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SMALL HYDRO FOR GREENING THE TEA INDUSTRY IN EASTERN AND SOUTHERN AFRICA FEASIBILITY STUDY ON GURA SMALL HYDROPOWER PROJECT IN KENYA Feasibility Study Report Final – March 2008

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Page 1: Feasibility Study Report on Gura Shp

SMALL HYDRO FOR GREENING

THE TEA INDUSTRY IN EASTERN

AND SOUTHERN AFRICA

FEASIBILITY STUDY ON

GURA SMALL HYDROPOWER PROJECT IN KENYA

Feasibility Study Report

Final – March 2008

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IED reference: 2007/022/EATTA

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 7 March 2008 28 March 2008

Written by TDV / PSAV/ GDC TDV / PSAV/ GDC

Reviewed by DRM DRM

Approved by DRM DRM

Distribution level EATTA EATTA

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TABLE OF CONTENT

EXECUTIVE SUMMARY __________________________________ 14

1 GENERAL INTRODUCTION ____________________________ 19

1.1 Background & Objectives ______________________________________ 19 1.2 Work Activities _______________________________________________ 19 1.3 Project Background ___________________________________________ 20

1.3.1 Introduction to project area __________________________________ 20 1.3.2 Presentation of tea sector ____________________________________ 21 1.3.3 Power supply and Rural Electrification plan _____________________ 23

2 INSTITUTIONAL FRAMEWORK & CONNECTION SCHEMES26

2.1 Legal and Regulatory Framework _______________________________ 26 2.1.1 Objectives and Methodology _________________________________ 26 2.1.2 Gura SHP Connection scheme ________________________________ 26 2.1.3 Legal and regulatory context _________________________________ 26 2.1.4 KPLC point of view ________________________________________ 27 2.1.5 Investors and operators _____________________________________ 27

2.2 Grid Connection Scheme Development ___________________________ 28 2.2.1 Quality issue _____________________________________________ 28 2.2.2 Existing power supply ______________________________________ 29 2.2.3 Connection scenarios _______________________________________ 31 2.2.4 Conclusion on grid connection _______________________________ 37

3 DEMAND ASSESSMENT AND LOAD FORECAST _________ 40

3.1 Objectives ____________________________________________________ 40 3.2 Methodology _________________________________________________ 40 3.3 Local interests in SHP and RE development _______________________ 41 3.4 Power demand from tea factory _________________________________ 42

3.4.1 Thermal power requirements _________________________________ 42 3.4.2 Electrical power requirements ________________________________ 44

3.5 Rural Electrification Power demand ______________________________ 47 3.5.1 Existing grid ______________________________________________ 47 3.5.2 Power demand from leaf collection centres ______________________ 48

3.6 Global power demand (Year 1) __________________________________ 49 3.6.1 Total Power Demand _______________________________________ 49 3.6.2 Load Curves ______________________________________________ 49 3.6.3 Load Duration Curves ______________________________________ 50

3.7 Load forecast _________________________________________________ 52 3.8 Prospects for Energy Savings ____________________________________ 54

4 SHP TECHNICAL DESIGN ______________________________ 55

4.1 General description of the site and location ________________________ 55 4.2 Gura SHP: Geology, Hydrology and Topography ___________________ 56

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4.2.1 Geology _________________________________________________ 56 4.2.2 Hydrology _______________________________________________ 58 4.2.3 Topography ______________________________________________ 70

4.3 Power scheme of development ___________________________________ 70 4.4 Optimization designed plant capacity / Unit arrangement ____________ 74

4.4.1 SHP sizing optimisation _____________________________________ 74 4.4.2 Unit arrangement __________________________________________ 83

4.5 Energy generation _____________________________________________ 83 4.5.1 Main characteristics of the Pelton turbine _______________________ 83 4.5.2 Energy produced in average year ______________________________ 84 4.5.3 Energy produced in dry years ________________________________ 84 4.5.4 Energy produced in rainy years _______________________________ 85

4.6 Plan of development ___________________________________________ 85 4.6.1 Hydraulic calculation and results ______________________________ 86 4.6.2 The weir and the intake structure ______________________________ 86 4.6.3 The settling basin __________________________________________ 88 4.6.4 The waterway _____________________________________________ 92 4.6.5 The forebay ______________________________________________ 95 4.6.6 The penstock line __________________________________________ 97 4.6.7 The powerhouse and the tailrace channel _______________________ 99 4.6.8 The access road works _____________________________________ 104 4.6.9 Operator’s house _________________________________________ 104

4.7 Work schedule _______________________________________________ 104 4.8 Staffing and training requirements for plant operation and management107

4.8.1 Tentative list of staff required _______________________________ 107 4.8.2 Hydroelectricity capacity building ____________________________ 107

4.9 Cost estimate ________________________________________________ 108 4.9.1 General approach, construction works by contracts and cost summary 108 4.9.2 Detailed basis of cost estimates ______________________________ 109

5 RURAL ELECTRIFICATION PLAN _____________________ 115

5.1 Rural power demand _________________________________________ 115 5.2 Spatial layout ________________________________________________ 115 5.3 Preliminary network design ____________________________________ 116

5.3.1 Main MV line ____________________________________________ 116 5.4 Electrical configuration _______________________________________ 116 5.5 Preliminary Costing __________________________________________ 116

6 ENVIRONMENTAL AND SOCIAL IMPACT ASSESSMENT 119

6.1 Detailed Study Report _________________________________________ 119 6.2 Preliminary Conclusions ______________________________________ 119 6.3 CO2 Impact _________________________________________________ 120

6.3.1 Emission reduction for Igara tea factory _______________________ 120 6.3.2 Overview of the carbon market ______________________________ 120 6.3.3 CERs Valorisation of the EATTA projects _____________________ 121 6.3.4 VER market _____________________________________________ 121 6.3.5 Recommendations on next steps _____________________________ 122

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7 FINANCIAL ANALYSIS ________________________________ 123

7.1 Decision Criteria _____________________________________________ 123 7.2 Presentation of the financial model ______________________________ 124 7.3 Results of the financial analysis _________________________________ 128

7.3.1 Baseline scenario _________________________________________ 128 7.3.2 Pessimistic cases _________________________________________ 129 7.3.3 Optimistic cases __________________________________________ 130 7.3.4 Sensitivity study on the PPA tariff with KPLC __________________ 131 7.3.5 Other benefits from the project ______________________________ 132

7.4 Conclusions _________________________________________________ 133

8 ANNEXES ____________________________________________ 134

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ACRONYMS

EATTA East African Tea Trade Association IPP Independent Power Producers PPA power purchase agreement PWA power wheeling agreement WB/IDA World Bank / International Development Association UNEP United Nations Environment Programme GEF Global Energy Fund SHP – SHPP Small Hydro Power Plants ABC Aerial Bundled Conductor (MV)

PHYSICAL UNITS

LV – MV – HV low – medium – high voltage kV kilo Volts kW – MW – GW electrical power in kilo – mega – giga Watt kWh – MWh – GWh electrical energy in kilo – mega – giga Watt hour kVA – MVA active power in Volt Ampere kVAR reactive power in Volt Ampere Reactive t – Mt – Gt ton – mega ton – giga ton

Exchange rate in 15 February 2008: In Kenya: 1 USD = 70 KES

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LIST OF TABLES, FIGURES AND MAPS

1. General Introduction

LIST OF TABLES

LIST OF FIGURES

LIST OF MAPS

Map 1.1: Tea Growing Districts of Kenya and project zone

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2. Institutional Framework & Connection Schemes LIST OF TABLES

Table 2.1: Pros and Cons of grid connection scenarios

Table 2.2: Criteria of evaluation

LIST OF FIGURES

Figure 2.1: Voltage drop profile and power transit in Othaya feeder

Figure 2.2: Electrical diagram of grid connection (A1)

Figure 2.3: Voltage drop profile and power transit in 11kV Othaya feeder

Figure 2.4: Electrical diagram of grid connection (A2)

Figure 2.5: Electrical diagram of grid connection (A3)

Figure 2.6: Voltage drop profile and power transit in 11kV Othaya feeder

LIST OF MAPS

Map 2.1: GURA area, Tea Factories and existing MV system

Map 2.2: Gura SHP grid connection scenarios

Map 2.3: Dedicated 11 kV connection

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3. Demand Assessment and Load Forecast LIST OF TABLES

Table 3.1: Specific energy costs per source

Table 3.2: Capacity of thermal equipments

Table 3.3: Installed capacities and energy consumption per source

Table 3.4: Energy consumption per source

Table 3.5: Annual electricity consumption from the 4 tea factories (2007)

Table 3.6: Maximum peak electricity demand from the 4 tea factories (2007)

Table 3.7: Inventory of Tea Buying Centres around tea factories

Table 3.8: Total energy demand and peak load for Gura SHP project

Table 3.9: Load Forecast for Tea Factories

LIST OF FIGURES

Figure 3.1: Energy cost and energy content in one ton of made tea

Figure 3.2: Annual thermal fuel consumption vs. made tea production

Figure 3.3: Annual electricity consumption from the 4 tea factories

Figure 3.4: Annual peak load curve (kW) for the 4 tea factories

Figure 3.5: Daily load curve for the 4 tea factories

Figure 3.6: Expected daily load curves for the 4 Tea Factories

Figure 3.7: Load Duration Curve models (%)

Figure 3.8: Actual Load Duration Curve (kW) for each tea factory

Figure 3.9: Actual Load Duration Curve (kW) for each tea factory

Figure 3.10: Load forecast indicators

LIST OF MAPS

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4. SHP Technical Design LIST OF TABLES

Table 4.1: Physical characteristics of the catchment area

Table 4.2: Annual rainfall (1999-2006)

Table 4.3: Total monthly & annual rainfall (Gathuthi & Gitugi 1999-2007)

Table 4.4: Total monthly & annual rainfall (Kiandongoro 1999-2007)

Table 4.5: Total monthly & annual rainfall (Gathuthi 1993-2007)

Table 4.6: Monthly & annual mean flows (Gura 1978-2007)

Table 4.7: Monthly & annual mean runoffs (Gura)

Table 4.8: Total monthly & annual rainfall (Kiandongoro 2003-2005)

Table 4.9: Monthly & annual mean runoffs (Gura 2003-2005)

Table 4.10: Daily maximum rainfall (Kiandongoro 1999-2006)

Table 4.11: Monthly and annual maximum daily flows (Gura)

Table 4.12: Precipitations and Runoffs on Gura bassin

Table 4.13: Location of the main works (Gura)

Table 4.14: Estimated yearly output vs. discharge (Gura)

Table 4.15: Preliminary Gura SHP sizing vs. design discharge

Table 4.16: Preliminary costing for various SHP sizing

Table 4.17: Estimated IRR vs. discharge (Gura)

Table 4.18: Hydraulic feature (Gura)

Table 4.19: Weir geometrical characteristics

Table 4.20: Weir gates characteristics

Table 4.21: Settling Basin geometrical characteristics

Table 4.22: Settling basin gates characteristics

Table 4.23: Lined trapezoidal channel characteristics

Table 4.24: Lined rectangular channel characteristics

Table 4.25: Water reserve by deepening

Table 4.26: Forebay geometrical characteristics

Table 4.27: Forebay gates characteristics

Table 4.28: Penstock geometrical characteristics

Table 4.29: Penstock mechanical characteristics

Table 4.30: Powerhouse & Tailrace geometrical characteristics

Table 4.31: Powerhouse equipment characteristics

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Table 4.32: General Summary of Project Costs

Table 4.33: Breakdown of Project Costs

Table 4.34: Detailed Costing for Civil Works (CW)

Table 4.35: Detailed Costing for Main Electro-Mechanical Works (MEMW)

Table 4.36: Detailed Costing for Electrical Network (EN)

LIST OF FIGURES

Figure 4.1: Monthly rainfall and runoffs (Gura)

Figure 4.2: Empirical Frequency Curve (EFC) for Gura – Median year

Figure 4.3: Empirical Frequency Curve (EFC) for Gura – Dry year

Figure 4.4: Empirical Frequency Curve (EFC) for Gura – Rainy year

Figure 4.5: Demand and Load Duration Curve

Figure 4.6: Simulation of the placement of energy – SHP supply to 4 tea factories

Figure 4.7: Main characteristics of the Pelton turbine

Figure 4.8: Power & Flow Duration Curves – Median year

Figure 4.9: Power & Flow Duration Curves – Dry year T10

Figure 4.10: Power & Flow Duration Curves – Rainy year T10

Figure 4.11: Single-line electrical diagram of the SHP powerhouse

Figure 4.12: Suggested detailed work programme

LIST OF MAPS

Map 4.1: Location of Gura SHP site (GUR-N°1)

Map 4.2: General development plan (GUR-N°2)

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5. Rural Electrification Plan LIST OF TABLES

Table 5.1: Key data on power demand

Table 5.2: Preliminary costing for MV network

Table 5.3: Detailed costing for 11kV lines (USD)

LIST OF FIGURES

Figure 5.1: One-line electrical diagram for Gura SHP project

LIST OF MAPS

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6. Environmental and social impact assessment LIST OF TABLES

LIST OF FIGURES

LIST OF MAPS

7. Financial analysis LIST OF TABLES

Table 7.1: Synthetic investment costs for Gura

LIST OF FIGURES

Figure 7.1: Structure of Financial Model

Figure 7.2: Cash Flow over 14 years

Figure 7.3: Sensitivity curve

LIST OF MAPS

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EXECUTIVE SUMMARY

The project “Greening the Tea Industry in East Africa” is co-implemented by UNEP & the African Development Bank (AfDB) and executed by the East African Tea Trade Association (EATTA).

The objective of the initiative is to encourage the tea sector in East African region to develop Small Hydropower Projects (SHP) with the aim of reducing operating costs, increasing power supply reliability and reducing greenhouse gas emissions during tea processing.

The present feasibility study has been prepared based on field survey conducted on Gura river in Kenya between mid October and mid of December 2007 with 4 surveyor teams: hydrological team, topographical team, rural electrification expert and institutional expert. The study is part of a 4 year initiative endorsed by 8 EATTA member countries in the region.

Four nearby tea factories (Gathuthi, Gitugi, Iria Ini, Chinga) belonging to KTDA have strongly expressed their interest to be supplied by an independent hydropower source. Each one is actually supplied by the national grid through 11kV from Othaya substation operated by KPLC. However the frequent power outages, voltage drops and load shedding significantly affect the tea production quality and costs. The SHP project is most welcome to end with the reliance on backup diesel.

The Gura Small Hydro Power site is located along Gura River in the Aberdare mountains and situated at 6 km from the closest tea factory (Gathuthi) and 24 km from the furthest one (Chinga) in Nyeri District.

Given the favourable and well-established legal and regulatory framework for IPP (Independent Power Producers) in Kenya, it has been proposed to interconnect the Gura SHP scheme with a dedicated 11kV line with the 4 tea factories. An injection point to the near MV grid will allow the sales of power to the KPLC Utility through a Power Purchase Agreement (PPA).

Thanks to strong government support, the power distribution network has been intensively extended during the last 2 years, in particular in the project area where all villages, trading centres and tea buying centres are now electrified or at less than 3km from the grid. Therefore no external power demand is considered in the study and the total requirement (based on grid + genset consumption) for the 4 factories is about 8.6 GWh in year 1 and an expected peak load of 2.2 MW in December-January (peak season). The annual load factor varies from 35% to 50% from one factory to another, with an average of 44%.

The load forecast over a 20 year period has been constructed on the basis of today’s energy consumption patterns from the 4 factories and on a range of assumptions. The results show that the energy and peak demands will reach respectively 11.6 GWh and 2.7 MW after 20 years, and the load factor will be 50%.

In the case of Gura SHP, there is no constraint on the energy that can be absorbed by the 4 tea factories load, while the excess power will be sold to the KPLC grid. Therefore, the share of energy placed on the tea factories local network and the share of excess energy sold to KPLC have been assessed, and the SHP scheme size has been optimised

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by maximising the total energy sold to the Tea factories and to KPLC over the SHP lifetime, without over investing.

The Gura SHP site is a run-of-river scheme with a high head (149m). Based on rainfall data and nearby flow measurements (Gura gauging station), a design flow of 2.5 m3/s has been selected for Gura SHP after optimisation, leading to an installed capacity of 2.8 MW and a mean annual production of 17.9 GWh; both being above previous demand forecast. Energy generation has been simulated for median, dry and rainy years considering the use of a Pelton turbine.

Then a scheme of power development has been prepared to maximise the river potential. The exact location and routing of the structures such as the weir, the intake, the settling basin, the waterway, the forebay, penstock and powerhouse have been established accurately on detailed maps and drawings. The canal is about 6.6 km long and 2.5 m broad and the steel penstock is 392 m long. Then 4.4 km of existing road have to be rehabilitated to access the SHP site and 6.6 km of service road along the canal. Detailed views of hydraulic structures have also been prepared. The dedicated MV line will include 3 feeders of 11kV to reach the 4 tea factories with a total length of about 35 km.

Salient features of the feasibility study (site location, hydrology, head, power, energy, equipment, costing, financing) are given below.

It is assumed that the development of Gura would be undertaken via a Build-Own-Operated company (BOO) only or in partnership with the tea factory (BOO + TF) which will bring the equity required for the development of the 2.8 MW Gura Small Hydro Power project. The set up of this company has still to be fixed.

In order to appraise Gura SHP project and to assess the profitability for the Project Developer (through the criterion Return on Equity - ROE), IED has run an in-house developed financial model covering all financial and fiscal aspects of hydropower plant development, in a real life simulation of taxes and loan values. The model computes project costs and revenue forecasts, including investment costs, contingencies, project development costs, O&M costs, PPA conditions (feed-in tariff), equity/loan/grant characteristics, macroeconomic parameters (exchange rate, depreciation, taxes, inflation ...) and Carbon revenue.

Simulations have been conducted for a baseline scenario as well as for other scenarios with more pessimistic or more optimistic assumptions. The main results indicate that:

- In the baseline scenario the project cost has been estimated at 8.75 M$ for 2.8 MW SHP plant from which 57% is for civil works, 23% for electromechanical equipments and 5% for the electrical network (MV lines).

- The investment cost of 2,966 US$/kW (96% or project cost) is relatively high for this type of SHP plant and could be decreased with (partial) transfer of civil work responsibilities to the tea factories. Loans are required to compensate the initial negative cash flow.

- Each tea factory has limited assets but together (14M$), the consortium should be able to provide the expected equity (35% of investment cost) by setting up a BOO company. The pay-back period in the baseline scenario is about 12 years.

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- The financial return measured by ROE is rather good and the Gura project financially viable in both cases: 13.3% with BOO Company alone or 14.6% with BOO Company together with the 4 tea factories, in the baseline scenario. The small difference results from the limited savings on diesel fuel costs actually supported by the tea factory. The financial risks are perceived to be minimal.

- A sensitivity study on the PPA tariff has demonstrated the importance to negotiate with national regulator feed-in tariff higher than the published one to make the project more attractive.

- The ROE factor is also improved by getting better CO2 market price, better financing conditions, etc.

Other benefits as improved quality of electricity service leading to better quality and quantity in tea processing have not been considered in the simulation.

To comply with national regulation, an ESIA study has been conducted along the project layout to assess the environmental and social impacts of the SHP construction. The main negative impacts pointed out are (i) the degradation of the vegetation cover (removal, clearance), (ii) safety concerns over having an open waterway canal and (iii) some minor risks of pollution during construction. As required in the national guideline, mitigation measures and an ESIA plan are prepared before submission to National Environmental Management Authority.

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Salient features: GURA SHP

Location : GURA SHP - Nyeri District - KENYA Longitude : 25.79 to 26.42 East Latitude : 994.43 to 994.48 South

River source : Gura Type of project : Simple RoR Hydrology Catchment area : 135 km2

Average flow : 4.16 m3/s Design flow (57% exceedence) : 2.50 m3/s

Head Gross head : 154.50 m

Net head : 147.54 m Weir

Type : Ogee type spillway Crest elevation : 2,066.00 m Length : 35.00 m Orifice size : 1 no 3.5x3.5 m (to flush off the sediments

of Gura river) : 1 no 0.8x0.8 m (to allow the residual

flow-416 l/s- downstream) Intake Type : Side intake with one layer orifice Upper layer orifice size : 2 nos. 1.5x1.5 m Settling basin & Intake canal Type : Concrete structure Total length : 34.60 m Dimension : Width 5.55 m and depth 5.00 m

Flow : 2.50 m3/s Lower layer orifice size : 1 no 1.2x1.2 m (supplying the canal) : 1 no 1.5x1.5 m (to flush off the sediments

downstream the weir) Concrete trapezoidal canal

Type : Concrete lining Length : 6,480 m Dimension : Raft width 1.20 m and depth 1.83 m

Concrete rectangular canal (on posts) Type : Concrete Length : 185 m Dimension : Width 2.50 m and depth 1.83 m

Forebay Type : Concrete structure Total length : 15.50 m Overall dimension : Width 6.86 m to 3.15 m and depth 5.00 m

Penstock Type : Steel pipe ND 900

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Length : 392 m Thickness : 10 mm

Powerhouse Type : Surface powerhouse, stone masonry

structure Floor size : Length 18.30 m Width 10.50 m and

height 5.50 m Power and energy

Installed capacity : 2,840 kW Median year annual energy : 17.87 GWh Dry year T10 annual energy : 17.50 GWh Rainy year T10 annual energy : 19.00 GWh

Turbine Type : Pelton Number of unit : 2 Rated capacity : 1,420 kW each

Generator Type : Synchronous Number of unit : 2 Rated capacity : 1,500 kVA each

Power transformer Type : Outdoor, oil cooled Number of unit : 2 Rated capacity : 2,000 kVA, MV/11 kV

MV line Type : Overhead on tubular pole Length : 35 km following the existing track roads Rated capacity : 11 kV - 3 phases Supported by : 11 m poles spaced out by 130 m

Access road (Earthen, gravelled or concrete lined pavement) Service road along the canal : 6,665 m

Rehabilitated existing road : 4,400 m (Kigumo road to access the weir) New access : 300 m (to access to the powerhouse)

Financial parameters (Baseline scenario) Total Project Cost : 8,752 k$ Investment cost : 2,966 US$/kW Equity : 3,063 k$ Annual Energy produced : 17,866 MWh (average year) Return on Equity for BOO Co : 13.3% Return on Equity for BOO Co + 4TFs : 14.6%

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1 GENERAL INTRODUCTION

1.1 Background & Objectives Greening the Tea Industry in East Africa, a small hydropower initiative, has recently been approved by the Global Environmental Facility (GEF) Council. The project will be co-implemented by UNEP & the African Development Bank (AfDB) and executed by the East African Tea Trade Association (EATTA).

The objective of the proposed Small Hydropower (0.2MW - 5MW) Project (SHP) is to reduce electrical energy use in tea processing industries in member countries of the East African Tea Trade Association (EATTA) while increasing power supply reliability and reducing Greenhouse Gas emissions through the removal of barriers. Specifically, the project aims to establish 6 small hydro power demonstration projects in at least 4 of the EATTA member countries, preferably with an attached rural electrification component as well as prepare additional pre-feasibility studies. Both studies and planned installations shall serve as training grounds for the entire tea sector in the region. A special financing window shall be designed that will provide incentives for individual tea processing plants to move into “green power generation”.

The project is a 4 year initiative endorsed by National Governments of eight EATTA member countries in the region, namely: Kenya, Uganda, Malawi, Zambia, Burundi, Mozambique, Rwanda and Tanzania.

The initiative is coordinated by a Project Management Office (PMO) hosted by EATTA and led by a PMO Director. The PMO is responsible for the operations of the project leading to successful achievement of the project outputs and outcomes within the four-year project period.

1.2 Work Activities In the framework of a contract with EATTA, I.E.D. has undertaken two detailed feasibility studies in two small-hydropower sites located in Kenya and Uganda.

As per Terms of References, I.E.D. has prepared, in a clear and concise manner, this detailed feasibility study report for Gura Hydropower Site in Kenya.

The site is located along Gura River situated in the Eastern Aberdares region of Kenya (Neyri District). The Tea Companies bordering the site are Kenya Tea Development Agency (KTDA).

The feasibility study covers in detail the following key aspects, as described in this Terms of Reference:

1. General assessment of the site and preliminary information

2. Small Hydropower Technical Feasibility

3. Demand Analysis and Load Forecast

4. Financial Analysis

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5. Legal and Regulatory Framework

6. Environmental and Social Impact Assessment

7. Other Activities

The present draft report includes the following key outputs:

• Draft Feasibility Document

• Draft Report on Environmental Social Impact Assessment

• Pre-qualification of construction firms, electrical firms, turbine manufacturers etc.

• SHP methodological note

• Project Idea Note (PIN)

The feasibility study will be presented to the Project Steering Committee, associated tea factories and interested financiers

Additional outputs will be delivered with the final report including the following:

• Specifications and tender documents

• Final Report on Environmental Social Impact Assessment

• Certification from National Environment Management Authority (NEMA)

• Letters of no objection from affected parties

• Water abstraction permits from the Water Boards

It should be noted that IED has been working closely with local consultants in a way to improve quality of delivered work (in particular for topographical, social and environmental surveys) and in the same time has contribute to strengthen local capacity to conduct detailed surveys and accurate reporting needed for a SHP feasibility study.

1.3 Project Background

1.3.1 Introduction to project area The Aberdares range is an isolated volcanic mountain chain that forms the eastern wall of the rift valley and runs about 100 kilometers north to south between Nairobi and Thomson Falls. Two peaks dominate the range : Ol Donya Lesatima (3999 m) and Kinangop. They are separated by a long saddle of alpine moorland. The terrain is diverse with deep ravines that cut through the forested eastern and western slopes and there are many clear streams and waterfalls. The Aberdares are a water catchment area feeding two of Kenya’s most important rivers : the Tana and Athi rivers and part of Central rift and Northern drainage basins.

Mist and rain occur throughout much of the year, with precipitation varying from around 1 000 mm yearly on the north western slopes to as much as 3 000 mm in the south east. Heavy rainfall occurs throughout most of the year although there are two main rain seasons, from March 15th to May 30th (the “long rains”) and from October 15th to December (the “short rains”). It should also be noted that there are no real dry seasons wherein the flow to the rivers is significantly reduced. For instance in Gathuthi,

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the yearly rainfall average on the last 10 years was 1 357 mm per year with a maximum of 1 970 mm in 1998 and a minimum of 763 mm in 2000 (cf. Chapter 4).

The population in tea growing areas of Kenya is usually of a dispersed yet relative dense nature. People will tend to live in small plots of lands out of the estate scenario.

Most tea estates will also have labourer compounds wherein pluckers and estate workers reside. In most cases drinking water is supplied to the compounds and community halls, dispensaries and schools are also supplied with electricity. The majority of households do not have access to electricity, although a number do use car batteries.

Some households, although a small percentage, will also reside in the few villages surrounding tea estates, these in most cases will be made up of a few shops, a posho mill and a school. The Tea factories are usually located close to a town which will be electrified and that provides a range of services.

Tea production is labor intensive and accounts for 80 000 people working on the estate and about 3 million people earning their livelihood from the sector in direct and indirect employment. KTDA factories alone are operated/ owned by 380 000 growers.

Tea growing and manufacturing are carried out in the rural areas thereby Tea Estates contribute significantly to rural industrialization and to the range of services available like schools and dispensaries and the standard of living, solid households and potable drinking water and community halls.

1.3.2 Presentation of tea sector Tea was introduced in Kenya in 1903 by the white colonialists for experimental purposes. After 1915 and the land reforms producer groups developed in the mountainous areas of Kenya. The industrial scale tea development occurred in the fifties when the Kenyan government tried to promote small scale tea culture. Regulation was ensured by the State and this dynamic sector developed from 21 500 hectares in 1963 to 113 900 hectares in 1997.

Today, the production of Tea in Kenya currently acts as the main export crop and overall represents about 80 %1 of the total tea production in East Africa. In the world market, in 2002 Kenya was the third largest producer after India and Sri Lanka and second largest exporter of black tea after Sri Lanka. In 2001, the tea industry turnover was 474 million USD of which 437 million USD occurred from export earnings with the balance being the value of locally sold tea.

In 2004, total tea production in Kenya alone amounted to 324 608 tons. Currently the small scale growers under the umbrella of Kenya Tea Development Agency (KTDA) account for sixty percent of the total tea production while the multinational sector and large scale growers account for the remaining forty percent.

Kenya tea has established a reputation world over for its high and consistent quality throughout the year. Production goes on all year round with two peak seasons of high crop between March and June and between October and December which coincide with the short and long rains respectively.

1 Market Report, Sale 44 – 7th and 8th November 2005

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Most Kenyan teas are manufactured using the Cut Tear and Curl (CTC) method of manufacture, although some factories also produce orthodox tea for export in middles eastern countries.

Investments in the sector are today focused on trying to significantly reduce production costs. Investments in hydro power wherein production costs are significantly lower than those by KPLC tariffs or diesel generator costs and a fast payback period are seen optimistically by the sector. Today for example some of the tea companies are investing into more energy efficient wood energy boilers.

In Kenya there are a total of 15 tea companies and 91 tea factories who are members of EATTA. The companies can be classed into three types of players : (i) small holder tea cooperatives, Kenya Tea Development Agency (KTDA); (ii) large multinational companies; Unilever, EPK and James Finlay and (iii) private small estate holdings like and Williamson, Nandi Hill, Sotik Highlands, Maramba etc.

In 2000, the public agency in charge of the organization of tea production was privatized and took the name of the Kenya Tea Development Agency Limited – KTDA Ltd. Today, KTDA accounts for the biggest tea producer in the country (61%) managing 54 tea factories. It should be noted that Tea Factories subscribing to KTDA services are independent and autonomous bodies.

KTDA acts as the direct beneficiary of this study and any future development will depend on the interest and intent of KTDA and the individual Tea Factories at stake.

KTDA alone has 54 tea factories spread in 24 districts. The factories are owned by 380 000 growers. KTDA was responsible for 60 % of the tea production in 2002.

The following map illustrates the tea growing districts and in particular the project zone. This cluster of Tea Factories is home to a total of 50 500 tea growers and a total of 63 500 households. Tea growers make up about 80% of the total households in the area.

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Map 1.2: Tea Growing Districts of Kenya and project zone

The eight factories in the study area are in operation throughout the year each processing an average annual 13 400 tons of green leaf tea per year amounting to about 3 200 tons of made tea. The ratio between green leaf tea to made tea amounts to an average of 4.12 kg of green tea to 1 kg of made tea – this figure however varies from factory to factory illustrating the varying efficiencies in processing – from plucking to packing.

1.3.3 Power supply and Rural Electrification plan

1.3.3.1 Power sector organisation

Hydropower is central to electricity provision in Kenya: over 60% of Kenya’s electricity is generated by large hydropower plants. It should be however noted that drought prone countries, including Kenya have had drought induced power rationing in recent years. The share of hydro power in the power mix in the future is predicted to decrease.

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In 1997, Kenya’s Electric Power Act allowed independent producers to supply electricity to the grid, but small decentralized schemes, such as micro hydropower, were not fully addressed. The New Energy Policy and the Energy Bill are very important documents that indicate the direction in which the Kenyan power sector is headed and will have important implications for SHP development in the country.

Institutional and power sector reforms in Kenya have to a large extent contributed to the reduction in Ministry of Energy (MoE) direct control of the electricity industry. MoE activities are now more focussing on policy formulation.

About 55 % of the Generation falls under the responsibility of KenGen, the only state-owned company undertaking generation, whilst the Kenya Power and Lighting Company (KPLC) is responsible for transmission and distribution. Plans are underway to reduce Government’s shares in KPLC to 30 % to reduce its majority share holding status. Recent sales of Government shares of KPLC have reduced government ownership to below 50 %. Although there is still some debate on the issue, KPLC can be legally considered to be a non-state controlled entity.

An electricity regulatory board – ERB - has been set in place and the government is presently working on a programme to strengthen the institutional capacities in order to improve their operational and financial performance. It should be noted that the Ministry of Energy and the Electricity Regulatory Board have had experience with a “light-handed regulation” approach which has resulted in the waiving of license requirements for 2 decentralised micro-hydropower schemes in Central Province.

The distribution of electricity outside the main towns has been undertaken by the Government of Kenya since the early 70’s. A Rural Electrification Fund was created and fed jointly by the Government of Kenya, foreign loans and grants and KPLC participation. The REF is under the direct control of the Rural Electrification Steering Committee whose members are representatives from MOE and KPLC. KPLC executes the works and operates the schemes by the Government of Kenya. It should be noted that the Government only provides infrastructure through the Rural Electrification Fund. Electricity supply is the mandate of KPLC. However, financial losses incurred by KPLC in its supply of electricity to rural areas are reimbursed by the REF. This is, however, to change in the near future.

Plans are underway to set up a Rural Electrification Authority to manage Rural Electrification. One of the REA objectives will be to explore other non-conventional alternatives to accelerate access to electricity, which will include small hydropower development, photovoltaic systems etc.

As of June 2005, 6.8% of the rural population has access to electricity. The Government goal is to connect 150 000 urban consumers per year. The prohibitive costs of extending the national grid, at 1.3 million KES per km (16,250 USD per km) will require other alternatives to be explored.

Kenya has made significant progress in reflecting electricity tariffs to long run marginal cost restructuring the power sector opening the power generation market to private investment and reforming the sector’s legal and regulatory environment. Specific progress achieved under the reform program includes:

8. Unbundling of power generation transmission and distribution activities on one hand and incorporation and commercialization on the other hand;

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9. Entrance of IPPs;

10. Elimination of government subsidies to the sector with possibly the exception of those to rural electrification;

11. Amendment of the Electricity Act which ascended in 1998 to legislate private sector participation and the establishment of an independent regulator.

Cost of electric power in Kenya is however high compared to regional competing nations in the COMESA region.

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2 INSTITUTIONAL FRAMEWORK & CONNECTION SCHEMES

2.1 Legal and Regulatory Framework

2.1.1 Objectives and Methodology The institutional framework for implementing energy projects in Kenya has been reviewed by the Consultant team. This review was inspired by a recent exhaustive survey recently patronized on the same subject by the European Union. The detailed information on the institutional framework are provided in Annex.

The Consultant highlighted critical points about the procedure and present key finding concerning the organisation of the future SHP companies in the following paragraphs.

2.1.2 Gura SHP Connection scheme The Small Hydro Power (SHP) projects on Gura river (Nyeri district) is primarily dedicated to supply the tea factories in the proximity. They suffer high electricity prices and low quality of power supply that are endangering their competitiveness on the world tea market. Consequently 4 tea factories have expressed their wish to support and to be part of the SHP project as it mainly aims at mitigating these negative economical factors.

SHP generation provides the Kenyan tea factories with an opportunity to reduce their operating costs through replacing the power supply from the local utility and from their backup diesel generators by a cheaper hydropower production. The local SHP also enables the tea factories to obtain a more secure and better quality supply through dedicated MV connection lines.

As detailed in the next section (cf. § 2.2), different potential connexion scenarios for the SHPP scheme have been considered during the study. It is finally recommended to connect the SHPP scheme with 3 independent 11kV feeders to the 4 factories. An additional feeder with switching system will allow the sales of extra power to the national grid. This MV line shall be laid down following the main track road along which the potential for rural electrification has been investigated (cf. § 3.5).

The new 11kV line could be theoretically operated and managed by either the SHP operator or KPLC. Due to the risk born by non-utility staff when operating MV lines in the open and the necessity to distribute power to the rural area, it is highly preferable to transfer this responsibility to KPLC.

2.1.3 Legal and regulatory context Gura SHPP development is fully compatible with Kenya power sector legal and regulatory documents. Either a private or state owned promoter can build the hydropower station, lay MV distribution lines and retail energy either directly to large private customers or a licensed distributor or trader through a Power Purchase Agreement (PPA). All these activities require that the promoter complies with the official procedure and obtains the needed licenses and authorizations that refer to the

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power, water and environmental specific aspects and to the non specific aspects of establishing a business in Kenya as described in Annex.

An important question is to decide whether the planned installed power in Gura will be more than 3 MW or less. In the first case a full fledged license will be necessary, which involves a more complex and probably longer procedure. The procedure will also include a competitive stage and more exposure to the environmental concerns that may delay the project.

On the other hand, the choice for a less than 3 MW project will only require an authorisation but may be questioned by the regulator if it is not getting the best of the site from the public interest point of view.

If at a later stage of the study the financial analysis shows little difference between sizing above/below 3 MW, the Consultant will recommend adopting a sizing below 3 MW.

Another point to consider with special care is the location of the water intake and channel inside the Aberdare national park, which requires the intervention of the Tourism Ministry.

2.1.4 KPLC point of view As explained in the grid connection study, KPLC is the likeliest counterpart of the promoter in the case where Gura SHP is connected to the grid. Due to the technical and commercial conditions prevailing on the region, KPLC is interested by buying the available energy and by taking advantage of the SHP opportunity to improve the quality of supply.

KPLC is keen to retain the tea factories as its direct customers that is to buy the whole of the energy generated by Gura and to retail it to its local customers. Nevertheless KPLC understands the quality of supply problems of the tea factories and could accept to fulfil quality obligations included in the PPA.

KPLC is neither in favour of the isolated operation of Gura that would result into energy waste nor in favour of buying / selling power to Gura operator only, which would be the case if the operator was selling directly to the tea factories. KPLC recognizes that it cannot oppose that solution although it would obviously express concerns to the regulator.

KPLC declares ready to operate the newly built MV lines and even the hydropower site under a management agreement with the promoter.

In any cases, it is suggested that the contents of this section on grid connection scenario be submitted to KPLC for confirmation and observations, as soon as the present study is approved.

2.1.5 Investors and operators It is still premature to recommend any promoter / operator arrangement. However the following assertions are fuel for thought.

The following stakeholders may be part of the future institutional / organisational / financial construction:

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- The tea factories as promoters, shareholders, operators and/or consumers

- Other investors and shareholders only

- Energy Service Companies as primary investors in the context of a BOOT contract

- Financial institutions (commercial banks and funds, IFIs and BFIs)

- Operators of the hydropower system and the MV distribution system.

The tea factories can expect positive returns from the following activities according to their implications in the project:

a. Reduced costs and losses associated with an improved quality of supply

b. Reduced energy bills

c. Profits from their shares in the SHP company

The returns from the category (a) will depend on the operator’s commitment to ensure quality of supply that can be ruled by the operator’s contract.

The returns from the categories (b) and (c) will strongly depend on the tariff charged by the SHP Company. If the tea factories have a majority in the SHP capital structure they will exert pressure to maintain the tariffs as low as possible to minimize their own energy costs and the SHP fiscal taxes. Nevertheless the tariffs will also depend of the financial costs charged by the financial institutions and the operating costs. In case of a majority by external shareholders, the company will tend to maximize its tariffs, at a level marginally competitive with KPLC, unless the tea factories have a long term agreement with the SHP Company. In that case, the tea factories could financially benefit from the SHP without having to invest too much.

2.2 Grid Connection Scheme Development

2.2.1 Quality issue As mentioned earlier, the local SHP scheme will enable the tea factories to reduce their operating costs as well as to obtain a more secure and better quality supply through dedicated MV connection lines.

Quality of supply can be characterized by parameters qualifying respectively the level and shape of the electric wave and the continuity of the supply. Concerning the quality of the wave, the tea factories are especially sensitive to the voltage drops and surges as they are using many motors. Excessive MV voltage drops are resulting from MV voltage standards, long connection lines / insufficient square sections and heavy loads. Surges are mainly due to atmospheric over-voltages that are affecting the electric lines and can be transferred to the lower voltages.

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Continuity of supply is resulting from the combined impacts of (i) generation and demand balance, (ii) transmission and sub-transmission grid capacity and integrity, (iii) distribution grid capacity and integrity. Unbalance between demand and generation can cause general black-out or preventive load shedding, both generating long lasting outages. Poor capacity of the transmission, sub-transmission and distribution grids can result in regional or local load shedding or long lasting brown-outs. Transmission and sub-transmission faults will cause either short brown outs, or voltage dips or medium to long outages. Distribution faults will translate into either voltage dips or medium to long lasting outages.

Sub-transmission and distribution MV feeders fault rates are heavily depending upon their overall extension in km, insulation status and the number of the connected substations.

2.2.2 Existing power supply The Gura area receives power from the interconnected national grid. Gathuti, Gitugi, Iria Ini and Chinga tea factories are connected to 2 of the 3 feeders in 11 kV originating from OTHAYA substation 11 kV busbar. OTHAYA 33/11 kV substation is supplied by a single 33 kV line originating from KIGANJO 132/33 kV substation.

The following map 2.1 beneath shows the 11 kV system linked to OTHAYA substation and the connection locations of the tea factories:

• Gathuti and Gitugi tea factory are connected to the Othaya (carmine) feeder. • Iria Ini tea factory is connected to that same feeder but on a long yellow spur

tapped on the feeder near the OTHAYA substation. • Chinga tea factory is supplid by the Chinga (light blue) feeder.

The OTHAYA substation also supplies the Sagana Falls 11 kV feeder.

Power generation in Kenya is mainly from hydro. The country is also enjoying a robust 6% annual growth. Both factors are increasing the risk of power shortages at the generation level especially in the recurring periods of drought. The 132 kV transmission and 33 kV systems that are serving the OTHAYA substation are rather weak. The developed length of the 33 kV feeder supplying the substation from KIGANJO is very large at more than 150 km. All these factors combine to produce about 500 hours of total outage per year, which is huge by international standards.

The local 11 kV network is in pretty good shape. KPLC local staff is well aware of the tea factory concerns with power supply and does its best to maintain service but it has little leeway on upstream shortages. The 11 kV specific quality of supply can also be threatened in the future due to the dynamic electrification policy recently undertaken in that area. The developed length of the 11 kV feeders is increasing without significant reinforcement of the network structures, which will automatically result in a greater amount of MV faults felt by each consumer.

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Map 2.1: GURA area, Tea Factories and existing MV system

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The present situation is not good in terms of voltage level. At peak time, voltage approximate calculations (based on feeder lengths, cable cross-section, transit power …) show that the 11 kV voltage drop exceeds the recommended 7% level in Gathuti and Gitugi. Real voltage drops can be much worse when the 33 kV voltage cannot be maintained in OTHAYA due to upstream low voltage regimes in HV and 33 kV. Losses from the substation are in the order of 250 kW.

Figure 2.1: Voltage drop profile and power transit in Othaya feeder Othaya Iria Ini Gitugi Gathuti

0.4% 4715.9 1.4%

706.7 7.0% 3391.9 8.7% voltage drop 1194.1 8.2% MVA transit 1216.2

The above drawing sketches the feeder supplying Gathuti, Gitugi and Iria Ini tea factories in a simplistic ways. The power supply comes from the left at 11000 V in Othaya. Chinga tea factory (the furthest) is supplied by another 11 kV feeder within acceptable voltage conditions.

2.2.2.1 Balance between GURA supply and the tea factory demand Based on the various scenarios that can be implemented to use GURA hydrological potential, the following aspects have been taken into consideration for this preliminary study:

• Tea factory peak power is between 5 and 600 kW per unit • Tea factory annual power consumption ranges from 1900 to 2700 MWh per tea

factory • GURA installed power is 2,8 MW (2x1,4) • GURA annual generation is 9 GWh per unit • GURA guaranteed power will not exceed 370 kW • Water storage will not exceed 3 MWh.

Those numbers are coming from the detailed study provided in chapter 3 and 4 of this report.

Consequently, there will be periods when GURA generation will exceed tea factory demand, giving an opportunity to sell excess power to either KPLC or a private consumer using KPLC grid. There will also be periods when tea factory demand will exceed GURA generation, creating a need for back-up power.

2.2.3 Connection scenarios

2.2.3.1 Feasible scenarios In the above circumstances, various technical scenarios can be considered to either connect GURA to the grid or create an isolated grid dedicated to the tea factory supply:

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A. with grid connection 1. Direct connection to the nearest existing 11 kV line (limit at 4 MW) 2. Direct connection to the nearest existing 33 kV line 3. Connection through dedicated 11 kV lines

B. without grid connection

1. Through dedicated 11 kV lines

The four possible scenarios A1 – A2 – A3 – B1 will be now scrutinized.

2.2.3.2 Scenario A1 (connection to existing 11kV) In this scenario, GURA SHP is connected to the 11 kV Othaya feeder next to the projected powerhouse (Munyange area). In this scenario, GURA generation is entirely sold to KPLC. The SHP is coupled to the grid as far as it is live. If the grid is missing, the SHP disconnects. The SHP can then be reconnected and run isolated on a manually restructured 11kV network the demand of which does not exceed the potential GURA generation. On grid return, manual intervention is necessary again to go back to the coupled situation. There is no change in the existing tea factory power contracts with KPLC and their energy purchases remain unchanged. They benefit as shareholders from the profits made on the power sales to KPLC. Due to the capacity of the existing ACSR 11 kV lines, this scenario is valid only for an installed power of less than 4 MW.

Figure 2.2: Electrical diagram of grid connection (A1)

As for quality of supply, there is no substantial change for Chinga Tea factory, which is connected to the Chinga feeder. For the consumers supplied on the Othaya feeder, the voltage regime has improved as shown on the figure below and the losses have been reduced to less than 3%:

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Figure 2.3: Voltage drop profile and power transit in 11kV Othaya feeder Othaya Iria Ini Gitugi Gura Gathuti

0.1% 1333.6 1.1%

706.7 0.2% 140.0 -0.8% 1455.0 0.2% 947.0 -4.3% 3142.5 1.3% voltage drop 1188.7 MVA transit

The above drawing shows the injection of Gura power (3000kW, 1800 kVAR) in the Othaya feeder that causes a voltage rise above 11000 V (negative numbers) in some locations.

There is little change in terms of quality of supply as GURA is not able to supply the whole Othaya feeder for most of the time, especially at peak period when load sheddings are more likely to occur. Manual restructuring of the feeder to adjust demand to GURA potential supply is a cumbersome process that would probably not allow supplying Iria Ini, given the present structure of the feeder.

In this scenario the tea factories would also be concerned by any 11 kV fault on their respective feeders.

2.2.3.3 Scenario A2 (connection to existing 33kV) In this scenario, GURA SHP is delivering supply in 33 kV through a dedicated line to OTHAYA 33 kV busbar as shown on map 2.2 below. This scenario applies when the installed power in Gura is higher than 4 MW.

The contractual conditions are the same as in scenario A1. There is no substantial change in the quality of supply conditions in terms of voltage level on the 11 kV side. The situation may improve on the 33 kV side that has not been investigated as it has little impact on the tea factory supply.

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Map 2.2: Gura SHP grid connection scenarios

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The main change in terms of continuity of supply is that GURA, due to its higher installed power may sustain the full OTHAYA substation during load shedding most of the time on the initial years of operation. That may simplify commuting between isolated and coupled situations provided that adequate remote distance coupling equipment is installed in OTHAYA substation.

Figure 2.4: Electrical diagram of grid connection (A2)

2.2.3.4 Scenario A3 (connection to dedicated 11kV) In this scenario, dedicated 11 kV feeders are proposed to connect the tea factories to GURA SHP. The GURA SHP is also connected to the nearest KPLC 11 kV line. No additional customer has been identified to be supplied by feeders that are linking GURA SHP and the tea factories. However, to reduce feeder cost, 3 feeders are proposed and listed below:

• One feeder supplies GATHUTI tea factory • One feeder supplies GITUGI tea factory • One feeder supplies both IRIA INI and CHINGA tea factories

To reduce cost even more, either the feeders serving GATHUTI and GITUGI can be merged or one single feeder can supply all the tea factories at the expense of the flexibility of demand/supply balance.

Figure 2.5: Electrical diagram of grid connection (A3)

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This scenario allows the following operating conditions:

• Coupled operation when the grid is live provided that the voltage profile remains acceptable.

• Isolated operation of the tea factory when the grid is out within the limit of the available power in Gura.

Restrictions can apply in the case of the coupled regime when Gura generated power is low and simultaneous tea factory demands are high. That could affect Chinga tea factory and to a lesser degree Iria Ini that could be better supplied with their current connection. The voltage profile at peak is as follows (Gura at 3 MW and tea factories at 600 kW):

Figure 2.6: Voltage drop profile and power transit in 11kV Othaya feeder Othaya Gura Gathuti Gitugi Iria Ini Chinga

0.1% 1653.2 0.1%

0.0 2.2% 1106.9 2.3% 238.1 2.4% 239.2 1.9% 320.1 2.5% 478.7 3.1% 720.1 3.1% 720.1 4.7% voltage drop 1534.6 7.0% MVA transit 763.2 As shown on previous map 2.2, the new lines will meander within the existing KPLC 11 kV network. It is highly recommendable that the new 11 kV lines get distinctive features when

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compared with the existing KPLC overhead lines to avoid operators’ mistakes that could threaten safety and cause faults and equipment damage. Consequently these lines should be realized with the MV aerial bundled conductor (MV ABC) technique that will enhance public and staff safety, improve the quality of supply and reduce maintenance requirements at a reasonable cost. This scenario includes two commercial options A3a and A3b that are differing under the commercial aspects:

• According to A3-a variant, Gura SHP operator also keeps control of the new feeders and buys whatever energy is necessary from KPLC to compensate insufficient Gura generation to supply the tea factories that are remaining connected. On the opposite the operator sells any energy excess to KPLC.

• According to A3-b variant, Gura operator is limited to hydropower management. In this case KPLC takes care of the MV system and buys the whole of Gura production under a PPA specifying high quality standard for the tea factories.

A3a scenario requires that the Gura operator also manages the MV ABC feeders on the public domain, which is somewhat unusual and maybe risky for non-utility staff.

Remarks: The above A3 scenario is equally dealing with all four tea factories. If Chinga tea factory was not directly supplied by dedicated line, the investment cost of connection would be seriously reduced and the operation simplified. In that case Chinga would only benefit from the commercial impacts and not the technical improvement brought up by Gura.

2.2.3.5 Scenario B1 (isolated 11kV line) In scenario B1, Gura SHP only supplies an isolated grid consisting of the dedicated feeders to the tea factories as previously described for the scenario A3. According to Gura power availability, one or more tea factories are supplied. The tea factories not supplied by Gura connect to the grid as before. When both Gura and the grid are missing, they use their diesel generator. This solution does not require any PPA with KPLC. However two major inconveniencies arise:

• excess hydropower shall be lost; • the operator again shall manage the MV ABC feeders on the public domain.

2.2.4 Conclusion on grid connection The following table reflects the advantages and the inconveniencies of the various connection scenarios along the criteria given below:

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Table 2.1: Pros and Cons of grid connection scenarios Sc

enar

io

Mai

n co

nnex

ion

feat

ure

Ene

rgy

effic

ienc

y

Qua

lity

of

supp

ly:

volta

ge

Qua

lity

of

supp

ly:

cont

inui

ty

Ope

ratio

n ea

sine

ss

Inve

st.

cost

Com

mer

cial

pr

ofita

bilit

y

TO

TA

L

A1 To existing 11kV ++ ++ +++ +++ ++ 13+

A2 To existing 33kV +++ + + + ++ 8+

A3a To new 11 kV +++ + +++ +++ 11+

A3b To new 11 kV +++ + +++ +++ ++ 13+

B1 Isolated (11kV) ++ ++ + 5+

Table 2.2: Criteria of evaluation Criteria 3+ means: no + means:

Energy efficiency full use of the hydropower potential large loss of the hydropower potential

Quality of supply voltage

satisfactory voltage profile in most current situations (with and without Gura supply) for all the tea factories

no sensible improvement of the voltage profile

Quality of supply continuity

strong improvement of the continuity of supply

no significant improvement of the continuity of supply

Operation easiness SHP operator bears no responsibility in the grid operation

SHP operator bears full responsibility of the grid in a coupled situation

Investment cost additional investment cost for grid connection is low additional cost is heavy

Commercial return operational margin is high operational margin is minimum

The table is suggesting the following conclusions:

• Scenario A2 is only relevant if Gura installed power is larger than 4 MW. It is also not very efficient in terms of quality of supply and is relatively expensive.

• Scenario B1 does not enable the promoter to fully use Gura hydro potential, which is negative for efficiency and commercial profitability.

• Scenario A1 is energy efficient, cheap and reasonably profitable but does not result in an improvement of the quality of supply.

• Scenarios A3-a and A3-b are energy efficient and provides the tea factories with an improved quality of supply. On the negative side, they require more investment and higher

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operational qualifications. Scenario A3-b allows transferring the MV management to KPLC at the expense of some profitability.

From the above, the Consultant will only consider scenarios A1 and A3-b for the economic and financial analysis conducted as part of the feasibility study. The economical analysis provided in Chapter 6 shall measure the implicit cost of quality through comparison between scenarios A1 and A3-b. Indeed, the priority given to improve the quality of power supply (higher voltage and continuity) gives a preference for the scenario A3b but the investment cost has to be considered in more details before deciding which of the two Scenarios should be recommended.

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3 DEMAND ASSESSMENT AND LOAD FORECAST

3.1 Objectives The objective of the demand analysis is to qualify and quantify the power demand of selected tea factories, but also of the surrounding settlements, by mapping the present energy end-uses, the range of fuels used and the fuel substitution potential.

The proposed SHPP scheme aims first to improve the quality of the power supply, and secondly to reduce drastically the use of diesel for power generators in tea factories and their electricity consumption from the national grid.

3.2 Methodology The demand analysis has been conducted by the RE expert in the Tea Factory and other potential clients in the vicinity of the factory. The adopted method was:

- Debriefing with the Hydropower expert to know with more accuracy the potential for hydropower generation and the seasonal variation in the production.

- Debriefing with the Institutional expert to get the preliminary findings on institutional issues and possible grid connection schemes

- Meetings with local authorities and power utility to get more information on the project area (socio-economical, demographic, rural electrification plans, …)

- Detailed survey on the energy end-uses and energy needs of the Tea Factory (electricity and thermal needs)

- Interview of the Tea Factory manager or with the board of members to assess their priority energy needs and their interest and willingness to provide extra power to surrounding settlements

- Detailed investigations to identify and to select the surrounding candidates for power supply (villages, trading centres, tea buying centres, etc.)

After having interviewed all key actors and collected the appropriate technical and socio-economical data/information, the RE expert has prepared the following demand analysis, the load forecast and the local grid extension plan. All tea factories have provided detailed information on their energy consumption for at least 2 years (hard and/or soft copies), except Gathuthi factory which has not provided data on their diesel fuel consumption.

Some information gaps have supplemented by previous surveys conducted in 2004 and 2005 in the framework of the Scoping Studies and Pre-Feasibility Studies under UNEP and EATTA and also via continued communication with the tea companies.

The range of data collected is described in the check-list for interviews and the questionnaire for village survey (cf. in Annex). The data from the tea factories includes:

• Yearly and monthly power consumption for the past 2 years

• Yearly and monthly diesel consumption for the past 2 years

• Yearly and monthly Peak (kVA) for the past 2 years

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Energy content (kWh/ton of made tea)

458.233%

9.100%

1139.967%

15553.0590%

griddieseloilwood

• Yearly and monthly electricity and diesel fuel bill

• Hourly consumption for several days

• Plans in processing expansion, with qualified/quantified data.

Other key issues have also been investigated during the interviews with the Tea Factory staff as:

- financial capacity to carry the main investment (based on balance sheet for last 2 yrs)

- technical skills for O&M activity required for the SHPP scheme and distribution network

Wherever possible, additional data on power consumption for individual households and various activities and services were also obtained from the Ministry of Energy (ongoing Rural Electrification Master Plan), from the Utility or from the tea factories themselves. Where specific consumption data was not available the Consultant has drawn on its wide rural electrification experience in the region.

3.3 Local interests in SHP and RE development Large amounts of thermal energy and electrical power are needed to produce Black Tea. Tea factories in Kenya rely on fuel wood and furnace oil to meet their thermal needs and on grid power and diesel generators to meet their electrical needs.

On average, energy accounts for 0.18 USD/kg of made tea (18 % of the current selling price for tea; 1.04 USD/kg). The next charts show the critical weight of the diesel consumption (almost 60% in 2006) in the cost structure and the weight of the wood and the energy balance:

Figure 3.1: Energy cost and energy content in one ton of made tea

Energy cost (USD/ton of made tea)

88.3550%

4.052%

9.075%

76.6043%

grid

diesel

oil

wood

Based on billing from energy suppliers, the following energy costs have been calculated for the different sources:

• The kWh unit price is 5.1 KES but the average electricity tariff paid by the 4 tea factories in 2007 was close to 10 KES per kWh or 0.14 USD/kWh, when including fixed charges, taxes and levies. Power factor surcharge are usually avoided by factories. 16% VAT is not refunded since 2003 (Gitugi).

• The average price for diesel fuel in 2007 was close to 70 KES/litre or 0.3 USD/kWh equivalent.

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• The firewood was sold on the local market in 2007 between 700 and 1500 KES per m3, i.e. in average 20.5 USD per ton or 0.4 cents of USD/kWh equivalent.

• The furnace oil was sold at around 27 KES per litre or 2 cents of USD/kWh.

Table 3.1: Specific energy costs per source 2007 Average price USD / kWh

Grid 10 KES / kWh 0.14 Diesel 70 KES / L 0.29 Wood 1200 KES / m3 0.004 Oil 27 KES / L 0.02

In addition to the effective costs of purchasing or growing the varying fuels, there are great losses which are incurred in production quality when power outages or voltage drops are experienced.

Each tea factory has strongly expressed its interest in producing hydropower itself to:

- Improve the power quality and availability,

- Reduce the operating costs,

- Sell extra power to KPLC and make benefits

- To provide power to surrounding settlements in the tea catchment area

It has clearly indicated that any positive impact from the project shall benefit to all tea farmers as they are all shareholders of the factories. Any improvement of power quality or any cost reduction will increase the profit on tea sales and thus the farmers’ incomes.

3.4 Power demand from tea factory

3.4.1 Thermal power requirements As in every tea manufacturing unit, the tea drying process requires very large amount of heat. The 4 selected tea factories (Gathuthi, Gitugi, Iria Ini and Chinga) are reliant on firewood and when necessary on furnace oil for their heat applications. The boilers and furnaces installed are as follow:

Table 3.2: Capacity of thermal equipments Tea Factory Wood boiler Oil furnace Comments

Gathuthi 2 1 Gitugi 1 2 Iria Ini 2 1 Oil is 3 times more expensive Chinga 1 2

The consumption of fuel is closely linked to the production of made tea which strongly varies between dry and rainy seasons.

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Made Tea (kg) - 2007

050000

100000150000200000250000300000350000400000450000500000

nov'

06

dec

jan

07 feb

mar ap

r

may ju

n jul

aug

sep

oct

Gathut hi

Git ugi

Ir ia Ini

Chinga

Figure 3.2: Annual thermal fuel consumption vs. made tea production

Wood + Oil consumption (GJ eq.) - 2007

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

nov'

06

dec

jan

07 feb

mar ap

r

may ju

n jul

aug

sep

oct

Gitugi

Iria Ini

Chinga

In average for the 4 factories, the specific wood consumption varies over the months from 3.0 to 5.0 m3 for every ton of made tea. In addition some furnace oil is consumed when the factories face wood shortage; the consumption is in average 50 litres/ton of made tea. In terms of energy, the furnace oil part is not more than 10% of the total fuel consumption for thermal needs but in term of cost, the use of expensive oil compared to wood price has high impact on the tea production price. In Gitugi, the oil expenditure was almost 40% of the total thermal fuel cost (wood+oil). Indeed the price for wood is in average 16 USD/ ton while the oil price is 0.37 USD/ litre. For Iria Ini, the furnace oil costs about 18 KES per kg of made tea while wood cost is only 5 to 8 KES.

For example in Chinga tea factory where 4,236 tons of made tea were produced over the last 12 months, the consumption of thermal fuels (wood + oil) amounts to 13,610 m3 or 10,890 tons of wood and 268,826 litres of oil, corresponding to about 63.36 GWh/year when convert into equivalent thermal kWh (2). About 15 kWh of thermal equivalent per kg of made tea were needed which is almost double of what has been recorded in Uganda (Igara tea factory).

When assuming that 1 ha of tree plantation produces in average 22 m3 of firewood (3), the tea factory should have at least 682 ha of forest to be self-sufficient or should harvest at least 0.25 ha of forest for each hectare of tea plantation.

As shown by the previous graphs (Fig. 3.1), the thermal energy requirements represent about half of the total energy costs incurred by the Tea Factories.

Yet in terms of energy content, the thermal power needs represent 89% of the total energy requirements of the production process. The power requirements to substitute the overall energy needs (thermal and electrical) of Chinga tea factory has amounted to 66 GWh for 2007, of which 57.5 GWh were or the thermal energy needs.

Other alternatives have been investigated in some of the tea factories as coal, saw dust, baggast but furnace oil remains the cheaper and easiest backup option after wood. Electricity furnaces have not been investigated as grid prices are too high.

2 by using the factors 0.8 ton/m3, 5.28 kWh/kg of firewood, 21.84 kWh/litre of oil, 3.6 MJ per kWh 3 The produced volume at the end of the 12 years has been valued in 264m3 / ha. The Annual Medium Increment in case of the Eucalyptus sp. is 22 m3/ ha/ year.

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Given the significant thermal energy requirements of the selected tea factories in Kenya and the potential to sell excess electricity back to the grid at good price, this feasibility study will not consider the potential for substituting the use of wood by electricity to meet the thermal needs.

However tea factories are willing to find alternative to fuel wood as the market price has increased from about 150 to 1250 KES in 10 years.

3.4.2 Electrical power requirements

3.4.2.1 Installed capacities & annual consumption The 4 tea factories are running in the same way their production lines with priority to the main grid when available and with backup diesel generators during power outages. Most of the backup systems are old and outdated but still running with maintenance costs. Recent improvements concern mainly the strengthening of the transformer and the electronic meters from KPLC. Capacity banks have also been increased to keep the power factor below penalties.

Table 3.3: Installed capacities and energy consumption per source

TF Transformer capacity

Genset unit

Year of inst.

Capacity bank Comments

(kVA) (kVA) (kVAR)

Gathuthi 1000 200 (HS) 450 Very old backup

system

Gitugi 1000 330 450

> 15 > 10 15 x 25 Old generators

Iria Ini 1000 200 450

‘81 ‘93 2 banks Old generators

Chinga 1000 200 450

The factories don’t have major extension plan in terms of production capacity but they put efforts to improve productivity and energy savings with existing equipments.

The power network in tea factories is usually designed with several separate lines:

- One or several departures (3 phases) for the factory

- One departure (single phase) for the administrative block

- One departure (single phase) for the worker settlements in the vicinity of the factory.

The same lines are supplied either by the grid or by the backup gensets. On the grid side, there is one main power meter (3-phase electronic meter), monthly read by KPLC.

There is usually no energy meter on diesel generators, only the fuel consumption is recorded in logbooks.

The annual consumption of energy for 2007 (with extrapolation for the last 2 months) is summarised in the following table:

Table 3.4: Energy consumption per source

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Tea Factory - Annual Consumption (grid+genset)

0

50

100

150

200

250

300

1 2 3 4 5 6 7 8 9 10 11 12

Months

MW

h/m

onth Gitugi

ChingaIria IniGathuthi

Tea Factory - Annual Consumption

0

200

400

600

800

1,000

1 2 3 4 5 6 7 8 9 10 11 12

Months

MW

h/m

onth

All TF

TF Grid peak

Grid consum.

Diesel consum.

Wood consum.

Oil consom.

Reliance on diesel

(kVA) (MWh/yr) (l/yr) (ton/yr) (l/yr) (%) Gathuthi 519 1,909 n.a. 10,732 n.a. n.a.

Gitugi 530 1,878 12,561 9,134 195,275 2.2% Iria Ini 557 2,200 14,425 15,898 83,634 2.1% Chinga 629 2,722 14,746 13,610 268,826 1.8%

3.4.2.2 Reliance on diesel genset The previous table indicates the reliance on backup diesel generators to provide continuous supply of the electricity to the factory. The recent strengthening of the grid lines and power supply in Nyeri district has noticeably reduced the dependence to the backup units: grid power consumption has increased and diesel consumption has decreased.

3.4.2.3 Monthly Power consumption

The tea production is directly linked to the rainy season and shows usually 2 peaks (cf. fig. 3.2):

- one peak between September and December

- one lower peak around May.

The electrical power demand is typically the lowest in July-August corresponding to the off-peak season.

The monthly consumption of electrical power (from grid and backup genset) is fluctuating between 100 and 250 MWh per month, with a total for the 4 factories of more than 8.5 GWh for 2007, as shown in the next graph and table.

Figure 3.3: Annual electricity consumption from the 4 tea factories

Table 3.5: Annual electricity consumption from the 4 tea factories (2007)

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Tea Factory - Yearly Load Curve

0

100

200

300

400

500

600

700

1 2 3 4 5 6 7 8 9 10 11 12

Months

kW

GitugiChingaIria IniGathuthi

Tea Factory - Yearly Load Curve

0

500

1,000

1,500

2,000

2,500

1 2 3 4 5 6 7 8 9 10 11 12

Months

kW All TF

2007 (MWh) 1 2 3 4 4 6 7 8 9 10 11 12 Tot Gathuthi 179 147 82 114 188 127 91 87 130 177 139 160 1,621 MWhGitugi 190 174 173 155 180 156 104 99 162 174 167 187 1,919 MWhIria Ini 224 218 197 192 230 185 121 100 146 206 214 214 2,248 MWhChinga 269 241 206 213 253 224 157 153 253 281 251 269 2,771 MWhTotal 862 780 659 674 851 692 474 439 690 838 771 830 8,559 MWh

3.4.2.4 Max peak load and load factor As shown in the table below, the highest peak loads recorded in the tea factories are usually in December - January between 500 and 600 kW.

All tea factories have batteries of capacitors to compensate the reactive power of their equipments. They manage the compensation to be above 0.92, as KPLC penalties start below 0.9. The KPLC meters measure both active and reactive power to control the power factor correction.

Table 3.6: Maximum peak electricity demand from the 4 tea factories (2007) 2007 (kW) 1 2 3 4 4 6 7 8 9 10 11 12 Max Gathuthi 519 450 397 413 500 500 382 404 516 516 477 477 519 kW Gitugi 530 530 464 525 504 493 442 447 488 488 509 530 530 kW Iria Ini 545 547 516 516 530 535 557 478 493 547 545 545 557 kW Chinga 629 611 567 583 620 620 526 539 628 628 617 629 629 kW Total 2,223 2,138 1,944 2,037 2,154 2,148 1,907 1,868 2,125 2,179 2,148 2,181 2,223 kW

Figure 3.4: Annual peak load curve (kW) for the 4 tea factories

As the tea factories have the same process programme over the hours and days, the individual load peaks can be added and the red curve above can be considered as first approximation with a max peak load of 2,200 kW.

The annual load factor for each tea factory was ranging between 40% and 50% in 2007 based on the annual consumptions. This load factor is the actual amount of kilowatt-hours consumed by the tea factory in one year as opposed to the total possible kilowatt-hours that could be delivered to the factory during that year. A high load factor indicates high usage of the system’s equipment and is a measure of efficiency. Lowest values are obtained in July and August (off-peak season).

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3.4.2.5 Daily load curve The daily load curve provides a closer indication of what happens in terms of demand over a 24 hour period. Hourly data are not daily recorded by the factories but data for specific days have been recorded on demand. The following graph illustrates the variation in consumption over an hourly period for one day in November (peak season). The shape of the load curve is supposed to be similar every day except on Monday (fixed maintenance day).

The typical load peak occurs in the morning starting at 8:00. The production is usually reduced during night period.

Figure 3.5: Daily load curve for the 4 tea factories

TF Daily Load Curve (Nov 2007)

050

100150200250300350400450

6-7

7-8

8-9

9-10

10-1

111

-12

12-1

313

-14

14-1

515

-16

16-1

717

-18

18-1

919

-20

20-2

121

-22

22-2

323

-24

0-1

1-2

2-3

3-4

4-5

5-6

kW

GathuthiChingaGitugi

3.5 Rural Electrification Power demand

3.5.1 Existing grid The Gura SHP project is located in Nyeri district where the power distribution network has been intensively extended during the last 2 years thanks to strong government support, as shown by the network map in Annex. At the time of the pre-feasibility study, a large number of villages, trading centres and public infrastructures were not electrified and no clear plan of grid extension was available. Only 10% of the so-called Tea Buying Centres (TBC) was electrified.

Today the Government through its Rural Electrification Authority has supported the extension of the 11kV feeders (from Othaya 33/11kV sub-station) in 2 phases: the first one targeted in priority the main important villages that include active trading centres and public infrastructures; the second phase which is now close to completion has targeted the remaining clusters of settlements and potential customers from each sub-location (lowest administrative division4), including the Tea Buying Centres (TBC – see next §).

4 Administrative boundaries in Kenya: Province > District > Division > Location > Sub-location > Village

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Today the national grid (11kV) has extended far to the West, close to the Aberdare National Park border, most of the villages are located at less than 3km and 60% of the TBC are already electrified with new transformers (usually 50 kVA – 3 phases).

Table 3.7: Inventory of Tea Buying Centres around tea factories Tea Buying Centres Gathuthi Gitugi Irai-Ini Chinga

Non electrified 16 12 12 17 Electrified (or ready) 28 18 27 26 Total 44 30 39 43

During the field visit in the vicinity of the 4 selected tea factories, KPLC was still working in the field to extend their 11kV lines5 toward remote TBC as the dead line to cover 100% of the area is December 2007. Therefore there is no RE potential for the Gura SHP project to include a rural electrification component as explained in Chapter 5. However, despite the very good coverage with the grid extension, small localities may also not be connected and the actual household electrification rate is most probably below 50% (not known yet).

3.5.2 Power demand from leaf collection centres The tea plantations attached to 4 tea factories are scattered on the East slopes of the Aberdare range. The green tea leaves harvested by farmers is daily collected at Tea Buying Centres (TBC). Those centres are spread all over the “tea catchment area” to ensure that farmers don’t have to walk too long with their harvest. All of them are located on a network of track roads to be reached by trucks.

The typical infrastructure is a basic permanent building with hard walls and roof and its size ranges from small to large depending of the farmer number linked to that centre. However the regional managing unit of KTDA has requested KPLC to extend the grid until the buying centres to provide power for basic lighting, weight measuring & recording equipments and computers.

Despite the sporadic requirement of power to supply few lamps during the peak evenings only, KPLC is providing 50kVA transformer6 in the proximity of each TBC; the underlying idea being that TBC will encourage the emergence of new trading centres and become attractive centre for business development and new settlements. The TBC are never farer than 3km from tea farmer’s houses.

In this context it is clear that there is no potential for a rural electrification component in the framework of this Small Hydro Power project. However the hydro power generation in the area is most welcome to alleviate the shortage of power due to the fast growing demand (total 33/11/0.4 kV losses are above 20%).

As the 4 targeted tea factories belong to KTDA and are 100% owned by the tea growers/farmers, all of them will benefit directly from the SHP project (either through power quality improvement or through lower kWh cost for tea production). The increase of income

5 KPLC cost: 825,000 KES for 1km of 11kV line (3 phase bare ACSR – 75mm² - 11m poles) or about 12,700 USD (includes labour but not local transport) 6 KPLC cost: 205,000 KES for 50kVA-11/0,4kV transformer + 160,000 KES for structure = 365,000 KES or about 5,600 USD (or 112$/kVA).

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is expected to help them to afford the connection fees (fixed 35,000 KES) and monthly instalments. Today about 50% of them are able to connect to the grid when available.

3.6 Global power demand (Year 1)

3.6.1 Total Power Demand Based on the previous findings, the total load to be considered for the Gura SHP project is from the 4 selected tea factories only as most of surrounding localities or trading centres are already electrified or shall be in a near future by governmental programmes. Therefore the total energy & power demand can be summarised by the following table:

Table 3.8: Total energy demand and peak load for Gura SHP project 2007 Energy

demand Gross peak

load Losses Production Net peak load

Load Factor

MWh kW % MWh kW % Gathuthi* 1,621 519 8% 1,751 561 35.6% Gitugi 1,919 530 8% 2,073 572 41.3% Iria Ini 2,248 557 8% 2,428 602 46.1% Chinga 2,771 629 8% 2,993 679 50.3% Total 8,559 2,223 9,244 2,414 44.0%

(*) Data for Gathuthi are calculated from 2005 values, due to lack of data for 2006-7

3.6.2 Load Curves The daily load curves have been drawn in previous section (§ 3.4.2) for 3 of the tea factories for specific days in November. The load curve for Iria Ini has not been provided but the manufacturing process over one day is similar in the 4 factories. Therefore the aggregate load curve for the 4 factories can be extrapolated from the 3 previous curves to give the following total daily load curve at peak (2,223 kW) during the peak season (November) where the tea factory operates 24 hours.

Figure 3.6: Expected daily load curves for the 4 Tea Factories

Daily Load Curve at peak (4 tea factories)

0

500

1000

1500

2000

2500

6:00

8:00

10:00

12:00

14:00

16:00

18:00

20:00

22:00 0:0

02:0

04:0

0

Average

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3.6.3 Load Duration Curves The Load Duration Curve (LDC) is a non-chronological graph, which plots demand magnitude (power) on one axis and percent of time that the magnitude occurs on the other axis. It provides a summary of demand levels and should be developed on the basis of the hourly load curve. Given the absence of hourly power measurement data over one year for the tea factory, it is necessary to simulate the load duration curve based on several key information collected from the factory as:

1) The typical daily load curve starts with a peak in the morning and decreases slowly during the day, with a minimum demand during the night (half of the peak value).

2) An annual Load Factors have been calculated for each factory over one year based on the total electricity consumption and the maximum peak power, an average value of 45% has been considered.

3) During maintenance day every Mondays the consumption is drastically reduced (about 10% for auxiliaries and worker settlements). Therefore 15% of the time (52 days / 365 days), the required power is at its minimum.

4) The maximum power demand is rather constant over the year (about 10% variation); the peaks occur usually during May-June and October-November-December periods. The total peak demand recorded in 2007 for the 4 tea factories was 2,200 kW. The demand is rather close to the peak value during the equivalent of at least 1 month, i.e. 8% of the annual time.

5) The behaviour of the curve between the maximum and minimum demand is dictated by the load characteristics of the tea production and the number of production lines in operation.

Figure 3.7: Load Duration Curve models (%)

Load duration curve models

0%10%20%30%40%50%60%70%80%90%

100%

0% 8% 17%

25%

33%

42%

50%

58%

67%

75%

83%

92%

100%

One TF

Four TF

The above load duration curve in blue colour has been simulated specifically for one tea factory. When adding other tea factories on the local distribution network, it is necessary to model again the load duration curve for the whole system as the curves for each tea factory can not be simply added.

The red curve above is the model LDC curve obtained for 4 similar tea factories inter-connected, based on additional considerations as:

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6) An annual Load Factor of 45% for the whole system has been assumed. 7) The maximum peak loads from the tea factories can be added for a short period of

time 8) To optimise the use of hydropower from Gura scheme, it is highly recommended to

shift the maintenance toward different days to avoid long and low off-peak demand (1 day per week is equivalent to 15% of the time at a level of 10% of peak power for each factory).

9) The minimum power required is dictated by the combination of 3 factories working at their lowest level (night time) and one factory stopped for maintenance; this happens for about 6 hours per night and 4 nights per week, i.e. 15% of the time

10) The power demand remains at a low level for another 10% of the time when the 4 factories are in production during night time.

11) The curve between the maximum and minimum demand will be little affected by adding all tea factories, giving a final load duration curve close to the curve for one tea factory only.

The following load duration curves (in kW) are obtained when applying the model curve (in %) to the actual max peak power for each factory.

Figure 3.8: Actual Load Duration Curve (kW) for each tea factory

Load duration curve (kW)

0100200300400500600700

0% 10%

21%

31%

42%

52%

63%

73%

83%

94%

kW

Chinga

Iria Ini

Gathuthi

Gitugi

The last curve below (in kW) shows frequency of the power demand for the 4 tea factories when using the red model curve above.

Figure 3.9: Actual Load Duration Curve (kW) for each tea factory

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Kenya Load duration curve (kW)

0

500

1000

1500

2000

2500

0% 13%

25%

38%

50%

63%

75%

88%

100%

kW 4 Tea factories

3.7 Load forecast In any rural off-grid electrification project, the assessment of the demand must be addressed carefully and in priority before any design work for the power generating and distribution system.

In our specific case of Gura SHP project where no rural electrification is proposed for the project area, the load forecast (LF) is simplified and constructed on the basis of today’s energy consumption pattern of the 4 selected tea factories.

Consumption growth rates and peak growth rate are then assumed so as to derive the demand for power over a 20 year period, as shown in the next table. Peak growth factor (%/yr) Y 1-2 Y 2-10 Y 11-20 Tea factory growth factor 5.00% 1.00% 0.50%

Consumption growth rate Y 1-3 Y 3-10 Y 10-20 Tea factory 5% 1.5% 1%

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Table 3.9: Load Forecast for Tea Factories Gathuthi, Gitugi, Iria Ini & Chinga Tea Factories (Kenya)

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

Peak Power Demand kW 2223 2334 2357 2381 2405 2429 2453 2478 2503 2528 2540 2553 2566 2578 2591 2604 2617 2630 2644 2657

Peak growth factor % 5% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5%

Gross Energy Demand MWh 8559 8987 9436 9578 9722 9867 10015 10166 10318 10473 10578 10683 10790 10898 11007 11117 11228 11341 11454 11569

Consumption growth factor % 5% 5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0%

Load Factor % 44% 44% 46% 46% 46% 46% 47% 47% 47% 47% 48% 48% 48% 48% 48% 49% 49% 49% 49% 50%

LF growth factor % 0.0% 4.0% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5% 0.5%

Figure 3.10: Load forecast indicators

Load Forecast

0

2000

4000

6000

8000

10000

12000

14000

1 3 5 7 9 11 13 15 17 19

Year

Peak Power DemandGross Energy Demand

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3.8 Prospects for Energy Savings Although not part of the ToR of the Feasibility study, the Consultant recommend that the tea factories should carry out detailed energy audits: it is not considered a good practice to start generating electricity that is subsequently wasted in-house. An energy audit should therefore be part of the field activities before starting the construction phase.

Based on the information obtained from the energy invoices, metered consumption, observations and calculations, the following will be provided by the Energy Audit: • A table showing the consumption, the unit costs, and total costs for all purchased

energy for the previous 3 years • A table showing the percentage changes and trends in energy costs over the previous 3

years • A summary of energy intakes such as supply meters and tariffs • Energy performance indicators for each facility will be calculated and compared with

benchmarks values established from similar institutions. • The ‘maximum demand’ profile over a two or three weeks period , depending of the

kind of equipment. • The most economical supply tariff, based on ‘maximum demand’ profile and past

invoices • The need for power factor correction • The suitability of putting generator(s) in standby mode, updating or replacing existing

equipments In terms of Energy Management, the following will be studied: • Existing energy management procedures, information available and metering and at the

site. • Improvement that can be made to the existing system. • Manpower availability, energy awareness levels and the cost requirements for setting up

an improved system of energy management. • Systems of energy management based upon quantitative measures of performance using

monitoring and targeting, relating energy consumption to known variables. • Management structures for collecting and processing data and taking action in response

to the findings. • System of recognizing energy savings and giving incentives to the staff to save energy.

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4 SHP TECHNICAL DESIGN

4.1 General description of the site and location The Aberdare range, which is the area sheltering the project in the Central Region North of Nairobi, is an isolated volcanic mountain chain that forms the eastern wall of the Rift Valley and runs about 100 kilometres north to south between Nairobi and Thomson Falls. Two peaks dominate the range: Ol Donya Lesatima (3,999 m) and Kinangop (3,906 m). They are separated by a long saddle of alpine moorland. The terrain is diverse with deep ravines that cut through the forested eastern and western slopes and there are many clear streams and waterfalls. The Aberdares are a water catchment area feeding, with Gura river, two of Kenya’s most important rivers: the Tana and Athi rivers.

Between Aberdares and Mount Kenya (5,200 m), Gathuthi, Gitugi, Iria Ini and Chinga tea factories are located in the Nyeri lowland area (around 1,750 m) This hilly area is rather wet providing the right conditions for tea growth as well as sufficient water to assure local hydro potential. In that area and facing west-east, Gura river valley, in strong V shape is straight. This river receives, at least in its final part, very short tributaries. The first two factories are located very close to Gura river on both sides.

In this area, rainfall is caused by orographic lifting of coastal air coming from the Indian Ocean, forced to elevate to higher altitudes by the almost continuous mountain range formed by the two mountainous areas. The rains are increased by the large protected forest covering the slopes of this chain.

Mist and rain occur throughout much of the year, with precipitation varying from around 1,000 mm yearly on the north western slopes to as much as 3,000 mm in the south east. Heavy rainfall occurs throughout most of the year although there are two main rain seasons, from March 15th to May 30th (the “long rains”) and from October 15th to December (the “short rains”). It should also be noted that there are no real dry seasons wherein the flow to the rivers is significantly reduced. For instance in Gathuthi tea factory, the yearly rainfall average on the last 10 years was 1,357 mm per year with a maximum of 1,970 mm in 1 998 and a minimum of 763 mm in 2000.

An important fact to be noticed is that most of Gura catchment area is close to a large protected natural forest (Aberdare Forest) growing in the highlands and attracting precipitation. This river draining in the Gathuthi and Gitugi tea catchments has in fact a large watershed that depends on this protected forest to smooth the flow variations and importantly reducing the occurrence of floods.

The four tea factories rely on KPLC power for the majority of their power needs and on average for 5/7% of the time on heir diesel generators as a backup to KPLC power outages. Power is delivered at each by a 33/11 kV line. Once it reaches the Tea Factory a step down transformer converting the power to 240 kV is often found. The Tea Factory distributes the power accordingly within its premises to the various load centres.

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4.2 Gura SHP: Geology, Hydrology and Topography

4.2.1 Geology

4.2.1.1 Regional geology The area of Nyeri is composed almost of entirely of volcanic rocks comprising lavas and basalt which, particularly west of the Aberdare range, are considerably faulted. Although the oldest rocks cannot be dated accurately it is believed probably tertiary age.

The oldest rocks in the area are the basalt of the Simbara Series7 exposed on Gura valley. These porphyritic rocks are overlain by basaltic agglomerates (or autobreccias); all are grouped together as representing the Simbara Series and are believed to be of Miocene age. The series has a probable minimum thickness of about 3,000 feet but the base was not seen. Closely associated with this period of vulcanicity are dyke-like intrusions of other basaltic composition which outcrop on Niandarawa and the Elephant.

During the period of erosion that followed the extrusion of the Simbara Series, the landscape composed of these rocks was highly dissected so that subsequent volcanic deposits were laid on a very uneven surface (these rocks belong to Laikipian group). The unconformable contact between the two series is seen in the south of Nyeri district, east of Othaya. No dykes were observed cutting any of these rocks.

Mainly composed of faded basalt, these representatives of Laikipian group compose the high peaks of the Aberdare range and are found mainly in the Kikuyu special area and east of the Aberdare range.

4.2.1.2 Site geology It was examined during the site visit (from October 27 to November 7, 2007) and on the basis of documents placed at our disposal.

The documents placed at our disposal were as follows:

- Extracts of a geological report which deals with an area of approximately 1,200 squares miles, bounded by latitudes 0°30’ and 1°00’S and by longitudes 36°30’ and 37°00’.

- The geological map of the Kijabe area.

This map includes parts of the countries of Gura river in the north, Maragua river in the middle and Chania river in the south

Only a first field geology survey was held to identify the under surface geology at every building location and the land area. (the border of the technical geology information we get follow the border of topography measurement)

The main rocks encountered are fine-grained, dark basaltic rocks becoming lighter-coloured as the felspar content increases, when the basalts appear also to be more vesicular. Another characteristic feature is that black augite crystals often stand out on weathered surfaces, or can be easily seen on fractured surfaces. The lower basalts on Gura valley are rich in ferromagnesian constituents, olivine and plagioclase in a groundmass of the same minerals.

The source of the boulders seen in Gura river possibly represents the oldest rock in the area; and the rocks most likely formed in the throat of the volcano responsible for the eruption of the Simbara basalts.

7 The Simbara Series was first described by Shackleton in 1945.

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On the two sides of the river the superficial materials are made of a thick layer of laterite.

4.2.1.3 Further investigations required During the establishment of the detailed design study, a certain number of investigations will have to be carried out near the works.

The field survey can be described as it follows:

4.2.1.3.1 Field survey Weir & Intake:

(1) 8 drilling bore-holes: 3 on each bank & 2 on the 2 small islets on both side of the axis – 15 m depth or thoroughly until the bed rock, (2) Lithological cuts of the 8 bore-holes which will indicate the water level under the natural ground, (3) Undisturbed soil sampling of each nature of soil met, (4) Pressure measuring tests in each bore-hole at the depth of two & four meters under the level of the weir foundation.

Waterway: (1) Altered soil sampling of a mix of red clay/clayish material (laterite) located close to the canal, or in a known material career in the vicinity, (2) Soil bearing capacity analysis (or Proctor tests in laboratory)

Forebay: (1) 2 drilling bore-holes distant of 20 m on the main axis of the work - 10 m depth or thoroughly until the bed rock, (2) Lithological cuts of the 2 bore-holes which will indicate the water level under the natural ground, (3) Undisturbed soil sampling of each nature of soil met, (4) Pressure measuring tests in each bore-holes at the depth of one & three meters under the level of the forebay foundation.

Power house site: (1) 2 drilling bore-holes distant of 15 m on the main axis of the building - 10 m depth or thoroughly until the bed rock, (2) Lithological cuts of the 2 bore-holes which will indicate the water level under the natural ground, (3) Undisturbed soil sampling of each nature of soil met, (4) Pressure measuring tests in each bore-holes at the depth of one & three meters under the level of the power house foundation.

4.2.1.3.2 Laboratory tests They contain the classification tests of the soils or other materials (families) encountered near each structure and some other specific tests.

(1) Soil classification: Name, nature and classification of the soils met, Water content W%, Density, Granulometry & sedimentometry, Atterberg limits.

(2) Triaxial tests for cohesion and friction angle determination,

(3) Proctor tests (if necessary) for bearing capacity analysis.

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4.2.2 Hydrology

4.2.2.1 Watershed context The main part of the watershed of Gura river upstream Gura hydropower project is located in the Aberdare Forest (Aberdare National Park).

The most elevated point of the watershed is about 3,900 m, while the level at the intake is 2,080 m and the level at the gauging station is 1,820 m.

The length of the river between the most elevated point and the intake is 25 km and the mean slope 73 m/km.

The length of the river between the most elevated point and the gauging station is 40.5 km and the mean slope 51.5 m/km.

Downstream the intake the slope of the river decreases quickly and it is only of 16.8 m/km between the intake and the gauging station.

The catchment area at the intake is 135 km2 while it is 165 km2 at the gauging station.

Table 4.1: Physical characteristics of the catchment area Items Catchment area of Gura river at the intake km2 135 Extreme altitude of the area catchment in m NGF Max in m 3,900.00 Intake elevation m 2,080.00 Altitude at the gauging station m 1,820.00 Length of the river (between the most elevated point & the gauging station)

m 40,500

Average slope (between the most elevated point & the gauging station)

% 5.15

Average slope (between the intake & the gauging station)

% 1.68

4.2.2.2 Data available

4.2.2.2.1 Precipitations There is no rain gauge inside the catchment but only in east limits:

- Gathuthi tea factory

- Gitugi tea factory

- Kiangondoro

For Gathuthi TF station monthly data are available since 1993 up to 2007 with missing values in 2004 and 2005. The daily data are so available since July 2005.

For Gitugi TF station monthly data are available since 1999 up to 2003. The daily data are not available.

For Kiandongoro station, monthly and daily data are available since 1999 up to 2005.

4.2.2.2.2 Flows The flows measured at Gura gauging station, 15 km downstream the intake, are available since 1978 up to 2007 but most of the years are missing (1997, 1998, 1999, 2002).

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4.2.2.2.3 Data carried for hydrology analysis Daily precipitation data at Gitugi are not available while daily precipitations at Gathuthi are only available since July 2005. In so conditions daily data at these two rain stations cannot be used for flood estimation. However they can be used to compare the monthly precipitation at the three posts for their common period of observation.

Kiandongoro rain station is the only post which covers during some years (1999-2006) the period of observations of flows data at the Gura gauging station. In so conditions it will be carried out as representative of precipitations on the catchment in order to compare rainfalls and runoffs on this one.

Gathuthi, Gitugi and Kiandangoro monthly and annual precipitations being compared for 5 years (1999-2003), the table below shows that mean annual precipitations in Gathuthi and Gitugi stations are almost equal (1,185 and 1,147 mm for the 5 years) while the mean precipitations in Kiandongoro are higher of 28 % (1,488 mm), due to the higher elevation of the station (2,300 m).

Table 4.2: Annual rainfall (1999-2006) YEAR 1999 2000 2001 2002 2003 2004 2005 2006 Mean

1999/2003Mean

1993/2003GITUGI 871 1011.3 1062.5 1827 1422.43 1651.9 1297,0 2234.1 1146.715 GATHUTHI 853.9 763.4 1299.5 1465.9 1542.5 1974.3 1185.04 1440.0 KIANDONGORO 1362.8 1094.8 1611.8 1674,0 1696.1 1463.1 1487.9

So the precipitations in Kiandongoro station may be considered as more representative of the precipitations on the whole basin (elevation of 2 080 m at the intake and 3 900 m at the higher point.

4.2.2.3 Monthly analysis Monthly and annual values of precipitation at the 3 stations are indicated in the tables below.

Table 4.3: Total monthly & annual rainfall (Gathuthi & Gitugi 1999-2007) Month 1999 2000 2001 2002 2003 2004 2005 2006 2007 Mean

1999/2003Jan 7.5 8.5 166.1 33.5 68.2 24.8 55.1 56.76 Feb 10.7 10.1 19.3 33.8 38,0 26,0 75.3 22.38

March 51.9 62.5 182.2 86.5 65.1 134.3 66.3 89.64 April 116.1 124,0 403.2 456.3 313.8 413.5 168;9 282.68 May 188.3 130,0 86.1 120.4 395,0 186,0 183.5 183.96 June 15.4 38.1 80.4 35.8 43.5 44.5 154.4 42.64 July 60.5 41.9 33,0 11.9 24.2 76.3 85,0 119.5 34.3

August 75.1 59.2 45.6 75.4 101,0 66,0 75.4 172,0 71.26 September 31.7 27.4 10.5 49.1 42.3 60.6 118.5 36.9 32.2

October 80.3 68.8 26.5 223,0 235.5 152.2 163.5 126.82 November 136.6 118.7 193.4 219.1 136.8 76,0 417.3 160.92 December 79.8 74.2 53.2 121.1 79.1 4.2 285.5 81.48

Total 853.9 763.4 1299.5 1465.9 1542.5 1974.3 1185.04

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Month 1999 2000 2001 2002 2003 2004 2005 2006 2007 Mean 1999/2003

Jan 22.7 16.5 22.7 28.4 31.7 24.40 Feb 18.2 22.0 17.2 75.2 54.5 37.40

March 19.2 15,0 27.9 122.2 356.6 108.18 April 131.0 126.0 142.0 465.0 64.73 185.70 May 158.0 147.6 183.5 196.5 175.0 172.12 June 37.0 16.0 32.0 42,0 56.4 36.68 July 39.0 44.0 37.0 48.2 36.9 41.02

August 75.1 82.1 73.0 84.5 100,0 82.94 September 49.0 62.1 56.0 64.0 54.5 57.12

October 68.1 84.9 76.1 327.1 277.5 166.74 November 164.2 176.7 198.5 152.2 168.2 171.96 December 89.5 218.4 196.6 221.7 46.4 154.52

Total 871.0 1011.3 1062.5 1827.0 1422.4 1297.0 2234.1 1238.80

Table 4.4: Total monthly & annual rainfall (Kiandongoro 1999-2007) Month 1999 2000 2001 2002 2003 2004 2005 2006 2007 Mean 1999/2007Jan 30.8 24.4 176.4 63.5 53.7 66.4 44.5 69.76 Feb 46.9 46,0 66.7 39.2 21.2 92.7 72.3 54.7 44.00 March 160.0 66.8 149.8 113.6 107.6 135.2 99.4 119.56 April 194.3 98.3 434.6 389.4 343.1 416.2 291.94 May 169.3 212.2 146.6 121.9 426.8 11.4 366.4 215.36 June 21.1 46.5 121.9 33.7 36.1 58.7 44.2 51.86 July 94.4 40.0 71.0 55.6 23.9 57.1 107.1 56.98 August 73.1 75.8 62.9 55.7 127.9 45.6 64.2 79.08 September 47.2 46.7 12.7 80.8 58.8 89.4 54.2 49.24 October 140.5 154.9 58.7 220.1 281.3 169.1 116.9 171.10 November 250.2 172.6 216.4 283.8 174.6 233.8 123.9 219.52 December 135.0 110.6 94.1 216.7 41.1 87.5 37.8 119.50 Total 1362.8 1094.8 1611.8 1674,0 1696.1 1463.1 1487.90

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Table 4.5: Total monthly & annual rainfall (Gathuthi 1993-2007)

Monthly and annual values of flows (in m3/s) and runoffs (in mm) at Gura gauging station are indicated in the table below.

Table 4.6: Monthly & annual mean flows (Gura 1978-2007) YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC YEAR

1978 4.24 5.00 11.25 16.71 10.09 1979 3.987 4.637 5.413 17.280 30.652 39.037 7.792 3.033 2.346 7.060 12.864 3.951 11.491980 2.495 2.291 2.456 7.489 11.697 5.294 3.188 2.382 1.595 2.359 8.352 4.935 4.551981 2.449 1.932 3.698 12.013 12.617 4.282 3.427 3.393 3.299 5.610 6.528 5.551 5.411982 3.319 1.939 1.478 9.509 19.997 6.445 3.549 2.895 2.775 8.519 12.101 9.504 6.861983 3.082 2.465 2.656 5.447 12.630 3.691 3.170 2.848 2.902 5.893 7.284 4.949 4.761984 3.309 1.794 1.393 3.586 3.382 1.391 1.730 1.597 1.559 4.757 5.483 4.184 2.851985 2.547 2.281 2.694 10.558 12.554 4.765 3.923 2.646 2.068 3.623 7.129 4.643 4.961986 2.231 1.329 1.450 8.118 12.580 6.224 3.320 2.132 2.155 4,000 7.213 5.138 4.671987 2.258 1.399 1.245 4.942 5.766 7.756 2.753 2.549 1.632 1.493 6.949 3.499 3.511988 2.803 1.609 2.131 12.619 9.745 4.013 2.891 2.664 3.975 4.678 6.029 4.277 4.791989 2.68 2.208 1.833 4.551 5.602 4.394 2.322 2.324 4.608 8.553 10.705 6.723 4.711990 6.264 2.466 5.300 13.001 8.601 3.689 2.647 2.451 2,000 2.683 6.062 4.548 4.981991 2.572 1.618 1.678 4.411 12.470 6.224 2.962 2.277 2.133 3.357 5.174 2.916 3.991992 1.658 1.232 1.237 6.443 9.218 3.987 2.765 2.608 2.538 6.652 9.512 6.977 4.581993 7.226 6.468 3.107 5.000 10.300 5.309 2.352 1.757 1.352 1.324 3.881 3.505 4.281994 1.925 2.002 2.224 8.146 14.230 5.775 3.086 3.071 2.065 4.143 19.188 5.720 5.961995 1.881 1.286 2.374 4.249 12.613 5.053 4.315 3.221 3.007 6.649 10.53 5.477 5.071996 2.680 2.878 2.421 4.216 6.812 7.423 3.427 2.429 2.754 2.574 4.111 3.695 3.782000 1.000 1.700 2.500 3.500 6.695 3.321 2.981 2.714 3.108 4.147 7.395 7,000 3.852001 7.919 5.057 3.738 16.681 13.793 6.586 4.203 4.138 3.746 1.800 11.833 5.000 7.022003 2.500 0.650 2.677 7.226 16.716 10.9633 3.641 3.164 3.5833 6.054 9.850 5.996 6.112004 3.029 2.475 2.964 8.920 6.286 3.970 2.900 2.812 2.876 5.019 13.896 6.227 5.112005 4.054 2.957 3.909 5.320 10.290 7.346 4.874 5.000 5.446 4.290 5.126 3.606 5.192006 2.670 1.889 3.822 10.046 12.316 4.820 3.612 4.553 3.283 4.483 12.356 7.519 5.962007 6.406 4.539 3.190 6.360

MEAN 3.189 2.357 2.683 8.053 11.565 6.740 3.410 2.861 2.784 4.572 8.731 5.231 5.189

ST.DEVIATION 1.682 1.318 1.157 3.989 5.564 7.139 1.158 0.794 1.002 2.031 3.663 1.545 1.668

This table shows that the mean annual runoff is almost 1,000 mm with small variability (standard deviation = 319 mm and coefficient of variation = 0.320), except for the year 1979

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with a very high runoff of 2 199 mm. The cumulative runoffs of May and June 1979 reached up to 1,111 mm. As the precipitation data are missing for this period, this exceptional value of runoff cannot be controlled. The highest runoffs are observed in April, May, June, November and December.

Table 4.7: Monthly & annual mean runoffs (Gura) JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC YEAR

MEAN 51.80 34.60 43.60 126.50 187.70 105.90 55.30 46.40 43.70 74.20 137.20 84.90 991.80

Table 4.8: Total monthly & annual rainfall (Kiandongoro 2003-2005) YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC YEAR

2003 53.7 21.2 107.6 343.1 426.8 36.1 23.9 127.9 58.8 281.3 174.6 41.1 1,696.12004 66.4 92.7 135.2 416.2 114.0 58.7 57.1 45.6 89.4 169.1 233.8 87.5 1,565.72005 70.0 72.3 99.4 350.0 366.4 44.2 107.1 64.2 54.2 116.9 123.9 37.8 1,506.4

Mean 2003/2005 63.40 62.10 114.10 369.80 302.40 46.30 62.70 79.20 67.50 189.10 177.40 55.50 1,589.40

Table 4.9: Monthly & annual mean runoffs (Gura 2003-2005) YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC YEAR

2003 40.58 9.53 43.46 113.52 271.34 172.22 59.11 51.36 56.29 98.28 154.73 97.34 1,167.812004 49.16 36.28 48.12 140.12 102.04 62.36 47.07 45.66 45.18 81.47 218.30 101.08 976.912005 65.82 43.35 63.46 83.57 167.04 115.40 79.12 81.16 85.56 69.64 80.53 58.54 993.23

Mean 2003/2005 51.90 29.70 51.70 112.40 180.10 116.70 61.80 59.40 62.30 83.10 151.20 85.70 1,046.00

The precipitations at Kiandongoro station and the runoffs at the Gura gauging station can be only compared for the period 2003-2005 (see tables 8 and 9 above). These tables show that the mean coefficient of runoff is almost of 2/3 (0.658) indicating a high level of surface runoff.

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Figure 4.1: Monthly rainfall and runoffs (Gura)

0.050.0

100.0150.0200.0250.0300.0350.0400.0450.0

Precipitation-Runoff (mm)

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35

Month

Figure 1 Monthly precipitations and runoffs

PrecipitationRunoff

The figure above shows a delayed flow for some months, for example June and December 2003, June 2005, due to the high values of precipitation the precedent months.

4.2.2.4 Daily analysis

4.2.2.4.1 Daily precipitations Table 4.10: Daily maximum rainfall (Kiandongoro 1999-2006) Month 1999 2000 2001 2002 2003 2004 2005 2006 2007 Mean 1999/2005January 8.5 15.6 59.0 26.5 15.8 16.0 15.8 22.45 February 17.5 21.0 22.9 16.0 12.0 15.6 19.6 15.0 17.45 March 35.7 17.4 40.0 41.0 21.8 30.0 24.7 30.08 April 35.8 20.0 63.6 59.5 52.0 56.2 47.85 May 27.0 49.2 16.4 16.5 45.5 36.5 53.3 34.91 June 4.6 10.5 31.0 7.0 15.3 21.5 10.0 14.27 July 20.5 7.8 26.5 16.0 7.6 25.5 31.8 19.38 August 12.6 21.4 23.0 7.6 22.6 11.5 8.0 15.24 September 14.8 10.4 3.4 24.5 20.0 47.1 10.2 18.62 October 39.4 70.0 14.4 52.7 41.0 17.8 27.4 37.52 November 77.4 43.0 41.1 53.1 30.0 36.7 20.0 43.04 December 25.0 22.6 22.3 30.5 20.4 16.2 16.2 21.88 Mean 26.6 25.7 30.3 29.2 25.3 27.6 22.1 Maximum 77.4 70.0 63.6 59.5 52.0 56.2 53.3 Mean Annual Daily Max 61.70 Std Dev Annual Daily Max 9.30

The period of available data is very short (1999-2005).

The table above shows daily maximum precipitation very slightly variable from one year to another. The daily maximum of the year are contained between 52 mm and 77 mm with a mean value of 61.7 mm. The standard deviation, which measures the annual variability, is only of 9.3 mm (coefficient of variation = 0.150).

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It is very difficult to fit a law of probability of the maximum values of daily precipitation with so few years of observation. The 10 more important values are upper than 50 mm and the 18 more important are upper than 40 mm and fitting a Gumbel law of probability gives the same results if the sample of data is built up with the 7 maximum annual values or with the 7 absolute maximum values.

The Gumbel law may be expressed by:

Pt = s/sn .yt + m – s/sn .(sn- yn)

where :

Pt is the daily precipitation of return period t

the mean of the sample of maximum daily values

s is the standard deviation of the sample of maximum daily values

yn is the mean value of reduced variates of Gumbel for 7 years

sn is the standard deviation of reduced variates of Gumbel for 7 years

For Kiandongoro case they take the following values:

m = 61.7

s = 9.30

yn = 0.4773

sn = 0.9449

Pt = 9.84 yt + 57.1

The slope of the law (Gradex) in a reduced Gumbel graphic is 9.84 mm

• For a return period of 10 years, y10 = 2.250 and P10 = 79.2 mm

• For a return period of 100 years, y100 = 4.600 and P100 = 102.4 mm

4.2.2.4.2 Daily flows The maximum daily flows at Gura gauging station are indicated, by month and by year, in the table 4.11 below.

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Table 4.11: Monthly and annual maximum daily flows (Gura)

Like the mean monthly flows, the maximum daily flows are observed in April, May, June, October, November and December, the most important values being observed in April and May.

The coefficient of variation of the maximum values of the year (Cv = 27.50/9.962 = 0.362) is higher than the same coefficient for precipitation values (Cv = 0.150).

It will be noted that, converted in runoff, the maximum value observed (45 m3/s) corresponds to 23.5 mm per day. The mean value of the sample (27.5 m3/s) corresponds to 14.4 mm and the standard deviation (9.96 m3/s) to 5.22 mm.

The 4 more important values are contained between 41, 6 and 45 m3/s, the 7 more important values are higher than 35 m3/s and the 10 more important values are higher than 30 m3/s. These near first maximum values do not denote a good exponential fitting (Gumbel law).

However, the fitting of the maximum values of runoff by a Gumbel law gives the following results:

• m = 23.5 mm

• s = 5.22 mm

• yn = 0.5332

• sn = 1.1215

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n being the number of value in the sample (n = 27)

The probability law of the runoffs (expressed in mm/day) is:

Rt = 4.65 yt + 20.8 The slope of the law in a reduced Gumbel graphic (4.65 mm) is approximately half of the slope (Gradex) of the daily precipitation (9.84 mm)

• For a return period of 10 years, R10 = 31.3 mm

• For a return period of 20 years, R10 = 34.6 mm

• For a return period of 30 years, R30 = 36.5 mm

Because of the weak value of the slope, the runoffs do not increase quickly with the return period.

So it can be applied the Gradex method, which considers that after a return period (20 years for example in this case where 27 years of data are available), all supplement of precipitation can be transformed in an equal supplement of runoff (total saturation of the soils for T = 20 years).

So, beyond the period of return of 20 years the law of runoffs becomes:

Rt = 9.84 yt + 5.4

For a return period of 30 years, R30 = 38.7 mm

For a return period of 100 years, R100 = 50.7 mm The daily maximum runoffs above may be transformed in mean daily discharges :

For a return period of 30 years, 24Q30 = 73.9 m3/s

For a return period of 100 years, 24Q100 = 96.8 m3/s The runoff coefficients (Precipitation/Runoff) are:

T = 10 years Cr = 31.3/79.2 = 0.395

T = 100 years Cr = 50.7/102, 4 = 0.495

It will be noted that daily coefficients of runoff are weak compared with the annual coefficients. This can be explained by the delayed runoffs after rainy events of several days.

The daily runoff deficits (Precipitation-Runoff) are:

T = 10 years Dr = 79.2 – 31.3 = 47.9 mm

T = 100 years Dr = 102.4 – 50.7 = 51.7 mm

Some rainy events can be analysed in order to compare them with the runoffs resulting.

The coefficient of runoff becomes high when rain duration becomes long and occurs after another event of several days with rain.

The observation of the discharges data show that the runoffs persist some days after the precipitations at their origin. This is due to the components of the watershed (geology and high level of forest cover which allow a surface detention of water released during a long time after). This phenomenon will allow having a good attenuation of the peak flows.

Note: Some missing values of flow, initially bridged by interpolation with values before or after, seem to correspond to flood values. The consequences can be a sub-estimation of maximum values and monthly values.

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Table 4.12: Precipitations and Runoffs on Gura bassin

Table 12 Precipitations and Runoffs on Gura basin

Events Precipitations (mm) Runoffs (mm) Coefficientof Runoff

Duration Amount Duration Amount

Mar. 2001 23 to 31/03 90.5 23 to 31/03 20.8 0.230

Apr. 2001 04 to 10/04 85.2 04 to 12/04 48.5 0.56914 to 18/04 123.5 14 to 20/04 35.7 0.28920 to 27/04 162.3 20 to 29/04 141.9 0.874

Nov. 2001 08 to 17/11 126.9 08 to 19/11 28.3 0.223

Apr. 2003 14 to 30/04 343.1 14/04 to 03/05 127.1 0.370

May. 2003 07 to 17/05 210.0 07 to 21/05 128.3 0.611

Oct. 2003 21 to 31/10 229.0 21 to 03/11 81.7 0.357

Nov. 2003 13 to 15/11 36.6 13 to 17/11 22.3 0.60919 to 29/11 122.2 19/11 to 02/12 65.2 0.534

Nov. 2004 2 to 15/11 184.5 02 to 18/11 147.4 0.799

May. 2005 21 to 31/05 226.5 21/05 to 03/06 86.4 0.381

4.2.2.5 Peak values of flood Not any hydrogram is available to compare mean daily values of flow and peak values. However, consecutive values of precipitations and flows show that flood sequences are long and with low variation of flow one day to another.

In so conditions it will be considered that the ratio “Peak Flow”/ “Mean Daily Flow” is about 2.00. So, the peak flows at the Gura gauging station are:

• For a return period of 30 years, pQ30 = 148 m3/s

• For a return period of 100 years, pQ100 = 194 m3/s The peak flows at the intake (S1 = 135 km2) and at the gauging station (S0 = 165 km2) are linked by the relation:

pQ1 = pQ0 . (S1/S0)0.,8

So, at the intake, the peak flows are:

• For a return period of 30 years, pQ30 = 126 m3/s

• For a return period of 100 years, pQ100 = 165 m3/s The flood project at the intake (T = 100 years) can be considered as 165 m3/s, so a specific flow of 1.22 m3/s/km2.

4.2.2.6 Empirical frequency curves As stated, the dependable flow analysis is one of the most important parts of the study as this will be the basis for determining the power generation potential and shall, likewise, be used as basis for the design of the hydraulic structures.

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the daily outputs observed at Gura intake are directly deduced from the flows observed at the Gura gauging station N°4AD04 (intercepted watershed: 165 km2) by the application of a coefficient equal to 0.8182 correspondent to the catchment area ratio (=135/165)

In accordance with the hydrology study:

• the median year at Gura intake is well represented by the year 1995,

• the dry years T=5 & T=10 are represented respectively by the years 1991 & 1996,

• the rainy years T=5 & T=10 are represented respectively by the years 1982 & 1994.

The EFC curves for Gura river are given hereafter for the median year, for dry five- and ten-years and in wet five- and ten-years.

These curves indicate a very regular hydrology having a guaranteed flow (seen all the time) ranging between 740 l/s and 1.28 m3/s.

4.2.2.6.1 Median year Figure 4.2: Empirical Frequency Curve (EFC) for Gura – Median year

The guaranteed flow (100%) is equal to 740 l/s

4.2.2.6.2 Dry year T = 5 & T = 10

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Figure 4.3: Empirical Frequency Curve (EFC) for Gura – Dry year

The two empirical frequency curves are crossing, so for the low values of flow, the probability values for T=5 years will be chosen on the 10 years curve and vice versa.

The guaranteed flows are respectively equal to 1.03 m3/s and 1.28 m3/s.

4.2.2.6.3 Rainy years T = 5 & T = 10 Figure 4.4: Empirical Frequency Curve (EFC) for Gura – Rainy year

The guaranteed flows are respectively equal at 950 l/s and 1.03 m3/s.

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It will be noted that the values vary hardly, between dry, median or rainy years, only for high values (low guarantee). At the contrary the low values (high guarantee) are very similar from type of year to another.

4.2.3 Topography Standard topographic maps scaled 1 / 50 0008 with contour lines covering the hydrographical network, roads, built-up areas, lands & administrative boundaries, and the whole watershed area of Gura river have been collected for the study: Nyeri 120/4-Kipipiri 120/3-Kirangop 134/1 ad Kangema 134/2.

Based on these data, a topographic survey of the Gura small hydro scheme was launched end of November 2007 during the Consultant’s mission. The area surveyed was along the future canal from the weir location to the power house area and close to the main structures of the project.

This topographic survey consisted mainly in two specific components:

General topographical mapping of a 200 m width corridor of land centred along the waterway between the weir / intake and the power house building & the outlet channel (the requirements include 1 m equidistance between level lines; grid co-ordinates in UTM zone 37; density of the points > than 20/ha)

Detailed mapping around the weir & the power house site (the requirements include 1 m equidistance between level lines; grid coordinates in UTM zone 37; density of the levelled points > than 500/ha; bathymetry under the water level of Gura river)

The following topometric bases were used for the establishment of these maps: 134 U 117 (Muyange 2)

These general and detailed maps have been used for the project design described hereunder.

4.3 Power scheme of development The guiding philosophy behind the preparation of the scheme of development (SOD) is to maximise the power generation potential of Gura river, taking simultaneously into account the river potential and the demand forecast for Gathuthy, Gitugi, Iria Ini and Chinga Tea Factories. This resulted in a maximum head development for Gura river.

At the stage of feasibility study (FS) the location and routing of the structures such as the weir, the settling basin, the waterway, the forebay, penstock and power house were preliminary based on the 1/50 000 NYERI 120/4 & KANGEMA 134/2 maps with field verification and survey using a hand help GPS for the location of the structures and a total station survey instrument for the detailed topographic survey from the weir to the power house plant. Hence, since a total station survey instrument was used for the elevations and contour surveys, the resulting head that can be developed from the proposed scheme is accurately determined. Furthermore, thanks to a quite well-researched hydrology, a complete study (water contributions, flood flow) could be led. Hence with accurately determined head and discharge, the resulting power capacity can reasonably be estimated with high level of confidence.

8 Series Y731 Kenya Government 1975 – Printed for Directorate of Overseas Survey – Ministry of Overseas Development

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The scheme of development (SOD) for small hydropower generation site on Gura river is shown, as initially planned, in the maps 4.1 and 4.2 hereunder. All detailed maps and drawings for Gura SHP site (GUR-N°1 to GUR-N°10) are given in annex, including sketch of the alternative (GUR-N°3), strip topographic layout (GUR-N°4 to GUR-N°6) and detailed views of hydraulic structures (GUR-N°7 to GUR-N°10).

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Map 4.1: Location of Gura SHP site (GUR-N°1)

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Map 4.2: General development plan (GUR-N°2)

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The table which follows presents the location of the main works for the suggested scheme.

Table 4.13: Location of the main works (Gura)

4.4 Optimization designed plant capacity / Unit arrangement

4.4.1 SHP sizing optimisation

4.4.1.1 Introduction on the approach In the previous paragraphs of section 4 of this study, we had a look at the topography, the geology and the hydrology of the Gura site where the projects is to take place. From these natural conditions we identified the energetic potential of the river that the project could yield.

An additional constraint to consider when designing a Small Hydro Power project is the demand. Indeed, there is only so much energy that can be absorbed by the KTDA tea factories load, while the excess power will be sold to the grid. As the PPA tariff with KPLC will be different from the actual value of the power directly consumed by the tea factories, the first step will be to assess share of energy placed on the tea factories local network and the share of excess energy sold to KPLC.

Therefore, there is a need to identify the optimal size of the project where one maximises the total energy sold to the Tea factories and to KPLC over the SHP lifetime, without over investing.

Our approach to select the optimal SHP project size is to compute the Internal Rate of Return (IRR) of the project, for various Small Hydro Power size and related preliminary costing. The hypothesis used to compute the IRR are the same as the one used in the financial model which will be presented in the Chapter 6 on the financial analysis.

The internal rate of return (IRR) of the project, in percent: IRR is the value of t for which the Net Present Value (NPV) of the project equals zero.

∑ +=

Nn

n

tCFNPV

1 )1(

with: NPV = Net Present Value of the project CF = project cash flows over the project’s lifetime N = number of years of calculation = project’s lifetime

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t = discount rate of the project.

As we consider the project IRR, all benefits should be considered. The SHP project comes as a substitution of the diesel and grid power bills. Thus, the cash flows generated by the project are measured in terms of savings realized each year by displacing diesel or grid power consumption with SHP production. Thus, the cash flows are computed as follows:

PPANBRBCFn +−+=

CFn = Project cash flow in year n

RB = Reference electricity bill 9

NB = New electricity bill for Project

PPA = Revenues generated via PPA to KPLC

Note: RB, NB, PPA are all in year n

( )EdEGpEdDpRB −×+×= GpEpENB ×−= )( Dp = Price of Electricity generated from diesel

Ed = Energy Demand satisfied by diesel

E = Energy Demand from the tea factories

Gp = Power price from grid

Ep = Energy placed

For each SHP sizing, the tool used for the estimation of the generation potential is presented hereafter.

4.4.1.2 Step 1: Assessment of generation potential For renewable energies in general, and hydroelectricity in particular, the International RETScreen model10, in self service data-processing is the world reference in term of dimensioning and decision-making aid.

This model evaluates the energy production from Small Hydro Power plants, isolated, or connected to a local / interconnected grid.

This tool is a standardized and integrated software for energy project analysis. It evaluates the power of the installations and the expected energy production.

It is developed as an individual Microsoft Excel file, composed of a number of worksheets, linked together. The three first sheets are entitled successively “energy model”, “hydrology and load” and “equipment data”.

Tab n°1 “energy model” gives the sites characteristics, the parameters of the system and the energy annual production. It fixes the classified load curves and the capacity.

9 As the tea factories will keep their grid connections, therefore the reference electricity bill only considers the variable costs of grid power. 10 Retscreen model is available on-line at www.retscreen.net

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Tab 2 “hydrology and load” represents the hydrological analysis of the site in a method of analysis defined by the user (the classified load curves are defined there - using correlation method - by the user on the basis of series validated here of the hydrological station N°84227 named Chambura at Kichwamba)

The type of installation suggested (here, run of the river), the residual flow and the percentage of availability of the guaranteed flow must, in addition, be provided.

Tab n° 3 “equipment data” characterises the turbines (Type, number and operation). It proposes a curve of output according to the considered equipment with a possible adjustment.

Based on the Gura hydrological characteristic and the proposed equipment for the power station, the RETScreen model estimates the annual quantity of renewable energy (in kWh) being produced.

This value is computed, in each case, based on the flow available (from the Flow Duration Curve), the turbine efficiency, the nominal installed capacity, the residual flow11, the head, and the probable losses from hydraulic and electric origin.

The yearly energy generated by the SHP (yearly output) is defined by the model as the area under the curve P of the classified power, by making a linear interpolation between the computed values of the produced powers (12). The following assumptions of energy losses and annual breaks/stops are taken into account in the evaluation of the energy produced:

• Maximum hydraulic losses: 5%

• Generator efficiency: 94%

• Electric losses: Transformer 1% - Parasitic electricity losses 2% → Total 3%

• Annual downtime losses: 5%

For Gura, the yearly output has been estimated for various design discharges, corresponding to different installed capacities:

Table 4.14: Estimated yearly output vs. discharge (Gura) Flow (m3/s) 1,5 2 2,5 3 3,5 4 4,5 Net Head (m) 148,4 148,6 148,9 149,2 149,2 149,3 148,6 Installed capacity (kW) 1 682 2 256 2 833 3 412 3 993 4 576 5 160 Energy utilisation ratio (%) 84 77 72 68 64 60 56 Yearly output (GWh/year) 12,337 15,244 17,866 20,246 22,338 24,03 25,49

4.4.1.3 Step 2: preliminary potential SHP sizing The SHP installed capacity depends on the design discharge. For each design discharge, one calculates the characteristics of the key components of the SHP scheme:

• dam

• canal

• spillway

11 Which is equal to 10% of the mean annual flow 12 The Flow Duration Curve represents an annual cycle. Each interval of 5% of this curve corresponds to 5% of 8760 hours (a number of hours in one year) that is to say 438 h. The hydrological cycle is thus well represented.

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• net head

• penstock

• installed equipment

The model used is an Excel spreadsheet developed by the Consultant.

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Table 4.15: Preliminary Gura SHP sizing vs. design discharge

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4.4.1.4 Step 3: preliminary costing for various SHP sizing For each of the potential SHP sizing, a preliminary costing has been carried out, based on Budget Unit price and preliminary estimated of quantities.

Results are provided in the table on the following page.

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Table 4.16: Preliminary costing for various SHP sizing GURA SHP 2,5 3,5 4,5

Kshs/US$ 70N° Work items Units Unit Price Qty. Total Total (US$) Qty. Total Total (US$) Qty. Total Total (US$) Qty. Total Total (US$) Qty. Total Total (US$) Qty. Total Total (US$) Qty. Total Total (US$)

Kshs Kshs Kshs Kshs Kshs Kshs Kshs KshsI. CIVIL WORKS1 General items

1.1 Land clearing ha 50 000 5 250 000 5 250 000 5 250 000 5 250 000 5 250 000 5 250 000 5 250 0001.2 Mobilisation-demobilisation LS 7 500 000 1 7 500 000 1 7 500 000 1 7 500 000 1 7 500 000 1 7 500 000 1 7 500 000 1 7 500 0001.3 Site office m² 50 0 50 included 50 included 50 included 50 included 50 included 50 included1.4 Operator house m² 20 000 300 6 000 000 300 6 000 000 300 6 000 000 300 6 000 000 300 6 000 000 300 6 000 000 300 6 000 000

Total 1 13 750 000 196 429 13 750 000 196 429 13 750 000 196 429 13 750 000 196 429 13 750 000 196 429 13 750 000 196 429 13 750 000 196 4292 Road works

2.1 New permanent gravelled road width 5 m km 11 250 000 0,300 3 375 000 0,300 3 375 000 0,300 3 375 000 0,300 3 375 000 0,300 3 375 000 0,300 3 375 000 0,300 3 375 0002.2 Rehabilitation of existing road km 3 000 000 5 15 000 000 5 15 000 000 5 15 000 000 5 15 000 000 5 15 000 000 5 15 000 000 5 15 000 0002.3 Bridge LS 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total 2 18 375 000 262 500 18 375 000 262 500 18 375 000 262 500 18 375 000 262 500 18 375 000 262 500 18 375 000 262 500 18 375 000 262 5003 Weir works and intake

3.1 Temporary works - cofferdam (sand bags) m3 2 000 700 1 400 000 700 1 400 000 700 1 400 000 700 1 400 000 700 1 400 000 700 1 400 000 700 1 400 0003.2 Excavation in soil m3 300 6 500 1 950 000 6 500 1 950 000 6 500 1 950 000 6 500 1 950 000 6 500 1 950 000 6 500 1 950 000 6 500 1 950 0003.3 Excavation in rock m3 2 000 600 1 200 000 600 1 200 000 600 1 200 000 600 1 200 000 600 1 200 000 600 1 200 000 600 1 200 0003.4 Jet grouting curtain m² 3 200 500 1 600 000 500 1 600 000 500 1 600 000 500 1 600 000 500 1 600 000 500 1 600 000 500 1 600 0003.5 Mass concrete m3 9 000 2 000 18 000 000 2 000 18 000 000 2 000 18 000 000 2 000 18 000 000 2 000 18 000 000 2 000 18 000 000 2 000 18 000 0003.6 Reinforced concrete 0 0 0 0 0 0

3.6 A Weir surface reinforced concrete m3 9 000 600 5 400 000 600 5 400 000 600 5 400 000 600 5 400 000 600 5 400 000 600 5 400 000 600 5 400 0003.6 B Weir structure reinforced concrete(Wings) m3 12 000 650 7 800 000 650 7 800 000 650 7 800 000 650 7 800 000 650 7 800 000 650 7 800 000 650 7 800 0003.6 C Bridge reinforced concrete (piers + deck) m3 12 000 150 1 800 000 150 1 800 000 150 1 800 000 150 1 800 000 150 1 800 000 150 1 800 000 150 1 800 0003,7 Rip-Rap (stone pitching) m² 600 450 270 000 450 270 000 450 270 000 450 270 000 450 270 000 450 270 000 450 270 000

Total 3 39 420 000 563 143 39 420 000 563 143 39 420 000 563 143 39 420 000 563 143 39 420 000 563 143 39 420 000 563 143 39 420 000 563 1434 Canal

4.1 Cut in soil for canal m3 300 13 483 4 045 007 17 514 5 254 231 21 497 6 449 121 25 446 7 633 828 29 369 8 810 821 33 272 9 981 705 37 159 11 147 5964.2 Cut in soil for base for chanel + road m3 300 250 922 75 276 747 265 329 79 598 577 278 354 83 506 137 290 398 87 119 427 301 699 90 509 734 312 412 93 723 505 322 643 96 793 0034.3 Gravelled road width 4 m km 5 000 000 6,700 33 500 000 6,700 33 500 000 6,700 33 500 000 6,700 33 500 000 6,700 33 500 000 6,700 33 500 000 6,700 33 500 0004.4 Slab reinforce concrete m3 12 000 1 523 18 281 564 1 697 20 363 456 1 850 22 197 640 1 988 23 855 870 2 115 25 380 769 2 233 26 800 110 2 344 28 133 1854.5 Massonery (walls) m² 1 000 15 004 15 004 407 17 326 17 325 597 19 371 19 370 606 21 219 21 219 436 22 920 22 919 610 24 502 24 502 094 25 988 25 988 395

Total 4 146 107 725 2 087 253 156 041 861 2 229 169 165 023 504 2 357 479 173 328 561 2 476 122 181 120 933 2 587 442 188 507 414 2 692 963 195 562 179 2 793 7455 Forebay

5,1 Excavation in soil m3 300 6 900 2 070 000 6 900 2 070 000 6 900 2 070 000 9 000 2 700 000 9 000 2 700 000 10 000 3 000 000 10 000 3 000 0005,2 Excavation in rock m3 2 000 720 1 440 000 720 1 440 000 720 1 440 000 850 1 700 000 850 1 700 000 1 000 2 000 000 1 000 2 000 0005,3 Earthworks : fill m3 300 690 207 000 690 207 000 690 207 000 850 255 000 850 255 000 1 000 300 000 1 000 300 0005,4 Mass concrete m3 9 000 400 3 600 000 400 3 600 000 400 3 600 000 500 4 500 000 500 4 500 000 600 5 400 000 600 5 400 0005,5 Hard core filling m3 1 500 600 900 000 600 900 000 600 900 000 700 1 050 000 700 1 050 000 1 000 1 500 000 1 000 1 500 0005,6 Lining 1000 gauge m² 100 2 000 200 000 2 000 200 000 2 000 200 000 2 500 250 000 2 500 250 000 3 000 300 000 3 000 300 0005,7 Rip-Rap (stone pitching) m² 600 690 414 000 690 414 000 690 414 000 750 450 000 750 450 000 1 000 600 000 1 000 600 0005,8 Reinforced concrete m3 12 000 60 720 000 60 720 000 60 720 000 70 840 000 70 840 000 80 960 000 80 960 0005,9 Flush valves and accessories LS 1 000 000 1 800 000 1 800 000 1 800 000 1 900 000 1 900 000 1 1 000 000 1 1 000 000

Total 5 10 351 000 147 871 10 351 000 147 871 10 351 000 147 871 12 645 000 180 643 12 645 000 180 643 15 060 000 215 143 15 060 000 215 1436 Penstock

6,1 Excavation in cut m3 300 1 540 462 000 1 650 495 000 1 760 528 000 1 870 561 000 1 958 587 400 2 046 613 800 2 134 640 2006,2 Reinforced concrete pipe support m3 9 000 30 270 000 40 360 000 50 450 000 60 540 000 70 630 000 80 720 000 90 810 0006,3 Penstock kg 200 70 336 14 067 200 75 360 15 072 000 80 384 16 076 800 85 408 17 081 600 89 427 17 885 440 93 446 18 689 280 97 466 19 493 1206,4 Back fill m3 300 1 232 369 600 1 320 396 000 1 408 422 400 1 496 448 800 1 566 469 920 1 637 491 040 1 707 512 160

Total 6 15 168 800 216 697 16 323 000 233 186 17 477 200 249 674 18 631 400 266 163 19 572 760 279 611 20 514 120 293 059 21 455 480 306 5077 Power house + Tail race

7,1 Excavation in soil 300 1 800 540 000 2 200 660 000 2 600 780 000 3 000 900 000 4 000 1 200 000 5 000 1 500 000 6 100 1 830 0007,2 Excavation in rock m3 2 000 280 560 000 400 800 000 550 1 100 000 700 1 400 000 950 1 900 000 1 200 2 400 000 1 460 2 920 0007,3 Earthworks : fill m3 300 1 250 375 000 1 400 420 000 1 550 465 000 1 700 510 000 2 350 705 000 3 000 900 000 4 800 1 440 0007,4 Mass concrete m3 9 000 130 1 170 000 170 1 530 000 210 1 890 000 250 2 250 000 300 2 700 000 350 3 150 000 445 4 005 0007,5 Reinforced concrete m3 12 000 95 1 140 000 130 1 560 000 165 1 980 000 200 2 400 000 265 3 180 000 330 3 960 000 535 6 420 0007,6 Metalworks (roof, doors,….) m3 150 2 350 352 500 2 700 405 000 3 100 465 000 3 500 525 000 4 500 675 000 5 500 825 000 8 550 1 282 5007,7 Superstructure building kg 20 000 210 4 200 000 300 6 000 000 400 8 000 000 500 10 000 000 650 13 000 000 800 16 000 000 995 19 900 0007,8 Parking area cut + fill m² 600 1 070 642 000 1 400 840 000 1 700 1 020 000 2 000 1 200 000 2 750 1 650 000 3 500 2 100 000 4 590 2 754 0007,9 Parking area gravel fill + compaction m3 1 200 410 492 000 500 600 000 600 720 000 700 840 000 850 1 020 000 1 000 1 200 000 1 820 2 184 0007,1 Rip-Rap (stone pitching) m² 600 440 264 000 700 420 000 900 540 000 1 100 660 000 1 550 930 000 2 000 1 200 000 2 950 1 770 000

Total 7 m² 9 735 500 139 079 13 235 000 189 071 16 960 000 242 286 20 685 000 295 500 26 960 000 385 143 33 235 000 474 786 44 505 500 635 7938 Metal works

8,1 Trash rack8,2 Trash rack rake LS8,3 Hand rails and miscellaneaous LS

Total 8 LS 4 000 000 57 143 4 000 000 57 143 4 000 000 57 143 4 500 000 64 286 4 500 000 64 286 5 000 000 71 429 5 000 000 71 429Total Civil Works 3 670 115 3 878 512 4 076 524 4 304 785 4 519 196 4 769 450 5 044 688

II. ELECTRO MECHANICAL WORKS US$/KSH Unit Price Total Kshs Total US$ Total Kshs Total US$ Total Kshs Total US$ Total Kshs Total US$ 100 Total Kshs Total US$ 100 Total Kshs Total US$ 100 Total Kshs Total US$1 Generating equipment LS 1 1 1 1 1 1 12 Electrical / Switchyard LS 1 1 1 1 1 1 13 Supporting equipment LS 1 1 1 1 1 1 14 Gates LS 1 1 1 1 1 1 1

Power kW 60 000 1 682 48 273 400 2 256 63 957 600 2 833 79 324 000 3 412 94 341 800 3 993 109 008 900 4 576 121 721 600 5 160 136 740 000Total E.M. works 0 48 273 400 689 620 63 957 600 913 680 79 324 000 1 133 200 94 341 800 1 347 740 109 008 900 1 557 270 121 721 600 1 738 880 136 740 000 1 953 42911 KV LINE 900 000 30 27 000 000 385 714 30 27 000 000 385 714 30 27 000 000 385 714 30,00 27 000 000 385 714 0,00 0 0 0,00 0 0 0,0033 KV LINE km 1 500 000 0 0 0 0 0 0 0 0 0 0 0 30,00 45 000 000 642 857 30,00 45 000 000 642 857 30,00 45 000 000 642 857

III. TOTAL DIRECT COST US$ 4 745 449 5 177 907 5 595 439 6 038 239 6 719 323 7 151 188 7 640 974Contengencies 5% 237 272 258 895 279 772 301 912 335 966 357 559 382 049Overhead costs 15% 711 817 776 686 839 316 905 736 1 007 898 1 072 678 1 146 146

Total 5 694 539 6 213 488 6 714 526 7 245 887 8 063 187 8 581 425 9 169 168

4,003,002,00Q (m3/s) 1,5

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4.4.1.5 Step 4: energy placement model The first input of the energy placement model is the load forecast. It provides important characteristics of the demand for each year: the total energy consumption of the 4 tea factories of that year, the peak load and the load factor of the demand. From this load factor and energy consumption, the model builds a load duration curve, based on typical load duration curves depending on the load factor, as shown in the graph below. Based on the data collected, the Load factor is estimated to be 44%.

Figure 4.5: Demand and Load Duration Curve

0%10%20%30%40%50%60%70%80%90%

100%

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

Load duration curve model for Four (4) Tea factories

The second input into the model is the SHP characteristics, for various installed capacity. The installed capacity and potential energy production (corresponding to the river potential) are computed in. The model identifies a maximum placement curve for each year of operation, which is the minimum between the SHP installed capacity and the demand load duration curve: at any given time, there is not necessarily enough water to produce the energy that could be placed. The model therefore includes a mismatch factor which is a way to represent the lack of correlation between hydrology and the power demand from the tea factories, and the impact on energy placement. The energy placement curve is therefore corrected with the mismatch factor in order to obtain the final energy placement value. The graph below illustrates the energy produced by the Gura SHP, placed on the local grid of the four (4) tea factories. On this scenario, the Gura installed capacity is 2.26 MW with an annual output of 15.24 GWh, and the four tea factories annual demand is 8.64 GWh. From this simulation, only 89.4% would be supplied by the Gura SHP and the four tea factories would consume only 50.7% of the yearly output.

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Figure 4.6: Simulation of the placement of energy – SHP supply to 4 tea factories

0

500

1 000

1 500

2 000

2 500

0% 21% 42% 63% 83%

kW Simulation of the Placement of EnergyGura SHP supply to the 4 Tea factories

Four (4) Tea factories Load duratrion curve

Energy placement from the SHP

We have computed the total energy placement for the various Gura SHP sizing assessed in the previous steps. The goal of step 4 is to work out the energy placement on the 4 tea factories local grid for each year and thus find out the excess power which will be sold to KPLC, over the lifetime of the project.

4.4.1.6 Step 5: Ranking of the SHP sizing scenario and selection As indicated earlier, our approach to select the optimal SHP project size is to compute the Internal Rate of Return (IRR) of the project, for various Small Hydro Power size and related preliminary costing. The financial model to compute the IRR is the same as the model which will be presented in the Chapter 6 on the financial analysis. The key parameters characterized of the potential sizing scenario for the Gura site are synthesized in the following table.

Table 4.17: Estimated IRR vs. discharge (Gura) Flow (m3/s) 1,5 2 2,5 3 3,5 4 Installed capacity (kW) 1,682 2,256 2,833 3,412 3,993 4,576 Energy utilisation ratio (%) 84 77 72 68 64 60

Yearly output (GWh/year) 12.337 15.244 17.866 20.246 22.338 24.03

Estimated Invest. (k$) 5 695 6 213 6 715 7 246 8 063 8 581 IRR (%) 16.8% 17.5% 18.0% 18.0% 17.1% 16.9%

From these results, it appears that the IRR grows as long as the installed capacity is below 2,833 kW (corresponding to 2.5 m3/s design discharge), then becomes constant and starts decreasing when the installed capacity grows.

For a 2.5 m3/s design discharge, an estimated 92% of the four tea factories demand would be supplied from the Gura SHP and only 87% in the case of a 1.5 m3/s design discharge.

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From the above, we will select the 2.50 m3/s flow discharge, corresponding to an installed capacity of 2,833 kW, for the full detailed feasibility study.

4.4.2 Unit arrangement

It is often the case that two smaller turbines will provide a better optimised solution than a single larger turbine.

Two smaller Pelton turbines are most likely to be more expensive than a single large Pelton turbine for the same combined capacity, but the benefits are:

• The reduced downtime associated with two machines. This varies from country to country and site to site and therefore any thorough evaluation would need to take a view on the reduction of the amount of downtime from going from one turbine to two, and the knock-on effect to the amount of electricity generated,

• A higher efficiency can be achieved for a higher proportion of the flow curve leading to a higher annual electrical energy capture,

• The ability to continue operation of the plant on one of the two turbines (at reasonable efficiency) at low flows, as opposed to very poor efficiency for only one installed turbine,

• The reduced weights for the individual pieces of equipment (i.e. turbine and generator) and associated reduction in costs for craneage, for the construction period and maintenance (using the internal powerhouse crane)

Ultimately the choice will be based on economics depending on local electricity prices but calculations would tend to indicate that the two machine option would be a good choice for the project: For the same installed capacity, it increases in average year the renewable energy delivered of 0.4%, but mainly to increase by 40% the plant firm capacity.

4.5 Energy generation

4.5.1 Main characteristics of the Pelton turbine The table hereafter summarizes the gross head, the design flow and the main characteristics of the Pelton turbines and their output-curve. These data are used in the evaluation of the energy generation defined in the three following chapters.

Figure 4.7: Main characteristics of the Pelton turbine

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4.5.2 Energy produced in average year Based on the previous analysis, the Gura Small Hydro Plant capacity is equal to 2,833 kW.

For the equipment defined above and the EFC in median year, the energy produced annually is equal to 17.87 GWh with a capacity factor of 72%.

According to the SHP scheme sizing and the hydrology & charge data of Gura river, the availability of power in % of the time is given by the following curves:

Figure 4.8: Power & Flow Duration Curves – Median year

4.5.3 Energy produced in dry years For the equipment defined above and the EFC in dry year T10, the annual energy production is equal to 17.5 GWh with a capacity factor of 71%.

These values are not very different from those obtained in average year.

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According to the SHP scheme sizing and the hydrology & charge data of Gura river, the availability of power in % of the time is given by the following curves:

Figure 4.9: Power & Flow Duration Curves – Dry year T10

4.5.4 Energy produced in rainy years For the equipment defined above and the EFC in rainy year T10, the annual energy production is equal to 19.0 GWh with a capacity factor of 77%.

As previously one can note that these values are not very distant from those obtained in average year: these results show the extreme regularity of the river.

According to the SHP scheme sizing and the hydrology & charge data of Gura river, the availability of power in % of the time is given by the following curves:

Figure 4.10: Power & Flow Duration Curves – Rainy year T10

4.6 Plan of development The plan of development is presented on the previous maps 4.1 and 4.2.

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4.6.1 Hydraulic calculation and results Developed in the following paragraphs and presented in the form of a longitudinal profile in map GUR-N°3 (cf. Annex), the hydraulic calculations were established on the basis of the weir water level of the two characteristic design flows (1) Qeq (2.50 m3/s) and (2) QT100 (165 m3/s) and by taking into account a certain number of elements such the slope of the waterway, the sets of the geometrical characteristics of the different hydraulic structures and the regular pressure losses (friction) and singular related (entry, exit, change, abrupt or not, of the flow cross-section etc…).

The next table summarizes, for each hydraulic works, the elevation of the water levels for the two quoted flows.

Table 4.18: Hydraulic feature (Gura)

Items Q= 2.5 m3/s Q= 165 m3/s

Weir level 2,066.00 2,066.00 Gura river ELV 1 2,066.11 2,067.65 Settling basin upstream ELV 2 2,066.10 2,066.45 Settiling basin downstream ELV 3 2,066.10 2,066.10 Main canal (upstream) ELV 4 2,066.00 - Main canal (downstream) ELV 5 2,061.85 - Forebay inlet ELV 6 2,061.68 - Forebay Max pool level MPL 2,062.19 - Forebay Low pool level LPL 2,060.86 - Forebay outlet ELV 7 2,061.51 -

Penstock ND 900 losses 1 PL1 0.78 - Penstock ND 900 losses 2 PL2 5.80 - Penstock ND 900 losses 3 PL3 0.38 -

Power house ELV 8 2,054.55 - Tail race level ELV 9 1,900.80 -

4.6.2 The weir and the intake structure In Gura SHP, the weir is a non-storage run-of-the-river diversion structure.

The following inherent design characteristics are adopted for the diversion weir structure:

Ogee-type spillway weir where the entire crest length (35 m) serves as the principal spillway in case of overflow;

Three (3) meter-high weir height from upstream apron slab to dam’s crest;

Boulder-core with concrete binder for the main Ogee core with 0.25 meter (m) concrete wearing surface;

Provided with 2 sluice gates:

(1) a simple one 3.5x3.5 m in the right bank. Its function is to flush off sediments from the upstream to the downstream locations and also to act as secondary spillway, and

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(2) a small one (dim.0.8x0.8 m) controlled by the upstream water level, to allow the residual flow downstream (416 l/s);

Provided with upstream and downstream apron slabs with penetrating cut-off walls beneath the river to arrest excessive seepages;

Provided with complete intake structure (towards the settling basin and the canal) with steel trash racks to prevent large debris from entering intake, lifting mechanism for gate control and sediment control device.

The design criteria adopted are as follows:

100 years flood frequency in the analysis of the afflux elevation (i.e. the rise in elevation above the weir’s flood level)

Safety factor of at least 1.25 in the stability analysis of the main weir ogee core with the maximum water pressure up to the afflux level, and seepage analysis by use of the Lane’s weighted creep theory in the sizing of the upstream and the downstream apron slab’s lengths.

At an elevation of 2,068 m, the intake barrier of 6.70 long and 5.00 m high, the intake is located on the small cliff forming the north abutment, at a suitable level to allow discharge into the settling basin and the canal.

Interdependent of the weir and the settling basin downstream, the intake is composed of two sluices 1.50x1.50 provided with two power-controlled valves.

A trash rack and a stop log isolate the civil works downstream the settling basin.

The flow in the canal is regulated (using an “opening law” formula), at the same time, by these first valves and an other motorised one, located at the end of the settling basin and upstream of the canal.

The bottom of the river bed, upstream and downstream, is composed of more or less important blocks (boulders) which were installed on the passing time and which appears stable under the effect of the river current.

Nevertheless, on the area of the various structures composing the weir/intake, these materials will be cleared down to the bed-rock and will be replaced by a rolled compacted fill carried out successively starting from the two banks.

If the location of the weir is on the quick velocity area of the river, the flushing gate, the intake and the settling basin are, on the right bank, over the (quiet) average velocity area.

In this upstream zone, these works are protected:

on the one hand by a small wall parallel to the river, occurring its with the weir and developing upstream.

On the other hand by an arrangement of the boulders built with a coal shovel upstream over a distance of 22 m.

These arrangements, if they do not isolate really the weir, reduce the risks of material drivings downstream from the river bed towards the intake and the settling basin.

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The map GUR-N°8 given in annex and the two tables hereafter show the outline design details for the weir and the intake structure for Gura SHP.

Table 4.19: Weir geometrical characteristics N° Items 1 Nominal discharge m3/s 2.5 2 Weir elevation m 2,066.00 4 Spillway lenght m 35.00 5 Spillway width m 9.81 6 Upstream apron slab elevation m 2,063.00 7 8

Downstream apron slab elevation Water levels (design flow &flood flow T=100)

m m

2,062.70 2,066.11/2,067.65

9 Associated sluice gates: m 10 to flush off the sediments downstream 11 Layout mm 1x3,500x3,500 12 Elevation m 2,066.50 13 For the residual flow (416 l/s) 14 Layout mm 1x500x500 15 Elevation m 2,065.50 16 General level of the banks m 2,690.00

Table 4.20: Weir gates characteristics

4.6.3 The settling basin

4.6.3.1 General description

The settling basin, proposed to clean the water from its suspended solid residues (TSS), will be laid immediately downstream the intake and upstream of the waterway.

In addition, this hydraulic structure plays also safety and regulation roles to protect the canal:

• Safety because its spillway is dimensioned to protect the canal at the time of occurred T100 flood flow (or other less important flood flows),

• Regulation because two servo-motorized sluice valves, upstream and downstream, will allow flow regulation before its entrance in the waterway.

The settling basin, perpendicular to the weir and superficially founded at elevation 2,062.00 m is built on reinforced concrete. It constitutes the right bank abutment of the river.

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34.60 m length, its working width 4.25 m (out off 5.55 m) allows an equipped flow transit (2.50 m3/s) under low speed (0.5 m/s)

Downstream, two manoeuvrable sluice gates at elevation 2,068.00 m regulate, on the one hand, the transit of the nominal capacity towards the canal (1 motorized 1,200x1,200) and, on the other hand, the periodic draining of the work (1 manual 1,500x1,500)

This last sluice gate is not designed to pass the flood through, but to be opened periodically in the flood season for cleaning out deposits.

The normal water level is regulated by a lateral spillway at elevation 2,066.10 m. This elevation corresponds to the structure water level when the nominal discharge goes through.

This spillway has the role to chop the flood flows (until the T100 flood flow) and to allow, with the downstream sluice gate 1,200x1,200, the keen adjustment of the flow required by the power station.

The water level reached in the work at the time of the happened T100 flood flow is 2,067.50 m for an drained off flow of 3.5 m3/s.

The design/dimensioning of the settling basin are given to the following chapter.

The inherent design characteristics given in the following table are adopted.

Table 4.21: Settling Basin geometrical characteristics N° Items 1 Nominal discharge m3/s 2.50 2 Length / Width of the settling basin m 34.60x5.55 3 Height of the settling basin m Between 5.00 & 5.30 4 Storage volume m3 231 5 Length of the spillway m 11 6 Input/output raft elevation of the settling

basin m 2,063.00 / 2,062.70

7 Input elevation of the canal m 2,064.77 8 General level of exploitation m 2,068.00 9 General level of the access m 2,066.60 10 11

Trash rack Water level during the design flow

m

1 2,066.10

12 Associated sluice gates: 13 To supply the settling basin (2,50 m3/s) 14 Layout mm 2x1,500x1,500 15 Elevation m 2,063.00 16 to flush off the sediments downstream 17 Layout mm 1x1,500x1,500 18 Elevation m 2,062.70 19 to supply the canal (2,50 m3/s) 20 Layout mm 1x1,200x1,200 21 Elevation m 2,064.70

Table 4.22: Settling basin gates characteristics

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4.6.3.2 Settling basin: Detailed design of civil construction

4.6.3.2.1 Dimension The design of the settling basin uses Camp method

According Camp:

WxL / VxY = ((WxY^1/6) / VxNxG^1/2) With:

W: Sedimentation velocity,

L: Length of the basin,

V: Flow velocity,

Y: Flow depth,

N: Manning coefficient,

G: Gravity acceleration.

When the particle diameter of sediment is 0.25 mm, according to Camp, the vertical speed W is equal to 0.03 m/s. The diameter of 0.25 mm is typically recommended by the suppliers of Pelton turbines.

With the assumption that flow depth Y equal with channel depth, and the basin width equal to 4.86 m, we assume that:

V = 3.00 / 1.23 x 4.86 = 0.50 m/s

((WxY^1/6) / VxNxG^1/2) = 0.03 x 1.23^0.1667 / 0.50 x 0.018 x 9.81^0.5 = 1.1016

So, for 100% sedimentation:

WxL / VxY = 1.1016

The length of the settling basin is then:

L = 1.1016 x 0.50 x 1.23 / 0.03 = 22.58 = 23 m.

So, we take L = 23 m and B = 4.90 m, with a transition length upstream (intake) equal to 7.7 m.

In the section considered and for V= 0.50 m/s, we obtain a gradient for the settling basin equal to 0.11 mm/m.

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4.6.3.2.2 Design of storage volume The storage volume capacity required depends on total of sediment (base and fly sediment) that will deposit till flushing time. The rate of sedimentation (TSS and iron) based on field survey is equal to 10 mg/l. We choose to dimension with this last value (10g/m3).

That is to say 10 x 3.0= 30 g/s.

We obtain, with a relative density of the grains (due to the water) of 1.5 t/m3, an evaluated annual throughput with 630 m3/year. That is to say 52.5 m3 per month.

The design of the storage volume is: (((2 064.9 – 2 062.7) + (2 064.9 – 2 063))/2) x 4.90 x 23 = 231 m3

So, the flushing frequency of de-silting is 231 / 52.5 = 4.40 months.

4.6.3.2.3 Control of the settling basin According Shields equation:

d = 10^4 x R x I with:

d: the biggest particle diameter that will throw away (same with trash rack opener, i.e. 50 mm)

R: mean of hydraulic radius,

I: bottom slope.

We have S = 6.027 m; P = 7.36; R = 0.8189

Therefore the bottom slope is I = 50 / 10^4 x 0.8189 = 0.0061 = 0.61%

The slope over 23 m distance is: I = 14.03 cm,

The depth difference till under sluice is selected equal to 0.3m.

4.6.3.2.4 Spill way The spillway is designed downstream of the settling basin, and be function to flow the increase water at flood condition.

The elevation of upstream water level at 100 years flood return period is 2,067.65 m.

Height of flood water at the intake: we use Bernoulli equation through 2 sluice gates 1.5 x 1.5 m.

E1 = E2+∆h

Z1+P1/γ+V1^2/2g = Z2+P2/γ+V2^2/2g + ∆h

with ∆h= K x V2^2/2g (K= 0.78 coarse shape)

Then Z = Z1-Z2 = 1.78 x V2^2/2g

V2^2 = 2gZ / 1.78

V2 = 0.75 x (2gZ)^0.5 with Z = 2 067.65 – 2 066.45 – ½ x 1.5 = 0.45 m

V2 = 2.2285 m/s

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And Q = 2x1.50x1.50 x 2.229 = 10.03 m3/s

The waterway capacity is, for h = 1.83 m, equal to 6.81 m3/s.

Then the discharge that will overflow at the settling basin is 10,03 – 6,810 = 3,21 = 3,5 m3/s.

To design the weir we use this formula:

Q = m x L x h x (2gh)^0,5 with m = 0.80 x 0.4375 = 0. 35

Then L = 2.2576 / h^1.5

h = 0.30 m → L = 13.73 m = 14 m

h = 0.35 m → L = 10.90 = 11 m

h = 0.40 m → L = 8.92 = 9 m

With L = 11.0 m, the water height that overflow over the spillway is 0.35 m.

4.6.4 The waterway

4.6.4.1 General description The waterway line is an important part of any hydropower system and its function is to convey water from the intake of the weir and the settling basin to the forebay and down to the turbine through the penstock line.

The total length of the waterway is 6,665 meters with a slope of 0.59 mm/m. The waterway consists mainly in cuts on the right bank of the river, between elevations 2,064.77 m and 2,059.72 m.

Its profile is essentially trapezoidal (over 6,480 m out of 6,665 m), except when crossing the specific ditches (marked) where the canal shall be rectangular and carried out on posts (over 185 m out of 6,665 m).

Maps GUR-N°9, N°5, N°6 & N°7 given in annex (i) show the outline design details for the typical cross sections and (ii) indicate in three topographic maps the various zones where the typical sections are applied.

Dimensioned for the capacity of 3.0 m3/s (nominal capacity of 2.50 m3/s with a safety factor of 20%), the height of normal water level in the canal is identical for the two profiles: 1.23 m.

With that flow capacity, the velocity of water flow in the trapezoidal profile is 1 m/s.

The free board suggested is 0.60 m.

We propose a concrete lining for the trapezoidal sections. The role of this coating is multiple: it must ensure the sealing, avoid the erosion of the closeness soils and facilitate the marling conditions, improve the condition of flow, ensure a long durability of the canal and reduce maintenance.

In certain sections and according to the closeness soils, this coating could be drained in the foundation raft (draining and/or filtering refill in alluvia) and on the walls of the canal (porous concrete trenches), water of drainage being evacuated by a longitudinal collector located under the foundation raft.

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According to the nature of the soils encountered, some joints could be placed in the coating. The purpose of these joints is to locate the cracking of the concrete slabs due to the withdrawal, the thermal expansions and the possible packing down.

The coating of the all length of the canal with a concrete lining has been proposed and has been taken into account in the total evaluation of the works.

However this proposal to coat the waterway or to adapt its coating-type (coating by stone pitching or masonry) could be modified according to the results of the detailed geotechnical investigations which will be conducted on the canal later, in particular if these new provisions result in reducing the total cost of this transfer. It will be however noted, in the chapter dealing with the total amount of the investments, that, for the canal itself, it is primarily the share of the earthworks which is important.

A service path protected by gravel (three meters broad) and ditches (especially for the cut profiles and intended to drain surface waters coming from the top of the valley) will border the canal on its all course.

A gutter of remote control, posed on sand and connecting the weir to the forebay and the power station will be laid out close to the canal edge.

As the canal in the low earth-cut zones will cross small existing foot tracks between some open settlements and various cultivated pieces, several new accesses for farmers and cattle will be realised above the trapezoidal canal (concrete slab and handrails).

Lastly, to allow the natural drainage of the slope, culverts (ND 200 to ND800) will be arranged under the raft foundation of the canal when it crosses the little marked ditches. These ditches will become the main discharge system of (1) the small drainage sewers which could sometimes be placed under the canal, (2) the few draining works of the canal (3) and its safety spillways.

The design/dimensioning of the canal are given to the following chapter.

4.6.4.2 Waterway: detailed design of civil construction The waterway is designed in trapezoid shape (some parts in rectangular shape).

The design of flow velocity in the channel is 1 m/s.

The waterway design discharge is 2.50 m3/s.

The channel capacity is designed with 120% of the design discharge, i.e. 3.00 m3/s. This requirement is to anticipate the discharge decrease over the 6.67 km length, caused of trash etc.

The waterway is considered as a long channel and the flow of this nature can be considered as uniform flow. Maning’s equation can be used below.

4.6.4.2.1 Canal trapezoidal: A=1.50 m2

The width of channel bottom is 1.20 m.

The left and right side slope of the channel is 1H/1V.

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Table 4.23: Lined trapezoidal channel characteristics LINED TRAPEZOÏDAL CHANNEL: Q=2.5 & 3.0 m3/s, K=55.5, Side slope 1/1, b=1.20 m, i=0.00059 m/m

h S P R Q V m m2 m m m3/s m/s 0.9 1.890 3.745 0.5045 1.614 0.85

0.95 2.042 3.887 0.5254 1.792 0.87 1.1251 2.615 4.382 0.5969 2.500 0.95 1.2325 2.998 4.686 0.6397 3.000 1.00 1.83 5.544 6.376 0.8696 6.810 1.23

We obtain with a slope of 0.59 mm/m :

For b=1.20 m: h= 1.13 m for 2.,50 m3/s and h= 1.23 m for 3.00 m3/s with V= 1.00 m/s.

Free board = 0.25xh+0.3= 0.6081 rounding to 0.6m.

4.6.4.2.2 Canal rectangular: The width of channel bottom is 2.5 m.

Table 4.24: Lined rectangular channel characteristics LINED RECTANGULAR CHANNEL: Q=2.5 & 3.0 m3/s, K=55.5, b=2.50m, i=0.00059 m/m

h S P R Q V m m2 m m m3/s m/s 1 2.486 4.486 0.5541 2.260 0.90

1.3 3.232 5.086 0.6354 3.220 1.00 1.0765 2.676 4.639 0.5769 2.500 0.93 1.2325 3.064 4.951 0.6189 3.000 0.98

We obtain with a slope of 0.59 mm/m:

For b=2.50 m: h=1.08 m for 2.50 m3/s and h=1.23 m for 3.00 m3/s.

The free board is the same as previously: 0.60 m.

4.6.4.2.3 Head loss along the channel: The length of the waterway is 6,665 m till the forebay, so, the estimated head loss along the channel is:

P1 = 1^2x6 665/(55.5^2x0.6398^4/3) = 3.92 m

Along the waterway there are 35 bends. The head loss caused by the bends is:

P2 = 0.3x 1/(2x9.81)x14 = 0.21 m

Total head loss along the waterway: 4.15 m

4.6.4.2.4 Water reserve Water Reserve (by deepening) at the end of the canal (intersection of the canal and the main road (from Gura river to the Munyange village)

The assumptions taken into account are as follows:

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• The deepening of the waterway (depth p) is carried out without modification of the geometry and the slope of the canal,

• Referring to the empirical frequency curve, the available minimum flow on Gura river is permanently of 740 l/s.

• The departure of the penstock is (in the forebay) under the foundation raft of the canal.

• Volumes available: (described here below)

This evaluation is given in the table hereafter, which presents 2 variables: (1) the deepening p and the length of the concerned reach L (the length of the reach between the canal and the village of Munyande is approximately 1,250 m).

Table 4.25: Water reserve (m3) by deepening (d (m)) D (m) 0,10 0,25 0,50 0,75 1,00 1,25 1,50

L (m) Additional volumes mobilised compared to the current section of the canal

100 37 94 200 317 448 590 746 250 93 236 499 794 1 119 1 476 1 864 500 186 472 998 1 587 2 238 2 952 3 728

1 000 373 944 1 997 3 174 4 477 5 904 7 457 1 250 466 1 181 2 496 3 968 5 596 7 381 9 321 1 500 559 1 417 2 995 4 762 6 715 8 857 11 1852 000 746 1 889 3 994 6 349 8 954 11 809 14 914

For L =1,250m and a deepening of one meter, the capacity storage is 5,600 m3.

For this volume, the power station can work with full capacity lasting T = 5,600/(2.50 – 0.74) x 3,600 = 0.88, that is to say 1 hour approximately.

4.6.5 The forebay

4.6.5.1 General description The proposed forebay, made of reinforced concrete, is located at the end of the canal at the top of the slope dominating the power house and the river.

Its aim is to receive the water from the canal and to distribute it to the penstock.

This structure shall be long and wide enough to accommodate the penstock, the spillway or the scouring gate. Its storage volume shall be capable of regulating the flow entering the penstock.

This buried construction has 15.50 m length for an inside width of 3.15 m. It is composed of two main parts, the first organising the lateral spillway (see below) and the scouring gate, the second feeding the pressure pipe.

Stop log separates these two parts enabling to completely isolate the pipe pressure at the time of the O & M operations.

On both sides of the gate, a first rough grid and a fine grid enable to stop the floating debris and the last immersed harmful particles before the penstock entrance.

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In SHP plants, the draw down/up of the water during transitory phenomena can be considered as small. When the plant is suddenly shut down, a hydraulic bore or surge takes place while the canal is still supplying water to the forebay. Nevertheless, this will happen during an emergency and will be considered.

Because of it, a side spillway is provided and then the complicated procedures associated with unsteady flows can be avoided. This side spillway is designed for maximum discharges into the canal.

Likewise, to accommodate the deposition of silt, the entrance elevation of the forebay’s intake is much higher than the floor base. As a result the maximum water depth picked in the proposed forebay is approximately 4.3 m, and the mean velocity is 0.20 m/s, so that it can be expected to settle out effectively the last harmful particles in this bottom of the reservoir.

The forebay outlet, scheduled during shut-down of the plant, will take place through a buried pipe ND 900 towards a stable gully located in the vicinity. Plumb in the pipe outlet area, a stone rip-rap, centred on the scouring pipe, is envisaged to prevent erosion and possible local landslides.

Map GUR-2 (given in annex) shows the gully and the spillway alignment from the forebay. Map GUR-10 (annex) and the two tables below show its outline design.

Table 4.26: Forebay geometrical characteristics N° Items 1 Length / Width of the forebay m 15.50x3.75 2 L1 12.00 3 B1 3.15 4 (Maximum) Height of the forebay m2 5.5 5 Length of the spillway m2 9.5 6 Input/output raft elevation of the forebay m2 2,059.72 / 2,057.55 7 General level of exploitation m 2,062.55 8 General level of the access m 2,061.5 9

10 Trash rack Water level during the design flow

m

2.00 2,061.68/2,061.51

11 Associated scouring gates: 12 for emptying & to flush off the sediments downstream 13 Layout mm 1x1,500x1,500 14 Elevation m 2,057.55

Table 4.27: Forebay gates characteristics

4.6.5.2 Forebay: Detailed design of civil construction

4.6.5.2.1 Dimension The width of the forebay is determined by the total width of the intake or other appurtenances, taking into consideration the average velocity in the forebay or in front of the intake.

B is the total width of the intake, B = 0.9 + 2 x 0.60 = 2.10 m

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And B1 the total width of the forebay, B1 =1.5 x B = 1.5 x 2.10 = 3.15 m

The length L of the forebay (excluding the intake length L1) is equal to 3 x B1 taking into consideration the layout of its appurtenances, such as the side spillway and the sand sluice or the scouring gate.

L1 = 3.50 m and L = 3 x 3.15 = 9.45 m

For hydraulic reasons partly due to the depth of the penstock ND 900, a L1 length of 12.00 m is retained.

The length of the horizontal floor base itself is be greater than B1.

4.6.5.2.2 Depth of the forebay based on penstock size and position The minimum depth of penstock intake from water surface (S) is done by:

S = C x V x ND^0.5 with C = 0.54; V: velocity in the penstock 3.93 m/s and ND900mm

S = 0.54 x 3.93 x 0.9^0.5 = 2.01 m

The depth of the penstock intake is 2,061.51- 2,058.45= 3.06 > 2.01 m

4.6.5.2.3 Spillway The side spillway should be designed for maximum discharge into the canal (3.00 m3/s) and the top edge of the intake should be well positioned below the lowest pool level to prevent air entrainment during draw down.

To design the weir we use the formula: Q = m x L x h x (2gh)^0.5 with m = 0.35

L = 1.9351 / h^1.5

h = 0.30 → L = 11.70 m = 12.00 m

h = 0.35 → L = 9.35 m= 9.50 m

h = 0.40 → L = 7.65 m = 8.00 m

With L = 9.50 m, the water height that overflow over the spillway is approximately 0.35 m.

4.6.6 The penstock line The penstock line is the high pressure component of the SHP system. It conveys water from the forebay (atmospheric or free pressure flow state) to the power house (pressure flow state) and converts the potential energy of the flow at the forebay into kinetic energy at the turbine level.

4.6.6.1 General description The proposed penstock is a steel penstock, being proof against stabilised pressures about 1.6 bars, and being able to reach 3 to 4 bars at the time of the hydraulic transient states.

The penstock is also buried. This decision is made, on the one hand, to avoid cutting a certain number of cultivated pieces and access tracks between the forebay and the power house, and on the other hand, for obvious environmental reasons since it is located on the opposed slope to the road connecting Ndugamano to Muyange.

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Between forebay and power house (and despite to be buried), seven anchor blocks (stable against overturning and sliding) are placed at every sharp change along the penstock pipe. They are designed to retain penstock pipe movement in all directions.

Two thermal joints (expansion/contraction), also playing the role of relative settlement joint between works and penstock, are envisaged to be installed.

For manufacture and production costs reasons, but also to face the hydraulic transient states, the penstock thickness is constant on its entire course. Later, the project building documents will examine the possibility of reducing sequentially this thickness according to the position of the pipe in the penstock line, and correlatively its final cost.

4.6.6.1.1 Penstock diameter Empirical formulas for ascertaining the economic diameters for penstocks are recommended by various authors on the basis of data from existing penstocks (by the regression method) among which the following empirical formula is recommended for SHP plants.

De = C1 x C2 Q^0.43 x H^-0.24 With C1 = 1.5 (areas where the energy cost is medium); C2 = 1.25 (steel penstock); Q = 3.0 m3/s and H = 155 m (design head of the plant)

Then De = 1.5 x 1.25 x 3.0^0.43 x 155^-0.24 = 0.896 m

We assume for Gura SHP a selected penstock diameter of ND 900.

For this diameter, speed at the nominal discharge is 3.93 m/s and the regular and singular pressure losses are close to 7 m (4,5% of the total height)

4.6.6.1.2 Material & Wall thickness The penstock uses steel material which is widely used in high head plants and where there is an expectation of a long service life.

Wall thickness of the penstock is calculated considering the static pressure owing to the difference in water level from the forebay to the power house’s tailrace and another pressure component: the (very importantly) dynamic pressure in the event of the rapid closure of the butterfly valve before the turbine.

Its thickness is determined by t = (ND + 800) / 400 = 4.25 mm

The corrosion thickness added for penstock will taken 3 mm.

As the dynamic pressure take as 40% of the static pressure (which is added to calculate the internal bursting pressure) and to keep more stiffness during transportation, we assume finally a thickness of t=10 mm.

The following inherent design characteristics are adopted for the penstock line.

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Table 4.28: Penstock geometrical characteristics N° Items 1 Nominal (Internal) diameter ND mm 900.00 2 Layout buried 3 Elevation departure (Edge of Gura forebay) m 2,058.00 4 Elevation arrival (Edge of Gura power house) m 1,903.50 5 Length m 392 6 Number of joint (expansion or relative settlement) 2 7 Work area width m 14.9

Table 4.29: Penstock mechanical characteristics

The map GUR-N°10 in annex shows its outline design.

4.6.7 The powerhouse and the tailrace channel

4.6.7.1 General description The powerhouse shall be a masonry-wall building partially buried in the natural right edge-slope of Gura river, covered with a metallic trussed roof. All the generating facilities are housed inside the building except the main and the auxiliary transformers, the treated water tank and the sewerage system.

The powerhouse shall be sized for housing all the electromechanical equipment in the machinery room and shall have an office area (3.00x2.50) and sanitary facilities (2.10x1.25). Its size shall be at least 18.33x10.50 m and high enough for unloading the equipment from a truck.

The building has of a double leaf door 4.50 m broad to allow equipment installation and an additional door to the office area.

The front side of the building has several windows and low and high airings, to allow natural lighting and ventilation of the groups.

Located not far from a school, the shape of the building and the building materials will reduce the visual impacts, and will bring back the acoustic incidence of the project to a low level in comparison with the current situation of this area. For that reason, accurate noise-traps will be placed in the high and low ventilations.

The architectural commitment and the frontages will be close to those of the local habitat.

An overhead gantry crane shall be installed to raise or lower the heaviest equipment in the machinery room.

In infrastructure, the civil engineering of the tail race canal is interdependent of the concrete support slab of the turbine-alternator group. It ensures the restitution of turbinate water until a section of the river located roughly at about forty meters from the powerhouse. This work will be adapted in its design to avoid the possible ascent of fish in its direction.

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A fence shall enclose the entire site of the powerhouse and forbid any trespassing except by the main gate.

The following inherence design characteristics are adopted for the powerhouse structure.

Table 4.30: Powerhouse & Tailrace geometrical characteristics N° Items 1 Length / Width of the Power house m 18,33x10,50 2 Total surface on the ground m2 220 3 -of witch office (soundproofed) m2 7.5 4 -of witch sanitary m2 3.5 5 Elevation of the axis of the turbine m 1,903.50 6 General level of SHP exploitation m 1,903.00 Tail race water level m 1,900.80 7 Raft elevation of the tail race to Gura river m 1,899.67 8 Raft width of the tail race to Gura river m 1.2

4.6.7.2 Electro-mechanical equipment The main electro-mechanical equipment in the machinery room includes:

- Two butterfly valves ND 600 NP 25 with their by-pass; servo-motors opens its and counterweights for safety closes its.

- Two horizontal axis unit with Pelton turbines and brushless synchronous generators

- Two oil system and governor for the turbines and the valves control

- The medium voltage switchgear with 8 cells:

o Two cells for the generators’circuit breakers

o One cell for the bus bar isolating switch and the measurement apparatus on the bus bar.

o One cell with fuses interrupter for the auxiliary transformer

o Four cells housing the circuit breakers for the feeders to Iria Ini-Chinga, Gitugi, Gathuti and KPLC

- The control and protection cubicles including the auxiliary AC and DC supplies

- The 20 KVA stand- by diesel generator

- The water filter and treatment system to supply the site with drinkable water.

- The Cadmium-Nickel battery for the DC supply

Two full-enclosed ONAN transformers (2 x 2,000 kVA) raising the generator voltage to 11 KV shall be located outdoor on a pad close to the PH wall. They shall be sheltered by the PH roof overhang and fully fenced.

The first pole of each 11 KV line shall be located inside the PH site. They shall be equipped with three lightning arrestors.

All the electrical equipment in the PH site shall be interconnected outside of the building by armed cables laid in the ground with specific protection.

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Earthing buried network shall be done during the earthwork in order to get an earthing resistance less than one ohm. All the metallic part and the lightning arresters on the site shall be strongly earthed. Neutral point of transformer and generator shall be earthed through a resistance to limit the fault-current to 30 Amp.

The site shall be protected from thunder by an active lightning rod on the PH roof and directly earthed in specific earth rods.

The main characteristics of the mechanical and electric equipment of Gura SHP are given hereafter:

Table 4.31: Powerhouse equipment characteristics N° Items 1 Design flow m3/s 2.5 2 Gross head m 154.50 3 Net head m 147,54 4 SHP capacity kW 2,840.00 5 Turbine type Pelton 6 Number/ axis 2/ horizontal 7 Turbine efficiency curve data source standard 8 Number of jets for the turbine 3 9 nominal speed t/mn 1,500

10 Turbine peak efficiency % 87 11 Flow at peak efficiency m3/s 1.7 12 Turbine efficiency at design flow % 85.8

13 Alternator type synchronous/brushless 14 Power (kVA) 3,000 kVA 15 Voltage MV 16 cos phi 0.8

17 Butterfly valve

18 Diameter/Nominal water pressure 2xND 600/ NP 25 kit out with its bypass

19 Opening/Closing Servo-motorized-Closing ensured by a counterweight

20 Production group of oil under pressure yes

21 Transformers Main transformer 3,000 kVA, MV/11 kV Transformer of the auxiliaries 50 kVA - 11,000 V/400 V

The drawing GUR-N°11 given in annex shows the powerhouse concept plan for Gura SHP.

4.6.7.3 Electrical diagram at powerhouse The electrical design is a block diagram design which is the most convenient for that size of power.

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The generators shall be synchronous brushless ones. The supplier shall determine output voltage by between 4 and 7.2 KV. Sets of CTs and PTs shall give the value of current and voltage for the protective relays, the synchronizer, the voltage regulator and the metering. Neutral point shall be formed and earthed through a resistance to limit fault current. The main transformers shall be a D/Y type with a no-load tap changer and neutral earthed through a resistance on the HV side. They shall be protected by thermal, buckholz and over-current relays. The drawable circuit-breakers shall be SF6 type. The control system and the protective relays activates directly the tripping by voltage missing. Auxiliary AC shall be supplied by the 100 KVA three-phase transformer and the 20 KVA stand-by Diesel generator could supply electricity in case of a long time breakdown. The power plant is designed for an isolated network but authorizes also operation in parallel with other generators. The control system has 4 modes:

1. Automatic mode, intake level monitoring: the control system starts/synchronizes/ connects and adjusts the units to the optimal power to maintain constant the intake water level.

2. Automatic mode, network monitoring: the control system starts/synchronizes/connects and adjusts the power to the network load but the power remains limited to the available upstream flow.

3. Semi automatic mode: the control system starts/synchronizes/connects and maintains the power to a set point chosen by the operator, but the power remains limited to the available upstream flow.

4. Manual mode: the operator starts/synchronizes/connects and adjusts the power output by push buttons on the control board.

In every mode, the protective relays, the synchro-check and the automatic emergency shut-down remain operative.

The operator has to adjust the voltage set point and the AVR shall maintain the voltage at the chosen value.

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Figure 4.11: Single-line electrical diagram of the SHP powerhouse

11 KV SWITCHGEAR

Yd11/ KV2000 KVA

R

R

G 1 1500 KWbrushless

VarW

rpm

u>

u<

A

kW

VF

I>>

TRIP

I>

I>>I>

A WkW

V

AUXILIARIES SERVICE

DDiesel generator20 KVA 400 V Y

Dy11/0,4 KV100 KVA

UNIT 2IDENTICAL

TOUNIT1

AVR

SYNCHRO

+ or -Speed & V

to SYNCHRO G2

A

Var

W

kWV

A

Var

W

kWV

A

Var

W

kWV

A

Var

W

kWV

FEEDERIRIA &CHINGA

FEEDERGITURI

FEEDERGATHUTI

FEEDERKPLC

I>>

TRIP

I>>

TRIP

I>>

TRIP

I>>

TRIP

I>

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4.6.7.4 Provisions for safety of the hydraulic works and the Gura river users In order to protect both the SHP scheme and the passers-by, the left bank of the Gura weir/intake and the immediate proximity of all hydraulic works, especially the powerhouse/tailrace site, will be prohibited and will be surrounded by fencing.

Panels of information judiciously located near these works will indicate to the farmers / villagers the nature of the equipment, the safety instruction and the ecological advantages of such installation.

4.6.8 The access road works Three accesses to the Gura SHP sites are envisaged.

• To reach the weir, Kigumo road will be rehabilitated on 4,400 m, from the school and the church located near the road Ngugamano/Muyange.

• The access to the forebay will be built from this road taking from middle height (towards Muyange) the way bordering the canal on 1,250 m.

• Lastly, the access to the power house and the operator’s house will be built from the bridge located 300 m downstream by taking on approximately 700 m the track bordering on the left bank the river.

The last two accesses will be carried out in provisional form to the whole beginning of work (at the same time as the earthworks of the canal in its final part). Final accesses will be carried out at the end of the work.

4.6.9 Operator’s house Operator’s house is close to the power house and located at the same level (1,902.80 m) It will occupy a land area of 8.0 m x 12.50 m.

Its architectural commitment is identical to that the power house.

Operator’s house shall be a masonry-wall building partially buried and covered with a metallic roof. Four reinforced concrete columns are placed at each corner where the walls are attached.

The building, which includes four rooms of which a kitchen, is largely open (bay window) in direction of the power house.

4.7 Work schedule For Gura SHP, a list of tasks has been established and detailed task durations have been assessed. A detailed tentative work program has been studied for the selected scheme.

The times before work are regulated mainly by the land control. A provision of 16 months is proposed for the total achievement of these tasks.

The time of works is 24 months.

This time is divided into 24 months for the realization of the civil engineering and 13 months for manufacture, transport and installation of the hydraulic and electric materials.

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Inside these two schedules: 17 months are proposed for the realization of the canal and its final work (forebay) and 8 months are proposed for the manufacture of the turbine generator set.

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Figure 4.12: Suggested detailed work programme

New work programme

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4.8 Staffing and training requirements for plant operation and management

4.8.1 Tentative list of staff required Provided that the tea factories are expected to play a direct and active role in the management and operation of the mini hydro plants, they must have qualified staff. This staff can be either recruited or adequately trained. In the first case utility personnel or former staff from the industry with practice in mini or large hydro can be sought.

The list of the personnel can be as follows:

• Management staff (engineer level):

The plant manager responsible for the power station,

and a financial & administrative officer (The both can directly come from the staff of the four tea factories recipient of the project)

• Operational staff (technician level):

6 operators working into three/eight with a responsible indicated,

• and:

1 security guard.

4.8.2 Hydroelectricity capacity building In the case of training on purpose of the tea factory, the following training actions can be taken:

• Management staff:

General theoretical training on power generation, hydrology, main principles of the civil works and electro-mechanics: runner, generator, transformers, DC and AC auxiliaries, protections, starting, stopping automates and the economics of hydropower (one week)

Specific training on the mini hydro performance and demand side management by the contractor in charge of the plant optimisation concepts and dedicated software.

• Operational staff:

• General theoretical training on power generation, hydrology, main principles of the civil works and electro-mechanics: runner, generator, transformers, DC and AC auxiliaries, protections, starting, stopping automates (one week)

• On site preliminary training in another hydro plant (one-to three months) operated by a power utility or another hydro power generating industry. This session should include a specific training about safety rules at work,

• Specific on site training on the mini-hydro plant installation as specified in the contractor’s terms of reference (operation and maintenance)

• Practical training on MV line and substation operation with the local utility.

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4.9 Cost estimate

4.9.1 General approach, construction works by contracts and cost summary

It is assumed that the development of Gura would be undertaken via a Build-Own-Operated (BOO) company which will bring the equity required for the development of the project.

The owner which probably is EATTA or GATHUTHY, GITUGY, IRIA-INI & CHINGA TEA FACTORIES will examine later the best way of tendering and organising the realisation of work.

But, as in most mini to medium hydroelectric power development projects, which involves multi-disciplinary works, it is the general approach in construction to categorized the specialized works and choose the qualified construction or manufacturing/supply/installation firms which best fit the required expertise on hand.

It is with this general approach that the cost estimates for Gura hydropower site in Nyeri district were based upon.

In the proposed cost estimate:

the prices of supply of construction materials and for civil work realisations (Weir, intake, settling basin, forebay and other hydraulic works), the prices of supply, transport on site and the prices for laying the penstock or to put in the various gates on the one hand,

the prices of supply, transport and assembly of the mechanical and electric equipments on the other hand,

are built either from unit costs established on the basis of price schedule extract from recent contracts, or after consultation.

It is the same for the costs generated by the access road installation and for the 11 kV grid connection.

The 2 following tables show the general summary and the breakdown of costs of the major project expenditures respectively.

Table 4.32: General Summary of Project Costs GENERAL SUMMARY OF PROJECT COST GURA SHP

ITEMS KESx10^3 US $x10^3 SUB-TOTAL "1" CIVIL WORKS (CW) 346 670 4 952 SUB-TOTAL "2" MAIN ELECTRICAL WORKS (MEMW) & SUB-TOTAL "3" ELECTRICAL NETWORK (MV+LV) 168 866 2 412

A CONTRACTED / CONSTRUCTION WORKS 515 536 7 365 B ENGINEERING SERVICES (DED & CS) 51 364 734 C CONTINGENCIES (5% OF PROJECT COST) 21 350 305 TOTAL PROJECT COST 588 250 8 404 US$ COST/kW 2,966

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Table 4.33: Breakdown of Project Costs BREAKDOWN OF COSTS GURA SHP

ITEMS KESx10^3 US $x10^3 A CONTRACTED / CONSTRUCTION COST I CONTRACT 1: CIVIL WORKS (CW) 1-GENERAL ITEMS 19 806 283 2-ROAD WORKS 6 256 89 3-WEIR WORKS & INTAKE 45 213 646 4-SETTLING BASIN 15 288 218 5-CANAL 180 130 2 573 6-FOREBAY 8 057 115 7-PENSTOCK LINE 18 406 263 8-POWER HOUSE & TAIL RACE 21 999 314

TOTAL 315 155 4 502 UTR 10% 31 515 450

Sub total '1' CIVIL WORKS (CW) 346 670 4 952

II CONTRACT 2: MAIN ELECTRO-MECHANICAL WORK (MEMW) MANUFACTURE, SUPPLY AND INSTALLATION, SUPERVISION OF HYDRO GENERATING EQUIPMENT SETS (TURBINE, GENERATOR, CONTROLS TRANSFORMERS ETC…)

TOTAL 133 239 1 903 UTR 5% 6 662 95

Sub total '2' MAIN ELECTRO-MECHANICAL WORKS (MEMW) 139 901 1 999

III CONTRACT 3: ELECTRICAL NETWORK (MV+LV)

TOTAL 27 585 394 UTR 5% 1 379 20

Sub total '3' ELECTRICAL NETWORK 28 964 414

TOTAL CONSTRUCTION / CONTRACTED COST 515 536 7 365 B ENGINEERING SERVICES I VALIDATION OF THE DETAILED ENGINEERING DESIGN (DED) 8 732 125

II CONSTRUCTION SUPERVISION 42 632 609 TOTAL ENGINEERING SERVICES 51 364 734 C CONTINGENCIES 21 350 305 TOTAL CONTINGENCIES 21 350 305 TOTAL PROJECT COST 588 250 8 404

4.9.2 Detailed basis of cost estimates The basis of cost estimates per pay items are found in the succeeding tables as follows:

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Table 4.34: Detailed Costing for Civil Works (CW) N° ITEMS UNIT COST

KESx10^3 QTY TOTAL KESx10^3

TOTAL kUS$

I CIVIL WORKS (CW) 1-GENERAL ITEMS

1.1 Mobilisation/Demobilisation LS 7500.00 1.0 7 500 1.2 Investigation drill holes m 20.00 160.0 3 200 1.3 Temporary works - Cofferdam (sand bags) m3 3.00 825.0 2 475 1.4 Land clearing ha 50.00 16.3 816 1.5 Water control LS 385.00 1.0 385 1.6 Site office m2 8.50 180.0 1 530 1.7 Operator house m2 13.00 300.0 3 900 19 806 283 2-ROAD WORKS

2.1 New permanent gravelled road width 5 m km 1125.00 0.300 338 2.2 Rehabilitation of existing road km 300.00 4.400 1 320

2.3 Gravelled road width 3 m (along the canal) km 690.00 6.665 4 599

6 256 89 3-WEIR WORKS & INTAKE

3.1 Normal excavation (works) m3 0.30 15 000.0 4 500 3.2 Rock excavation w/out blasting m3 1.50 3 000.0 4 500 3.3 Rock excavation w/ blasting m3 1.90 1 500.0 2 850 3.4 Backfilling compacted m3 0.53 750.0 398 3.5 Rip-rap lining m3 0.70 830.0 581 3.6 Cleanness concrete (100 kg/m3) m3 4.90 45.9 225 3.7 Reinforced concrete (350 kg/m3) m3 11.50 1 685.0 19 378 3.8 Formwork for concrete m2 1.00 515.0 515 3.9 Reinforcing steel bars Kg 0.09 84 250.0 7 583

3.10 Mild steel bars Kg 0.07 8 425.0 590

3.11 Sluice gate 3,500x3,500 (fixed and mobile parts) u 3145.00 1.0 3 145

3.12 Sluice gate 800x800 (fixed and mobile parts) u 950.00 1.0 950

45 213 646

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N° ITEMS UNIT COST KESx10^3 QTY TOTAL

KESx10^3 TOTAL

kUS$ 4-SETTLING BASIN

4.1 Normal excavation (works) m3 0.300 1,250.0 375 4.2 Rock excavation w/out blasting m3 1.500 250.0 375 4.3 Rock excavation w/ blasting m3 1.900 125.0 238 4.4 Backfilling compacted m3 0.530 62.5 33 4.5 Cleanness concrete (100 kg/m3) m3 4.900 22.7 111 4.6 Reinforced concrete (350 kg/m3) m3 11.500 370.0 4,255 4.7 Formwork for concrete m2 1.000 900.0 900 4.8 Reinforcing steel bars Kg 0.090 37,000.0 3,330 4.9 Mild steel bars Kg 0.070 3,700.0 259 4.10 Steel for trash rack and screen cleaner Kg 0.300 1,203.3 361

4.11 Steels for ironwork (grating, footbridge and handrail…/…) Kg 0.250 484.0 121

4.12 Sluice gate 1,500x1,500 (fixed and mobile parts) u 1260.000 3.0 3,780

4.13 Sluice gate 1,200x1,200 (fixed and mobile parts) u 1150.000 1.0 1,150

15,288 218 5-CANAL

5.1 Normal excavation (works) m3 0.300 259,700.0 77,910 5.2 Rock excavation w/out blasting m3 1.500 25,970.0 38,955 5.3 Backfilling normal (careful embanking) m3 0.300 12,985.0 3,896 5.4 Concrete lining (150 kg/m3) m3 5.250 6,500.0 34,125 5.5 Reinforced concrete (350 kg/m3) m3 11.500 450.0 5,175 5.6 Formwork for concrete m2 1.000 2,700.0 2,700 5.7 Reinforcing steel bars Kg 0.090 45,000.0 4,050 5.8 Mild steel bars Kg 0.070 4,500.0 315 5.9 Welded wire-mesh Kg 0.060 97,500.0 5,850

5.11 Concrete culverts 0,50 m dia - 1 m m 3.850 75 288 5.12 Concrete culverts 0,75 m dia - 1 m m 4.350 75 326 5.13 Concrete culverts 1,00 m dia - 1 m m 4.850 37 182 5.14 Concrete culverts 1,50 m dia - 1 m m 7.450 37 279

5.15 Supply and poses electric precasted concrete sleeves, single slope along the top of the channel: 15x15

m 0.850 7,057 5,998

5.16 Supply and poses in buried rooms 30x30 - spacing 100 meters - with plug cast iron of visit

u 1.150 71 81

180,130 2,573

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N° ITEMS UNIT COST KESx10^3 QTY TOTAL

KESx10^3 TOTAL

kUS$ 6-FOREBAY

6.1 Normal excavation (works) m3 0.300 770.0 231 6.2 Rock excavation w/out blasting m3 1.500 77.0 116 6.3 Rock excavation w/ blasting m3 1.900 38.5 73 6.4 Backfilling compacted m3 0.530 38.5 20 6.5 Cleanness concrete (100 kg/m3) m3 4.900 11.5 56 6.6 Reinforced concrete (350 kg/m3) m3 11.500 220.0 2,530 6.7 Formwork for concrete m2 1.000 850.0 850 6.8 Reinforcing steel bars Kg 0.090 22,000.0 1,980 6.9 Mild steel bars Kg 0.070 2,200.0 154

6.12 Steel for trash rack and screen cleaner Kg 0.300 2,494.8 748

6.13 Steels for ironwork (grating, footbridge and handrail…/…) Kg 0.250 155.0 39

6.14 Sluice gate 1,500x1,500 (fixed and mobile parts) u 1260.000 1.0 1,260

8,057 115 7-PENSTOCK LINE

7.1 Normal excavation (canal & penstock) m4 0.300 1,100.0 330 7.2 Rock excavation w/out blasting m3 1.500 110.0 165 7.3 Backfilling compacted m3 0.530 550.0 292 7.4 Mass concrete (250 kg/m3) m3 9.000 15.0 135

7.5 Supply and poses of pipe ND 900 mm out of steel with welded joints m 41.000 392.0 16,072

Supply and poses of pipe ND 600 mm out of steel with welded joints m 37.000 16.0 592

7.6 Supply and poses of altimetric or planimetric bends in ND 900 mm out of steel with welded joints

u 200.000 2.0 400

7.7 Supply and poses of a bifurcation ND 900/600 mm out of steel with welded joints u 420.000 1.0 420

7.8 Joint ND 900 (relative settlement) u 320.000 2.0 640 18,406 263

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N° ITEMS UNIT COST KESx10^3 QTY TOTAL

KESx10^3 TOTAL kUS$

8-POWER HOUSE & TAIL RACE 8.1 Normal excavation (works) m3 0.300 3 256.0 977 8.2 Rock excavation w/out blasting m3 1.500 651.2 977 8.3 Backfilling compacted m3 0.530 325.6 173 8.4 Rip-rap lining m3 0.700 300.0 210 8.5 Cleanness concrete (100 kg/m3) m3 4.900 33.2 163 8.6 Concrete lining (150 kg/m3) m3 5.250 42.1 221 8.7 Mass concrete (250 kg/m3) m3 9.000 41.3 371 8.8 Reinforced concrete (350 kg/m3) m3 11.500 165.0 1 898 8.9 Formwork for concrete m2 1.000 850.0 850

8.10 Reinforcing steel bars Kg 0.090 14 437.5 1 299 8.11 Mild steel bars Kg 0.070 1 443.8 101 8.12 Welded wire-mesh Kg 0.060 631.9 38

8.13 Production of wall/partition armed in breeze blocks e=22.5 coated 2 layers m2 0.850 0

8.14 Interior painting in two layers - Oil-based paint m2 0.380 303 115

8.15 Industrial tiling on the ground and walls inside the powerhouse m2 0.750 238 179

8.16 Steels for pipes, connection part and special parts in ND 600 (inside the powerhouse)

Kg 0.410 1 933.7 793

8.17 Steels for ironwork (grating, footbridge and handrail…/…) Kg 0.250 577.4 144

8.18 Operating platform and access m2 7.100 1 500.0 10 650 8.19 Kerbstones m 0.430 168.0 72 8.20 Rainy network LS 275.000 1.0 275 8.21 Sewage network LS 145.000 1.0 145 8.22 Built or covered ditch 0,5x0,5h m 3.900 137.5 536 8.23 Vegetalized platform m2 2.250 750 1 688 8.24 Sowing - Plantation of trees and shrubs LS 125.000 1.0 125

21 999 314 TOTAL I 315 155 4 502 Unforeseen & technical risks 10% 31 515 450 TOTAL CIVIL WORKS 346 670 4 952

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Table 4.35: Detailed Costing for Main Electro-Mechanical Works (MEMW)

N° ITEMS UNIT COST KESx10^3 QTY TOTAL

KESx10^3 TOTAL kUS$

II MAIN ELECTRO MECHANICAL WORKS (MEMW)

1

Supply of 2 Pelton / generator with horizontal axis - nominal discharge: 1.25 m3/s, head 155 m - Capacity 2x1,420 MW including 2 butterfly valves ND 600 - PN25 equipped with a by-pass

LS 73 149.9 1.0 73 150

2

Supply of an electric control panel for orders, protection and automatism of the equipment including tele-signalling / remote control, main transformer 23.000 kVA, MV/11 kV and auxiliary transformer 50 kVA, 11 kV/400V

LS 52 695.0 1.0 52 695

3 Connection with the 11kV line LS 1 258.4 1.0 1 258 4 Tests on site LS 3 619.0 1.0 3 619 5 Start-up of the equipment LS 2 516.9 1.0 2 517 133 239 1 903 Unforeseen and technical risks 5% 6 662 95

TOTAL MAIN ELECTRO MECHANICAL WORKS 139 901 1 999

Table 4.36: Detailed Costing for Electrical Network (EN)

N° ITEMS UNIT COST KESx10^3 QTY TOTAL

KESx10^3 TOTAL kUS$

III ELECTRICAL NETWORK (11 kV LINE) TOTAL III 27 585 394 Unforeseen and technical risks 5% 1 379 20 TOTAL 11 KV LINE + LV NETWORK 28 964 414

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5 RURAL ELECTRIFICATION PLAN

5.1 Rural power demand It was shown in chapter 3 that the national grid managed by KPLC has been intensively extended in the project area and most localities and trading centres are (or will be very soon) connected to the grid or located at less than 3km from the grid. Only the small and less financially attractive localities (remote location, low commercial activities, lack of financial capacity to contribute to the initial investment and to afford electricity tariff, even social) may not be connected soon.

For those reasons, extending the network lines to supply those remaining non-electrified settlements has not been considered within the Gura SHP project as they could be better targeted by solar electrification projects.

Therefore the total power demand presented in chapter 3 is coming from the 4 selected tea factories only, as summarised in the table below:

Table 5.1: Key data on power demand Input Data Gathuthi Gitugi Iria Ini Chinga

Division Tetu Othaya Othaya Othaya Total energy demand MWh 1,621 1,919 2,248 2,771 Total peak load kW 519 530 557 629 Transformer kVA 1000 1000 1000 1000 Number of phases 3 3 3 3 Distance to SHP scheme km 5.5 5 11 24

5.2 Spatial layout Before starting any system design, the geographic representation of the power demand is extremely important to draw the most economical electrical distribution network between the power generation point(s) and the load points.

A Geographic Information System (GIS) has been used to localise the SHP power plant, the tea factories, the villages and trading centres, the access roads and the existing KPLC network. The developed GIS has allow the optimisation of the lengths/sections of the lines from the powerhouse to each step-down transformer at entrance of tea factories. It has also been used to represent and compare the various grid connection scenarios. The GIS map given in Annex has been prepared with data collected from field surveys (GPS points), tea factories, REA database and KPLC.

In the case of Gura SHP project, the proposed grid connection scenario (cf. chapter 2) requires the investment in new dedicated MV lines between the SHP powerhouse and the 4 tea factories, independent from the existing MV network operated by KPLC. One of these 11kV lines from KPLC comes at less than 0.5km from the powerhouse.

As shown on the GIS map, one road goes to Gathuthi factory located at about 5km from the powerhouse, while the 3 other factories are positioned on another road. Gitugi, Iria Ini and Chinga are respectively at 5km, 11km and 24km from the powerhouse.

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5.3 Preliminary network design

5.3.1 Main MV line In the retained scenario described in chapter 2.2, 4 feeders will start from the powerhouse:

- one feeder of 5.5km along one road to reach Gathuthi factory (3x 50 mm² ABC),

- one feeder of 5km along the second road to reach Gitugi factory (3x 50 mm² ABC),

- one feeder of 24km along the same road to reach the 2 furthest factories Iria-Ini and Chinga (3x 95 mm² ABC),

- one feeder of 500m along the same road to interconnect with KPLC network (3x 95 mm² ACSR).

The total length of MV line between the powerhouse and the tea factories is 35km, following the existing track roads for simple land access and easy maintenance reasons.

Given the maximum peak power to transit in the lines, the electrical losses have been calculated (cf. § 2.2.3). The 3 conductors will be supported by 11m poles spaced out by 130m.

5.4 Electrical configuration The next figure illustrates schematically the electrical network interconnecting the Gura SHP, the 4 tea factories and the existing KPLC grid.

Figure 5.1: One-line electrical diagram for Gura SHP project

11 kV (new line)

11 kV (KPLC existing line)

ChingaTea

Factory

GitugiTea

FactoryIria IniTea

Factory

GathuthiTea

FactoryAuxiliaries

GuraSHP

5.5 Preliminary Costing The next table summarises the estimated investment budget for the MV line between the hydropower source and the tea factories and leads to 11,422$ per km of 11kV line.

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Table 5.2: Preliminary costing for MV network 11kV line Cost ($)

KPLC 7,547 Gathuthi 60,915 Gitugi 55,941 Iria Ini + Chinga 269,671 Total MV lines 394,074

The next table gives more details on electrical network equipments, indicative quantities and estimated costing for the electrification of tea factories.

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Table 5.3: Detailed costing for 11kV lines (USD) KPLC Gathuthi Gitugi Iria Ini + Chinga Total

11 KV Line Unit Price Unit Qty Total Qty Total Qty Total Qty Total Qty Total Alu cable 50mm² 1.02 ml 0 0 18,000 18,270 16,000 16,240 0 0 34,000 34,510 Alu cable 95mm² 1.02 ml 2,000 2,030 0 0 0 0 77,000 78,155 79,000 80,183 joint sleeve 3.63 set 4 15 36 131 32 116 154 558 226 819 Treated wood pole - 11m 261.00 per pole 4 1,044 44 11,484 40 10,440 194 50,634 282 73,602 suspension equipment 362.50 per pole 4 1,450 44 15,950 40 14,500 194 70,325 282 102,225 Reinforced concrete 108.75 per pole 4 435 44 4,785 40 4,350 194 21,098 282 30,668 11m pole (stop-end) - 2 HEA 240 1,740 per stop 1 1,740 4 6,960 4 6,960 19 33,060 28 48,720 stop-end pole equipment 616.25 per stop 1 616 4 2,465 4 2,465 19 11,709 28 17,255 Reinforced concrete (stop-end) 217.50 per stop 1 218 4 870 4 870 19 4,133 28 6,090 TOTAL USD 7,547 60,915 55,941 269,671 394,074

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6 ENVIRONMENTAL AND SOCIAL IMPACT ASSESSMENT

6.1 Detailed Study Report As per contractual Terms of References, an Environmental and Social Impact Assessment of the site has been undertaken by IED and a local subcontractor (Que Energy Ltd) in accordance to the prevailing Environmental Legislation in Kenya.

The expected environmental and social impacts of developing the site have been identified and an environmental management plan to mitigate any identified negative impacts of developing the site has been provided. The Environmental and Social Impact Assessment report also includes an overview of the range and depth of environmental and social issues inherent in developing the small hydro site, including possible conflicts and identify categories of affected groups, downstream impact on the river flow on socio-economic activities such as irrigation, fishery resources, drinking water and land use as well as any scale of displacements, if any, resulting from implementing the Gura Small Hydro Power.

The ESIA Report is a separate document provided in annex and it shall be presented to the respective National Environmental Management Authority (NEMA) in Kenya for approval and certification.

6.2 Preliminary Conclusions The construction of a Small Hydropower Plant (SHP) of 2.8 MW on Gura river shall include several components (weir, waterway, forebay tank, penstock, powerhouse, electrical network) that have in some extend impacts on the population and environment in the surrounding area. 5 villages and about 60 hectares of land (mainly agricultural crops) are concerned and have been surveyed by the ESIA team.

Some direct positive impacts have been identified for the project area as job creation, clean electricity supply for local industry and communities, road network, security.

The main potential negative impacts which require adequate preventive / mitigation measures include:

• Vegetation cover degradation caused by the removal of trees from the intake and canal route within the forest,

• Removal of vegetation and clearance from canal route, power house and forebay sites along farms, some with tea bushes,

• The community expressed safety concerns over having an open waterway canal, • There are significant risks of pollution of the abstraction points for construction

water, • Risks of pollution from oil spills, waste disposal of oils, grease etc from

construction equipment and activities, • Risks of pollution from the spoiling of excess excavation materials and from

dust from construction activities.

The principal mitigation measures included in the ESIA plan are:

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• Creation of a tree nursery. Initiate a trees nursery and tree planting programme in collaboration with the tea factories, the Kenya Forestry Service and relevant government organs, financiers and experts, • Undertake top-soiling and grassing programme for any access road reserve, • Develop and document Standard Operating Procedures (SOPs), schedules and supervision guidelines for the project for controlling the risks from oil spills, dust, water abstraction for construction etc, • Address safety concerns of the community for waterway canal crossings either through covering of the canals or provision of specific crossings both for humans and livestock, • Regular interaction and discussions with the community. A position of environmental manager/officer shall be created during construction to oversee to oversee environment and social management of re-planting of trees and other vegetation along the canal route, the recovery of any eroded areas, enhanced safety measures and general liaison with the community during and post construction period.

Environment Impact Statement (EIS) prepared according to the national EIA guidelines shall be submitted to the Executive Director of NEMA.

6.3 CO2 Impact

6.3.1 Emission reduction for Igara tea factory Gathuthi, Gitugi, Iria-Ini and Chinga tea factories is connected to the national grid and use backup diesel generators during power outages or low grid quality. Total consumptions of grid electricity and fuel for backup gensets have been calculated in Chapter 3. To assess the CO2 reduction impact when interconnecting the factory to a hydropower plant, we apply the electricity emission factor of 0.8 tCO2/MWh as substitution of diesel and the electricity emission factor 0.5223 tCO2/MWh as substitution of the grid electricity.

The final calculation gives a emission reduction of 11,450 tCO2 per year for the four tea factories, that can be valued at a price of 14 $ / ton of CO2 emission.

An updated status of carbon market is given hereafter.

6.3.2 Overview of the carbon market Global carbon markets are worth €40 billion in 2007, up by 80 percent from 2006. The total traded volume increased by 64 percent from 1.6 Gt (1.6 billion tonnes) in 2006 to 2.7 Gt in 2007.

According to Point Carbon's Carbon Market Survey 2008 entitled "Carbon 2008: Post-2012 is now", the CDM (Clean Development Mechanism) market increased to 947 Mt and €12bn in 2007. This is an increase of 68 percent in volume terms, and a staggering 200 percent in value terms from 2006, constituting 35 percent of the physical market and 29 percent of the financial market.

The market for secondary trading of CDM credits is the fastest growing segment. From limited activity at the start of the year, over 2007 the market saw around 300 Mt of

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sCER (Certified Emission Reductions) trades, much of this related to EUA-sCER swaps.

Huge evolution in the carbon finance are anticipated in the years coming, leading to new post2012 agreements due to be reached in Copenhagen 2009. Therefore, any accurate analysis and selling strategy for a particular project needs a more detailed study.

The work performed under the EATTA study corresponds to the pre-feasibility of the CDM qualification.

The client may choose to register his project and the emission reductions as CER (Certified Emissions Reductions of the CDM) or VER (Verified Emissions Reductions). Additional step after documentation completion is to choose who to sign an ERPA with (Emission Reduction Purchase Agreement), either one of the major carbon buyers or on the different niches of the voluntary market13.

6.3.3 CERs Valorisation of the EATTA projects The selling price of the emission reductions will depend on each mini hydro project intrinsic characteristics and the selling strategy.

Projects with high social and development impact, can be labeled as Gold Standard CER or VER and carry a premium price (up to ~20 euros)

Given the positive local impacts on electrification and poverty reduction, the project may qualify under a label, benefiting then from a premium price. Labels for Clean Development Mechanism (CDM) projects are : Gold Standard (GS for VER and CER); Voluntary Carbon Standard 2007 (VCS 2007) ; VER+ ; Voluntary Offset Standard (VOS) ; Chicago Climate Exchange (CCX)

A comparison of the different standards is available in "Making Sense of the Voluntary Carbon Market - A Comparison of Carbon Offset Standards". The study has been written by Anja Kollmuss and Clifford Polycarp from the Stockholm Environment Institute and Helge Zink from Tricorona. The report and the executive summary can be downloaded from SEI-US’s website: http://www.sei-us.org/offset_standard_report.html

6.3.4 VER market Huge evolution are anticipated on the VER market as different code of best practices are reflecting the buyer’s need, such as DEFRA14 or ADEME. More and more carbon buyer’s are asking for CDM projects with a label (mostly Gold Standard) to ensure transparency.

Indeed, according to the Point Carbon 2008 survey, voluntary market is small and non-transparent. Only 10 percent of the respondents consider the voluntary market to be transparent, yet 50 percent think it is more mature now than one year ago.

13 Buyers may be MDG Carbon Facility, World Bank Funds, Action Carbone, Atmosfair, My Climate, Eco-Securities, AHL Carbono ; Mitsubishi Securities… 14 The Code initially covers only Certified Emissions Reductions (CERs), that are compliant with the Kyoto Protocol. See http://www.defra.gov.uk/environment/climatechange/uk/carbonoffset/codeofpractice.htm

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Differences between the Gold Standard for CDM projects and the Gold Standard for voluntary offsets („Gold Standard VER“) are listed at:

http://www.cdmgoldstandard.org/uploads/file/differences_GS-CER_VER.pdf

Possibilities to engage the project on the VER market should be studied in a subsequent study once mini hydro plant engineering details and rural electrification plan are available.

6.3.5 Recommendations on next steps Special assistance is usually needed to register a project under the CDM or on the VER market.

Various international donors (such as UNDP and MDG Carbon Facility, World Bank, etc) or private brokers and investors may propose financial assistance.

Gold Standard projects under the Clean Development Mechanism, Joint Implementation and voluntary offset markets are eligible for development assistance and partnership with Carbon Asset Management Sweden AB and the Carbon Asset Management Gold Standard Fund http://www.camgoldstandard.com/application.php

Normally, the carbon buyer only pays for the carbon, once the savings are reality, and measured, meaning year after year. However, in the case of the voluntary buyer (CERs or VERs), who is also focused on the development impact, it is possible to collect advance payments which will enable the implementation of development activities.

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7 FINANCIAL ANALYSIS

The aim of this section is conduct a simulation of what would be the profitability of the project for a Project Developer, with an investment in the 2.8 MW Gura Small Hydro Power project. The simulation therefore assesses what is the profitability for the Project Developer (Return on Equity) on the Gura project, in a real life simulation of taxes and loan values.

It is assumed that the development of Gura would be undertaken via a Build-Own-Operated (BOO) company which will bring the equity required for the development of the project. The set up of this company has still to be fixed.

The section firstly presents the model and the assumptions for running the model. The results are then presented and indicate the project’s profitability ratios, and sensitivity studies are carried to assess the level of risk and uncertainty.

7.1 Decision Criteria The criterion used for assessing the profitability of the Gura SHP is the Return on Equity (ROE): • It is assumed that the income after taxes is distributed as dividend among the equity

investors (provided, of course, that the income is positive). At the end of the period (20 years in the case of this study), the investors will have to settle outstanding liabilities if any. Multiplying the equity paid in by –1 and then adding for each year of 20 years period the equity paid in, the received dividend payment and, at the end of the 20 years period, the difference between the current assets and the current liabilities yields the net income stream of the investor. The rate of return on equity (ROE) is calculated as the IRR of the net income stream.

• It is considered that investors will be paid the residual book value of the fixed assets at the end of the period.

It should be noted that ROE calculation depends on the period of study (20 years in our case). Also, the SHP will still have an economic operating life for a number of years to come and be a profitable asset. It is possible that equity can be resold to other equity investors at a negotiated market price, above the simple residual book value. The earlier the study period ends, the larger the difference between the ROE with and without the residual value is. Only if the study period ends after 15 years or more years is the difference too small to be of importance. As we are in this case (20 years), we have considered a simple residual book value in the model.

With the above conditions, the Return on Equity (ROE) of the investors, in percent, is the value of t for which the Net Present Value (NPV) of the investors equals zero.

∑ +=

Nn

n

tCFNPV

1 )1(

With:

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NPV = Net Present Value of the Investors, CF = Investor cash flows over the project’s lifetime, N = number of years of calculation = project’s lifetime, t = discount rate of the analysis.

The Return on Equity (ROE) will be calculated for the BOO company alone and for the BOO company + the tea factory: in the second case, the savings on the electricity bill for the tea factory (which will shift from diesel electricity to hydro electricity) are considered as a benefit and in the first they are not considered.

For the BOO Company All the benefits of the SHP project come from the sales of power to KPLC. Thus, the cash flows are computed as follows:

ELPPACFn +=

CFn = Investor cash flow in year n PPA = Revenues generated via PPA with KPLC EL = Equity injection and loan reimbursement

(note: PPA, EL are all in year n)

For the BOO Company + the Tea factory The benefits of the SHP project come from the sales of power to KPLC and from the saving resulting the shift from diesel electricity to hydro electricity. Thus, the cash flows are computed as follows:

SELPPACFn ++=

CFn = Investor cash flow in year n PPA = Revenues generated via PPA with KPLC S = Savings for the Tea factory EL = Equity injection and loan reimbursement

(note: PPA, EL are all in year n)

7.2 Presentation of the financial model IED runs an in-house developed financial model for project appraisal. This model runs on Excel and covers all financial and fiscal aspects of hydropower plant development.

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Figure 7.1: Structure of Financial Model

CALC

ULA

TIO

NS

Investment costs Tax rates

Insurance rates

Exchange rates

Inflation rates

Energy placement forecast

Financial scheme

(debt vs. equity and grant)

PPA price and duration

Loan / grant characteristics

ANNUAL PROJECT CASH FLOWS :

- Investment costs expenditures

- Working capital req.

- Operating expenditures

- Insurance expenditures

- Financial expenditures

- Tax expenditures

+ Sales receipts

+ Equity / Grant / Debt injections

Contingencies

INT

PUT

S

ANNUAL SHAREHOLDER CASH FLOWS :

- Equity injections

- Retained earnings and taxes

+ Residual value

+ Dividends

Project IRR IRR for investor

The model computes investment costs and revenue forecasts, based on the following inputs:

Macroeconomic Parameters The user can specify the KES/USD exchange rate during the base year, the local rate of inflation from y+1 onward and the foreign rate of inflation from y+1 onward. We have assumed a 2% inflation rate for both currencies. It should be pointed out that between the start and the end of the study, the Consultant has faced significant variation of the KES/USD exchange rate. All cost have been established on basis of January 2008 exchange rate (1 $ = 70 KES).

Time Parameters

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

Investment Costs and Contingencies From chapter 4.9 (Cost Estimate), the investment costs for the Gura SHP are identified. Provisions have been made to include access roads and MV lines in the costing – as sensitivity analyses can easily be run to modify the Investment costs. The engineering services during construction are estimated to be at 10% of the investment costs of the project. The investment costs presented below include contingencies, which are the safety margin that the Bill of Quantities takes into consideration to adjust the unit prices (in order to reflect more accurate investment costs). The E&M costs are based on indicative prices provided by potential suppliers.

Contingencies also include insurance cost related to the construction phase which could be taken by the BOO company:

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• Construction all risk insurance: a typical cost would be 0.5% of the investment value of civil works, electro-mechanical equipment and the MV line at the end of construction. The insurance premium is due at the start of construction.

• Advance loss of profit. This is an insurance against delays of construction and the subsequent later start of commercial operation. A typical cost would be 0.8% of the sales value in the first full year of commercial operation, which would represent for Gura less than 0.2% of the total investment cost. To be paid at the start of construction for one year.

Table 7.1: Synthetic investment costs for Gura ITEMS GURA SHP KESx10^3 US $x10^3 A CONTRACTED / CONSTRUCTION WORKS 515 536 7 365

SUB-TOTAL "1" CIVIL WORKS 346 670 4 952 SUB-TOTAL "2" MAIN ELECTRO-MECHANICAL WORKS 139 901 1 999 SUB-TOTAL "3" ELECTRICAL NETWORK 28 964 414

B. ENGINEERING SERVICES 51 364 734 C. CONTINGENCIES 21 350 305 TOTAL PROJECT COST 588 250 8 404 US$ COST/kW 2 966

Project Development Costs The project development costs cover the remaining studies, the cost of various application/certificates (WRMA application (42,000 KES ~600 $) and WRMA permit (50,000 KES ~700 $), certificate of NEMA (0.1% of project cost ~$ 7,500), ERC License ( ~200,000 KES ~3,000$), cost to establish a Build-Own-Operated (BOO) company (~50,000 $) and the certification from UNFCCC for the CO2 benefits (~$100,000): as a global estimates, we’ll take: $175,000.

Operation and maintenance Costs Operation and Maintenance costs comprise Operation costs of the BOO company, maintenance costs of Gura SHP, O&M costs of the MV line. In the model, they are taken as 2.5% of the investment value per year.

In addition, different insurances could be adopted by the BOO company. • Insurance against damages: a typical cost would be 0.15% per year of the

investment value.

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

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

The above are only baseline assumptions and would have to be adjusted for the actual situation once 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 investment value per year.

Generation, Sales and Sales Price The model assumes that the PPA will fix the sales price per kWh to be paid every year of operation. The value adopted for the PPA in the base case scenario is the PPA tariff

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applied between KenGen and KPLC (2.36 KES/kWh). Usually, this tariff apply for HV power while in our case, this is for MV power. It can be considered that it is a very conservative value and that sensitivity studies will be carried.

Financing Equity is assumed to cover 35% of total investment project costs. There is no Grant component on investment costs in the base case scenario.

A loan has been assumed to finance the investment project costs that are not financed by grant or equity. The loan is in US$. This loan finances the costs associated with the access road, the construction costs of the plant, the MV line and all other project development costs that are not covered by equity or grant. The conditions for the loans are as follows:

- Loan duration and grace period: repayment over 7 years; with a grace period of 1 year (included in the 7 years).

- Commitment fees are assumed to be 0.85% of the loan amount.

- Front-end-fees cover the arranger fee, the provision, the participation commission and the agent fee. They amount to 1% of the loan amount.

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

- Repayments are made every year in equal instalments.

In case of negative cumulated cash flow, the BOO Company will be charged an 8% interest rate on negative cash flow.

Depreciation Investment costs are depreciated, all in straight line.

- Electromechanical equipment, engineering services, and the MV line are depreciated over 20 years

- Civil works are depreciated over 30 years

Tax The tax system in Kenya that is applicable to Mini Hydro Power Plants is as defined in the Energy Act, 2006. The establishment of an appropriate financing and fiscal policy framework for Renewable Energy Technology investments is one of the objectives of the Government. Nevertheless, there is a not yet specific Income tax holiday for Small hydro power projects, or no accelerated depreciation possibility.

In the model, Corporate Tax will be taken at 30%. As sensitivity study, Tax holidays on dividend incomes for 7 years will be carried.

A provision for Licensing fees and Tax to the Local Authorities should be considered. In the model, they will be taken at 1% of annual revenues.

Carbon revenue The tea factories are connected to the national grid. We apply the electricity emission factor of 0.8 tCO2/MWh as substitution of diesel and the electricity emission factor of 0.6396 tCO2/MWh as substitution of the grid electricity; and a price of 14 $ / ton of CO2

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emission reduction. This price is closed to the actual CER market price, and lower than Volontary Emissions Reduction (VER) market price. On the VER market, buyers are willing to pay a higher price as long as the project has positive local benefits in addition to CO2 emission reduction. This is the case for the Gura small hydropower as it will contribute to local employment through the tea factories and also improve (in the long term) the income of small tea growers who will be the ultimate owners of the BOO company. Given these characteristics the BOO should seek for partnership with VER buyers or with consultancy who, in return from the sell of VER will carry out in partnership with the tea factories part of the remaining development activities and other services.

Inflation Inflation have been taken at 2%, both in US$ and in KES. As the revenues are solely in KES, and the investment are in US$ (foreign loan in US$), there is a risk of fluctuating inflation and therefore the PPA tariff should be indexed on the inflation rate.

7.3 Results of the financial analysis The financial analysis has been done:

- for the baseline scenario – i.e. with the hypothesis & assumption described in the previous paragraph,

- for pessimistic scenario – i.e. some of the actual conditions are less favourable than in the baseline scenario ;

- for optimistic scenario – i.e. some of the actual conditions are more favourable than in the baseline scenario.

7.3.1 Baseline scenario Total Cost 8 752 k$ Equity 3 063 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 13.3% Return on Equity for BOO company + 4TFs 14.6%

In the baseline scenario, the cash flow happens to be negative until the end of the repayment period. The minimum cumulated cash flow for the BOO company is around – 700 k$. The pay-back period is about 12 years.

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Figure 7.2: Cash Flow over 10 years

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‐500

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7.3.2 Pessimistic cases Increase of 20% of the project investment cost Total Cost 10 433 k$ Equity 3 652 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 8.1% Return on Equity for BOO company + 4TFs 9.3%

Less attractive financing conditions (40% equity, loan interest 8%, repayment period 5 years): Total Cost 8 752 k$ Equity 3 063 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 11.2% Return on Equity for BOO company + 4TFs 12.4%

Low hydrology in year 2, 3 and 4: Total Cost 8 752 k$ Equity 3 063 k$ Annual Energy produced 17 866 MWh (average year) Annual Energy produced 17 000 MWh (dry year) Return on Equity for BOO company 13.0% Return on Equity for BOO company + 4TFs 14.3%

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One year delay payment on the PPA: Total Cost 8 752 k$ Equity 3 063 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 12.1% Return on Equity for BOO company + 4TFs 13.4%

No CO2 revenues: Total Cost 8 752 k$ Equity 3 063 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 10.3% Return on Equity for BOO company + 4TFs 11.6%

Worst case scenario:

In the worst case scenario, there is an increase of 20% of the project investment cost, no CO2 revenues and one year delay payment on the PPA. Total Cost 10 433 k$ Equity 3 652 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 4.8% Return on Equity for BOO company + 4TFs 5.9%

7.3.3 Optimistic cases Decrease of 20% of the project investment cost Total Cost 7 072 k$ Equity 2 475 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 20.1% Return on Equity for BOO company + 4TFs 21.7%

High hydrology in year 2, 3 and 4: Total Cost 8 752 k$ Equity 3 063 k$ Annual Energy produced 17 866 MWh (average year) Annual Energy produced 19 000 MWh (rainy year) Return on Equity for BOO company 13.7% Return on Equity for BOO company + 4TFs 15.0%

Better CO2 revenues (30$/ton instead of 14 $/ton): Total Cost 8 752 k$ Equity 3 063 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 16.8% Return on Equity for BOO company + 4TFs 18.1%

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More attractive financing conditions (30% equity, loan interest 6%, repayment period 10 years): Total Cost 8 752 k$ Equity 2 626 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 14.5% Return on Equity for BOO company + 4TFs 16.0%

In this scenario, the cash flow happens to be always positive until the end of the repayment period.

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Most optimistic scenario:

In the most optimistic scenario, there is a decrease of 20% of the project investment cost, higher CO2 revenues 30$/tCO2) a more attractive financing package (30% equity, 10 years loans, 6% interest rate).

Total Cost 7 072 k$ Equity 2 121 k$ Annual Energy produced 17 866 MWh (average year) Return on Equity for BOO company 26.6% Return on Equity for BOO company + 4TFs 28.4%

7.3.4 Sensitivity study on the PPA tariff with KPLC The 2.36 KES/kWh used in the baseline scenario is very conservative, as it represents the actual tariff applied between KenGen and KPLC for high voltage power. The Ministry will shortly published special feed-in tariff for renewable energies sources, which where not known at the time of the study. The sensitivity study below illustrate what would be the impact on the Return on Equity for various feed-in tariffs. It should be noted that 5 KES/kWh is closed to the actual feed in tariff for small hydro power

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plants which has been adopted in Uganda, and in that case the RoE would be 21.4% with the other hypothesis of the baseline scenario. Figure 7.3: Return on Equity (RoE) for various PPA tariffs (feed-in tariffs)

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ROE depending on the PPA with KPLC (Ksh / kWh)

7.3.5 Other benefits from the project In addition to an attractive RoE, the tea factories will also have from indirect benefits, including an improved quality of service which will result in less power shortage, and therefore less interruption in the tea processing which a better quality. These benefits are not quantified in the financial analysis but would of importance for the tea factories.

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7.4 Conclusions These results show that in terms of financial returns which the site could yield, we are in an attractive situation in view of the returns which would normally be expected.

The Project is financially viable as returns on equity for BOO Company or BOO Company together with Tea factories are 13.3% and 14.6% respectively, in the baseline scenario. At around 15% return on equity even a private investor could be “just” interested. Furthermore, even in the worst case scenario, the return on equity is still positive and thus, financial risks are perceived to be minimal. The negative cash flow during repayment period entails seeking loans from other sources or negotiating a longer payback period. The attractiveness of the project would further increase if the KPLC tariff increased from the current 2.36 KES/kWh, e.g., at 4 KES/kWh, the return on equity is around 21,4%.

There no significant difference in terms of attractiveness when considering the global return for both the BOO company and the tea factories, or the BOO company alone. This situation results from the little saving on diesel costs actually supported by the four KTDA factories.

In all events, it would seem that the attractiveness of the project would be marginally improved with a more attractive financial package but the impact on the cash flow would be very significant as it would result in a positive cash flow.

The investment cost of 2,966 $/kW could be decreased if the tea factories take the responsibility to do part of the civil work or at least the excavation work.

The RoE would be more significantly improved by getting a good CO2 price. This would be possible on the VER market, as buyers are willing to pay for a higher price if social benefits can be added to the avoiding CO2 emission. Given these characteristics the BOO should seek for partnership with VER buyers or with consultancy who, in return from the sell of VER will carry out in partnership with the tea factories part of the remaining development activities and other services.

On the technical side, the project is technically simple but would require some management skills to operate the resulting power systems. The loss of revenue due to current interruptions in power supply resulting in lower quality tea and the fact that this is less likely to happen once the SHP power plant is in place will be an indirect benefit of the Gura Small Hydro power project, which is not computed in the RoE.

As a conclusion, the four KTDA tea factories should be interested to develop the Gura SHP project, being alone as single developer or in association with a private developer as the required equity is quite high (~3 M$ in the baseline scenario) compare with their actual cumulated assets of 14 M$ for the 4 Tea factories.

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8 ANNEXES