth (see section 1.4 establishing a geo-spatial database and performing Model Parameters and Other Data Inputs). electrification modeling. In December 2014, the Working from this base of input data and pa- Earth Institute team provided an Inception Report, rameters, the SEL/EI team has performed geospatial outlining various sources and approaches to obtain- analysis to estimate the overall extent, cost and tech- ing key input data. In the months that followed, up nical details of a grid and off-grid electricity system to July 2015, the SEL/EI team established the geo- that would serve the whole population of the three spatial database. This work is described in Chapter states (Kano, Katsina and Jigawa) of KEDCO service 1 – Input Data and Parameters and comprised the area. This modeling effort and results are described following three steps: in Chapter 2. Preliminary results were written up in Mapping by KEDCO of its own medium-voltage draft form throughout April–June, 2015. This was (MV) grid distribution infrastructure, including followed by two trainings which took place in May, ~10,000 km of lines, ~7,000 transformers, sub-sta- 2015—one in MV line mapping, targeting multiple tions and generation sites (completed July, 2015, see utilities, and the other focused on data preparation section 1.1. Mapping Medium Voltage Grid Line). and geo-spatial electrification modeling, targeting Assessment and reprocessing of INEC polling only KEDCO. This document provides a final, up- unit data in comparison with data for the existing dated report of all work for this project. grid, satellite imagery and survey data. This work focused on three estimates: a) the number of non- paying “consumers” currently receiving service Endnote form the KEDCO grid; b) the number of “isolated” 1. www.se4all.org. 1 CHAPTER 1 Input Data and Parameters 1.1 Mapping Medium Voltage zz Latitude / longitude coordinates were collected for ~7,000 transformers and ~45 substations; Grid Line zz The KEDCO service area is ~68,000 sq. km and A key input for electrification planning is geo-ref- has a total population of ~25 million (2015 est.3). erenced data for electricity infrastructure, which is needed to quantify the spatial patterns of current This commendable effort by KEDCO merits at- access and costs for future connections. At project tention for the aspects of implementation that con- inception, the sources of information for KED- tributed to its speed and success. CO’s grid distribution system were rough maps, single-line diagrams, or other resources that were zz KEDCO leadership provided firm and consis- sufficient for many utility operations but lacked tent support for the program: Grid mapping is a geo-spatial detail needed for village-level access labor- and resource-intensive exercise, requiring planning. To address this gap, SEL/EI provided sustained engagement of many layers of utility a week-long training in the use of smartphones staff across the full service area. The commitment and open-source editing software (JOSM1) for of vehicles, fuel, and labor for fieldwork, as well as data capture, editing and management to approxi- the office work required for data editing and vali- mately 15 KEDCO staff in Abuja in December, dation, necessarily compete with other budget- 2014. This was followed up with remote technical ary priorities and duties. These factors often lead support during the next 4–6 months, as KEDCO utilities to stop mapping efforts before comple- mapped the utility’s grid assets, including ~10,000 tion or validation. Given this risk, it was funda- km of MV Lines and 7,000 transformers (see Fig- mentally important that support from KEDCO’s ure 2 below).2 top management was consistent throughout and Some highlights and lessons from the KEDCO articulated clearly to all levels of staff engaged mapping: in the effort. In addition, mapping was not out- sourced, as is often the case, but rather execut- zz The entire effort required ~3–4 months of steady ed entirely by KEDCO staff. This ensured that work, spread over approximately 8 months, in- KEDCO absorbed new technical capacity (skills, cluding time for validation and gap-filling; software, data-gathering tools like smartphones zz Mapping employed ~12 team-vehicles (1 team and laptops) while retaining control of the pace per KEDCO business unit); of work and quality of the resulting map data. zz One vehicle was able to cover ~10–100 km per zz KEDCO management multiplied the work- day, depending on whether target areas were force and pushed the mapping effort: In many urban or rural (~10–30 km/day in urban areas; projects, mapping is attempted by small teams of ~40–100 km/day in rural areas); GIS or mapping specialists, whether consultants zz KEDCO mapped ~10,000 km of MV line: ~4,300 or utility employees. This tends to restrict the km in Kano, ~3,000 km in Jigawa, ~2,700 km in mapping team to a small group, slowing overall Katsina; progress, which in turn causes many utilities to Input Data and Parameters 3 Figure 2   MV grid line and transformers coverage in the KEDCO service area, July 2015 cease mapping long before the work is complete. ress, while driving data collection teams with In contrast, the SEL/EI team has found that map- frequent reminders and supporting the efforts of ping work proceeds better if the utility broadens field teams by phone and in person. There was an the mapping workforce, involving technical staff element of competition among business units, as at several levels of the utility’s hierarchy, and the planning department released weekly reports including technicians from all geographic ar- of teams’ performance. eas who can provide locally informed guides to zz Cloud-based data platform enabled better mapping teams. KEDCO’s planning department supervision and technical support: Typically, recognized early this need to “multiply the work- mapping projects encounter difficulties with the force” for grid mapping, and quickly ensured use of GIS software, particularly problems with that those trained in Abuja passed on their new sharing and collaboratively editing shapefiles. skills to others in each business unit. This in- These include problems with organizing and su- creased the number of trained mappers and data pervising mapping work, such as duplication and editors by roughly a factor of three, ensuring that omission of feeders or equipment; difficulty shar- each of KEDCO’s 12 business unit had at least ing map data and preserving “version control” as one full team of mappers and data editors. Then, multiple shapefiles are merged and edited; and KEDCO central management supervised prog- difficulty “seeing the bigger picture” when map 4 Input Data and Parameters Figure 3   Left: KEDCO engineers labeling and correcting data for MV grid infrastructure using JOSM editor. Right: A KEDCO engineer in training to map MV line infrastructure using a smartphone data are restricted to one or few staff comput- tional workshop to enable other Nigerian electricity ers. To address these issues, KEDCO’s mapping distribution companies4 to use this same mapping effort ensured that newly gathered map data was approach, supporting Nigeria’s capacity to establish uploaded to a cloud-based platform that could a national distribution map with common features be viewed in KEDCO field offices, Kano City as a step toward geo-spatial, data-driven planning headquarters, and by SEL/EI staff in New York. as a national standard. By June, 2015, data gaps in This allowed multiple users to review, integrate, the MV grid map were resolved, specifically for the correct, and validate map data in a collabora- northern portion of Katsina State, thus completing tive fashion as it was collected. This avoided the the map of KEDCO’s MV system. common pitfalls listed above, while facilitating The entire grid mapping effort spanned approxi- remote work among KEDCO headquarters, field mately 8 months, but took place in bursts of inten- offices, and the SEL team in NYC. Overall, this sive activity spanning perhaps 3–4 months. The greatly accelerated the identification and resolu- final stages of data review, in preparation for techni- tion of technical problems and validation of data. cal and cost modeling, emphasized the importance of validating the dataset. In May and June of 2015, As this mapping effort came to a close, the Earth problematic results in preliminary model runs and Institute/SEL team provided additional training validation efforts clarified gaps in MV line maps, (Abuja, March 2015) on validating the grid data and and these were resolved in June and July, 2015, lead- basic GIS skills. This training also introduced the ing to the final results presented here. The key les- KEDCO team to SEL/EIs modeling approach and sons learned and future steps of grid and possibly software (NetworkPlanner) and allowed the SEL/EI other infrastructure mapping is discussed in the and KEDCO teams to discuss and refine key model Summary Report document for this NEAP project. parameters. In May and June, 2015, SEL/EI and Considering future uses of this data and system, KEDCO used this new MV grid distribution system KEDCO recognizes the value of this map over the map as a key input to the technical and cost model- longer-term, as it allows an updated and accurate ing to support planning for expanded grid and off- measure of the system’s line length. It also pro- grid access throughout the KEDCO service area. vides a starting point for a data-driven approach Also in May, KEDCO mappers and planners joined to other important KEDCO concerns, such as load the SEL/EI staff as part of the training team in a na- flow analyses and establishing a customer database. Input Data and Parameters 5 Figure 4  INEC polling sites throughout the three state KEDCO service area, 2015 KEDCO plans to continue to validate, expand, and level, geo-located population data for the KEDCO maintain this power line dataset for its growing net- service area; however, voter registration data offers work to support future planning and maintenance. a useful proxy. Several other utilities have also responded favorably to this mapping approach, seeing it as a low-cost, Polling Unit Data: A Proxy for Village-level convenient method to establishing a basic map of Population Data utility assets to serve future planning. While the inception report noted various poten- tial sources of demographic data in Nigeria, the 1.2 Geo-located Populated most comprehensive, highest resolution and most validated data source currently available has proven Places to be the national voter registry created by Nige- An essential input data type for this modeling ap- ria’s Independent National Electoral Commission proach, and particularly for planning electricity ac- (INEC)5. The three states of the KEDCO distribu- cess for the underserved rural areas, is geo-located tion area (Kano, Katsina and Jigawa) contain about populated places. Because this project also aims 16,000 polling sites, out of a total of 120,000 nation- to quantify needs for small, off-grid communities, ally. These serve approximately 10 million voters, or population data that extends down to the level of an average of 600–650 voters per site. This compares individual villages is ideal. There is currently no with a total population for the three states of about known source of comprehensive, accurate, village- 19 million (Kano 9.4, Katsina 5.8, Jigawa 4.3 mil- 6 Input Data and Parameters Figure 5   Satellite imagery (Google) for part of Jigawa state shows correspondence between INEC polling sites (green points) and clustered structures indicating locations of communities lions), according to the 2006 census, and ~25 mil- Conversion of registered voters into populations: lion in 2015.6 Individual polling unit records list only the num- Figure 4 above illustrates that polling unit data is ber of registered voters, and so require conversion comprehensive throughout KEDCO’s service area, to estimate a population count. The conversion with apparent gaps in western Katsina and southern performed here employed a combination of census Kano corresponding to protected areas or reserves. information for populations and growth rates, as Similarly, as Figure 5 below shows, there is often a well as geospatial information defining urban vs. close match between polling unit locations (green rural areas based on the “night lights” satellite da- points) and human settlements, particularly larger taset7. The detailed method is described in Annex villages, which are easily identified in satellite imagery. A1 Derivation of Population based on Registered However, Nigeria’s polling unit data is not a cen- Voters at Polling Units. Figure 6 below shows ur- sus, and thus is only a proxy for geo-located pop- ban and rural extents derived from “night lights” ulation. The issues related to its use are described data. There is a clear correspondence between ar- below. eas identified as urban using night lights (yellow boundaries) and areas that have high population Corrections and Estimates Related to density as reported in the 2006 Census (darkest Polling Unit Data green polygons). Polling unit data required substantial pre-process- ing to address differences between the locations and Estimation of the percentage of isolated house- number of voters recorded for each polling unit ver- holds: Second, particularly in sparsely populated sus the locations and number of residents of popu- rural areas, a single polling place may serve popula- lated places. These pre-processing steps used a com- tions which are in fact dispersed (see Figure 7 be- bination of quantitative and GIS analysis, the results low). This dispersal may be either among multiple of which are summarized below and described in separate small villages or “isolated” households, greater detail in Annex A – Pre-processing of Elec- which in this analysis are defined as those more than tricity Demand Point Data. 100 meters from their nearest neighbor. Input Data and Parameters 7 Figure 6   Population density at LGA level (2006 Census) combined with urban boundaries as defined by the “night lights” satellite dataset shows correspondence of high density and urban areas To correct for this, SEL/EI used satellite imag- centage of isolated households in rural, low-den- ery to estimate the percentage—ranging from 5% sity areas. to 30%—of isolated homes in each of the ~16,000 The quantitative results of this analysis are pre- polling units throughout the KEDCO service area. sented in Table 3 below. A small percentage of the The method is detailed in Annex A2 Estimating the total population (a bit less than 3%) have been iden- Frequency of “Isolated” / Off-grid Households. The tified as “isolated”, starting at ~126,000 households geo-spatial result is presented in Figure 8 below in 2015 and growing to around 164,000 in the 15 which shows the percentage of isolated households years from 2015–2030. Also, as evident in Figure 8 using a grayscale for each polling unit coverage above, the vast majority of these isolated households area. Note the correspondence between areas with are in rural areas (>99%). lower estimated frequency of isolated households in Figure 8 and the urban areas shown previously Estimation of a “Medium Voltage Correction Fac- in Figure 6, as well as the higher estimated per- tor”: Another potential modeling error arises from 8 Input Data and Parameters Figure 7   One polling site (yellow point, left) serves a widely dispersed population (households marked with blue points). Some of these are clustered into neighboring villages that lack a polling site (upper center of image); others are “isolated” households, more than 100 meters from their nearest neighbor (periphery of image) the fact that not every village has its own polling accurately represented by polling units, while the site. Instead, voters from multiple separate villages dotted line illustrates an MV line to serve villages are assigned to vote at a single polling site that may which lack polling sites. be a significant distance from households and other A rough estimate, described in detail in Annex points that need electricity. Since these separate A3 Estimating the “Medium Voltage Correction Fac- villages would most likely be served by their own tor” suggests that the additional MV line required MV grid lines, the total MV line needed for an ac- to reach these villages that have no polling sites will tual grid extension program will exceed the length increase the total MV line needed throughout the predicted by modeling with polling unit points. This KEDCO coverage area by factor of 2. The techni- effect is illustrated in Figure 9 below, with a solid cal implications of doubling the total MV length of red line showing the grid recommended for villages the grid extension program are clearly significant, Table 3   Population estimates for “isolated” households through the KEDCO service area (2015–2030) 2015 2015–2030 (with Pop. Growth) Population % of Urban/ Population % of Urban/ KEDCO area Rural KEDCO area Rural (Households) population population (Households) population population “Isolated” (SHS 830,000 3% Ur: ~5,000 985,000 3% Ur: ~6,000 recommended) (126,000) Rur: (164,000) Rur: ~825,000 ~979,000 Input Data and Parameters 9 Figure 8   Estimated frequency of “isolated” households (suitable for off-grid technologies) for all polling unit areas in the KEDCO service area but this does not change the overall cost outcome of access, commonly referred to as “penetration”. This the analysis fundamentally. The reason for this, as includes two main categories of existing or potential stated previously, is that the bulk of the grid access connections: program’s costs (90%) arise from local, low-voltage distribution and connection. A doubling of MV- 1. “Customers” (connections with KEDCO ac- related costs only increases the total cost of the full counts): KEDCO estimates that as of 2015 it has grid access program by around 5%. ~400,000 customers. 2. “Consumers” (those connected to and consum- Estimating grid penetration: Since the breakup of ing power from the grid, but who do not pay for the national power company, Power Holding Com- service): KEDCO says the number of customers pany of Nigeria (PHCN)8, KEDCO and other re- is unknown, but estimates that the number is 2–3 cently privatized utilities throughout Nigeria face times as large as the number of customers. a challenge in quantifying the current state of grid 3. Households reachable with “intensification”: 10 Input Data and Parameters Figure 9   Solid blue lines show MV needed to reach villages represented by polling sites (yellow points); the dotted blue line shows the extra MV line needed to reach villages without polling sites households within a 1.5 km range of existing sis are described in detail in Annex A4 Estimating transformers but currently without grid access Grid Penetration, and the results are summarized in are reachable with LV extensions and connec- the following section. tions. KEDCO has no estimate of the number of households in this category. 1.3 Components of a The utility is working urgently to establish an ac- Universal Electrification curate database of existing customers while launch- ing a program to convert non-paying consumers Program into paying customers by improving connections, The combination of geo-spatial data, estimates of installing meters, and establishing accounts. How- grid-connected and isolated households, and cor- ever, substantial progress on all of these goals is like- rection factors establishes the basis for modeling by ly to require at least one year. In the meantime, to es- placing households in categories based on whether timate the number of households in the second and they are connected to the grid, and how distant they third categories, the SEL/EI team conducted a geo- are. This physical description serves as a basis for de- spatial analysis that combined three data sources: (i) fining the categories (or “components”) of a national the locations of recently-mapped transformers; (ii) electrification program. This analysis considers grid polling place data as a proxy for population; and (iii) and off-grid electrification programs separately. Nigerian LSMS data regarding grid electricity access in the home. A key assumption in this analysis is Grid Extension Program the 1.5 km distance from a KEDCO transformer to Table 4 below provides estimates of the number of a household that still permits connection with only households that fall into each of these categories, us- low-voltage line extension.9 The steps in this analy- ing population values for 2015. Input Data and Parameters 11 Table 4   Electricity access status and four components of grid electrification program for the KEDCO service area (2015) Four components of grid Population Electricity access status (2015) extension program (2015) (households) Percent Connected 7,430,000 A) Customers: 2,400,000 10% to grid (1,240,000) pre-existing KEDCO Accounts (400,000) B) Consumers: 5,030,000 21% need KEDCO meters & accounts (840,000) Not 16,480,000 Within Range of C) Intensification: 7,690,000 32% connected (2,750,000) Transformer (<1.5 km) need only LV & connection (1,290,000) to grid Outside Range of D) Grid extension 8,790,000 37% Transformer (>1.5 km) need MV, LV & connection (1,460,000) Total 23,910,000 Total 23,910,000 100% (3,990,000) (3,990,000) Reading the table from left to right, it first di- of the grid electrification program that will require vides the 2015 population into those connected or extension of the MV grid line. not connected to the grid. Then, based on the kind Further analysis considered these geospatial pat- of connection or the proximity or distance from the terns for population and grid location data for 2015 grid, it defines the four categories of existing and throughout urban and rural areas served by KED- potential grid connections. Of those that are con- CO. Table 5 below highlights differences in the pen- nected, about one-third (or 400,000 households) etration rate between urban and rural areas yielding can be categorized as (A) “customers”: those house- a few important observations. The vast majority of holds with formal grid access which currently re- the KEDCO area’s urban population (98%, or about ceive and pay KEDCO for service. Another 840,000 5.2 million) is within range of transformer. This estimated homes are in component (B) “consum- leaves only 140,000 urban residents who require ex- ers” which have informal grid access and receive tension of the MV grid. In contrast, only half of the KEDCO service but do not pay. The ~2.75 million rural population (8.8 out of 16.7 million) is within homes that are not currently connected to the grid 1.5 km of a transformer; the rest will require MV fall into two more categories. Those within 1.5 ki- grid extension. lometers of an existing transformer are placed in Note that much of the information in the two category (C) “LV intensification’ meaning that they preceding tables is based on estimates, rather than can be connected through extension of only the verified counts. The estimates are based on a combi- low voltage (LV) grid at relatively low cost. Those nation of geo-spatial datasets and criteria—such as households more than 1.5 km from an existing urban/rural discrimination performed using night transformer fall in category (D) “MV extension” lights data and KEDCO’s somewhat informal des- meaning that they require addition of medium ignation of 1.5 km limit for LV extension—that are voltage line to reach the community, as well as all essential for electrification modeling and provide the LV and connection investments that apply for information that was not obtainable from more category (C). These data match the columns labeled standard sources within Nigeria. “Electricity Access Status (2015)” in Table 1 from The final important step in preparation of the the Executive Summary. geo-spatial data for modeling is to project these This breakdown provides a few important in- 2015 population values forward to 2030, the final sights. It appears that ~60% of the population (com- year of this planning exercise. Table 6 below pres- ponents A, B and C) within the KEDCO service area ents the projected populations and household num- either already has grid access, or can obtain grid ac- bers for the categories defined in Table 4, with a few cess relatively quickly and inexpensively, with only important assumptions. It is assumed that popula- LV extensions and connections.10 There is nonethe- tion growth from 2015–2030 among those who cur- less a large group, probably ~37% (component D) rently have grid access (components A and B) will 12 Input Data and Parameters Table 5   Estimates of population in various categories (in range of current grid, requiring grid extension, and “isolated”) in the KEDCO service area (2015 projected data) Total (urban + rural) Urban Rural Grid access estimates (2015) Population Percent Population Percent Population Percent Within range of Connected to grid 7,400,000 31% 3,400,000 54% 4,000,000 23% transformer (<1.5 km) Not connected to grid 7,700,000 32% 2,800,000 44% 4,800,000 27% Outside range of transformer (>1.5km) 8,800,000 37% 140,000 2% 8,700,000 50% Total population 23,900,000 100% 6,300,000 100% 17,500,000 100% lead to net formation of new households that will age vs. 5.8 for urban households. For simple com- need new connections requiring LV intensification putations and where the ratio of urban and rural (component C), MV grid extension (component D). households is unknown, 6 persons per household is In other words, components A and B do not show assumed. population growth from 2015–2030, because this The most important conclusion to be drawn population will “spill over” into categories C and D. from this table relates to the size of the future grid Also, population growth generally is modeled based extension effort. Once population growth is con- on census information regarding urban and rural sidered, the total of homes newly connected to the growth rates. Projections for this analysis utilize grid is estimated to reach 4.4 million by 2030 (as those growth assuming that the incorporate factors opposed to 2.75 million estimated to need connec- such as internal migration, differential fertility in tions in 2015). It is crucial for utilities to keep in urban and rural populations. That is, we have made mind that, however daunting the task of reaching no additional assumptions about how populations the ~70% of homes that are currently unconnected, move among categories. Finally, based on census this population will nearly double in an additional data, rural households have 6.1 persons on aver- 15 years. Table 6   Electricity access in 2015 and grid extension program for the KEDCO service area, 2015–2030 Electricity access status (2015) Grid extension program (2015–2030) Type of Population Components of Grid program Population access (Households) Percent (Type of grid access planned) (Households) Percent Grid 7,430,000 31% A) Customers: 2,400,000 7% access KEDCO has ~400K customers (2015); 63% need (400,000) meters ($160/HH) (1,240,000) B) Consumers: 5,030,000 15% ~840K HHs (est.) consume power but do not pay (840,000) KEDCO; all need meters & improved connections (~$180 per HH) No grid 16,480,000 69% C) LV Intensification: 15,680,000 47% access By 2030, ~2.7 M HHs near the grid will need LV line, (2,670,000) meter, connection (~$630 per HH) (2,750,000) D) MV grid extension: 10,560,000 31% By 2030 ~1.8 M more distant HHs (>1.5 km from (1,760,000) transformer) will need MV and LV line, connection, meter (~$840 per HH) Total 23,910,000 100% Total 33,670,000 100% (3,990,000) (5,670,000) Input Data and Parameters 13 Off-Grid Electrification Program the population—about 830,000 people in 2015, or Two subcomponents are broadly distinguished 980,000 by 2030—are estimated to live in “isolated” within the off-grid program. households that are more than 100 meters from the nearest neighboring structure. Another even A.  Pre-electrification in Transitional Off-grid smaller population lives in communities in which Areas households may be tightly clustered but, due to a This component of the off-grid program poten- combination of low total demand and distance of tially targets “transitional areas” to meet the needs the community from existing and proposed grid, of households and communities as they await grid are not viable for grid extension. Both of these pop- rollout. The total size, scope, and cost per house- ulations—isolated households and remote com- hold of a transitional off-grid program will be de- munities—will be most cost-effectively served by termined based on numerous factors unknown at solar home systems or similar non-grid technolo- this time, such as the expected pace of grid con- gies.11 This more permanent off-grid component is struction, the availability of funds for off-grid in- much smaller, totaling between about 130,000 and vestments, and the service standard (kWh per year 170,000 households, depending upon population supplied). As the KEDCO grid extends to a grow- growth. ing population of more than 4 million homes over the 15 years between 2015 and 2030, in any realistic implementation timeline a substantial number of 1.4 Model Parameters and households would likely wait 5, 10, or more years for grid connectivity. The homes that would wait Other Data Inputs the longest probably fall within the MV Grid ex- Gathering Modelling Parameters from Local tension program (component D in Table 6 above). Sources Many of these would be good candidates for some A fourth key type of information includes the nu- sort of transitional, off-grid electrification, using merous parameters related to equipment costs, technologies such as solar home systems and mini- technical specifications, growth rates, and other de- or micro-grids. The pool of potential beneficiaries tails required for modelling grid and off-grid costs is so large that service for even a fraction of these and technical needs. These parameters have been homes with modest solar home systems, at a cost of acquired in various ways, such as conversation with perhaps $150–$200 per household, would result in the utility, field visits and international sources. The a program cost of hundreds of millions of dollars. Earth Institute team gathered many of these during It is essential to note that the transitional off-grid the March, 2015, training visit, and refined them in systems would be in addition to all other invest- discussion with KEDCO staff throughout the fol- ments described in the grid extension program lowing 2–3 months. (components A-D), and at least some aspects of Electricity demand per household is among the these installations, possibly the majority, would be most important parameters for modelling pur- temporary. It is unknown at this time what propor- poses, but it is also often difficult to obtain con- tion of the transitional off-grid investments would clusive data for this metric. KEDCO officials and be recoverable once the grid arrives, and this will engineers provided current electricity demand certainly depend upon factors such as whether in- values ranging from a low of 600 kWh per house- frastructure such as local LV distribution networks hold per year, to a high of around 1,200 kWh/ are built to utility standards, and whether elements HH-year.12 This range was validated through a such as solar panels could be moved and reinstalled number of steps. KEDCO applies a “life-line” tar- elsewhere. iff for households consuming up to 50 kWh per month, the lowest tier residential customers cat- B.  Off-grid Electrification – Areas Where Grid egorized as “R1” (see Table 7 below), marking a Is not Least Cost lower end of this range at 600 kWh per year. The A second component of the off-grid program upper end was determined in part through discus- would target “isolated” households and commu- sion with KEDCO staff and in comparison with nities which cannot be cost-effectively served by international results, which tend to range from grid, and so would need off-grid service for the about 1,000–1,200 kWh per year for households foreseeable future. As described previously (see that use electricity for services such as rice cooking Table 3), a small, but significant portion (~3%) of that are beyond the minimal needs for lighting and 14 Input Data and Parameters Table 7   Nigerian Electricity Regulatory Commission Costs for solar systems were obtained from a (NERC) residential retail tariff classes, Multi-Year combination of sources, including renewable energy Tariff Order (MYTO), 2014 specialists with the Federal Ministry of Power and compared with international prices.14 Customer classification Description Residential zz Solar PV panels: US$0.80 per Watt-peak. R1 Life Line (50 kWh/month maximum zz Batteries: US$150 per kWh; with 3 year lifespan. R2 ‐phase Single and 3-­ R3 LV Maximum Demand Household size was derived for each state or re- R4 HV Maximum Demand (11/33 kV) gion using the data reported in the Population and Housing Census Priority Tables by the National Pop- ulation Commission of Nigeria based on 2006 Cen- phone charging. Finally, this range was compared sus, which included both the number of households, with income and expenditure data from the LSMS and the total population for a given community. data for Nigeria, which showed a factor of two between poor and richer household expenditures Poverty Mapping for energy overall. Based on this range, demand Poverty and wealth mapping information can be for a “poor” residential customer was estimated to used in a variety of ways to address goals of shared be 600 kWh per year while non-poor households prosperity in national electrification planning. One were assumed to consume twice as much electric- is to add spatial nuance to estimates electricity de- ity, or 1,200 kWh per year. mand. Data on household and community income, Other key grid cost and technical parameters13 assets and expenditures can act as a guide to spatial are illustrated below (for the full list of more than 70 variation in demand estimates and service stan- parameters and their sources, see Annex B – Model dards, and as a proxy for willingness and ability to Parameters): pay both initial connection costs and tariffs. Anoth- er way to integrate poverty mapping data into the zz MV line: US$16,000 / km analysis is to use it as a means to estimate needed zz LV line: US$12,600 / km subsidies, provisions such as “life line tariffs,” or zz Distribution losses: 15% other policies that can help the poor benefit from zz Connection cost: US$250 (this is an average for electrification. single and three-phase connections, including a As indicated in the inception report, SEL/EI $75 connection cost for labor and administrative team has worked to integrate the outputs received work to establish a new connection and account, (in mid-March, 2015) from the Oxford Poverty plus $175 equipment costs, for the meter and ser- Mapping effort funded by the World Bank for the vice drop) whole country of Nigeria.15 A map illustrating the zz Cost of power: US$0.16 per kWh overall results of poverty estimates for specific areas of the KEDCO coverage area is shown in in Figure The last of these cost parameters, the US$0.16 10 below. The percentages show in this map indicate per kWh “bus bar” cost of power, is of fundamental the fraction of households consuming 600 kWh per importance. Briefly, it represents all costs of genera- year as is assumed for poor households versus the tion and transmission to deliver power to the medi- non-poor rate of 1,200 kWh per year. Details of this um-voltage substation, considering the full mix of analysis are provided in Annex B2 Poverty mapping existing and new generation, across all technologies and household demand estimates. including hydropower, gas turbines, and others, as well as all costs for existing and new transmission, including losses at this HV level. It represents the Endnotes internal cost of power for the utility, not the final 1. Java Open Street Maps (JOSM) is a free, open- retail price of power to the consumer. source desktop editing program supporting For diesel gensets, cost of fuel is a dominant re- multi-user mapping tasks (https://josm.open- curring (and lifetime) cost: streetmap.de/). 2. These results include all data available as of early zz Diesel Fuel: US$0.87/liter July, 2015, which KEDCO assures is complete. Input Data and Parameters 15 Figure 10   Poverty rate (% of poor households) for the KEDCO service area based on geospatial data recent research from Oxford University (Gething & Molini) 3. Population projections for 2011 are provided by 6. National Population Commission of Nigeria pro- the National Population Commission of Nigeria; jected forward based on state level growth rates. these were projected to 2015. 7. “Night Lights” refers to various datasets provided 4. Total attendance at this training was approximate- by the Earth Observation Group, NOAA National ly 40. In addition to 4 KEDCO staff who assisted Geophysical Data Center (http://ngdc.noaa.gov/ in as trainers, the training was attended by teams, eog/) which provide geo-located data for light typically of 4 staff members, from each of the fol- observed by orbiting satellites, providing a useful lowing DISCOs: Abuja, Benin, Eko, Ibadan, Ikeja, indicator of areas with nighttime human activity, Jos, Port Harcourt, and Yola. A full list of all Ni- including urbanized areas. gerian DISCOs is available at http://www.nercng. 8. http://www.nigeriaelectricityprivatisation.com/ org/index.php/myto-2/discos. 9. Technical factors limit the total length of wire that 5. The SEL/EI team has permission from INEC to low voltage power can travel and still be of usable use updated data from 2015, however this dataset quality. Although 1.0 km is widely viewed as a is only partially available: location data has been good technical standard, this is frequently exceed- obtained, but as of June, 2015, numerous efforts ed by contractors, utilities and communities who to acquire data for the number of registered voters must balance concern for the quality of power de- per polling unit in 2015 have not been successful. livered against strong pressure to connect as many 16 Input Data and Parameters customers as possible. For this report, the maxi- 13. All parameters are obtained from KEDCO, unless mum distance of 1.5 km was chosen by KEDCO otherwise noted. A few critical parameters, such management (May 2015). Although the standard as cost per meter of MV and LV line, were also value for Nigerian utilities is typically 1.0 km, in discussed with Transmission Company of Nige- practice 1.5 km was seen as a more realistic of the ria World Bank Project Management Unit (TCN way connections are performed in practice. PMU) for validation. 10. This estimate agrees roughly with figures provided 14. International spot market prices are available on- by KEDCO staff in discussions, May 2015. line (http://www.solarserver.com), to which 20% 11. This analysis models solar home systems as the was added for transport and local markup. These off-grid option which can be planned reliably and costs were checked with the Ministry of Power and generally throughout the study area with available a major local vendor M-Rald Global Resources data. However, other generation technologies can (http://m-rald.com/), and compared against recent be substituted for solar by local planners where reli- market research and procurement efforts in other able, geo-spatially specific information is available. countries where SEL/EI team has worked (Uganda, 12. Requests were made for customer billing record Tanzania, Guinea and Myanmar). in an attempt to validate this demand range at the 15. Gething, P., Molini, V. (2015, June 10) Developing local level, but these data are not available as KED- an Updated Poverty Map for Nigeria. Final Report. CO is in the early stages of establishing a customer [No web address available] database. CHAPTER 2 Cost and Technical Results The preceding steps have assigned communities age cost of ~$630/HH, $1.7 bn overall) and finally within the KEDCO service area into three broad the component D, MV grid extension, in which me- geo-spatial categories: communities that are already dium voltage lines are extended to areas beyond the connected or in range of grid electrification, com- range of existing transformers (at an average cost of munities that require either extension of the MV line ~$840/HH, $1.5 bn overall). or off-grid power for the whole community, and iso- The first three components of this program can lated households. Considering only this last catego- be accomplished without substantial additions to ry, SEL performs a least cost analysis to recommend the MV grid line. Due to the extensive coverage of an electricity system type—grid, off-grid or mini- the existing grid, these three represent nearly 70% of grid—and a recommended electricity network. (The the entire grid electrification program and address a least-cost planning approach is described in greater large portion of the KEDCO coverage area (see Fig- detail in Annex E.) The following section describes ure 11 below). the results, with details geo-spatial, cost and techni- Areas beyond 1.5 km from the exiting grid re- cal details for each of these grid and off-grid pro- quire extension of the medium voltage line. This grams and components. component (D) constitutes about 31% of the elec- trification program for 2015–2030, and is shown in Figure 12 below. Overview: Grid Extension 2.1  The following sections explore these cost and Program technical results in more detail, with particular em- As described in 1.3. Components of a Universal Electri- phasis on the manner in which geo-spatial factors fication Program, the majority of the universal electri- affect the cost buildup for household connections, fication program will, over the long term, be achieved leading to a prioritized grid roll-out program. by adding connections and extensions to the electric- ity grid. Table 8 below provides a cost overview of the Geo-Spatial Factors in Grid Extension proposed ~$3.3 billion grid extension program. The most important recommendation of the geo- Table 8 below divides the grid electrification spatial least-cost electrification plan is that over the program into four components, each with different long term grid extension is the most cost-effective costs per household connection. Since households in means of electrifying virtually all localities (>99%). component A are already connected, the main con- These results are shown quantitatively and visually cern for this component is the cost of adding meters in Table 9 and Figure 13 below. to the 63% of customers who lack them, at accost Figure 13 below shows that the model’s recom- of ~$160/household, $40 mn overall). Component mendations for non-grid systems are very rare and B refers to the effort by KEDCO to turn “consum- target areas that already have a high predicted per- ers” into “customers” by adding meters and estab- centage of “off-grid / isolated” households.1 lishing accounts for around 840,000 million homes This shows the NetworkPlanner model recom- (at an average cost of ~$180/HH, $150 mn overall). mendations for electrification of settlements with The next component, LV intensification, represents grid (blue), mini-grid (red) and off-grid / SHS connections to homes that are within 1.5 km range (green) technologies. The left panel shows an en- of a transformer with low voltage line (at an aver- larged area of Katsina state already identified for 17 18 Cost and Technical Results Table 8   Electricity access in 2015 and grid extension program for the KEDCO service area, 2015–2030 Electricity access status (2015) Grid extension program (2015–2030) Total CAPEX Type of Populationa Components of grid program Populationa,b CAPEX per HH access (Households) Percent (Type of grid access planned) (Households) Percent (M USD) (USD) Grid 7,430,000 31% A) Customers: 2,400,000 7% $40 $160 access KEDCO has ~400K customers (2015); 63% need meters ($160/HH) (400,000) (1,240,000) B) Consumers: 5,030,000 15% $150 $180 ~840K HHs (2015 est.) consume power but do not pay KEDCO; all (840,000) need meters & improved connections (~$180 per HH) No grid 16,480,000 69% C) LV Intensification: 15,680,000 47% $1,670 $625 access By 2030, ~2.7 M HHs near the grid will need LV line, meter, connection (2,670,000) (~$630 per HH) (2,750,000) D) MV grid extension: 10,560,000 31% $1,470 $835 By 2030 ~1.8 M more distant HHs (>1.5 km from transformer) will need MV (1,760,000) and LV line, connection, meter (~$840 per HH) Total 23,910,000 100% Total 33,670,000 100% $3,330 $590b (3,990,000) (5,670,000) a Based on census data, rural households have 6.1 persons on average vs. 5.8 for urban households. For simple computations and where the ratio of urban and rural households is unknown, 6 persons per household is assumed. b It is assumed that population growth from 2015–2030 among those who currently have grid access (components A and B) will lead to net formation of new households that will need new connections requiring LV intensification (component C), MV grid extension (component D) or off-grid access. c Average household costs are calculated by summing all CAPEX costs across all program components and dividing by the total number of households served. a high fraction (30%) of off-grid / isolated house- by NetworkPlanner for grid or mini-grid service in holds (shown by the dark grey polygons) and sub- specific polling sites amounts to less than 2% of the sequently targeted for non-grid electrification in ~164,000 “isolated” households previously estimat- NetworkPlanner modeling (shown by the green ed as requiring off-grid service by 2030 (see Table 3, and red points). The right panel shows the full map and Annex A2). For this reason, we recommend that of the KEDCO service area, which illustrates that the two groups be aggregated. non-grid recommendations are rare and confined A brief summary of MV grid extension costs to specific areas. The ~2,000 households targeted appears in Table 10 below, for both average sized Table 9   NetworkPlanner model recommendations for grid and off-grid (SHS) electrification in the KEDCO service area, 2015–2030 Polling sites >1.5km from transformer Household connections recommended State Population Grid Mini-grid Off-grid Total Jigawa 2,410,000 512,000 — 100 512,000 Kano 2,980,000 640,000 13 60 641,000 Katsina 2,870,000 611,000 16 1,650 613,000 Grand total 8,260,000 1,763,000 29 1,810 1,766,000 Percentage 100% >99% (99.8%) <1% (0.002%) <1% (0.10%) 100% Cost and Technical Results 19 Figure 11   Areas served by improved connections and LV intensification near the existing grid connect 69% of the projected population (2030) households and an “average settlement”. The nected homes would require about 250 W of added majority of the network expenditure for extensions, generation capacity, resulting in a need for around about 80%, would be for “local” costs such as low- 440 MW of additional generation on the network voltage line, connection costs and transformers, overall by 2030. Finally, the levelized cost of elec- while the remaining 20% would be spent on the tricity (LCOE) for the additions to the KEDCO sys- MV network. Each of the 1.8 million newly con- tem would be around 30 US cents per kWh (about Table 10   Projected electricity demand and grid extension metrics for the KEDCO service area, 2015–2030 Indicators for MV extension program Units Total Per household Per settlement Proposed MV line length km 19,070 0.011 3.4 Proposed new grid HH connections Households 1,760,000 310 Initial cost for LV grid network USD $1,163,000,000 $665 $204,000 Initial cost for MV grid network USD $308,000,000 $175 $54,000 Total Initial costs (MV + LV line and equip.) USD $1,471,000,000 $840 $259,000 Peak demand met (by grid) kW 440 0.25 80 Levelized cost per kWh for grid USD/kWh $0.30 20 Cost and Technical Results Figure 12   MV extensions can bring grid access to another 27% of the projected (2030) population that is targeted for grid (with 3–4%, mostly isolated homes, for off-grid) half of which is the US$0.16 kWh “bus-bar” cost of an algorithm assigns a ranking for each grid seg- power, while the other half is the amortized cost of ment which prioritizes lines that meet higher elec- the new extensions). tricity demand with the shortest MV line extension. Table 11 below provides a breakdown by state Figure 14 below shows MV grid roll-out results for of where the new grid-connected households, MV the KEDCO service area—component D of the in- line, and new generation are recommended. The vestment program—divided into four categories program would require nearly 20,000 km of addi- based on average costs per household connection. tional MV line, effectively tripling the length of the This per household cost metric offers a means to KEDCO MV distribution network. The largest need prioritize extensions which meet a greater electricity for additional household connections and genera- demand per unit of investment, and thus are more tion is focused on Kano State, but the majority of cost-effective. This figure illustrates how initial new MV grid line will be built in the more rural phases of grid construction is more likely to reach states of Jigawa and Katsina. communities that are closely spaced and nearer to the existing electricity grid, where less medium Prioritization of Grid Roll-Out voltage line is needed per household and hence In addition to these aggregate and State-level metrics per household connection costs are lower (~$700 for grid extension, the SEL/EI analysis also quanti- per connection). Later phases reach remote, rural fies variation in per household costs of grid exten- communities where the required MV/household is sion throughout different geographic areas to allow much higher, resulting in higher unit costs (~$1,000 for a prioritization of grid roll-out. In this analysis, per household or more). Cost and Technical Results 21 Figure 13   NetworkPlanner recommendations for electrification with grid (blue), mini-grid (red) and off-grid/SHS (green). Left: Enlarged portion of Katsina State. Right: Full KEDCO service area It is important to emphasize that this analysis technical needs (equipment, added generation, etc.). provides a plan for universal electricity access from It does not show an annual timeline for grid construc- 2015–2030, not a design for grid construction. This tion, yearly expenditures, or the specific pathways of applies to the grid-roll out plan, as well, in that it future grid extensions, locations of transformers, describes which locations should be connected, and etc. A more detailed design would require impor- the relative prioritization of connections, in a cost- tant additional factors, including: a) an investment benefit sense, and an estimate of overall costs and plan, clarifying how quickly funds could be made Table 11   Proposed household grid-connections with related MV line extension and new generation, for each state in the KEDCO service area, 2015–2030 New generation needed Number household grid Grid Length (MW) for residential connections proposed proposed (km) connections MV grid LV extension intensification MV grid LV MV/HH MV grid LV State extension intensification MV LV (avg, m) LV extension intensification Jigawa 510,000 482,400 6,600 15,200 12.9 13,200 120 120 Kano 640,000 1,523,200 5,600 18,700 8.7 34,800 170 400 Katsina 610,000 664,400 7,000 18,200 11.4 17,000 150 160 Sub-total 1,760,000 2,670,000 19,200 52,100 10.8 65,000 440 680 Grand total 4,430,000 136,300 1,120 22 Cost and Technical Results Figure 14  Prioritized grid roll-out for the KEDCO service area (2015–2030) available, and effectively used, to construct new lines at the level of the “feeder” (i.e., constructing exten- and make connections (such an investment prospec- sions to all locations along a given line at once). tus has been commissioned by the World Bank, for However, this model’s output incrementally priori- which this analysis is an input); and b) input from lo- tizes each connection along the line in a manner cal engineers to determine the paths of lines and best that might imply construction of some parts of a sequence of connections in response to local factors feeder in different phases. These kinds of investment such as available electricity supply and local geogra- and construction decisions are beyond the scope of phy topography, right-of-way, etc. (this is anticipated a high-level analysis such as this. But this dataset as part of the implementation program to follow the and analysis do provide rich data to support such investment prospectus). detailed decision-making. These maps are based on GIS data that can be From these maps, spatial patterns can be seen in viewed at higher levels of magnification. Figure 15 the prioritization of home connections: below shows the same results for an enlarged area of Jigawa State, providing a clearer illustration of zz High priority connections consist of in-filling in how specific grid extensions can be viewed for lo- urban areas or areas close to existing grid, where cal areas. a large number of new connections requiring This figure also helps to emphasize the difference less MV line result in a lower cost per household between a prioritized grid expansion plan created (~$730, on average). here, versus a true construction design. To give only zz In lower priority areas, grid extension requires one example of the sort of practical consideration higher MV and LV investment per household, that makes the two different: utilities and project and thus higher costs (reaching an average of implementers are likely to plan construction work ~$1,100). Cost and Technical Results 23 Figure 15   Prioritization of grid roll-out in an enlarged area of the Jigawa State, 2015–2030 Per Household Costs and Grid Prioritization one household to another; (ii) the costs of the LV line The basic cost elements of household grid connec- that spans between homes and MV extension that tions are of two types: (i) the costs of the service spans the distances between villages, both of which drop, meter and other costs related to the connection may vary significantly with spatial factors such to the home, which are approximately the same from as household and village density. These fixed and Table 12  Fixed and variable costs per household grid connection (KEDCO service area, 2015–2030)a Cost category Notes Low Average High Connection equipment ($175) Fixed: meter, service drop $175 Connection fee ($75) Fixed: labor, cost to create account, fees $75 Low voltage line (at $12.6 / meter) Varies: 15–30 meters per HH $189 $375 $378 (almost all un-electrified HHs are rural) Set at 15m for urban, 30 m for rural HHs Transformer (at $100 per kVA) Varies: 200–500 W per household $20 $35 $50 (varies with household demand) Average of 350 kVA / HH Medium voltage line (at $16 / meter) Varies: 1 to 40 meters (and above) $16 $176 $640b (varies with village density) Average of 11 meters per HH Total cost $475 $836 $1,318b a Based on discussions with KEDCO, April 2015. May prove less expensive due to economies of scale anticipated with large-scale procurement and implementation in a future electrification program. b More than 95% of household connections can be achieved with less than 20 meters of MV line per household, setting the higher value in this table. 24 Cost and Technical Results Figure 16   Detail of rising MV costs per household mulative average, which rises from nearly zero throughout the grid roll-out in the KEDCO meters of MV per household to nearly 11). Simi- service area, 2015–2030 larly, the blue line shows the gradually increasing average cost per household metric, beginning at $2,300 100 US$600–700 per household in the highest priority Cost per household connection (US $/HH) $2,100 90 portion of the MV extension program, and reach- MV line required per HH (meters) 80 ing US$900–1,100 or more per household in the $1,900 70 final phases. Note that both moving average curves $1,700 show a rapid and dramatic increase in the final 60 $1,500 portion of grid extension. Here, the MV per house- 50 $1,300 hold metric jumps quickly from around 20 meters 40 (or about $300 worth of MV line) per household $1,100 30 to reach 40–50 m (or about $600–800 of MV line $900 20 per household). This rapidly rising helps to illus- $700 10 trate the tendency of grid extension to become far less cost-effective in the final stages, where a single $500 0 0 0.3 0.6 0.9 1.2 1.5 1.8 household connection may cost $1,400 or more.2 This may suggest alternate electrification strate- Cumulative implementation of grid extension program (Millions of HH connected) gies for the most remote areas, such as mini-grids or solar home systems, which could provide power Cumulative average of Moving average of instead of the grid, or for a temporary period as initial cost per HH initial cost per HH these locales await grid extension. Cumulative average of Moving average of MV length (m) per HH MV length (m) per HH 2.2 Results Overview: Off-Grid Program variable components are presented as per-household cost build-up in Table 12 above, with notes on the It remains to assign costs to these components. The low, average and high values for the latter. hardware costs for solar home systems vary roughly The variation in per household initial costs has a linearly with the “service standard” (assumed annual small demand component, but is primarily related household demand, in kWh). A service standard of to geo-spatial factors, most importantly the density 150 kWh/HH-year, one-quarter of the “grid connect- of households and villages over the landscape. In ed poor” level of 600 kWh/year described above, can rural areas, households are, on average, more dis- be met by a solar home system of approximately 130 tant from each other, raising LV costs, and commu- peak watts. Assuming a range of system sizes from nities are also more distant from each other, raising 80–200 peak Watts (Wp), and an average system size MV costs. The cost build-up shows that these two of ~120 Wp, the average cost of a simple solar off- factors are the dominant variable costs in electrifi- grid system would be ~$425 per household for hard- cation by grid extension. In very rough terms, ini- ware with some additional programmatic soft costs. tial costs for grid connections tend to fall within a Note that in such systems additional the costs to range of ~US$700–1,100 per household which, for consumer are also include maintenance and replace- ~1.8 million homes, results in a total initial cost of ment costs. Such small solar home systems would ~$1.5 billion. support services up to general lighting, phone charg- Figure 16 above provides additional detail for the ing, the use of a small television and a fan3. For those medium voltage grid costs per household. communities that are clustered enough, stand-alone The rougher of the two red lines shows a mov- networks (mini-grid) solutions could provide simi- ing average MV Length Installed per Household. lar services. Such solar home systems do limit peak This metric increases from an average of 0–5 power (ranging from 100 to 200 Watts) and growth meters of MV per household connection in the in consumption is not easily admissible. A mini-grid highest priority part (from a cost effectiveness system where an “energy as a service” model is used prospective) of the grid extension program to allows consumers not risking maintenance/replace- 25–30 meters, for the lowest priority, most costly ment costs, exploit load and consumption diversity, households (the smooth red line shows the cu- higher individual power limits (possibly up to 1 kW), Cost and Technical Results 25 Table 13   Electrification status (2015) and proposed connections through both LV intensification and MV grid extension (2015–2030) for educational facilities (KEDCO service area) Connected or Connected or w/in Will need non-grid w/in 1.5 km of 1.5 km of existing power (> 1.5 km Connected to existing grid (2015) and proposed from existing & grid (2015) (2015) grid (2030) proposed grid) Education facilities Total # % # % # % # % Total (all facilities) 12,406 2,508 20% 7,946 64% 11,620 94% 786 6% Primary 10,369 1,744 17% 6,171 60% 9,599 93% 770 7% Junior & senior 1,510 548 36% 1,309 87% 1,471 97% 39 3% Vocational & technical 13 5 38% 10 77% 13 100% 0 0% Unknown type 558 211 41% 456 82% 537 96% 21 4% energy demand growth over time and easier future be covered by the grid extension program mod- integration into the grid. A basic service standard of eled to meet residential needs. Geo-located social 60 kWh/HH-year per customer (with much higher infrastructure data collected for the Nigeria MDG consumption for small business) could be provided Information System (NMIS)4 indicate that, as of in the Kano service area at a cost range of $500–700, 2015, only about 20% of institutions are connected, whereas a service of 120 kWh/HH-year could be pro- although 80% of the most important ones, such as vided at a cost of $1000–1200. hospitals, already have grid connections to the exist- ing network. For those that are not already connect- Electricity Access for 2.3  ed, 94% of all education facilities (11,620 of 12,442) (see Table 13 above) and 94% of all health facilities Social Infrastructure (3,490 of 3,693) (see Table 14 below) will fall within Considering electrification for “social infrastruc- 1.5 km of MV grid lines proposed to meet residen- ture” such as schools and clinics: While these loca- tial needs. tions are certainly a vital part of any universal access Similarly, Figures 19 and 20 illustrate that the plan, the overwhelming majority of these sites will vast majority (94%) of both types of facilities will Table 14   Electrification status (2015) and proposed connections through both LV intensification and MV grid extension (2015–2030) for health facilities (KEDCO service area) Connected or Connected or w/in Will need non-grid Connected w/in 1.5 km of 1.5 km of existing power (> 1.5 km to grid existing grid (2015) and proposed from existing & (2015) (2015) grid (2030) proposed grid) Health facilities Total # % # % # % # % Total number (all facilities) 3,699 842 23% 2,021 55% 3,490 94% 209 6% Hospital 140 96 69% 133 95% 139 99% 1 1% Dispensary 330 21 6% 116 35% 300 91% 30 9% Clinic, basic/primary health 1,428 498 35% 931 65% 1,369 96% 59 4% centre Health post 1,775 224 13% 828 47% 1,659 93% 116 7% Unknown facility type 26 3 12% 13 50% 23 88% 3 12% 26 Cost and Technical Results Figure 17   Social infrastructure (education and health) facilities with grid access (2015) Figure 18   Social Infrastructure (education and health) facilities without grid access (2015) Cost and Technical Results 27 Figure 19   Social infrastructure (education and health) facilities planned for grid connection (2015–2030) Figure 20   Social infrastructure (education and health facilities) beyond the 1.5 km range of grid (2015–2030) 28 Cost and Technical Results get grid access during the 2015–2030 grid roll-out, ($16 per meter x ~45 meters = $720) for a total of while very few will remain out of range, requiring $1,380 (rounded to $1,400). off-grid systems. 3. These services are defined by the Multi-Tier The remaining sites to be electrified by non- Framework for electricity Access developed by grid options amount to 203 health facilities and the Bank under the Sustainable Energy for All 822 schools, a total of ~1,000 facilities. These con- (SE4All) engagement. The framework defines five sist almost entirely of those institutions with the different tiers of access and the household sup- smallest electricity demands (small health posts ply described above corresponds to Tier 2. For and primary schools). Overall, electrification of more information, visit: https://www.esmap.org/ these points would add far less than 1% to the node/55526. grid extension program of more than 1.7 million 4. The Nigeria MDG Information System is an on- households. line portal providing location and attribute data for social infrastructure collected nationally in two rounds (2010 and 2014) led by the Office of the Se- Endnotes nior Special Assistant to the President on the Mil- 1. See discussions of “off-grid / isolated” households lennium Development Goals (OSSAP-MDGs) for in “Corrections and Estimates Related to Polling the purpose of ensuring “informed decision mak- Place Data” within Chapter 1.2. ing and implementation in local, state and fed- 2. This is a rough figure, obtained by adding the non- eral interventions aimed at achieving the MDGs.” MV costs (about $660 per household, see Table (nmis.mdgs.gov.ng). 12 with the costs of MV line in very sparse areas CHAPTER 3 Conclusions and Next Steps Given the data available for this analysis, the extent ral households fall into this category, with the high- of the existing grid network, and the predicted de- est percentage applying to the most rural, sparsely mand levels for households, results have shown that populated areas. This off-grid analysis relied funda- grid extension is ultimately the most cost-effective mentally upon estimates derived from visual inspec- solution for the 15 year electrification program tion of high resolution satellite imagery, as there is modeled for the KEDCO service area. At an esti- currently no comprehensive rural settlement dataset mated cost ranging between $700 and $1,100 per for KEDCO’s service area. The total cost of such a household, the grid can be extended to reach the program will vary linearly with the assumed service vast majority of those currently without service, in standard, in kWh of electricity delivered per year, the process adding ~20,000 km of MV line, roughly for each household system. Assuming a standard of tripling the length of the current KEDCO MV net- ~150 kWh per year, it is likely that this program will work once the MV Correction Factor is incorpo- cost ~$400–450 per household, or a total of between rated into grid extension plans. These conclusions $55 and 60 million. As yet, there is also currently comes with some important caveats. There may be no clear consensus on the specifics of an off-grid small remote population clusters that are not cap- electrification plan for this region—whether this tured in the demographic data, medium-voltage will be led by the public or private sector, at what grid costs per household values inevitably require a costs, etc.—so this analysis provided information significant degree of estimation, and finally the low- on system sizing, cost and an overall estimate of the voltage wire needs and energy demand estimates magnitude of the need which might help inform a may end up being spatially and temporally different discussion of such a program among policymakers from those assumed. and other stakeholders. A separate analysis has addressed the problem The results presented here for the NEAP-TA are of estimating how to meet the needs of the small based on the best available data at this time. Ad- remaining fraction of the population who will not ditional data—perhaps updated polling place data cost-effectively be served by grid in the short term. for 2015 (provided by INEC), improved data from It was concluded that about 3–4% of projected un- KEDCO itself regarding existing “customers” vs. electrified population, or about 140,000 households, “consumers”, or improved census data with greater may be best served by off-grid technologies, solar accuracy or spatial specificity for populated places— home systems in particular. Depending upon the could all help to form an increasingly comprehen- household density of a polling unit coverage area, it sive and accurate foundation of data from which to is estimated that between about 5% and 30% of ru- revise this analysis in the future. 29 30 Conclusions and Next Steps Annex A – Pre-processing of below) around each polling unit (yellow point) to represent areas from which a polling site is as- Electricity Demand Point Data sumed to draw its voters. A1.  Derivation of Population Based on For each polling unit area polygon, SEL/EI cal- Registered Voters at Polling Units culated the density (voters or population per square Nigeria’s 2006 Population and Housing Census re- kilometer). In addition, SEL/EI visually identified ports a total national population of 140 million, all human dwellings (blue points), calculated each with 73 million adults (over 18), of which 62 million point’s nearest neighbor, and categorized any point (85%), are registered to vote. This yields a nation- more than 100 meters away from any neighbor as al ratio of voters to total population of about 2.25 “isolated” (distances > 100m are red lines). The suggesting that simply multiplying the number of number of isolated dwellings in a polling unit area, voters at any polling site by this multiple provides compared with the total number of dwellings, gives a reasonable estimate of the total population resid- a percent of isolated homes for the area. In Fig- ing near that site. While this very simple conversion ure 21 above, 6 isolated dwellings, compared with offers a useful basis for a preliminary estimate, the 90–100 dwellings in the entire area, yields a ratio SEL/EI team chose a more geo-spatially specific ap- of about 6–7%. The population in this polling unit proach: census values at the LGA (Local Govern- is relatively closely aggregated; in many rural poll- ment Area) level were projected from 2006 to 2011, ing units, 30% or more of the households appear then proportionally allocated among polling units to be “isolated” (greater than 100 meters from any within an LGA according to the percent of an LGA’s neighbor). total registered voters represented by each polling SEL/EI then repeated this process of visually unit. There were also data gaps in the original INEC identifying human dwellings in satellite imagery data—some polling site records had location infor- throughout a sample of about 95 polling units mation, but no data for number of registered voters. (from a total of 16, 300) chosen randomly from In those cases, information from ‘night lights” sat- three different rural areas in Kano State (see Figure ellite imagery was used to identify urban and rural 22 below). For each “polling unit area” within the areas and polling units, then the average value of sample, two metrics were calculated: a) the ratio of registered voters for polling units in urban or rural isolated compounds and b) the polling unit’s house- areas in each state was assigned to each polling unit hold density. that lacked a registered voter value. SEL/EI created plots of the percent of isolat- ed dwellings (>100m from any neighbor) versus Estimating the Frequency of “Isolated”/ A2.  household density of each polling unit (see Figure Off-grid Households 23 below). These curves allow a rough estimate One important caveat regarding use of the INEC of the percent of isolated (more cost-effectively polling unit dataset to represent human settlements served by non-grid technologies) dwellings based is that rural villages, particularly the smallest ones, on a polling unit’s household density. In this way, are often not served by a polling unit located with- the quantitative insight gained from the visually in- in the village. Instead, their voters are likely to be spected polling unit areas could then be applied to registered at polling units either in nearby villages or other central locations, such as a school that is shared by multiple settlements. This is understand- Table 15   Estimated percentage of able given the cost and logistics of providing poll- isolated dwellings in polling ing places to the smallest and most rural commu- unit areas based on household nities. However, this concentration of voters for density multiple villages at a single polling site results in Clustered PU density Isolated HH an apparent aggregation of rural populations that bins (HH no/sq. km) ratio risks introducing inaccuracy in geo-spatial plan- ning. To address this inaccuracy, the SEL/EI team 0–10 30% performed a detailed manual analysis of satellite 10–50 10% imagery, combined with measurements to identify 50–70 5% “isolated” households. This work began by using > = 70 0% GIS to create polygons (yellow lines in Figure 21 Conclusions and Next Steps 31 Figure 21   Dwellings (blue) identified in satellite imagery; red lines indicate inter- household distances greater than 100 meters (yellow points represent polling places; yellow polygons illustrate estimated “coverage areas” for polling places) polling unit areas elsewhere throughout the rest of A3. Estimating the “Medium Voltage the KEDCO service area, using household density Correction Factor” as the key metric. As stated in the report’s main body, use of INEC This allowed an estimate of the percentage of polling place data introduces inaccuracy in the MV each polling unit’s population that is “isolated” and line length arising from the fact that not all human thus appropriate for off-grid / solar home system settlements include polling units. The fact that many electrification throughout the KEDCO service area. substantial villages lack a polling site can cause the This percentage of the population was removed from model results to under-estimate the required length the grid extension analysis, and set aside for off-grid of MV line to connect all locations in the dataset electrification. The final estimate is that 2–3% of to- that are grid recommended. To remedy this, SEL/ tal households in the KEDCO area, corresponding EI utilized the same visually identified dwelling to 5–6% percent of currently non-electrified loca- dataset described previously (see A2 Estimating tions, will be most cost-effectively served by solar the Frequency of “Isolated”/Off-grid Households). A home systems. clustering algorithm was used to identify clusters of 32 Conclusions and Next Steps Figure 22   Rural area of Kano state where visual identification of dwellings (blue points) in satellite imagery was repeated for many polling unit areas (yellow polygons) homes that were not represented in the polling unit tained from satellite imagery then algorithmi- data, and quantifying the additional length of MV cally clustered, and the other using polling unit line needed to reach them. points—are presented in Figure 24 below. The effort included three broad stages: 2. The results form two curves, both showing the estimated length of MV line needed to connect 1. This clustered dataset was run in NetworkPlan- households in each polling unit (y-axis) com- ner under the same assumptions as the original pared with the household density for each polling dataset, which included only polling sites as unit (x-axis). The higher curve (in blue) shows an populated places. As with the “isolated house- estimate of the MV line length needed to con- hold” analysis described previously in Annex nect all households that were visually identified A2, this MV “correction factor” analysis was in satellite imagery and algorithmically clustered carried out for many polling unit polygons. to form proxy villages. The lower curve (in red) The results of the two NetworkPlanner model shows an estimate of the MV line needed to con- scenarios—one using household points ob- nect households using the much more limited Conclusions and Next Steps 33 INEC polling place dataset. Both curves trend Figure 23   The correlation between household density downward from left to right, indicating that less and percent of isolated dwellings identified medium voltage line is needed per household as using satellite imagery in ~90 polling units the density of a polling area increases. The verti- belonging to the KEDCO service area cal difference between the two curves is, very approximately, a factor of two, meaning that 60% identification of households and villages by % of dwellings > 100 m from nearlest neighbor 50% satellite imagery leads to a greater estimated number of electrification sites spread over a 40% Low density PUs Medium density PUs High density PUs (polling unit areas) greater area, meaning that roughly twice as ~25–30% isolated ~10% isolated dwellings 0–5% of dwellings are isolated much MV is required to complete electrifica- 30% dwellings tion than is suggested by the INEC polling sites 20% alone. y = –0.086ln(x) + 0.3762 3. The cost implications of this correction factor 10% R2 = 0.3063 are significant, but do not dramatically affect the total cost of the grid extension program overall. 0 0 10 20 30 40 50 60 70 80 90 100 MV extension without the 2 X “MV correction factor” are about $740 per household, or $260 Household density (HH no./km2) million total; while costs for MV extension with the 2X “MV correction factor”, which are about $840 per household, or $300 million total. The application of this correction factor adds only 10–20% to the total cost for MV extension. This can be explained both by the relatively low cost of MV per km quoted by KEDCO (around HH HH US$16,000), the somewhat high initial con- HH nection costs (~US$650 per household); and HH HH HH HH 1. Household dwelling HH the relatively extensive grid penetration, which points were identi- fied in satellite imag- leads to relatively short needed MV extensions HH ery for areas where per household (5–11 meters per household on HH HH polling units do not HH fully represent all average, depending upon whether one includes HH villages. HH the doubling factor). HH 1,000 meters HH A4.  Estimating Grid Penetration The SEL/EI analysis used the following process for HH estimating grid penetration for the 2011 dataset: HH HH 2. These dwelling HH HH points were algo- HH HH zz KEDCO mapped key grid assets, including all HH rithmically clustered into groups of distribution transformers—those which step HH households within down power from MV (11/33 kV) to LV (415 V) HH HH 500 meters of each HH other—creating a (see Figure 2). HH proxy for villages HH zz INEC 2011 Polling Unit data was used to create HH (colored circles). HH 1,000 meters geo-located estimates of population (see Figure 4 and Annex A1 Derivation of Population based on Registered Voters at Polling Units). HH HH zz GIS buffering (a standard proximity analysis HH 3. The NetworkPlanner which creates a circular zone around a point HH HH model was run, with HH HH HH each group acting a feature based on the radius) identified all poll- node for a grid con- ing units within 1.5 km of existing transformers. HH nection, yielding These Polling Unit locations were also designat- HH HH new MV extensions HH not previously mea- ed as urban or rural based on “night lights” data HH HH sured (blue lines). (see Figure 6). Using a 1.5 km radius, this a total HH HH 1,000 meters of about 13 million people, or ~55–60% of the 34 Conclusions and Next Steps Figure 24    Two trend-lines show the relationship precursor to KEDCO): 80% of households in ur- between MV per household recommended ban areas report a grid connection, while 53% of by NetworkPlanner and polling unit density survey respondents in rural areas report a grid for two datasets: clustered household connection. zz SEL/EI applied these grid access rates—urban locations identified from satellite imagery (80%) and rural (53%)—to INEC Polling Units and locations of polling sites. Comparison of according to the urban / rural classification these trendlines yields a rough estimate of the based on “night lights” data. The result is ~38% difference to be approximately a factor of 2 of the population has grid access (either as cus- 20 tomers or consumers), which compares favour- ably with the LSMS figure that around 33% of the Meters of medium voltage line 18 per household (MV/HH) 16 population overall has grid access in the KEDCO 14 service area. 12 zz The difference between the population that is 10 “within range of a transformer” and the popula- 8 tion that already has grid access is about 22% of Roughly a factor the total population. This is the population iden- 6 of 2X between 4 two trendlines tified for “intensification” (requiring only low 2 voltage line and connection costs, i.e. component 0 D in Table 4). 0 10 20 30 40 50 zz These already connected households (customers Household density (#HH/sy km) or consumers) and those amenable to “intensifi- cation” (LV only) were separated from the total Clustered households Polling units population of the KEDCO service area, leaving Expon. Expon. the remainder (~40%) as the population to be (clustered households) (polling units) electrified either by grid extension (MV + LV) or off-grid / solar home systems (see Annex A2 Estimating the Frequency of “Isolated”/Off-grid total area population was identified as “within LV Households). These are represented in compo- range of a transformer”. These 13 million people nents D and E in Table 4. represent the first three components, A-C, in zz All figures were projected forward to 2030 with- Table 4. in the NetworkPlanner scenarios that employed zz LSMS household survey data (2011) provides state level urban and rural growth rates for each percentages of households connected to PHCN point. They were also interpolated for 2015, as service (Power Holding Company of Nigeria, the needed. Conclusions and Next Steps 35 Annex B – Model Parameters B1 List of model parameters Parameter category Parameter Value used for model demand (household) household unit demand per household per year Assigned to each location based on Oxford / WB poverty mapping (see Annex B2) demand (household) target household penetration rate 14 demand (peak) peak demand as fraction of nodal demand occurring 0.44 during peak hours (rural) demand (peak) peak demand as fraction of nodal demand occurring 0.44 during peak hours (urban) demand (peak) peak electrical hours of operation per year 14604 demographics mean household size (rural) 6.13 demographics mean household size (urban) 5.83 demographics mean inter-household distance Assigned to each location: 15 m in urban areas, 30 m in rural areas1 demographics population count Assigned to each location using polling unit and census data (see Annex A1) demographics population growth rate per year (rural) 0.00798 3 (census value recomputed to reconcile 20 year electrification time horizon with 30 year time horizon for scenario) demographics population growth rate per year (urban) 0.02847 3 (census value recomputed to reconcile 20 year population growth time horizon with 30 year time horizon for accounting amortization and recurring costs) demographics urban population threshold urban and rural areas were identified by nightlights data, not population threshold distribution low voltage line cost per meter 12.61 distribution low voltage line equipment cost per connection 1751 distribution low voltage line equipment operations and maintenance 0.011 cost as fraction of equipment cost distribution low voltage line lifetime 301 distribution low voltage line operations and maintenance cost per year 0.011 as fraction of line cost Finance interest rate per year 0.074 Finance time horizon 305 system (grid) available system capacities (transformer) 25.0 kVA (minimum)1 system (grid) distribution loss 0.151 system (grid) electricity cost per kilowatt-hour 0.161 system (grid) installation cost per connection 751 system (grid) medium voltage line cost per meter This was doubled to mimic the 2X MV Correction Factor (see Annex A3) system (grid) medium voltage line lifetime 301 system (grid) medium voltage line operations and maintenance cost 0.011 per year as fraction of line cost 36 Conclusions and Next Steps Annex ( B) continued – Model Parameters B1 List of model parameters Parameter category Parameter Value used for model system (grid) transformer cost per grid system kilowatt 1001 system (grid) transformer lifetime 101 system (grid) transformer operations and maintenance cost per year as 0.031 fraction of transformer cost system (mini-grid) available system capacities (diesel generator) 6.0 kVA (minimum) 4 system (mini-grid) diesel fuel cost per liter 0.871 system (mini-grid) diesel fuel liters consumed per kilowatt-hour 0.54 system (mini-grid) diesel generator cost per diesel system kilowatt 1501 system (mini-grid) diesel generator hours of operation per year (minimum) 14604 system (mini-grid) diesel generator installation cost as fraction of generator 0.254 cost system (mini-grid) diesel generator lifetime 54 system (mini-grid) diesel generator operations and maintenance cost per 0.011 year as fraction of generator cost system (mini-grid) distribution loss 0.14 system (off-grid) available system capacities (diesel generator) 6.0 kVA (minimum)4 system (off-grid) available system capacities (photovoltaic panel) 0.05 kWp (minimum) 4 system (off-grid) diesel generator hours of operation per year (minimum) 14604 system (off-grid) peak sun hours per year 1320 system (off-grid) photovoltaic balance cost as fraction of panel cost 0.54 system (off-grid) photovoltaic balance lifetime 104 system (off-grid) photovoltaic battery cost per kilowatt-hour 1502 system (off-grid) photovoltaic battery kilowatt-hours per photovoltaic 64 component kilowatt system (off-grid) photovoltaic battery lifetime 34 system (off-grid) photovoltaic component efficiency loss 0.14 system (off-grid) photovoltaic component operations and maintenance 0.054 cost per year as fraction of component cost system (off-grid) photovoltaic panel cost per photovoltaic component 8002 kilowatt system (off-grid) photovoltaic panel lifetime 204 Minimum node count per sub-network 204 Sources: 1 KEDCO. 2 Market Research & Int’l Comparison. 3 Nigerian Population Census. 4 default value (based on international experience). Others are noted explicitly. 5 Modeling used the base values provided by NBS/CBN/NCC Social-Economic Survey on Nigeria, 2010, modified to fit two timelines: a timeline of ~20 years to project population from 2011 to 2030, and a timeline of 30 years since as a widely accepted duration for amortization of loans and computing recurring costs for major infrastructure investments (such as grid lines, generation equipment, etc.). Note: parameters that were not used (null values entered) in this modeling work were removed from this list). Conclusions and Next Steps 37 Figure 25   Predicted map of poverty headcount rates in Nigeria in 2012/13. The continuous surface is the posterior mean prediction at 5x5 km resolution B2.  Poverty Mapping and Household then implemented using geospatial covariate layers Demand Estimates that are correlated with the poverty headcount rate, The Oxford Poverty Study1 was based on Gen- and that partially explain variation in order to gen- eral Household Survey panel survey (GHS-Panel), erate approximations of the distributions of the pov- part of the Living Standards Measurement Surveys erty headcounts at each location on a regular 5×5 (LSMS) Integrated Surveys on Agriculture project km spatial grid across Nigeria. conducted jointly by the World Bank and Nigerian The covariates that were chosen by the Oxford National Bureau of Statistics. Enumeration Areas team were based on factors that have previously (EA) were first classified as either poor or non-poor been shown to correlate with poverty and included according to the $2/day equivalent poverty lines, in the model for testing as possible explanatory co- with all individuals within each household assigned variates. These are as follows: the same classification. EA-level headcount rates were then derived as the proportion of individuals zz Travel Times: a gridded surface estimating ac- within each EA classified as poor. A geo-statistical cessibility, measured in likely travel times (via all modeling combined with Bayesian inference was transport methods), to cities with greater than 38 Conclusions and Next Steps Figure 26   Polling unit locations in the KEDCO service area shown with poverty values extracted from the raster pixels 50,000 inhabitants. This provides a useful com- zz Climatic/Environmental conditions: NASA’s posite measure of the extent to which regions are Moderate Resolution Imaging Spectroradiom- rural versus urban as well as the degree of their eter (MODIS) generates high-resolution satellite connectedness to the national system of trans- imagery on three key measures on environmen- portation. tal conditions: land surface temperature (LST), zz Population Density: gridded data on popula- the enhanced vegetation index (EVI) and middle tion density across Nigeria constructed from infrared reflectance (MIR). satellite-derived settlement maps and available census data. SEL/EI team then worked with the predicted zz Aridity and Potential Evapotranspiration pixel-level map of the poverty headcount rate for (PET): these grids allow differentiation of areas Nigeria (see Figure 25 above) at 5x5 km which was with adequate rainfall and moisture regimes to used to derive the poverty rate for each polling unit. sustain agriculture versus those where drier and A raster-based GIS analysis extracted values of each more arid conditions prevail. pixel which geographically coincides with the loca- zz Nightlights: these surfaces allow differentiation tion of the polling units. The results of this analysis of regions based on both the density of popula- are shown in Figure 26 above. When applied to en- tion and the degree of electrification of dwell- tire polling unit areas, the result is the map shown in ings, commercial and industrial premises, and Figure 10, of this report. infrastructure. SEL/EI also calculated the daily electricity ex- zz Elevation: a Digital elevation model (DEM) dif- penditure based on a detailed examination of the ferentiating high from low altitude regions. LSMS survey results for the three states served by Conclusions and Next Steps 39 KEDCO. Energy expenditures related to services 2. Assume the pre-electrified population is non- such as lighting, mobile phone, media (TV, radio, poor and isolated population is poor. Define In- etc.)—but excluding cooking—were aggregated for put poor population: poor vs. non-poor respondents. The ratio of the ex- penditures for poor and non-poor categories were a. If Poor pop – isolated pop ≥ Total input pop, compared and estimated to be at a factor of 2. This which means all the input population are ratio was then used to estimate electricity demand poor, so range in the NetworkPlanner modeling for the Input poor pop = Total input pop. KEDCO area: poor household demand was estimat- b. If 0 < Poor pop – isolated pop < Total input ed to be 600kWh/year and non-poor to be twice as pop, which means part of the total input pop much which is 1200 kWh/year. Electricity demand is poor, so was estimated for each polling unit based on pov- erty rate as computed above by calculating number Input poor pop = Total input pop – isolated pop. of households—poor vs. non-poor—in each poll- c. If Poor pop – isolated pop ≤ 0, which means all ing unit, then computing a weighted household the input pop is non poor, so demand. A polling unit composed of 100% poor Input poor pop = 0 households would have an average demand of 600 3. Define Input non-poor population: kWh/year (the lowest extreme), while a polling unit Input non poor pop = Total input pop – composed of 100% non-poor households would Input poor pop have a demand of 1,200 kWh/year. However, as shown by the preceding figures, each area has a mix 4. Assume poor household uses 600 kWh electric- of poor and non-poor households. Thus, each poll- ity per year, non-poor household uses 1200 kWh ing unit falls somewhere within this range, and the per year and household size is 6. Define annual average household demand, across the entire data- household electricity demand in each polling unit: set, is estimated to be about 840–850 kWh per year. Input poor household = Input poor pop/6 The demand computation in detail: Input non poor household = Input non poor pop/6 1. Apply poverty rate (from Oxford study) to calcu- Annual household electricity demand late the poor population and non-poor population Input non poor household x 1200 + in each polling unit: Input poor household x 600 = Poor pop = Total pop × Poverty Rate Input non poor household + Non poor pop = Total pop × (1 − Poverty Rate) Input poor household 40 Conclusions and Next Steps Annex C – Sensitivity Test – For base demand scenario, the household elec- tricity demand per year per household is in a range Variation in Household of 600–1200 kWh, depending on the poverty rate, Demand with an average of about 840–850 kWh/year. While Household demand is typically the most critical the model results show shifts in the recommenda- metric (whether as an assumption or modeling pa- tion of grid, mini-grid or off-grid / solar home sys- rameter) on the final outcome of modeling and elec- tem electrification technologies as demand changes, trification planning. This is because it fundamentally these changes even at their maximum, amount to impacts the relative cost-effectiveness of various an extremely small percentage of the electrification technologies with very different balances of initial program overall. The largest variation, an increase and recurring costs. One of the most important fac- in recommended off-grid household systems from tors that electricity demand impacts is the recom- ~2,000 to ~12,000 due to 50% cut in household mended proportion of grid and non-grid electrifica- demand from the base value, yields less than 1% tion technologies. Grid electrification typically has change in the overall mix of technologies. Thus, as relatively high initial costs (for wire, transformers, a source of uncertainty in the overall results, house- connections) but lower recurring costs (since the hold demand has a far smaller impact than other “bus-bar” cost of power tends to be as low as pos- important, and currently irresolvable, sources of sible). In contrast, solar photovoltaic systems tend to uncertainty. The latter include the uncertainty in have lower initial costs since but has relatively high population values (at least 10%, as a conservative recurring costs (due to the need to continually re- estimate, though no data source exists for valida- invest in battery storage). Mini-grids typically offer tion) and MV line lengths (approximately a factor an intermediate option to meet demands that are of 2, see Annex A3) caused by the necessarily re- too high to be met cost-effectively served with solar liance on INEC polling unit points as a proxy for home systems, but not large enough to justify con- populated place data from a source such as a de- nection to the full grid. Changes between the pro- tailed, village level census (which is not available portion of grid and non-grid systems, in turn, impact for Nigeria). Moreover, these changes are also quite another key metric for electricity system planning: small compared with the 140,000 off-grid systems the medium voltage line required per households recommended following the identification of isolat- Because the type of system recommended by ed homes by satellite imagery. The changes in mini- the model is most sensitive to variation in house- grid recommendations are even smaller, given that hold demand, SEL/EI has included a brief analysis the total number of systems is recommended for a of this sensitivity. Table 16 below shows how chang- maximum of 174 households, representing less than ing household demand influences electricity system 0.01% of the overall electrification program. Con- recommendations and MV/HH for the third com- sidered in the comparison to the electrification pro- ponent of the electrification plan for the KEDCO gram as a whole, these variations are insignificant in service area, involving households beyond 1.5 km a practical sense, since they are all well within the from existing transformers. margin of error of an analysis such as this one. Table 16   Variation in recommended electricity type and MV/HH with changing household electricity demand Household electricity demand Households recommended for each kWh per HH per year Percent of “base” electrification technology MV length/ (average, all households) demand Grid Mini-grid Off-grid HH (m)a 853 100% (Base) 1,763,385 29 1,809 10.96 426 50% 1,752,625 — 12,598 10.76 640 75% 1,762,051 — 3,172 10.90 1706 200% 1,765,049 174 — 11.10 2,559 300% 1,765,183 40 — 11.12 a These results have been adjusted to reflect the 2X “MV Correction Factor”. Conclusions and Next Steps 41 These results—obtained by large variation of electrification of more remote and isolated house- the most critical parameter in the modeling sys- holds within the KEDCO service area, the INEC tem—show that the overall recommendation of data used for this requires additional processing grid as the dominant system type are quite robust and assumption, along the lines of the procedure on a cost and geo-spatial basis. While off-grid explained in Annex A2, to yield quantitatively sig- systems may have a significant role to play in the nificant guidance. 42 Conclusions and Next Steps Annex D – Least-Cost as well as the fixed and recurring costs for electric- ity supply, for all points. Cost calculations are then Electrification Modeling made, incorporating all initial and recurring costs A key tool used in this planning approach is Net- over the long-term (30 years3) for all system types workPlanner, the Sustainable Engineering Lab’s (grid, mini-grid, off-grid). The total costs (initial (SEL) web-based geospatial electricity cost model- and recurring) for each point become the basis for ing and planning software.2 The tool allows users to the algorithmic identification of communities rec- explore cost tradeoffs of different electricity tech- ommended for grid connectivity, as well as those lo- nologies and create quantitatively rigorous costs and cations for which mini-grid or off-grid (solar home technical estimates for electricity planning. Applica- system) is the least-cost option. Communities rec- tion of the NetworkPlanner tool and approach typi- ommended for the grid are identified and the cor- cally includes three broad stages of work. responding electricity network is mapped in Figure 27 (right panel). Finally, a cost-benefit analysis of all Step 1: Data Gathering and Preparation grid network segments considers the energy deliv- The electricity planning effort begins with gather- ered (in kWh) compared to the total costs, and pri- ing and preparation of relevant geospatial, cost, oritizes segments that deliver more energy for lower demographic and economic data in collaboration investment. The result is a least-cost electricity plan. with government, utilities, and other key practitio- Locations where the grid is not recommended are ners and stakeholders. This includes geo-referenced instead assigned the least-cost non-grid alterna- population figures, data representing both the tive which may be mini-grid (solar, diesel, hybrid, planned and existing electricity grid, and detailed etc.) or off-grid (typically solar photovoltaic home costs of electricity inputs and equipment. These systems). For this analysis, these (very few) off-grid data serve as the basis for computation of the fixed recommendations made by the NetworkPlanner and ongoing costs for the grid and off-grid systems. software have been added to the (much larger) com- NetworkPlanner also draws upon other data types ponent of isolated households and “transitional” off- which may or may not have a spatial dimension but grid connections. are essential for forecasting, the most important being electricity access rates, population growth Key Metric: Meters of Medium-Voltage Line rates, geographic information on urban versus rural per Household (MV/HH) areas, poverty and wealth data, and electricity de- Many costs related to electric power infrastructure mand values, particularly for the residential sector, are either the same for all households (e.g. the cost which is typically the most important for questions for an electric meter) or vary with electricity de- of electricity access in under-served areas. The spe- mand (the costs for transformers, solar panels, or a cific data gathering steps taken for this analysis are diesel engine). A key insight from and justification described previously in Chapter 1 – Input Data and for geo-spatial electrification planning is that a few Parameters important costs related to electric grid infrastruc- ture have a spatial dimension. The most important Step 2: Least-cost Electricity Grid and Off- of these is the length of medium-voltage grid line grid Planning required to connect communities, which creates Drawing upon the information obtained in the first a substantial cost differential between costs per step, the model then applies a range of user-defined households in dense / urban versus sparse / rural parameters to project population, demand growth, areas. The key metric this analysis employs to reflect and costs for power equipment independently for this geo-spatial factor is meters of medium voltage every point in the proposed system. It then per- line installed per household connection, or MV/ forms a least-cost comparison of on-grid, mini-grid, HH for short. MV/HH is a valuable metric, first, and off-grid electricity systems for each settlement. for understanding the cost-benefit trade-offs re- The NetworkPlanner model first projects the ex- lated to grid extension versus off-grid alternatives, pected population and electricity demand for each and, second, for prioritizing grid extensions in a settlement, as shown by the Uganda example (Fig- least-cost manner. In general, the medium-voltage ure 27, left panel). line per household (MV/HH) is low in urban and This is followed by a computation of technical peri-urban areas, reducing grid extension costs on a system requirements to meet these electricity needs, per household basis, and higher in remote and rural Conclusions and Next Steps 43 Figure 27   NetworkPlanner map with magnitude of electricity demand for each point shown by circle size (left), 2030; and algorithmically specified least-cost electricity grid network (right) (example is from a rural area in southwestern Uganda) areas. When the metric MV/HH is used to select to concentrate connections and prioritize sequential which communities should be reached by grid, and extension within denser areas, which are lower cost, then to algorithmically determine the most cost-ef- and continue onto more remote, less dense, higher fective pattern of connections, the result is typically cost areas. Figure 28  Model summaries (data and maps) presented through a web browser format 44 Conclusions and Next Steps Step 3: Data-rich Outputs the NetworkPlanner model considers the entire NetworkPlanner provides data-rich reporting of set of populated places, however far from the grid, results that can be the basis for detailed charts and simultaneously and over a longer time horizon. maps. First, summary data and maps are presented The difference in the two approaches is captured immediately in the web-browser, allowing users to in Figure 29 below. make rapid, high level assessments of outputs to The typical “sequential” approach looks for con- guide decisions about revisions to subsequent mod- nections within a limited radius (usually 10–25 el runs (Figure 28 above). For more detailed results, km) of existing MV lines. Longer extensions to technical and cost data are provided in tabular for- major towns and cities are typically considered on mat (comma separated variable) while map infor- an ad hoc basis, perhaps weighing political consid- mation is provided as shapefile outputs. These for- erations and, most importantly, annual budgetary mats can be processed and revised locally according constraints. This limits the number of cost-effective to specific project objectives. opportunities, thus leaving large areas without grid access (see Figure 29, left panel). Non-grid options, Benefits of the NetworkPlanner Approach such as mini-grids or solar home systems, tend to At a fundamental level, the analysis performed be considered in an ad hoc fashion as well. This ap- by NetworkPlanner is familiar to electrification proach is necessarily limited in scope, and neither planners and utility engineers: the software evalu- grid or non-grid options are likely to be considered ates a combination of factors, including electricity from a quantitatively rigorous, cost-benefit perspec- demand, cost and distance from existing grid, to tive, across the entirety of the un-electrified popula- determine where grid extension is affordable. The tion. This tends result in slow progress toward uni- key difference for a planner using the software is versal electrification. the size of the datasets that can be considered, and In contrast, the algorithmic approach taken by the speed and scope of the analysis. Due a com- NetworkPlanner considers the dataset as a whole, bination of factors—including a lack of detailed allowing villages to be connected to neighbors ac- geospatial data, or difficulty in evaluating large cording to the most cost-effective pattern of con- datasets as a whole—most grid extension plans nections over longer temporal and spatial scale. In consider only incremental or “sequential” grid effect the algorithm can evaluate not only where the extension to connect locations near the existing grid is currently, but where it will expand in com- grid, in a manner that cost-effective in the near ing years. As a result, grid extensions typically reach term based on current infrastructure. In contrast, further into un-electrified areas to connect larger Figure 29  Sequential versus algorithmic approaches to grid extension planning Conclusions and Next Steps 45 villages that are cost-effective to serve, but distant Endnotes from the current grid (see Figure 29, right panel). Meanwhile, areas that are not cost-effective for grid 1. Gething, P., Molini, V. (2015, June 10) Developing over the long term can be identified throughout the an Updated Poverty Map for Nigeria. Final Report. entire dataset, allowing planning for non-grid sys- [No web address available] tems comprehensively, on a large scale. 2. The system website (networkplanner.modilabs. The speed of the algorithm analysis also permits org) offers details on the system, including sample multiple model runs to be compared to determine datasets useful for training. sensitivity of the results to changes in different cost 3. Thirty years is chosen as the duration for amortiz- inputs, assumptions, and other factors. (Results of ing investments (2015–2045), not the duration of this approach are described in Annex C – Sensitivity the electrification program, which is approximate- Test – Variation in Household Demand). ly 15 years (2015–2030). PART 2 INVESTMENT PROSPECTUS FOR THE ELECTRIFICATION OF THE KEDCO SERVICE AREA (2015–2030) Advisory Service Document Consultant Summary Report Contents 52 Abbreviations and Definitions 53 Executive Summary 53 ES1 Introduction 54 ES2  Least-cost geospatial electrification rollout programme 56 ES3  Programme implementation – Readiness 56 ES4  Mobilizing physical programme implementation 57 ES5  Financing the universal access rollout programme 58 ES6  Phasing strategy for road-map implementation (2016–2023) 60 ES7  Grid rollout implementation (2018–2023) – Two scenarios 61 ES8  Investment financing prospectus – Grid rollout (2018–2023) 63 ES9  Investment financing gap (2018–2023) 64 ES10  Financing mechanisms and on-lending terms for public funds support 64 ES11  Technical assistance 65 ES12  Off-grid programme 69 Chapter 1: Background to the Kano Service Zone and KEDCO 70 Geospatial least-cost plan for universal electrification 1.1  77 Chapter 2: Indicative Electrification Programme 79 2.1 Conservative grid electrification scenario 80 2.2 Best-practice electrification programme 82 2.3 Capacity strengthening 85 Chapter 3: The Role of the Policy Maker and Regulator 85 A national policy for universal access 3.1  89 Chapter 4: Financing and Implementation of the Access Program 91 Capital costs of the electrification programme (2018–2023) 4.1  93 Investment needs in generation and transmission 4.2  97 Chapter 5: Current Tariff Regime and the Electrification Program 98 Equity concerns and strategic rollout of the electrification programme 5.1  101 Chapter 6: Off-grid Electrification 103 The current regulatory framework for isolated grids 6.1  103 DISCO-led off-grid electrification and targeted support 6.2  104 Non-DISCO-led off-grid electrification 6.3  104 The future role of REA and REBs 6.4  107 Annexes 49 50 Contents 107 Summary of KEDCO Rapid Readiness Assessment 1  113 2 Customer Income, Expenditure and Affordability 113 2.1  Income and expenditure distribution 114 2.2  Geographical distribution 116 3 Estimation of Cross-subsidy to R1 Customers 116 3.1  The tariff regulatory framework 116 3.2 Tariff design limited to the current R1 and R2 categories 116 3.3 KEDCO’s proposed R2-lite and R2-classic categories 118 4 Transitional Electrification Options 118 4.1 Choices 118 4.2  Electrification to target poverty 118 4.3  Off-grid electrification strategies 121 Independent Electricity Distribution Networks 5  122 6 Examples of International Experience 122 6.1 Brazil 123 6.2 Chile 124 6.3 India 125 Off-grid developments: Bangladesh and Ethiopia 6.4  Figures 73 Figure 1 Map showing existing grid lines and LV intensification connecting 69% of the projected population (left) and the prioritized grid expansion plan based on average cost per household (right), 2015–2030 74 Figure 2 Map showing social infrastructure (schools and clinics) planned for grid connection (2015-2030) (left) and beyond reach of existing and projected grid (2030) (right) 79 Figure 3 Conservative grid electrification programme for KEDCO 81 Figure 4 Best-practice grid electrification programme for KEDCO 99 Figure 5 Impact of cross-subsidy requirements on tariffs 108 Figure A1 Post-privatization market structure 109 Figure A2 KEDCO payment of NBET invoices (Feb-Dec 2015) 114 Figure A3 Estimated distribution of relevant energy expenditure 115 Figure A4 Poverty rate (% of poor households) for the KEDCO service area 119 Figure A5 Multi-tier matrix for access to household electricity supply 120 Figure A6 Decision tree for non-KEDCO grid electrification Tables 55 Table 1 Electricity access in 2015 and grid extension programme for the KEDCO service area, 2015–2030 57 Table 2 Technical summary for the LV intensification and MV extension components of the universal access programme for the KEDCO service area, 2015–2030 59 Table 3 Electrification phasing for the KEDCO service zone 60 Table 4 Roadmap – Phase I Key Actions 61 Table 5 Electricity access rollout programme (2018–2030) 62 Table 6 Capital cost of the electrification programme Contents 51 63 Table 7 Impact on electricity demand 63 Table 8 Investment financing requirements for grid electrification ($ million) 65 Table 9 Technical assistance (TA) programme (present–2023) – US$ million 71 Table 10 Electricity access in 2015 and grid extension programme for the KEDCO service area, 2015–2030 71 Table 11 Technical summary for the LV intensification and MV extension components of the universal access programme for the KEDCO service area, 2015–2030 78 Table 12 Electricity access rollout programme (2018–2030) 80 Table 13 Conservative grid electrification programme 80 Table 14 Capital cost of the KEDCO grid electrification programme (conservative) 81 Table 15 Increased grid load associated with the conservative roll-out program 81 Table 16 Best-practice grid electrification programme 82 Table 17 Capital cost of the KEDCO grid electrification programme 82 Table 18 Increased grid load associated with best-practice roll-out program 83 Table 19 Technical assistance (TA) programme (present–2023) – US$ million 89 Table 20 KEDCO’s past and forecast financial position 90 Table 21 Summary of KEDCO’s non-access investment requirements (US$ million) 91 Table 22 Capital investment requirements – grid electrification (US$ mn.) 97 Table 23 KEDCO selected Tariffs (February 2016 after Tariff revision) 97 Table 24 KEDCO customer numbers and kWh consumption (May 2015) 113 Table A1 Current expenditure on energy 114 Table A2 Expenditure in NGN/month 52 Abbreviations and Definitions ATCC  Aggregate technical, commercial and NESI Nigerian Electricity Supply Industry collection losses NGN Nigerian Naira BPE Bureau of Public Enterprise NIAF  Nigeria Infrastructure Advisory DISCO Distribution company Facility ECA Economic Consulting Associates NIPP National Integrated Power Project EPSRA Electric Power Sector Reform Act NW North West FGN Federal Government of Nigeria Off-grid Electricity provided other than through IFI International Financing Institution the main DISCO network (i.e., isolated KAEDCO Kaduna Electricity Distribution grids, SPDs (see below) and distributed Company power such as solar home systems and KEDCO Kano Electricity Distribution Company pico lighting) LGA Local Government Area PHCN  Power Holding Company of Nigeria MYTO Multi-year tariff order (successor to NEPA) NAPTIN National Power Training Institute of PRG Partial Risk Guarantee Nigeria RAB Regulatory Asset Base NBET  Nigerian Bulk Electricity Trading REA  Rural Electrification Agency (Federal Company level) NEAP Nigeria Electricity Access Program REB Rural Electrification Board (State level) NEPA  Nigerian Electric Power Authority SHS Solar home systems (former vertically integrated electricity SPD Small Power Distribution company utility) TCN Transmission Company of Nigeria NEPP National Electric Power Policy (2001) WACC Weighted Average Cost of Capital NERC  Nigeria Electricity Regulatory Commission Key Data Exchange rate, September 2015: US$ 1 = Naira 200. Calculations were made in 2015 and starting in January 2016 the exchange rate experienced major fluctuations (as of June 2016 the official exchange rate dropped to US$ 1 = Naira 280 and the unofficial rate is still lower). Price datum: mid-2015 (Costs are based on the prices and exchange rate of mid-2015. It is assumed that subsequent movements in the exchange rate will eventually feed through into local prices and costs and purchasing power parity will prevail.) Financial year for Discos: 1 June to 31 May Executive Summary This Investment Prospectus was developed in close ES1 Introduction collaboration with the Kano Electricity Distribution Company (KEDCO) and is based on the geospatial The Kano Electricity Distribution Company (KED- least-cost electrification plan produced by the Earth CO) service zone comprises the states of Kano, Kat- Institute of Columbia University. sina and Jigawa in the North West Nigeria, with a The Prospectus provides a multi-year action plan combined population of about 24 million and an es- for the achievement of universal access by 2030 in timated 4 million households. Today, access to elec- the Kano service area, combined with an assessment tricity grid in the KEDCO service zone is approxi- of the projected investment needs, financing gaps, mately 31% of the population. Schools, clinics, and a and possible sources of funding for the implementa- large number of businesses also have limited access, tion of the first five years of the electrification rollout. not only in rural areas. By 2030, the population in The recommendations contained in the report the Kano service zone is projected to be of almost reflect and respond to the operating context and the 34 million or about 6 million households. Under challenging sector environment of KEDCO, while business-as-usual, the share of population without integrating the knowledge emerged from best prac- access will grow, not diminish. tices in international experience.1 The Prospectus The KEDCO’s Business Plan attached to the Per- identifies the key weak links, and interrelated issues, formance Agreement under the overall Concession in respect of the major gaps and ambiguities in the Agreement submitted at privatization (2012), and policy, institutional, and financing frameworks that entered into force in January 2015, envisages capital pose significant barriers to achieving universal ac- expenditures for a small number of “new customer” cess by 2030 at least-cost. Investments alone will not connections (about 350,000 in a five-year period). be sufficient, and these make or break challenges for However, these in effect are already reflected in the scaling up access—especially those outside KEDCO’s 31% access statistic mentioned above; as they mostly control—require priority attention and resolution. represent the installing of meters in the sub-popula- The Prospectus is divided in seven sections. The tion of existing consumers without meters presently.2 report provides first an overview of the Kano ser- The analysis underpinning this Report is guided vice area and the findings of the geospatial analysis by the national targets identified in the Federal Gov- (Chapter 1) to then present the access rollout plan ernment of Nigeria (FGN)’s National Electric Power up to 2030, detailed scenarios for the first five years Policy (2001). Specifically, the KEDCO’s electrifica- of implementation, and an overview of capacity tion plan for achieving universal access by 2030, is strengthening needs (Chapter 2). The key role of underpinned by the following building blocks: sector institution and policies is highlighted (Chap- ter 3) before providing an assessment of the electri- zz Geospatial least-cost electrification rollout fication plan’s investment requirements and related program plan (2015–2030) to achieve univer- financing gap (Chapter 4). The last two sections are sal access by 2030. This high level (MV, LV, fi- devoted to equity considerations (Chapter 5) and nal beneficiary connections) geospatial plan also the potential offered by off-grid solutions for the delineates broadly the boundaries in space and timely scale-up of electricity access (Chapter 6). over time of areas for staging a well-designed This Summary presents an overview of the main and coordinated off-grid rollout across the entire findings and recommendations emerged from the KEDCO service zone for pre-electrification; par- analysis. ticularly in areas where grid extensions are not 53 54 Executive Summary projected to materialize through the mid-term funds—besides private equity—that would have (2025). Also identified are investments for major to be intermediated by the Government for the equipment categories, including MV extensions, KEDCO Prospectus. LV rollout, final customer connections where zz Technical assistance and capacity strength- grid delivery is appropriate. ening for key sector institutions and agents zz Implementation Readiness – A rapid appraisal are identified in terms of areas of focus directly was undertaken at start to broadly gauge critical linked to and essential for the successful imple- readiness factors that pose material limitations mentation of the programme; although detailed for scaling up affordable and reliable electricity scoping can only be undertaken once the inter- access, efficiently and sustainably, and in a timely linked set of key policy and regulatory ambigui- manner. Some are relatively easy to address by ties and gaps are effectively addressed. targeted capacity strengthening (especially tech- nical, planning, logistics of mobilisation and program management of a hugely scaled up ac- ES2 Least-cost Geospatial cess rollout program by KEDCO). Some others Electrification Rollout are inter-related systemic factors endemic to the sector’s power market operating environment Programme that are beyond any single sector agents’ control. A high level KEDCO least-cost geospatial plan for These are severely limiting KEDCO’s financial scale up of electricity access in KEDCO’s entire ser- condition and its space to undertake even rou- vice area was prepared by the Earth Institute of Co- tine capital expenditures critically needed to up- lumbia University. The analysis and results provide grade the existing network and operations. In ad- a geospatial and quantitative frame for the design dition, there are “show stoppers” that emanate in and detailing of a well-coordinated and harmonized one manner or another, from ambiguities and key implementation program for off-grid electrification gaps in the enabling policy and regulatory frame- over a fifteen-year timeframe (2015–2030), along- work today. Any meaningfully significant start of side the grid rollout, which is the focus of this re- implementation of an electrification programme port. for achieving universal access can only begin sub- Columbia University undertook a digital map- ject to the Federal Government of Nigeria’s (in col- ping of the spatial demographic settlement patterns laboration with the Ministry of Power and NERC) of households across the entire service area. In addi- addressing of the key enabling show stoppers iden- tion, KEDCO engineers and field staff were trained tified in this report. by the Columbia geospatial specialists to undertake zz Investment Financing Prospectus (2018– the digital mapping of KEDCO’s existing network 2023) – The investment financing requirements infrastructure (MV lines). This involved digital data for achieving universal access are substantial and capture and processing to prepare the spatial repre- financing must be sustained over the duration sentation data layer to support the least-cost analysis of the program and beyond to 2030, and ensur- of network rollout. ing its “bankability” is the pivotal challenge. No The Columbia University Network Planner Plat- country that has achieved universal access, or ad- form is supported by several digitised data layers vanced substantially in access provision, has done (demographic, socio-economic, affordability, exist- so without significant levels of public funding ing MV infrastructure). The modelling algorithm support for investment sustained over the pro- rapidly assesses the relevant technical, economic and gram duration; irrespective of whether the distri- financial trade-offs underlying the delivery modali- bution sector was privatised or a national utility. ties and technology options available—grid connec- The Prospectus highlights for the specific case tions by LV intensification, MV lines extension, off of KEDCO the extent of the projected financing grid Solar Home Systems and isolated mini-grids— gap in magnitude, and the potential sources of to identify the least-cost option for access provision. Executive Summary 55 The geospatial analysis indicates that over the registered as customers, they all require meters. long term (2030), grid extension is the least-cost c. Customers without a meter and consumers electrification option for virtually the entire popula- together are the lowest hanging fruit in the tion (~97%) within the KEDCO service area. electrification programme as they require a Table 1 below summarizes the components and one-time very low capital investment to in- costs for a ~US$3.3 billion3 grid extension program stall appropriate metering and integrate them that will reach about 5.3 million households, result- into the customer billing and revenue collec- ing in nearly universal grid coverage, by 2030: tion systems; thereby boosting otherwise lost revenues from energy purchased but unbilled. a. Customers: KEDCO has approximately From a commercial and business perspective 400,000 residential customers who are billed, this represents a high yield and quick payback but only 160,000 are metered (63% receive es- investment opportunity. timated billings). d. LV Intensification: By 2030, 45% of pro- b. Consumers: About 840,000 households are jected homes will be situated in locations that served with electricity but are not metered not are currently within 1.5 km4 of an existing Table 1  Electricity access in 2015 and grid extension programme for the KEDCO service area, 2015–2030 Electricity access status (2015) Grid extension program (2015–2030)* Components of grid Total CAPEX Type Populationa program Populationa,b CAPEX per HH of (Type of grid access access (Households) Percent planned) (Households) Percent (M USD) (USD) Grid 7,430,000 31% A) Customers: 2,400,000 7% $40 $160 access KEDCO has ~400K customers (400,000) (2015); 63% need meters ($160/HH) (1,240,000) B) Consumers: 5,030,000 15% $150 $180 ~840K HHs (2015 est.) consume (840,000) power but do not pay KEDCO; all need meters & improved connections (~$180 per HH) No grid 16,480,000 69% C) LV Intensification: 15,680,000 47% $1,670 $625 access By 2030, ~2.7 M HHs near the grid (2,670,000) will need LV line, meter, connection (~$630 per HH) (2,750,000) D) MV grid extension: 10,560,000 31% $1,470 $835 By 2030 ~1.8 M more distant HHs (1,760,000) (>1.5 km from transformer) will need MV and LV line, connection, meter (~$840 per HH) Total 23,910,000 100% Total 33,670,000 100% $3,330 $590 c (3,990,000) (5,670,000) Source: Earth Institute, 2015. a Based on census data, rural households have 6.1 persons on average vs. 5.8 for urban households. For simple computations and where the ratio of urban and rural households is unknown, 6 persons per household are assumed. b It is assumed that population growth from 2015–2030 among those who currently have grid access (components A and B) will lead to net formation of new households that will need new connections requiring LV intensification (component C), MV grid extension (component D). c Average household costs are calculated by summing all CAPEX costs across all program components and dividing by the total number of households served. *Least-cost grid coverage is 97 percent. 56 Executive Summary transformer. They require possibly a simple LV even though scaling up access is within the broader extension; otherwise service drops and meters. mandate of the terms of its Concession Agreement Costumers, consumers and LV connections to- entered into with the Federal Government of Nigeria gether target a total of nearly 4 million homes, (FGN) and the Bureau of Public Enterprises (BPE).6 which represents almost 70% of the universal The Readiness Assessment focused on the key fac- access program. tors and drivers that pose a material and significantly e. MV Grid Extension: About 1.8 million house- inhibiting impact on KEDCO’s technical, operating holds are located beyond 1.5 km range of a and financial performance in the immediate to near transformer and their connection would re- term; and looking beyond, to the Company’s ability quire extension of MV lines and LV reticula- and incentives as a private utility to initiate imple- tion. This segment corresponds to 30% of the mentation of an access scale up program of the scope, overall grid-access programme. and scale identified by the Geospatial least-cost roll- out plan. Broadly, the key challenges to initiate and Table 2 below highlights physical program specific accelerate the program implementation broadly stem parameters—kilometers of MV and LV lines, and from two institutional framework dimensions: incremental demand from the new connections— specific for each of the three states in the KEDCO i. those within KEDCO, that are relatively easily service zone. and quickly addressable, and ii. those critically impacting KEDCO but largely Physical Program – Over half the population in the out of its control as they are driven by the ex- KEDCO service zone is in Kano state. Significantly ternal environment in the sector within the for the access program implementation, Kano is the utility must function, including in particular: most urbanized of the three states (over 50% of the (a) regulatory framework and process for re- LV physical program). The MV physical program tail tariff review and setting; and, (b) systemic numbers in Table 2 also reflect that the populations modus operandi of the bulk power supply mar- in Katsina and Jigawa states are not only less urban- ket adequacy, cost structure, and transactional ized, but live in communities that are more scat- payments settling environment presently. tered, reflected by the fact that about 70% of the MV extension is targeted for Katsina and Jigawa, and MV line needed per household is higher in Jigawa Mobilizing Physical ES4  and Katsina (11–13 m) than in Kano (8–9 m). Programme Implementation Incremental demand – The grid extension program will result in a substantial increase in generation KEDCO has limited experience to date of extend- supply requirements for the KEDCO service zone. ing electricity grids on any scale. Most if not all of The program would add 5–5.5 million new residen- the “new connections” reported and/or depicted in tial customers to the KEDCO grid, with incremen- its capital expenditure plan filed with NERC, are in tal demand of about 1,100MW,5 of which about 700 essence a few new meter installations mostly.7 Fur- MW is attributable to new connections spatially lo- ther, KEDCO presently have limited human, mate- cated near existing transformers (“intensification”). rial and technical resources for undertaking a major programme of connecting customers through in- tensification and grid extension.  S3 Programme Implementation E KEDCO staff and management acknowledge that – Readiness purely from a technical and engineering standpoint, KEDCO (indeed, most the other DISCOs as well) is to a large extent the electrification work will need still attempting to correct years of under-investment to be and can be contracted out to the private sector and poor management of the industry. A Rapid (both grid and off-grid). However, KEDCO will need Readiness Assessment was undertaken at the outset targeted capacity building to enable it to supervise to gauge the key hurdles and challenges to the compa- and manage a major electrification programme. For- ny’s ability—managerially, technically, and financial- tunately, the private sector in North West Nigeria is ly—to mobilize for another priority, of the magnitude sufficiently experienced in undertaking electrification and scope called for by the universal access program; works, though not on the scale necessary to achieve the electrification roll-out required for KEDCO. Executive Summary 57 Table 2   Technical summary for the LV intensification and MV extension components of the universal access programme for the KEDCO service area, 2015–2030 New generation needed Number household grid Grid length proposed (MW) for residential connections proposed (km) connections MV grid LV MV grid LV extension intensification extension intensification MV grid LV MV/HH State extension intensification MV LV (avg, m) LV Jigawa 510,000 482,400 6,600 15,200 12.9 13,200 120 120 Kano 640,000 1,523,200 5,600 18,700 8.7 34,800 170 400 Katsina 610,000 664,400 7,000 18,200 11.4 17,000 150 160 Sub-total 1,760,000 2,670,000 19,200 52,100 10.8 65,000 440 680 Total 4,430,000 136,300 1,120 Source: Earth Institute, 2015. Upstream training and capacity strengthening Under the present policy and regulatory frame- can readily address this limitation in implementa- work and review process in-place, financing the uni- tion capacity to the physical program rollout; both versal access implementation program is not a bank- within KEDCO as well as trading of more private able proposition. To wit, the Readiness Assessment contractors typically provide in-house training for clearly indicates: linesmen, fitters, jointers, etc. In particular, the Industrial Training Fund (ITF) zz The multi-year tariff order (MYTO) approved is used for training engineers and technicians for in February 2016 covering the next 5–10 years, more complex equipment and processes. In the elec- does not make allowance for large scale elec- tricity sector, the National Power Training Institute trification investment. This will need to be sat- of Nigeria (NAPTIN) operates a training facility on isfactorily remedied before the electrification the outskirts of Kano city that provides training for programme can be launched. Indeed, there are the electricity companies in NW Nigeria. This fa- no explicitly mandated access targets over the cility is equipped with modern equipment. While medium term and beyond. Furthermore, under it does not currently provide training in the skills the current MYTO 2015 regime, tariff revenues needed for the expansion of the distribution net- are in-sufficient to even cover 100 per cent of all work (linesmen, fitters, jointers, etc.). operating expenses with rapidly accumulating deficits of account payables.8 ES5 Financing the Universal zz The bulk power market that KEDCO purchases supply from, is still marked by conditions of Access Rollout Programme power supply inadequacy (even planned alloca- The investment requirements of the least-cost access tions), considerable unpredictability, and a rising scale up program are substantial. For the grid com- unit cost of bulk power generation, most of the ponent, capital expenditure of about $3.3 billion time working in the direction of pushing retail over 15 years is estimated, at an annual average of tariff adjustments upwards. Under such circum- $220 million per year over the program implemen- stances, the lagged six monthly tariff review pro- tation period. Undertaking implementation of such cess of NERC, to remedy such “unanticipated a program will require mobilisation of significant changes” to assumptions in the baseline tariff levels of financing flows into KEDCO, sustained calculations, results in adding to the cumula- year-in-and-out over its implementation horizon; tively mounting adverse pressures on KEDCO’s and at terms that do not undermine KEDCO’s com- financial conditions. mercial and financial position. 58 Executive Summary Everything considered, for the foreseeable fu- at the same time ensuring commercial viability of ture, very limited equity contributions can be KEDCO. To the extent that NERC regulated tar- expected forthcoming from KEDCO owners to- iffs—guided by FGN policy on access—combined wards financing some portion of the capex for the with other revenue sources potentially available to universal access program implementation. And as a utility10 do not allow recovery of 100 per cent of highlighted above, financing capex for the access the capital expenditures (capex) of the access scale scale up program via retail tariffs is not a workable program (investment in MV, LV and final service proposition. drops and connections, meters); the universal ac- Indeed, relevant experience from other nations— cess policy would need to identify the means and that have effectively implemented electrification mechanisms for providing public funds to bridge programmes for achieving universal access—un- the shortfall (investment financing gap associated ambiguously indicates that no country has achieved with the access rollout implementation each year). universal electricity access—irrespective whether the Such funding would need to be ex-ante, adminis- distribution sector is privatised or in public hands— tered transparently and backed by independent without some form of public funds (subsidy) to fi- regulatory review, oversight, monitoring and com- nance a substantial portion of the capital investment pliance process of the physical program implemen- requirements of the access rollout (MV, LV and service tation, and by an independent and competent trust connections), at least in the early stages of program agent to administer the funds flows and reporting implementation when revenues from other sources requirements. are inadequate. Indeed, this distinguishing feature of the en- abling policy framework marks a dividing line sepa- Phasing Strategy for ES6  rating those countries that have effectively navigated Implementation of a universal access rollout and others that are stalled the Electrification or move in starts and stops. This represents a lynch- Programme (2016–2023) pin (and make-or-break) policy issue that the FGN/ Ministry of Power would need to address in any In light of the Readiness Assessment considerations new/updated National Energy Policy for Universal highlighted above, this section recommends a time- Electricity Access. The policy context for achieving phased implementation (2016–2030), as shown in universal access, goes well beyond addressing “rural Table 3: electrification”. zz Phase 1 (present-2017 end) – Laying essential More specifically, a necessary pre-requisite for groundwork any meaningful and sustainable start of an electri- zz Phase 2 (2018–2023) – Building momentum and fication programme, is for FGN to adopt a specific acceleration in scale of implementation (grid and policy, encompassing much more than a statement off-grid) of vision, and access targets. Inter alia, the “National zz Phase 3 (2024–2030) – Full throttle grid electrifi- Universal Access Policy” should address clearly the cation rollout full range of enabling policy measures and drivers necessary to facilitate the DISCOs in scaling up Phase I allows for time essential to prepare for electricity access in a systematic and comprehensive program launch (both on- grid and off-grid), which manner for provision of adequate, affordable and would require the timely undertaking of specific ac- reliable access to all residents. The national access tions, as shown in Table 4, to set in place a policy and policy should also clarify the key roles, mandates regulatory enabling environment and to acquire the and accountabilities of the sector institutions (in- capacity and materials needed for the programme cluding State and Local Authorities) and stakehold- implementation. Development partners could pro- ers, whose engagement is essential in some manner vide targeted support via technical assistance to for achieving the Universal Access Program’s time- strengthen the capacity ok key sector actors. specified targets. In particular, the preparatory phase should focus Such a policy would need to transparently put on three dimensions: forth and articulate the principles and key support- ing mechanisms for ensuring affordability, espe- zz FGN to prepare and enact National Universal cially for the poor (connection charges9 and tariffs); Access Policy – to drive Nigeria’s National Elec- Executive Summary 59 Table 3  Electrification phasing for the KEDCO service zone PHASE 1 2016–17 Preparation Capacity-building – directly linked to facilitate grid rollout consistent with achievement of annual connection targets. Finalise national policy for enabling achievement of universal electricity access – targets, public funding support, tariffs, and guidelines on service standards appropriate for range of off-grid access services (pre-electrification, as well as remote area); Regulatory framework: update tariff regulation and related oversight consistent with national access policy; to monitor achievement of DISCO targets for access per agreed annual rollout plan parameters. Off-Grid program: complete detailed design of key components of rollout; including institutional framework, service standards, certification, and annual targets to be achieved consistent with overall geospatial least-cost rollout plan (2015–2030) Tier 1 and 2 beneficiary segmentsa – market based supply and delivery chains for cash-and-carry pico-solar PV products and home systems that are quality certified. Isolated mini grids (Tier 3+) – identify business models that are commercially viable, and readily scalable, consistently with meeting off-grid program targets.b PHASE 2 2018–23 Accelerate grid electrification carefully Grid: Focus on intensification with some MV extensions. Build up experience. Substantial increase in grid access by 2023. Off-grid: launch pre-electrification program for Tier 1 and Tier 2 beneficiary segments. For Tier 3+ field test business models and schemes for isolated micro/ mini-grid networks. For latter, focus priority on spatial locations projected to receive grid service after 2023; per geospatial least-cost plan. PHASE 3 2024–30 Full throttle grid electrification Grid: Focus on extension of the MV grid; complete any remaining or emerging intensification. Off- grid: continue with pre- electrification where appropriate. Note: the off-grid pre-electrification programme entails both communities that are not expected to receive access in the medium-term and those that are not expected to receive a grid connection by 2030. a A Multi-Tier Framework for electricity access was developed by the World Bank Group under the Sustainable Energy for All (SE4All) engagement. The framework defines five dif- ferent tiers of access for electricity supply corresponding to different electricity services is further discussed in Annex 4. b Various donors are providing support for off-grid electrification in Kano zone and elsewhere including GIZ and DFID. trification Rollout Program for Universal Access zz KEDCO – to strengthen its organisational and as outlined above. The Policy will include access functional capacities to implement the access targets and supporting financing mechanisms. scale up program particularly in relations to zz NERC – informed by the Universal Access Pol- planning, design, procurement, construction icy—to appropriately refine, expand and detail management, contracting, materials manage- the MYTO framework and update its oversight, ment, quality and standards. In parallel, KEDCO review and verification processes and mecha- would continue to further reduce technical and nism to play its due role in support of the Uni- commercial losses and strengthen its financial versal Access Implementation Program. stance. 60 Executive Summary Table 4  Preparatory Phase – Key Actions Responsible agent Action Milestone On-grid electrification FMP Design and adoption of a National Access Policy by end 2016/beginning of 2017 KEDCO Develop plan for electrification showing indicatively when by end 2017 different areas will be electrified. This will allow them to be prioritised for off-grid electrification. FMP/NERC/KEDCO Set electrification targets, targets developed in coordination beginning early 2017 with the NERC tariff review. NERC/KEDCO/FMP Update MYTO. Begin early 2017 for implementation of new tariffs in 2018 Off-grid electrification NERC/GIZ Finalise the revised regulation on Independent Electricity early 2016 Distribution Networks. KEDCO KEDCO management to decide role in relation to off-grid early 2017 electrification – include in tariff submission to NERC in 2017. Grid Rollout ES7  zz best-practice scenario – reflects best practice experience in ramping up the physical rollout of Implementation (2018– implementation on a programmatic basis; that 2023) – Two Scenarios all key actors commit with top priority to putting their best efforts towards making best practice In light of the Readiness assessment findings and rec- achievable in Nigeria; especially FGN ( policy), ommendations above, two scenarios Fare identified NERC (tariff framework) and KEDCO (similar following completion of Phase I – laying the essential to their counterparts institutions in e.g. Indo- groundwork. They differ in the trajectory of the year- nesia, Kenya, Tunisia, Laos and Rwanda, where to-year implementation of the physical program on- access was increased by a factor of five times in grid; the number of connections implemented each under three years). year and speed and acceleration. They also differ in the underlying expectations on improvements in Conservative scenario – in the first two phases of the key constraining/inhibiting factors, especially: bulk programme for KEDCO, up to 2023, an investment power supply adequacy and variability; quality of en- financing requirement of US$ 362 million would be abling policy framework announced, and its provi- required for grid electrification. The on-grid electri- sions and mechanisms for public funding to bridge fication would begin cautiously with 30,000 new con- the capex financing gap; and a conducive and sup- nections in 2018 rising to nearly 200,000 connections portive regulatory framework for retails tariffs con- in 2023 and cumulatively over this period a total of sistent with the universal access policy. Table 5 shows nearly 550,000 new connections would have been the annual implementation profile. made. The electrification rate would still be a rela- zz conservative scenario – reflects a cautious tra- tively modest 37% at the end of 2023 (62% for insti- jectory due to the degree of progress in the sec- tutions), compared with 33% today,11 but this would tor environment, with slow enactment of key be the foundation for of a much more rapid electri- enabling actions and/or processes and funding fication rate over the subsequent years with an an- mechanisms; power supply adequacy picture nual electrification rate of up to 500,000 per year and takes more time as well as KEDCO’s commit- ultimately bringing the electrification rate to 83% by ment and readiness to engage. 2030 (94% for social and administrative institutions). Executive Summary 61 Table 5  Electricity access rollout programme (2018–2030)a Access Rollout 2018–2030 2015 (baseline): Conservative scenario Best-practice scenario Grid Institutions Institutions Grid Institutions Institutions connections: Grid access connected: access rate: connections: Grid access connected: access rate: 1.24 mn. rate: 33% 3,350 21% 1.24 mn. rate: 33% 3,350 21% New New New New connections Progressive Institutions Progressive connections Progressive Institutions Progressive (‘000) access rate connected: access rate (‘000) access rate connected: access rate (%) (‘000) (%) (%) (‘000) (%) 2018 30.0 31% 600 25% 50.0 31% 600 25% 2019 40.0 31% 800 29% 75.0 32% 800 29% 2020 50.0 31% 1,100 36% 125.0 34% 1,100 36% 2021 93.0 32% 1,300 44% 200.0 37% 1,300 44% 2022 137.0 34% 1,400 53% 275.0 42% 2,050 57% 2023 198.0 37% 1,417 62% 375.0 48% 2,878 75% Total additions 548.0 6,617 1,100.0 8,728 2018–2023 Total 1788.0 37% 9,967 62% 2,340.0 48% 12,078 75% connections by 2023 Total 3,200.0 5,153 3,360.0 3,032 connections added 2024–2030 Total 4,988.0 83% 15,120 94% 5,700.0 95% 15,110 94% connections by 2030 a Note, the electrification rate declines between 2015 and 2018 because, despite some electrification in 2018, this has not kept pace with the growth in the number of households. The same is not true of social institutions where the total number of institutions is assumed to be fixed (instead the size of the schools and clinics grow as the population grows). Best practice scenario – in the first two phases of ES8 Investment Financing the programme for KEDCO, up to 2023, an invest- ment financing requirement of just over US$ 731 Prospectus – Grid Rollout million would be required for grid electrification. (2018–2023) The on-grid electrification would again begin rela- Table 6 summarizes for the two scenarios the capital tively cautiously with 50,000 new connections in requirements of the physical programme. Cumula- 2018 rising to 375,000 connections in 2023 and tively, the implementation of the conservative roll- cumulatively over this period a total of nearly 1.1 out is estimated to require US$ 2.5 billion by 2030, million new connections would have been made. whereas US$ 3.2 billion are estimated for the best The electrification rate would still be nearly 50% practice rollout. The year-to-year capital costs are at the end of 2023 (75% for the institutions). Over also displayed, together with the investment need the subsequent years the annual electrification for the construction of LV and MV lines. As shown rate would increase up to 500,000 connections per in the Table, the conservative scenario up to 2030 is year ultimately bringing the electrification rate to relatively less focused on MV extension (US$ 680 95% by 2030 (94% for social and administrative million), and the investments are mostly directed institutions). to the construction of LV lines (US$ 1.7 billion). In 62 Table 6  Grid rollout capital investment cost (2018–2030) Conservative scenario 2018–2030 LV Intensification LV Intensification Total New grid New grid Average $/ Grid access connections $ per Total cost connections $ per Total cost connection Total LV+ Executive Summary rate (‘000)” connection ($ mn.) (‘000)” connection ($ mn.) (LV+MV) MV/$ mn. 2018 31% 30 630 19 0 n/a 0 630 19 2019 31% 40 630 25 0 n/a 0 630 25 2020 31% 50 630 32 0 n/a 0 630 32 2021 32% 63 630 40 30 761 23 672 63 2022 34% 97 630 61 40 765 31 669 92 2023 37% 148 630 93 50 771 39 666 132 Total prospectus: 2018–2023 428 630 270 120 766 92 660 362 Total: 2024–2030 2,272 630 1,431 880 823 724 684 2,155 Total program life: 2018–2030 2,700 630 1,701 1,000 816 816 680 2,517 Best-practice Scenario 2018–2030 LV Intensification LV Intensification Total New grid New grid Average $/ Grid access connections $ per Total cost connections $ per Total cost connection Total LV+ rate (‘000)” connection ($ mn.) (‘000)” connection ($ mn.) (LV+MV) MV/$ mn. 2018 31% 50 630 32 0 0 0 630 32 2019 32% 75 630 47 0 0 0 630 47 2020 34% 100 630 63 25 765 19 657 82 2021 37% 150 630 95 50 771 39 665 133 2022 42% 200 630 126 75 780 59 671 185 2023 48% 275 630 173 100 792 79 673 252 Total prospectus: 2018–2023 850 630 536 250 782 195 664 731 Total: 2024–2030 1,850 630 1,166 1,550 848 1,314 729 2,480 Total program life: 2018–2030 2,700 630 1,702 1,800 839 1,509 714 3,211 Executive Summary 63 Table 7  Impact on electricity demand Year Conservative Best practice Grid access rate Demand impact (MW) Grid access rate Demand impact (MW) 2018 31% 7 31% 12 2019 31% 16 32% 29 2020 31% 28 34% 58 2021 32% 49 37% 104 2022 34% 81 42% 167 2023 37% 128 48% 257 the best-practice scenario, investments in LV lines by KEDCO’s shareholders of 10% of the capital re- are coupled with more investments in MV extension quired.12 This assumes that KEDCO’s shareholders (US$ 1.5 billion), which are pursued more aggres- are comfortable that the regulatory framework going sively in time (starting in 2020 instead of 2021) and forward will reward them sufficiently for the risks size (1,800 new connections versus 1,000 in the con- entailed in such investments and that the market re- servative scenario), and the main reason underpin- forms continue to show results in terms of improved ning bigger achievements in access by 2030. availability of electricity at the wholesale level. Table 7 presents the incremental impact on de- The DISCOs were privatised at the end of 2013. The mand due to new connections by 2023, which is of 2005 Electric Power Sector Reform Act prescribes the 128MW in the conservative scenario and 257MW regulatory framework governing them, such that the in the best-practice one. This should be manageable. companies should earn revenues that cover their costs and provide a reasonable market return on the capital ES9 Investment Financing invested. For the DISCOs, any investment they make in the expansion of electricity access would therefore Gap (2018–2023) need to be undertaken on a commercial basis. The investment financing requirements are indicated The current owners of the DISCOs largely fi- in Table 8 below for the two electrification scenarios. nanced the acquisitions of the companies with loans This provisionally assumes an equity contribution securitised against the parent companies’ assets, not Table 8   Investment financing requirements for grid electrification ($ million) Conservative Best practice Capital investment requirement (2018–2023) 2018 19 32 2019 25 47 2020 32 82 2021 63 133 2022 92 185 2023 132 252 Total capital investment 362 731 Minus: Assumed KEDCO equity (assumed 10%) 36 73 Connection charges - - Plus technical assistance 11 16 Total financing gap 336 674 64 Executive Summary against the DISCOs’ own profits. Nigerian com- to specific rules and guidelines, with the supervi- mercial banks are currently unwilling to finance the sion of NERC, governing cash-flow management DISCOs’ investments or to finance revenue shortfalls and in particular how the financial resources are to when securitised against the DISCOs’ revenues on be dispersed, monitored and, in the case of loans, terms that are consistent with the MYTO allowed returned. Finally, if the Fund is to be housed at an revenue formula. Borrowing by the DISCOs on com- already existing agency (e.g. NERC), firewalls will mercial terms to finance investments that are needed have to be raised between the two entity to ensure simply to create a stable platform to supply their ex- the independence of both. isting customers is therefore problematic,13 and ma- jor borrowing on commercial terms on any scale to expand the network is unlikely over the first phase of ES11 Technical Assistance the electrification access programme. We tentatively Technical assistance directed to key sector institu- assume for illustration purposes, that KEDCO share- tion and agents is envisaged for the acquisition of holders may be willing to contribute 10% as an equity the capacity required for the physical implementa- contribution (injections or retained profits).14 tion of the access rollout and for the design and es- The resultant financing gap is assumed to be tablishment of the enabling policy, legislations, and financed in some manner consistent with interna- regulatory instruments that would set the stage for tional best practices, highlighted above. Namely, the and ensure the successful execution of the electrifi- international experience with undertaking national cation programme. Although some support should electrification programmes has almost universally be directed toward the achievement of the key ac- been largely financed through grants and conces- tions to be undertaken in the phase preliminary to sionary loans15 obtained by the Government from a the access rollout (described in Table 4), capacity variety of sources including Development Partners, strengthening will be needed on an ongoing basis Provincial Governments, Local Authorities, and on during the implementation phase as the programme lent to the utility; on terms that ensure the commer- expands and accelerates. cial viability of the implementing agent, be it private A proposed technical assistance programme for or a public entity. capacity strengthening is described in Table 9. The programme is indicative, as the detailed scoping and its quantification will ultimately be defined by the ES10 Financing Mechanisms more specific actions that KEDCO, the private sec- and On-lending Terms tor and the FGN will decide to undertake to close the gaps and solve the ambiguities related to the for Public Funds Support policy and regulatory framework and to the role of Based on international electrification rollout experi- public finance within the programme. ences16 we suggest the establishment of an Electrifi- Two main areas of assistance are identified: cation Fund that will be used to provide financial support to the private DISCOs when expanding zz Programme design: FGN to prepare and enact access. The Fund will on-lend to DISCOs publicly National Universal Access Policy coordinating raised funding on terms that are commercially vi- grid and off-grid solutions comprehensive of tar- able, whether in the forms of grants or concessional gets and timetables and ensuring the commercial loans, and will also keep DISCOs accountable for viability of the programme for the DISCOs to- the financing received by monitoring and auditing gether with affordability of electricity services for their progress. As shown by international experi- consumers. The policy will identify the key roles ence, it would be the Government responsibility to and responsibilities of sector stakeholders, fill (i) secure the funding and (ii) ensure its availability the gaps for the establishment of an enabling leg- before the electrification rollout takes off. islative and regulatory environment, including Various arrangements have been adopted world- mechanisms to monitor progress and a system of wide for this kind of institution, but all of them rewards and penalties of performance toward the responded to four main principles: transparency, achievement of the access targets; accountability, independence and ex-ante funding zz Physical implementation: KEDCO to acquire of the programme. The Fund management will act the organizational capacities to implement the as a trust fund payment agent and will be subject access scale up program (particularly in rela- Executive Summary 65 Table 9   Technical assistance (TA) programme (present–2023) – US$ million Best Beneficiary Measures Conservative practice KEDCO Planning (yearly program), tendering, 2.5 3.0 management, supervision Strengthening of standard equipment 0.5 0.5 specification, policies & procedures, procurement, mains records (location of plant) Customer Relationship Management 1.0 2.0 Off-grid electrification assessment 0.5 0.5 Sub-total 4.0 5.5 Ministry of Power Planning, training for private contractors a 5.3 8.0 other activities Private manufacturers Technical assistance to ensure manufacturing 1.0 2.0 processes are up to standard NERCb To be determined REA c To be determined Monitoring & evaluation 0.2 0.2 Ministry of Finance To be determined Total 11.0 16.2 a This could be provided through NAPTIN, the electricity training institute based just outside of Kano. b Nigerian Electricity Regulatory Commission (NERC). c Rural Electrification Agency. tions to planning, design, procurement, con- eas where the grid is not recommended as the struction management, contracting, materials least-cost option by 2030. This is a small percent- management, quality and standards) and su- age of the total population (about 3% or 164,000 pervise private sector contractors. The rollout households by 2030) and of schools and clinics will require large scale training of contractors (about 6%). to expand the work force and to bring private zz Pre-electrification – households residing in ar- manufacturing up to standard, to be achieved eas targeted for grid electrification in the latter for instance through the capacity expansion of part of the electrification programme which will the National Power Training Institute of Nigeria thus be required to wait for several years (5 to (NAPTIN).17 10, if not longer) for electricity access. This is potentially the largest component of the off-grid programme and, depending on the electricity ac- ES12 Off-grid Programme cess services provided, it could be characterized Although connection to the grid is the least-cost so- by two subcomponents: lution in the long-run for most of the population, to i. Tier 1&2 access delivery – The economic po- ensure shared well-being and prosperity across the tential of this off-grid sub-programme refers country, off-grid solutions should also be employed to the ~3.3 million households that are not ex- in coordination (in space and time) with and to pected to receive access to the grid during the complement grid developments. first 5 years of the electrification programme More specifically, on the basis of the geospatial (up to 2023) regardless of the conservative analysis, three categories of beneficiaries and uses of or best-practice trajectory implemented (see off-grid solutions can be identified: Table 5)19. ii. Tier 3+ access delivery – the technical po- zz Long-term off grid – small communities or tential for isolated mini- and micro-grids households residing in remote and isolated18 ar- is identified in the latter segment of grid 66 Executive Summary development (in space and time), requiring combination of private sector and public sector-led the extension of MV lines and affecting ~1.8 endeavours: million households (see also Table 5)20. zz Private sector-led off-grid – the establishment These communities and households could be of a credit line for off-grid electrification has provided with sufficient power for essential electric- proven to be very successful in countries such ity services such as household lighting, charging of as Ethiopia and Bangladesh.23 The financing mobile phones and other batteries and devices, and mechanism can be designed to create a market- basic connectivity for schools and clinics to power driven, private sector-led approach addressing computers, vaccine cold chain, and other services. some of the main issues preventing the off-grid Given the country’s richness in solar resources, the market from taking off such as: access to finance technologies identified to provide off-grid services at relatively lower cost of capital, improvements are pico-solar, solar home systems or diesel or hy- to the general lending environment, and iden- brid mini-grids, although a throughout geospatial tification of commercially viable delivery mod- resource mapping of the country, completing the ex- els. A line of credit could be opened to support ercise started by GIZ, could reveal more renewable DISCOs or small and medium sized private energy opportunities. For the Kano service zone, sector enterprises, and it could either become the costs associated to these technologies are in the integral part of the Electrification Fund sug- range of US$50–100 for pico-solar, US$425 on aver- gested for the on-grid rollout or established age for solar home systems, and between US$500 to separately. US$1,200 for mini-grids 21. zz Public sector-led off-grid – building on the Na- The costs associated to an off-grid programme tional Renewable Energy and Energy Efficiency will eventually depend on its size (that is, on the Policy adopted in 2015, stating that solar PV number of beneficiaries, their needs, and the tech- and SHSs will be used to power low to medium nologies deployed) and are potentially substantial. power applications such as communication sta- For instance, given per-household SHS costs, the tions, water pumping and refrigerator in public needs of the long-term off-grid beneficiaries could facilities in remote areas, the FGN could provide be met for around US$70 million. As regards pre- electricity access to all public institutions across electrification purposes, the full rollout of the Tier the country. 1 & 2 programme could require around US$ 450 million alone (with an average combination of pico- The successful implementation of a large scale solar and SHS solutions). plan would also require tackling the other major ob- Not strictly belonging to the off-grid access pro- stacles to off-grid electrification. In particular, roles gramme, but a potentially important segment of the and responsibilities of sector institutions (e.g. Rural off-grid market is constituted by the use of off-grid Electrification Agency) and stakeholders should be solutions for power back-up purposes. This market identified in the new market structure, leading to refers to households already provided with electric- the establishment of an enabling policy and regula- ity access in 2015, or to be connected during the tory framework. This would include designing and rollout plan, that could choose to rely on off-grid enforcing quality standards and possible subsidy technologies for power back-up as long as the pow- frameworks. The establishment of technical stan- er supply provided by the grid is not reliable (high dards for off-grid technologies will also be key to fluctuation of voltage, blackouts and load shedding). protect protect investors’ businesses after the arrival This could also constitute a significant component of the grid, after which off-grid solutions can become of the off-grid developments, as Nigeria is the sec- power supply back-ups and/or feed into the grid net- ond market for self-generators, far more expensive work. Finally, off-grid electrification will have to be than efficient off-grid solutions would be. undertaken in coordination with the actual spatial Several factors constrain the growth of the solar grid rollout of KEDCO in the next five to seven years. market in Nigeria, particularly lack of access to fi- nance for importers, distributors and consumers.22 Hence, a financing plan—tailored to the current Endnotes market structure—should be developed to support 1. The Prospectus’ findings and recommendations off-grid developments. The plan could envisage a are specific to the operating situation of KEDCO Executive Summary 67 DISCO and in light of the broader sector-wide NERC approved retails tariffs have not been set to framework and operating environment context of allow for full recovery of this cost of service. KED- Nigeria today. At the same time, the analysis and CO like all other DISCOs face this systemic under- recommendations of the Prospectus are informed recovery for their respective bulk power purchase by the rich lessons and experiences of relevant best costs. Regardless of the circumstances—that soon- practices from national electrification programs er or later, FGN together with NERC would need to from numerous countries world-wide, that have satisfactorily and speedily resolve and redress this successfully navigated their respective electrifica- distortionary situation. Carrying such amounts of tion programmes to universal or well advanced “accounts payables” on the balance sheets does not access (Morocco, Indonesia, Vietnam, Thailand, bode well for any DISCO to raise even short terms Tunisia, Kenya, among others). While in each working capital from financial markets. instance the specific design features were home 8. KEDCO’s accumulated deficit from privatization grown and tailored to their institutional environ- through 2015 is US$140 million. These figures are ment and political economy, they all exhibit ad- not debt per se; they represent the unpaid share herence to a set of core organizing principles and of costs of bulk power purchases over this period, policy drivers that were necessary to enable their on account, NERC approved retails tariffs have not remarkable achievements. been set to allow for full recovery of this cost of 2. As per discussions with the utility, we understand service. KEDCO like all other DISCOs face this that connections targets for access scale up (to the systemic under-recovery for their respective bulk estimated 69 percent without access today) may power purchase costs. Regardless of the circum- be revisited as DISCOs requested a review and stances—that sooner or later, FGN together with update of the Performance Agreement parameters NERC would need to satisfactorily and speedily originally entered into with BPE. resolve and redress this distortionary situation. 3. All costs throughout the text and tables of this Carrying such amounts of “accounts payables” document are in constant 2015 US dollars, unless on the balance sheets does not bode well for any otherwise noted. DISCO to raise even short terms working capital 4. KEDCO estimates 1.5 km as the radius within from financial markets. which customers can be connected without addi- 9. As per NERC 2012 Regulation DISCOs are cur- tional MV line. rently not allowed to impose connection charges, 5. Ensuring adequate electricity supply to all cus- but the policy could be apt for revision at some tomers served by KEDCO is an urgent. As of 2015, stage of the access rollout. peak supply to KEDCO was typically around 250 10. For example: connection charges, utility equity, bill MW with occasional higher peaks. This is well be- surcharge on non-poor customers within KEDCO. low the 1 GW that KEDCO estimates to be its to- 11. This differs slightly from the figure in the least-cost tal current demand. The 1.1 GW demand forecast geospatial analysis (31% access) as the Investment here would be a) only for residential needs, and b) Prospectus was drafted on the basis of earlier re- in addition to any unmet current need. sults of the geospatial report. 6. The access targets stated in the original Perfor- 12. At the time of drafting this Report, the sharehold- mance Agreements entered into with FGN/BPE ers, IFIs and development partners were not in a have been essentially treated to this day, by all par- position to comment on their likely willingness ties, as “pro forma place holders”, to be revisited to provide equity, debt or grants. The mix of fi- and revised appropriately; once the DISCO man- nancing provided here are therefore placeholder agements assumed control and gained some oper- values. ating experience and obtained hand first knowl- 13. World Bank estimates, February 2016. edge of the ground realities facing the company. 14. The 10% equity contribution is consistent with in- 7. Furthermore, this limited physical program is it- ternational experience from countries such as Bra- self severely constrained on account of financing zil, though it may be optimistic for Nigeria. limitations as elaborated in following. KEDCO’s 15. Examples described in the Report include Brazil accumulated deficit from privatization through where 90% of capital expenditures were financed 2015 is US$140 million. These figures are not debt from grants and concessionary loans and India per se; they represent the unpaid share of costs of where 100% is financed in this way. bulk power purchases over this period, on account, 16. Brazil, India and Chile, for instance. 68 Executive Summary 17. NAPTIN was formerly part of the Power Hold- is to date around 10% (i.e. 180,000 connections ing Company of Nigeria (PHCN) but is currently of the 1.8 million potential beneficiaries). World owned by the Federal Government of Nigeria Bank Task Team Leaders estimates, 2016. The (FGN). WBG Lighting Global started to operate in the 18. Defined by the geospatial report as distant more Tier 3+ access delivery market. than ~100m from any neighbouring structure. 21. The geospatial analysis identified the cost for a 19. The successful experience of the WBG Light- mini-grid with a service standard of 120 kWh/ ing Africa and Lighting Global initiatives in Af- HH-year to be in the range of US$1,000-1,200 and rica (see, for instance, the experiences of Kenya, for a 60 kWh/HH-year per customer service, be- Ethiopia and Tanzania) and Asia demonstrated tween US$500 and US$700. that Tier 1 &2 products can be rapidly scaled-up, 22. Other factors include: i) lack of an enabling policy although not yet at the scale of ~3.3 million house- and regulatory framework; (ii) lack of national holds (international experience suggest that ~30% quality standards for PV products and competition of the size could be easily provided with access). from low quality products; (iii) low levels of aware- World Bank Task Team Leaders estimates, 2016. ness of solar products, their advantages and ways For more information, visit: https://www.lightin- to distinguish good quality products; and (iv) low gafrica.org/. availability of products due to lack of distribution 20. No country has yet scaled-up an isolated mini- or networks in rural areas. Lighting Nigeria, 2015. micro-grid programme and the identification of 23. The Bangladesh SHSs program has been widely viable business models is still a work in progress. acknowledged as the most successful national off- However, international experience suggests that grid electrification program in the world reaching the market potential for this off-grid development 100,000 installations a month. CHAPTER 1 Background to the Kano Service Zone and KEDCO The Kano Electricity Distribution Company (KED- Electricity Supply Industry (NESI) had experienced CO) is responsible for the distribution and supply of years of under-investment and poor management electricity to users in the three states of Kano, Kat- in all parts of the electricity supply chain from fuel sina and Jigawa in the North West of Nigeria. This is supply through to distribution and customer supply. referred to as the Kano service zone. This resulted in chronic power shortages across the The states served by KEDCO are among the most whole country and privatisation was an attempt to populous in Nigeria with a combined population of remedy these problems. The new DISCOs manage- 24 million or 4 million households. Kano is Nigeria’s ment inherited a number of major issues including most populous of Nigeria’s 36 states, while Katsina massive Aggregate Technical, Commercial and Col- and Jigawa are 4th and 8th respectively.1 All the three lection (ATC&C) losses estimated after the comple- states have a relatively high population density. To- tion of the privatization process at around 50%,7 very day, electricity services in the KEDCO service zone poor customer record keeping and billing systems, are available to approximately 31% of the popula- poor network maintenance and overloading of lines tion. By 2030 the population of the three states is ex- and transformers, and very low levels of supply reli- pected to reach 34 million, which will add a further ability. The problems are well documented.8 two million households to the zone for a total of 6 Although the 2010 Power Sector Reform Road- million households. Under business-as-usual, the map has achieved important goals, such as the com- share of the population without access will grow, not pletion of the privatization process for the generation diminish. and the distribution segments, the establishment of Although Kano is Nigeria’s second largest city the Nigerian Electricity Regulatory Commission after Lagos, with a population of 3.6 million, it has (NERC) and the Nigerian Bulk Electricity Trader only one quarter of the population of Lagos.2 Kat- (NBET), the speed of the ATC&C loss reduction sina is the largest city in the state, but is relatively programme that had been anticipated at the time of small with a population of less than 400,000. Dutse privatisation9 has not been achieved and by the end is the capital city of Jigawa. of 2016 DISCOs will have accumulated almost US$3 North West Nigeria has a high concentration of billion10 owed to the rest of the value chain. poverty. The Updated Poverty Map of Nigeria pre- KEDCO inherited ATC&C losses for about pared by Oxford University for the World Bank3 in- 49%, the majority of which are due to collection dicates that Jigawa, Katsina and Kano are among the losses (37.4%).11 The utility has now been in pri- bottom ten states from Nigeria’s 36 states in terms of vate ownership for nearly just over two years and poverty, with Jigawa, Katsina and Kano having 88%, management are attempting to come to grips with 82% and 76% incidence of poverty respectively4 the problems of enumerating customers, collecting compared with a national average of 53%. There is revenues and computerising basic accounting and also a correlation between poverty and low electrifi- management systems. The utility has accumulated cation rates. Kano state alone has the highest num- deficits for US$140 million from 2013 until the end ber of households without electricity in the country of 2015 and has received US$38 million from the (about 1.8 million).5 FGN’s Nigeria Electricity for Market Stabilization KEDCO was privatised, together with nine of Ni- Fund (NEMSF) to pay upstream debtors at the be- geria’s other DISCOs at the end of 2013.6 The Nigerian ginning of 2015. However, in 2015 KEDCO was able 69 70 Background to the Kano Service Zone and KEDCO to pay for 40% only of NBET invoices. Although the financially or managerially, to prioritise a major Performance Agreements came into effect in Janu- electrification programme. Even if the Business Plan ary 2015, cost-reflective tariffs were adopted but submitted at privatization (and entered into force in subsequently abandoned until February 2016, and January 2015), listed as part of KEDCO’s Minimum the utility hasn’t made any investments in improved Performance Targets the connection of 350,000 efficiency beside the purchase of 64,000 meters at customers in a five-year period, the target involved the beginning of 2016.12 mostly meter deployment to existing consumers With the implementation of the new MYTO more than access provision.17 2015 in February 2016, tariffs were brought back to KEDCO has also limited experience of extend- cost-reflective levels, however, to reduce the impact ing electricity grids on any scale, and it has limited on end-consumers they were set at under-recovery human, materials and technical resources for un- for the first few years then allowing for over-recov- dertaking a major electrification programme. How- ery for the achievement of cost-recovery levels over ever, these are not “systemic” challenges, and could a ten-year period. The size of under-recovery has quickly be addressable. been estimated at almost US$700 million for 2016 or 16% of expected total revenue for the whole sec- 1.1 Geospatial Least-cost tor. KEDCO is expected to achieve cost-recovery levels in 201813 and will hence keep accumulating Plan for Universal deficits on account payables until then. Electrification The regulatory framework for tariffs covering the A geospatial analysis conducted by the Earth Insti- next 5–10 years, does not make allowance for large tute under a separate contract with the World Bank scale electrification investment and this will need to disclosed that 1.24 million households in the three be remedied before the electrification programme states are supplied from KEDCO’s grid, represent- can be launched. Under MYTO 2015 tariff revenues ing an electrification rate of around 31%.18 This is are also in-sufficient (fixed charges were also re- consistent with estimates of the current overall na- moved)14 to cover for 100% fall operating expenses. tional grid electrification rate that is thought to be The capital expenditure allowance was also reduced around 35%–40%.19 by 20%15 although DISCOs need to undertake pri- The geospatial analysis provided a detailed as- ority interventions for loss reduction, network re- sessment of the optimal technologies to electrify habilitation and meter installation to enhance rev- the population of the Kano service zone and the enue collection from existing consumers and help investment cost to achieve 100% electrification by improve their financial position. 2030. The plan identified the optimal electrifica- Wholesale generation and transmission is also tion strategy for the year 2030 with the electrifica- inadequate to supply electricity to meet the demand tion of all households either through connection to implied by a rapid roll-out of electrification. The the KEDCO grid or through off-grid solutions for company is currently allocated with 8% of total of remote population and isolated households or as in- total generation capacity, but in 2015 received only terim solutions before grid arrival. The results of the 5% due to transmission constraints16 and at the be- geospatial analysis for the grid extension program, ginning of 2016 power supply was further decreased including highlights of the physical programme spe- because of pipeline militant attacks. Power supply cific to each state belonging to the KEDCO service is therefore characterized by inadequacy and un- zone are summarized in Table 10 and Table 11 below. predictability, adding further pressure on KEDCO’s The geospatial planning study found that: planning capacity and financial conditions (tariffs are currently adjusted to changes in the baseline zz KEDCO has approximately 400,000 customers with a 6 months’ time lag). who are billed, of whom about 160,000 are cur- It emerges that the utility, together with all the rently metered (Component A: costumers). other DISCOs, is still attempting to correct years zz Another 840,000 households are supplied with of under-investment and poor management of the electricity but are not metered and not registered industry by focusing on stabilising its business and as customers of KEDCO (Component B: con- generating cash flow for the establishment of a solid sumers). financial and electrical foundation for moving for- zz Combining the customers with the consumers, ward. It is therefore not immediately in a position, 1.24 million households are currently supplied Background to the Kano Service Zone and KEDCO 71 Table 10  Electricity access in 2015 and grid extension programme for the KEDCO service area, 2015–2030 Electricity access status (2015) Grid extension program (2015–2030)* Components of grid Total CAPEX Type Populationa program Populationa,b CAPEX per HH of (Type of grid access access (Households) Percent planned) (Households) Percent (M USD) (USD) Grid 7,430,000 31% A) Customers: 2,400,000 7% $40 $160 access KEDCO has ~400K customers (400,000) (2015); 63% need meters ($160/HH) (1,240,000) B) Consumers: 5,030,000 15% $150 $180 ~840K HHs (2015 est.) consume (840,000) power but do not pay KEDCO; all need meters & improved connections (~$180 per HH) No grid 16,480,000 69% C) LV intensification: 15,680,000 47% $1,670 $625 access By 2030, ~2.7 M HHs near the grid (2,670,000) will need LV line, meter, connection (~$630 per HH) (2,750,000) D) MV grid extension: 10,560,000 31% $1,470 $835 By 2030 ~1.8 M more distant HHs (1,760,000) (>1.5 km from transformer) will need MV and LV line, connection, meter (~$840 per HH) Total 23,910,000 100% Total 33,670,000 100% $3,330 $590 c (3,990,000) (5,670,000) Source: Earth Institute, 2015. a Based on census data, rural households have 6.1 persons on average vs. 5.8 for urban households. For simple computations and where the ratio of urban and rural households is unknown, 6 persons per household are assumed. b It is assumed that population growth from 2015–2030 among those who currently have grid access (components A and B) will lead to net formation of new households that will need new connections requiring LV intensification (component C), MV grid extension (component D). c Average household costs are calculated by summing all CAPEX costs across all program components and dividing by the total number of households served. *Least-cost grid coverage is 97 percent. Table 11   Technical summary for the LV intensification and MV extension components of the universal access programme for the KEDCO service area, 2015–2030 New generation needed Number household grid Grid length proposed (MW) for residential connections proposed (km) connections MV grid LV MV grid LV extension intensification extension intensification MV grid LV MV/HH State extension intensification MV LV (avg, m) LV Jigawa 510,000 482,400 6,600 15,200 12.9 13,200 120 120 Kano 640,000 1,523,200 5,600 18,700 8.7 34,800 170 400 Katsina 610,000 664,400 7,000 18,200 11.4 17,000 150 160 Sub-total 1,760,000 2,670,000 19,200 52,100 10.8 65,000 440 680 Total 4,430,000 136,300 1,120 Source: Earth Institute, 2015. 72 Background to the Kano Service Zone and KEDCO from KEDCO’s grid, whether paying for electric- (around 97%) the optimum electrification strategy ity or not (representing an electrification rate of by 2030 was found to be connection to the main around 31%). grid. The geospatial analysis also found that inten- zz Between now and 2030 some 2.7 million house- sification of LV lines is the biggest component (over holds that lie within 1.5 km of the existing grid 115,000 of the 136,000 km of new grid lines) of the could be connected without extending the MV electrification plan, with the potential of providing network. These would represent 45% of house- access to almost 70% of the population by 2030 (in- holds in 2030. At an estimated cost of US$630 cluding those already connected) for the KEDCO per connection, the total cost of this investment service area. This is illustrated in Figure 1. would be US$2.7 billion, or 90% of the overall The geospatial analysis indicates that only about cost of the electrification programme. The ma- 20% of public institutions (such as schools and clin- jority of this intensification will target Kano ics) are currently connected, although 80% of the state, the most urbanized state within the KED- most important ones, such as hospitals, already have CO service area. grid connections to the existing network. The least- zz Another 1.8 million households, or 30% of all cost plan also indicates that by the end of the grid- households in 2030, could be connected eco- electrification programme, about 94%20 of the exist- nomically by extending the MV network at an ing institutions will be connected. Two thirds of the average cost of US$840 per connection inclusive institutions could be reached via LV intensification of MV and LV costs. The total cost of this invest- only, whereas the rest would require MV extension. ment would be US$1.5 billion. This part of the Although connection to the grid is the least-cost electrification programme has been further sub- solution in the long-run for most of the popula- divided by the Earth Institute into five phases, tion, for those communities that are geographically with increasing distance and cost. About 70% remote and/or scattered clusters, off-grid solutions of the MV extension is targeted for Katsina and (mini-grids, SHS and small-scale solar lighting/ Jigawa, and the estimated MV line needed per charging products) are the most cost-efficient. The household is higher in these two states (11–13 m) geospatial analysis revealed that about 3% of the than in Kano (8–9 m). projected 2030 population will be best suited for off- zz For approximately 3% of households in the KED- grid solutions together with about 6% of the existing CO zone off-grid solutions would be the least-cost schools and clinic, as shown by Figure 2 (bottom). option by 2030, together with households and The largest component of the off-grid electrifica- communities which are targeted for grid connec- tion program potentially consists of households and tion in the latter part (beyond the medium-term) communities21 which are targeted for grid connec- of the MV grid extension plan for which transi- tions in the latter part (beyond the medium-term) tional arrangements should be developed. of the 15-year MV grid extension plan and thus zz The access rollout will add 5–5.5 million new will be required to wait potentially for several years residential customers with an incremental de- (5–10, if not longer) for electricity access. This could mand of about 1.1 GW, nearly 700 MW of which be a large group of beneficiaries, although, the size, is attributable to intensification, while the other target areas, cost and timing of a pre-electrification ~450 MW would result from MV grid expan- program will eventually also depend upon the ac- sion. It is assumed that each new KEDCO resi- tual implementation and sequencing of the rollout dential customer will add, on average, around plan. The electrification possibilities for such pre- 250–300 W of peak demand to the system (the electrification areas are described in Annex 4.3. weighted average is ~260 W). Grid-coordinated pre-electrification plans will have to be developed as transitional measures since The geospatial planning study conducted by the the grid is still the least-cost solution in the long- Earth Institute showed that there is a binary eco- run, while at the same time designed to protect in- nomic choice of electrification technology in the vestors’ businesses after the arrival of the grid. These KEDCO service zone. This choice is between grid pre-electrification transitional off-grid solutions electrification on the one hand and distributed could then become power supply back-ups and/or (mini-grid an off-grid) solar on the other. Because feed into the grid network. the majority of households lie within a short dis- A plan for off grid will have to be separately de- tance of the grid, for the majority of households veloped and will have to identify the role of sector Background to the Kano Service Zone and KEDCO 73 Figure 1   Map showing existing grid lines and LV intensification connecting 69% of the projected population (top) and the prioritized grid expansion plan based on average cost per household (bottom), 2015–2030 Source: Earth Institute, 2015. Note: Nigeria Electricity Access Program (NEAP) Final Report, Geospatial Least-Cost Implementation Plan for Grid and Off-Grid Rollout (2015–2030), October 2015. 74 Background to the Kano Service Zone and KEDCO Figure 2   Map showing social infrastructure (schools and clinics) planned for grid connection (2015–2030) (top) and beyond reach of existing and projected grid (2030) (bottom) Source: Earth Institute, 2015. Note: Nigeria Electricity Access Program (NEAP) Final Report, Geospatial Least-Cost Implementation Plan for Grid and Off-Grid Rollout (2015-2030), October 2015. Background to the Kano Service Zone and KEDCO 75 institutions, enabling policies and regulations, solar 12. This purchase was made with the proceeds of the market developments and service delivery ability NEMFS. The loans received by the Fund are ex- and modalities of interested and qualified providers. pected to be invested in metering and other key The off-grid plan will also identify Tier 1 and 2 elec- capital expenditures after paying upstream debts. tricity needs (see Annex 4.2), costs, commercially 13. World Bank estimates based on the MYTO model, viable investment opportunities, and financing pro- March 2016. spectuses to attract and syndicate funding from the 14. Arrears from the public administration, account- private sector, donors, and government institutions ing for about 3% of total collection losses, were (see also Chapter 6). also removed. As per NERC 2012 Regulation DIS- CO are not allowed to impose connection charges. 15. For KEDCO capex fell from US$23.5 million to Endnotes US$19 million. The capex allowance was reduced 1. 2006 Census, population.gov.ng. as DISCOs hadn’t made use of it (in the absence of 2. CIA World Factbook, 2015. Lagos has a popula- cost-reflective tariffs). See Also Annex 1. tion of 13.1 million. 16. The utility receives power from the Southern re- 3. World Bank, Updated Poverty Map of Nigeria, gions of the country, where power is produced. Gething and Molini, June 2015. 17. As per discussions with the utility. 4. This is a multidimensional definition of poverty 18. This report was drafted on the basis of the first adopted by the University. A person is identified findings of the geospatial analysis, indicating an as multidimensionally poor if they are deprived electrification rate of 33%, which was subsequent- in at least one third of the weighted indicators in- ly slightly changed the 31% in the final version of cluding child mortality, education, access to infra- the report. There were no major changes in the structure services, house size and assets. findings and in the year-to-year implementation. 5. 2006 Census, population.gov.ng. 19. The figures of 35-40% for grid electrification is 6. The 11th DISCO was privatised but subsequently taken from a draft Nigerian Electrification Ac- the private owner withdrew and it was taken back tion Plan prepared by the World Bank (September into government ownership. 2015). The overall electrification rate, including 7. The estimate of AT&C losses provided to bid- own-generation, was thought to be around 48% in ders at the time of privatisation was much lower 2011. The latter figure of 48% is from World Bank (around 28%) than the estimates revealed to the Energy Data Table indicators 2012 report. The fig- companies when they took over and gained full ure of 35-40% was derived from figures prepared access to the DISCOs’ records (around 50%). by NERC and the Bureau of Public Enterprise and 8. See, for example: www.nigeriaelectricityprivatisa- extrapolated to 2015. tion.com. 20. Among those that are not already connected to the 9. During the privatization process, bids were won KEDCO grid, 94% of all education facilities and all on the basis of the ATC&C loss reduction targets. health facilities fall within 1.5 km of the MV grid 10. World Bank estimates, May 2016. lines proposed to meet residential needs. 11. The baseline of losses integrated into the new 21. The total number of households or communities MYTO 2015 (implemented by NERC in February targeted for pre-electrification will depend upon 2016) reports 37.4% of collection losses, 6.8% of several factors that cannot be known at the time commercial and 13.5 of technical losses. Note that of this study, including the pace of grid expansion the aggregate ATC&C losses of 48.7% is not addi- year-to-year, and the total funds available for these tive but it is defined by a formula. additional electricity systems. CHAPTER 2 Indicative Electrification Programme The geospatial plan concentrated on the optimal subsidy to finance the capital investment require- strategy for the year 2030 but in the sections below ments (MV, LV and service connections), irrespec- we show two scenarios—a conservative and best tive of whether the distribution sector was privatised practice one—for the potential programme of con- or in public hands (see Chapter 4 for the financing of nections over the period leading up to 2030. The the capital costs of electrification programme). conservative scenario assumes that greater time is The regulatory framework and tariff design will need to allow improvements in the power market have to be tailored to the achievement of the goals and the regulatory framework to take place, and that set in the access policy. In particular, NERC will therefore it won’t be possible to achieve universal have to appropriately refine, expand and detail the electrification by 2030. The best-practice scenario is MYTO framework in support of the access pro- on the contrary consistent with the 2030 optimum gramme and update its oversight, review and veri- identified in the geospatial plan and reflects world- fication processes and mechanisms. Furthermore, wide best practice experience in ramping up the guidelines and regulations, including service stan- physical rollout with the quintuplication of access dards, appropriate for the coordination of grid and rates within three years and their tenfold increase off-grid efforts and for the development of an off- within five years.1 grid market, encompassing several service solutions Although expanded electrification is currently (mini-grids, SHSs and pico-solar, but also interim not KEDCO’s priority, with the right regulatory, and long-term solutions), will have to be designed. commercial and incentive framework, expanded The electrification targets for KEDCO and the electrification access should be an attractive option DISCOs will have to be designed by the Federal Min- for the company to grow its business and expand istry of Power (FMP) in coordination with the Office its customer basis. For this reason, the electrifica- of the Vice President through the Advisory Power tion program is assumed to commence to start in Team—currently responsible for advancing the 2018, allowing for a window to design the enabling power sector reform—in coordination with NERC policies and regulations for access rollout. The util- and the DISCOs, taking account of funding sources, ity could use this time to concentrate on reducing grants available, and the impact on end-user tariffs. losses and creating proper customer databases and The targets will be firm for the initial periods, typi- billing systems and both the utility and the private cally five-year periods to coincide with the multi- sector could develop the capacity required by an year tariff formulae, and indicative beyond that. electrification program. In addition, the preparatory phase should be Particularly key during the preparatory time up used by KEDCO to strengthen its organizational to 2018 will be the adoption of a National Univer- and functional capacities to implement the access sal Access Policy (see also Section 3.1). The strategic scale up program particularly in relations to plan- document will have to define the roles and respon- ning, design, procurement, construction manage- sibilities of sector institutions and include targets for ment, contracting, materials management, qual- annual connections coupled with monitoring in- ity and standards. In parallel to the access rollout, struments and funding mechanisms, including from KEDCO would also have to continue to further re- public sources. In fact, no country has achieved uni- duce technical and commercial losses and strength- versal electricity access without some form of public en its financial stance. 77 78 Indicative Electrification Programme The two scenarios presented differ in the tra- technical assistance to enable the programme to be jectory of the year-to-year implementation of the accelerated (discussed in Section 2.3). physical on-grid programme in terms of number Table 12 below shows the year-to-year imple- of connections implemented per year, speed and mentation profile and the corresponding access acceleration. They also differ in the underlying ex- achieved by the two trajectories. pectations on improvements in key constraining/in- In the conservative scenario the on-grid elec- hibiting factors, in particular: bulk supply adequacy, trification would begin cautiously with 30,000 new quality of enabling policy framework, support from connections in 2018 rising to nearly 200,000 con- the regulatory framework for retail tariffs consistent nections in 2023 and cumulatively over this period with the universal access policy, and provisions and a total of nearly 550,000 new connections would mechanisms for public funding to bridge the capi- have been made. The electrification rate would still tal expenditure financing gap (discussed in Chap- be a relatively modest 37% at the end of 2023 (62% ter 4). The best-practice scenario requires a sig- for institutions), compared with 31% today, but nificantly greater commitment from all parties to a this would be the foundation for of a much more programme of full electrification by the target date rapid electrification rate over the subsequent years of 2030 and for these reasons would require more with an annual electrification rate of up to 500,000 Table 12  Electricity access rollout programme (2018–2030)a Access rollout 2018–2030 2015 (baseline): Conservative scenario Best-practice scenario Grid Institutions Institutions Grid Institutions Institutions connections: Grid access connected: access rate: connections: Grid access connected: access rate: 1.24 mn. rate: 33% 3,350 21% 1.24 mn. rate: 33% 3,350 21% New New New New connections Progressive Institutions Progressive connections Progressive Institutions Progressive (‘000) access rate connected: access rate (‘000) access rate connected: access rate (%) (‘000) (%) (%) (‘000) (%) 2018 30.0 31% 600 25% 50.0 31% 600 25% 2019 40.0 31% 800 29% 75.0 32% 800 29% 2020 50.0 31% 1,100 36% 125.0 34% 1,100 36% 2021 93.0 32% 1,300 44% 200.0 37% 1,300 44% 2022 137.0 34% 1,400 53% 275.0 42% 2,050 57% 2023 198.0 37% 1,417 62% 375.0 48% 2,878 75% Total additions 548.0 6,617 1,100.0 8,728 2018–2023 Total 1788.0 37% 9,967 62% 2,340.0 48% 12,078 75% connections by 2023 Total 3,200.0 5,153 3,360.0 3,032 connections added 2024–2030 Total 4,988.0 83% 15,120 94% 5,700.0 95% 15,110 94% connectionsv by 2030 a Note, the electrification rate declines between 2015 and 2018 because, despite some electrification in 2018, this has not kept pace with the growth in the number of households. The same is not true of social institutions where the total number of institutions is assumed to be fixed (instead the size of the schools and clinics grow as the population grows). Indicative Electrification Programme 79 per year and ultimately bringing the electrification Figure 3   Conservative grid electrification programme rate to 83% by 2030 (94% for social and adminis- for KEDCO trative institutions). In the first two phases of the programme (up to 2023), an investment financing 7 90% Number of households (millions) requirement of US$362 million would be necessary 6 80% for grid electrification and the estimated increase in Grid electrification rate 70% 5 demand is of 128MW. 60% In the best-practice scenario the on-grid elec- 4 50% trification would again begin relatively cautiously 3 40% with 50,000 new connections in 2018 rising to 30% 375,000 connections in 2023 and cumulatively over 2 20% this period a total of nearly 1.1 million new connec- 1 10% tions would have been made. The electrification rate 0 0 would still be nearly 50% at the end of 2023 (75% for 2016 2018 2020 2022 2024 2026 2028 2030 the institutions). Over the subsequent years the an- Existing 2015 consumers Connections within 1.5km Connections beyond 1.5km nual electrification rate of up to 500,000 per year and Non-grid electricity Without electricity Grid electrification rate ultimately bringing the electrification rate to 95% by 2030 (94% for social and administrative institu- tions). In the first two phases of the programme for KEDCO (again, up to 2023), an investment financ- power back-up solutions. The off-grid programme is ing requirement of just over US$731million would separately discussed in Chapter 6. be necessary for grid electrification and the estimat- ed increase in demand is of 257MW. From a physical implementation perspective, the 2.1 Conservative Grid two scenario differ as the conservative one is rela- tively less focused on MV extension (US$ 680 mil- Electrification Scenario lion) for the whole duration of the programme (up The conservative electrification trajectory for KED- to 2030), and the investments are mostly directed to CO is depicted in Figure 3 below, with the electri- the construction of LV lines (US$ 1.7 billion). In the fication rate starting at 33%2 in 2015 and reaching best-practice scenario, investments in LV lines are 82% by 2030. coupled with more investments in MV extension Specifically, there are an estimated 1.24 million (US$ 1.5 billion), which are pursued more aggres- households in the KEDCO service zone with an elec- sively in time (starting in 2020 instead of 2021) and tricity connection (though not all are registered and size (1,800 new connections versus 1,000 in the con- billed). At the early stages of the electrification pro- servative scenario), and the main reason underpin- gram, the grid electrification rate dips somewhat (from ning bigger achievements in access by 2030. 33% to 31%) reflecting KEDCO ‘s focus on building its An off-grid electrification part of the programme business (from customer enumeration and service to would include pre-electrification communities that system automation) and the number of connections would otherwise wait several years for grid access. fails to keep pace with population growth. These areas are targeted for grid connections in the The access scale-up program in the KEDCO ser- latter part (beyond the medium-term) of the 15-year vice zone is assumed to begin in 2018 with some MV grid extension plan and would otherwise be relatively small-scale intensification programme required to wait potentially for several years (5–10 (within 1.5 km of the existing grid) that begins to years) for electricity access. Specific electrification build KEDCO’s capacity and that of the private technologies would be evaluated and selected—from supply chains and contractors to undertake electri- options such as solar home systems and diesel or hy- fication. As also shown by Table 13, this lasts for a brid mini-grids—during a more detailed program period of three years by which time an additional design. A second group of off-grid electrification 120,000 new intensification connections are as- would provide non-grid solutions to areas where grid sumed to have been added by the end of 2020. The is not the recommended least-cost option within the programme then begins to move into a more serious period covered by the electrification programme. gear, with a target of one million intensification con- Finally, off-grid technologies could provide efficient nections by 2025 and 2.7 million by 2030. 80 Indicative Electrification Programme Table 13  Conservative grid electrification programme HH units 2015 2018 2023 2030 Existing 2015 KEDCO consumers mn. 1.24 1.24 1.24 1.24 New intensification connections a mn. 0.00 0.03 0.43 2.70 New connections w/MV extensions b mn. 0.00 0.00 0.12 1.00 Total KEDCO grid connections mn. 1.24 1.27 1.79 4.94 Grid electrification rate (HHs) 33% 31% 37% 83% Total households in the KEDCO zone mn. 3.80 4.16 4.85 6.00 a Defined as less than 1.5 km or less away from the existing grid. b Greater than 1.5 km away from the existing grid. As the MV grid extends outwards, households will be closer to the grid but they are still included in the ‘MV extension’ category. The MV grid extension programme begins in anticipated by NERC in its guidance to the DISCOs.3 2021 in this programme with the same broad ap- Some of this capital expenditure might be concession- proach of building capacity over the first three years al financed, as discussed in Chapter 4, but there will and then ramping up the rate of electrification to be nevertheless a need for some capital expenditure to reach one million connections by 2030. Contrary to be financed by KEDCO and this implies the need for a what envisaged in the geospatial plan, in the con- revision to MYTO before the electrification program servative scenario KEDCO will not connect all 1.8 is launched in the KEDCO service zone. million potential connections involving MV exten- The financing of the conservative electrification sions by 2030, but the electrification rate reaches program and related financing gap are discussed in only 82% by 2030, with the remaining section of the Chapter 4. population for which grid connection is the least- cost solution to be electrified after 2030. Increment of demand on the main 2.1.2  grid from the conservative 2.1.1  Capital costs – grid electrification electrification program conservative scenario Household electricity demand is calculated by the The capital cost associated with the KEDCO grid Earth Institute in the geospatial planning study at electrification programme is estimated at US$2.5 200 Watts per household for poor households and billion. As indicated in Table 14 below, the electri- 400 Watts for others.4 The aggregate peak demand fication program starts with an investment cost for associated with the electrification programme de- the first five years (2018–2023) of US$362 million scribed above is shown in Table 15 below and is cal- whereas the subsequent 7-year time slice shows a culated using these household demand parameters.5 gradual ramping up of the program, with US$2.2 billion in the period 2024–2030. 2.2 Best-practice electrification Although the investment needs for the first five years of the electrification program are relatively mod- programme est, they have not been anticipated in KEDCO’s tariff The best-practice electrification trajectory for KED- (MYTO) approved in February 2016 and they repre- CO is depicted in Figure 4. The scenario also starts sent a substantial increase on the capital expenditure with an electrification rate of 33% in 2015, but as- Table 14   Capital cost of the KEDCO grid electrification programme (conservative) Units 2018–23 2024–30 2018–2030 New intensification connections US$ mn. 270 1,431 1,711 New connections with MV extension US$ mn. 92 724 816 Total US$ mn. 362 2,155 2,517 Indicative Electrification Programme 81 Table 15  Increased grid load associated with the conservative roll-out program Units 2018 2023 2030 Energy demand (sales) from new connections a GWh 0 385 2,814 Maximum demand from new connections MW 0 128 938 a Excluding technical losses. The energy needed from the wholesale market will be higher after taking account of network losses. Table 16  Best-practice grid electrification programme HH units 2015 2018 2019 2020 2021 2022 2023 2030 Existing 2015 KEDCO consumers mn. 1.24 1.24 1.24 1.24 New intensification connections mn. 0.00 0.05 0.85 2.70 New connections w/MV extensions mn. 0.00 0.00 0.25 1.80 Total KEDCO grid connections mn. 1.24 1.29 2.34 5.74 Grid electrification rate (HHs) 33% 31% 48% 97% Total households in the KEDCO zone mn. 3.80 4.16 4.85 6.00 sumes that Nigeria achieves the full electrification The subsequent 7-year time slice shows a gradual plan laid out in the geospatial analysis with 97% ramping up of the programme, with US$ 2.5 billion electrification by 2030. in the period 2024–30. The best-practice scenario shown in Figure 4 Since the cost of an electrification program has also starts with an estimated 1.24 million house- not been anticipated in MYTO, the implementation holds in the KEDCO service zone with an electric- of the best-practice scenario would also require a re- ity connection (including unregistered and unbilled examination by NERC of the tariffs to finance capi- connections). tal expenditure, even in the event of available grants The electrification program in the KEDCO ser- and concessionary financing. vice zone is also assumed to begin in 2018 with an The financing of the best-practice electrification intensification programme (within 1.5 km of the ex- program and related financing gap are discussed in isting grid) that begins to build KEDCO’s capacity Chapter 4. and that of the private supply chains and contractors to undertake electrification. As shown in Table 16, however, by 2023 it is assumed that KEDCO con- nects 1.1 million new households, both with in- Figure 4  Best-practice grid electrification programme tensification and grid extension, to its electricity for KEDCO grid bringing the grid electrification rate to 48% 7 120% (compared with 37% in the conservative scenario). Number of households (millions) 6 Thereafter, in the period 2024 to 2030, a further 3 100% Grid electrification rate million households would be connected through 5 80% the program. 4 60% Capital costs – grid electrification 2.2.1  3 best-practice scenario 2 40% The capital cost associated with the KEDCO best- 1 20% practice electrification programme is estimated at US$3.2 billion. As shown in Table 17 below, similarly 0 0 to the conservative scenario, the program estimates 2016 2018 2020 2022 2024 2026 2028 2030 a relatively slow build-up of investment cost for the Existing 2015 consumers Connections within 1.5km Connections beyond 1.5km first period, with of US$ 731 million in 2018–2023. Non-grid electricity Without electricity Grid electrification rate 82 Indicative Electrification Programme Table 17  Capital cost of the KEDCO grid electrification programme Units 2018–23 2024–30 2018–2030 New intensification connections US$ mn. 536 1,166 1,702 New connections with MV extension US$ mn. 195 1,314 1,509 Total US$ mn. 731 2,480 3,211 Increment of demand on the main 2.2.2  limited human, material and technical resources grid from the best-practice for undertaking a major programme of connecting electrification program customers through intensification or grid extension, Electricity demand in this scenario is calculated in whether implemented with a conservative or best- the same way as the conservative scenario, as de- practice trajectory. In fact, KEDCO accepts that to scribed above. The demand is summarised below. a large extent the electrification work will need to be contracted out to the private sector (both grid and off-grid). The utility will therefore need capac- 2.3 Capacity Strengthening ity building to supervise and manage a major elec- Technical assistance directed to key sector institu- trification programme. As shown in Table 19, most tion and agents is envisaged for the acquisition of of the technical assistance proposed for KEDCO the capacity required for the physical implementa- would be directed towards supporting the utility’s tion of the access rollout and for the design and es- planning capacity. Overall, the best-practice scenar- tablishment of the enabling policy, legislations, and io will require more technical assistance (from US$4 regulatory instruments that would set the stage for million in the conservative scenario to US$5.5 mil- and ensure the successful execution of the electrifi- lion) to enable the access programme to be acceler- cation programme. Although some support should ated, with greater resources allocated to manage the be directed toward the achievement of the key ac- programme and to improve more quickly KEDCO’s tions to be undertaken in the phase preliminary to in-house capacity to plan, operate and manage an the access rollout (described in Table 4), capacity expanded network. strengthening will be needed on an ongoing basis The private sector in North West Nigeria is ex- during the implementation phase as the programme perienced in undertaking electrification works,6 expands and accelerates. though not on the scale necessary to achieve the A proposed technical assistance programme for electrification roll-out required for KEDCO and the capacity strengthening is described in Table 18 be- work force will need to be expanded. Training and low. The programme is indicative, as the detailed capacity strengthening can readily address this limi- scoping and its quantification will ultimately be de- tation capacity to the physical programme rollout. fined by the more specific actions that KEDCO, the The Industrial Training Fund is currently used for private sector and the FGN will decide to undertake training engineers and technicians for more complex to close the gaps and solve the ambiguities related to equipment and processes. In the electricity sector, the policy and regulatory framework and to the role a wide range of training and services are currently of public finance within the programme. provided by the National Power Training Institute of The utility has currently limited experience in Nigeria (NAPTIN)7 under contract to the electricity extending electricity grids on any scale, and it has companies and the Institute could be expanded to Table 18  Increased grid load associated with the best-practice roll-out program Units 2018 2023 2030 Energy demand (sales) from new connectionsa GWh 35 770 3,540 Maximum demand from new connections MW 12 257 1,180 a Excluding technical losses. The energy needed from the wholesale market will be higher after taking account of network losses. Indicative Electrification Programme 83 Table 19  Technical assistance (TA) programme (present–2023) – US$ million Beneficiary Measures Conservative Best-practice KEDCO Planning (yearly program), tendering, management, supervision 2.5 3.0 Strengthening of standard equipment specification, policies & 0.5 0.5 procedures, procurement, mains records (location of plant) Customer Relationship Management 1.0 2.0 Off-grid electrification assessment 0.5 0.5 Sub-total 4.0 5.5 Ministry of Power Planning, training for private contractors a 5.3 8.0 other activities Private manufacturers Technical assistance to ensure manufacturing processes are up to 1.0 2.0 standard NERCb To be detailed REA c To be detailed Monitoring & evaluation 0.2 0.2 Ministry of Finance To be detailed Total 11.0 16.2 a This could be provided through NAPTIN, the electricity training institute based just outside of Kano. b The Nigeria Electricity Regulatory Commission is the regulator. c Rural Electrification Agency. provide the training necessary to enable the rollout for the monitoring and evaluation of the program is of the electrification programme (linesmen, fitters, currently quite small (US$200,000), this would be jointers, etc.).8 The facility might also provide train- one of the most expensive but key activities of the ing suited to the development of isolated grids and access programme, to be detailed hand in hand with solar home systems. The best-practice scenario sees the access policy. a 50% increase (from US$5 million in the conserva- On the off-grid side, capacity strengthening tive scenario to US$8 million) in the technical assis- will be needed to develop the rules and regulations tance needed to fast-track the training of linesmen, governing the off-grid market and to define roles fitters and jointers through the Ministry of Power of responsibilities of sector stakeholders, including (NAPTIN) and the doubling of the technical assis- private and public actors. Since the role of Rural tance (from US$1 to US$2 million) needed to bring Electrification Agency needs to be re-defined in the private manufacturing processes up to standard for a new sector structure, tailored technical assistance large-scale programme. will have to be detailed accordingly. The distribution Finally, power sector institutions may also need companies may also have an interest in participating some technical assistance for the development of na- in the off-grid rollout (see also Chapter 6). tion-wide access policy, coordinating grid and off- grid solutions—with targets and timetables on par with international best practices and supported by a Endnotes legislative and regulatory enabling environment en- 1. See, for instance, the successful experiences of suring the financial viability of the programme for Indonesia, Kenya, Tunisia, Morocco, Laos, Thai- the DISCOs and affordability of electricity services land, Vietnam and Rwanda. for consumers. Combined with training of private 2. This report was drafted on the basis of the first contractors, support to increase the planning capac- findings of the geospatial analysis, indicating an ity of the Ministry of Power is envisaged as the area electrification rate of 33%, which was subsequent- mostly in need of capacity strengthening (with US$5 ly slightly changed the 31% in the final version of million in the conservative scenario and US$8 mil- the report. There were no major changes in the lion in the best-practice one). Although the support findings and in the year-to-year implementation. 84 Indicative Electrification Programme 3. US$ 120 million over the five-year period, or jection assumes that some households migrate to US$24 million per year. higher consumption bands after a time. 4. The classification of households was based on a 6. Private contractors typically provide in-house geospatial poverty mapping study undertaken by training for linesmen, fitters, jointers, etc. Oxford University on behalf of the World Bank. 7. NAPTIN was formerly part of the Power Hold- 5. The household demand is understood to be the ing Company of Nigeria (PHCN) but is currently coincident, after-diversity maximum demand (i.e., owned by the Federal Government of Nigeria the contribution to the aggregate peak demand of (FGN). KEDCO). We assume this takes account of net- 8. A facility already exists on the outskirts of Kano work losses (i.e., is measured at the bulk supply city and although equipped with modern equip- point entering the KEDCO grid). If the demand ment, it does not currently provide training in the parameters are non-coincident or before diversity, skills needed for the expansion of the distribution the aggregate demand would be lower. The pro- network. CHAPTER 3 The Role of the Policy Maker and Regulator The current institutional framework for policy mak- Policy making Regulation Separation of ing, regulation, delivery and financing in the elec- Federal Ministry of Power – Nigerian Electricity regulation and Department of Distribution tricity distribution sector is depicted in the figure on and Advisory Power Team Regulatory Commission policy making (NERC) the right. of the Vice President Office The Federal Ministry of Power (FMP), in coordi- Distribution planning, construction, nation with the Advisory Power Team of the Office operation and supply Crossing State of the Vice President (currently responsible for ad- Eleven privately owned Distribution Companies (DISCOs) boundaries vancing the power sector reform), is the policy mak- ing arm of the Federal Government. NERC is the Distribution planning and regulator and determines tariffs and allowed rev- construction; grid & isolated grids Federal agency enues for the DISCOs based on principles laid out Rural Electrification Agency (REA) in the primary law. NERC also ensures that Federal Government policy is appropriately implemented. Distribution planning and construction, grid and isolated grids State level The Rural Electrification Agency (REA) and the agencies Rural Electrification Boards (REBs) have, in the past, 36 x Rural Electrification Boards (REBs) both had the primary function of supporting the former Federal-owned and vertically integrated elec- tricity company1 to develop electricity grids in rural areas and to then connect them to the national grid policy explicitly specified a target for electrification to be owned and operated by the electricity company. to increase to 75% by 2020 towards the achievement When the electricity supply chain was Govern- of universal access by 2030.2 However, these targets ment-owned, the roles of REA and the REBs in help- were established when the electricity sector was ful- ing develop distribution networks were clear but ly state-owned and before privatisation plans were post-privatisation they need to be revised and prop- introduced in 2005 with the Electric Power Sector erly designed and harmonized with the remit and Reform Act and were not actively pursued. mandate of DISCOs throughout their service areas. The NEPP electrification targets were designed The following Section 3.1 discusses the need for to help prioritise actions by the Federal and State an access policy and electrification targets to be ad- Governments, donors, REA and REBs and to help opted by FMP, the role of NERC in allowing the re- identify funding needs, but they were not actively covery of costs in electrification incurred by the DIS- pursued. They are not firm targets with financial COs, in incentivising the electrification programme, penalties or rewards for the DISCOs nor a monitor- and in making provisions for cross-subsidisation. ing and oversight system was ever set in place. In 2010, the Federal Government of Nigeria initi- A National Policy for 3.1  ated a bold power sector reform program encompass- ing the entire value chain with the launching of the Universal Access Power Sector Reform Roadmap. The Roadmap op- The 2001 National Electric Power Policy (NEPP) is erationalized the 2001 National Electric Power Policy still the operational policy issued by the FGN. The and the 2005 Electric Power Sector Reform (EPSR) 85 86 The Role of the Policy Maker and Regulator Act. The Road Map, subtitled “A Customer Driven tial periods, typically five-year periods to coincide Sector-Wide Plan to Achieve Stable Power Supply”, with the multi-year tariff formulae, and indicative stemmed from the acknowledgment of consumers’ beyond that. frustration for unreliable and/or absence of electric- Access targets will have to be designed and con- ity services. While achieving many of the goals set in cretely pursued. The targets are necessary because the Roadmap, including the completion of the priva- there is currently no licence obligation to connect tization process,3 the reform didn’t detail targets and customers on demand and because, for affordability timetables for electricity access enhancement, nor the reasons, there is a need for cross subsidies between role of the FGN in a mostly privatized setting. customer groups. Cross-subsidisation means that A necessary pre-requisite for any meaning- the DISCOs will be incentivised to maximise sales ful and sustainable start of an electrification pro- to the non-subsidised customers and to minimise gramme, is for FGN to adopt a National Universal the connection of subsidised customers. Access Policy, encompassing much more than a The targets will have to have a concrete function statement of vision. The revision of the 2001 NEPP in helping to identify investment expectations in should be tailored to the sector structure presently the multi-year tariff orders (issued by NERC) and in place and include specific access targets accom- to provide incentives (penalties and rewards) for panied by enabling policies. As demonstrated by DISCOs for failing or succeeding in achieving the international best practice experiences, no country targets—again to be monitored and implemented by has achieved universal access without a strong gov- NERC. ernment commitment, vision and policy, whether The electrification investments and the targets in a privatized power sector setting or in a state- will need to be established based on discussions owned one.4 between FMP, NERC and the DISCOs. The MYTO The National Universal Access Policy should ad- should be revised reflect the cost of investments in dress clearly the full range of enabling policy mea- electrification and the DISCOs should be held to sures and drivers necessary to facilitate the DISCOs account in achieving the electrification targets im- in scaling up electricity access in a systematic and plied by the investment programme. NERC should comprehensive manner for provision of adequate, also appropriately update its oversight, review and affordable and reliable access to all residents. The verification processes and mechanisms to play Policy should also define the roles, mandates and its due role in support of the electrification pro- accountabilities of sector institutions (including at gramme. the local levels) and stakeholders, and include tar- To the extent that NERC regulated tariffs, com- gets for grid annual connections and off-grid devel- bined with other revenue resources potentially opments coupled with monitoring instruments and available to the utilities (e.g. equity) do not allow funding mechanisms, including from public sourc- for a complete recovery of the capital expenditure es. The regulatory framework and tariff design will required by the access scale-up programme, the have to be tailored to the achievement of the goals Policy would also need to identify the means and set in the access policy; and guidelines and regula- mechanisms for providing public funds to bridge tions, including service standards, appropriate for the financing gap. In fact, no country has success- the coordination of grid and off-grid efforts and for fully achieved universal or well-advanced degree of the development of an off-grid market, encompass- electricity access without a strong financial commit- ing several service solutions (mini-grids, SHSs and ment from the Government, even in a privatized pico-solar, and interim and long-term provisions), setting (see also Chapter 4). will have to be designed. The discussion between FMP, NERC and the The Policy and the electrification targets for DISCO will then centre around the utilities’ busi- KEDCO and the other DISCOs will have to be de- ness plans, financial projections and financing termined by the Federal Ministry of Power (FMP) needs (for investment in all aspects of their busi- with the Office of the Vice President through the ness—not only for electrification) and grants and Advisory Power Team—currently responsible for concessionary funding available to the DISCOs and advancing the power sector reform—in coordina- the implications, positive or negative, for end-user tion with NERC and the DISCOs, taking account of tariffs. More specifically, NERC will have to oversee funding sources, grants available, and the impact on the balance between DISCOs financial viability on end-user tariffs. The targets will be firm for the ini- the one hand, and of affordability on the other. The Role of the Policy Maker and Regulator 87 Endnotes were established to facilitate private investments in power generation. A management contractor was 1. Until 2005 this was the Nigerian Electric Power brought in for the Transmission Company of Nige- Authority (NEPA) and between 2005 and 2013 ria (TCN) and an independent regulator (Nigerian it was the Power Holding Company of Nigeria Electricity Regulatory Commission, NERC) was (PHCN). established. By early 2015, in accordance with the 2. The 2006, Rural Electrification Strategy and Im- newly established market-based rules, the major- plementation Plan, developed by econ ONE for ity of the PHCN successor companies had signed the Bureau of Public Enterprise mentions a policy power trading contracts with NBET and NERC had of universal access to electricity by 2040. We have adopted and revised the ‘Multi-Year Tariff Order’ not obtained a copy of the original NEPP. (MYTO) to cost-reflective levels. 3. Under the reform program, PHCN was unbundled 4. Best practices include the ones of Vietnam, Thai- and privatized into eleven distribution and six gen- land, Lao PDR, Kenya Rwanda, Tunisia and Mo- eration companies (40 percent of shares are owned rocco. For more information, see also Independent by the FGN), and the Gas Aggregator Company of Evaluation Group (2015), “World Bank Group Nigeria (GACN) and a bulk power trading company Support to Electricity Access, FY2000-2014. An (Nigeria Bulk Electricity Trading Company, NBET) Independent Evaluation”, Washington D.C. CHAPTER 4 Financing and Implementation of the Access Program KEDCO was privatised at the end of 2013 and has formance Agreement and Business Plan submitted been in operation for two full financial years—2014 at the time of privatization,2 which entered into force and 2015. During the first of those two years, the in January 2015 (one year after the completion of company slowly began to piece together a set of fi- the privatization process) when cost-reflective tariffs nancial statement but a set of audited accounts for where firs adopted (but abandoned in April 2015).3 2014 and 2015 were not available at the time of this The projections show improvements in KED- report.1 After privatization, the DISCOs have no CO’s future financial performance. The Table shows obligation to publish their financial statements, but a rapid growth in electricity sold, in part because of the absence of accounts or financial data is itself an a halving of technical and commercial losses from indication of poor financial health. 18% in 2015 to 9% in 2021. However, the growth The most recent and available estimated of KED- is primarily due to an expected increase in electric- CO’s historical accounts, and projections of its future ity available from the national grid and a resulting financial performance were submitted by the utility increase in electricity sales to customers with an (on request of NERC) for the definition for MYTO underlying growth rate of 10% per annum. At the 2015. Some of the highlights are provided in Table same time, the company is expected to reduce its 20 below. The estimates incorporate the loss reduc- collection losses from nearly 33% in 2015 to 6.3% tion targets that KEDCO committed to in the Per- by 2020. These improvements are designed to allow Table 20  KEDCO’s past and forecast financial position 2014 2015 2016 2017 2018 2019 2020 2021 Electricity purchased wholesale (GWh) 3,142 2,414 3,091 4,132 5,213 6,110 6,644 7,374 Losses (technical and commercial – % of purchased) 18.1% 18.1% 17.5% 15.1% 12.1% 10.0% 9.1% 9.1% Sales (GWh billed) 2,573 1,977 2,549 3,530 4,602 5,512 6,054 6,719 Growth in sales (%) 7% –23% 29% 38% 30% 20% 10% 11% Average tariff (NGN/ kWh) 31.70 45.04 36.27 30.24 27.65 25.80 25.09 25.18 Revenues (billed – NGN million) 81,567 89,058 92,472 106,753 127,272 142,197 151,911 169,144 Collection losses (%) 37.4% 32.8% 25.1% 17.4% 11.7% 8.2% 6.3% 6.3% Revenues collected (NGN million) 51,094 59,872 69,289 88,207 112,347 130,491 142,344 158,492 Bulk electricity costs (NGN million) 39,058 38,765 54,028 71,582 94,399 110,936 121,241 135,986 Operating costs incl. depreciation (NGN million) 8,438 8,897 9,416 10,073 10,772 11,514 12,340 13,170 Earnings before interest and tax (EBIT) (NGN million) 3,598 12,211 5,846 6,552 7,176 8,040 8,762 9,336 Return on regulated asset base (RAB) 9.7% 24.4% 11.2% 11.8% 12.3% 13.1% 13.5% 13.7% Allowed return on RAB 11.0% 11.0% 11.0% 11.0% 11.0% 11.0% 11.0% 11.0% Source: KEDCO’s submission to NERC for MYTO 2015 (December 2015). 89 90 Financing and Implementation of the Access Program the average tariffs to fall from NGN 36.3 (US$ 0.18 jected investments for US$13 million in meter- cents) per kWh in 2015 in 2015 by nearly one third ing, but the average price per meter modelled was to around NGN 25 (US$ 0.12 cents) in 2020. of about US$27,7 whereas current estimates are of However, the fulfilling of the financial projec- US$160,8 not lastly because the company decided to tions is hindered some of the underpinnings of deploy smart meters only. Furthermore, the geospa- KEDCO ’s Business Plan and by developments in tial analysis disclosed that approximately 1.5 million the power sector after the completion of the privati- households would need a meter, in order to achieve zation process, including recent power supply issues the target of 100% metering in five years as set in due to militant pipeline attacks. the Performance Agreement, a target 65% bigger in In fact, the ATC&C loss reduction targets sub- numbers of households than what detailed in the mitted at privatization (upon which bids were won Business Plan (which targeted the deployment of and now integrated into MYTO 2015) and the cor- 512,164 meters).9 responding investment needs (shown in Table 21 The new MYTO 2015 also removed losses com- below) were designed to be consistent with the capi- ing from MDAs non-payments from the ACT&C tal expenditure allowance contained in the MYTO figures contained in the tariffs, which in the case model at the time of privatization, allowance that of KEDCO accounts for about 3% of the overall was decreased by 20% in MYTO 2015.4 The decision losses.10 Because of the delay in the adoption of was taken by NERC because DISCOs had made no cost-reflective tariffs (two years after completion of use of the capital expenditure allowance they had. the privatization process) and the removal of FGN The only significant loss reduction capital expen- arrears from collection losses, the DISCOs are cur- diture made by KEDCO after privatization was the rently negotiating with BPE and NERC a re-sculpt- purchase of 64,000 meters at the beginning of 2016 ing of the over the next five years of the targets, with the proceeds of the Nigeria Electricity Market which is further delaying their implementation. Stabilization Fund (NEMSF), entity established by Furthermore, the achievement of KEDCO’s fi- the FGN to provide loans through the Central Bank nancial projections is hampered by the deficit that of Nigeria (CBN) to finance the losses accumulated all DISCOs have been accumulating since privati- by the DISCOs after privatization. However, the ab- zation. In aggregate, DISCOs have only been able sence of loss reduction investments by KEDCO and to pay for around 70% of the electricity purchased other DISCOs was also due to their inability to justi- from NBET11 and by the end of 2015 their accumu- fy the borrowing needed to fund capital expenditure lated arrears had amounted to nearly US$2 billion.12 in the absence of cost-reflective tariffs.5 Although figures on the deficit accumulated by Although ATC&C losses were assessed and vali- KEDCO since privatization are not publicly avail- dated only after privatization,6 and incorporated able, KEDCO is estimated to have accumulated into the last round of MYTO revision, a throughout US$140 million since privatization.13 The utility has and bottom-up assessment of the utility’s invest- been significantly underperforming with regards to it ment needs hasn’t been conducted yet. For instance, payments for energy received from generation com- as shown in Table 12 above, the Business Plan pro- panies and in 2015 was only able to pay 40% on aver- age of NBET invoices (see also Annex 1). The com- pany also received US$38 million in the first quarter of 2015 from the Nigeria Electricity Market Stabiliza- Table 21   Summary of KEDCO’s non-access investment tion Fund (NEMSF)14 as loans funded by the Central requirements (US$ million) Bank of Nigeria (CBN) to pay upstream debtors.15 Year Metering Loss reduction Other Total In addition, to manage the increase in tariffs for end consumers, the new MYTO 2015 implemented 2015 3.8 2.4 18.8 25.0 in February 2016 was designed to smooth the tariff 2016 4.7 1.0 15.7 21.5 path by allowing under-recovery of revenues initially 2017 1.2 8.8 13.2 23.2 and over-recover in later years over a ten-year period. 2018 1.5 13.5 14.1 29.1 For the whole sector, this is expected to lead to an increase in the DISCOs’ collective deficit to nearly 2019 1.8 18.0 0.6 20.5 US$ 3 billion by the end of 2016,16 corresponding to Total 13.1 43.8 62.4 119.3 an under-recovery of 16% of expected total revenues. Source: KEDCO Business Plan, 2012 (entered into force in January 2015). KEDCO is expected (by MYTO) to have fully cost- Financing and Implementation of the Access Program 91 recovery tariffs (i.e. no under-recovery) by the begin- DISCOs, such that the companies should earn rev- ning of 2018, when it is therefore also expected to enues that cover their costs and provide a reasonable stop accumulating deficits. Until then, KEDCO will market return on capital invested. For the DISCOs, not be able to recover its operating costs and will only any investment they make in the expansion of elec- be able to undertake minor capital expenditures. tricity access would therefore need to be undertaken The achievement of the targets set out in the on a commercial basis. Business Plan and reflected in MYTO 2015 would The current owners of the DISCOs largely fi- also be difficult as Nigerian commercial banks are nanced the acquisitions of the companies with loans currently unwilling to finance the DISCOs’ invest- securitised against the parent companies’ assets, not ments or to finance revenue shortfalls when secu- against the DISCOs’ own profits. As Nigerian com- ritised against the DISCOs’ revenues on terms that mercial banks are currently unwilling to finance the are consistent with the MYTO allowed revenue DISCOs’ investments or to finance revenue short- formula. Commercial banks are not familiar with falls when securitized against the DISCO’s revenues the distribution segment of the power sector nor on terms that are consistent with the MYTO allowed have yet developed long-term lending instruments formula, any major borrowing on commercial terms necessary for infrastructure development. Borrow- on any scale to expand the network is unlikely over ing by the DISCOs on commercial terms to finance the first phase (2018–2023) of the electrification ac- investments that are needed to create a stable plat- cess programme. As noted, borrowing to finance form to supply their existing customers is currently investments that are needed to reduce losses and already problematic.17 create a stable platform to supply their existing cus- Finally, the projected 10% increase in sales will tomers is already problematic.20 Furthermore, given also be affected by power availability,18 which is cur- the scale of the of the required investment, it would rently hampered by transmission constraints and be a challenge to secure substantial commercial more recently by a resurgence of militant attacks in funding for the initial six-year period to cover the the producing regions of Nigeria. The utility is cur- capital costs between US$360 and US$730 million rently allocated with 8% of total generation capacity, (shown in Table 22 below). but in 2015 it only received 5% due to transmission Under current regulations, DISCOs are not per- constraints in the wheeling of power from the South- mitted to charge residential customers a connection ern regions of the country, where power is produced, fee, so that customer contributions will not, at least to the Northern regions. Total available power sup- under the current framework, reduce the financing ply has been 3500MW (KEDCO received 280MW) on average in 2015, and has decreased to an average of 3150MW in the first quarter of 2016 (252MW re- ceived by KEDCO) due to militant attacks. Table 22   Capital investment requirements – Grid The fall in bulk electricity supply over the past electrification (US$ mn.) months due to gas supply problems and optimism in the power supply figures during the last major Conservative Best-practice MYTO review should, in theory, in accordance with Capital investment requirement (2018–2023) the MYTO tariff formula be corrected through an 2018 19 32 increase in allowed revenues. However, it is estimat- 2019 25 47 ed that the tariff increase would be of 50% for the whole sector (including foreign exchange devalu- 2020 32 82 ation),19 and would very unlikely be implemented 2021 63 133 without triggering further public opposition. 2022 92 185 2023 132 252 Capital Costs of the 4.1  Total capital investment 362 731 Electrification Assumed KEDCO equity Minus:  36 73 Programme (2018–2023) (assumed 10%) Connection charges — — The 2005 Electric Power Sector Reform Act pre- Total financing gap 326 658 scribes the regulatory framework governing the 92 Financing and Implementation of the Access Program necessary for the electrification programme. KED- nisia, Kenya, Rwanda, Vietnam, Thailand and Indo- CO’s owners may themselves wish to finance some nesia, amongst others. of the investment—the rate of return allowed in The financing gap shown in Table 13 provision- current NERC regulations does make such invest- ally adopts an equity contribution by KEDCO’s ment attractive in theory. However, given regulatory shareholders of 10% of the capital required.22 This uncertainties over tariffs experienced over the past assumes that KEDCO’s shareholders are comfort- 12 months, the risks for equity investment is poten- able that the regulatory framework going forward tially high. will reward them sufficiently for the risks entailed in The investment requirements of the least-cost such investments and that the market reforms con- access scale-up programme are substantial. For tinue to show results in terms of improved availabil- the grid component, capital expenditures for about ity of electricity at the wholesale level. This equity US$3.3 million are estimated over a 15-year period, may come from retained profits or from external with an annual average of US$220 million over the calls on cash from the shareholders—essentially it is implementation period. For the time frame covered the same source. Investment in distribution is nor- by this Prospectus (2018–2023), the on-grid financ- mally regarded internationally as a low risk business ing needs for the two rollout scenarios are sum- but the returns on investments in distribution in Ni- marised in Table 13 below. geria are currently uncertain and for this reason we An overall capital cost for grid electrification of have suggested only a 10% equity contribution. US$ 362 million will be required for the conserva- For the reasons described above commercial tive scenario and just over US$ 730 million will be borrowing is not anticipated. To the extent that needed for the implementation of the best-practice NERC regulated tariffs—guided by FGN policy scenario. The financing gap for 2018–2023 is pro- on access—combined with other revenue sources jected to be of US$326 for the conservative scenario potentially available to a utility (e.g. equity, con- and of US$658 for the best-practice one. nection charges, bill surcharge on non-poor cus- Relevant experience from other nations that have tomers) do not allow recovery of 100 per cent of successfully navigated a universal access rollout un- the capital expenditures (capex) of the access scale ambiguously indicates that no country has achieved program, public funds will be needed to bridge the universal access without significant and sustained shortfall (i.e. the investment financing gap associ- levels of public funding to finance a substantial por- ated with the access rollout implementation each tion of the capital investment requirements (capex), year). Therefore, the resultant financing gap for irrespective of whether the distribution sector was both scenarios (US$326 for the conservative sce- privatised or state-owned. This applies in particular nario and of US$658 for the best-practice one—or to the early stages of access rollout implementation 90% of the investment requirements) is assumed to when revenues from other sources are inadequate to be financed by the FGN, consistently with interna- finance LV and MV lines and service connections. tional best practices, through grants and conces- Combined with the adoption of a National policy sionary loans. The FGN could obtain the financing for Universal Access with targets and timetables, from a variety of sources including Development Governments’ financial commitment constitutes a Partners, Provincial Governments, Local Authori- key driver of performance for the success of a large ties and will on-lend to the utility on terms that en- scale electrification programme.21 sure its commercial viability. For instance, in Brazil the state and regional Although the mix of financing provided here governments provided 85% of the investment costs are placeholder values we note that the equity through grants and concessionary loans while share assumed (10%) is broadly consistent with the the private owners contributed 15%. In India, the share adopted for example in Brazil’s electrification electrification programme was 100% government scheme, though higher than in India (see Annex 6). funded with 90% provided by central government The equity and loan contribution would have to be and 10% by the state governments. In Chile, the discussed with KEDCO management and owners electrification programmes were awarded on the and other potential financing institutions. The split basis of the provider offering the lowest subsidy among financing sources (equity, grants, conces- requirement. Successful programs, that have either sionary loans) will be determined at syndication. achieved universal access or are well advanced in Based on international electrification rollout their rollout, were also undertaken in Morocco, Tu- experiences23 (described in Annex 6), we suggest Financing and Implementation of the Access Program 93 we suggest the establishment of an Electrifica- Investment Needs 4.2  tion Fund, similar to that adopted in Brazil, that will be used to provide financial support to the in Generation and private DISCOs when expanding access. The Fund Transmission will on-lend to DISCOs publicly raised funding on The analysis reveals that the electrification pro- terms that are commercially viable to the DISCOs, gramme will lead to an increase in electricity de- whether in the forms of grants or concessional mand of between 130 MW and 260 MW by 2023 loans, and will also keep DISCOs accountable for (and around 1,000 MW by 2030)—this is just for the financing received by monitoring and auditing KEDCO (if the programme is rolled out to other their progress. Grant funding will make it easier for DISCOs, a similar increase in demand would be the electrification targets to be accepted by all par- expected for the other ten DISCOs). Generation ca- ties and co-funding of investments through donor pacity is a pooled resource and this demand will be grants and concessionary loans will also help lower supplied from the TCN grid and allocated to KED- the actual or perceived risks for KEDCO’s owners. CO and other DISCOs. KEDCO’s current allocation As shown by international experience, it would be is 8% but this could potentially be negotiated up- FGN’s responsibility to (i) secure the funding and wards if it’s demand increases faster than other DIS- (ii) ensure its availability before the electrification COs and sufficient capacity is available. KEDCO’s rollout takes off. demand resulting from new connections will be in Various arrangements have been adopted world- addition to the anticipated underlying increase in wide for this kind of institution, but all of them re- electricity demand which is expected by NERC to sponded to four main principles: transparency, ac- grow at 10% per annum, with generation rising to countability, independence and ex-ante funding of over 14,300 MW by 202824 from NERC’s assump- the programme. The Fund management will act as tion of approximately 4,120 MW available in 2015.25 a trust fund payment agent and will be subject to Generation has been privatised and the current specific rules and reporting requirements, with the framework envisages that new generation capac- supervision of NERC, governing cash-flow manage- ity will be developed by the private sector and sold ment and in particular how the financial resources to the bulk trader (NBET). Some significant new are to be dispersed, monitored and, in the case of power plants are currently under development with loans, returned. Finally, if the Fund is to be housed state funding through the NIPP (see also Annex 1). at an already existing agency (e.g. NERC), firewalls The first private sector power plant reached finan- will have to be raised between the two entity to en- cial closure in December 2015 (Azura-Edo, part of sure the independence of both. a 2,000MW IPP)26 and the framework for attracting For the KEDCO investment programme, loans private investment in power generation therefore will be made to KEDCO. These loans may be pro- exists (specifically, the wholesale tariffs available for vided by the proposed Fund, together with grants. generators are attractive), guarantees are available, If concessionary loans are provided this may not, and a number of conditional licenses have been is- under the current regulatory framework, benefit sued by NERC. Partial risk guarantees are being pro- end-users because the rate of return allowed by vided by the World Bank and AfDB. The World Bank NERC is independent of the actual cost of bor- has provided or is providing loans to support the rowing (this should be remedied by changing the upgrade of hydropower projects.27 Relatively small- regulatory formula so that the benefit of conces- scale but grid connected renewable generation is be- sionary debt is passed on to end users). Grants will ing developed in Nigeria—these projects are being be made to KEDCO (through FGN or from FGN) provided with grant support from the German gov- but grant-funded assets should not be included in ernment/EU/GIZ and the Clean Technology Fund KEDCO’s net asset base and the company should (under World Bank management). JICA is also pro- not be allowed to recover these costs from custom- viding grants for a grid connected solar power plant. ers through a return on net fixed assets and depre- It must be assumed that in time there will be ciation charges. Ultimately, KEDCO’s customers adequate generation capacity to satisfy the grow- will repay the equity and loan components of the ing demand. There will be substantial investment KEDCO investment programme through tariff rev- financing needs of the private sector for generation enue designed to cover operating costs including to satisfy the growth in demand. This is not covered depreciation and a return on net fixed assets. by this Investment Financing Prospectus. We note 94 Financing and Implementation of the Access Program that a generation masterplan study is underway, fi- rate assessment of ATC&C losses was not available, nanced by JICA.28 and an agreement was reached between NERC and Transmission remains state-owned (Transmission the DISCOs to assess and validate them for their Company of Nigeria – TCN) and substantial invest- incorporation in the following round of MYTO ment will also be required both to satisfy the under- revision (adopted in January 2015). MYTO 2015, lying demand growth and to meet the demand to be adopted in February 2016 is based on the same set generated by an electrification programme. The trans- of validated losses. For KEDCO, losses were estab- mission system to the KEDCO franchise area has a lished at almost 49% whereas in the Business Plan transfer capability constrained to less than 250 MW. were estimated at 40%. The maximum demand that has actually been sup- 7. In 2015 terms, accounting for inflation for plied was 286 MW. Because of the transmission con- 2012–2015. straint, KEDCO is not able to take its full 8% alloca- 8. As reported by the geospatial analysis. More recent tion of generation from the wholesale market. In 2015, conversation with the utility indicate that the aver- KEDCO was able to take about 5% if its allocation. age price per meter could also be higher, around The unreliable pipeline infrastructure is current- US$220. ly leaving as much as 1,500 MW of installed power 9. KEDCO’s Business Plan submitted at privatiza- generation capacity stranded29 in the sector and the tion. The target for meter deployment included management contractor has identified several areas the provision for new connections (this mostly of critical investment that are needed for the trans- referred to regularize existing consumers) but not mission system (estimated at about US$8 billion) to for R1 new customers. achieve a wheeling capacity of at least 20,000 MW 10. According to Energy Markets and Rates Consultants by the year 2020. Some of the financing for TCN is (EMRC), formerly Mercados EMI, a consultancy provided from the World Bank, AfDB,30 AFD31 and providing advisory services to Nigerian DISCOs. JICA.32 We also note that a transmission planning 11. Verbal communication with NBET. study has been contracted by TCN with World Bank 12. World Bank estimates, February 2016. funding. Again, the investments required for trans- 13. World Bank estimates, March 2016. mission network expansion, reinforcement and re- 14. The Nigeria Electricity Market Stabilization Fund habilitation are not covered by this Investment Fi- covers the losses accumulated from privatization nancing Prospectus. until the end of 2015. To cover for the 2016 arrears, the FGN was supposed to issue a bond, but at the time of writing it hadn’t been issued yet. Endnotes 15. Any surplus after paying the debt was expected to 1. Verbal communication with KEDCO. be invested in metering and other key capex. 2. For all DISCOs, bids were won on the basis of the 16. World Bank estimates, February 2016. loss reduction targets to be implemented over a 17. World Bank analysis, February 2016. five-year plan. 18. The increase in sales is also due to the projected re- 3. The delay in the enforcing of the Performance duction in ATC&C, but primarily due to increase Agreements signed at privatization was due to ab- in electricity availability in the national grid, as sence of cost-reflective tariffs, which were intro- noted at the beginning of the Section. duced for the first time in January 2015 but then 19. World Bank estimates, March 2016. abandoned in March 2015 after political backlash 20. World Bank analysis, February 2016. triggered by the tariff increase. 21. For an overview of the key drivers of performance 4. In the case of KEDC the capital expenditure allow- and successful experiences world-wide see also ance decreased from US$23.5 million to US$19 mil- IEG (2015), “World Bank Support for Electricity lion per year (NGN 4.7 billion to NGN 3.8 billion). Access FY2000–2014”, Washington D.C. 5. After the adoption of cost-reflective tariffs in 22. At the time of drafting this Report, the sharehold- January 2015, which determined the activation of ers, IFIs and development partners were not in a the privatization Performance Agreements, tar- position to comment on their likely willingness iffs were reverted back to their previous levels in to provide equity, debt or grants. The mix of fi- March 2015 because of political backlash. nancing provided here are therefore placeholder 6. Although privatization bids were won on the basis values. of targets for loss reduction, at that time an accu- 23. Brazil, India and Chile, for instance. Financing and Implementation of the Access Program 95 24. The basis for NERC’s forecast is unclear and, in 27. Approximately US$100 million for rehabilitation particular, it is unclear how much is assumed to of power plants, focusing particularly on water relate to increased electrification and how much resource management. Some.is funded from the to increased supply to existing customers and con- Carbon Fund. sumers. Strictly speaking, the NERC forecast is a 28. Japanese International Cooperation Agency. supply forecast rather than a demand forecast. 29. Also due to lack of policy and regulatory reform in 25. This differs slightly from the figure provided by the gas sector, together with outdated commercial NBET for 2015 of 4,500 MW of available genera- frameworks and price ceilings. tion capacity. 30. US$ 150 million soft loan for budget support to 26. The facility is expected to produce 450 MW in the the Ministry of Power that is being used for trans- first phase, and then increase production up to mission investment. 2,000 MW. The commissioning was supported by 31. US$ 170 million loan. guarantees from the World Bank Group and con- 32. US$ 200 million loan. struction started in January 2016. For more infor- mation, visit: www.azurawa.com. CHAPTER 5 Current Tariff Regime and the Electrification Program The latest electricity tariffs were approved in Feb- regulation issued by NERC allows the DISCOs to ruary 2016 through version 2015 of MYTO. These convert R1 customers to R2 if their consumption removed the fixed charge from tariffs and substan- exceeds 50 kWh per month for three months in tially raised the kWh charges for all DISCOs includ- succession. Immediately after privatisation, KED- ing KEDCO. CO’s R1 customers were using nearly 100 kWh per A key policy aspect of the current tariff design is month on average in December 20132 but this had maintains a ‘lifeline’ tariff, classified under the label since fallen to around 50 kWh by the start of 2015 as ‘R1’ and has been fixed at NGN 4/kWh (US$0.02/ customers were re-allocated to the R2 category. The kWh) for many years without a fixed monthly R2 category currently represents the largest group charge. In MYTO 2015, the R1 tariff has been fixed by customer numbers and kWh sales as shown in again at this same level until 2024. The R1 tariff of Table 24 below. NGN 4/kWh compares with KEDCO’s MYTO 2015 Cost reflective residential tariff designs would tariff for the standard non-lifeline residential cus- normally mean that residential customers pay tomer (R2A) which is nearly five times greater.1 more than commercial and industrial customers The R1 tariff is available to customers who are per kWh. The R2 tariff already incorporates some assessed to have a monthly consumption of less than element of cross-subsidy from non-residential cus- 50 kWh per month. However, this is not an increas- tomers to R2 customers and the R1 customers are ing block tariff and customers paying the R1 tariff very heavily subsidised from non-residential con- may consume in excess of 50 kWh per month. A sumers. Table 23   KEDCO selected tariffs Table 24   KEDCO customer numbers and (February 2016 after tariff kWh consumption (May 2015) revision) Tariff Customer MWh sales Feb. 2016 tariff category numbers (% of total) Tariff category (NGN/kWh) R1: residential 48,141 4% R1: residential <=50 kWh/ 4.0 lifeline month, single phase R2: residential 250,471 48% R2A: residential >50 kWh/ 20.3 >50 kWh/month month, single phase C2: LV 630 6% C2: commercial LV 36.3 commercial LV maximum demand13 D2: industrial LV 138 11% D2: industrial LV 37.3 D3: industrial HV 31 17% maximum demand14 Other 12,572 15% D3: industrial HV 37.3 maximum demand15 Total 311,983 100% (60,942) Source: NERC website. Source: Extracted from KEDCO billing data. 97 98 Current Tariff Regime and the Electrification Program The regulatory framework determining elec- Equity Concerns and 5.1  tricity revenues and tariffs is set out in the 2005 Electric Power Sector Reform Act and the tariff Strategic Rollout of the regulations have been developed by NERC using Electrification Programme a building-blocks model to establish the allowed Ensuring the affordability of electricity services revenues and tariffs on a multi-year basis. Al- will be key for the success of the electrification pro- lowed revenues for the DISCOs are calculated on gramme and for the equitable development of the the basis of operating costs including depreciation country. The design and implementation of the en- on fixed assets plus rate of return on net fixed as- abling policy and regulatory framework for the ac- sets plus pass-through of elements such as the bulk cess programme will therefore have to go hand in purchase tariff and the fees for TCN, NBET and hand with ensuring affordability and shared pros- NERC. At the start of the control period, the tar- perity. iffs are fixed for its whole duration (with periodic The analysis of the available datasets on income, adjustments for the non-controllable components) expenditure and geographic distribution of poverty and the DISCOs are expected to manage their (described in detail in Annex 2) indicates that the costs efficiently. If they can make above average R24 tariff is only affordable by around half of the profits by being cost-efficient, they are allowed to population and that there is a huge step change in keep the profits and the shareholders receive good in affordability between the very cheap R1 lifeline dividends but if DISCOs are inefficient, they make tariff (NGN 4/kWh with no fixed monthly charge low profits and the shareholders receive no or low or US$0.02/kWh) and the conventional R2 tariff dividends. (above NGN 18.75/kWh in 2020). The R1 is afford- There is currently no allowance for an electrifica- able to 85% of the population, but the bottom 15% tion programme in the multi-year tariff calculations of households would not be able to afford it. Final- approved by NERC and the tariffs hence do not al- ly, the top 30% of households would, however, be low the DISCOs to recover large scale electrification able to afford the to-end industrial tariffs of around costs. Combined with the absence of an electrifica- NGN 34/kWh (US$0.17/kWh). tion allowance, the DISCOs have no incentive to Large sections of new costumers of the electrifi- embark in a large scale effort as there are no targets cation programme would therefore belong to the R1 set in place, nor mechanism for rewards and penal- tariff category, which would not be attractive for a ties, and the “sculpting” of the tariffs (with MYTO profit-maximizing company. In fact, we assume that 2015) is not even allowing for cost recovery. The the regulation adopted by NERC in 2012 requiring companies are currently focused on facing the inef- DISCOs to not impose connection charges would ficiencies inherited from years of under investments be maintained during the first phase of implemen- in the sector and on stabilizing their business and tation of the rollout plan (2018–2023), although it generating cash flow. could be apt for revision at a later stage. Since the However, if the capex programme requirements maximum tariff that could be earned from lifeline of the access roll-out are reflected in the allowed customers is NGN 4/kWh and the cost of supply is revenue calculations used to design the MYTO tar- over NGN 20/kWh, the utility would sell every unity iffs, and if the tariffs are affordable (to be examined of electricity sold at a loss and would rather connect by NERC), then customer revenues would be suffi- profit-making customers, leaving large sections of cient to allow the DISCOs to make a respectable re- the population—and the ones most in need—with- turn on their investment and to service their debts. out electricity provision. Looking forward, with the right regulatory, com- However, this is a common issue of any large mercial and incentive framework, expanded electri- scale electrification program. Experiences world- fication access should be an attractive option for the wide show that new connections should be strate- companies to grow their business and expand their gically approached with the combination of low- customer base. According to NERC, the inclusion of income customers with profit-making ones. Hence, electrification financing into the tariff could also be KEDCO, as well as the other distribution companies, approved during a minor tariff review (conducted could combine R1 lifeline connections with com- every six months), provided that the DISCOs sub- mercial and industrial ones. This tactic would prove mit their plans and a proof of some degree of imple- to be particularly successful during the first stages mentation.3 of the rollout as there is a large base households and Current Tariff Regime and the Electrification Program 99 businesses to connect. Over time, economic growth Figure 5   Impact of cross-subsidy requirements on tariffs will increase energy consumption and the base 18,000 0.9 from which to collect the cross-subsidy narrowing 16,000 0.8 the financial gap to be recovered when connecting Cross-subsidy (NGN mn.) Tariff impact (NGN/kWh) new customers. The utility should therefore evalu- 14,000 0.7 ate these strategic options when designing its access 12,000 0.6 roll-out strategy. 10,000 0.5 The alternative would be an increase in the cross- 8,000 0.4 subsidy, which we modelled for illustration purpos- 6,000 0.3 es only, as it can and therefore should be avoided. 4,000 0.2 2,000 0.1 Potential cross-subsidy implications 5.1.1  0 0 of the access rollout 2015 2020 2025 2030 In this sub-section we consider the potential con- Cross-subsidy impact Tariff impact sequences on revenue requirements and tariffs of connecting large numbers of R1 customers through the electrification program. The impact is illustrated using the conservative electrification scenario and tively large amount compared with KEDCO’s an- the implementation of the realistic although more nual revenues today (approximately US$100 mil- ambitious best-practice trajectory would have an lion billed, but significantly less collected), but by even higher impact. 2030 this is predicted by NERC to represent a much Although R2 customers currently constitute smaller share of the total. While the cross-subsidy KEDCO’s biggest category of sales, since large pro- amount steadily increases in absolute terms, the portions of the population of North West Nigeria number of non-R1 customers, and their consump- will not be able to afford the conventional resi- tion, also increases steadily, thereby increasing the dential R2 tariff5 we assume that 70%6 of the new base across which the cross-subsidy can be col- households connected to an access roll-out plan will lected. We calculate that the incremental amount initially be connected as R1 customers and then mi- needed on top of the average cost-recovery tariff to grate to the R2 tariff. meet the cross-subsidy will rise to NGN 0.7/kWh We model the conservative connection scenario by 2030 (US$ 0.003/kWh) or around 4% of KED- to determine the total requirement for cross-subsidy CO’s commercial tariffs. Initially, however, the in- to new R1 connections, with the following assump- crease would be more modest at around NGN 0.2/ tions: kWh in 2020. The above assumes that the consumption of non zz KEDCO serves approximately 70,000 R1 cus- R1 customers connected through the electrification tomers at the present time program, and of those R1 connections moving to zz 70% of the additional 3.7 million customers add- the R2 tariff category after five years, grows at 10% ed through the conservative scenario by 2030 per year, allowing a large base of consumption from through intensification and grid extension will which to collect the cross-subsidy. If this grows in- be connected as R1 customers stead at, for instance, 5% per year, the impact on tar- zz These R1 customers will increase their consump- iffs will be greater. tion and become R2 customer after five years7 The continuation of the current subsidy policy zz The R1 tariff will remain at NGN 4/kWh in tandem with the electrification program would zz KEDCO’s cost to serve R1 customers is the same not add substantially to the bills of non-residential as the cost to supply the average R2 customer8 consumers. However, the tariff increase of NGN 0.7/ zz The difference between KEDCO’s R2 tariff and kWh by 2030 assumes an increase in consumption the R1 tariff is the required cross-subsidy. of current and future non R1 customers of 10%, which could eventually be lower. In addition, as Following these assumptions, we forecast that shown by Figure 5, the tariff increase is relatively the value of cross-subsidies required will increase flat until 2020, but becomes steep in the following steadily, reaching NGN 15 billion per year (US$ years up to 2030, and its impact would therefore be 77 million) in 2030 (see Figure 5). This is a rela- felt more by KEDCO customers. Finally, the tariff 100 Current Tariff Regime and the Electrification Program increase assumes that new R1 customers will pro- 5. Though R2 is far from reflecting the costs of sup- gressively migrate to the R2 category after five years, plying residential customers, it is the closest ap- which may or may not happen. proximation we have available. 6. This is an assumption. The income profile of cus- tomers over the period to 2030 is not known so Endnotes the household expenditure data provides only 1. The multiple of six is slightly misleading as the partial guide to the proportion connecting as R1 high average R2 tariff is partly the result of load customers. shedding resulting in low kWh supplied to R2 cus- 7. This is an assumption. KEDCO has relatively few tomers so that the costs are divided over a smaller R1 customers compared with R2 and it is therefore denominator. If supply could be increased, the av- likely that customers relatively quickly exceed 50 erage R2 tariff should fall. kWh per month. 2. 96 kWh per month in December 2013 and in- 8. This assumption is incorrect since the cost to sup- creasing to 139 kWh per month in March 2014. ply new (mostly R1) customers will be greater than 3. Based on discussion with the Regulator. that to supply customers in more urban areas, but 4. Here we use the 2020 tariff as the benchmark as it is a first approximation. this is when the electrification programme is likely to take off. The tariff then is expected to be NGN 18.75/kWh with no standing charge. CHAPTER 6 Off-grid Electrification The geospatial analysis revealed that given the demo- the electrification programme (up to 2023) iden- graphic settlement patterns and relevant technical, tified by this Prospectus (illustrated in Table 3), economic and financial parameters provided primar- regardless of the conservative or the best-practice ily by domestic sources (including KEDCO), connec- trajectory implemented. The successful experi- tion to the grid is the least-cost solution in the long- ence of the World Bank Group Lighting Africa run for most of the population. However, the analysis and Lighting Global initiatives in Africa (see, for also allows to identify the potential and scope for an instance, the experiences of Kenya, Ethiopia and off-grid electrification programme, to be coordinat- Tanzania) and Asia demonstrated that Tier 1&2 ed (in space and time) with and to complement grid products can be rapidly scaled-up, although not developments. In particular, two categories of ben- yet at the scale of ~3.3 million households3. eficiaries can be identified: long-term off-grid and ii. Tier 3+ access delivery – the technical potential pre-electrification. The use of off-grid solutions for for isolated mini- and micro-grids is identified in power back-up is also discussed, although not strictly the latter segment of grid development (in space belonging to an off-grid access programme. and time), requiring the extension of MV lines Long-term off-grid refers to small communi- and affecting ~1.8 million households (also il- ties or households geolocated in remote, isolated lustrated in Table 3). Although no country has (defined as distant more than ~100 m from any yet scaled-up a mini- or micro-grid programme, neighbouring structure1) or scattered areas where well designed pilot schemes (a pilot scheme has the grid is not recommended as the least-cost op- been recently launched by GIZ) can aide in the tion by 2030. They constitute a small percentage of identification of viable business models to sup- the population, about 3%, corresponding to about port the spreading of distributed generation4. 126,000 households in 2015 and growing to 164,000 by 2030 and to 6% of current schools and clinics. To ensure shared well-being and shared pros- The largest component of the off-grid electrifi- perity across the country, these communities could cation program potentially consists of beneficiaries be provided access with sufficient power for essen- of pre-electrification solutions, that is, households tial electricity services such as household lighting, and communities which are targeted for grid con- charging of mobile phones and other batteries and nections in the latter part (beyond the medium- devices, and basic connectivity for schools and clin- term) of the 15-year MV grid extension plan and ics to power computers, vaccine cold chain, and thus will be required to wait potentially for several other services. Grid-coordinated pre-electrification years (5 to 10, if not longer) for electricity access. plans will have to be developed as transitional mea- Depending on the electricity access services provid- sures when the grid is still the least-cost solution in ed, pre-electrification beneficiaries could be charac- the long-run, while at the same time designed to terized by two subcomponents: protect investors’ businesses after the arrival of the grid (i.e. ensuring technical compatibility between i. Tier 1&2 access delivery2 – The economic poten- off-grid solutions and the distribution network). tial of this off-grid sub-programme refers to the These pre-electrification transitional off-grid solu- ~3.3 million households that are not expected to tions could then become power supply back-ups receive access to the grid during the first 5 years of and/or feed into the grid network. The electrifica- 101 102 Off-grid Electrification tion possibilities for such pre-electrification areas provided to sector stakeholders in the form of Techni- are described in Annex 4.3. cal Assistance. Not strictly belonging to the off-grid access pro- A financing plan needs to be developed to support gramme, but a potentially important segment of the off-grid developments. The plan will have to be tailored off-grid market is, in fact, constituted by the use of to the current market structure and could envisage a off-grid solutions for power back-up purposes. This combination of private sector and public sector-led market refers to households already provided with programs and financing. International best practices electricity access in 2015, or to be connected during can inform off-grid developments as well, and the es- the rollout plan, that could choose to rely on off-grid tablishment of a line of credit and/or a credit facility technologies for power back-up as long as the power for the rollout of off-grid solutions has already proven supply provided by the grid is not reliable. Nigeria is to be very successful in countries such as Ethiopia and affected by chronic high voltage fluctuations, black- Bangladesh (described in Annex 6.4).7 A line of credit outs and load shedding, making the country the sec- could be opened to support DISCOs or small and me- ond market for self-generators, far more expensive dium sized private sector enterprises, and the facility/ than efficient off-grid solutions would be. line of credit could either become integral part of the Given the country’s richness in solar resources, Electrification Fund suggested for the on-grid rollout the technologies identified to provide off-grid ser- or established separately. The financing mechanism vices are solar lighting/charging products, solar can be designed to create a market-driven, private home systems or diesel or hybrid mini-grids, al- sector-led approach addressing some of the main is- though a throughout geospatial resource mapping of sues preventing the off-grid market from taking off the country, completing the exercise started by GIZ, such as: access to finance at relatively lower cost of could reveal more renewable energy opportunities. capital, access to foreign currency, and improvements For the Kano service zone, the costs associated to to the general lending environment (e.g. fair-market these technologies are in the range of US$50–100 for collateral values), and identification of commercially pico-solar, US$425 on average for solar home sys- viable delivery models. tems, and between US$500 to 1,2000 for mini-grids, On the public sector side, the FGN could build depending on the service standard5. upon the National Renewable Energy and Energy The costs associated to an off-grid programme Efficiency Policy adopted in April 2015 to develop will eventually depend on its size (that is, on the an off-grid programme providing access to public number of beneficiaries, their needs, and the tech- institutions across the country. The National Policy nologies deployed) and are potentially substantial. was established to remove the key barriers that put For instance, given per- household SHS costs, the renewable energy and energy efficiency at econom- needs of the long-term off-grid beneficiaries could ic, regulatory or institutional disadvantages relative be met for around US$70 million. As regards pre- to other forms of energy in Nigeria. The policy states electrification purposes, the full rollout of the Tier that PV power will be utilized to power low to me- 1 &2 programme could require around US$ 450 dium power applications such as communication million alone (with an average combination of pico- stations, water pumping and refrigerator in pub- solar and SHS solutions). lic facilities in remote areas and to extend modern Notwithstanding its potential, the growth of the energy service to rural and remote off-grid areas, solar market in Nigeria is currently constrained. In through the use of solar home systems. fact, it is estimated that only 0.3 percent of house- The successful implementation of a large-scale holds are using solar lighting products compared to off-grid plan would also require providing a policy 2–3 percent in countries such as Kenya, Tanzania and regulatory enabling environment. In particular, and Ethiopia. Annual sales of solar lighting products institutional roles and responsibilities of sector in- are estimated at around 100,000 units, compared to stitutions (e.g. Rural Electrification Agency, NERC 900,000 in Kenya. Two are the main factors that need and DISCOs) and stakeholders should be identified to be tackled to support large scale off-grid develop- in the new market structure. Furthermore, rules ments: (i) lack of access to finance for importers, dis- governing the off-grid space, fostering market pen- tributors and consumers and (ii) lack of an enabling etration and the coordination of private and pub- policy and regulatory framework.6 For the improve- lic efforts, should be developed and enforced. This ment of both the financial and the policy/regulatory rules should include service standards for off-grid dimensions, capacity strengthening support could be technologies, which may be differentiated for long- Off-grid Electrification 103 term and pre-electrification off-grid areas. Quality understand that these regulations are currently un- standards and warranties systems should be adopted der review, with support from GIZ. At this stage, it for Tier 1&2 building on the best practices emerged is uncertain when revised regulations will be made internationally in this field, and for Tier 3+ grid available, but we anticipate this to happen sometime compatibility should be ensured, not lastly to pro- in early 2016. Some of the important provisions in tect private investments. NERC should also be re- the regulations are summarised in Annex 5. sponsible for compiling a list of approved selected At present, there is nothing in the regulations to organizations. Subsidy frameworks could also be guide the options for operators of isolated IEDNs identified to ensure the scalability and affordability when the DISCOs extend their network to within of the programme8, particularly given the high cost proximity of the IEDN. This question is a critical one of off-grid generation and current low penetration of in the context of the access expansion plan that is off-grid solutions (support could be provided in the proposed, particularly if it is anticipated that private first phases for e.g. the marketing and distribution operators will be a key agent in developing IEDNs. In of products9). Problems of affordability of electrifica- other countries, IEDN operators are comfortable with tion that were described for grid-connected house- the approach of main grid networks, provided there is holds will in fact be magnified in the off-grid space. certainty over the timing of when the grid will arrive, The geospatial distribution of poverty reveals that and the operator’s options when this happens. the areas with high poverty risk are also the areas We understand that the revised IEDN regula- furthest form the existing grid, with the lowest pop- tions will cover the options for IEDN operators ulation densities, and the highest cost of grid elec- when the main grid arrives. We also understand that trification. Hence, households that are expected to the regulations will focus on systems between 100 be connected in the later phases of the electrification kW and 1 MW. rollout, or already targeted for off-grid solutions, are also mostly affected by poverty (see also Annex 2). Although a specific rollout plan for off-grid will 6.2 DISCO-led Off-grid to some extent depend on KEDCO’s determination Electrification and to undertake a rollout plan in the next few years and Targeted Support its year-by-year geographic implementation and se- Although the main role of the DISCOs is to provide quencing, this should not prevent the adoption of all grid-based electrification services and electricity of off-grid solutions. In fact, while the deployment supply, they could have no role in providing elec- of mini-grids may take longer, particularly in light tricity through isolated grids or, indeed, through of the absence of a regulatory framework (see Para- off-grid options (pico-solar lighting, solar home sys- graph below), the distribution of pico-solar solutions tems). In many countries in Africa and elsewhere, and installation of SHS—supporting services up to the distribution companies also provide electricity general lighting, phone charging, and the use of a through isolated grids (for example, Kenya, Malawi, small television and a fan—should be firmly pursued. Tanzania and Tunisia). The paragraphs below provide an overview of pos- There should be no obstacles to KEDCO becom- sible KEDCO-led as well as non-utility-led develop- ing involved in developing IEDNs and providing ment of small grids isolated from the current distribu- electricity services using off-grid solutions (solar tion network that may supply consumers before they home systems and solar pico-lighting). The utility become connected to KEDCO’s grid in the future. should, in principle, be eligible under their existing licence to include the proposed costs of such invest- The Current Regulatory 6.1  ments in their projected Regulated Asset Bases and Framework for Isolated required revenues, and to recover the costs through tariffs. They might also consider establishing subsid- Grids iary companies with separate licences to allow great- Under Nigerian regulations, isolated grids (also er flexibility in charging customers for these services. known as mini-grids) are known as Independent Targeted support could be made for increasing Electricity Distribution Networks (IEDNs). They electricity access through off-grid programmes. The are currently regulated under the Nigerian Electric- power supplied by IEDNs and other off-grid tech- ity Regulatory Commission (Independent Electrici- nologies tends to be more expensive than that from ty Distribution Networks) Regulations, 2012, but we main grids on a fully cost-reflective basis. If KEDCO 104 Off-grid Electrification (or indeed any operator) is able to charge tariffs high- ing communities without grid electricity for some er than approved R1 levels for grid customers, it will time into the future, the Rural Electrification Boards need to consider both the cost to serve and the will- (REBs) could take the lead in developing isolated ingness of customers to pay. Tariffs cannot be greater mini-grids and solar home system programmes for than customers’ willingness to pay, but if this level is these communities. Similarly, while traditionally the lower than the full cost to serve, the operator will re- Rural Electrification Agency (REA) has focused on quire a subsidy. This may be targeted towards one-off grid-based electrification, recognising that DISCOs capital costs or recurring operating costs (the former will not be able to achieve full grid electrification by is preferred for transparency and sustainability). 2030, a better focus for the Agency would be on off- If and KEDCO management decides to be in- grid electrification (solar home systems, pico-solar volved in off-grid developments, then it would have lighting) and isolated grids in areas that are not ex- to include its cost in the tariffs and get NERC’s ap- pected to be grid-electrified in the near future. proval. Following the principle that tariffs should Furthermore, while the approach for cross-sub- be set at cost-recovery levels, tariffs for such off- sidies between main grid and off-grid customers grid customers would either need to be set higher assumes a transfer within KEDCO’s business, the than those for main grid customers, or alternatively, principle may be applicable between the utility and those customers on the main grid with relatively a private operator, whereby KEDCO is required to cheaper costs to serve could cross-subsidise those collect tariffs that exceed its costs to serve particular customers not connected to the grid. customers in order that the surplus is transferred to The approach for cross-subsidisation could be ei- reduce the cost to serve off-grid customers. In such ther implicit or explicit. An implicit approach would an instance with different operators, it would be eas- ‘hide’ the additional cost for the cross-subsidy within ier to collect and transfer the subsidy if it is explic- the tariff, where customers simply observe that they itly itemised and collected in a customer’s bill. This are charged the same tariffs regardless of their con- principle makes the economic outcome of off-grid nection type. An explicit approach would set an ad- supply indifferent to the system’s ownership. ditional amount in the tariff to cover off-grid cus- There may be scope for some local networks to tomers, identified clearly on all main-grid customers’ be operated as small power distributors, with KED- power bills. As either approach should achieve the CO merely providing the bulk power, and distribu- same effect economically, the choice is perhaps more tion, metering and billing being undertaken by the one of public or consumer acceptability. community or a local entrepreneur. As these local grids may later to be absorbed into the utility’s dis- tribution grid, appropriate regulatory arrangements 6.3 Non-DISCO-led Off-grid need to be implemented to allow for a fair recovery Electrification of costs when this absorption takes place. The DISCOs should not be barred from being in- volved in off-grid electrification, but at this juncture it would be counter-productive to make this manda- The Future Role of REA 6.4  tory. Off-grid electrification is likely to involve high and REBs costs and require a disproportionate allocation of The 2005 Electric Power Sector Reform Act estab- management time, without a commensurate flow of lished the Rural Electrification Agency (REA) and revenue. These factors will discourage the KEDCO the associated Rural Electrification Fund (REF) and from becoming involved in off-grid electrification. REA began operation in 2006. The law and associ- One advantage of their doing so, however, would ated policy documents outline the principles for ru- be providing scope for cross-subsidisation between ral electrification to:10 higher-paying customers on the grid and the off- grid consumers. For this to become a significant “Facilitate the provision of steady and reliable feature of electrification in KEDCO coverage area, power supply at economic rates for residential, the cross-subsidy requirements would need to be commercial, industrial and social activities in analysed and explicitly incorporated in the MYTO the rural and peri-urban areas of the country. calculations and approved by NERC. To the extent that the KEDCO declines to take Facilitate the extension of electricity to rural up off-grid electrification and publish plans show- and peri-urban dwellers. Off-grid Electrification 105 Encourage and promote private sector partici- Endnotes pation in grid and off-grid rural development using the nation’s abundant renewable energy 1. As noted by the geospatial report, these house- sources while ensuring that Government Agen- holds and communities may, or may not, be far cies, Co-operatives and Communities, partici- from the exiting grid, but their local isolation from pate adequately in enhancing electricity service neighboring structures raises the cost of grid con- delivery.” nectivity greatly. 2. A Multi-Tier Framework for electricity access was The Rural Electrification Agency’s focus was on developed by the World Bank Group under the grid electrification based on funding from the Fed- Sustainable Energy for All (SE4All) engagement. eral budget through the extension of existing grids The framework defines five different tiers of access to rural areas11 (and handing over these networks for electricity supply corresponding to different to be operated by the then state-owned PHCN). electricity services is further discussed in Annex 4. Its current focus is the completion of around 2,000 3. International experiences suggest that ~30% of the electrification schemes that had begun but before ~3.3. million identified as potential beneficiaries 2009 but not completed. No information is current- could be easily provided with access. World Bank ly available on the degree of their completion. Team Task Leaders estimates, 2016. For more in- In the current new sector structure with priva- formation, visit: https://www.lightingafrica.org/. tized DISCOs, REA’s old role is no longer operative 4. International experience suggests that the market and a new mandate and portfolio will have to be re- potential for this off-grid development is to date defined at the FGN level. Recognising that DISCOs around 10% (i.e. 180,000 connections of the 1.8 will not be able to achieve full grid electrification by million potential beneficiaries). World Bank Team 2030, a better focus of REA could be on off-grid elec- Task Leaders estimates, 2016. The WBG Lighting trification (solar home systems, pico-solar lighting) Global recently started to operate in the Tier 3+ and isolated grids in areas that are not expected to be access delivery market. grid-electrified in the near future. When re-defining 5. The geospatial analysis identified the cost for a the role of REA in the off-grid space, careful atten- mini-grid with a service standard of 120 kWh/ tion will have to be paid to avoid any conflict of in- HH-year to be in the range of US$1,000-1,200 and terest that could hamper the development of a com- for a 60 kWh/HH-year per customer service, be- petitive, transparent and vibrant market for off-grid tween US$500 and US$700. solutions with the participation of the private sector. 6. Lighting Nigeria also mentions as major obstacles Electrification targets and rollout plans, re- for the development of an off-grid market: low lev- viewed and cleared by NERC for each DISCO, will els of awareness of solar products, their advantages need to be published by the DISCOs and NERC to and ways to distinguish good quality products and inform and guide the players of the off-grid space low availability of products due to lack of distribu- (potentially REA and REBs, but also independent tion networks in rural areas. electricity distribution network -IEDN- providers, 7. The Bangladesh SHSs program has been widely private investors, and other off-grid providers and acknowledged as the most successful national off- contractors) in choosing where to focus and align grid electrification program in the world reaching their efforts models, consistently with the updated 100,000 installations a month. energy access policy related to the off-grid institu- 8. Typically, for mini-grids, this implies grants to tional framework.12 cover up to 80% or 90% of the capital costs. The role and funding of state-level Rural Electri- 9. Lighting Africa has supported the promotion of fication Boards (REBs) will also have to be redefined pico-solar lighting products to the base-of-the-pyra- in the new sectoral context by a new mandate at the mid households for a number of years but is no lon- FGN and State Government levels. The REBs have ger proposing direct subsidies the products. How- resources and capability to undertake grid electrifi- ever, this kind of subsidies could also be considered. cation and could potentially reorganise themselves 10. This is extracted from the REA website. as contracting agencies able to compete with private 11. This focus was described in a presentation by a sector contractors for electrification projects com- Special Advisor to the Minister of Power during a missioned and paid for by the DISCOs. This would Presidential Retreat in January 2012. be a policy decision for the State Governments. 12. Discussed in Chapter 6. Annexes Summary of KEDCO Rapid 1  In February 2016, tariffs were re-set to cost- recovery levels (MYTO 2015), initially adopted in Readiness Assessment January 2015 but then reversed in April 2015. Fol- A Rapid Readiness Assessment was undertaken by lowing the adoption of cost-reflective tariffs in Janu- the ECA team in October 2015 to understand the ary 2015, the Performance Agreements (PA) and the potential major barriers for delivering affordable Minimum Performance Targets (MPT) submitted at and reliable electricity access, efficiently and sus- privatization came into effect. tainably nationwide. The assessment also consid- Since cost-reflective tariffs were adopted two ered the capacity strengthening initiatives needed years after privatization, the MPT (ATC&C losses to de-bottleneck an electrification access roll-out reduction, metering and new connections)2 may which are reflected in the proposed Technical Assis- need to be re-sculpted over the next 5 years and re- tance activities outlined in the report. A summary of flected accordingly in the business plans and in new the findings is provided below. targets. An assessment of the progress achieved by The Readiness Assessment concluded that KED- Discos since privatization (estimates of improve- CO, together with the DISCOs, will need to focus ment in efficiency) could also be reflected in the on stabilising its business and generating cash flow new targets. Discos argue that there is also a need in order to establish a solid financial and electrical to reflect the removal of MDA non-payments from foundation for moving forward. For all DISCOs, collection losses in the overall loss reduction targets. expanded electrification access is not an immediate Negotiations between Discos and BPE are ongoing priority. Looking forward, with the right regulatory, which is further delaying the implementation of commercial and incentive framework, expanded measures to achieve the targets. electrification access should be an attractive op- The adoption of MYTO 2015 shows progress tion for the companies to grow their business and in the assessment of ATC&C losses. Although expand their customer base. For this reason, the bids were won on the basis of business plans for electrification programme discussed in Chapter 2 is ATC&C losses reduction at the time of privatiza- assumed to commence in 2018. tion an accurate assessment of losses was not avail- Progress in sector reform: Major milestones able, hence tariffs were not adequately estimated. for the implementation of the 2010 Power Sector An agreement was then made between NERC and Reform Roadmap and the establishment of a com- DISCOs to assess and validate the losses for their petitive market have been met. The unbundling and incorporation into MYTO 2.1 (January 2015). The privatization of the vertically integrated sector util- validated losses for KEDCO were established at ity, Power Holding Corporation of Nigeria (PHCN), 48.7% (instead of the 40% indicated in the Busi- was completed in November 20131 and the Nigerian ness Plan). MYTO 2015 is based on the same set of Electricity Regulatory Commission (NERC) has validated losses with committed reductions start- been fulfilling its mandate of economic regulation ing in 2015. including management of tariff reviews. The Nige- The adoption of MYTO 2015 was meant to coin- rian Bulk Electricity Trader (NBET) was established cide with the activation of the Transitional Electric- to be the initial counter-party to bilateral contracts ity Market (TEM), one of the pillars of the reform pending declaration of the TEM when the bilateral set out in the 2010 Roadmap to Sector Reform. contracts between DISCOs and generation compa- TEM is the stage of market development which oc- nies become effective. curs after the activation of PPAs (with generation 107 108 Annexes Figure A1   Post-privatization market structure Current – March 2016 Source: World Bank, 2016. companies), GSAs (with gas suppliers) and vesting consumers, while DISCOs are expected to pay in contracts (with distribution companies) thereby en- full for the supply received. DISCOs will under- abling full payments across the power sector value recover revenues in the first few years and over- chain. Whilst it was originally envisaged that the recover later to have a fully cost-reflective outcome TEM would be declared before or at the time of the over a 10-year period (included into MYTO 2015). completion of the privatization of the PHCN suc- The FGN is expected to raise a bond and on-lend cessor companies, its commencement had to be funds to Discos so as to enable them to make full delayed until the adoption of cost-reflective retail payments up-stream from 2016 onwards. How- tariffs. Following the implementation of the new ever, the timing and the size of the bond are un- tariffs, few conditions precedent remain before con- certain, and DISCOs may be forced to fund the tracts can be activated (the most important being under-recovery from commercial banks. This LCs provided by the Discos). The activation of the could be problematic though as the deficit accu- TEM will be a step forward in the contract-based mulated has surpassed their value at privatization market for electricity trade in Nigeria, essential for (US $1.8 billion). The size of the under-recovery market discipline and for the financial viability of has been estimated at almost US$ 700 million in the electricity market. Furthermore, it is a step for- 2016 (16% of expected total revenue) for the whole ward towards the ultimate goal of a robust competi- sector, to be combined to the ~US$ 1 billion deficit tive market where DISCOs will purchase directly accumulated in 2015 only (after the abandonment from generation companies (without the need of a of MYTO 2.1 in April) and the ones accumulated single buyer)—as set out in the Electric Power Sec- from privatization until the end of 2014 (in the ab- tor Reform Act of 2005. sence of cost-reflective tariffs) amounting to US$ Although the tariffs have been raised to cost- 1 billion, for a total of almost US$ 3 billion owed and losses-reflective levels, the FGN decided to by the DISCOs to the rest of the value chain by the “sculpt” them to manage the increase for end- end of 2016.3 The losses accumulated until the end Annexes 109 of 2014 are expected to be covered by the Nigerian Figure A2  KEDCO payment of NBET invoices (Feb–Dec 2015) Electricity Market Stabilization Fund (NEMSF) 180% through loans provided by the Central Bank of Ni- 160% geria (CBN) but there is uncertainty about how the deficits for 2015 and 2016 onwards will be tackled. 140% 120% Policy, institutional and regulatory framework: A 100% policy, institutional and regulatory framework for 80% expanded electrification access needs to be adopted 60% with the inclusion of targets and timetables, fund- 40% ing mechanisms, and roles and mandated of sector 20% institutions. The policy on electrification targets 0% would need to be formally introduced by the Fed- 1 2 3 4 5 6 7 8 9 10 11 eral Government of Nigeria (FGN), with NERC re- Source: World Bank, 2016. sponsible for implementing this policy by recognis- ing the targets when approving the next multi-year tariff order (MYTO) and for approving the tariff de- signs in that Order. NERC will also be responsible for implementing the incentive framework to help the case of KEDCO account for 3% of the ATC&C ensure that the targets are met without damaging losses,6 without the introduction of a mechanism the commercial viability of the DISCOs. for defrayal. In addition, MYTO 2015 was based on The 2015 round of MYTO has not anticipated optimism in the tariff review process over the power major electrification investment expenditures. Al- supply figures (of 5,000MW whereas a more real- though MYTO is set for ten years and is normally istic figure would have been 4,000MW–4,500MW), reviewed every five years, there are provisions for further decreased by recent militant pipeline attacks earlier reviews. Such a review should be undertaken in the producing zones of the country. In 2015, to- ahead of an electrification programme commencing tal available supply was of 3,500MW and in the first in 2018. Given the need time needed to properly de- quarter of 2016 of 3,150MW. Estimates foresee an velop a new MYTO and the importance of ensuring average (for the whole sector) increase in tariff by that the DISCOs are creditworthy and able to attract 50% (including forex)7 to reflect the new available commercial financing for their normal business, the supply conditions, which is likely not going to be ap- review should begin early in 2017. proved by NERC.8 The newly approved MYTO 2015, covering the Financial readiness: Since privatization until the period to 2024, made no provision for electrification end of 2015, KEDCO itself has accumulated US$140 investment and, because of the “sculpting”, tariffs million in debts owed upstream for the supply4 re- are currently not covering for all operational costs. ceived and has received US$38 million in 2015 from The companies urgently need to make other invest- the Nigeria Electricity Market Stabilization Fund ments including metering, management and billing (NEMSF) as loans funded by the Central Bank of systems, and rehabilitation and upgrade of existing Nigeria (CBN) to pay upstream debtors. KEDCO networks and these will have a higher priority than currently has negative cash flows and as shown by expanded electrification. Although a bottom-up as- Figure A2 below, it is currently able to meet an aver- sessment of progress in loss reduction and efficiency age of only 40% of payment obligations to the bulk since privatization is not available for KEDCO nor trader (NBET). for other utilities, it is worth noting that the only Because of the “sculpting” introduced with known significant loss reduction capital expendi- MYTO 2015, KEDCO is expected to have cost-re- ture made by KEDCO was the purchase of 64,000 flective tariffs (with no under-recovery) by the start meters from the proceeds of the CBN NEMSF at the of 2018 and it will hence keep accumulating deficits beginning of 2016. until then.5 During the last round of tariff revision, DISCOs Like the other DISCOs, KEDCO’s financial posi- lamented the insufficient capex to meet the Mini- tion is also worsened by the removal of fixed charg- mum Performance Targets contained in the Per- es form MYTO 2015 and of MDAs debts, which in formance Agreements, but NERC didn’t allow for 110 Annexes an increase. In MYTO 2015 the capex allowance larized and not access provision to un-electrified was actually decreased by 20% and in the case of households. Planning should therefore also carefully KEDCO capex fell from US$ 23.5 million to US$ make the distinction between new connections and 19 million per year. NERC’s decision was based on regularized ones. the fact that DISCOs had not made use of the ca- pex allowance they’ve had so far. This is because in (ii) Revenue collection an environment where tariffs were non-cost-reflec- The majority of KEDCO’s ATC&C 49% losses are tive, DISCOs were unable to justify the borrowing due to collection issues (responsible for about 37% needed to fund capital expenditure and therefore to of ATC&C losses).9 KEDCO needs to implement an implement their business plans and invest in meter- aggressive meter deployment rollout and build the ing and other loss reduction activities. DISCOs are capacity to support new metered connections. The allowed to file for upward revisions if and when they Business Plan does not contain plans for metering are able to prove that they have sufficient funding lifeline (R1) costumers, whereas it is key that this sources for planned capital expenditure. category is also included to ensure billing of actual energy consumption over time and hence track mi- Technical readiness of KEDCO and the supply grations toward an upward consumption category, chain: three main issues will have to be tackled in particularly since R1 costumers are expected to be order to embark in an extensive access program the majority of new connections in the access pro- (i) business planning (ii) revenue collection (iii) in- gram. frastructure building. With the adoption of MYTO 2015 in February 2016, and the removal of fixed charges and MDAs (i) Business planning debts from the tariffs without a mechanism for de- KEDCO needs to improve its business planning ca- frayal, and the rejection by NERC of a further diver- pacity as Business Plan submitted at privatization sification of the R2 category, the liquidity and col- by KEDCO presents some numeric inconsistencies lection pressure has become even greater. Given the and leads to confusion in the actual values for the negative implementation record of the Credit Ad- Minimum Performance Targets. DISCOs also need vance Payment for Metering Initiative (CAPMI),10 to harmonize future investments with current ex- KEDCO should either build the capacity in-house penditure. or rely on trustworthy vendors. The business plan submitted at privatization was not based on sound estimates of ATC&C losses and (iii) Infrastructure building the meter deployment targets didn’t reflect a realis- KEDCO has limited experience of extending elec- tic price for meters. The average price of meter esti- tricity grids on any scale, and it has limited human, mated was of about $25, which compares low with material and technical resources for undertaking a the current price range of $160–220 (as indicated by major programme of connecting customers through the geospatial analysis and as per discussions with intensification or grid extension. It accepts that to a KEDCO), even when taking into account that the large extent the electrification work will need to be utility now plans to deploy smart meters only. contracted out to the private sector. Sound planning should to be based on a bottom- KEDCO will need capacity building to be able to up assessment of the utility’s investment needs. The supervise and manage a major electrification pro- geospatial analysis revealed that in order to achieve gramme. the Minimum Performance Target of 100% meter- The private sector in NW Nigeria is experienced ing, KEDCO will have to deploy about 1.5 million in undertaking electrification works, though not on meters in the next five years, a target that is 35% the scale necessary to achieve the electrification roll- bigger than the one contained in the Business Plan out needed for KEDCO. submitted at privatization, which envisaged the de- Kano has a strong manufacturing base and it has ployment of 512,164 meters. private companies that manufacture poles, overhead The Minimum Performance Target on new con- line steelwork and conductors for the electricity sec- nections indicated KEDCO’s plans to connect about tor. It also has private contractors who undertake 350,000 new customers. However, as per discussions electricity distribution works (procurement and with the utility, the majority is targeted households construction)11 typically working in NW Nigeria. were already consumers that needed to be regu- The economy in the NW of Nigeria has been under- Annexes 111 mined by security problems in recent years and the ects (NIPP) originally launched in 2005. The first private sector currently has underutilised resources.12 private sector power plant reached financial clo- An electrification programme would help boost the sure in December 2015 (Azura-Edo, part of a 2,000 economy and increase utilisation of staff and equip- MW IPP).14 ment of manufacturers and contractors. Some dis- The framework for attracting private investment tribution equipment is imported (e.g. transformers). in power generation exists (specifically, the whole- This is normally procured by KEDCO and by private sale tariffs available for generators are attractive) construction companies on the open market but Ni- and guarantees are available, and it must be assumed geria often faces bottlenecks at the ports and customs that in time there will be adequate generation capac- and this will inevitably result in some bottlenecks ity to satisfy the growing demand. The conservative that will impact the electrification programme at electrification plan for KEDCO described in Chap- times. This is a chronic problem in Nigeria. ter 2 in the main report is based around a relatively Private contractors typically provide in-house slow initial electrification rate that allows generation training for linesmen, fitters, jointers, etc. The In- capacity to catch up with demand over the next five dustrial Training Fund (ITF) is used for training or so years. The electrification plan anticipates a rel- engineers and technicians for more complex equip- atively modest additional 30 MW arising because of ment and processes. In the electricity sector, training the electrification programme by 2020 and 128 MW is provided by the National Power Training Institute by 2023. In the best-practice electrification scenario, of Nigeria (NAPTIN). NAPTIN was formerly part an estimated additional 60 MW of demand is antici- of PHCN but is currently owned by FGN and pro- pated by 2020, and 257 MW by 2023 and the geo- vides a range of training services under contract to spatial analysis revealed that by 2030, about 1 GW the electricity companies. It has a training facility on will be needed to support the rollout plan. the outskirts of Kano city that provides training for the electricity companies in the north-west of Ni- Transmission adequacy: The transmission system geria. This facility is equipped with modern equip- to the KEDCO franchise area has a transfer capa- ment. It does not currently provide training in the bility constrained to less than 250 MW. The maxi- skills needed for the expansion of the distribution mum demand that has actually been supplied was network (linesmen, fitters, jointers, etc.) but it has 286 MW. Because of the transmission constraint, space on the site to allow such training if requested KEDCO is not able to take its full 8% allocation of by the DISCOs or the private sector. Support for the generation from the wholesale market. A series of expansion of this facility would be valuable in en- transmission investments have been prioritised by abling the roll-out of the electrification programme the Transmission Company of Nigeria (TCN) to in the KEDCO service zone (and potentially also in relax the transmission constraints on the supply Kaduna service zone). The training facility might to KEDCO and to improve supply reliability. As also provide training suited to the development of with generation capacity, it must be assumed that isolated grids. transmission investments will be made and that the transmission network will be adequate to allow sup- Wholesale generation adequacy: There is currently ply to match demand in the KEDCO zone. Again, insufficient generation to meet consumer demand. the gradualist electrification programme described Wholesale generation is generally rationed to the in Chapter 215 with the first connections beginning DISCOs with KEDCO being allocated 8% of elec- in 2018 and growing slowly at first will allow time tricity available. Since privatisation, the availability for the transmission investments to be made. of existing generation plants has improved substan- tially and the supply to DISCOs has increased13 but generation shortages and load shedding remain Endnotes chronic. Furthermore, recent pipeline vandalism 1. With the exception of Kaduna, which was priva- attacks brought the available power supply from tized in 2014. 3500MW in 2015 to 3150MW at the beginning of 2. Discussions with KEDCO revealed that the for 2016, a value below 2014 levels (3300MW). In 2015, new connections the utility intended for the most KEDCO only received 5% of the allocated supply. part to regularize exiting ones. New generation projects in the pipeline are the 3. World Bank estimates, June 2016. FGN sponsored National Integrated Power Proj- 4. World Bank estimates, March 2016. 112 Annexes 5. World Bank estimates based on the MYTO model, 12. We understand that some factories used for man- March 2016. ufacturing poles and conductors are temporarily 6. According to Energy Markets and Rates Consul- closed but could be re-opened at relatively short tants (EMRC), formerly Mercados EMI, a con- notice. sultancy providing advisory services to Nigerian 13. Some DISCOs are said to be rejecting load. It is be- DISCOs. lieved that, despite high demand, it costs DISCOs 7. World Bank estimates, May 2016. more than they earn in revenues on electricity sold 8. A further increase in tariffs would also trigger to some consumer groups. This is largely because public discontent. of the high commercial, technical and collection 9. The baseline of losses integrated into the new losses and low tariffs. With the tariff increase in MYTO 2015 reports 37.4% of collection losses, February 2016 this situation may no longer be true. 6.8% of commercial and 13.5% of technical losses. 14. The facility is expected to produce 450 MW in the Note that the aggregate ATC&C losses of 48.7% is first phase, and then increase production up to not additive but it is defined by a formula. 2,000 MW. The commissioning was supported by 10. The Minister of Power, Works and Housing re- guarantees from the World Bank Group and con- quested NERC to stop the CAPMI scheme in April struction started in January 2016. For more infor- 2016 because meters were not being deployed. mation, visit: www.azurawa.com. 11. Their main clients were the REBs but this work has 15. Both the conservative and best-practice pro- partially fallen away following privatisation. There gramme build up gradually, though the conserva- is ongoing work with the local government and for tive scenario has a slower take-off. isolated schemes. Annexes 113 2 Customer Income, 2.1  Income and expenditure distribution Table A2 shows the level of expenditure in NW Ni- Expenditure and geria for income quintiles, broken down by type of Affordability expenditure.2 The analysis of affordability reviewed the available More detailed figures from the distribution of datasets to inform the access rollout program and the broader category Expenditure on non-food non- ensure that shared prosperity across the country is durable goods of the General Household Survey pursued during the design and implementation of (GHS) proxies for the distribution of the average ex- the programme. penditure in energy goods reported by Lighting Af- Current expenditure in energy (whether electric- rica and NIAF (of about 2,000 NGN/HH/month).3 ity or alternative sources, such as kerosene, battery The results of this are shown in Figure A3. lamps, etc.) can be used to assess people’s ability to At the standard residential tariff for KEDCO (R2 pay for electricity. Table A1 provides a summary of tariff – see Section 5.1) for 2020, 50 kWh would cost the average level of household expenditure on en- a household NGN 938 (US$ 4.69) per month.4 The ergy and a measure of how these values of average above implies that 49% of the population normally expenditure translate into kWh per month at the pay less than NGN 938 per month on electricity- standard residential tariff.1 type energy consumption. From a policy perspec- The measures of expenditure above, despite their tive, it suggests that 49% of the population may not limitations, provide similar results on the average be able to pay for electricity at the standard tariff. level of expenditure of households (about 2,000 It also suggests that 15% of the population may not NGN per household per month, equating to an av- even be able to afford the lifeline tariff of only NGN erage consumption of 83 kWh). 4/kWh (US$0.02). The following sub-sections provide additional details on the distribution of expenditure among potential electricity customers, and the affordability of electricity prices. Table A1  Current expenditure on energy Reported average Equivalent in kWh/ expenditure (NGN/HH/mo) month at the R2 tariffa Source Scope and limitations 1,773 69 General Household Average for NW region, includes all types of Survey (GHS), wave energy (for lighting, cooking, transportation, 2, post-harvest etc.), but excluding batteries and phone dataset charging (which, unfortunately, may be the (2012–2013), LSMS most relevant substitues of electricity. 2,258b 107 Lighting Africa Limited to Kano state, mainly Base of 2,375c Nigeria Insights Pyramid population domiciled in rural Study, August 2013 and urban locations (without electricity) – includes expenditure on rechargeable lamps, kerosene and petrol genstes. Does not include phone charging. 1,989 83 NIAF surveys Surveys in 3 rural villages in Jigawa state. Average expenditure in battery lamps, kerosene and phone charging. Sources: General Household Survey, Lighting Africa, and Nigeria Infrastructure Advisory Facility. a At KEDCO’s current tariff for R2 customers – see above. b Variable. c Total, including cost of purchase of device (e.g. lamp, genset). 114 Annexes Table A2  Expenditure in NGN/month Total Expenditure on non- Durable Energy Quintile expenditurea food non-durable goods goods expenditureb 0–20 10,876 683 374 0 20–40 16,625 1,749 813 400 40–60 23,050 3,355 1,386 1,200 60–80 35,049 6,342 2,483 2,400 80–100 331,114 243,343 33,300 61,000 Average 27,238 5,089 1,744 1,773 Source: General Household Survey. a Includes food, other non-durable goods, and durable goods. b Includes goods and services that are not strictly relevant to this analysis, as they will unlikely be replaced by electricity (e.g. petrol used in transporta- tion, firewood and charcoal used for cooking). 2.2  Geographical distribution Elsewhere there are areas with high incidence of Figure 7 shows the poverty rate (% of poor house- poverty, particularly in Katsina and Jigawa. holds) for the KEDCO service area based on re- search from Oxford University on behalf of the World Bank. This is based on geostatistical mod- Endnotes elling using geospatial covariates that are corre- 1. KEDCO data for R2 customers, May 2015, shows lated with poverty (e.g. travel times, population an average of NGN 22.8/kWh but this includes a density, aridity, night lights, etc.). The report indi- fixed charge of NGN 667/month and a price per cates a poverty headcount at the state level of 45% kWh of NGN 16.01. for Kano, 57% for Jigawa and 57% for Katsina. The 2. The questionnaire omitted expenditure on batter- poverty data was used by the Earth Institute to clas- ies (disposable dry-cell batteries or battery charg- sify households as having a potential demand for ing, including phone charging), which are signifi- electricity of 50 kWh per month or 100 kWh per cant to this analysis month. 3. This excludes cost of buying appliances (lamps, Figure A4 highlights that there are areas with- gensets) out poverty (the dark blue areas) around the cities 4. 50 kWh at NGN 16.01 per kWh plus NGN 667 per of Kano and Katsina with low incidence of poverty. month comes to NGN 1,467. Figure A3   Estimated distribution of relevant energy expenditure 5,000 4,483 4,500 Energy expenditure (NGN/month) 4,000 3,500 3,000 2,493 2,500 2,000 1,722 1,500 1,319 977 1,000 688 465 500 135 268 0 0 0% 20% 40% 60% 80% 100% Population percentile Annexes 115 Figure A4   Poverty rate (% of poor households) for the KEDCO service area Source: Nigeria Electricity Access Program (NEAP*) based on geospatial data from Oxford University (Gething & Molini). * Final Report, Geospatial Implementation Plan for Grid and Off-Grid Rollout (2015-2030), Earth Institute, October 2015. 116 Annexes Estimation of Cross-subsidy 3  zz 70% of the additional 3.7 million customers added by 2030 through intensification and grid to R1 Customers extension will be connected as R1 customers 3.1  The tariff regulatory framework zz These customers will remain as R1 customers, The regulatory framework determining electricity with consumption at 50 kWh per month for the revenues and tariffs is set out in the 2005 law1 and foreseeable future the tariff regulations have been developed by NERC zz KEDCO’s cost to serve R1 customers is the same using a building-blocks model to establish the al- as the cost to supply the average customer.4 lowed revenues and tariffs on a multi-year basis. zz The difference between KEDCO’s average tariff Allowed revenues for the DISCOs are calculated on and the R1 tariff is the required cross-subsidy. the basis of operating costs including depreciation on fixed assets plus rate of return on net fixed assets Following these assumptions, we forecast that the plus pass-through of elements such as the bulk pur- value of cross-subsidies required will increase steadily, chase tariff and the fees for TCN, NBET and NERC. reaching NGN 15 billion per year (US$ 77 million) At the start of the control period, the tariffs are fixed in 2030. This is a relatively large amount compared for the duration of the control period (with periodic with KEDCO’s annual revenues today (approximately adjustments for the non-controllable components) US$100 million billed, but significantly less collect- and the DISCOs are expected to manage their costs ed), but by 2030 this will represent a much smaller efficiently. If they can make above average profits share of the total. While the cross-subsidy amount by being cost-efficient, they are allowed to keep the steadily increases in absolute terms, the number of profits and the shareholders receive good dividends non-R1 customers and their electricity consumption but if DISCOs are inefficient, they make low profits also increases steadily, thereby increasing the base and the shareholders receive no or low dividends. across which the cross-subsidy can be collected. We In theory, if the capex programme implied by the calculate that the incremental amount needed on top electrification programme is reflected in the allowed of the average cost-recovery tariff to meet the cross- revenue calculations used to design the MYTO tar- subsidy will rise to NGN 0.7/kWh by 2030 (US$ iffs, and if the tariffs are affordable, then customer 0.003/kWh) or around 4% of KEDCO’s commercial revenues would be sufficient to allow the DISCOs to end-user tariff. Initially, however, the increase would make a respectable return on their investment and be more modest at around NGN 0.2/kWh in 2020. to service their debts and no further subsidy would The above assumes that consumption of non R1 be required. However, there is currently no allow- customers grows at 10% per year, allowing a large ance for an electrification programme in MYTO base of consumption from which to collect the 2015 and the tariff is not covering in full for operat- cross-subsidy. ing costs. While from the utility’s perspective, KEDCO should recover all costs at the aggregate level and be Tariff design limited to the current R1 3.2  provided with sufficient revenue to earn a reasonable and R2 categories rate of return on capital investment, it will be able to Annex 2.1 noted that large proportions of the popu- make higher profits by avoiding the connection of cus- lation of NW Nigeria could not afford the conven- tomers at the R1 tariff. When the maximum tariff the tional R2 tariff.2 We therefore assume that 70% of DISCO can earn from R1 customers is only NGN 4/ households will initially be connected as R1 cus- kWh and the cost of supply is over NGN 20/kWh, tomers but that on average they will migrate to the KEDCO will lose money on every unit sold at the R1 R2 tariff after 5 years.3 In this sub-section we con- tariff. A profit-maximising company will therefore sider the potential consequences of connecting large naturally attempt to avoid R1 customers. Therefore, numbers of R1 customers through the electrifica- it will be necessary to place some obligations on the tion programme. DISCOs to connect and supply these customers. This We model a connection scenario to determine is discussed further in Chapter 5 of the Report. the total requirement for cross-subsidy to new R1 connections, with the following assumptions: KEDCO’s proposed R2-lite and 3.3  R2-classic categories zz KEDCO serves approximately 70,000 R1 cus- As KEDCO observed in its tariff submission to tomers at the present time NERC, there is a large difference in monthly bills Annexes 117 between an R1 and an R2 customer. A household us- Endnotes ing 50 kWh on the R1 tariff will pay NGN 200 per month, while a household also using 50 kWh on the 1. Electric Power Sector Reform Act, 2005. R2 tariff in 2016 will pay NGN  1,013 per month.5 2. Though it is not reflective of the costs of supplying There will therefore be a large deterrent to customers residential customers, it is the closest approxima- using more than 50 kWh per month because of the tion available. step increase in their monthly electricity bill. Table 3. This is an assumption. KEDCO has relatively few 23 in Annex 2 shows that the conventional R2 tar- R1 customers compared with R2 and it is therefore iff is affordable by less than half of the population likely that customers relatively quickly exceed 50 whereas the R1 tariff is affordable by more than 85%. kWh per month. The R2-lite tariff proposed by KEDCO to NERC 4. This assumption is incorrect since the cost to sup- in its tariff submission offered an intermediate step ply residential customers is greater than the cost between R1 and R2-classic that makes the step less to supply all other customers, but it is a first ap- expensive, though still quite substantial. Unfortu- proximation. nately, this was rejected by NERC. 5. This is based on KEDCO’s approved R2 tariff for 2016. 118 Annexes 4 Transitional Electrification tion access ‘tiers’3 whereby electricity access is not simply defined by reference to a grid connection or 0ptions not, but is graduated through tiers 1 to 5 where tier 1 4.1 Choices households have access to simple low wattage light- The main choices for pre-grid electrification are iso- ing (solar, rechargeable batteries or conventional lated mini-grids, SHS and pico-solar lighting prod- batteries) and phone recharging through to tier 5 ucts. The choice between these options depends where households have access to a reasonably high on how long it will be until the main grid arrives, quality, continuous, and reliable electricity supply population densities, load densities and capital con- that is capable of powering significant electrical ap- straints. The choice is discussed further in Annex pliances such as electric irons, fridges and TVs. The 4.3. Pico-solar lighting products are ideal for bridg- tiers have multiple attributes of capacity (W or kW), ing the gap in the short-term until power arrives; duration (hours/day), reliability (interruptions per this can be for a period of a year up to perhaps three week), quality (stable voltage), legality (a formal years. Even after the grid arrives, these products will connection, or an informal or illegal one) and safety still have value in providing lighting and battery (see A5 below). charging during power cuts from the main grid. If We assume that ‘un-electrified’ households the main grid is not expected to arrive within five will have access to pico-solar lighting (and battery years, but is expected between five and ten, then a charging) solutions through local markets. Con- mini-grid could provide a transitional arrangement. sideration could be given to supporting this group If the main grid is not expected for many years be- of products perhaps in areas where market pen- cause the population is highly dispersed, distributed etration is low—particularly to areas where poverty solar will be the preferred solution in this case. levels are greatest. Support need not necessarily be The regulation governing IEDNs (see Section provided through subsidies to the product itself, 6.1) will be revised and will hopefully introduce a though this is an option, but potentially through framework that makes it attractive to develop iso- support to the marketing and distribution channels lated grids1 even where they may be engulfed by the for pico-solar lighting. Lighting Africa has support- KEDCO grid in the foreseeable future. Assuming ed the promotion of pico-solar lighting products to this is the case, the optimum policy on electrifica- the base-of-the-pyramid households for a number tion technology is then determined by economic of years but is no longer proposing direct subsidies principles and financing constraints. This recog- for the products. Pico-solar lighting is an excellent nises that electrification based on isolated grids short-term product providing lighting and mobile and distributed solar may face fewer financing con- phone charging until more substantive solutions straints than grid electrification provided that the can be introduced. We assume this is the solution framework is appropriate.2 to be adopted for those households who will remain A decision tree for this calculation is provided in ‘un-electrified’. The Lighting Africa Market Study4 Figure 9 in Annex 4.3. conducted in 12 Nigerian states including Kano, found that the majority of households were aware 4.2  Electrification to target poverty of pico-solar lighting products. We could not find The geospatial distribution of poverty is described information from the survey on the penetration of in Annex 2.2. Further analysis of the geospatial data solar in the market in the KEDCO zone or in NW through correlation analysis reveals that the areas Nigeria in general, but the publicly available find- with high poverty risk are the areas furthest from ings indicate some reservations, particularly among the existing grid and with the lower population den- urban households, around the limitations of pico- sities and the highest costs of grid electrification, solar lighting products. and therefore these are the areas least likely to be connected to the KEDCO grid early in the electrifi- 4.3  Off-grid electrification strategies cation programme. This suggests that programmes Below we consider the choice between pre-electrifi- designed to support off-grid electrification will have cation strategies: important social dimensions because these are also likely to be areas with high poverty. zz wait and do nothing Our approach to solutions for the off-grid com- zz distributed solar (SHS and pico-solar), or ponent of the programme is built around electrifica- zz isolated mini-grids Annexes 119 TABLE ES.1 Figure A5   Multi-tier matrix for access to household electricity supply Multi-tier Matrix for Access to Household Electricity Supply TIER 0 TIER 1 TIER 2 TIER 3 TIER 4 TIER 5 Very Low Low Power Medium High Power Very High Power Power1 Power Min 50 W Power Min 800 W Min 2 kW Min 3 W Min 200 W AND Daily Min 12 Wh Min 200 Wh Min Min Min 8.2 kWh Capacity 1.0 kWh 3.4 kWh 1. Capacity Lighting of Electrical lighting, 1,000 lmhrs air circulation, OR Services per day television, and and phone phone charging charging are possible Hours per day Min 4 hrs Min 4 hrs Min 8 hrs Min 16 hrs Min 23 hrs 2. Duration Hours per ATTRIBUTES Min 3 hrs Min 4 hrs Min 4 hrs Min 1 hrs Min 2 hrs evening 3. Reliability Max 14 Max 3 disruptions disruptions per week of total per week duration < 2 hours 4. Quality Voltage problems do not affect the use of desired appliances 5. Affordability Cost of a standard consumption package of 365 kWh per annum is less than 5% of household income 6. Legality Bill is paid to the utility, prepaid card seller, or authorized representative 7. Health and Safety Absence of past accidents and perception of high risk in the future 1 The minimum power capacity ratings in watts are indicative, particularly for Tier 1 and Tier 2, as the efficiency of end-user appliances is critical to determining the real level of capacity, and thus the Source: electricity .services that can be performed. type ofESMAP a a Beyond Connections: Energy Access Redefined, Conceptualization Report, ESMAP, June 2015. We cannot offer a precise time criteria to decide and the rule-of-thumb parameters would need to be when to choose between do nothing, distributed so- updated. lar (SHS or pico-solar) or mini-grids. The mini-grid Off-grid electrification involving SHS and pico- is a more expensive transitional solution but if the solar lighting products has a relatively low capital mini-grid can be incorporated into the main grid, cost but the equipment has relatively short lives. the investment will not be lost when the main grid Pico-solar lighting solutions in particular are cheap arrives. It is a trade-off between having no power and have a life of only perhaps 5 years because of the for, say, five years versus introducing a more ex- current battery technologies, and this makes them pensive mini-grid in, say, one year. This requires a particularly suited as interim solutions for bridging complex economic cost-benefit analysis, possibly on the gap until power arrives; this can be for a period a case-by-case basis. of a year up to perhaps three years. Even after the An example of a study in India that attempted grid arrives, they will still have value in providing to provide a systematic basis for choosing was un- lighting and battery charging during power cuts dertaken in India and published in Energy Policy: A from the main grid. techno-economic comparison of rural electrification SHS have higher capital costs than pico-solar based on solar home systems and PV microgrids.5 lighting and longer economic lives. For areas that However, the primary focus was the choice between do not currently have electricity but are expected to grid electrification and isolated grids rather than a be electrified within a few years, investment in SHS pre-grid electrification programme. Moreover, costs could incur relatively high capital costs (compared of solar PV have declined substantially since 2010 with pico-solar lighting) that may be largely wasted 120 Annexes Figure A6   Decision tree for non-KEDCO eas”. These are expected to be electrified within five grid electrification years. In Namibia these were excluded from the off- grid masterplan except where there were delays in Distributed Optimum grid electrification. In Kenya, an area that is not ex- Develop solar KEDCO grid economic choice distributed of technology pected to be electrified within 10 years was consid- solar ered suited to off-grid electrification (but because of (if no constraints)? the absence of a grid roll-out plan, a criterion of 50 Financing km distance from the main grid was also adopted Extend No KEDCO constraints to as an alternative). KEDCO grid grid connection? Population densities in Nigeria are generally Yes higher than in Kenya and Namibia and grid cover- age is very widespread so that few households are far Financing Develop No constraints to from the existing grid. The rule-of-thumb policies mini-grid mini grid as in Kenya and Namibia ignore the benefits of devel- interim solution? oping isolated grids using grid technical standards Yes that can then be absorbed into the main grid and Develop fully compensated by KEDCO, or kept as small- distributed power distributors (SPDs) and purchase electricity solar wholesale from KEDCO. Endnotes once the grid arrives. They may have some residual 1. i.e., financial compensation from KEDCO to the value when the grid arrives as backup for grid inter- grid developer following takeover by KEDCO or ruptions or to supplement the supply from the grid the conversion of the isolated grid to a small power or potentially they could be recycled for use in other distributor (SPD), plus a feed-in tariff for renew- areas.6 However, SHS may also be suited to more able energy purchased from the generator. remote areas with low population and load densi- 2. Experience in Cambodia is relevant here. Elec- ties for whom the geospatial analysis reveals that trification initially took place successfully with a neither grid connection nor isolated mini-grids are large number of isolated grids that are now being economically justified at least not within the time connected to the main grid as the main extends horizon of 2030. further outwards. The isolated grids may be con- Investment in isolated grids in areas that will be nected as SPDs or may be fully absorbed into the connected in a few years’ time will not be wasted main grid. if those isolated grids can simply be connected into 3. Beyond Connections: Energy Access Redefined, the main grid when it arrives. The generation plants Conceptualization Report, ESMAP, June 2015. used to supply the isolated grids could, when the 4. Lighting Africa, Nigeria Consumer Insights Market isolated grid is connected to the main grid, be re- Study, 2013. located to other isolated areas or alternatively they 5. A. Chaurey, T.C.Kandpa, A techno-economic could be used to inject power into the main grid comparison of rural electrification based on solar and/or support the network in that area.7 These gen- home systems and PV microgrids, Energy Policy, eration investments will not then be wasted though 38(2010)3118–3129. if relocation takes place this will incur some cost 6. Though experience elsewhere suggests that the re- (relocation will not in any case be possible for some use value of SHS is relatively low because of rapid technologies such as small hydro). technological development and the deterioration From the perspective of optimum economic in the batteries and other equipment. policy, the choice of interim technologies for areas 7. Solar plants that are suitably designed can be relo- that will eventually be connected to the KEDCO cated. Small hydro can be used to inject power into grid is therefore complex. One way to approach the existing grid. this is to categorise areas as in Namibia’s off-grid 8. Off-grid energisation masterplan for Namibia, masterplan8 with one category called “pre-grid ar- January 2007. Annexes 121 5 Independent Electricity The regulations currently allow and/or require: Distribution Networks zz Cost-reflective tariffs Under Nigerian regulations, isolated grids (also known zz Meeting ‘relevant Technical Codes and stan- as mini-grids) are known as Independent Electricity dards’ Distribution Networks (IEDNs). They are currently zz Compliance with the System Operator’s require- regulated under the Nigerian Electricity Regulatory ments (if connected to the main grid) Commission (Independent Electricity Distribution zz Provide non-discriminatory open access to its Networks) Regulations, 2012, but we understand that distribution system by any other Licensee, if it these regulations are currently under review, with has the capacity to do so support from GIZ. At this stage, it is uncertain when zz No increase charges to accommodate losses revised regulations will be made available, but we an- above the MYTO limit ticipate this to happen sometime in early 2016. zz Meter any new customers Some important characteristics of an IEDN un- zz Apply the connection charge approved by NERC1 der current regulations: zz Meet voltage standards based on the capacity of the generation in the system zz May be developed, owned and/or operated by a DISCO or other entity In addition, a relevant reference in the Electric zz Include both purely isolated systems and those Power Sector Reform Act, 2005, states: connected to existing DISCO networks zz May have their own embedded generation zz Distribution systems with capacity under 100 source, or purchase power from the DISCO op- kW do not require a license erating the network to which it is connected zz Allowed to operate within a DISCO’s concession area, provided there is no other distribution sys- Endnotes tem ‘within the geographical area’ 1. Currently NERC does not approve connection zz [Must be at least 5 MW] charges for residential customers. 122 Annexes Examples of International 6  Until the 1990s, rural electrification policies were implemented largely at the State level, using State Experience budgetary resources. Electrification programmes Nigeria is unusual in Africa, though not unique, in had been introduced during the 1970s, 1980s, 1990s having privatised electricity distribution companies. and early 2000s but the discussion below focuses on The expansion of electricity access through electric- the last programme that was began in 2003—the Luz ity grids in developing countries is typically handled para Todos (Light for All, or LpT), which achieved by state-owned companies or through agencies virtual universal access to electricity by 2010. created for the primary purpose of electrification. LpT is based on an obligation for concession- However, international experience suggests that aires to provide universal electricity access using expansion of access to electricity can be effective in substantial federal and state resources channelled to countries where electricity distribution is privatised. the companies, and on low electricity tariffs for low- A report prepared by IFC1 notes that: income and rural consumers. Lpt was to provide 2 million new rural connec- A rigorous 2009 study looked at data on 250 tions, subsequently revised to 3 million, over a five electricity companies across 50 countries.2 The year period to 2008. Each household was also to re- study found that utilities that had been priva- ceive power plugs, lamps, and other necessary ma- tized, or which operate under PPPs, extended ac- terial needed to undertake the internal wiring and cess more rapidly than publicly owned utilities. lighting. The deadline was later extended to 2010. ANEEL (the regulator) set and verified the an- The IFC report also notes that: nual electrification targets for the companies while Almost all examples of grid-based electrifi- Eletrobrás (the Federally-owned holding company cation business models have involved a PPP owning a large part of the generation plant and the with some degree of capital subsidy to attract transmission grid) managed the electrification pro- private investment. Governments have most gramme including carrying out the technical and often awarded contracts with legally binding financial analyses of the connections to be installed coverage targets and quality-of-service re- by the companies and the allocation of funds to the quirements. This sometimes comes with public companies and the monitoring to ensure the claimed financing to help cover the cost of such obliga- installations had been made. MME co-ordinated the tions. This subsidy is most often allocated on LpT programme and set the policies governing it. the basis of the lowest-cost but highest-quality The LpT programme mainly targeted those liv- service offering, and is applied to cover the vi- ing in the northern and north-eastern states where ability gap on capital but not operating costs. electricity access at the beginning of the programme was lowest. These two regions accounted for more International experience therefore offers some than 75% of the planned installations. useful lessons for the expansion of electricity in Ni- The overall cost of LpT was around US$ 7 bil- geria. An example of Brazil is provided below. Other lion (original estimates were US$ 4.2 billion). It was examples of countries that have combined substan- funded largely by Federal and State governments in tially increased electricity access with private elec- the form of grants and concessionary loans to the tricity supply include Chile and India. concessionaires. The State governments’ contribu- tions averaged 13% of the total capital costs while 6.1 Brazil the Federal government was the main source of Brazil, like Nigeria, has a large population (approxi- funding (72%) through Global Reversion Reserve mately 190 million) and a Federal and State admin- (RGR) which provided grants and concessionary istrative structure. By 2009 Brazil had reached an loans. RGR is funded by annual levies on the con- overall electrification rate of 98% achieved largely cessionaires supplemented by funds from various through grid extension. Electricity distribution is other sources (payments for the use of public as- mainly privately operated through geographically sets, fines received by ANEEL). The concessionaires’ based concession arrangements. The Ministry of equity participation in financing the electrification Mines and Energy (MME) is the policy making en- was around 15% of the capital cost. No connection tity for the power sector and the companies are regu- charges were levied on rural consumers. Operating lated by the Electricity Regulatory Agency (ANEEL). costs for rural consumers were to be covered by the Annexes 123 utilities through general electricity tariffs. The tariffs lowest subsidy required per user. In some cases, this were subsidised for consumers with low consump- created a competition among the private utilities to tion. Around 35% of all consumers have low con- find innovative ways of reducing operational costs sumption and benefit from subsidised tariffs. These to receive the contract. This helped lower the cost of represent an even higher proportion in rural areas. rural electrification in some areas. In others, where no competition existed, the private utility some- 6.1.1  Key lessons learned times deliberately adopted assumptions designed zz Rural electrification access, whether undertaken to increase potential profit. As a response, PER ad- by the private sector or the public sector, will opted standard measures, based on local data, for need substantial external financial support. subsidy calculations. zz Widened electrification access can go hand-in- The aid offered by PER was constructed in a way hand with privatised distribution. to help utilities during the first stages of implemen- zz Electrification targets need to be set for the dis- tation, and then decrease with time. Due to Chile’s tribution concessionaires. long history with private utilities, a clear set of rules zz A framework is needed to monitor the connection and standards for infrastructure was already in place. of rural households and to disburse funds based This eased the transition into subsidised rural electri- on verified connections of designated consumers. fication projects as most problems and disputes could be resolved by referring to standards and precedents. 6.1.2  Information sources The Chilean National Energy Commission (CNE) zz Comparative Study on Rural Electrification Poli- was the central entity responsible for the design of cies in Emerging Economies, Keys to successful PER and allocation of funds to regional governments policies, IEA, Alexandra Niez, 2010. who then allocated them on a project basis. 6.2 Chile 6.2.1  Key lessons learned Chile has a long history of rural electrification as lo- The need for a clear and transparent project assess- cal cooperatives were formed as early as the 1930s ment methodology is vital to this type of a program. to support agricultural development. The national It limits political and commercial influence on the distribution companies were split up and privatised program and makes sure projects are ranked on the in the 1980s but did not hold an exclusive right to basis of merit. serve customers. Electrification rates increased Governmental support is very important to the gradually under private ownership and in 1990 rural credibility of a program. CNE’s role in PER was vital coverage reached just under 50% of households. The as it provided a leadership and monitoring role while Chile Rural Electrification Program (PER) aimed at maintaining authority within the regional govern- increasing rural electrification was implemented in ments. CNE built enough public and political mo- 1994 and was supposed to increase rural electrifica- mentum for the program to continue across admin- tion coverage from 50% to 75% by the year 2000. istrations and shifts in Chile’s political landscape. The program offered governmental subsidies to pri- By adopting construction and material stan- vate entities in order to incentivise rural electrifica- dards, construction costs can be kept at a minimum. tion. PER was given sufficient authority to develop and guide the policy initiative and long-term gov- 6.2.2  Information sources ernmental goals were established. A strict project zz Integrated Transmission Planning and Regulation selection method was created and built on top of the Project: Review of System Planning and Delivery, already stable private distribution companies and Electric Policy Research Group, Imperial College cooperatives. The goal of 75% electrification was London/University of Cambridge, 2013 reached in 1999 and due to the program’s success a zz Challenges of power transmission expansion in a goal of 90% electrification by the year 2005 was set. fast growing country, Prof. Hugh Rudnick, Pon- The project selection methodology ruled out tificia Universidad Católica de Chile, Workshop all projects which were assumed to have a positive on International Experience in Transmission IRR as it provided sufficient incentive for the private Planning and Delivery, Imperial College, Lon- market to develop. The selection method accounted don, 11–12th January 2013 for economic benefits of electrification within the zz Market Based Transmission Planning: Chilean Ex- region and projects and utilities rated based on the perience, Juan Carlos Araneda, Transelec, Work- 124 Annexes shop on Transmission Network Security Stan- Grameen Vidyutikaran Yojana (RGGVY) scheme and dards, Imperial College London, March 9th, 2009 the Remote Village Electrification (RVE) programme. zz Electricity distribution tariffs, the Chilean Expe- The latter focused on off-grid electrification and non- rience, Hugh Rudnick, Pontifícia Universidad grid solutions. The RGGVY scheme was aimed at grid Católica de Chile, International Seminar on electrification and is the focus of this case study. Electricity Tariffs, Brazil, June 2009 zz International transmission pricing review, Fron- 6.3.1  Rajiv Gandhi Grameen Vidyutikaran tier Economics, a Report prepared for the New Yojana (RGGVY) scheme Zealand Electricity Commission, July 2009 Launched under the “Power for all by 2012“ initia- tive, the RGGVY programme involved a major grid 6.3 India extension and reinforcement of rural electricity India has the largest rural population in the world, infrastructure. The primary approach was through totalling 876 million people in 2014, making rural grid extension, with stand-alone systems if grid ex- electrification a major challenge. One of the major tensions were not feasible. barriers to rural electrification expansion has been a The policy initially aimed to provide electricity general lack of electricity generating capacity in In- access for all households (an additional 87 million dia. Technical and commercial electricity losses also households) by 2009 in the without subsidy for rank among the highest in the world and have acted households above the poverty line, but the rollout as a barrier to electrification. was slow and was extended. Only 30% of household The Electricity Act of 2003 compelled the utili- connections and 51% of villages targeted under the ties to supply electricity to all households, includ- initial plan had been achieved by 2009. The main ing rural areas. The National Electrification Policy reason for the delay was the high technical and com- of 2005, the Rural Electrification Policy of 2006, and mercial losses in India’s rural distribution network, the National Tariff Policy of 2006, were all designed which meant that utilities were disinclined make ru- to encourage rural electrification efforts. Addition- ral electrification connections. ally, they improved the financial and institutional As the RGGVY programme was refined, the cen- status of the state utilities, generation, transmission, tral and state governments were given joint respon- and distribution. This included unbundling state sibility for rural electrification, with state govern- utilities, widening the scope for state government ments required to prepare rural electrification plans action in rural electrification efforts. The Electricity that outlined methods and electrification technolo- Act of 2003 also increased competition by giving the gies. Plans were then coordinated across state gov- private sector access to all power sector operations, ernments and utilities by the Rural Electrification including investing in rural electrification projects. Corporation Limited (REC). Administrative mechanisms were established to al- 90% of funding was provided by the central Min- low for the private setup of decentralised generation istry of Power (MoP), with state governments cover- projects and stand-alone systems. ing the rest through their own funds or loans through Institutional and regulatory reforms undertaken the REC or other institutions. State governments over the past 15 years have included unbundling the were then responsible for implementation through State Electricity Boards (SEBs), increasing private their state power utilities, with the MoP directing the sector involvement in generation, transmission, and states to establish Coordination Committees to track distribution, and looser rules on electricity tariffs. progress and identify issues. Milestone-based moni- These reforms also initiated the “Power for all by toring mechanisms were put in place from project 2012“ goal, which aimed to ensure sufficient power approval to completion, including a web-based to achieve GDP growth targets, reliability, quality, monitoring system at the village level, and with the optimum costs, and commercial viability. release of funds being dependent on milestones be- Rural electrification accelerated under the 11th ing met. Independent, random evaluations were also Five-Year Plan (ending March 2012), which provid- used to verify the connections claimed. MoP noted ed both political will and funds. The Plan allocated that progress in rural electrification projects im- US$241 billion for electricity including, with US$65 proved with these mechanisms in place. billion for generation and US$30 billion for transmis- By 2012, India had reached an urban electrifica- sion and distribution for rural areas. Two electrifica- tion rate of 93%, but only 53% for rural areas, bring- tion programmes began in 2005: the Rajiv Gandhi ing an overall electrification rate of 65%. As of 2015, Annexes 125 India claimed 97% of villages were electrified, but the household is eligible for refinancing from IDCOL a more stringent definition of rural electrification at the prevailing market interest rate of 6–9 percent, based on households connected would lower this with a 5/7-year repayment period and a 1–1.5-year rate to approximately 70%. grace period. Partnering organizations are responsi- ble for collecting payments, providing maintenance, 6.3.2  Key lessons learned and training customers in both operation and main- High levels of losses and poor revenue collection is tenance. Beneficiaries are given a buy-back guarantee a significant barrier to enhanced electricity access. with the option of selling their system back to IDCOL Notwithstanding the privatised distribution at a depreciated price if a grid connection is obtained companies in India, there is a need for state funding within a year of purchase, however most customers of electrification access. have preferred to hold on their solar system as grid It is possible to adopt different technical stan- supply remains unreliable. dards for different states. Use of milestone-based monitoring improved ru- The World Bank Electricity Network ral electrification progress, with the release of funds Reinforcement and Expansion Project (ENREP) made dependent on states reaching milestones The Electricity Network Reinforcement and Expan- sion Project (ENREP), approved in 2012, targets the 6.3.3  Information sources private sector-led development of stand-alone renew- Information derived largely from Comparative able energy and energy efficient products in Ethiopia. Study on Rural Electrification Policies in Emerging The design of the financing mechanism creates a mar- Economies, Keys to successful policies, IEA, Alex- ket-driven, private sector-led approach and addresses andra Niez, 2010. the following main issues to enhance the market for renewable energy in Ethiopia: access to finance at Off-grid developments: Bangladesh 6.4  relatively lower cost of capital, access to foreign cur- and Ethiopia rency, and improvements to the general lending envi- The Bangladesh SHS program has been widely ac- ronment (e.g. fair-market collateral values). knowledged as the most successful national off-grid As a result, ENREP’s design entails a US$20 mil- electrification program in the world. Since its incep- lion credit line (as a Financial Intermediary Loan) tion, more than 3 million SHSs have been installed, for renewable energy and energy efficiency products two-thirds of which in the last 3 years and reaching administered by the Development Bank of Ethiopia 100,000 installations a month. The programme was (DBE). The credit line has two main elements: retail developed under The Rural Electrification and Re- lending to private sector enterprises and whole sale newable Energy Development World Bank project. lending to the microfinance institutions. There are The programme is managed by Infrastructure De- no limitations placed on the technologies/products velopment Company Limited (IDCOL), a semi-gov- being supported, so long as they are of approved ernmental infrastructure finance organization, which quality standards (e.g. Lighting Global). works through a pool of partnering microfinance in- To date, ENREP’s credit line has been a huge stitutions and it demonstrates the feasibility of having boost to Private Sector Enterprises and has resulted beneficiaries pay for a substantial portion of the SHS in the local sale of almost 250,000 (15,000 targeted asset in affordable instalments (quality standards are by the project) Lighting Africa quality verified so- vetted by a technical standard committee). lar portable lanterns, is on track surpass 2 million SHS systems are affordable through a combination products by the end of 2016, and provided 750,000 of consumer credit/refinancing and (declining) sub- people with access to modern energy services. sidies. The idea was to bring monthly expenditures as close as possible to existing household spending on kerosene and dry cells. Partner organizations provide Endnotes microfinance loans to households, who are required 1. From Gap to Opportunity: Business Models for to make a down payment equivalent to 10–15 per- Scaling-up Energy Access; IFC, undated, probably cent of the cost of the system. The remainder is re- 2012. p.111. paid in 2–3 years at prevailing market interest rates 2. Does Private Sector Participation Improve Perfor- (typically 12–15 percent). Sixty to eighty percent of mance in Electricity and Water Utilities? Gassner, the credit that the partner organization extends to Popov, and Pushak, World Bank, 2009. 1818 H Street, NW Washington, DC 20433 USA Telephone: +1 202 473 1000 Internet: www.worldbank.org