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POVERTY ALLEVIATIONTHROUGH CLEANER ENERGYFROM AGRO-INDUSTRIES IN

AFRICA - PACEAA

RURAL ELECTRIFICATIONPLAN

GICIYE SHP, RWANDA

Draft v.1.0

PACEAA – Rural Electrification Plan tied to Giciye SHP, Rwanda –D3 Report August 2009

IED – Innovation Energie Développement 2

IED reference: PACEAA/06-027

IED

Innovation Energie Développement

2 chemin de la Chauderaie

Francheville 69340, France

Tel. +33 (0)4 72 59 13 20

Fax. +33 (0)4 72 59 13 39

E-mail: [email protected]

Version 1 Version 2

Date 13/11/09

Written by AJ & LB

Reviewed by DRM

Approved by DRM

Distribution level limited

PACEAA – Rural Electrification Plan tied to Giciye SHP, Rwanda – D3 Report November 2009


TABLE OF CONTENT

1 EXECUTIVE SUMMARY ______________________________7

2 GENERAL INTRODUCTION ___________________________9

2.1 Background & Objectives______________________________________________9

2.2 Presentation of the project area _______________________________________11

2.3 Electrification status of the area _______________________________________12

2.4 District level plans and ongoing RE projects in the area ___________________13

2.5 Overall presentation of the methodology________________________________14

3 IDENTIFICATION AND RANKING OF LOAD CENTRES ____15

3.1 Objective __________________________________________________________15

3.2 Definition of “load centres” ___________________________________________15

3.3 Ranking method ____________________________________________________16

3.4 Results ____________________________________________________________17

4 LOAD FORECAST __________________________________19

4.1 Objective __________________________________________________________19

4.2 Methodology _______________________________________________________19

4.3 Assumptions and parameters _________________________________________19

4.4 Results ____________________________________________________________21

4.4.1 Detailed results __________________________________________________ 21

4.4.2 Maps for the whole area ___________________________________________ 24

5 SUPPLY OPTIONS _________________________________26

5.1 Hydropower ________________________________________________________26

5.2 Decentralised small-scale renewable energy projects _____________________27

6 RURAL ELECTRIFICATION PLANS____________________28

6.1 Proposed plan ______________________________________________________28

6.2 Network design _____________________________________________________30

6.3 Costing ____________________________________________________________31

6.3.1 Unit costs_______________________________________________________ 31

6.3.2 Results_________________________________________________________ 32

6.4 Financial Analysis ___________________________________________________33

6.4.1 Objective _______________________________________________________ 33

6.4.2 Methodology ____________________________________________________ 33

6.4.3 Parameters and assumptions _______________________________________ 34

6.4.4 Results – business as usual ________________________________________ 36

6.4.5 Capability to pay _________________________________________________ 37

6.4.6 Results – with subsidies ___________________________________________ 37

6.4.7 Sensitivity studies ________________________________________________ 39



6.5 Economic Analysis __________________________________________________41

6.5.1 Economic Internal Rate of Return ____________________________________ 41

6.5.2 Levelized cost ___________________________________________________ 41

6.5.3 Comparison with the grid___________________________________________ 41

ANNEX’s 42



LIST OF FIGURES

Figure 1: PACEAA rural electrification project sites in East Africa ............................................. 10

Figure 2: Muhumyo village at 3,7 km from the Tea Factory of Rubaya represents an interestingopportunity for rural electrification ...................................................................................... 12

Figure 3: Map of RMT Giciye Hydropower Project, with line extension to Vunga ...................... 13

Figure 4 IPD calculation process ................................................................................................ 16

Figure 6 Results of spatial analysis............................................................................................. 17

Figure 7 Average daily load curve in W for the first year (without technical losses)................... 21

Figure 8 Average daily load curve in W for the20th year (without technical losses) .................. 22

Figure 9 Average daily load curves for the first, 10th

and 20th

year (without technical losses) ... 22

Figure 10 Evolution of yearly consumption and peak demand during the planning period (inc.technical losses) ................................................................................................................. 22

Figure 11 Evolution of LV and MV clients during the planning period (inc. technical losses)..... 23

Figure 12 Yearly consumption in the project area (year 1) ......................................................... 24

Figure 13 Yearly consumption in the project area (year 20) ....................................................... 25

Figure 14 Breakdown of hydro output in year 1 .......................................................................... 26

Figure 15 Breakdown of hydro output in year 20 ........................................................................ 26

Figure 16 RE plan around Nyabihu and SHP ............................................................................. 28

Figure 17 RE plan around Nyabihu and SHP ............................................................................. 28

Figure 18 Project cash flow......................................................................................................... 36

Figure 19 Breakdown of operation costs over the planning period............................................. 37

Figure 20 Evolution of retail tariffs to reach financial equilibrium, under different levels of subsidy............................................................................................................................................ 38

Figure 21 Evolution of retail tariffs to reach financial equilibrium, under different levels of subsidywith lower purchase tariff.................................................................................................... 38

Figure 23 Average retail tariffs under different scenarios and different levels of subsidy .......... 40



ACRONYMS

AfDB African Development Bank

AFREPREN/FWD Energy, Environment and Development Network for Africa

CECB Central Engineering Consultancy Bureau

CFL Compact Fluorescent Light bulb

EATTA East African Tea Trade Association

EDPRS Economic and Development Poverty Reduction Strategy

EC European Community

EIRR Economic Internal Rate of Return

ESCOM Electricity Supply Corporation of Malawi

FIRR Financial Internal Rate of Return

IED Innovation Energie Développement

IPD Indicator for Potential Development

GEF Global Energy Fund

GTIEA Greening the Tea Industry in East Africa project

HDI Human Development Index

KPLC Kenya Power & Lighting Company Limited

LRMC Long Run Marginal Cost (of the grid)

MINALOC Rwandan Ministry of Local Administration

MININFRA Rwandan Ministry of Infrastructure

O&M Operation and Maintenance

PACEAA Poverty Alleviation Through Cleaner Energy from Agro-industries in Africa

PMO Project Management Office of GTIEA

RE Rural Electrification

RECO Rwanda Electricity Company

RMT Rwanda Mountain Tea

RURA Rwanda Utilities Regulatory Agency

SHP Small Hydro Power Plants

STEG Société Tunisienne de l’Electricité et du Gaz

UNDP United Nations Development Programme

UNEP United Nations Environment Programme

PHYSICAL UNITS

LV – MV low – medium voltage

kV kilo Volts

kW – MW electrical power in kilo – mega Watt

kWh – MWh electrical energy in kilo – mega Watt hour

kVA active power in Volt Ampere

Exchange rate in 29th

September 2009: 1 USD = 565 RWF



1 EXECUTIVE SUMMARY

The project area lies in the North-Western part of Rwanda, across Nyabihu and Ngororerodistricts.

Rwanda Mountain Tea plans to invest in a small hydro scheme (4.5 MW) on the Giciye river.Power would be injected on the nearby grid and sold to RECO at an agreed feed-in tariff.Wheeling agreement will be negotiated to ensure Tea Factories benefit from the cheaper hydropower.

In terms of positive side-effects of the project on electricity access in the area, RMT has alreadyagreed with MININFRA to build a line to Jomba health centre and Vunga town, which arepresidential promises.

In addition to these two villages and as part of the PACEAA project, those communitiescultivating tea and living in close proximity to the tea factory’s (Rubaya and Nyabihu) and theproposed SHP scheme should also benefit from the proposed rural electrification plan.

Since both tea factories are located far from the hydro site, and RECO lines are covering theseareas, it is suggested to extend lines from the utility grid and use the power wheeling agreementwith the tea factories to benefit from the cheaper hydropower.

Figure 1 RE plan around Nyabihu and SHP

Figure 2 RE plan around Rubaya



In total, the following load points are targeted :

- 12 trading centres (including Muhumyo, which is cited as a priority by Ngororeroplanning office)

- More than 3000 people

- 5 primary schools, two secondary schools and 1 health centre

- 292 commercial activities expected shortly after electrification

- 229 customers in year 1 and 739 in year 20

It has been assumed that most demand would be for productive and social uses whilst domesticdemand would account for only 9% to 17% of total demand over the planning horizon, due tothe overall low household consumption rates. Targeting productive and social services willensure that basic services are provided to all.

The Rural Electrification would account for a negligible share of the hydro output:

8% 1%

91%

Tea factories

Rural electrif ication

RECO

Figure 3 Breakdown of hydro output in year 1

Investment costs of the project including meters, transformers, switches, 8.9km of MV lines and3.3km of LV lines, would amount to 567 800 USD in the first year and an additional238 400 USD over the 20 year planning period. These figures assume that cost reductions inMV and LV lines will occur in the near future, so as to reach 45 000 USD/km of MV lines and30 000 USD/km of LV lines, in line with forecasts provided in the “Rwanda Electricity AccessProgramme”.

A distribution company is assumed to purchase power from Giciye SHP at feed-in tariff pluswheeling fee (66 RWF/kWh) and then sell it to its customers. Under conventional businessconditions, and with 20% equity brought by the distribution company, the distribution companywould need to sell power at 324.70 RWF/kWh (32.66 UScts/kWh) on average to reach only 5%IRR over 20 years. Although this very high tariff may still be affordable for some categories ofend-users, because of their very costly current alternatives (kerosene, batteries, diesel…),solutions to come closer to RECO tariffs have been sought.

To reach the RECO tariff a grant of 70% on all investments would be necessary. Asupplementary move from the hydro project developer would be to sell power at a lower price tothe distribution company, e.g. 20% above hydro production costs. In this case, only 53% granton investments would be required to reach the RECO tariff. Another way of improving thefinancial viability of the project is to consider it as part and parcel of the Giciye hydropowerproject. This would increase investments costs only by 7.5% and decrease the IRR from 19.1%to 18.3%.

Sensitivity studies reveal that removing connection fees does not have a dramatic impact onfinancial results of the project and may even improve it by bringing in more customers (the lowerthe connection cost the more customers will subscribe to an electricity service), therefore it issuggested to keep them much below the actual cost of connection & metering.

The Economic IRR of the project is 20.1% (assuming economic benefits are in the order of 70UScts/kWh) and the economic levelized cost of kWh is 184.51 RWF/kWh (32.66 UScts/kWh),benefiting from a much cheaper energy source than the current grid generation mix.



2 GENERAL INTRODUCTION

2.1 Background & Objectives

Agro-industries that are located mostly in rural areas have an important role in the developmentof surrounding rural communities. Rural agro-industries stimulate local economies by providingaccess to local employment, improved access to public services, improved road infrastructureand today also have the possibility of providing access to power services.

Agro-industries such as the processing of tea and sugar require significant amounts of smoothuninterrupted power to run production lines – any interruptions in supply or voltage fluctuationscan simply spoil processing and incur product losses. Being located in rural areas theinterconnection with the grid for power supply is either not economically viable due to distanceor if possible the quality of power is often variable due to brown and/or black outs due to weakgrids and/or shortage of generation supply. Agro-industries have therefore had to rely as muchas possible on their own in house power generation – for example many tea factories havebeen relying for part of their power needs from hydro power since the early 1930’s whilst thesugar cane industry has relied for its heat and power needs on bagasse, a by-product of thesugar production industry, which has been used in part as a fuel in low pressure - 20 bar -boilers and low efficiency steam turbines.

Two projects are working on agro-industries power generation :

Cogen for Africa : designed to promote wider use of efficient cogeneration options in Africa inagro-industries: sugar, pulp and paper, forest products, palm oil, ground nuts, sisal and rice.Upgrading these to highly efficient, high pressure systems with higher capacities significantlyimproves the heat and power output. The initiative is co-implemented by UNEP (United NationsEnvironment Programme) and AfDB (African Development Bank) and executed byAFREPREN/FWD (Energy, Environment and Development Network for Africa).

Greening the Tea Industry in East Africa (GTIEA) : has been working since 2005 in theidentification, pre-feasibility and today feasibility studies of Small Hydropower (0.2MW - 5MW)sites in close proximity to Tea Factories. The objective being to reduce electrical energy use intea processing industries in member countries of the East African Tea Trade Association(EATTA) while increasing power supply reliability and reducing Greenhouse Gas emissions byreducing Tea Factory’s reliance on diesel backup generators. Specifically, the project aims toestablish 6 small hydro power demonstration projects in at least 4 of the EATTA membercountries. The project is a 4 year initiative endorsed by National Governments of eight EATTAmember countries in the region, namely: Kenya, Uganda, Malawi, Zambia, Burundi,Mozambique, Rwanda and Tanzania. The initiative is coordinated by a Project ManagementOffice (PMO) hosted by EATTA and led by a PMO Director. The PMO is responsible for theoperations of the project leading to successful achievement of the project outputs and outcomeswithin the four-year project period.

A horizontal action whose activities work across both of the above projects, called “PACEAA –Poverty Alleviation through Cleaner Energy from Agro-Industries In Africa” explores how theexcess power generated and not needed by the agro-industry’s own needs could be diverted torural communities in close proximity to the agro-industries or generation site. The overallobjective is to achieve positive impact on poverty alleviation in the tea growing areas and areassurrounding agro-industries.

Concretely in the case for the Rwandan project, a 33kV RECO line connects both Nyabihu andRubaya Tea Factory’s (TF) to the grid, yet due to brown-outs and black-outs which often occurin peak tea production seasons the factory’s often have to rely on their costly and pollutingbackup diesel generators. With the cost of diesel fuel, power unreliability and global tea marketprices falling – the tea industry, which often represent important national export markets and thebackbone of many rural economies, are increasingly facing “operational” challenges. Thedevelopment of SHP could provide the type of power reliability and economic returns that theTea Factory’s are in need of, not to mention the possibility of increasing the access to power inthose rural areas which are in close proximity to the hydro power plant or tea factory’s thusproviding further economic stimulus in the area. The reduced reliance of the TF’s on RECOwould directly mean that a 1 MW of RECO power would released for other demand centres.



PACEAA addresses the national legal and regulatory frameworks for distributing power in ruralareas, the challenges in identifying competent and interested actors who could establish apotential distribution company and aspects pertaining to rural electrification planning, businessmodels, implementation per se and financing. Lessons learned and recommendations areprovided through a series of seminars aiming to arise interest amongst agro-industries andexchanges between the multiple actors working in the rural electrification sector.

Specific deliverables of PACEAA include:

A publicly accessible report reviewing of policy and regulatory options that encouragethe involvement of agro-industries in rural electrification. Available for download on theproject website: www.paceaa.org

Four Business models for Rural Electrification from Agro-Industries & Four ruralelectrification local plans for four sites wherein SHP feasibility studies are being carriedout under the GTIEA project and for which the perceived potential for rural electrificationis significant.

Training sessions on least cost options for rural electrification

Training sessions on local rural electrification planning

Training sessions on business models and financial issues

Final workshop open to the Agro-industry of the Continent

The project is coordinated by UNEP Risoe, Denmark and has as partners the Frenchconsultancy firm Innovation Energie Developpement (IED), UNEP, the GTIEA PMO hosted atEATTA, and the Institute AFREPREN/FWD (Energy, Environment and Development Networkfor Africa). The project is financed by the European Community (EC) and receives cofinancing

from the GEF.

PACEAA is working closely in particularwith four tea factory’s in Kenya, Malawi,Rwanda and Tanzania. The four projectsare located in areas wherein feasibilitystudies are being conducted for smallhydro power development under the GTIEAproject. GTIEA is conducting eightfeasibility studies: 4 in Kenya, 1 in Malawi,1 in Rwanda, 1 in Tanzania and 1 inUganda. The PACEAA rural electrificationplans are being carried out in four out ofthe eight. The selection of the PACEAAsites was based on the following criteria:

Regional distribution of projects;

Potential for rural electrification;

Interest by the tea factory on therural electrification component.

The four RE Plans as can be viewed inFig. 1, are carried out for:

Eastern Produce Kenya, KipchoriaSHP site, Nandi Hills, Kenya;

Lujeri Tea Estate, Ruo upstreamSHP site, Mulanje, Malawi;

Rwanda Mountain Tea Ltd, GiciyeSHP site, Giciye, Rwanda; and

Wakulima Tea Company, SumaSHP site, Tukuyu, Tanzania.

Figure 4: PACEAA rural electrification project sites in East Africa

The rural electrification plans have been drawn on the basis of:



The identification of potential load centres in proximity to the small hydro power houseand Tea Factory’s & the assessment for power demand:

o on site identification of rural communities through review of topographic maps,discussions with Tea Extension Workers and locals, and on site identification.GPS readings for each load centre were taken.

o surveys on identified load centres conducted during a field mission in January2009: village level survey, household surveys, surveys to public services,commercial activities, and agro-industries.

o Interviews with the head of the district administrative offices.

o Review of consumption patterns/behaviours of existing RECO clients: monthlyconsumption & variation, percentage of people connected, growth rate inconsumption.

The application of a multicriteria analysis to rank identified load centres according to theassumed impact electrification would have not only on the load centre itself but also onsurrounding communities.

The assessment of the existing grid layout in the area: review of existing distributionlines in relation to proposed loads and grid extension master plans.

The review of the SHP feasibility study to understand potential generation output.

Economic and financial analysis of the proposed plan.

Identification of potential operators of a distribution network.

Identification of potential financing lines for the implementation on support to thenetwork operator.

An understanding of the legal and regulatory framework in the country.

The rural electrification plans presented in this report have been written by IED.

2.2 Presentation of the project area

The project in Rwanda is centred around the two Rwanda Mountain Tea factories: Nyabihu andand Rubaya and the Giciye SHP site studied at pre-feasibility in 2005/06 by IED, France and atfeasibility level in 2009 by CECB, Sri Lanka.

Nyabihu and Rubaya Tea Factories are located in the Western Province, in districts Nyabihuand Ngororero,respectively,150 km North-Westfrom Kigali. Thefactories havebeen running since1979/1980 by theGovernment andwere privatized inAugust 2006, todaythey are ownedand operated bythe RwandaMountain Tea Ltd.Between 30% and35% of the madetea is supplied bythe smallholdingoutgrowers whoare organized intotwoassociations/cooperatives: COPTEGA who supply green leaf to Nyabihu and COTRAGAGIcooperative who supply green leaf to Rubaya Tea Factory.



The Rubaya smallholder tea growers cooperative has 1280 members, and provide in total about200 tonnes of green leaf per month, representing about 33% of the total processed tea by theTea Factory. The Nyabihu cooperative is relatively smaller and has 250 members. Thesmallholder outgrowers are not labelled as Fairtrade as they are not aware about this system –this avenue should be looked into seriously by both cooperatives with the support of theRwanda Mountain Tea Company as this could represent a significant income stream for thesmallholders. There is already experience in Rwanda on fairtrade (Sorwathe S.A.R.L) and thisshould be replicated to other companies in the country.

Since privatization the production of tea has increased by 20% in two years, and the growth isexpected to increase as yields per hectare are improved and more land is set aside for teagrowing.

The tea plantations are found on slopes of hills with maximum altitude of 2600 m asl. The areais highly mountainous with villages located along roads or on plateaus. Due to the terrainvillages tend to be restricted in space and tend to be densely populated.

The SHP identified is 11 km and 15 km from the two tea factory’s, yet at 5km from Jomba (roaddistance) which is electrified and has a 33 kV transformer. Both tea factory’s are connected tothe grid and rely on diesel backups during power shortages.

No unelectrified settlements was identified in very close proximity to the SHP, yet a number ofinteresting unelectrified settlements were identified in close proximity to the two tea factories. Inproximity to Nyabihu TF are three segments of track road on which a number of villages arelocated, including the stretch from: (1) Guriro to Gatwe, (2) Gihigwa to Nyaburaro and (3)Gihigmeto to Nyiragikokora. Whilst in close proximity to Rubaya Tea Factory (about 3.5 km fromthe TF) the unelectrified village of Muhumyo is of particular interest (see photograph below).With power wheeling one can imagine that the power produced at the SHP could be directed tothese settlements.

Figure 5: Muhumyo village at 3,7 km from the Tea Factory of Rubaya represents an interesting opportunity for ruralelectrification

There are also a number of villages/trading centres on the main road on which a 33kV linepasses and that lie in close proximity to an existing transformer which are not electrified andshould be considered for electrification.

It should be noted that through the Rwanda’s “densification imidugudu” programme, householdsare being encouraged to move to villages, so that the provision of services can be more readilyprovided so as to speed up development country-wide. The area will therefore increasinglydensify in the next coming years.

Households are of good standard, often with tile roofs or corrugated iron roofs. The villagesoften have a number of economic activities and a few people use car batteries to power theirhomes or commercial activities.

2.3 Electrification status of the area

A 33kV RECO line connects both Nyabihu and Rubaya Tea Factory’s (TF) to the grid. A few ofthe settlements that lie on the road between the two tea factory’s are connected to the grid,



namely: Guriro, Ralbura, Gasiza, Birembo, Jomba, Kabaya and Rubaya Village. Others who lieon the same road are not connected, yet should be considered for electrification.

In unelectrified villages a small percentage of people use car batteries for lighting, rechargingtheir mobile phones and powering a radio. In the village of Muhumyo 30 households ownbatteries that they recharge on average every two to three days. The round trip cost to bring thebattery to the charging station costs 1400 RWF by bicycle or by motorbike 4000 RWF and thecost of the charge costs 1000 RWF for a battery or 250 RWF for mobile phones.

Further down river from the SHP site there is another site of rated capacity of 2 MW whichShyira Hospital is thinking of investing in. This would supply the hospital and the communities inthe area.

2.4 District level plans and ongoing RE projects in the area

According to district-level 5 year plans from both districts covered by the project, namelyNgororero and Nyabihu, a number of projects in the energy sector are considered and some ofthem fit with the proposed plan. The opportunity of connecting Muhumyo near Rubaya teafactory is indeed considered by Ngorerero district office (p 156).

Moreover, Nyabihu district had planned to connect Vunga centre from another site on Giciyeriver. Recent information shows that this project will finally happen as part of the currentRwanda Mountain Tea Giciye hydropower project, as the tea company agreed to meet thispresidential promise by extending a line from the hydro site to both Jomba Health Centre andVunga centre, as shown on the map below (cf. dotted line in blue).

Figure 6: Map of RMT Giciye Hydropower Project, with line extension to Vunga



2.5 Overall presentation of the methodology

This Rural Electrification feasibility study follows the following steps:

(1) Spatial Analysis (identification and ranking of candidates for Rural Electrification)

(2) Load Forecast (assessment of the characteristics of demand over the planning period)

(3) Review of possible power supply options

(4) Presentation of the suggested Rural Electrification plan, including costing and economic& financial analysis



3 IDENTIFICATION AND RANKING OF LOAD CENTRES

3.1 Objective

The main objective of this first step is to anticipate the impact of the RE project on social andeconomic development, in order to maximise it at the planning stage. In other words, cost perkWh or number of connections achieved will not be the only criteria to design the RE plan,contrary to orthodox methods.

A multicriteria analysis will thus be done, to rank identified load centres according to theassumed impact electrification would have not only on the load centre itself, but also onsurrounding communities (e.g. through better service in health and education facilities).

The rationale behind this is that RE should be regarded in this project as a tool to achievepositive impact on poverty alleviation in the tea growing areas.

3.2 Definition of “load centres”

Load centres have been defined in this study as the centre of each “umudugudu” (tradingcentre) in the areas described in the previous chapter. These centres have been identified withthe help of RMT staff and local authorities (district offices and sector chiefs), and have beensurveyed during the field mission in January 2009 (cf. list in annex 1). Their location has beenassessed with the help of GPS measurements and/or maps. Location of villages, their namesand demographic data has been cross-checked with MINALOC in Kigali, however somediscrepancies have been found in a few cases, probably because the umudugudu process isjust starting.

We have also been informed that a new trading centre Rukorati will be created and located onthe road between the Rubaya TF and Rubaya. Assumptions have been made on its likelyevolution after creation: about 100 households (comparable to other imudugudu in the area)and socio-eco facilities extrapolated by comparison with nearby Muhumyo centre.

The boundaries of each load centre have been defined with a 500m radius, to allow low voltagedistribution from a single MV transformer installed at the centre of the area. The remaininghouseholds will still have access to improved social and economic activities in the village centre.



3.3 Ranking method

The method used to rank load centres according to their assumed potential on localdevelopment draws its inspiration from the Human Development Index (HDI) developed by theUNDP. The overall idea is to calculate a composite index, similar to the HDI, but for each loadcentre of the area (and not only at the macro scale). This index, called the Indicator for PotentialDevelopment (IPD), is calculated from survey data on social and economic facilities and rangesfrom 0 (no potential for development) to 1 (highest potential).

IPD for allsettlements

Multisector data

1/4

1/4

1/4

1/4

1/3

2/3

1/2

1/2

WEIGHT

[0,1]

Distance to the nearestroad

Savings and creditorganization

Market

Population of thesettlement

Enrolment ratio

Adult literacy

Access to drinking water

Health posts

Examples of CRITERIA

1/3HEALTH

1/3LOCALECONOMY

1/3EDUCATION

WEIGHT

[0,1]

PART

1/4

1/4

1/4

1/4

1/3

2/3

1/2

1/2

WEIGHT

[0,1]

Distance to the nearestroad

Savings and creditorganization

Market

Population of thesettlement

Enrolment ratio

Adult literacy

Access to drinking water

Health posts

Examples of CRITERIA

1/3HEALTH

1/3LOCALECONOMY

1/3EDUCATION

WEIGHT

[0,1]

PART

Evaluation grid

Figure 7 IPD calculation process

The evaluation matrix of the HDI consists of 3 main components (health, education andeconomy), each subdivided into different criteria.

Likewise, IPD has an analytical matrix featuring the same components(health, education and local economy), which will have an equalweighting in the final result. The score for each component iscalculated from a weighted set of criteria: not all criteria will have thesame importance in the final result. The score for each criteria is itselfdefined by indicators (for example the score for the “Access tohealthcare” criteria can be defined by the “Type of best hospital insettlement” indicator). Criteria, their weights and indicators must beestablished and accepted by the different stakeholders. The matrix,which has been used in this study, is shown in Annex 2.

The socio-economic database of the villages, featuring data onschools, health services, economic activities etc., is available in Annex 1.

In the end, villages with the highest IPD scores will be those, whichhave already decent community and economic services. Givinghigher electrification priority to such village will thus ensure the short term benefits of the projecton local communities. Naturally, electricity brings new services and income generatingopportunities over time, wherever electricity is brought. This will also be taken into account inthe Load Forecast.

Education

Healthand social

welfare Local

economy

Figure 8 Components of IPD



3.4 Results

Figure 9 Results of spatial analysis

The sizes of the dots on the above map are proportional to their IPD : the bigger the size thehigher the expected benefits of electrification on local development. This ranking is of coursedependent on the IPD matrix (criteria and their weighting), which has been chosen. However,

Zone 1Zone 3

Zone 4

Zone 5

Zone 2



we believe this gives a fairly accurate overview of the socio-economic profile of the area. Thelist of all villages with their IPD is given in Annex 1.

The IPD is supplemented on the map with the government priorities (EDPRS): more than 50%of schools should be electrified (villages marked in orange) and 100% of health centres andgovernment buildings (marked in red) by 2012.

Most interesting group of villages are as follows (circled in red on the map):

(1) Zone 1: located close to proposed SHP. Two villages (Kabutozi & Gatovu) covered onthe main road.

(2) Zone 2: 4 interesting villages around Nyabihu Tea Factory.

(3) Zone 3: potentially interesting but located slightly too far from the grid.

(4) Zone 4: tea nursery and upcoming umudugudu (Rukorati), located under existing RECOpower line.

(5) Zone 5: villages leading to Muhumyo centre. Considered as priority by Ngororero districtoffice.

It is suggested to include in the plan the above zones, except zone 3, which is too far from thegrid.



4 LOAD FORECAST

4.1 Objective

Contrary to the previous chapter, the objective is now to characterise load centres from anelectrical point of view: how much would they consume over the planning period (20 years).

More specifically, for each load centre and each year of the planning period, the followingoutputs will be produced:

Number of single phase and three phase clients

Peak demand (in kW)

Yearly consumption (in MWh)

Average daily load curves

4.2 Methodology

The approach used here belongs to the “bottom-up” family of load forecasting models: demandis calculated from the number and average consumption profiles of each type of end-user(households, schools, shops, other productive activities etc.).

The number of households and current commercial and social facilities have been surveyedduring the field mission (see table in annex 1). Then assumptions have been made on the rateof creation of electricity-powered income generating activities shortly after electrification, partlybased on the current situation in electrified villages of the area.

Questionnaires to shop and mill owners as well as households have provided insight on thepossible demand in the area, complemented by other studies and estimates from theConsultant in similar contexts, namely having conducted all the SHP pre-feasibility studiesunder the GTIEA project in 2005 - 2006.

4.3 Assumptions and parameters

The population growth rate has been taken equal to 2.9% in Nyabihu district and 2.6% inNgororero (district data 2007), and the number of people per households is different for eachvillage, according to cell-level data (average of 4.9, cf. figures in Annex 1).

Households have been segmented in 3 income classes, and without accurate estimate from thesurvey, their distribution for each village has been taken as 5% for class 1, 25% for class 2 and70% for class 3. According to Ngororero district plan, 70% of households live with less than1$/day and are thus considered as having very low capability to pay for the electricity service,hence much lower connection rates, cf. Table 3 below. It is assumed that the weight of thepoorest class of households (class 3) will decrease by 10% over 20 years, while the weight ofthe middle class will increase by 10%.

The number of social and community facilities (schools, health centres and churches) isassumed to stay constant over time. However, it is assumed that the number of commercialactivities will quickly grow after electrification as shown in the following table:

Current average in nonelectrified villages

Additional activitiesafter electrification

Shop, butcher, restaurant, drink house,government building

9 5

Barber/saloon, bycicle repair, tailor, video 1 4

Carpenter, welding, battery charging, milkcooperative

1 2

Mills 0.5 1

Table 1 New economic activities after electrification



A summary of assumptions for specific consumption of each class of end-user is providedbelow, detailed load curves for each type of end-user are available in annexes:

Appliances

Installedcapacity

(W)Consumption(kWh/month)

HH class 1 5x7W CFLs, 1 stereo, 1 TV 215 30

HH class 2 4x7W CFLs, 1 radio, 50% own 1 TV 46 7

HH class 3 3x7W CFLs, 1 radio 32 5

water pump (per 100 hh) 500 91

street lighting (per 100 hh) 250 53

School 10x25W lighting evening (CFLs) 250 23

Health centre

150W all the time (refrigeration, nominalcapacity 450W), 5x25W lighting morning andevening (CFLs) 275 132

Church2x25W lighting morning and evening (CFLs)and sound system (200W) 250 38

Shop, butcher, restaurant,drink house, governmentbuilding

50W all the time (refrigeration, nominalcapacity 150W), 1x25W lighting morning andevening (CFL) 75 43

Barber, video show, tailor on average 300W during the day 300 62

Carpenter, welding,battery charging

Installed capacity of 1.5kW, operating in themorning and afternoon 1500 224

Mill Average 5kW 5000 228

Table 2 Specific consumption of different types of end-users

For the purpose of transformer sizing, the possibility of having all mills and other power users(battery charging stations, carpenters and welding) operating at the same time of the day hasnot be ruled out to avoid under sizing transformers. Then again, to cut down on transformercosts, scheduled time of use for these different customers may be an interesting option.

Assumptions for connection rates and specific consumption growth rates are given in thefollowing table:



Years 1 1-10 10 10-20 20

Connection rates

Households1

class 1 50% 80% 100%

Households class 2 20% 30% 50%

Households class 3 5% 10% 20%

Commercial and community activities 40% 80% 100%

Consumption growth rates2

(%/year)

Households (all classes) 5% 0%

Commercial and community activities 1% 0%

Table 3 Connection rate and consumption growth rate assumptions

Finally, technical distribution losses of 8% are added on top of the overall end-user energydemand.

4.4 Results

Load forecast has been done for each identified load centre (village) of the area. Therefore,detailed tabulated results and charts are given for the targeted villages (load curves, number ofclients, peak load…). Then a map giving a broader picture for the whole area is provided.

4.4.1 Detailed results

0

10000

20000

30000

40000

50000

60000

0-1

2-3

4-5

6-7

8-9

10-1

1

12-1

3

14-1

5

16-1

7

18-1

9

20-2

1

22-2

3

Time range

Po

wer

(W)

Households

Commercialandcommunityactivities

Figure 10 Average daily load curve in W for the first year (without technical losses)

The shape of the load curve is mostly determined by the load profile of mills, battery chargingstations, carpenters and welding machines operating during the day with a peak in theafternoon.

The same load curve is given for the final year of the planning period (20th

year):

1NB - this refers to households that are reachable (within 500m of village centre).

2These growth rates apply to the consumption of each single customer, not to the overall

demand.



0

20000

40000

60000

80000

100000

120000

140000

160000

180000

200000

0-1

2-3

4-5

6-7

8-9

10-1

1

12-1

3

14-1

5

16-1

7

18-1

9

20-2

1

22-2

3

Time range

Po

we

r(W

) Households

Commercialandcommunityactivities

Figure 11 Average daily load curve in W for the20th year (without technical losses)

Domestic demand has slightly increased its share (from 9% in year 1, to 17% in year 20), butpeak demand is still determined by non domestic uses. This very low domestic share assumesthat significant efforts will be made to promote productive and social uses of electricity, if this isnot the case the economic and social benefits as well as financial sustainability of the projectsmay be lowered. Evolution of load curve over the planning period is shown in the next chart:

0

20000

40000

60000

80000

100000

120000

140000

160000

180000

200000

0-1

2-3

4-5

6-7

8-9

10-1

1

12-1

3

14-1

5

16-1

7

18-1

9

20-2

1

22-2

3

Time range

Po

we

r(W

)

Year 20

Year 10

Year 1

Figure 12 Average daily load curves for the first, 10th and 20th year (without technical losses)

Evolution of consumption, peak demand and number of clients are given in the following charts:

0

50 000

100 000

150 000

200 000

250 000

300 000

350 000

400 000

450 000

500 000

1 2 3 4 5 6 7 8 9 10 11 12 1314 15 16 17 18 19 20Year

Co

nsu

mp

tio

n(k

Wh

)

0

50

100

150

200

250

Po

wer

(kW

) Consumption(kWh)

Peak (kW)

Figure 13 Evolution of yearly consumption and peak demand during the planning period (inc. technical losses)



0

100

200

300

400

500

600

700

800

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Year

Sin

gle

ph

.cli

en

ts

0

10

20

30

40

50

60

70

80

Th

ree

ph

.cli

en

ts Singlephaseclients

Threephaseclients

Figure 14 Evolution of LV and MV clients during the planning period (inc. technical losses)

YearSingle ph.clients

Three ph.clients

Consumptionper year

Peak(average)

kWh kW

1 198 31 139 758 57

5 289 47 235 916 106

10 401 63 356 114 168

15 535 66 405 981 181

20 667 72 455 848 195

Table 4 Load forecast



4.4.2 Maps for the whole area

The above calculations have been undertaken for each load centre of the area. Results aresummarized in the following maps (for the first year and 20

thyear of the planning period).

Figure 15 Yearly consumption in the project area (year 1)



Figure 16 Yearly consumption in the project area (year 20)



5 SUPPLY OPTIONS

A number of power supply options can be considered for non electrified settlements in theproject area: connection to the SHP directly or through the utility network, or distributed powergeneration (Pico hydro or PV).

5.1 Hydropower

The proposed plan for Giciye hydropower development is to connect directly to RECO networkin nearby Jomba town and then wheel power through RECO lines to both tea factories (awheeling agreement is under negotiation, so that tea factories can actually benefit from thischeaper source of energy). Therefore, the only target of our Rural Electrification plan to be ableto connect directly to hydro would be Gatovu & Kabotuzi, on the tarmac road between GiciyeSHP and the interconnection point with RECO network (cf. map in chapter 2).

All other identified areas would be connected directly to RECO network but virtually takingpower from hydro and thus purchasing power at a reduced price, thanks to the wheelingagreement.

Although the regulatory framework does not yet allow such agreements, discussions with allrelevant stakeholders from MININFRA and RURA have revealed that the upcoming energy lawwill indeed include this possibility and that there is good hope that the RMT Giciye hydropowerproject could be one of the very first to benefit from it. Negotiations are ongoing with RECO onthis matter.

The expected breakdown of hydropower use is as follows:

8% 1%

91%

Tea factories


RECO


23%

2%

75%

Tea factories


RECO


Under the following assumptions:

- Tea factories would consume 1.4 GWh in the first year (average of years 2006, 2007and 2008), and their consumption would triple by the end of the planning period (RMTestimate).



- Total hydro ouput is 18 GWh according to the GTIEA feasibility study.

As shown on the above pie charts, there should be no issue with energy availability for thewheeling agreement, ensuring cheaper energy available throughout the year. Technicalavailability of power will mostly depend on the reliability of RECO network, since all suggestedloads will be on this network. In any case, contribution of RE to total demand is negligible.

5.2 Decentralised small-scale renewable energy projects

It is very likely that not all identified villages of the area will be connected to the electricityservice in the near future, because of constraints on power availability and access to capital.Furthermore, even in electrified villages some households may be too far from suggestedtransformers to be eligible for connection. For some of the households of the project area,connecting them to an electricity service may prove to be too costly, hence a project developershould also look into the distribution of PV modules and pico hydro systems (around 1kWsystems for ~150 USD). A revolving fund/ credit scheme could assist households in coveringthe first initial investment costs which in the case of renewable tend to be the main stumblingblock to investment.

Slightly larger schemes, such as micro hydro (10-100 kW) projects may also be considered togo slightly beyond mere domestic energy uses, obviously without ensuring power availability forany kind of users such as large mills.



6 RURAL ELECTRIFICATION PLANS

6.1 Proposed plan

The following maps show the suggested location of lines and transformers.


A line would be extended from Nyabihu Tea Factory to nearby villages along the main road andto Gatwe centre. Gatovu & Kabutozi on the way to the grid from the hydro site would also beconnected.




Another line would be extended from Rubaya up to Muhumyo centre, and a transformer couldalso be dropped in Rukorati.

Shortly after electrification, the expected number of households and commercial and communityactivities are:

Households in year 1 738

Households in year 20 1282

Primary school 5

Secondary school 2

Dispensary/Clinic 1

Church 27

Shops and restaurants 175

Barber, video show, arts and crafts 55

Carpenter, welding, battery charging 43

Mill 19

Table 5 List of population and services covered by RE plans

NB: these figures are based on field survey and assumptions on growth of economic activitiesdetailed in chapter 4.3. They indicate the total number of activities, which may be eligible forconnection to electricity within the few years following electrification. However, the actualnumber of customers will be lower initially, as shown in table below.

Year 2 Year 20

Single Phase Customers 220 667

Three Phase Customers 32 72

Table 6 Expected number of customers



6.2 Network design

6.2.1.1 MV lines and transformers

The transmission line standard used by RECO is 30kV. Recommended sizing is three phase 3 x35 mm

2, given the peak loads transiting through the proposed lines (a few hundred kWs at

most). 11m treated wood poles are suggested, with an admissible span of 150m between poles.A total of 8.9 km will be required.

The following step-down transformer (30/0.4 kV) capacities have been considered: 15, 25, 50and 100 kVA. Smallest transformers being used by RECO are 50 kVA. However, given the lowdemand of most centres (as shown below), it is advised to look for slightly smaller units.

Load centreTF Size year1 (kVA)

TF Size year20 (kVA)

Rukorati 15 50

Burorero 15 25

Muhumyo centre 25 50

Muhumyo schools 15 15

Gatovu 15 50

Bukongora 15 50

Nkomane (Kadahenda) 15 50

Nyaburaro 15 25

Gatwe 15 25

Ntalama 15 15

Remera 15 15

Table 7 TF sizes for selected load centres

These capacities have been calculated from the load forecast, with the conservativeassumptions that mills and other large power users would be operating at the same time, with aCos Phi factor of 0.8 and a safety margin of 10%.

The 4 Interconnection points with RECO network will be equipped with manual aerial switches.NB: to cut down on costs, no MV meter will be installed at the interconnection point, as the costof these equipments (including protection) can go up to 30,000 USD. Therefore, it is suggestedto keep track of energy consumption of the project with the disaggregated consumption of eachend-users (sum of all LV meter readings).

6.2.1.2 LV network

Given the presence of several engines among the potential customers, it is recommended toinstall tri-phase LV lines (Almelec 3 x 35² + 54.6² + 16²). This cable section should allowextension of 4 independent LV lines up to 500m from the transformer, while remaining under8% voltage drop, assuming a maximum peak demand of 22kW on each line, which is the caseaccording to the load forecast.

Poles would be 8m treated wood poles, with an admissible span of 50 meters between poles. Atotal of 3.3 km will be required.

Most of the customers in rural load centres will be connected to the main LV line with singlephase cable (2x16mm² Alu). Only users with significant power demand (mills, coffee factory,water pumping, welding) are expected to ask for tri-phase supply (4x16mm² Alu).

An average of 15m per customer has been considered to assess the required length of LV lines(relatively dense housing in the centres).

In-house wiring is not considered in the present study and will supported by the end-user.



6.2.1.3 Network and TF capacity expansion planning

The MV network is not expected to expand over the planning period. However, LV lines will beextended, transformers will have to be upgraded and new meters will be installed.

Meters will be installed when required by new customers. LV lines and transformers are sizedaccording to forecasted demand 7 years in the future. New investments in LV lines andtransformers are thus planned every 7 years.

6.3 Costing

6.3.1 Unit costs

Cost of transformers are as follows:

TF capacity(kVA)

Unit cost(USD)

15 751

25 1255

50 2500

Table 8 Transformer unit costs

Cost of MV and LV lines are respectively 45 000 USD/km and 30 000 USD/km. Due to variousreasons (high standard lattice towers, little competition, landlocked country are among the mainfactors), current unit costs of MV lines are among the highest in the world, ranging up to 100000 USD/km. However, the “Rwanda Electricity Access Programme” of 2009 expects thesecosts to decrease progressively to 45 000 USD/km for MV lines in 2011 (roughly the date whenthe proposed lines would be built). This cost reduction is expected to happen with increasedcompetition, bigger market (as a consequence of the aggressive grid extension programme)and least-cost technical improvements such as the ones suggested by the Tunisian STEG in arecent pilot project.

Detailed breakdown is provided below:

ComponentUnit Price(USD)

Unit

Alu cable 35mm² 4.03 ml

joint sleeve 14.33 set

Treated wood pole - 11m 1030 per pole

suspension equipment 1431 per pole

Reinforced concrete 429 per pole

11m pole (stop-end) - 2 HEA 240 6.87 per stop

stop-end pole equipment 2433 per stop

Reinforced concrete (stop-end) 859 per stop

Table 9 Breakdown of costs for 30kV lines

Component DescriptionUnit Price(USD)

Unit

Alu conductor (3x35+54,6+1x16) mm² 26.91 ml

sleeve 67.27 Unit

Wood pole - 8 m Span of 50m 269 Unit

Conductor support 22.43 Unit

Other accessories 22.43 Unit

Table 10 Breakdown of costs for LV lines

Cost of three phase and single phase connections are 366 USD and 153 USD respectively.

Detailed breakdown is provided below:



Component DescriptionUnitPrice(USD)

Unit

Conductor – sin ph. 20 m - 2x16² Alu 43.50 per cust.

Connectors 3.63 per cust.

Circuit breaker single ph. 18.85 per cust.

Meter (1-5A). single ph. 65.25 per cust.

Other accessories 21.75 per cust.

Conductor – triph. 20 m - 4 x16² Alu 87 per cust.

Connectors 3.63 per cust.

Circuit breaker triphase 101.50 per cust.

Meter (10-15A) triphase 145 per cust.

Other accessories 29 per cust.

Table 11 Breakdown of costs for single phase and three phase connections

Unit cost of manual aerial switch has been taken at 2500 USD.

6.3.2 Results

Total investments required would be 567,800 USD in the first year and 238,400 USD3

ofadditional investments would be required over the planning period for transformer upgrading,new connections and extension of LV lines, as shown in the tables below. This amounts toabout 1090 USD per customer in year 20. This is slightly higher than figures from the “RwandaElectricity Access Programme”, which aims at 782 USD per customer for MV/LV investments.

YearSingle ph.Clients

Three ph.clients

ConsumptionPeak Total TF

capacityMV lines LV lines

kWh kW kVA m m

1 0 0 0 0 0 4 461 1 650

2 220 32 163 798 69 170 4 461 1 650

3 243 36 187 837 82 190 0 0

4 265 42 211 877 94 215 0 0

5 289 47 235 916 106 240 0 0

6 310 47 259 956 119 240 0 0

7 334 52 283 995 131 240 0 1 800

8 356 58 308 035 143 300 0 0

9 379 62 332 074 156 300 0 0

10 401 63 356 114 168 300 0 0

11 428 63 366 087 171 310 0 0

12 454 63 376 061 173 320 0 2 010

13 479 65 386 034 176 330 0 0

14 506 65 396 007 179 330 0 0

15 535 66 405 981 181 380 0 0

16 562 70 415 954 184 380 0 0

17 588 70 425 928 187 380 0 1 185

18 614 72 435 901 189 380 0 0

19 641 72 445 874 192 380 0 0

20 667 72 455 848 195 380 0 0

Table 12 Sizing elements of the project over the planning period

3 NB: this figure is in constant price.



Year MV lines LV lines MV switch TransformersThree ph.

connectionsSingle ph.

connections

1 200 723 49 500 5 000 6 008 0 0

2 200 723 49 500 5 000 6 008 11 712 33 656

3 0 0 0 0 1 464 3 519

4 0 0 0 0 2 196 3 366

5 0 0 0 0 1 830 3 672

6 0 0 0 0 0 3 213

7 0 54 000 0 4 002 1 830 3 672

8 0 0 0 0 2 196 3 366

9 0 0 0 0 1 464 3 519

10 0 0 0 0 366 3 366

11 0 0 0 0 0 4 130

12 0 60 300 0 1 530 0 3 977

13 0 0 0 0 732 3 825

14 0 0 0 0 0 4 130

15 0 0 0 0 366 4 436

16 0 0 0 0 1 464 4 130

17 0 35 550 0 0 0 3 977

18 0 0 0 0 732 3 977

19 0 0 0 0 0 4 130

20 0 0 0 0 0 3 977

Table 13 Investment plan (in USD)

NB: initial investments are assumed to be spread equally over the first 2 years to anticipatepossible delays in actual realization of the SHP and/or RE distribution network. Clientconnections thus begin in year 2 only. Cost of connections have been included in theinvestment costs, but they will be recovered over a period of 1 year.

6.4 Financial Analysis

6.4.1 Objective

The aim of this section is to conduct a simulation of what would be the profitability of the projectfor a Project Developer, implementing and operating the RE project. The simulation thereforeassesses what is the profitability for the Project Developer (Financial Internal Rate of Return -FIRR), in a real life simulation of taxes and loan values.

It is assumed that the development of the project would be undertaken via a Build-Own-Operated (BOO) company which will bring part of the equity required for the development of theproject. This Distribution Company would not invest directly in the hydro scheme, but wouldpurchase bulk power from the Hydro Developer instead.

The section first presents the model and the assumptions for running the model. The results arethen presented for the different scenarios, and the need for subsidy is reviewed together withsensitivity studies.

6.4.2 Methodology

The criterion used for assessing the profitability of the project is the Financial Internal Rate ofReturn (FIRR) of the net income stream of the project:

It is assumed that the profits after taxes are not distributed as dividends but insteadreinvested in the Distribution Company (provided, of course, that the income is positive). Ifprofits are negative, additional equity will have to be injected in the Distribution Company bythe Project Developer.

It is considered that equipments will be sold at the residual book value of the fixed assets atthe end of the period.



With the above conditions, the Financial Internal Rate of Return (FIRR), in percent, is the valueof t for which the Net Present Value (NPV) of the project equals zero.

N

n

n

t

CFNPV

1 )1(

Equation 1 Net Present Value formula

With:

NPV: Net Present Value of the Investors

CF: Cash flows over the project’s lifetime

N: Number of years of calculation (20)

T: discount rate of the analysis.

Project Developers are assumed to seek a rather low FIRR of 5%. Therefore, the Retail Tariffwill be adjusted to reach this figure. Higher rate of return are not sought in this study, as RE isnot, by essence, a profitable activity. Interested Project Developers are thus expected to seekfinancial equilibrium in the long term, but with a social objective in mind.

6.4.3 Parameters and assumptions

Macroeconomic Parameters

We have assumed a 2% foreign inflation rate, applied to all costs and benefits, except localsalaries. This means that bulk power purchasing tariff and project retail tariff will follow globaltrends in inflation. However, local salaries will bear the national inflation rate of 15.40% (CIAWorld Factbook, 2008) for a period of 5 years, after which hyperinflation is expected to stop.Salaries will then inflate by 5% per annum.

NB: investments over the period are assumed to follow foreign inflation, however thisassumption may be wrong if most equipments are produced locally.

Time Parameters

All parameters are considered on yearly basis. It is assumed that construction works will becarried out in year 1 and finished at the end of year 1, and that start of Commercial Operation isassumed as right after the end of the construction period. The length of the study period is 20years.

Connection of new customers is assumed to happen during the 6th

month of each year.

Investment Costs and Contingencies

From chapter 6.3.2, the investment costs are identified. Investment costs over the period aim atupgrading equipments, but there is no provision for replacement of equipments. All installedequipments have lifetimes equal or greater than the project lifetime, therefore the issue ofreplacement is left aside.

Initial costs include initial investment costs but also engineering studies and capacity buildingactivities for the project developer: 5% of initial investments costs for capacity building and 10%for engineering.

Operation and maintenance Costs

Operation and Maintenance costs comprise technical operation and maintenance costs of MVand LV lines, transformers, as well as meters. They are taken as 2.5% of the investment valueper year.

In addition, different insurances could be adopted by the company.

Insurance against damages: a typical cost would be 0.15% per year of the investmentvalue.

Insurance against loss of profit: a typical cost would be 0.25% per year of the annual salesvalue corresponding to less than 0.1% per year of the investment value.

Other insurances could be considered: on equity paid in for investment costs, ondisbursements of commercial loans … etc.

The above are only baseline assumptions and would have to be adjusted for the actual situationonce the BOO company will be set and after asking insurance companies for rates in the



specific context under consideration. In the model, they are taken as 0.5% of the investmentvalue per year.

These technical O&M costs include provision for small maintenance as well as servicing costs.

On top of these O&M costs, a salary component has been added to take into account billcollection and accounting expenses. The assumptions are as follows:

Number of full-time staffper 1000 customers

Salary(USD/month)

Salary(RWF/month)

Accountants 1 200 1 356 000

Collection officers 2 50 339 000

Table 14 Assumption for salary costs

The target ratio for East African utilities such as KPLC (Kenya) or ESCOM (Malawi) is around130 customers per staff, i.e. 7.7 staffs per 1000 customers. However, this includes staff for nonadministrative/accounting work and the organizational structure is thus necessarily lighter in thecontext of our much smaller scale projects.

Power purchase

Technically, power will be supplied by the RECO network. However, as explained in chapter 5,a wheeling agreement is expected, allowing the distribution company to purchase power directlyfrom the hydro powerplant with a wheeling fee to account for technical transmission losses aswell as renting of existing RECO lines.

There is currently no regulated feed-in tariff for hydro projects in Rwanda, and discussions arebeing carried out to determine this tariff for the Giciye project. However, experiences withprevious similar projects in the country show that 60 RWF/kWh is a likely figure. Therefore, toensure that RE is not reducing possible revenues of the hydro project developer, we assumethe distribution company would purchase its power at 60 RWF/kWh, and add an additional 10%wheeling fee (rough estimate), resulting in a tariff of 66 RWF/kWh.

Sales

The variable domestic retail tariff of the project is the parameter, which we seek to determine toachieve a FIRR of 5%. The proposed tariff structure draws inspiration from the current RECOtariff structure, to allow easier comparison between the two (except that domestic end-users payhalf of non domestic end-users):

Single Phase Three Phase

Domestic Fixed fee: 200 RWF/month

Tariff: Parameter

N/A

Non domestic Fixed fee: 200 RWF/month

Tariff: 2 x Domestic tariff

Fixed fee: 200 RWF/month

Tariff: 2 x Domestic tariff

Table 15 Proposed tariff structure

A rate of unpaid bills of 5% has been taken, to take into account the fact that some clients maydefault on paying their bills (assuming postpaid meters).

Connection fees of 50 USD (28 000 RWF, one third of actual connection costs) for single phaseand 183 USD (103 000 RWF, half of actual connection costs) for three phase customers havebeen taken. These fees are spread over 1 year and are included in the electricity bill.

Financing

Equity is assumed to cover 20% of initial investment project costs. There is no Grant componenton investment costs in the “business as usual” scenario.

A loan has been assumed to finance the investment project costs that are not financed by grantor equity. The conditions for the loans are assumed to follow conventional (very conservative)local business rules:

Loan duration and grace period: repayment over 15 years; with a grace period of 1 year (notincluded in the 15 years).



The loan is expected to be coming from local banks at the current commercial lending rateof 15.84% (CIA World Factbook, 2007).

Timing of disbursements: the disbursements are made in 12-month intervals; i.e. duringyear 1.

Repayments are made every year in equal installments.

In case of negative cumulated cash flow, the Company will be charged a 16.84% interestrate on negative cash flow (short term loan). NB: the cash flow considered here is the cashflow of the Distribution Company, which is not the same as the “project cash flow” used tocalculate the FIRR. The latter measures inflows and outflows from the point of view of theProject Developer, which also bears the capital investments over the period.

Investments over the period (after year 1) are covered partly by operational results of theDistribution Company and if insufficient, the gap is filled by additional equity from the ProjectDeveloper.

Depreciation

Investment costs for power lines, transformers and meters are depreciated, linearly, over 20years.

Taxes

Corporate Tax on corporate profits, after loan interests and depreciation, has been taken at30%. 18% VAT is added to all sales.

6.4.4 Results – business as usual

The detailed cash flow is presented in annexes. Only main indicators and final cash flow will beshown in this section.

Investment first year (USD) 567 800

Investment over the period (USD, constant price) 238 400

Equity first year (USD) 130 600

Maximum equity injection (USD) 238 400

Domestic Retail Tariff to achieve 5% FIRR (RWF/kWh, inc. taxes) 173.41

Commercial Retail Tariff to achieve 5% FIRR (RWF/kWh, inc. taxes) 346.82

Average Retail Tariff to achieve 5% FIRR (RWF/kWh, inc. taxes) 324.70

Average Retail Tariff to achieve 5% FIRR (UScts/kWh, inc. taxes) 57.5

Table 16 Financial results – “business as usual”

C as h F low

-250

-200

-150

-100

-50

050

100

150

200

250

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Mil

lio

ns

Ye a rs

RW

F

C as h F low (R EP rojec t)

C umulated C as hF low (R E P rojec t)

Figure 21 Project cash flow

As shown in the cash flow above, the payback period is 18 years. The maximum equity injectionoccurs on the 12

thyear, with a total of 238 400 USD poured into the project (cf. cumulated cash



flow). In fact, the first 15 years are hampered by the heavy interests of the short and long termloans:

Recurrent costs

0

10

20

30

40

50

60

70

80

90

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Mil

lio

ns

Years

RW

F

Interests (negative cash flow)

Interests (loan)

Power purchase

O&M & insurance

Salaries

Figure 22 Breakdown of operation costs over the planning period

6.4.5 Capability to pay

Tariffs presented in the previous chapter are obviously much higher than what the average tariffwould have been with the current RECO tariffs.

However, domestic tariff being only half of commercial tariff, the expected average bill fordomestic end-users would be “only”:

- Class 1 (5% richer households): 5446 RWF/month and 7800 RWF/month in the firstyear (including connection fee)

- Class 2: 1410 RWF/month and 3764 RWF/month in the first year

- Class 3 (70% poorer households): 1072 RWF/month and 3426 RWF/month in the firstyear

With an average expenditure of 5000 RWF/month on kerosene (BTC 2009), it is interesting tonote that these bills are not necessarily unaffordable for most users. Besides, an average teagrowing household earns from 15000 to 20000 RWF monthly. Assuming households are willingto spend up to 10% of their income on energy in rural contexts (“Rwanda Electricity AccessProgramme” 2009), these tariffs seem reasonable even when including the connection fee.

As far as commercial activities are concerned, if the baseline for avoided costs is car batteries(costing an average of 3 USD/kWh), savings are naturally high in spite of the already very highproposed tariff (0.57 USD/kWh), and connection fees are paid back during the first monthalready. However, for slightly larger power users such as mills, the comparison with diesel isless favorable. Assuming a local diesel production cost of 400 RWF/kWh (Amahoro Energy2009), savings on the monthly bill would be 13% only, ensuring a payback of connection fee in9 months.

In any case, it is likely that having a much higher tariff per kWh than other grid customers wouldnot be acceptable for the end-users and solutions will thus be needed to bring the tariffs closerto RECO levels.

6.4.6 Results – with subsidies

Three solutions may be considered:

- Grant on part or totality of investments

- Lower power purchasing tariff

- Treat RE project as part of the SHP project

6.4.6.1 Grants

Since investments are spread not only in the first year but also throughout the planning period, itis advised to provide a grant on all expected investments (possibly releasing part of the grantprogressively, as needed by the project). The results on the retail tariff would be as follows:



0,00

50,00

100,00

150,00

200,00

250,00

300,00

350,00

0,0% 20,0% 40,0% 60,0% 80,0% 100,0%

Average Retail Tariffto achieve 5% FIRR

Average powerpurchase tariff (66RWF/kWh)

Target tariff (132,2RWF/kWh)

Figure 23 Evolution of retail tariffs to reach financial equilibrium, under different levels of subsidy

Above 80% of subsidy on investments, the share of equity decreases progressively from 20% to0%. In the best case scenario (100% subsidy on investments), retail tariff of the RE project willalmost reach the power purchasing tariff, meaning that there will be a very small margin for theDistribution Company.

Parity with the grid (same retail tariff as RECO) is reached for 70% subsidy on investments.

6.4.6.2 Lower power purchase tariff

Another form of support could come from the hydro project developer, with a power purchasingcontract at a better rate. A slightly lower purchasing tariff for hydro power will thus be taken, at31 RWF/kWh, which would be 20% above hydro production costs. The annual cost of such amove for the power seller would be 8 000 USD in year 1 and 27 000 USD in year 20.

0,00

50,00

100,00

150,00

200,00

250,00

300,00

0,0% 20,0% 40,0% 60,0% 80,0% 100,0%

Average Retail Tariff


Figure 24 Evolution of retail tariffs to reach financial equilibrium, under different levels of subsidy with lower purchasetariff

This time, the power purchasing tariff can reach RECO’s retail tariff with 53% of subsidy oninvestments.

6.4.6.3 Treat RE project as part of SHP project

Another, radical solution to improve the financial viability of the project is to “cross-subsidise” itwith the profits of the generation project. Using the financial analysis model from the feasibilitystudy, and assuming an average retail tariff of 132 RWF, the results would be:

- Investment costs increase by 7.5%

- IRR over 20 years decreases from 19.1% to 18.3%



6.4.7 Sensitivity studies

Higher unit costs for MV lines

If current unit costs are kept (80 000 USD/km), results would be:

Investment first year (USD) 888 600

Investment over the period (USD, constant price) 252 300

Equity first year (USD) 204 400

Average Retail Tariff to achieve 5% FIRR (RWF/kWh, inc.taxes) 436.29

Average Retail Tariff to achieve 5% FIRR (UScts/kWh, inc.taxes) 77.2

Table 17 Financial results – higher unit costs

Soft loan

Under better loan conditions:

- 8% rate- Repayment over 15 years- 9% on short term loans

The results are:



Table 18 Financial results – soft loan scenario

Impact on retail tariff is very significant, as the cost of financing (especially short term loans) inthe first years of the project is much less.

No connection fee

If connection fees are removed altogether, the financial results are:

Table 19 Financial results – soft loan scenario



Impact on tariffs is limited (only 10 RWF above the base case scenario). An increase in numberof customers of only 6% would offset the revenue loss. However the question remains whetherto allow end-users to connect without any form of compensation from their side.



Impact of subsidies on all sensitivity analyses

0,00

50,00

100,00

150,00

200,00

250,00

300,00

350,00

400,00

450,00

500,00

0,0% 20,0% 40,0% 60,0% 80,0% 100,0%

Subsidy level (% all investments)

Re

tail

Ta

riff

(RW

F/k

Wh

)

Base scenario

Higher unit costs

Soft loan

No connection fees


Average powerpurchase tariff (66RWF/kWh)

Figure 25 Average retail tariffs under different scenarios and different levels of subsidy

The chart shows that with low levels of subsidies, soft loans do have an importance in thefinancial sustainability of the project. However, as the share of subsidy increases, soft loanshave naturally less and less influence on the results.

At high subsidy levels, all scenarios tend to remain in a narrow interval above the powerpurchase tariff. This fixed gap between the power purchase tariff and the retail tariff is explainedby the O&M costs of the projects (technical maintenance, salaries…), as well as thediscrepancy between cost of meters and connection fees, which are paid by the end-user.

All scenarios reach the target RECO tariff, for grants on investments from 67% (soft loan) to80%(with higher unit costs).



6.5 Economic Analysis

6.5.1 Economic Internal Rate of Return

The Economic Internal Rate of Return (EIRR) of the project has been calculated with a fixedRetail Tariff of 70 UScts/kWh (395 RWF/kWh), to stay in line with the assessment of economicimpact of the “Rwanda Electricity Access Programme”. This rate of return gives a picture ofproject profitability from the point of view of society as a whole and not from the point of view ofthe project developer alone (as opposed to the FIRR). Therefore, its does not take into accountassumptions on inflation, corporate taxes and cost of financing.

The resulting EIRR is 20.1%, assuming all power comes from hydro (with a production cost of26 RWF/kWh). If we assume that power comes from RECO only, with a Long Run MarginalCost of the grid taken at 90.7 RWF/kWh (USAID 2005, adjusted with 2% inflation), the EIRRgoes down to 15.2%.

6.5.2 Levelized cost

The levelized cost is given by the following formula:

horizon

i i

horizon

i i

r

iBenefits

r

iCosts

1

1

)1(

)(

)1(

)(

kWhofcostLevelized

With:

Costs(i) the costs in year i of the planning period, including investments,operating and maintenance, and production costs of hydro

Benefits(i) the quantity of kWh sold in year i

r the economic discount rate, taken at 10%

The interesting aspect of the levelized cost is that benefits are considered in terms of kWh only,and potential controversies on the economic value of a kWh are thus avoided. Levelized cost ofthe project is 184.51 RWF/kWh (32.66 UScts/kWh).

6.5.3 Comparison with the grid

As the project is technically an extension of the grid, any economic comparison of the projectwith conventional grid extension is thus purely theoretical. The only difference between the twoscenarios being the cost of power generation, taken at 90.7 RWF/kWh for conventional gridextension and 26 RWF/kWh for grid extension tied to the RMT Giciye hydropower project (cf.6.5.1). The resulting cost of the project with plain grid extension would have been 249.22RWF/kWh, instead of 184.51 RWF/kWh as explained previously.



ANNEX 1: List of surveyed load centresIncluded

in RE

plan Village/Umudugudu Description District Sector Cell Longitude Latitude

Distance

from main

road

Total HH's in

village

Number of

people per

HH

Reachable

HH's

x Bukongora Bukungora and Gihigwe, near Mwiyanike Nyabihu Karago Kadahenda 29.5091 -1.6517 2 0 4,78 0x Bukunzi PS (1670 p.), SS (243 p.) Ngororero Muhanda Bugarura 29.4876 -1.7962 7379 0 4,14 15x Burorero Kanengo centre, Burorero umudugudu Ngororero Muhanda Bugarura 29.4920 -1.7946 6886 40 4,14 30

Gatongo Gatongo umudugudu Nyabihu Jenda Kareba 29.4773 -1.6499 2287 70 5,22 65x Gatovu Gatovu & Kabutozi Nyabihu Karago Gatovu 29.5565 -1.6907 7 232 4,81 139x Gatwe Nyabihu Karago Gatagara 29.5373 -1.6524 2563 83 5,23 83

Kazuba Nyabihu Rambura Rugemba 29.5014 -1.6645 0 5,23 0x Mashya Small centre (Mashya cell) Ngororero Muhanda Mashya 29.5006 -1.7851 5490 151 4,14 30x Muhumyo centre Muhumyo centre, Gatomvu umudugudu Ngororero Muhanda Bugarura 29.4800 -1.7951 8022 176 4,14 110

Nkomane (Busoro) Nkomane umudugudu (Busoro cell) Nyabihu Karago Busoro 29.4967 -1.6430 2 88 6,02 40Nkomane (Cyamabu) Nkomane umudugudu (Cyamabu cell) Nyabihu Rambura Cyamabu 29.4823 -1.6784 3624 88 5,23 44

x Nkomane (Kadahenda) Nkomane umudugudu (Kadahenda cell) Nyabihu Karago Kadahenda 29.5059 -1.6461 9 135 4,78 135Ntalama PS (4 rooms) Nyabihu Rambura 29.5294 -1.6698 1373 0 5,23 7

x Nyaburaro PS (12 rooms) Nyabihu Karago Kadahenda 29.5187 -1.6490 951 133 4,78 133Nyamatanzi Nyamatanzi umudugudu near proposed SHP Nyabihu Jomba Nyamatanzi 29.5714 -1.6993 1540 129 5,07 35Nyiragikokora Nyiragikokora umudugudu Nyabihu Rambura Mutaho 29.4730 -1.6729 4215 218 5,23 100Rebero Rebero umudugudu Nyabihu Karago Busoro 29.4766 -1.6581 2784 83 5,22 20Remera Nyabihu Karago 29.5321 -1.6651 1594 50 5,23 50

x Rukorati Tea nursery & future umudugudu Ngororero Kabaya 29.5210 -1.7602 2224 100 4,55 63

Included

in RE

plan Village/Umudugudu

Primary

School

Secondary

school

Dispensary/

Health

centre Hospital Church Shop Restaurant

Cabaret/drin

khouse

Government

building Butcher

Barber/salo

on Video show

x Bukongora 0 0 0 0 1 8 19 5 0 0 1 1x Bukunzi 1 1 0 0 1 0 0 0 0 0 0 0

x Burorero 0 0 0 0 0 5 0 2 0 0 0 0Gatongo 0 0 0 0 0 2 0 3 0 0 0 0

x Gatovu 0 0 0 0 3 7 2 3 0 0 0 0

x Gatwe 1 0 0 0 4 3 1 11 1 0 1 0Kazuba 0 0 0 0 0 4 0 3 0 1 0 0

x Mashya 1 0 0 0 3 0 0 3 0 0 0 0x Muhumyo centre 0 0 0 0 7 20 4 10 0 0 3 2

Nkomane (Busoro) 0 0 0 0 2 6 0 0 0 0 0 0Nkomane (Cyamabu) 0 0 0 0 0 6 0 2 0 0 1 1

x Nkomane (Kadahenda) 1 1 1 0 3 1 0 1 0 0 2 0

Ntalama 1 0 0 0 1 0 0 0 0 0 0 0x Nyaburaro 1 0 0 0 1 0 0 0 0 0 0 0

Nyamatanzi 0 0 0 0 0 0 3 4 0 1 0 0

Nyiragikokora 2 0 1 0 0 20 4 0 0 1 4 0Rebero 0 0 0 0 0 5 0 1 0 0 0 0Remera 0 0 0 0 0 0 0 0 0 0 0 0

x Rukorati 0 0 0 0 4 11 2 6 0 0 2 1



ANNEX 2: Criteria for load centre ranking

Theme : Weight :

Value

0.00.20.40.60.81.0

0.00.20.40.60.81.0

0.01.0

Theme : Weight :

Value

0.00.81.0

0.00.30.71.0

Theme : Weight :

Value

0.00.51.0

None

Health centre

Criteria Criteria Weight Indicator

Best health facility 1/1

2

>3

Health 1/3

Best education facility 4/5

None

Hospital

Primary

Secondary

Church 1/5

0

1

Education 1/3

Criteria Criteria Weight Indicator

>23

Government building 1/6

Yes

No

Distance from main road (m) 1/3

<100

100-999

6-7

8-9

10-15

16-23

Indicator

Commercial activities 1/2

0-5

Economy 1/3

Criteria Criteria Weight

1000-1499

1500-2499

2500-4199

>4200



ANNEX 3: Load curves for the load forecast model



ANNEX 4: Economic and Financial Analysis of the baseline scenario

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