rural electrification plan report suma v5...paceaa – rural electrification plan for tanzania –...

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POVERTY ALLEVIATIONTHROUGH CLEANER ENERGYFROM AGRO-INDUSTRIES IN

AFRICA - PACEAA

RURAL ELECTRIFICATIONPLAN

SUMA SHP, TANZANIA

PACEAA – Rural Electrification Plan for Tanzania – D3 Report November 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 24/09/09 19/11/09

Written by AJ & LB AJ & LB

Reviewed by DRM DRM

Approved by DRM DRM

Distribution level limited limited



TABLE OF CONTENT

1 EXECUTIVE SUMMARY ______________________________ 7

2 GENERAL INTRODUCTION ___________________________ 9

2.1 Background & Objectives______________________________________________9

2.2 Overall presentation of the methodology________________________________11

3 PRESENTATION OF THE PROJECT AREA _____________ 11

3.1 Overview __________________________________________________________11

3.2 Electrification status of the area _______________________________________14

3.3 Selection of target villages____________________________________________15

4 LOAD FORECAST _________________________________ 16

4.1 Objective __________________________________________________________16

4.2 Methodology _______________________________________________________16

4.3 Assumptions and parameters _________________________________________16

4.4 Results ____________________________________________________________19

5 SUPPLY OPTIONS _________________________________ 22

5.1 Grid network _______________________________________________________22

5.2 Suma Small Hydro Power Plant________________________________________22

5.3 Decentralised small-scale renewable energy projects _____________________22

6 MATCHING SUPPLY WITH DEMAND __________________ 23

6.1 Objective __________________________________________________________23

6.2 Methodology _______________________________________________________23

6.3 Assumptions _______________________________________________________23

6.3.1 Katumba tea factory __________________________________________________ 23

6.3.2 Rural demand _______________________________________________________ 25

6.3.3 Hydro ______________________________________________________________ 26

6.4 Results ____________________________________________________________26

7 RURAL ELECTRIFICATION PLANS ___________________ 29

7.1 Proposed plans _____________________________________________________29

7.2 Network design _____________________________________________________30

7.3 Costing ____________________________________________________________32

7.3.1 Unit costs___________________________________________________________ 32

7.3.2 Results_____________________________________________________________ 33

7.4 Financial Analysis ___________________________________________________34

7.4.1 Objective ___________________________________________________________ 34

7.4.2 Methodology ________________________________________________________ 34

7.4.3 Parameters and assumptions ___________________________________________ 35

7.4.4 Results – business as usual ____________________________________________ 38

7.4.5 Capability to pay _____________________________________________________ 39

7.4.6 Results – with subsidies _______________________________________________ 39



7.4.7 Sensitivity studies ____________________________________________________ 41

8 ECONOMIC COMPARISON WITH GRID EXTENSION _____ 43

8.1.1 Objective ___________________________________________________________ 43

8.1.2 Methodology ________________________________________________________ 43

8.1.3 Results_____________________________________________________________ 44



LIST OF FIGURES

Figure 1 RE plan ................................................................................................................................... 7

Figure 2 Sources of electricity in year 1 ................................................................................................ 8

Figure 3 Sources of electricity in year 20 .............................................................................................. 8

Figure 4: PACEAA rural electrification project sites in East Africa ..................................................... 10

Figure 5: Map of the project area ........................................................................................................ 12

Figure 6: 3D Map of the project area .................................................................................................. 13

Figure 7: Google image of part of the study area, showing the household desnsity in the vllages ofBusona (to the left of the river) and Bunyakikosi (to the right of the river). The box’s show wherethe location of the households.................................................................................................... 14

Figure 8 Average daily load curve in W for the first year (without technical losses)........................... 19

Figure 9 Average daily load curve in W for the20th year (without technical losses) .......................... 19

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

and 20th

year (without technical losses) ......... 20

Figure 11 Evolution of yearly consumption and peak demand during the planning period (inc.technical losses) ......................................................................................................................... 20

Figure 12 Evolution of LV and MV clients during the planning period (inc. technical losses)............. 20

Figure 13 Evolution of yearly demand since 2001 .............................................................................. 23

Figure 14 Monthly grid consumption in Katumba factory.................................................................... 24

Figure 15 Monthly grid consumption in Katumba factory, in percentage of maximum yearly demand.................................................................................................................................................... 24

Figure 16 Daily demand of Katumba tea factory................................................................................. 25

Figure 17 Monthly variations of demand in TANESCO supplied Suma village .................................. 25

Figure 18 Seasonal rainfall pattern in Katumba.................................................................................. 26

Figure 19 Evolution of rural demand compared to tea factory demand.............................................. 26

Figure 20 Hydro and load curve, first week of the first year of the planning period............................ 27

Figure 21 Hydro and load curve, first week of September, 1st

year of the planning period ................ 27

Figure 22 Breakdown of hydro power use in year 1 ........................................................................... 28

Figure 23 Breakdown of hydro power use in year 20 ......................................................................... 28

Figure 24 RE plan map ....................................................................................................................... 29

Figure 25 Project cash flow................................................................................................................. 38

Figure 26 Breakdown of operation costs over the planning period..................................................... 38

Figure 27 Evolution of retail tariffs to reach financial equilibrium, under different levels of subsidy... 40

Figure 28 Average retail tariffs under different scenarios and different levels of subsidy .................. 42

Figure 29 Map of grid extension.......................................................................................................... 44

Figure 30 Map of economic breakeven between hydro and the grid.................................................. 45



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

EC European Community

EIRR Economic Internal Rate of Return

ESCOM Electricity Supply Corporation of Malawi

EWURA Energy & Water Utilities Regulatory Authority of Tanzania

FIRR Financial Internal Rate of Return

IED Innovation Energie Développement

GEF Global Energy Fund

GIS Geographical Information System

GTIEA Greening the Tea Industry in East Africa project

KPLC Kenya Power & Lighting Company Limited

LRMC Long Run Marginal Cost (of the grid)

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

REA Tanzanian Rural Energy Agency

RSTGA Rungwe Smallholders Tea Growers Association

SACCO Savings and Credit Cooperative Societies

SHP Small Hydro Power Plants

TANESCO Tanzania Electric Supply Company Ltd. (power utility)

TATEPA Tanzanian Tea Packers

TF Tea Factory

UNDP United Nations Development Programme

UNEP United Nations Environment Programme

VAT Value Added Tax

WATCO Wakulima Tea Company Ltd.

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 21st

September 2009: 1 USD = 1297 TSh

1 EXECUTIVE SUMMARY

The project area falls in Rungwe district in Mbeya region (South-Western part of Tanzania). Thestudy area is defined by the Katumba Tea Factory to the west, the Mwakaleli Tea Factory to theeast and the proposed small hydro power plant to the south of the town Suma.

Wakulima Tea Company plans to invest either directly or through a SPV into the Suma hydroscheme on Suma river, evaluated at about 1.5 MW. A direct line would be built to supplyKatumba tea factory and inject the surplus on the TANESCO grid, at the regulated feed-in tariff.

The TANESCO grid covers already some of the main towns of the area, such as Suma town,along the main road going from Katumba to Mwakaleli tea factory and Kendete town.Electrification rate in these places is very low, and support should be given to help pay theupfront connection costs.

Most villages inland from this main road are relatively scattered, making rural electrificationproject appear less attractive. However, a few centres are still suggested as targets forelectrification from the suggested Suma SHP and the power line going to Katumba tea factory,as shown on the map below:

- Malamba village, next to SHP, to connect a school and compensate local community forthe use of the river

- Itagata, under the line going to Katumba tea factory, with two schools and a healthcentre

- Busona & Bunyakikosi centres on the road towards Suma town from Suma SHP

Figure 1 RE plan

In total, the following are targeted

- 4 villages

- 296 households living close enough to the transformers to be potential customers (442in year 20)

- 4 primary schools, 1 secondary school, 1 dispensary and 4 churches

- 46 commercial activities expected shortly after electrification

- 62 customers in year 1 and 182 in year 20



It has been assumed that most demand would be for productive and social uses whilst domesticdemand would account for only 17% (year 1) to 14% (year 20) of total demand over theplanning horizon, due to the overall low household consumption rates. Targeting productive andsocial services will ensure that basic services are provided to all.

Part of the power needed for rural electrification would come from hydro, and part from theTANESCO grid through a two-way interconnection with the grid.

65%

35%

Suma SHP

Grid

Figure 2 Sources of electricity in year 1

51%

49%Suma SHP

Grid

Figure 3 Sources of electricity in year 20

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

41%

0%

59%

Tea factories

Rural electrif ication

TANESCO

Figure 6 Breakdown of hydro output in year 1

83%

3%

14%

Tea factories

Rural electrification

TANESCO

Figure 6 Breakdown of hydro output in year 20

Investment costs of the project including meters, transformers, switches, 3.5km of MV lines and2.2km of LV lines, would amount to 178,800 USD in the first year and an additional 108,300USD over the period.

A distribution company is assumed to purchase power from the hydro project developer at bulktariff and then sell it to its customers. The power purchase tariff of 100 TSh/kWh has beencalculated as the weighted average of hydro feed-in tariff and TANESCO industrial tariff, sincepart of the power would come from the grid as shown above.

Under conventional business conditions, and with 30% equity brought by the distributioncompany, the distribution company would need to sell power at 432.41 TSh/kWh (33.3UScts/kWh) on average to reach only 5% IRR over 20 years. Although this very high tariff maystill be affordable for some categories of end-users, because of their very costly currentalternatives (kerosene, batteries, diesel, PV… cf. chapter on capability to pay), solutions tocome closer to TANESCO tariffs have been sought.

The challenge in this endeavour is that the power purchase tariff of 100 TSh/kWh is alreadyhigher than the average retail tariff from the grid (95.6 TSh/kWh). Therefore, a grant of 100% onall investments would bring retail tariffs of the project down to 146 TSh/kWh only. Asupplementary move from the hydro project developer would be needed, by selling power at alower price to the distribution company. In this case, and assuming 100% grant on investment, apower purchase tariff of 61 TSh/kWh would be needed to reach TANESCO tariffs (costing thehydro project developer 1100 USD in year 1 and 8100 USD in year 20). Another way ofimproving the financial viability of the project is to consider it as part and parcel of the Sumahydropower project. This would increase investments costs by 4.7% and decrease the IRR from7.3% to 6.4%.

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 comparison with plain grid extension shows that, even though hydro productioncosts are higher than the marginal costs (LRMC) of the grid, targeting villages, which are closerto hydro than to the grid, such as the ones suggested here, makes economic sense.

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.

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 cofinancingfrom 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 inNovember 2008: village level survey, household surveys, surveys to publicservices, commercial activities, and agro-industries.

o Review of consumption patterns/behaviours of existing TANESCO clients:monthly consumption & variation, percentage of people connected, growth ratein consumption.

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 have been written by IED.

2.2 Overall presentation of the methodology

This Rural Electrification feasibility study follows the following steps:

(1) Identification 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, including brief study of the supply/demandmismatch

(4) Presentation of the suggested Rural Electrification plans, including costing and financialanalysis

(5) Comparison of proposed projects with plain grid extension

3 PRESENTATION OF THE PROJECT AREA

3.1 Overview

The project area falls in three administrative wards : Suma, Kandete and Mpombo words,located in Rungwe district in Mbeya region. The study area is defined by the Katumba TeaFactory to the west, the Mwakaleli Tea Factory to the east and the proposed small hydro powerplant to the south of the town Suma. A map of the area follows. The area covers an area ofabout 16 km long by 10 km wide.



Figure 5: Map of the project area



Figure 6: 3D Map of the project area



100 m

Sumariver

School

School

Busonacentre

The two tea factory’s were privatised in September 2000 to Wakulima Tea Company ltd(WATCO) who in turn is owned by TATEPA (Tanzanian Tea Packers) owning 75% of theshares and 25% of the shares by the Rungwe Smallholders Tea Growers Association (RSTGA),representing 15 000 small holder tea growers that together supply 83% of the green leafprocessed by the two tea factory’s.

Mbeya region is in the South Western Corner of the Southern Highlands of Tanzania, the regionlies at an altitude of 475 metres above sea level with the Rungwe peaks reaching heights of2 981 m above sea level. The topography is characterised by rolling hills, large plateaussurrounding high peaks and ridges, bounded on all sides by escarpments or deeply dissectedhills. The altitudes of the plateaus range from 1 400 to 2 400 m.

Mbeya region is one of the most important cash crops producer in Tanzania, responsible for35 % of tea produced in the whole country. About 5 535 ha are under tea production. Populationdensities are among the highest in Tanzania, reaching 134 people/km2.

The study area is home to about 7 400 households (2002), that reside in the small towns on themain road from Katumba to Kandete or inland from the main road wherein households tend tobe of a dispersed nature as shown in the image au-dessous. Villages tend to cover large areaswith a few hamlets of a very few households, population density is therefore low resulting incostly electrification.

Growers in most cases only collect 60 TSh/kg of green leaf which barely makes plucking tea aworthwhile activity hence the diversification to other cash crops like banana’s, beans, maize,coffee etc.

In the villages close to the small hydro power the number of tea growers is small, in Busonathere are 38 tea farmers, in Bunyakikosi there are 97 growers and in Malamba 4 growers only.However, there are plans to expand the area under tea in the Rungwe District, and alsoincrease the yield per unit area for the existing areas.

Figure 7: Google image of part of the study area, showing the household density in the vllages of Busona (to the left ofthe river) and Bunyakikosi (to the right of the river). The box’s show where the location of the households.

3.2 Electrification status of the area

A 33 kV TANESCO line follows the road from Katumba to Kandete and ends at Isange. Anumber of villages have transformers yet a significant proportion of households remain withoutaccess to power. In the village of Suma for example (located close to the project site), only 12clients are connected to the 100 KVA TENESCO transformer. Access rates remain very low andconcerted efforts should be made to address this. The reasons echoed by everyone is the costof connection which is prohibitive for the vast majority of people, even with the introduction byTANESCO of a staged three installment payment over three months for the connection cost,people seem to still have problems in saving this amount of money in this short period of time.No power is provided to the customers until the full amount is transferred. Some other people



expressed that it was not so much paying the connection costs but more the handoutsdemanded by some of the actors in the area.

A battery charging station does exist in Suma yet has only two clients per day and in total eightpermanent clients who recharge on a weekly basis paying 1500 TSh per week. The clients areeither teachers or churches. The main barrier to the extended use of car batteries wasexpressed by the owner as being the initial investment cost of the battery which amounts toabout 85,000 TSh (45 Euro). Not many households can afford this first initial cost. Overall, in thearea around the SHP site the standard of living was considered as poor with the majority ofhouseholds having thatched roofs. It is hoped that increased access to fairtrade premiumssome of the returns will be fed back into the community.

Presently most villages consume kerosene for lighting and small batteries for radio’s. Socio-economic activities in villages are very low.

3.3 Selection of target villages

Considering the very low density of villages in the area, it is suggested to connect only villages,which are along or close to the upcoming power line going from the proposed hydro site toKatumba Tea Factory:

- Malamba village, where the hydro site will be located. Two distribution transformers aresuggested: one west of the powerhouse, where a primary school is located. Andanother one on the eastern side of the scheme, where the hydro canal will be built.Household density in this area is comparatively good, and supplying power in this areamay be seen as a compensation move for the canal.

- Itagata village, below the proposed power line going straight from the hydro site toKatumba tea factory (cf. Suma Feasibility Study). 3 interesting areas in the village maywelcome a transformer, covering 2 primary schools and a dispensary, as well as about140 households.

- Busona and Bunyakikosi centres, which can be supplied by a single MV/LV transformerconsidering their proximity. This area, on the way from the hydro site to the main road,has slightly higher household density, as well as a primary and secondary school. Eventhough it is farther from the upcoming power line than other RE targets, it has beenfound that its relatively higher demand compensates the distance. Financial aspects ofthe project are thus not changed drastically, whilst social benefits improve significantly.

Target populations are those within LV range of these proposed transformers, i.e. 500m. Thenext map provides an overview of their location, but their exact coordinates are given in Annex1.

Table 1 Location of proposed transformers



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 number of households living within LV range of each proposed transformers (500m) hasbeen determined from satellite imagery (Google Earth®), adjusted with a +30% correctionfactor, to take into account the possibility of households not appearing on the image, as well aspossible new households coming in the area as a result of electrification.

The population growth rate has been taken equal to 2.04% (CIA World Factbook, 2009) and thenumber of people per households is taken to be 4.46 (survey data). Households have beensegmented in 3 income classes, and their distribution for each village has been assessedthrough discussions with village chiefs. Significant discrepancies have been found betweenfigures given by local authorities and a few direct interviews with villagers, therefore relativeweights of households classes have been slightly adjusted (e.g. a few 200,000+ TSh/monthincome households have been encountered in areas supposed to be left without any “richerhouseholds”). It is assumed that the weight of the poorest class of households (class 3) willdecrease by 10% over 20 years, while the weight of the middle class will increase by 10%.

The number of social and community facilities (schools, health centres and churches) obtainedthrough interviews with village representatives, are assumed to stay constant over time.However, the number of commercial activities will quickly grow after electrification, to reach agiven ratio

1per number of households in the village. These ratios, which have been taken,

correspond to averages of the project area for partially electrified villages, as shown in thefollowing table.

1The ratio applies not only to the number of households within LV range of proposed

transformers but rather to the total population of the hamlet, under the safe assumption thateconomic activities will concentrate in its electrified part. In cases where several transformersare suggested for a single hamlet, its total population is split equally among the differenttransformers.



Chosenfigures

Average ratios per 100 HH from survey

Electrified Partly electrified Non electrified

Shops & restaurants 1.9 7.5 1.9 1.3

Barber/saloon, bicycle repair, tailor, video 0.5 1.2 0.5 0.1

Carpenter, welding, battery charging 0.8 1 0.8 0.4

Mills 0.7 2 0.7 0.1

Table 2 Ratios of economic activities per 100 households

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 5x25W CFLs, 1 stereo, 1 TV 305 43

HH class 2 4x25W CFLs, 1 radio, 50% own 1 TV 158 20

HH class 3 3x25W CFLs, 1 radio 93 12

water pump (per 100 hh) 500 91

street lighting (per 100 hh) 250 53

School 10x25W lighting evening (CFLs) 250 23

Dispensary

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

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

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

Carpenter, welding,battery charging

Installed capacity of 1.5kW, operating in themorning and afternoon 1,500 224

Mill Average 15kW (~20 hp) 15,000 1770

Table 3 Specific consumption of different types of end-users

NB: consumption figures for households are lower than actual consumption averages inTANESCO supplied areas (2008 data): 15 kWh/month for the small consumers and 51kWh/month for medium. However, these figures include non domestic users, and given the lowpenetration rate in already richer TANESCO areas, it is expected that people, which are actuallyconnected to the electricity service, are slightly richer than the average consumer of thisproposed RE project. Moreover, new appliances will probably be added over time (fans, iron,fridge…), which is reflected in the 5% consumption increase per annum, cf. table below.

It is assumed that the size of mills would be similar to the ones encountered in the area.However, for the sake of power availability it is strongly advised to promote use of smaller mills,



such as the ones used in Western Africa, with nominal capacities of not more than 3kW (4 hp),instead of 15 to 20kW. The average mill consumption in Suma village has been kept (1770kWh/month in 2008).

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

Years 1 1-10 10 10-20 20

Connection rates

Households2

class 1 50% 80% 100%

Households class 2 20% 30% 50%

Households class 3 5% 10% 20%

Commercial and community activities 50% 80% 100%

Consumption growth rates3

(%/year)

Households (all classes) 5% 0%

Commercial and community activities 1% 0%

Table 4 Connection rate and consumption growth rate assumptions

Connection rates for households classes 2 and 3 are assumed to remain low because of thehigh upfront costs borne by the customer, which include the connection fee, in-house wiring andpurchase of appliance.

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

2NB - this refers to households that are reachable (within 500m of proposed transformers).

3These growth rates apply to the consumption of each single customer, not to the overall

demand.



4.4 Results

Load forecast has been done for each identified load centre. Detailed tabulated results andcharts are given for the whole group of load centres.

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

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 8 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):

0

20000

40000

60000

80000

100000

120000

140000

160000

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

Domestic demand has further reduced its share (from 17% in year 1, to 14% in year 20),revealing the importance of non domestic end-users in the technical sizing and economicviability of the project. Evolution of load curve over the planning period is shown in the nextchart:



0

20000

40000

60000

80000

100000

120000

140000

160000

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 10 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

1 2 3 4 5 6 7 8 9 1011 12 13 14 1516 17 18 19 20Year

Co

nsu

mp

tio

n(k

Wh

)

0

20

40

60

80

100

120

140

160

180

Po

wer

(kW

) Consumption(kWh)

Peak (kW)

Figure 11 Evolution of yearly consumption and peak demand during the planning period (inc. technical losses)

0

20

40

60

80

100

120

140

160

180

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

5

10

15

20

25

Th

ree

ph

.cli

en

ts Singlephaseclients

Threephaseclients

Figure 12 Evolution of LV and MV clients during the planning period (inc. technical losses)



YearSingle ph.clients

Three ph.clients

Consumptionper year

Peak

kWh kW

1 47 8 41 542 22

5 70 14 133 203 73

10 98 20 247 780 138

15 135 21 274 345 148

20 169 22 300 910 157

Table 5 Load forecast for scenarios A1 and B1

It can be noted that the forecasted demand is rather marginal compared to the expected hydrooutput. RE demand would represent from 0.7% (in year 1) to 5% (in year 20) of the 6 GWhproduced by Suma hydro according to the CECB draft feasibility study.



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 tea company distribution network, ordistributed power generation (Pico hydro or PV).

5.1 Grid network

Plain grid extension has not been considered directly for RE plans, as it doesn’t fall within thescope of this study. In fact, it is believed that prior to grid extension, significant efforts should bemade on grid densification (increase connection rates in already electrified area). However,comparison of RE plans with grid extension from an economic point of view has been carriedout in the last chapter.

The grid network will nevertheless play a role in the supply of power to the proposed REprojects, if the power line connecting Suma SHP to Katumba tea factory operates as a two-wayline (exporting power when hydro is sufficient, and importing from the grid otherwise). This is intheory possible since voltage levels (33kV) will be the same. However, technical issues remainto ensure the safety of both hydro and TANESCO grids. This option will still be considered, aspart of the RE demand will probably not be met by hydro only (cf. chapter 6 on hydro supply anddemand matching) and TANESCO did not reject this option after presentation of the plans.

5.2 Suma Small Hydro Power Plant

The Suma SHP would be a run of the river type scheme located at the Suma waterfalls inMalamba, close to Bunyakikosi. Its recommended installed capacity would be 1.54MWaccording to the CECB feasibility study, and estimated annual output would be around 6 GWh.

The feasibility study suggests to build a 8km 33kV transmission line from the SHP site toKatumba tea factory.

Rainfall being quite seasonal (load factor would be 47%), it is expected that the SHP would notmeet the demand of the Katumba tea factory during the dry season, which may be a challengeto the RE project. This is explained in detail in the next chapter.

5.3 Decentralised small-scale renewable energy projects

Due to the abundance in small streams, the low consumption patterns and the low populationdensity it is thought that the area holds an interesting potential for pico hydro’s (<10kW) forcommunity electrification. Pico hydro’s in South East Asia of a reasonable standard are sold ataround 50 USD / 200 W system (or 150 USD for 1 kW). A revolving fund/ credit scheme couldassist households in covering the first initial investment costs which in the case of renewabletend to be the main stumbling block to investment.



6 MATCHING SUPPLY WITH DEMAND

6.1 Objective

The objective here is to match the demand from rural communities and Katumba tea factory,with the assumed output from hydro, to assess the part of rural demand which could be met byhydro, and the part which would not be satisfied.

6.2 Methodology

The most common way of matching hydro production with demand is to use a statisticalapproach with load and power duration curves. This approach assumes that power and demandare not correlated. This assumptions may not be accurate in the case of tea factories, sincerainfall is related to their activity.

Periods of lower rainfall tend to be periods of lower activity. Therefore, the approach used in thisstudy is based on actual comparison of power and demand for each hour of the year, usingassumptions on power and demand fluctuations for different time scales (monthly, weekly, dailyand hourly). Calculations have been done with a dedicated Excel tool.

6.3 Assumptions

6.3.1 Katumba tea factory

Yearly variations of demand are as follows:

-

500 000

1 000 000

1 500 000

2 000 000

2 500 000

3 000 000

3 500 000

2001 2002 2003 2004 2005 2006 2007 2008

Co

ns

um

pti

on

(kW

h/y

r)

Figure 13 Evolution of yearly demand since 2001

Demand in Katumba has drastically increased over the past decade, with an average growthrate of 18% per annum. The trend over the past 3 years has been 11%, therefore this figure willbe kept until year 5, thereby bringing the load factor to ~50% (of the installed transformercapacity of 1000 kVA). After this date, a slightly lower growth rate of 2% is taken.

NB: diesel consumption has not been included in the analysis, as data was missing before2006. However, recent consumption shows that it remains marginal (2% of total demand).



Seasonal variations have been averaged over 7 years:

-

50 000

100 000

150 000

200 000

250 000

300 000

350 000

400 000

450 000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Co

nsu

mp

tio

n(k

Wh

)

Average 2001 2002 2003 2004

2005 2006 2007 2008

Figure 14 Monthly grid consumption in Katumba factory

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Co

nsu

mp

tio

n(%

of

yearl

ym

ax)

Average 2002 2003 2004

2005 2006 2007

Figure 15 Monthly grid consumption in Katumba factory, in percentage of maximum yearly demand

Daily demand data taken from 31st

Jan to 4th

Feb 2006 shows a rather erratic pattern, withslightly less demand in the evening (no demand happens on Monday):



0

100

200

300

400

500

600

700

6:0

0

7:0

0

8:0

0

9:0

0

10:0

0

11:0

0

12:0

0

13:0

0

14:0

0

15:0

0

16:0

0

17:0

0

18:0

0

19:0

0

20:0

0

21:0

0

22:0

0

23:0

0

Lo

ad

Cu

rve

(kV

A)

Tue Wed Thu Fri Sat Sun Average

Figure 16 Daily demand of Katumba tea factory

Based on these significant variations, he following assumptions have been done for the dailyand hourly random variations of the model:

- Day-to-day variation: +/- 32%

- Hour-to-hour variation: +/- 52%

6.3.2 Rural demand

TANESCO data in Suma gives an indication of seasonality of rural demand:

0,00%

10,00%

20,00%

30,00%

40,00%

50,00%

60,00%

70,00%

80,00%

90,00%

100,00%

Jan

Feb Mar Apr

May Ju

nJu

lAug Sep O

ctNov

Dec

Co

nsu

mp

tio

n(%

of

yearl

ym

ax)

Small customers

Medium customers

Large customers

Mills

Figure 17 Monthly variations of demand in TANESCO supplied Suma village

Given the weight of mills in the total consumption, seasonality will be taken from the milldemand pattern.

In the absence of daily load curves for rural customers, the following assumptions have beendone for the daily and hourly random variations:



Other assumptions are taken from the load forecast, detailed in chapter 3. As a conservativehypothesis, demand data has been taken from the largest scheme (including all identified loadcentres).



6.3.3 Hydro

Technical sizing of the Suma SHP has been taken from the feasibility study. Seasonal flowvariations have been estimated from the following rainfall data:

-

100

200

300

400

500

600

700

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sept

Oct

Nov

Dec

Katu

mb

aR

ain

fall

(mm

)

1993 1994 1995 1996

1997 1998 1999 2000

2001 2002 Average

Figure 18 Seasonal rainfall pattern in Katumba

Assumptions on daily and hourly random variations are:



6.4 Results

Long-term variations

0,00

1000,00

2000,00

3000,00

4000,00

5000,00

6000,00

7000,00

8000,00

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

Year

MW

h

Rural demand Tea factory

Figure 19 Evolution of rural demand compared to tea factory demand

As shown in chapter 3, rural demand remains marginal compared to tea factory demand (from2% to 6% of tea factory demand).



The following charts show samples of randomly generated load and power curves for differenttimes of the year.

0

200

400

600

800

1000

1200

1400

1600

1800

Time

Po

we

r(k

W)

Production Total demand (RE + TF) Rural demand

Figure 20 Hydro and load curve, first week of the first year of the planning period

The x-axis of these charts represents the time of day, and a full week is shown (from Tuesdayto Monday). In the example above, the contribution of rural demand to total load curve is almostnegligible, and all rural demand is met. On the contrary, the following chart shows a situation inSeptember of the 1

styear (2009), in which demand is not fully met.

0

100

200

300

400

500

600

700

800

900

1000

Time

Po

we

r(k

W)

Production Total demand (RE + TF) Rural demand

Figure 21 Hydro and load curve, first week of September, 1st year of the planning period

In this case, hydro output is extremely low, whereas tea factory demand remains high.Therefore, even though enough power may be available for the low rural demand, if the teafactory has the priority, then no power will be left for rural end-users.



The following tables give the final result of the calculation:

YearPart of RE demandcovered by hydro

Part of Katumba TFdemand covered by hydro

1 65% 67%

5 57% 60%

10 55% 58%

15 53% 56%

20 51% 54%

Table 6 Part of demand supplied by hydro power

In terms of usage of hydro power output, the results are as follows:

27%

0%

73%

Katumba TF


TANESCO

Figure 22 Breakdown of hydro power use in year 1

NB: the total demand of the RE project and Katumba tea factory amount to 41% of hydro outputin the first year. However, since all demand will not be met by hydro power (cf. Table 6 above),the shares indicated on the pie chart above are slightly lower.

45%

3%

52%

Katumba TF


TANESCO

Figure 23 Breakdown of hydro power use in year 20



7 RURAL ELECTRIFICATION PLANS

7.1 Proposed plans

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

Figure 24 RE plan map

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

Households in year 1 296

Households in year 20 442

Primary school 4

Secondary school 1

Dispensary/Clinic 1

Church 4

Shops and restaurants 23

Barber, video show, arts and crafts 7

Carpenter, welding, battery charging 8

Mill 8

Table 7 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 54 169

Three Phase Customers 8 22

Table 8 Expected number of customers

7.2 Network design

7.2.1.1 MV lines and transformers

The transmission line standard suggested by the Suma Feasibility Study is 33kV, therefore thisvoltage will be used, although 11kV would have been sufficient for the RE part.

Recommended sizing is three phase 3 x 35 mm2, given the peak loads transiting through the

proposed lines (a few hundred kWs at most). 11m treated wood poles are suggested, with anadmissible span of 150m between poles.

The following step-down transformer (33/0.4 kV) capacities have been considered: 15, 25, 50and 100 kVA.

Load centreTF Size year1 (kVA)

TF Size year20 (kVA)

Malamba 1 15 50

Malamba 2 15 50

Busona 25 100

Itagata 1 15 50

Itagata 2 15 50

Itagata 3 15 50

Table 9 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 the hydro power line will be equipped with manual aerialswitches. NB: to cut down on costs, no MV meter will be installed at the interconnection point,as the cost of these equipments (including protection) can go up to 30,000 USD. Therefore, it issuggested to keep track of energy consumption of the project with the disaggregatedconsumption of each end-users (sum of all LV meter readings). Another option would be tosubtract the sum of energy produced by Suma SHP and energy consumed from the grid, by theconsumption of Katumba tea factory. The latter method, however easier to manage, would putthe burden of technical losses on the RE project.

7.2.1.2 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.

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 40m per customer has been considered to assess the required length of LV lines.This ratio has been estimated from the average distance between adjacent buildings, measuredby the GIS software from satellites images.



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

7.2.1.3 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.



7.3 Costing

7.3.1 Unit costs

Cost of transformers are as follows:

TF capacity(kVA)

Unit cost(USD)

15 2 178

25 3 639

50 7 250

100 10227

Table 10 Transformer unit costs

Cost of MV and LV lines are respectively 26 214 USD/km and 18 350 USD/km, to stay in linewith current costs experienced by REA in 2009.

Detailed breakdown is provided below:

ComponentUnit Price(USD)

Unit

Alu cable 35mm² 2.35 ml

joint sleeve 8.35 set

Treated wood pole - 11m 600 per pole

suspension equipment 834 per pole

Reinforced concrete 250 per pole

11m pole (stop-end) - 2 HEA 240 4.00 per stop

stop-end pole equipment 1417 per stop

Reinforced concrete (stop-end) 500 per stop

Table 11 Breakdown of costs for 11kV lines

Component DescriptionUnit Price(USD)

Unit

Alu conductor (3x35+54,6+1x16) mm² 16.46 ml

sleeve 41.15 Unit

Wood pole - 8 m Span of 50m 165 Unit

Conductor support 13.72 Unit

Other accessories 13.72 Unit

Table 12 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 13 Breakdown of costs for single phase and three phase connections

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



7.3.2 Results

Total investments required would be 178,800 USD in the first year and 108,300 USD4

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 1 503 USD per customer in year 20, which is a rather high figure.

YearSingle ph.Clients

Three ph.clients

ConsumptionPeak Total TF

capacityMV lines LV lines

kWh kW kVA m m

1 0 0 0 0 0 1 766 1 080

2 54 8 64 457 35 125 1 766 1 080

3 59 8 87 373 47 125 0 0

4 64 14 110 288 60 125 0 0

5 70 14 133 203 73 125 0 0

6 75 14 156 119 86 175 0 0

7 81 14 179 034 99 175 0 1 280

8 86 20 201 949 112 175 0 0

9 91 20 224 864 125 225 0 0

10 98 20 247 780 138 350 0 0

11 104 20 253 093 140 350 0 0

12 113 20 258 406 142 350 0 1 400

13 119 21 263 719 144 350 0 0

14 126 21 269 032 146 350 0 0

15 135 21 274 345 148 350 0 0

16 141 21 279 658 150 350 0 0

17 148 21 284 971 152 350 0 840

18 154 22 290 284 153 350 0 0

19 163 22 295 597 155 350 0 0

20 169 22 300 910 157 350 0 0

Table 14 Sizing elements of the project over the planning period

4 NB: this figure is in constant price.



Year MV lines LV lines MV switch TransformersThree ph.

connectionsSingle ph.

connections

1 46 281 19 818 5 000 12 722 0 0

2 46 281 19 818 5 000 12 722 2 928 8 262

3 0 0 0 0 0 765

4 0 0 0 0 2 196 765

5 0 0 0 0 0 918

6 0 0 0 0 0 765

7 0 23 488 0 21 033 0 918

8 0 0 0 0 2 196 765

9 0 0 0 0 0 765

10 0 0 0 0 0 1 071

11 0 0 0 0 0 918

12 0 25 690 0 0 0 1 377

13 0 0 0 0 366 918

14 0 0 0 0 0 1 071

15 0 0 0 0 0 1 377

16 0 0 0 0 0 918

17 0 15 414 0 0 0 1 071

18 0 0 0 0 366 918

19 0 0 0 0 0 1 377

20 0 0 0 0 0 918

Table 15 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.

7.4 Financial Analysis

7.4.1 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.

7.4.2 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.

7.4.3 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 10.30% (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 7.3.2, 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(TSh/month)

Accountants 1 400 519 000

Collection officers 2 100 130 000

Table 16 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 hydro power line. However, as explained in chapter 6,part of the demand may not be met by the SHP, but by the TANESCO grid instead (through thehydro power line). Therefore, specific costs of TANESCO and hydro power have to bedetermined to assess the likely bulk purchase tariff agreed between the distribution companyand the hydro SHP owner.

The published feed-in tariff for hydro is 96.11 TSh/kWh (EWURA, 2009). Therefore, to make itinteresting for the hydro developer to sell to the rural distribution company, we suggest to setthe hydro purchasing price equal to the FIT (besides, this tariff is expected to increase with a2% inflation per year in our model, which may not be the case for the FIT).

The current bulk purchase tariff from the grid for the tea factory is 104.92 TSh/kWh on average(including fees for installed capacity and without VAT, which is refunded).

The resulting power purchase tariff is a weighted average of both tariffs, using the proportion ofpower coming from hydro calculated in chapter 6: 100.03 TSh/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 currentTANESCO tariff structure, to allow easier comparison between the two:



Single Phase Three Phase

Domestic No fixed fee

Tariff: Parameter

N/A

Non domestic No fixed fee

Tariff: 2.65 x Domestic tariff5

Fixed fee: 1892 TSh/month

Tariff: 2.65 x Domestic tariff

Table 17 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 (65 000 TSh, one third of actual connection costs) for single phaseand 183 USD (237 000 TSh, 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 30% 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 10 years; with a grace period of 1 year (notincluded in the 10 years).

The loan is expected to be coming from local banks at the current commercial lending rateof 16.03% (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 17.03% 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%.

22% of taxes are added to the Project Retail Tariffs:

- VAT: 18%

- EWURA levy: 1%

- REA fund: 3%

5This ratio is the same as in the current TANESCO tariff structure



7.4.4 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) 178 800

Investment over the period (USD, constant price) 108 300

Equity first year (USD) 61 700

Maximum equity injection (USD) 166 900

Domestic Retail Tariff to achieve 5% FIRR (TSh /kWh, inc. taxes) 180.85

Commercial Retail Tariff to achieve 5% FIRR (TSh/kWh, inc. taxes) 479.26

Average Retail Tariff to achieve 5% FIRR (TSh /kWh, inc. taxes) 432.41

Average Retail Tariff to achieve 5% FIRR (UScts/kWh, inc. taxes) 33.3

Table 18 Financial results – “business as usual”

C as h F low

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C umulated C as hF low (P rojec t)

Figure 25 Project cash flow

As shown in the cash flow above, the payback period is 18 years. The maximum equity injectionoccurs on the 8

thyear, with a total of 166 900 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

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O&M & insurance

Salaries

Figure 26 Breakdown of operation costs over the planning period

It is interesting to note that average retail tariff of 432.41 TSh/kWh (including all taxes) is notexcessively above the published tariff for wholesale of power on a mini-grid (334.83 TSh/kWh).However, this tariff is obviously much higher than what the average tariff would have been withthe current TANESCO tariffs (95.6 TSh/kWh), being already below the tariff at which power ispurchased by the distribution company. The capability to pay for such high tariffs will still bereviewed in the next section.



7.4.5 Capability to pay

The expected average bill for domestic end-users would be:

- Class 1 (richer households): 7777 TSh/month and 13181 Tsh/month in the first year(including connection fee)

- Class 2: 3654 TSh/month and 9058 TSh/month in the first year

- Class 3 (poorer households): 2103 TSh/month and 7507 TSh/month in the first year

These electricity bill must be compared to current energy expenditures (kerosene, mobilecharging, dry cells…), as per the survey done in November 2008:

- Class 1: 15,600 TSh/month



Domestic customers would normally face serious issues in securing initial costs of connection,as shown with current experiences in nearby electrified villages. In fact, car batteries, which arecomparable to the proposed connection fee (85 000 TSh against 65 000 TSh), are generallydeemed not affordable and are thus very rare in the area. However, the suggested pre-financingof connection costs and partial subsidy makes the initial cost of connection much moreaffordable as shown above: monthly expenditure including repayment of connection fee wouldstill remain under the current expenditure on kerosene, batteries etc.

Another possible criterion to assess affordability of electricity is to compare with householdbudget. The survey revealed an average income of 174,000 TSh/month from various activities,such as banana, coffee, tea (in small amounts, currently few households in the area are actuallygrowing tea), maize, beans, pigs and cattle rearing. Although this figure may be overestimatedbecause of sampling and biased answers from respondents, it is believed that at least theminority of households in class 1 (the ones assumed to have high connection rates) would beable to fetch incomes around this figure. It is usually accepted that 10% of household budgetspent on energy is a reasonable proportion, therefore again affordability should not be an issuefor such households.

Finally, an ongoing programme to distribute PV systems for domestic end-users in the area(with the help of RSTGA) sells the systems for 1.5 to 2M TSh, with 40% of it brought as downpayment and the rest through a 3 year credit from local SACCOs. This demonstrate affordabilityfor even more expensive and lower quality electricity service.

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 (0.33 USD/kWh), and connection fees are paid back during the first monthalready. For slightly larger power users such as mills, the comparison with diesel is alsofavorable. Assuming a 5L daily consumption, their diesel expenditure would be around1,150,000 TSh/month, whereas with electricity it would be about 850,000 TSh (26% costreduction).

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 TANESCO levels.

7.4.6 Results – with subsidies

As explained above, it is very likely that such high tariffs would not be well accepted socially,since populations living nearby in TANESCO areas would be enjoying a much lower prices.Therefore, subsidies are considered mandatory to make the project happen under reasonableconditions for the end-users and limited risk for the Project Developer.

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



7.4.6.1 Grants

Grant facilities may be sought such as the fair trade fund of the Outgrowers Cooperative(RSTGA), funds from the Rural Electrification Agency

6and specific programmes of bilateral

agencies. Since investments are spread not only in the first year but also throughout theplanning period, it is advised to provide a grant on all expected investments (possibly releasingpart of the grant progressively, as needed by the project). The results are as follows:

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Average Retail Tariffto achieve 5% FIRR

Power purchasetariff (100 TSH/kWh)

Average TANESCOtariff (95,6TSH/kWh)

Published tariff formini-grid injection(334,8 TSH/kWh)

Figure 27 Evolution of retail tariffs to reach financial equilibrium, under different levels of subsidy

Above 70% of subsidy on investments, the share of equity decreases progressively from 30% to0%. In the best case scenario (100% subsidy on investments), retail tariff of the RE project willcome closer to the power purchasing tariff.

In spite of this, tariff remains higher than TANESCO tariffs, since the anticipated bulk powerpurchase tariff from Suma SHP is almost equal to the average TANESCO retail tariff. 100%subsidy on all investments would bring the retail tariff down to 146 TSh/kWh only. In thiscontext, reaching parity with the grid is impossible without other forms of support.

7.4.6.2 Lower power purchase tariff

Another form of support could indeed come from the hydro project developer, with a powerpurchasing contract at a better rate. Assuming 100% subsidy on investments, a power purchasetariff of 61 TSh/kWh would be needed to reach TANESCO tariffs. The annual cost of such amove for the power seller would be 1100 USD in year 1 and 8100 USD in year 20.

7.4.6.3 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 95.6 TSh/kWh, the results would be:

- Investment costs increase by 4.7%

- IRR over 20 years decreases from 7.3% to 6.4%

Although the impact of RE on the generation project is relatively small, the fact that thegeneration project itself does not appear attractive to the tea factory (targeting IRRs around20%) makes this possibility unlikely.

6Experience from similar projects show that a grant of about 500 USD/customer can be

expected, amounting to about 100,000 USD in this project – about 50% of investments in thefirst year.



7.4.7 Sensitivity studies

Cheaper equipment

Second-hand material may be sought for the RE project. In this case, the unit prices for powerlines and transformers may be halved. The results would then be as follows:

Investment first year (USD) 104 000

Investment over the period (USD, constant price) 65 500

Equity first year (USD) 35 900

Average Retail Tariff to achieve 5% FIRR (TSh/kWh, inc.taxes) 306.24

Average Retail Tariff to achieve 5% FIRR (UScts/kWh, inc.taxes) 23.6

Table 19 Financial results – second hand scenario

Interestingly, if REA is able to provide 500 USD/customer, almost all investment costs in the firstyear would be covered. The resulting retail tariff would then be 145 TSh/kWh.

Soft loan

Under better loan conditions:

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

The results are:



Table 20 Financial results – soft loan scenario

No connection fee

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

Table 21 Financial results – soft loan scenario



Impact on tariffs is limited (only 16 TSh above the base case scenario). An increase in numberof customers of only 9% 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

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h)

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Second-hand

Soft loan

Lower connectioncosts

Power purchasetariff (100TSH/kWh)

Figure 28 Average retail tariffs under different scenarios and different levels of subsidy

The above chart shows that with no subsidy, the most interesting scenario is second-handequipments. Naturally, as the share of subsidy increases, soft loans and cheaper equipmentshave less and less influence on the results.

However, at high subsidy levels, all scenarios tend to remain in a narrow interval above thepower purchase tariff. This fixed gap between the power purchase tariff and the retail tariff isexplained by 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.

At this stage, further improvements on the tariff may be achieved only through better conditionson the power purchase tariff.



8 ECONOMIC COMPARISON WITH GRID EXTENSION

8.1.1 Objective

The aim of this chapter is to compare the economic and financial aspects of the proposed REprojects with conventional grid extension.

8.1.2 Methodology

The Economic Internal Rate of Return (EIRR) is often used to give a broader picture of projectprofitability from the point of view of the national economy. However, its use remains heavilydependent on the choice of economic tariffs, i.e. how much a kWh is valued in terms of generalbenefits for the economy.

A quick and easy way to do it is to base the economic analysis on actual tariffs being charged togrid connected customers, but this approach is usually not relevant for RE projects since theselow (subsidized) tariffs would always result in negative EIRRs. Besides, it is generallyacknowledged that the benefits of electricity are often much higher than the mere value of soldelectricity, through indirect benefits for the communities, even though their extent remainsdifficult to quantify.

To avoid these hurdles, the proposed methodology is based on the levelized cost analysis:

horizon

i i

horizon

i i

r

iBenefits

r

iCosts

1

1

)1(

)(

)1(

)(

costLevelized

Equation 2 Levelized cost of kWh formula

With:

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

Benefits(i) the quantity of kWh sold in year i (not their monetary value)

r the economic discount rate

The economic discount rate is a theoretical construct, the value of which cannot be measured inreality. The rate shall reflect the society’s preference for the short-term consumption ofresources versus the long-term consumption. In developing countries, a high discount rate (>=10%) is used because of the comparatively low standard of living. The economic discount rateused in this study is 10%.

To avoid distorting results with monetary phenomena, inflation as well as cost of financing (loaninterests) are not considered.

All investments and O&M costs remain similar to the financial analysis, except for the cost ofpower purchase:

- The part of power bought from hydro is valued with the economic levelized cost ofSuma SHP: 103.41 TSh/kWh (estimate from Feasibility Study data, including MVdistribution costs)

- The part of power bought from the grid is valued with the Long Run Marginal Cost(LRMC) at MV distribution level of main grid, taken at 74.45 TSh/kWh, which is in linewith EWURA documents (“Tanzania SPPT for Mini-grids under SPPA – 2009”). As avery conservative assumption, the LRMC is not expected to increase over time.

NB: while the financial cost of hydro was lower than the grid, the situation is reversed in theeconomic analysis. This tends to favor the grid over small hydro from the economic point ofview.



8.1.3 Results

8.1.3.1 Same project but different power sources

The levelized cost of the project is 294.25 TSh/kWh (22.69 USc/kWh). Assuming we keepexactly the project as it is except for the power supply, which would be 100% grid powered, thelevelized cost would fall to 278.28 TSh/kWh (21.46 USc/kWh). Grid supply would indeed bemore interesting in this case, because of the lower LRMC of the grid as explained above. Itshould be noted at this stage that the gap between LRMC and hydro levelized cost is flattenedby other (distribution) costs of the project and the fact that approximately half of the powersupplied comes from the grid (cf. chapter on supply and demand matching).

8.1.3.2 Different MV line lengths

However, if we were to connect the same villages from the grid, we would actually need to buildnew power lines from the TANESCO network (in orange dotted lines):

Figure 29 Map of grid extension

Length of MV lines required would be 9.8 km, instead of 3.5 km for scenario A1, because linesof scenario A1 start from the expected powerline going from Suma SHP to Katumba tea factory,which is much closer to them.

Therefore, the resulting levelized cost from the grid (using the same cost assumptions as theRE project) would be 412.28 TSh/kWh (31.79 USc/kWh), which is 40% higher than from hydro.

The breakeven between grid and hydro is reached for 4.7 km of MV lines (1.34 times longerthan length of lines in the proposed RE project).

In conclusion, the economic cost of such a small scale hydro-based rural electrification projectis lower than grid extension, provided targeted villages are sufficiently far from the grid andclose to the hydro site, i.e. distance from the grid is about 1.34 longer than distance fromhydro (which is the case of this project).

8.1.3.3 Off-grid micro-hydro vs. grid extension

The previous conclusions apply to our particular RE project, with 45% of its power coming fromthe grid. If we were to generalise them for 100% hydro powered RE projects, we would need tocompare the levelized cost of the grid (be 412.28 TSh/kWh), with the levelized cost of the



proposed RE project assuming all its demand could be met by hydro: 307.24 TSh/kWh. Even inthis case, the hydro project appears more interesting than grid extension.

The new breakeven would then be reached for 5.3 km of MV lines, approximately 1.5 times thelength required in the hydro project. This criteria is illustrated in the following map:

Figure 30 Map of economic breakeven between hydro and the grid

Even though Busona appears outside the economic profitability criteria, it is compensated bythe fact that all other loads are much closer to hydro and its distribution line, thereby making thewhole project more interesting than the grid as explained above.



ANNEX 1: List of RE candidates

Malamba 1 Malamba 2 Busona Itagata 1 Itagata 2 Itagata 3

Longitude 33.7071 33.7135 33.7104 33.6687 33.6663 33.6753

Latitude -9.2588 -9.2571 -9.2347 -9.2348 -9.2386 -9.2389

HH's (google earth) 12 39 67 23 42 44

HH's in hamlet 132 132 403 151 151 151

HH's reachable in year 1 16 51 87 30 55 57

HH's reachable in year 20 24 76 130 45 82 85

Demand year 1 (MWh) 1.3 2.4 30.9 2.1 2.4 2.4

Demand year 20 (MWh) 36.2 40.2 107.3 38.0 40.7 40.4

TF Size year 1 (kVA) 15 15 25 15 15 15

TF Size year 20 (kVA) 50 50 100 50 50 50

Primary school 1 0 1 1 1 0

Secondary School 0 0 1 0 0 0

Dispensary 0 0 0 1 0 0

Church 0 1 1 0 1 1

Shops and restaurants expected after elec 3 3 8 3 3 3

Barber, video show, arts and crafts expected after elec 1 1 2 1 1 1

Carpenter, welding, battery charging expected after elec 1 1 3 1 1 1

Mill expected after elec 1 1 3 1 1 1



ANNEX 2: Load curves for the load forecast model



ANNEX 3: Economic and Financial Analysis of the baseline scenario

rural electrification plan report suma v5...paceaa – rural electrification plan for tanzania –...

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