RETA 7329: PROMOTING ACCESS TO RENEWABLE ENERGY IN THE PACIFIC SOLOMON ISLAND COMPONENT Technical Assistance (ADB RETA 7329)

MINI HYDRO PRE-FEASIBILITY STUDIES

Prepared for

Asian Development Bank TA 7329- Promoting Access to Renewable Energy in the Pacific MINI HYDRO PRE-FEASIBILITY STUDIES

Contents

Executive Summary i

1. Introduction 1 1.1 Background 1 1.2 Problems and Objectives 1 1.3 Objectives and Scope of Report 2 1.4 Limitations of the Report 2 1.5 Structure of Report 3 1.6 Project Team 4 1.7 Acknowledgements 4

Part I 5

2. Methodology 6 2.1 Overview 6 2.2 Review of Existing Data and Information 7 2.3 Financial Analysis 8 2.4 Stakeholder Analysis: Unserved Potential Customers 8 2.5 Counterparts, Capacity Building and Training 9 2.6 Data Availability and Data Quality 9

3. Mini Hydropower in Solomon Islands 10 3.1 Definitions 10 3.2 Hydrology and Hydro Resources 10 3.3 Collection of Hydrological Data 12 3.4 Ongoing Data Collection 13 3.5 Project Design 14

4. Implementation and Financing Modalities 21 4.1 The Choices 21 4.2 Independent Power Producer 21 4.3 Enabling Environment 22 4.4 Risk Management in Hydro IPPs 23 4.5 Procurement and Implementation of IPP Projects 26

5. Financial Viability of Mini Hydropower in SI 28 5.1 Analysis of SIEA’s Financial Situation 28 5.2 Fuel Supply Cost at SIEA Outstations 30

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5.3 Supply Cost and Benefits of Hydropower 31 5.4 Carbon Finance 32

Part II 34

6. Identification of Sites 35 6.1 Overview 35 6.2 Consultations and Preliminary Site Selection 36 6.3 Site Specific Investigations and Field Missions 36

7. Auki Malaita 38 7.1 The Auki Power System 38 7.2 Auki Load Forecast 41 7.3 System Expansion Planning Auki 44 7.4 Hydro Options for Malaita Province and Auki 45 7.5 General Description Fiu 47 7.6 Hydrology 48 7.7 System Layout 48 7.8 Variations 50 7.9 Cost Estimates 51 7.10 Financial Analysis 52

8. Lata, Temotu 55 8.1 The Lata Power System 55 8.2 Lata Load Forecast 58 8.3 System Expansion Planning Lata 62 8.4 Hydro Options for Lata 64 8.5 General Description Luembalele 64 8.6 Hydrology 65 8.7 System Layout 66 8.8 Cost Estimates 68 8.9 Financial Analysis 68

9. Ringgi, Noro and Munda, Western Province 71 9.1 The Noro/Munda Power System 71 9.2 Load Forecast 73 9.3 Noro/Munda System Expansion Planning 77 9.4 Hydro Options for Western Province 79 9.5 General Description Vila 80 9.6 Hydrology 82 9.7 System Layout 84 9.8 Variations and Least Cost Option 86

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9.9 Cost Estimates 86 9.10 Financial Analysis 87 9.11 IPP Financial Analysis: Bulk Energy Transfer Price 91

10. Taro 94 10.1 The Taro Power Supply 94 10.2 Load Forecast 95 10.3 Taro System Expansion Planning 98 10.4 Hydro Options for Taro 99 10.5 Hydrology 100 10.6 System Layout 101 10.7 Cost Estimates 104 10.8 Financial Analysis 105

11. Mataniko and Lungga, Honiara 108 11.1 The Honiara Power System 108 11.2 Load Forecast 111 11.3 System Expansion Planning 116 11.4 Hydro Options for Honiara 116 11.5 General Description Mataniko 117 11.6 Hydrology 118 11.7 System Layout 118 11.8 Variations 120 11.9 Cost Estimates 122 11.10 Financial Analysis 123

12. Environmental Aspects 128 12.1 Methodology 128 12.2 Project Description 129 12.3 Local Environment Auki, Malaita Province 129 12.4 Local Environment Taro, Choiseul Province 131 12.5 Local Environment Lata, Temotu Province 133 12.6 Local Environment Ringgi, Western Province 135 12.7 Local Environment Mase River, Western Province 136 12.8 Local Environment Mataniko River, Guadalcanal 138 12.9 Screening of Environmental Impacts 138 12.10 Environmental Management Plan and Monitoring 143 12.11 Conclusion and Recommendations 144

13. Social and Poverty Analysis 145 13.1 Introduction 145

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13.2 Methodology 145 13.3 Stakeholder Analysis 146 13.4 Poverty and social exclusion 147 13.5 Management of Social risks and Vulnerabilities 150 13.6 Social safeguards 151 13.7 Site Specific Findings 153

14. Conclusions and Recommendations 160

Picture Index Picture 3.1: Data Recording Equipment 12 Picture 3.2: Features of SI Rivers 14 Picture 7.1: Auki Power Generation 39 Picture 7.2: Pulalaha Limestone Gorge at Afio 46 Picture 7.3: Fiu River 47 Picture 8.1: Luembelele River, Santa Cruz 65

Table Index Table 2.1: Sites Selected for Pre-Feasibility Studies 6 Table 2.2: Shortlisted Sites and Variants 7 Table 4.1: Risks for a Hydro IPP during Construction 24 Table 4.2: Risks for a Hydro IPP during Operation 25 Table 5.1: Summary of Operational Financial Results for all Stations, ($SBD) 2003-2007 30 Table 5.2: Delivered Diesel Fuiel Cost by Outstation (SBD$/litre, June 2010) 31 Table 6.1: Potential Impact of Hydro Projects on Electrification Rates of Provinces 37 Table 7.1: Generation Assets Auki Power Plant, April 2011 38 Table 7.2: New Domestic Loads Expected in Auki following System Extension 41 Table 7.3: Auki System Load Forecast, Generation Requirements, Fuel Requirements and Generator Scheduling 43 Table 7.4: Potential Loads in Afio 45 Table 7.5: Characteristics Ruala’e Site Auki 46 Table 7.6: Design Variations for Fiu Hydro Site 50 Table 7.7: Design Parameters of Variations 51 Table 7.8: Investment Cost Fiu River Hydropower Scheme 51 Table 7.9: Sensitivity Analysis, Auki 53 Table 8.1: Population, Lata 55 Table 8.2: Generation Assets - Lata Power Pant 56 Table 8.3: New Loads expected in Lata following System Upgarde 59 Table 8.4: Lata System Load Forecast, Generation Requirements, Fuel Requirements, and Generator Scheduling 61

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Table 8.5: Distribution Cost Summary Option B 63 Table 8.6: General Information - Luembelele Hydro Plant 67 Table 8.7: Variations 67 Table 8.8: Cost Estimates 107 kW Hydro Scheme 68 Table 8.9: Sensitivity Analysis 70 Table 9.1: Industrial Demand Growth Noro by end of 2011 74 Table 9.2: Ringgi System Load Forecast (Varian A), Generation Requirements, Fuel Requirements and Backup Generator Scheduling 75 Table 9.3: Ringgi Noro Munda System Load Forecast (Variant B), Generation Requirements, Fueld Requirements and Backup Generator Scheduling 76 Table 9.4: Options for Ringgi, Munda and Noro 80 Table 9.5: Location of Intakes and Powerhouses 82 Table 9.6: Catchment Run Off Vila River 83 Table 9.7: Capacity and Energy of Vila Options 84 Table 9.8: Cost Estimates 87 Table 9.9: Sensitivity Analysis, Ringgi (Variant A) 89 Table 9.10: Sensitivity Analysis, Ringgi (Variant B) 91 Table 9.11: Calculation of a Bulk Energy Price (SBD/kWh) that Achieves FIRR=15% 92 Table 9.12: SIEA Analysis, Hydro Energy Purchase from IPP (Ringgi, Variant B) 93 Table 10.1: Installed Generation in Taro 95 Table 10.2: Load Forecast Taro 97 Table 10.3: Calculated Runoff for Sorawe Catchments 100 Table 10.4: Characteristics of Sorawe Alternatives 104 Table 10.5: Cost Estimates Tarp Hydro 105 Table 10.6: Sensitivity Analysis, Taro 107 Table 11.1: Honiara Generator Status May 2011 109 Table 11.2: Honiara System Load Forecast, Generation Requirements, Fuel Requirements, and Backup Generator Scheduling (With Tina) 113 Table 11.3: Honiara System Load Forecast, Generation Requirements, Fuel Requirements, and Backup Generator Scheduling (Without Tina) 114 Table 11.4: Design Variations of Lungga Low Head Scheme 116 Table 11.5: Technical Characteristics of Mataniko Variations 121 Table 11.6: Cost Estimates Mataniko Hydro 121 Table 11.7: Sensitivity Analysis, Mataniko (with Tina) 125 Table 11.8: Sensitivity Analysis, Mataniko (without Tina) 126 Table 12.1: Public Consultations 127 Table 12.2: Environmental Categorisation 143 Table 13.1: Summary Stakeholder Analysis 146 Table 14.1: Summary of Hydro Projects 159

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Figure Index Figure 3.1: Lata Rainfall 25 Years 10 Figure 3.2: Flow Duration Curves Lungga River 11 Figure 3.3: Typical Intake Structure 16 Figure 3.4: Recommended Sand Trap Design 17 Figure 3.5: Headrace Canal Cross Section 17 Figure 3.6: Peak Ground Acceleration 20 Figure 6.1: Location of Sites Considered and Studied 35 Figure 7.1: Auki Load Profile 39 Figure 7.2: Auki Load Forecast 41 Figure 7.3: Auki Capacity Requirements 44 Figure 7.4: Location of Fiu 47 Figure 7.5: Flow Duration Upper Fiu River 48 Figure 7.6: Fiu Branch Profile 48 Figure 7.7: Fiu Hydro Scheme Layout 49 Figure 7.8: Levelized Cost versus Installed Capacity 50 Figure 7.9: Auki Hydro Scenario 52 Figure 7.10: Auki All-Diesel Scenario 52 Figure 7.11: Profit/(Loss) after Tax and Finance Charges, Auki 53 Figure 8.1: Load Profiles, Lata 57 Figure 8.2: Lata Existing 415 V AC LV Distribution Single Line Diagram 57 Figure 8.3: Lata Power System Load Forecast 59 Figure 8.4: Generation Mix Lata with Hydro 60 Figure 8.5: Lata Peak Load, Installed Capcity and Firm Capacity 62 Figure 8.6: Location of Luembelele Hydro Site 65 Figure 8.7: Assumed Flow Duration Curve for Luembelele 66 Figure 8.8: System Layout 66 Figure 8.9: Revenue vs Expenses Lata Hydro 69 Figure 8.10: Revenue vs Expenses Lata All Diesel 69 Figure 8.11: Lata Profit and Loss Diesel and Hydro 70 Figure 9.1: Load Profiles Noro on Two Consecutive Weekdays 71 Figure 9.2: Load Forecasts Variant A and B 74 Figure 9.3: Mase and Vila Hydro Sites 79 Figure 9.4: Rainfall Pattern Ringgi 80 Figure 9.5: Possible Developments on Vila River 81 Figure 9.6: Monthly Rainfall for Ringgi Station 82 Figure 9.7: Rainfall Duration Curve Ringgi 83 Figure 9.8: Flow Duration Curves Vila Catchments 83 Figure 9.9: Exploitable Catchments of Vila River 85 Figure 9.10: Levelized Production Cost as a Function of Installed Capacity 86 Figure 9.11: Revenues vs Operating Expenses Variant A 88

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Figure 9.12: Revenues vs Operating Expenses Variant A All-Diesel 88 Figure 9.13: Profit/Loss Variant A 89 Figure 9.14: Revenues vs Operating Expenses Variant B 90 Figure 9.15: Revenues vs Operating Expenses Variant B All-Diesel 90 Figure 9.16: Profit/Loss Variant B 91 Figure 10.1: Map Taro 94 Figure 10.2: Settlements Around Taro 95 Figure 10.3: Taro Load Forecast 96 Figure 10.4: Taro Generation Mix 96 Figure 10.5: Taro Capcity Requirements (Entire Taro Ward) 98 Figure 10.6: Hydro Options Taro 99 Figure 10.7: Rainfall Taro 100 Figure 10.8: Flow Duration Curve for Lower Catchment 101 Figure 10.9: Flow Duration Curve for Upper Catchment 101 Figure 10.10: Long Profile for Sorawe Lower 102 Figure 10.11: Layout Lower Scheme 102 Figure 10.12: Long Profile Sorawe 103 Figure 10.13: Sorawe Upper Alternatives 104 Figure 10.14: Revenues and Operating Expenses Hydro Taro 106 Figure 10.15: Revenues and Operating Expenses Diesel Taro 106 Figure 10.16: Profit/Loss Hydro and Diesel Taro 107 Figure 11.1: Single Line Diagram SIEA Honiara 110 Figure 11.2: Generation Requirements Honiara 111 Figure 11.3: Generation Mix With and Without Tina 112 Figure 11.4: Location of Lungga and Mataniko Projects 115 Figure 11.5: Flow Duration Curves for two Mataniko Catchments 117 Figure 11.6: Long Profile Mataniko River 118 Figure 11.7: Layout of Mataniko Scheme 119 Figure 11.8: Cost and Energy Production Analysis Mataniko Variations 120 Figure 11.9: Revenue versus Operating Expenses Mataniko with Tina 122 Figure 11.10: Revenue versus Operating Expenses Honiara with Tina 123 Figure 11.11: Profit/Loss SIEA Honiara with Tina 123 Figure 11.12: Revenue versus Operating Expenses Mataniko without Tina 124 Figure 11.13: Revenue versus Operating Expenses Honiara with Tina 124 Figure 11.14: Profit/Loss SIEA Honiara with Tina 124

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Annex 163 Annex 1: Automatic Stations Used on ADB RETA 7329 163 Annex 2 Legal Framework for Rural Electrification 168 Annex 3: Risk Analysis for Hydropower IPP in SI 179 Annex 4 Financial Analysis Profit and Loss 187 Annex 5: Financial Internal Rate of Return 194 Annex 6: Rapid Environmental Assessment Checklists 197 Annex 7: Social Analysis 223 Annex 8 Stakeholder Analysis 237

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GHD Level 8, 180 Lonsdale Street Melbourne Vic 3000

T: 61 3 8687 8000 F: 61 3 8687 8111 E: [email protected]

© GHD 2012 Document Status

Rev Reviewer Approved for Issue Author No. Name Signature Name Signature Date 1 G Zieroth C French A Baker Oct 11

2 G Zieroth L Keam A Baker Feb 12

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Abbreviations and Acronyms

AC Alternate Current ADB Asian Development Bank

ADO Automotive diesel oil ACSR) Aluminium Conductor Steel Reinforced Ah Ampere hours

ASL Above Sea Level AusAID Australian Agency for International Development

AWLR Automatic Water Level Recorder BOO Build Own Operate

BOOT Build Own Operate Transfer BOT Build-Operate-Transfer CA Concession Agreement

CDM Clean Development Mechanism CNO Coconut Oil

CPI Consumer Price Index DC Direct Current DME Direct Micro Expelling (of Coconut oil) also referred to as ‘virgin CNO production’

DSM Demand-side management EIA Environmental Impact Assessment

EIB European Investment Bank EPC Engineer Procure Construct (Contract) EU European Union

ENERCAL New Caledonia Electricity Company FIRR Financial Internal Rate of Return

FOB Freight On Board GIS Geographical Information Systems GSI Government of the Solomon Islands

IC Internal Combustion (engine) IEC International Electrotechnical Commission

IPCC Intergovernmental Panel on Climate Change IPP Independent Power Producer

IUCN International Union for Conservation of Nature KFPL Kolombangara Forest Company, Ringgi kV Kilo Volts (thousands of volts)

kW Kilowatt kWh Kilowatt Hour

kWp Kilowatt Hour peak for PV panels under standard conditions

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MoF Ministry of Finance

MJ Megajoule MLA Multilateral Lending Agency MWh Megawatt hour (1000 kWh)

MMERE Ministry of Mines Energy and Rural Electrification MoA Ministry of Agriculture

MoE Ministry of Environment MoU Memorandum of Understanding NPV Net Present Value

NZAID New Zealand Agency for International Development O&M Operation and Maintenance

PPA Power Purchase Agreement PRIF Pacific Regional Infrastructure Fund PV Photovoltaics

UNELCO Vanuatu Electricity Company RE Renewable energy

SB$ Solomon Island Dollar SICE Solomon Islands Copra Exporters

SIEA Solomon Islands Electricity Authority SIWA Solomon Islands Water Authority SME Small and Medium Scale Enterprise

SPC/SOPAC Pacific Community / Pacific Islands Applied Geoscience Commission ToR Terms of Reference

UNDP United Nations Development Programme UNFCCC United Nations Framework Convention on Climate Change US United States (of America)

US$ United States Dollar VCNO Virgin Coconut Oil

WAAC Weighted Average Cost of Capital WB World Bank Wh Watt hours

For the purposes of this report an exchange rate of 1 SB$ = 0.125 US$ has been used.

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Executive Summary

Background In the Solomon Islands electricity is supplied to less than 20% of the population. Almost all generation is based on imported diesel fuel. Apart from this high dependence on external supply, the country also faces challenges in the development of the energy sector, including maintaining reliability, ensuring commercial viability of the power utility Solomon Islands Electricity Authority (SIEA) and increasing access to modern energy supply. With few exceptions, electrification is confined to Honiara and the provincial centres. Outside of these centres, only about 5% of the rural population has access to electricity through a small number of off-grid and individual household systems. Against this background, the Government of the Solomon Islands through its Ministry of Mines, Energy and Rural Electrification (MMERE) is seeking to reduce both the cost of electricity supply and Solomon Islands’ vulnerability to oil price shocks through an accelerated development of local renewable energy resources. With support from the Asian Development Bank under the initiative ‘RETA 7329: Promoting Access to Renewable Energy in the Pacific’ this report assesses the potential for developing alternative energy sources for electricity generation, in particular small scale hydropower for the outstations of the Solomon Islands Electricity Authority1. This report summarizes the findings of several field missions undertaken by the consultant. The first mission took place from 24 August to 17 September 2010 and included preliminary investigations at sites determined by the Ministry of Mines Energy and Rural Electrification. It included field surveys in Auki, Afio, Taro, Ringi and Lata. A second mission from 25 April to 20 May 2011 allowed the expansion of data collection, installation of river level and rainfall gauging stations and more detailed assessments of the proposed sites together with an analysis of alternative sites such as Mase on New Georgia. It also included the review of two sites on Guadalcanal indicated by the Ministry of Finance in response to a proposal by a prospective private sector developer. Community Consultations Community consultations, focus group workshop discussions and individual discussions were held to explore the attitudes and views of stakeholders towards a) hydropower development in general, b) land and water use acquisition, c) environmental and social impacts, d) potential participation in hydropower development of local communities, and f) the introduction of pre- payment metering systems. Local communities were actively involved in project investigations and the installations of measuring equipment. The results of these consultations and surveys clearly suggested a broad support for the concept of the project, in particular for expanding SIEA’s services into unserved areas. Both connected and prospective SIEA customers have unequivocally welcomed the introduction of pre-payment metering. Hydropower as an Alternative to imported Fuel Most inhabited islands of the Solomon Islands have hydropower potential. Rainfall in higher catchment areas is evenly distributed over the year and the rivers draining catchments have often sufficient slope to allow the development of high or at least medium head schemes with estimated specific investment cost in the range of 2,600 – 3,600 US$ per installed kW for plants in the class 1 – 5 MW. Smaller schemes in the 100 kW class are typically costing around 6,000 – 7,000 US$ per installed kW but can be significantly higher where conditions are unfavourable. These figures do not include land acquisition cost. Factors limiting hydropower development are unfavourable geological conditions (porous limestone formations and thick layers of unstable alluvium) and high flood levels associated with extreme weather events (cyclones). These

1 A separate report provides prefeasibility studies for five coconut oil sites in the Solomons

31/25866 February 12 Page i TA 7329- Promoting Access to Renewable Energy in the Pacific MINI HYDRO PRE-FEASIBILITY STUDIES constraints can, however, be overcome by appropriate designs that avoid dams and tunnelling. Run off river plants with contour canals and steep, short penstock pipes seem to be cost efficient and environmentally friendly as long as minimum flows are maintained in the respective rivers. Another constraint is landowner resistance or unrealistic compensation claims made by landowners. In addition, there is inadequate hydrological data to accurately forecast river run off and energy potential of specific sites. This lack of data has been addressed in this TA through the installation of 5 automatic river gauging and rainfall recording stations. Costs and Benefits of Mini Hydropower Despite the constraints mentioned above, hydropower is considered viable for most of SIEA’s grids. SIEA’s plants in Buala (Santa Isabel) and Malu (Malaita) have already demonstrated that hydropower is a reliable energy source with relatively low operating and maintenance cost. As it requires no fuel input, electricity from hydropower is in most cases less costly than equivalent diesel energy. It also avoids the expense and insecurity of fuel logistics. It is as effective in rural supply areas as it is in urban supply areas, provided that local topological and hydrological conditions (rainfall, catchment area, runoff) are adequate and landowner issues can be resolved. Its capital cost can vary enormously from site to site, depending upon local topological and geological conditions. For the five sites investigated in this prefeasibility study, hydropower has considerable potential to provide access to affordable, renewable electricity to rural areas. In the investigated load centres and perhaps others, hydropower has good potential to turn loss-making rural diesel stations into profitable operations or to create new rural power supply systems that are profitable, either for SIEA or for an independent power producer (IPP). Assuming that the willingness to pay for electricity it is at least equal to the national electricity tariff, hydropower will benefit the rural population by raising the quality of life, widening the opportunities for improved social services, and perhaps stimulating commercial development. The following table summarises the results of our investigations for the five sites that have been selected in close consultation with SIG and SIEA senior management.

Summary of Hydro Projects Load Installed Annual Investment Levellized FIRR Approx Environmental Center kW GWh US$m US$/kWh % US$/kW Category Auki 1,160 9.8 4.2 0,08 35% 3,600 B Lata 107 0.8 2.2 0.20 13% 20,300 B Ringgi A 1,210 10.4 4.4 0.07 45% 3,600 A Ringgi B 4,320 26.3 11.3 0.06 47% 2,700 A Taro 260 2.1 1.7 0.12 18% 6,500 C Honiara 2,740 12,7 7.2 0.08 40% 2,600 A +Tina Honiara 2,740 12,7 7.2 0.08 47% 2,600 A -Tina These preliminary cost estimates have been prepared for the purpose of prioritizing sites for further investigation and must not be used for any other purpose. They are subject to the limitations contained in section 1.4 of this report. While specific investment cost vary considerably, the results show that for projects above 1 MW, total costs (excluding land acquisition) are below US$ 3,000 per kW which results in robust FIRR values in the 40% range and in levelized energy production cost below 10 US cents per kWh. Sensitivity analysis shows that even under pessimistic assumptions the projects turn out to be competitive with diesel generation for which a real increase in fuel cost of 3% p.a. has been assumed. Hydro development use will fundamentally change SIEA’s financial position in the

31/25866 February 12 Page ii TA 7329- Promoting Access to Renewable Energy in the Pacific MINI HYDRO PRE-FEASIBILITY STUDIES centres investigated, in particular if SIEA invests in the projects. The larger projects (above 1 MW also seem to support development as privately financed IPPs with the benefits shared between a developer and SIEA as an off-taker. IPP Development SIEA has expressed an interest in leaving hydropower development to private IPP investors. The main reasons for this position are firstly a reluctance of SIEA to deal with landowner issues that will inevitably arise in conjunction with hydro development and secondly the shortage of investment funds. The IPP development modality can indeed overcome these two obstacles. Landowners could be made shareholders in IPP developments with land acquisition compensation paid as dividends tied to the performance of the projects. However, the IPP modality requires effective and efficient risk management and an enabling framework that is able to balance interests of investors, consumers and the off-taker SIEA. Such a framework or a regulatory authority that could address risk management issues does not yet exist. In case the IPP route is chosen for the hydro projects, it seems prudent to aim at preparing the projects in the public sector (possibly with TA support from donors) and then competitively procure the projects in international tenders. This means that funding needs to be located to perform the feasibility and preliminary design studies for the priority locations. Environmental Screening The ADB’s Rapid Environmental Assessment (REA) checklist for hydropower was used to determine the environmental categorization for each of the sites selected for this pre-feasibility study. The screening and assessment of environmental issues in all project sites identified in this pre-feasibility study demonstrate that the main impacts will stem from road construction and the clearing of forest vegetation on steep terrain for head race canals, penstocks and ancillary structures. While these are highly significant in those project sites on steeper terrain (Auki, Mataniko) ensuring that environmental issues are an integral part of the design criteria can substantially mitigate them. The Environmental Management Plan (EMP) would cover key design considerations related to sound construction and long term serviceability of infrastructure including provisions to mitigate environmental effects during construction such disposal of debris and spoil instep terrain, noise and dust nuisance, and safety. A Monitoring Plan would provide for community feedback, linkage with ongoing water quality monitoring programs and monitoring for compliance with the EMP. The environmental categorisation of each of the project sites is summarised within the report and is based on the summary of impacts in the REA checklists. Ringgi and Mataniko are the only sites where there are significant environmental and public interest issues that require special attention. These sites have been assessed as a category A and a full EIA is recommended as part of the feasibility study work. Social Screening The principal purpose of the project is to improve and extent electricity supply in and around provincial centres throughout Solomon Islands. The project is likely to also reduce poverty of opportunity throughout Solomon Islands by improving the environment for pro-poor growth and social development. Electricity supply can improve access to and the quality of education, health, water supply, sanitation and other basic services, increase social and economic opportunities especially for small businesses and other forms of income-generation, improve living conditions, and reduce the physical and time work-load of women. The project will contribute to the achievement of MDG-related non-income poverty goals in education; infant and child survival; water and sanitation; and gender equity through greater access for women to health, education and other services and livelihood opportunities, progress that is seriously needed, but lacking, in Solomon Islands.

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Full realisation of this potential will not occur automatically, however. In order for it to happen, the enabling environment for inclusive planning, gender equity, community development, small enterprise growth and the like needs to be nurtured through other, supporting development programs, some of which are already being implemented in Solomon Islands by provincial and national governments, NGOs and aid partners. While the project will benefit the whole community and region, access to electricity supply can particularly benefit women through improved living conditions, reduced physical or time burden of some household tasks; new opportunities for small businesses and other forms of income- generation. Indigenous people’s issues are significant in the project. Solomon Islanders have a strong attachment to their ancestral lands. In some parts of the country, land has been alienated from traditional to government ownership but even here landowner concerns must be addressed. Of the proposed sites, four are on customary land and two (Ringgi and Lata) are on alienated land. In Lata, the plant will be on alienated land but transmission lines will cross over customary land. It is critical to the progress and sustainability of the project that landowner aspirations for project benefits are fairly met. Project benefits, need to be included in the final land access and/or acquisition agreement to be negotiated with the landowners through wide-based community consultations. This agreement needs to acknowledge and calculate a value for the landowner’s contribution to the improved electricity supply and the lower cost of generation. Principal responsibility for these negotiations rests with the provincial governments. The poverty alleviation and inclusive development outcomes of the project would be increased if proceeds for resource use can benefit the whole community. An in-perpetuity return to landowning communities, perhaps in the form of a development trust fund, could enhance both community ownership and participation in the project and provide a fair distribution of returns to all of the community by gender and age. Priority Projects This Report is subject to, and must be read in conjunction with, the limitations set out in section 1.4 and the assumptions and qualifications contained throughout the Report From the consultant’s perspective, there is a clear merit order for the projects. The highest priority should be given to the Ringgi project. It is not only the best performer in terms of FIRR, it also has the highest quantitative impact in terms of kWh supplied. An additional advantage is the absence of landowner issues, as the forest company owns the land where the hydropower plant would be installed. It is recommended to focus on a variant that would not only supply the demand of Ringgi, but also the demand of the demand centres Noro and Munda. SIEA will have to restructure its power supply to these centres anyway and instead of building a new diesel power plant, Noro and Munda could be supplied from Ringgi with diesel back-up provided by the 3 MW of diesel capacity installed at the Soltai fish processing company in Noro. An additional advantage of the Ringgi project is that the forest company has already all equipment that would be necessary for the construction of the hydro plants on site. I.e. mobilization cost would be low in comparison with other projects. This project has been classified as a category A project due to environmental concerns related to the High Conservation Value Forests within the Vila River catchment including the riparian buffer zones. Whilst KFPL have indicated that the project would not compromise their environmental objectives, a full EIA would be required. The Mataniko project shows equally high FIRR values, in particular under the assumption that the Tina river project will not go ahead. Developing this project will, however, have to include resolving some critical land acquisition issues as compensation demands for the installation of a simple automatic gauging station were already quite substantial. A waterfall used as a tourist site will be impacted and detailed environmental investigations would be required for this site. The Fiu River hydro scheme on Malaita has the potential to provide low cost electricity for the provincial capital Auki including surrounding areas. At 35% the FIRR is still significantly above the Weighted Average Costs of Capital and the project should also be considered as a priority.

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The smaller projects Lata and Taro show significantly higher specific investment cost and while still viable under standard assumptions taken, they may require some donor support to materialize.

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1. Introduction

1.1 Background In the Solomon Islands electricity is provided to less than 20 % of the population and almost all generation is based on imported diesel fuel. The country also faces considerable challenges in the development of the energy sector, including maintaining a reliability of energy supply, ensuring commercial viability of the power utility SIEA, increasing access and improving energy security by reducing dependence on imported fossil fuels. The poor performance of the power industry also presents a major constraint to private sector development and economic growth. Rural electrification coverage in the Solomon Islands is particularly limited. With few exceptions, electrification is confined to Honiara and the provincial centres. Outside of these centres, only about 5% of the rural population has access to electricity through a small number of off-grid and individual household systems. To develop the economic potential of villages and to provide social infrastructure to rural populations, greater emphasis on rural electrification is needed. However, a scaling-up of rural electrification services through expansion of existing grids and stand-alone systems is a substantial challenge. Though lack of funding is perhaps the dominant constraint, weaknesses in policy, legislation, regulation and the lack of feasible models that would allow the development of local, renewable energy resources also play their part in limiting the rate at which access to electricity services is improved for rural communities. Against this background the Government of the Solomon Islands through its Ministry of Mines, Energy and Rural Electrification (MMERE) is seeking to reduce both the cost of electricity supply and Solomon Islands’ vulnerability to oil price shocks through an accelerated development of local renewable energy resources including hydropower and coconut based biofuels. Opportunities to develop hydropower in the Solomon Islands have been investigated since the 60s, but despite a promising potential no larger development has taken place in the country. While other Pacific island nations such as Fiji, PNG, Samoa and Vanuatu have been able to exploit hydro resources; project development in the Solomon Islands could not overcome serious challenges related to land and water right acquisition and difficult geological conditions. The current Government of the Solomon Islands (GSI) recognises, however, that hydropower remains an attractive alternative to diesel imports that have been burdening the economy and undermine energy security of a country characterized by a very high vulnerability to external shocks. While the development of the medium size Tina river project is currently under way for the Honiara system, smaller sites in the outer islands may also represent an opportunity to develop hydropower as a reliable and environmentally friendly alternative to diesel. Serious challenges, remain. Questions that need to be addressed and answered include (i) how to overcome resistance of local landowners and ensure their support for projects through participative approaches and fair distribution of project benefits; (ii) how to arrive at project designs that allow for difficult geological conditions, (iii) how to reduce planning and project preparation costs to levels that do not render selected projects unviable, (iv) how to implement and finance projects in a way that reconciles sometimes conflicting interests of GSI, SIEA, consumers and potential private sector participants.

1.2 Problems and Objectives The overall objective of Asian Development Bank (ADB) ‘RETA 7329: Promoting Access to Renewable Energy in the Pacific’ is to support the development of alternative energy generation in the Solomon Islands including Coconut Oil (CNO) and hydropower. This prefeasibility study report considers alternative energy sources for electricity generation through mini hydropower. The use of these resources is expected to improve reliability and financial viability of energy supply, allowing expansion of electrification services to un-served communities. At the same time, hydropower development is expected to increase income generation that would stimulate

31/25866 February 12 Page 1 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro– PRE-FEASIBILITY STUDIES local cash economies and render the uptake of electricity supply more affordable for the local communities. The ADB RETA seeks to take a new look at small scale hydropower development that aims to use innovative and inclusive approaches allowing stakeholders in both the public and private sectors to participate in project identification and preparation from the beginning of the project cycle. The analysis presented in this report includes a project pipeline for five individual sites at pre-feasibility level, of which the Mataniko site would feed into the Honiara grid, two sites would feed into existing SIEA outstations, one into an existing diesel system operated by a commercial forest operation. For two sites new rural electrification grids would have to be established.

1.3 Objectives and Scope of Report The objective of this report is to present pre-feasibility studies for five shortlisted selected mini hydropower sites in Solomon Islands to assist with the identification and prioritization of sites for further investigation. The pre-feasibility studies for each site are presented in Part II of this report and include preliminary engineering and financial analysis of sites, plus initial social and environmental screening to assist with the prioritization process. The assessment and analysis is based on available documentation and hydrological data provided by SIEA, initial site inspections, on-site surveys, broad stakeholder and community consultations, and preliminary analysis of electricity demand in the potential project areas at the time. Limited hydrological data for the schemes is available and automatic gauging stations have been installed under this ADB RETA to adderss this issue. The analyses, conclusisions and recommendations presented in this Report should be revised once more accurate and site specific hydrological data is available for the shortlisted schemes.

1.4 Limitations of the Report This Mini Hydro Prefeasibility Study (“Report”) has been prepared by GHD Pty Ltd (“GHD”) for ADB and this report: 1. may only be used and relied on by ADB, SIEA and MMERE 2. must not be copied to, used by, or relied on by any person other than ADB, SIEA and MMERE without the prior written consent of GHD; GHD and its servants, employees and officers otherwise expressly disclaim responsibility to any person other than ADB, SIEA and MMERE arising from or in connection with this Report. To the maximum extent permitted by law, all implied warranties and conditions in relation to the services provided by GHD and the Report are excluded unless they are expressly stated to apply in this Report. The services undertaken by GHD in connection with preparing this Report were limited to those specifically detailed in Section 1.3 of this Report. The opinions, conclusions and any recommendations in this Report are based on assumptions made by GHD when undertaking services and preparing the Report, as detailed in the Report. GHD expressly disclaims responsibility for any error in, or omission from, this Report arising from or in connection with any of the Assumptions being incorrect. GHD has prepared this Report on the basis of Information obtained from Solomon Islands Electricity Authority (SIEA) and unless specified, GHD has not independently verified or checked (“Unverified Information”) beyond the agreed scope of work. GHD expressly disclaims responsibility in connection with the Unverified Information, including (but not limited to) errors in, omissions from, the Report, which were caused or contributed to by errors in, or omissions from, the Unverified Information.

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GHD has prepared the preliminary cost estimates for the five shortlisted hydropower schemes as set out in sections 7 to 11 of this Report (“Cost Estimates”) using information reasonably available to the GHD employee(s) who prepared this Report; and based on assumptions and judgments made by GHD. The Cost Estimates are drawn from RETScreen42 and unit rates for construction projects provided by SIEA. The Cost Estimates have been prepared for the purpose of prioritizing sites for further investigation and must not be used for any other purpose. The Cost Estimates are a preliminary estimate only. Actual prices, costs and other variables may be different to those used to prepare the Cost Estimates and may change. GHD does not represent, warrant or guarantee that the projects can or will be undertaken at a cost which is the same or less than the Cost Estimates. Further detailed investigations, including geotechnical and hydrological investigations, would be required to firm up the cost estimates for budget setting purposes. Subject to the paragraphs in this section of the Report, the opinions, conclusions and any recommendations in this Report are based on conditions encountered and information reviewed at the time of preparation and may be relied on until 31st April 2012, after which time, GHD expressly disclaims responsibility for any error in, or omission from, this Report arising from or in connection with those opinions, conclusions and any recommendations.

1.5 Structure of Report This Report summarizes issues, options and constraints related to the development of hydropower at five potential sites in the Solomon Islands at prefeasibility level. The sites are Lata, Temotu Province, Auki and Afio, Malaita Province, Ringi Western Province, Taro Choiseul Province and Mataniko on Guadalcanal. The report contains two parts, Part I covers general information on Hydrology resources and hydropower technology and Part II covers the site investigations.

Part I Section 2 briefly outlines the methodology used for consultation and analysis. Section 3 contains a resource and assessment, starting with a review of SI’s hydropower resources followed by a description of the situation found in the provinces where detailed investigations were undertaken. Section 4 assesses recent experiences with mini hydro project development in the Solomon Islands and other developing countries. The section also presents a brief introduction into mini hydropower technology. Section 5 addresses the issues associated with the competitiveness mini hydropower versus conventional diesel fuel. It starts with an assessment of SIEA’s financial situation in order to determine if the utility has room to subsidize a renewable power source. Typical supply costs for hydropower are compared with other renewable energy sources available in the Solomon Islands. The section also analyses non-financial benefits of mini hydropower and tests if and under which market conditions the sale of emission reduction certificates (carbon finance) could create an additional revenue streams that would be able to enhance the attractiveness of mini hydropower development in the Solomon Islands.

2 http://www.retscreen.net/ RETScreen is a Canadian based decision support and costing tool, used worldwide, to evaluate the energy production, costs, emission reductions, financial viability and risk for various renewable technologies including hydropower projects

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Part II Sections 6 to 11 present the results of a detailed pre-feasibility analysis for six sites (within Lata, Auki, Ringi, Taro and Honiara) selected in close consultation with the Ministry of Mines and Energy and SIEA senior management. For each site, the current power systems are analyzed and possibilities are explored on how to expand electricity supply in order to improve access to electricity generated from renewable energies. In the absence of detailed expansion planning for the SIEA’s outstations, for each potential site a load forecast has been developed together with system expansion planning that would ensures demand is met. The sections end with a financial analysis for each site where profits and losses and FIRR are calculated for potential investments in hydropower. Sections 12 and Section 13 present an analysis of environmental and social impacts of hydropower development and operation. Section 14 summarizes findings and outlines recommendations on how to approach mini hydropower development in the Solomon Islands. It also describes strategies and actions required to overcome issues and constraints which have hampered hydropower development in the past.

1.6 Project Team The GHD study team consisted of Gerhard Zieroth (Rural Electrification Specialist and Team Leader), Chris Cheatham (Economist), Arne Anderson (International Hydro Specialist), Margaret Chung (Social SafeguardsSpecialist), Rene Weterings (Environmental Safeguards Specialist), Nixon Silas (National Hydro Specialist) and Fred Conning/Francis Kapini (Power Systems Engineer). GSI staff of the Ministry of Mines Energy and Rural Electrification actively participated in site surveys and installation of measuring equipment included. SIEA staff actively working on the project included Martin Sam (Deputy GM), John Kofela (Manager Outstations) and Robinson Wood (GIS Manager) Abraham (Surveyor).

1.7 Acknowledgements The consultant’s team conducted Field investigations and stakeholder consultations for this study in April/May 2011. During the field investigations data was collected, including a number of relevant reports, legal documents such as Power Purchase Agreements and project proposals, which supported the analytical work required under the assignment. The consultant’s team gratefully acknowledges the assistance provided by GSI, SIEA, donor agencies and some private sector parties to obtain these data and information. The Provincial Governments their Premiers, Provincial Ministers, and Heads of Agricultural and Forestry Departments also warmly received the consultants. The local support by SIEA’s Officers in Charge for the outstations visited is especially acknowledged. Special thanks are due to Chief David Mandua of Anatollo, who assisted the ADB study team in installing a gauging station at the Fiu river and provided much appreciated food during an exhausting day in the mountains.

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Part I

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2. Methodology

2.1 Overview The consultant’s ToR initially required the study of five sites suitable for small-scale hydropower development in the outer islands of the Solomons, based on a hydropower master plan study carried out with support from JICA in 1999. In the inception phase of the project the Permanent Secretary of the Ministry of Mines Energy and Rural Electrification and the Director of Energy indicated that GSI’s priorities would be: Auki (Rualae river), Taro, Afio, Lata and Ringii. In response to a proposal of a prospective private sector developer the Ministry of Finance requested the inclusion of two more sites on Guadalcanal, namely Mataniko and Lungga rivers. All nominated sites were subjected to an initial (remote sensing based) screening which included both considerations of technical feasibility and economic viability. Field investigations followed for all sites resulting in preliminary designs and preliminary cost estimates. In a third step the consultant searched for alternatives for sites where field investigations showed that the initial priority sites nominated by GSI would not result in competitive development. The long list of projects and the selected five sites to be investigated at pre-feasibility level as shown in Table 2.1 below.

Table 2.1: Sites Selected for Pre-Feasibility Studies

Load Center River Potential Remark kW

Auki/Malaita Rualele 180 Excluded due to small size and difficult hydrology (spring), studied by Hydro Tasmania of Mines, Energy Energy of Mines,

Afio/Malaita Pualalaha 15 Excluded due to insignificant size and difficult geology (limestone)

Lata/Temutu Luembalele 107 Included in shortlist

Ringgi/Noro Vila 4,320 Included in shortlist

Suggeted By Ministry Ministry By Suggeted and Rural Electrification Taro/Choiseul Sorave 260 Included in shortlist

Honiara/Guadalc Mataniko 2,740 Included in shortlist anal

Honiara/Guadalc Lungga 10,600 Excluded, technical feasibility in anal doubt due to geotechnical conditions Suggeted By Suggeted of Ministry Finance

Noro/Munda Mase/New 3,400 Included in gauging program as a Gerogia fall back site in case Ringgi is not feasible

Auki/Malaita Fiu 1,160 Included in shortlist Suggetsed by Suggetsed Consultant

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As explained in more detail later in the report, the sites Afio (Pulalaha river) and the Lungga river site in Honiara have been excluded as the consultant does not consider them feasible options. Afio is only a 15 kW scheme that had to be built for a very small demand but would incur very high specific cost due to a porous lime stone formation. The Rualae river site in Auki was also excluded as the Rualae site has in the meantime been investigated under a different project3. As SIEA and GSI have indicated that hydro development for the Noro/Munda network would be a priority, an additional site has been identified on the Mase River on New Georgia. This site could be developed if the Vila River site on Kolombangara Island cannot be developed for environmental or other reasons. The remaining five sites for which the pre-feasibility studies are conducted are considered optimal investments for the respective load centers. For both the Mataniko and Vila Rivers, two variants have been analysed. Vila/Ringgi A refers to a version where only the demand of the island of Kolombangara is served. Vila/Ringgi B is a larger investment where the load centers of Munda and Noro are also supplied from this site. For the Mataniko site in Honiara two variants of financial performance have been analysed: A version which assumes that the Tina hydro projects goes ahead as planned and a version where the Mataniko project could operate at a higher capacity factor due to the lack of contribution frm Tina. Table 2.2 summarizes the selected sites.

Table 2.2: Shortlisted Sites and Variants

Load River Installed kW Annual GWh Investment FIRR Distance to Center US$m Load kM

Auki Fiu 1,160 9.8 4.2 35% 9.6

Lata Luembalele 107 0.8 2.2 13% 11.2

Ringgi A Vila 1,210 10.4 4.4 45% 1.5

Ringgi B Vila 4,320 26.3 11.3 47% 22

Taro Sorave 260 2.1 1.7 18% 8.5

Honiara Mataniko 2,740 12,7 7.2 40% 4.0 +Tina

Honiara Mataniko 2,740 12,7 7.2 47% 4.0 -Tina

2.2 Review of Existing Data and Information Traceable studies of hydropower resources in the Solomon Islands date back to the 60s when Sir William Harcrow investigated sites on Gudalcanal and elsewhere. Since these first studies more than 40 resources assessments, pre-feasibility and feasibility studies have been undertaken. The consultant has reviewed accessible documents in particular more recent work performed by the Japan International Cooperation Agency (JICA), Masterplan study of Power Development in Solomon Islands, August. Solomon Islands Electricity Authority (SIEA) 2000, and the work performed under the assistance of the German Technical Assistance (GTZ) and

3 Hydro Tasmania investigated the site under a SPREP funded project

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Ministry of Energy joint programme: “Improvement of rural electricity supplies in the Solomon Islands”, 1985 – 1996. The later program is one of the few initiatives that resulted in investment and the construction of the Buala mini hydro scheme that feeds the SIEA grid on Santa Isabel. The consultant has also reviewed more than 2,000 pages of documentation on the Lungga hydropower scheme provided by the ADB as well as recent studies performed by Hydro Tasmania on Malaita (Rualae River) and Kira Kira (Huro River)4. The quality and depth of studies varies and it appears that there is no common understanding where the boundaries between pre-feasibility and feasibility studies lie. In general some common findings of most studies emerge: While Solomon Islands have favourable rainfall conditions above 3,000 mm of rain per year in most higher catchments and a topography favourable for medium to high head hydro schemes, there are some factors that militate against the development of these renewable energy sources: Firstly, there are geological or geotechnical constraints. Most rivers flow through porous limestone formations that render the construction of reservoirs difficult and sometimes impossible. Sinkholes are common and volcanic formations overlaying limestone form ideal conditions for the building of caves and caverns not conducive to cost effective development of hydropower. Then there is a mismatch of resource and demand. While hydro resources have been identified on practically all of the larger islands, many sites are either too remote to supply an existing demand (at reasonable cost) or are simply inaccessible due to difficult terrain and lack of a road network. A third obstacle has been described repeatedly in relevant reports: Intentions to develop hydro power often meet considerable resistance or unrealistic compensation claims from traditional land owners who have not only stopped project development but in the case of the SIEA operated Malu scheme on Malaita have even stopped the operation of an installed power plant.

2.3 Financial Analysis A financial analysis was then developed on the basis of available SIEA data (billing data, station logs, and relevant financial statements). Due to data inconsistencies and gaps, assumptions and corrections were made in order to develop a plausible financial scenario for the projects. Future hydropower production and supply cost, the most critical parameter determining financial viability of hydropower has been analysed against the background of world market commodity price developments adjusted for local fuel supply cost at the five locations in question. The outcome of the financial analysis shows the impact of these projects on SIEA’s financial performance in the outstations. Profit and Looss calculations indicate if the projects can improve the financial performance of the systems. In addition the Financial Internal Rate of Return (FIRR) were calculated for the projects based on avoided cost for diesel fuel. This allows to rank project according to their merit order. Assuming that financial resources to be allocated to the development of mini hydropower in SI will be limited, such a ranking will allow GSI and its development partners to prioritize projects in order to ensure optimum allocative efficiency.

2.4 Stakeholder Analysis: Unserved Potential Customers For both Lata and Auki sample surveys of unserved customers in low-income clusters were carried out. The objective of these surveys was to assess current energy use and expenditure for kerosene, and determine unserved households’ willingness to connect and ability to pay for electricity. Annex 10 displays the result of these surveys. The results suggest i) an overwhelming support for the provision of access to electricity, ii) relatively high average expenditures for kerosene of up to SB$ 240 per household per month, iii) an expressed willingness and ability to pay for electricity and iv) a willingness to actively support electrification through labour, materials and permissions for easements.

4 The material provided by ADB on the Lungga project is mainly administrative in nature

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Current monthly energy expenditures are mostly for lighting kerosene. Some households also use dry cell batteries and occasionally, families own small petrol generators. The lower energy expenditure in the Lata cluster is probably due to lower income levels compared to Auki, where most families have a stable cash income from fishing activities. The details of these surveys are attached as Annex 8.

2.5 Counterparts, Capacity Building and Training GSI contact points were the Permanent Secretaries for Mines, Energy and Rural Electrification Mr. Luma Darcy and Mr. Benjamin Newyear as well as Mr. John Korinihona, Director of Energy. The SIEA nominated the Chief Engineer, Mr. Dadily Posala, and the Generation Manager and Deputy General Manager, Mr. Martin Sam, as the contact points for the project. The consultant also maintained regular contact with Mr. Norman Nicholls, General Manager SIEA. Mr. Edward Lapongi, Mr. Sam Indu, Mr. Drerek Sonitogha, Jay officers in charge for the SIEA outstations worked with the consultants’ team on field surveys and assessments in their respective stations. In line with the agreement between ADB, GHD, and GSI, the consultants were provided with an office and logistical support by SIEA since April 2010. The consultant provided on the job training for GSI staff in GPS surveying techniques, and discharge measurements using the conductivity method. In addition, the team’s hydro engineer provided training in installation and maintenance of state of the art level gauging using pressure differential method and rain gauging by automatic rain gauging stations.

2.6 Data Availability and Data Quality Lack of reliable and up-to date data and information remain a serious challenge in SI. In May 2011, the 2009 census data have not yet been made available. The lack of up-dated demographic data is a serious constraint when analysing growth trends and developing load and energy demand forecasts. In general, data availability and quality has been very poor at all levels. Hydrological data is sketchy and unreliable as the collection process is often not documented and data is often not plausible. While there is reliable hydrological data including run off modelling, for the Lungga River, there is no such data for the rivers analysed in this study. It was therefore decided to include both rainfall recording and automatic water level recording for the priority sites. Essential SIEA statistics have been analysed for the outer island stations but both generation data and financial records show serious inconsistencies. Records of essential generation parameters such as total engine hours, service histories, and fuel consumption are either not available and if available often not credible; comparisons of generation data and units sold for a particular system shows discrepancies that cannot be explained. Efforts to resolve these anomalies were helped as SIEA’s billing system has been upgraded recently and is now able to produce analytical reports. GHD attempted to analyse original power station log sheets in order to establish daily load curves and load development trends. Unfortunately practically all the log sheets are incomplete, typically missing up to 10 hours of data entries in a 24-hour period (loads, voltage, Amps, frequency, kWh etc). The consultant has raised these issues with SIEA senior management and it is expected that over the lifetime of this project, data availability and quality will further improve and allow the consultant to work with more accurate and reliable data.

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3. Mini Hydropower in Solomon Islands

In the following section 3, the general conditions for the development of hydropower in SI are discussed in order to avoid repetition in the sections dealing with the five individual projects in Part II of this report.

3.1 Definitions There is an ongoing debate what a definition of mini hydropower should be. Mostly, the boundaries are defined using installed capacities drawing the line between mini and micro hydropower somewhere at 100 kW. For the purpose of this report a system is considered a mini hydropower unit if it operates in the framework of an established or planned formal SIEA supply system where SIEA standards apply and power consumption is metered either conventionally or through pre-paid meters. The range of installed capacities would range between 100 and 5,000 kW. Some clarification is also required with regard to the depth and content of feasibility and pre- feasibility studies for mini hydropower. We consider an analysis at prefeasibility level as a decision making and prioritisation tool involving no detailed hydrological analysis (due to a lack of data) or geotechnical investigations, that would a) determine if a project shows a high probability of being technically doable and b) rank a variety of projects according to their financial and economical merits. A feasibility study in contrast would investigate a mini hydro project in greater depth and may include geotechnical investigations, design work anddetailed costing for major components. Assumptions in the pre-feasiblity analysis would be confirmed during the \feasibility studies. A feasibility study typically includes a design of sufficient detail to allow the international tendering of EPC contracts.

3.2 Hydrology and Hydro Resources Numerous studies and investigations on hydropower in the Solomon Islands carried out since the 60s have concluded that the country is well endowed with hydropower resources with a total resource that exceeds current electricity demand in the country. Consistent and evenly distributed rainfall in the range of 3,000 mm per annum or more in most of SI’s catchments and a topography that is characterised by mountainous terrain lead creates hundreds of river with steep enough gradients to allow harnessing hydropower on most inhabited islands of the group.

Figure 3.1: Lata Rainfall 25 Years

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Figure 3.1 above shows an analysis of rainfall data for Lata, Temotu province. While there is a significant spread between the highest and the lowest rainfall in the 25 year period analysed the mean values show rainfall of 300 mm or more for each month. This is an even rainfall distribution that suggests that high plant factors can be achieved. High rainfall creates another favourable factor for hydropower: most catchments are covered in dense vegetation either in the form of natural rainforests or as fast growing secondary bush in areas where logging or slash and burn agriculture has been practised. The vegetation acts like a buffer, avoiding fast run offs. It also reduces erosion of surfaces, which creates high river sediment loads that are unwanted in hydropower development. The prevailing topography allows most potential sites to be developed as medium or high-pressure schemes, which results in lower specific investment cost than low head schemes.

Flow Duration Curves The basis of hydropower planning is the construction of a flow duration curve for a selected site. The flow duration curves depend mostly on the annual rainfall distribution, the land use (natural undisturbed forests have high infiltration rates, reducing surface runoff and increasing groundwater flow) and the availability of groundwater reservoir capacity. Every site will have its own distinct flow duration curve depending on these factors and the smaller the catchment, the more prominent fluctuations will be. With regard to hydrological modelling, data for the rivers investigated here are either fragmentary or simply not available. The best data available are based on a long term analysis of the flows of the Lungga River (in Guadalcanal) were hydrological measurements and data analysis has been performed over several years in preparation of a hydro project. By scaling for catchment size and adjusting for available rainfall data, the Lungga hydrology can however be used as a proxy for the sites analysed5. This is a common practice at pre-feasibility level and is used for this report. As described below, a data collection program has been initiated under this RETA which will allow the construction of more accurate flow duration curves using discharge and rainfall data collected on the sites in question. This will allow comparison with the proxy curve for each catchment. Figure 3.2 depicts flow duration curves for the Lungga river for the three sites where long-term discharge data is available.

Figure 3.2: Flow Duration Curves Lungga River

0.2

Lungga Gorge 0.18 Lungga Bridge

0.16 Lungga Komarindi

0.14

0.12 ) 2 /s/km 3 0.1

Flow (m 0.08

0.06

0.04

0.02

0 0 10 20 30 40 50 60 70 80 90 100 % of Time Exceeded

5 This approach was also taken in Phase 1 of the Tina Feasibility Analysis.

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Source: Hydrological Report Tina River (HTC 2010)

3.3 Collection of Hydrological Data For the rivers to be investigated at feasibility level, the use of proxy data from a different catchment does not yield an accuracy required for a bankable project. While rainfall data are generally available covering most catchments, discharge and run off data are scanty at best and the quality of existing data is poor. It has therefore been decided to create a database of reliable hydrological data as part of this project. Seven rainfall loggers and seven automatic water level recording units have been procured and installed at various sites in cooperation with staff of the water resource division of MMERE6. While the data generated by these units will only become useful after a recording period of at least a full hydrological year, the prospects of mini hydropower in SI are attractive enough to justify the efforts and cost associated with a measuring program.

Picture 3.1: Data Recording Equipment

Rainfall Logger Fiu Installation Levelogger Villagers assisting gauge installation

When selecting the equipment and approach towards collection of hydrological data, emphasis was put on using cost-effective, simple and robust methods and equipment likely to survive harsh conditions. At the same time it was necessary to operate the data stations automatically with site visiting and data downloading intervals of six to nine months. The solution selected consists of ARG100 automatic rain gauges (featuring dipping measuring generating an electric impulse with two magnets passing each other when tipping), automatic water level recorders that uses differential pressure method by recording water column and atmospheric pressure independently using sol called barologgers. Both rainfall and barologgers are controlled via communications cables and special software. Discharge measurements are performed using the conductivity (salt dilusion) method. Conductivity change in the rivers is measured using a temperature compensated and self- calibrating Hanna HI-8733 conductivity meter. The rational for selecting the methods and equipment described above are provided in Annex 1, which also describes operation of the equipment in detail. During installation of measuring equipment the project team successfully sought participation of local residents. The purpose of the installations was explained together with the impacts hydro development could have for the local areas in question (access to roads and power, employment during construction etc).

6 MMERE’s water division has agreed to operate these stations and has budgeted for regular visits

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The data collected under this program will significantly improve hydrological knowledge in the Solomon Islands, especially for smaller catchments. It will also allow to establish a relation with the Lungga data and the Tina river data currently collected.

3.4 Ongoing Data Collection The data collected by this equipment needs to be downloaded onto a field laptop. Whilst the data logger can store up to 12 month of data, it is recommended that the data is downloaded quarterly during the first 12 months to ensure equipment set up is functioning and that a high quality data set is available for future investigations and analysis. A small field laptop has been procured and the National Hydropower Specialist will undertake two rounds (6 months) of data download as part of his project work. The Water Department of the Ministry of Mines, Energy and Rural Electrification has agreed to take on the data collection and download after this time. It is important to ensure this ongoing data download occurs and the initial investment in the equipment is full utilised, with a quality data set being available for any future feasibility work. Limitations to hydropower development in SI There is however a number of factors present in SI that limit the feasibility of hydropower development and/or lead to high and sometimes prohibitively high investment cost. The first factor is the small size of most of the catchments in question. With upper catchment areas typically around a few square kilometres, sometimes less, the flows in SI’s rivers show significant daily and/or weekly fluctuations despite the buffer effect of vegetation. I.e. design of components such as weirs, dams and spillways have to be designed to accommodate flows that are much higher than mean flows would suggest. Flooding can be extreme during tropical cyclones that occur on a regular basis. A river having a mean flow of 20 m3/s can show discharges of 5,000 m3/s, i.e. a thousand times more than the mean flow during heavy rains associated with the cyclone season. These high flows put pebbles, rocks and even larger boulders into suspension and deposit them downstream in riverbeds. Larger rivers therefore show alluvial deposits of pebbles that are several meters and sometimes up to 30 meters thick. Obviously, these formations are not stable and can render civil engineering costs for dams and other structures that need to be build in riverbeds prohibitive. A second limiting factor is SI’s geology. Most rivers flow through porous limestone formations that render the construction of reservoirs difficult and sometimes impossible. Sinkholes are common (see Picture 3.2) and volcanic formations overlaying limestone form ideal conditions for the building of caves and caverns not conducive to cost effective development of hydropower. While porous limestone is often the reason for significant water losses in reservoirs, the presence of such formations often interrupted by fault lines also makes tunnelling difficult or increases associated cost because of the need to line tunnels. Unfavourable geotechnical conditions brought an end to the Lungga gorge hydro project after more than 10 years of investigations at cost of approx 10 million US$. The soft limestone formations also favour the creation of deep gorges characterized by steep and sometimes vertical walls. This feature militates against the construction of canals at optimum contour levels and may necessitate the construction of bridges or the use of tunnels and pipelines to bring the water to a fore bay.

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Picture 3.2: Features of SI Rivers

Limestone and sinkhole Narrow canyon and fault lines Thick alluvium

Often there is also a mismatch of resource and demand. While hydro resources have been identified on practically all of the larger islands, many sites are either too remote to supply an existing demand (at reasonable cost) or are simply inaccessible due to difficult terrain and lack of a road network. It should be noted in this context, that even the main island of Guadalcanal has no circumferential road and roads from the coast to the interiors are either nonexistent or in extremely poor conditions. This lack of infrastructure including the lack of a transmission system for power increases project costs significantly. In the past intentions to develop hydro power have often met considerable resistance or unrealistic compensation claims from traditional land owners who have not only stopped project development but in the case of the SIEA operated Malu scheme on Malaita have even stopped the operation of an installed power plant. Although, some or all of these constraints are present at most sites, an appropriate technical design together with innovative project development and ownership arrangements can mitigate the presence of obstacles. Avoiding dams, reservoirs and tunnels will help to overcome some of the technical constraints.

3.5 Project Design The projects considered in this study are therefore small run-of-river hydropower projects (less than 5 MW) with minimum technical complexity, as well as minimum social and environmental impact. It should be noted that there is insufficient information on both hydrology and – perhaps more importantly on topography and geotechnical conditions to optimize the design for the individual plants, In line with the objective of the overall project (Improving Access to Renewable Energy) a selection criteria for the projects chosen for the pre-feasibility analysis was maximizing renewable energy penetration in the respective systems. I.e. if a site has the potential to completely meet energy demand, the power plant is sized to meet demand throughout the 20 year planning horizon. Given the nature of run-off river with no storage, this sizing leads to relatively high values for installed capacity. This is necessary to ensure that the hydro plants can actually follow the load curves of the systems they supply. Detailed surveys to undertaken during feasibility study work will allow optimization of the investments for lowest generation cost or highest FIRR.

The social and environmental impacts found typically on conventional reservoir based hydropower projects are avoided. Instead submerged intake sills are proposed, which will allow fish movement past the intake during a large part of the year when the discharge exceeds the installed capacity. Instead of tunnels lined concrete canals are used to transport water from the intake to the top of the penstock.

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These canals follow contour lines on the slopes above the river and end in a forebay. Slope stability and quality assurance during construction are critical when building such canals, which can be a weakness in the system. During plant operation there regular maintenance must be ensured to clear the canals of landslides or flood debris blocking the flow in the canal. The headrace canal including intake, sand trap and forebay delivers water from the river to the top of the penstock starting with the trash rack in the fore bay and ending with the manifold in the power station. The powerhouse building contains the electro-mechanical equipment typically consisting of valves, turbines, controls, governors, generators, transformers and circuit breakers. A tailrace canal discharges the water back into the river immediately downstream of the powerhouse. In addition the projects require access roads to the power station and to the top of the penstock and forebay tank.

Access Roads The access roads would have to be constructed first. It is finished as a permanent road with either laterite surfacing, if good quality laterite is locally available, or if less erosion stable gravel materials have to be used, a double bituminous surface treatment (DBST) surfacing may be the most efficient solution on the sloping stretches. The access road is made primarily to the powerhouse, with a branch leading up to the top of the penstock. The branch roads would be designed with a longitudinal slope of 14% or less and with systematic cross drainage, every 100 - 200 m to reduce erosion and the canal section. The roads are assumed to be single lane roads with meeting bays made at maximum 500 m intervals. For the main road to the powerhouse, the road is assumed to have a 6.0 m crest with 3.6 m of pavement and curves that allow access by large trailers supplying the heavy units. The branch road to the forebay is assumed to have a 5.5 m width crest with 3.0 m pavement. Some of the sites under consideration in this report do have partial access roads that can be improved upon to make them suitable for the requirements of the hydropower plants.

Intake Structures The intakes would be constructed by excavating or blasting a diversion intake canal on the bank of the river, ideally on the outside of a bend, where the river does not carry much sediment and debris. Only light works are constructed across the river such as placing large boulders, anchored together, in the deep mid section of the river to keep a low barrier in place and define the minimum supply water level. Figure 3.3 displays such an arrangement. The recommended technical solution differs from the more traditional concept of a large concrete intake weir across the river, with the advantage to add some head to the scheme. Due to the considerable depth of unstable alluvium at the intake sites the construction of large weirs is however, not recommendable. Such structures also causes settling sediments upstream of the intake and creates a barrier for the movement of migratory fish up the river.

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Figure 3.3: Typical Intake Structure

Sand Trap and Flow Regulator It is recommended to locate the sand traps where the intake canal level is above the flood level of the respective river. Prior to entering the sand trap, the flow is separated in two. The amount required for the power plant plus say 5% enters the sand trap, while any excess passes by the sand trap on the riverside and leaves over a long side spillway. The purpose of the bypass is to divert excess; sediment rich flows during heavy rains (cyclones) from overwhelming the capacity of the sand trap. A flow regulator is located at the outlet to the sand trap. A coarse trash rack, keeping large branches and logs out of the headrace canal may typically be placed at the inlet to the sand trap, making the overflow regulator at the outlet easier to access and maintain. An outlet for washing out the sediments is located at the deepest point of the sand trap. This design only allows the design flow into the sand trap. Figure 3.4 below displays the recommended design for sand traps.

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Figure 3.4: Recommended Sand Trap Design

Headrace Canal The canal would be constructed with an initial roughness around n = 0.011, using steel formwork. The canal is assumed to be cement concrete without reinforcement, requiring that it will be kept moist by always keeping water in the canal. The cross section is rectangular with the width equal to twice the design water depth H and with a 0.015 m freeboard. As roughness will increase over the lifetime, the new and clean canal should have a capacity that is about 35% higher than its design capacity.

Figure 3.5: Headrace Canal Cross Section

The canal is cast by first laying out a bottom layer of stiff concrete that is immediately vibrated and is ready to accommodate formwork for the walls and casting of walls. This technique would allow the total canal cross section to cure together. Following the removal of the formwork after 24 hours and completing final finishing on the concrete surface, water is let into the section to a depth of 1/3 of H to keep the concrete wet, so no shrinkage occurs during the curing period. For the first 2 weeks a 2 m wide strip of geo-textile is put over each wall pulling water up from the canal and keeping the wall wet to avoid shrinkage in the unreinforced concrete.

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Forebay Tank The forebay tank is located at the end of the canal and connects it to the penstock. It is similar to the sand trap at the top of the canal except for the spillway. A small excess flow, at least during heavy rains has to be managed by the spillway as well as the full flow of the canal during sudden shutdown of the power station. This flow has to be safely carried back to the river without endangering the penstock or the power station below. To achieve this, the spillway is typically located 50-200 m before the forebay. Further down the canal towards the forebay, the canal wall height is increased to manage the surge wave without overtopping during a sudden power plant shut down. With this type of hydropower design the main operation risk is related to production stop due to landslides on the steep slope above the cut made for the canal after saturation of the soil during heavy rains. This problem is addressed by constructing cut-off drains further up the slope, which intercept surface flow on the natural stable slope and carries it down to the nearest cross flow structure passing under the canal. In this way the risk of saturation and build up of hydrostatic water pressure in longitudinal cracks in the soil on the slope, resulting in landslides, are significantly reduced.

After the construction of the canal, the road access along the alignment for vehicles is no longer available. Instead a special vehicle is made using the canal walls as rails. It is then used for inspection along the canal, for transporting equipment and materials for repairs and for conveying sediments, to be removed after accumulating between the inner canal wall and the uphill slope, obstructing the flow of water there towards the piped cross drains located every 100 m or so. A large fine trash rack is located in the forebay before the entrance to the penstock with opening width as per the specification of the turbine manufacturer to protect the turbines. The trash rack has an automatic trash rack cleaner starting as soon as the head loss over the trash rack exceeds a given value to prevent clogging.

Penstock The penstock would typically be constructed from steel pipes welded into long sections (as long as possible given any transport constraints), sandblasted and then painted with epoxy paint three times on both inside and outside at the workshop before delivery. Due to limited capacity of the local engineering industry in SI, the penstock pipes would have to be pre-fabricated and shipped in. To reduce transport cost, the penstock pipes could be produced in several diameters (similar to the power poles used by SIEA) with the larger diameter thin-walled pipes placed over the medium size pipes inside and finally the heavy smaller diameter pipes used at the bottom of the penstock placed inside again.

This design also results in an optimum pipe diameter, as the most economical pipe diameter decreases with increasing pressure and wall thickness. Where the slope of the penstock is covered by a significant layer of soil, the penstock is placed in a trench and backfilled, which is less costly than placing the pipe on concrete blocks or steel pole foundations every 10-15 m, which is necessary on exposed rock slopes. Whether buried or on poles, the pipe is fixed on a thrust block wherever there is a change in vertical or horizontal direction. The downstream part pipe then is able to move axially through a joint made for this below each thrust block. The penstock ends in a manifold or bifurcation if there are more than one turbine and where the valves for the turbines are mounted. The penstock can be installed in parallel with the canal construction.

Power House The powerhouse would be small structures as the heads of the schemes are medium to high resulting in compact turbines and generators. Where the powerhouse is located directly on the bank of the river, it is affected by the extreme flood water levels of the river. It might be necessary to locate powerhouses further up the slope at the foot of the penstock slope to avoid flood water levels in the river impacting on the powerhouse. In such a scenario both impulse

31/25866 February 12 Page 18 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro– PRE-FEASIBILITY STUDIES turbines (Pelton or Turgo which have to stay just above the tail water) or reaction turbines (Francis) with long tube below can manage significant tail water variations.

In case of reaction turbines, the tailrace canal ends deep under the powerhouse and the lower edge of the draft tubes would be located just below the minimum water level of the tailrace canal. Preferably, the powerhouses would be located so the rock surface is about the floor level of the turbine hall or above. On top of the narrow tailrace trenches under the turbines, the turbine hall floor is cast with shallow trenches in which the pipes from the penstock manifolds or bifurcations enter under the floor level to the turbines. Where possible, a platform at the floor level is made outside the building in continuation of the turbine hall, where vehicles can deliver or pick up equipment within reach of an overhead crane foreseen in the powerhouse. Circuit breakers, controls, batteries, etc. are typically placed in a room parallel to the turbine hall a level above the penstock manifold/bifurcation and the cut off valves together with control room and office space for the operators. In order to shorten construction schedules, the powerhouse can be constructed in parallel to the canal and penstock.

Electromechanical Equipment The actual type and configuration of turbines would be left to the supplier of electromechanical equipment that would be procured through competitive tenders requesting proposals for turnkey contracts. Suppliers would be requested to develop an efficient package based on a given flow duration curve. In most cases 1 or 2 or turbines are considered appropriate with the smallest able to manage at the minimum flow at a satisfactory efficiency. The equipment is small enough that it can be transported fully factory assembled and typically offloaded and placed directly on the floor by crane.

The hydro schemes typically supply small grids (except for the Mataniko project on Guadalcanal) and have to work in conjunction with diesel sets. This requires a control of the hydro plants output by:

(i) Water level sensors in the sand trap by the intake (determining whether there is more water available for the headrace canal, in which case the flow regulator in the outlet to the canal can be adjusted to a higher flow within the capacity range of the plant) (ii) Water level sensors on both sides of the trash rack in the forebay (controlling the trash rack cleaner and adjusting the turbine control by opening or closing the guide vanes nozzles on impulse turbines to maintain a constant maximum operation water level in the fore bay)

The main power transformers and the station transformer will typically be located outdoors to reduce fire risks from explosions to damage the power station. The connected breakers are located inside the building. A simple SCADA system may be included to remote control the hydro plant from the main SIEA powerhouse. The turnkey contracting, manufacturing and delivery of the electro/mechanical equipment woud probably be the time critical activity, as the other activities do not necessarily require long lead times, unless long access roads and canal alignments are the required.

Transmission Lines Transmission lines of medium voltage (11 or 33 kV) are also needed to evacuate the power generated and feed it to an existing distribution system. In some cases 11 kV aerial bundle conductors (ABC) may be needed as power evacuation has to cross dense rainforests characterized by fast growing vegetation. The 11 kV line evacuating the power from the power station would typically be a double circuit Aluminium Conductor Steel Reinforced (ACSR) conductor. However, where the length exceeds 15-20 km (as in a project considered for New

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Georgia) it may be necessary to increase the voltage to 33 kV, as the losses at 11 kV become prohibitive and it will become impossible to maintain common voltage standards with less than 20% voltage fluctuations. Constructing new lines might be made more economic by increasing the span length from the usual SIEA practice, where the strength of ACSR conductors is typically not fully utilized. Wind loads appears low in Solomons, so span lengths like 150-200 m for single circuit and 100 m for double circuit should be more economic than the present tradition of spans below 100 meters. This would involve tensioning the conductors to the maximum to reduce the sag and putting stay wires everywhere the line changes direction. The size of standard cross arms may also have to be increased. The feasibility and cost effectiveness of this approach would need to be examined on a case by case basis during the feasibility study for a specific site.

Earthquake Design of Small Hydro Projects The main consideration when designing structures to manage earthquake loads is to determine the load or ground accelerations to be accommodated in the design. The safety margins employed also depend on the assumed consequences of an earthquake-induced failure of the structure. The question here is whether a catastrophic event would only impact on the structure itself or also jeopardize the safety of the population of a settlement. In the latter case conservative design requires considering events with a return period of 1,000 to 10,000 years or expressed as 10% probability in 100 or 1,000 years. However, the infrastructure involved in typical small run-of-river hydropower projects without dams or any other infrastructure causing significant risks to the public, belongs to the former category, where design return periods of 500 years (10 % in 50 yrs, the assumed lifetime of the infrastructure) are common. In the Seismic hazard map of SI (refer Figure 3.6) depicting Peak Ground Acceleration in m/s2 with a 10% chance of exceedance in 50 years. Guadalcanal clearly shows the highest risks with most of the projects falling into the 1.6 -2.4 m/s2 categorie. The relevance of this for site specific hydropower designs should be considered if this site proceeds to a feasibility study.

Figure 3.6: Peak Ground Acceleration

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4. Implementation and Financing Modalities

4.1 The Choices Two implementation modalities have been realised for hydropower projects: A) conventional public sector projects often with MLA loans provided to governments and on-lend to power utilities and B) project finance through private sector. A is a well-established modality but would not necessarily be aligned with GSI and SIEA’s interest to attract private sector finance and reduce the burden of managing new projects. For very small schemes outside the SIEA supply areas, there is also the community ownership model that has seen some success in particularly in Malaita province. However, for the purpose of this study these types of projects are not considered, as they were typically grant funded and did not have to overcome the issues involved in financing larger projects. For regular power projects, public sector finance is well understood in SI and there is no need to elaborate on the modality. Typically, larger projects would be financed by multilateral lending agencies with GSI being the lender and guarantor. For the projects considered in this study it would be a financing option that could combine grant and loan finance and would probably result in the lowest financing cost. It would allow private sector participation through EPC and management contracts. Managing the risk associated with hydropower development would mostly be the responsibility of the public sector. For at least one of the projects investigated there is another option: The forest company in Ringi, a joint venture between GSI and a private Taiwanese investor could be financed by the company itself, either with financing support from commercial banks or as balance sheet financing by the private shareholder. SIEA senior management and GSI have expressed a strong interest in exploring alternative financing of hydro projects through BOT/IPP modalities. The involvement of the private sector in the development, ownership and operation of power projects represents a major change from past practice in the Solomon Islands. An appropriate development regime is needed to reconcile potentially divergent interests of the Government, private developers, power purchasers and other interested parties. Neither the Government nor SIEA can expect private investors to risk their money in hydro projects unless profitability and risk offered by such investments match alternative opportunities in SI. The promotion of private financing of power generation projects in SI will require SIEA and the government to take a significant role in the facilitation of such projects. The issues associated with private sector participation in hydropower development are discussed below.

4.2 Independent Power Producer An Independent Power Producer owns one or more facilities that generate electricity that is either sold to a national utility (single buyer model) or in a market or pool where several sellers and buyers clear the market for power on an hourly basis (merchant power producer). A privately financed IPP that includes a transfer of assets after a certain period of time to the utility or the government is referred to as a BOT or BOOT project (Build Own Operate Transfer). In the absence of a power market only the single buyer model, which requires a long term Power Purchase Agreement (PPA) between producer and off-taker, is suitable for SI. In fact SIEA has already signed two PPAs with small-scale producers in Honiara that operate diesel power plants. There is, however, no precedent of a hydro IPP in SI. Even at an international scale hydro IPPs are quite rare compared to IPPs based on thermal generation. The risk profile of hydropower puts it at a considerable disadvantage in competing for scarce project development finance through an IPP modality. Risks must be managed if a project is to be financed and even in the presence of ECA coverage a large portion of debt from civil engineering work is typically unsupported. Hydropower projects therefore normally require

31/25866 February 12 Page 21 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro– PRE-FEASIBILITY STUDIES risk guarantees to cover this unsupported debt. In order for private hydropower projects to become bankable in Solomon Islands it will be necessary to develop a clear understanding of the specific risks, and equally important, develop cost effective ways to allocate and manage these risks. In SI high risk of non-payment and risks related to controversy with landowner add further to an already complex risk profile. The problems typically encountered in the IPP project cycle include incompatible views on tariffs7, long delays, overlapping responsibilities of government departments, foreign exchange risk, unavailability of government guarantees, inability to take security of assets, weak legal framework, etc. Despite these barriers, some countries in the Asia Pacific region, namely Lao PDR, Nepal and the Philippines, have build relevant experience with IPP/BOT hydropower with a number of projects either completed or under construction. While the impetus behind private hydropower in each of these countries has been quite different there are some commonalities with the Solomon Islands that would allow learning from experiences and a variety of valuable lessons.

4.3 Enabling Environment The typical risk profile and the highly site-specific nature, of hydropower schemes pose a number of unique problems that require special consideration in creating an enabling environment for private sector investment. Any sizable IPP investment will have to face a number of constraints in the legal, institutional and commercial fields. Although the present commercial and regulatory environment in SI is not attractive to private sector participation in hydropower, experience in other countries clearly demonstrates that a favourable environment can be created. At present there is uncertainty with regard to applications, approval and licensing process with responsibilities divided amongst central and provincial government authorities with respect to investment licences, environmental approvals, water and land use rights, construction permits, import permits, foreign exchange transactions and other approvals required to implement a IPP project. GSI is aware of constraints to private sector investment and intends to streamline its bureaucratic processes with the intention of expediting and simplifying its investment application and approval regime for both foreign and local investors.

Despite these intentions, private investors have maintained a very cautious approach to power sector investments in SI8. To attract private investors for power projects the GSI will have to maintain macroeconomic stability, further streamline its legal and regulatory framework and adopt project implementation models in line with international best practice standards. Perhaps most importantly, an innovative framework must be established that allows landowners to participate in project development rather than becoming an obstacle to project development. It is expected that the development of the Tina hydro project, which has been set up as an IPP project from the very beginning will make a major contribution to the development of an enabling framework for hydropower IPP in Solomon Islands. However, for the small size of projects under consideration in this report, the use of a Standard Power Purchase Agreement (SPPA) seems to be an effective means to create such a framework. It should be noted that a single agreement would in most cases not be sufficient to cover all issues of hydro IPP. Typically, a number of other legal instruments need to be used as well:

• Legal and regulatory framework. The framework is designed to overcome concerns of foreign investors in connection with issues such as contract enforceability, foreign exchange, sovereign risks and payment risks. Annex 2 provides a description of relevant laws and regulations.

7 An unsolicited hydropower IPP proposal tabled by SMEC in 1999 encountered these problems and went nowhere 8 In recent years several attempts have been made by the World Bank to engage the private sector in SI’s power industry, but so far without success

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• Implementation (or concession) agreement. Arrangements between a project sponsor and government are defined in the implementation agreement, which addresses matters not covered within the legal and regulatory framework. The more attuned the framework is to IPP development models, and the more ‘standard’ the concession conditions of the project, the less there is to say in an implementation agreement.

• Grid code (or connection agreement). The grid code sets out technical standards, responsibilities and other matters relating to the interconnection and dispatch of the facility within the power system. In SI, system standards are defined by SIEA. There is at present no written grid code in SI. However, it would not be difficult to adopt an existing grid code (such the Electricity Council of the United Kingdom “Recommendations for Connection of Private Generating Plant to the Electricity Boards System – Engineering Recommendation G59 of June 1985).

• Shareholders agreement. It is common for larger projects to be sponsored by a consortium of investors and this entails a shareholders’ agreement which sets out the arrangements for control and operation of the consortium. Shareholders’ agreements are not generally needed for small projects, which tend to be developed by a single sponsor. However, in case of traditional landowners participating in projects, such an agreement would become necessary and could become a major instrument to avoid land owner resistance.

• Land lease agreement. Whether the project is small or large, legal title to the use of the project site (land and water) must be obtained. Two factors simplify land issues for smaller projects. Firstly, the land requirements are more modest and rarely involve sensitive social and environmental impacts. Secondly, if the co-sponsor is local, laws are generally less restrictive in the rights of the party to own and use land.

• Engineering, Procurement and Construction. EPC contract(s) must be formed with consultants, contractors and equipment suppliers for the design and construction of a project. For larger projects these contracts involve international firms and international competitive bidding and can be difficult to administer.

• Loan agreements. For larger projects financed on a non-recourse or partial recourse basis, complicated syndicated loan arrangements can become necessary, with inter- creditor agreements between multiple lenders backed by export credit agency and/or multilateral guarantees. Such complexities are largely avoided with small power projects that tend to involve balance sheet financing utilising smaller and locally denominated loans.

• Operation and maintenance contracts. If the sponsor is to contract out the operation and maintenance of the project, it will need to enter into an O&M contract with a suitable operator. Conversely, the need for an O&M contract is avoided if the sponsor intends to operate the facility itself.

4.4 Risk Management in Hydro IPPs In comparison with thermal generation private sector investments hydro IPPs require complex risk management. It is assumed here that risk management follows the accepted risk allocation principle that the party who can manage risk at the lowest cost and in the most effective way should wear a particular risk. The main risks of a hydro IPP project that require a clear allocation and management are depicted in Table 4.1 and Table 4.2 below. Construction and operation phases are distinguished as they involve different sets of risks. Annex 3 provides a more comprehensive risk allocation and management matrix that also includes the consequences of certain risk events for the main stakeholders of an IPP project.

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Table 4.1: Risks for a Hydro IPP during Construction

TYPE OF RISK EVENT RISK MANAGEMENT OPTION • Regulatory Changes • Change-in-law and Extension of Time clauses in Sovereign/ concession agreement, PPA, EPC contract • Government guarantee Political Risk • Political risk insurance or MLA partial risk guarantee (PRG) • Landowner Controversy • Participative approaches • Landowner compensation or landowner shareholding (Also applicable for Operation Phase ) • Expropriation, Nationalization • Government guarantee or Cancellation of Concession • Political risk insurance or MLA partial risk guarantees

• Default, termination and disposal of assets clauses in Project Agreements • Inadequate Contract • Transparent, independent dispute resolution Enforcement procedures • Sound legal, regulatory & institutional framework • Economic Problems, currency • Foreign exchange adjustment formulas in EPC and realignments) PPA contracts • Hedging of EPC costs with financial instruments Completion Risk • Non-Political Force Majeure • Force Majeure clauses in concession, off-take and (e.g. major flood, earthquake, O&M agreements fire) • Insure against insurable non-political Force Majeure events • Unforeseen Conditions • Thorough site investigations and project feasibility studies • Transfer risk to EPC contractors through fixed price & fixed date contracts with liquidated damages • Transfer risk to off-taker through off-take price adjustment and extension of time clauses in PPA • Contractual remedies: Fixed price/date EPC contract and liquidated damages in project contracts • Cost and Time Overrun on • Contingency finance measures: EPC Contract not related to - emergency equity unforeseen conditions - stand-by finance • Contractual remedies: Fixed price/date EPC contract • -Liquidated damages in project contracts • Environmental and Social • Good quality EIA, Action Plans and Management Impacts Plans • Environmental obligations and constraints specified in Concession Agreements

Once completed, hydropower IPP projects face a variety of operating risks. These are displayed in Table 4.2 below.

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Table 4.2: Risks for a Hydro IPP during Operation

TYPE OF EVENT RISK MANAGEMENT OPTION RISK Hydrological • Under-estimation of long term • Quality hydrological analysis using reliable data and Risk mean monthly and annual independent self-checking flows • Adjustment to concession terms to compensate for long term hydrological variances • Minimum payment to guarantee debt service • Variations in flow about the • Optimize design mean • Minimum payment to guarantee debt service • Adjustment to concession terms to compensate for annual hydrological variances • Declining catchment yield • Contractual safeguards on catchment management • Co-operation with landowners Operating • Force Majeure (major flood, • Force Majeure clauses in concession, and off-take Risk earthquake, fire, etc.) agreements. • Insure against insurable non-political Force Majeure events • Interruptions due to operator • Employ an experienced and reputable operator default • Include design safeguards to reduce plant and transmission line outages • Liquidated damages remedies • Lenders step-in–rights in chronic cases • Tariff structure to secure debt service revenues (e.g. “take- or-pay” or capacity-type charge) Market • Reduced demand • Minimum payment mechanism (Take-or-Pay, capacity-type Risk charge) • Conflict over dispatch • A grid code to control system operation and dispatch Commercial • Assurance of adequate debt • Structure project and financing plan to achieve acceptable Risk service coverage Debt Service Coverage Ratio • Maintenance of debt service cash reserve • Insolvency of Project Co. • Default, termination and disposal of assets clauses in Project Agreements • Lenders’ Step-in Rights • Collateral Arrangements • Inability of Off-Taker to make • Government guarantee of Off-Taker obligations payment • MLA partial risk guarantee (PRG) to secure debt service payments Foreign • Availability of foreign • Sovereign guarantee of currency convertibility and foreign Exchange exchange for foreign debt exchange availability Rate Risk service • .MLA partial risk guarantee (PRG) to secure debt service payments • Availability of foreign • Sovereign guarantee of currency convertibility and foreign exchange for repatriation of exchange availability profits • Analysis of economic indicators including ability to generate foreign exchange to match payment obligations • Devaluation of the local • Match PPA payment currencies to financing package currency • Hedging of debt service portion • Maximize local contribution in construction work Environmental • Environmental impact on • Design project as run off river with environmental flow and Social river and surrounding • EIA, Environmental Monitoring Plan and Environmental Risks environment Management Plan to development agency standards • Re-regulation of power station releases. • Variable level intake structures for improved water quality • Social impacts • Landowner participation and ownership • Economic development initiatives in vicinity of project

Reliability of available hydrological data is of major concern to project developers, investors and lenders. This includes the insufficient duration of time series, incorrect readings and extends to the inadequate location of data recording stations. In general, the more reliable the data the

31/25866 February 12 Page 25 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro– PRE-FEASIBILITY STUDIES better the easier it is to assess and take hydrological risk. If data is scarce or unreliable, no investor will bear hydrological risk and this risk will in turn have to be transferred to the power purchaser or the government.

4.5 Procurement and Implementation of IPP Projects In practical terms, besides tariff, risk allocation remains the most prominent commercial issue in IPP hydropower projects. An effective management of these risks described above has significant impacts on the procurement process and associated contractual arrangements. In case one of projects described here is to be implemented as an IPP it is recommended to procure an initial project using a one-stage bidding process. I.e. a tariff is determined in a single round of bidding. All Pre-investment activities would be carried out to MLA standards in the public sector. The government’s consultants will undertake full site investigations, technical studies, and preliminary designs. It is assumed that the project would attract the support of development agencies to provide grants for feasibility studies and bid preparation activities. Solomon Islands currently does not have any local private investors who have the financial and technical expertise necessary to develop a hydropower project to international standards. This is mainly because the private sector is still in its very early stages of development and most infrastructure projects, have to date been developed and owned by the state or state owned enterprises. This means that for hydropower projects, investment would have to be the traditional public sector finance or private equity investment would have to come from experienced and financially sound international developers. If a project is procured within the public sector, there is a standard set of procurement rules that MLA agencies or the government itself applies for the supply of machinery or EPC contracts. Procurement of an IPP project with significant private sector involvement is significantly more complex and the paragraphs below describe the processes and rules to consider.

Project Development Technical design, environmental and social impact studies, environmental and social action plans (including community mobilisation and landowner agreements) and watershed management plans would have to be prepared by the public sector (typically using grants or concessionary loans). With this shift of project investigation and formulation activities into the public sector, the successful bidder and the project’s lenders would be protected to some degree from associated risks by providing contractual relief through a minimum payment clause that secures debt service in case of hydrological or demand short falls. In order to retain the business character of the IPP it is recommend that the investor wear the risk of hydrological shortfalls beyond the debt service period. The payment risk and foreign exchange risk beyond debt service could be covered by guarantees provided by MLA and/or the government. Back-to-back provisions can provide relief from unforeseen conditions during construction in the concession agreement and the EPC contract allowing the investor to claim compensation for cost overruns that occur due to latent conditions through downward adjustment of royalties and taxes. Shifting the risk to the investor would force bidders to make substantial upward price adjustments in order to cover for potential errors in project preparation work outside its control. For investors, the benefits of the One-Stage Model over a directly negotiated transaction include the elimination of protracted negotiations and the freedom to award the engineering, construction and procurement work to anyone it pleases. In turn, the investor has to assume the risk of cost and time overrun of EPC contract or shift this risk to the EPC contractor for all events not classified as unforeseen conditions. Depending on size and type of project it may be appropriate that the operating risk assumed by the investor is partly transferred to a specialized O&M contractor. While the government has to assume the off-taker payment risk in the commercial risk category the investors and lenders have to assume what is left as commercial risk.

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Developers and Lenders At first glance, investment in hydropower in SI may seem to offer higher risks and lower returns in comparison to alternative investments. A PPA project would lock the investor into a long-term contract with a monopoly buyer and involve assets that are essentially immovable. Private investors would typically chose risky projects because they are familiar with the specific sector and confident that they can use this knowledge to their advantage in assessing and managing risk. In the absence of developers with specific private infrastructure or power sector know how in SI we have to assume that in the eyes of an indifferent investor9, hydropower projects will have to compete with a wide range of other industrial projects such as manufacturing, real estate, agriculture etc. The PPA contract on offer would then be appraised against other ventures, many of which could have shorter pay back periods, involve less specific risks and may be manageable with less demanding approval procedures. A developer or investor (such as the SI pension fund) may be motivated by the desire to diversify to invest in an IPP project. Such a project might enhance the risk profile of the overall portfolio. A portfolio of investments, which has a high exposure to exchange rate fluctuations, might reduce its overall financial risk by selecting a project with a high local content of both capital outlay and revenue. Again, the investor will then compare various alternatives that show a similar characteristic and compare, say, the IPP with an investment in real estate or the fisheries sector. On balance, the relation between the return, which accrues from the guaranteed revenue stream of the IPP, and the risks the project and or the investment portfolio are exposed to must be attractive to the developer. Even if the PPA strikes a good balance and allocates the various risks efficiently, the developer might still not have the confidence to deal with the specific risks of a hydropower power project and instead select another investment. Lenders on the other hand have a perspective that is different from the project developer/investor. They have downside risks (they lose their money if the borrower becomes insolvent or breaches its loan agreements) but do not participate in the upside risks (they do not increase their gains if the project is especially profitable). Accordingly, they are normally conservative in their approach to risk. Lenders have, or should have a broader view of capital markets, often manage larger portfolios and typically have experience in assessing specific risks of projects. They will identify the projects assets and take security over them. In order to further mitigate their risk they will look at third parties such as suppliers and contractors and the purchaser to provide additional layers of security. Lenders are aware that a project whose performance depends on various parties fulfilling their obligations is only as strong as its weakest link. If there is a weak party whose creditworthiness is in question, lenders will request guarantees or risk transfers. In SI commercial banks (such as ANZ and Westpac) might be willing to accept risk transfers and accommodate risks that remain uncovered10. Commercial lenders will, however, follow the same principle as developers in seeking the highest return for the lowest possible risk and will try to insulate themselves from as much risk as possible.

One of the most important factors in the success of a private hydro project is the careful selection of eligible developers in a competitive process. Developers of projects must demonstrate to their lenders, in addition to their own financial capacity, that the project is soundly conceived and that the expected financial performance of the plant under the offered tariff is sufficient to reliably meet debt service obligations, operating and maintenance charges, and provide a reasonable return on investment.

9 An investor who just wants to maximise return on his investment at the lowest risk possible 10 ANZ has been involved with the World Bank in an energy sector financing program which has in the meantime been assessed as unsuccessful

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5. Financial Viability of Mini Hydropower in SI

For mini hydropower to be a financially viable alternative for SIEA its development and use has to reduce SIEA’s overall cost. In section 5.1 below we demonstrate that SIEA is currently (and presumably in the foreseeable future) in no position to afford – based on energy security or environmental grounds – an energy source that is more expensive than its conventional alternative. The financial competitiveness of mini hydropower (MHP) as a substitute for diesel fuel in the SIEA outstations depends mainly on the capital cost, while diesel based power supply depends mainly on the delivered cost of fuel. This introduces the need to predict a future price development for petroleum products. As hydropower plants are typically not assets that cab be moved (stranded assets once build), a conservative approach seems to be in order. In other words, hydropower needs to show a robust financial and economic performance in order to justify investments that are risky in nature.

5.1 Analysis of SIEA’s Financial Situation A verified picture of SIEA’s current and recent past financial condition is not available. Critical records, both financial and operational, are missing or are inconsistent with other available records. SIEA’s financial statements for the years ending 31 December 2004, 2005, 2006, and 2007 were audited in 2009, but the Auditor General was unable to issue an opinion on any of the statements, citing a lack of fundamental records needed for verification. These problems are acknowledged by the SIEA Directors who, in their cover report for the Statements of 2005, for example, “note that due to the unavailability of certain records, relevant estimates and assumptions have been made in compiling these financial statements.” The rate of revenue collection in the SIEA system nation-wide is reportedly between 80 and 90 percent of electricity invoices to consumers11, but billing records are incomplete. Under assistance from the World Bank12, the SIEA is undertaking an ambitious effort to install prepayment meters on all consumers (thus reducing and, in time, eliminating the poor collection rate), in parallel with an overhaul of the billing, accounting, and data management systems. These improvements are necessary to enable SIEA to comply with the provisions of the State Owned Enterprises Act of 2007, and they are clearly urgent management priorities for the SIEA. It may be expected that SIEA’s financial picture and prospects will gradually become clearer as the improvements are implemented. In April 2008, the GSI agreed to assume or forgive some SBD 196 million of SIEA’s long term debt and to forgive approximately SBD 8.6 million in SIEA tax arrears, while the SIEA agreed to write off about SBD 62.5 million13 of arrears for government electricity consumption. In aggregate, these steps represent earnest attempts to resolve SIEA’s current financial difficulties and to enable the Authority to restructure itself and start with a new slate. However, the Authority continues to face chronic arrears problems from some large customers, e.g., the Solomon Islands Water Authority.14 On this evidence, it would appear that neither the SIEA nor the GSI are in a position to assume substantial new long-term debt for the foreseeable future.

11 Personal communication, SIEA Chief Engineer, April 2010 12 SISEP, Solomon Islands Sustainable Energy Project 13 SIEA’s 2007 Profit and Loss Statement shows a write-off of SIG arrears of SBD 62.45 million, but the Directors’ Report for that year shows the write off as SBD 32.40 million. The reason for the discrepancy is not known. 14 SIEA, Corporate Plan 2010-2015

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The financial statements that are available from SIEA indicate that the Authority’s operations have incurred heavy financial losses in four of the five years between 2003 and 2007. However, in most of these years it is difficult to put a finger on the proximate causes of the losses, due to the lack of reliable records. The large write-off of GSI arrears in 2008 (applied to the accounts of 2007) are partly responsible for the loss of SBD 37 million in 2007—the worst losses of the period. The SIEA Corporate Plan 2010-2015 states that the regulated tariff is too low to allow full cost recovery, but it would be difficult to verify this claim with the present data. It is possible, for example, that a significant improvement in revenue collections (as would follow from universal prepayment metering) would strengthen the profit and loss position dramatically. SIEA’s financial statements are national in scope and do not show detail by outstation. However, a recent tariff study15 managed to develop such detail for the years 2004, 2005, and (provisionally) 2006. Averages from these years have been applied to the national accounts reported by SIEA for 2003 and 2007. By these means it has been possible to derive a contiguous data set showing the financial operating performance of the SIEA in Honiara and in each of the nine outstations (Lata, Buala, Gizo, Kirakira, Lata, Malu’u, Munda, Noro, and Tulagi) for 2003-2007 inclusive. Considering only sales revenues and direct O&M expenses in each centre (ignoring national corporate overheads, finance costs and exchange rate losses, and bad-debt write-offs), it is seen that, in general, only Honiara and to a lesser extent Lata, Gizo, Munda, and Noro show consistent operating surpluses, which are used in part to cross-subsidise loss-making operations in Buala, Kirakira, Lata, Malu’u, and Tulagi. Honiara overwhelmingly dominates the SIEA national system, accounting for about 80% of total revenues and about 90% of total generation. The chief operational financial results for Honiara and the outstations for 2003-2007 are summarised over the page in Table 5.1.

Tariffs In the financial analysis of this report, no attempt has been made to calculate tariff adjustments that may be possible or necessary in the future to keep SIEA solvent. The analysis is based, rather, on keeping the base tariff constant in real terms throughout the 20-year planning period, while allowing the “energy” or fuel price component of the tariff (set at SBD 0.63/kWh for all consumers in all power centres in March 201016) to rise in concert with the assumed real increase in international fuel prices (in this analysis, 3% per annum). In this connection, it is noted that the fuel price component of the tariff does not fully recover SIEA’s fuel costs in any centre. In Lata, for example, the rate of SBD 0.63/kWh recovers about 20% of fuel costs, whereas in Auki the recovery rate is about 30%. Although data are not available for a full analysis, it is estimated that the recovery of fuel costs system-wide (including Honiara) through the fuel price component does not exceed 50%. An implication of keeping the base tariff constant through time in combination with a fuel component that does not fully recover fuel costs, despite allowing the fuel component to rise in line with international fuel prices, is that financial losses in operations steadily rise as fuel prices rise. (However, as shown below, the introduction of hydropower is capable of reducing financial losses as it displaces diesel fuel).

15 The Ridgway Study (PIEPSAP), 2007 16 It is understood that the fuel price component has been reduced to SBD 0.32/kWh, starting with April 2010 bills. However, as the mechanism used by SIEA for adjusting the fuel component is not well understood, the rate of SBD 0.63/kWh has been retained in this analysis, for 2010.

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In this context, GSI and SIEA may contemplate the revision of the current tariff. Hydropower may allow a lower tariff in stations that have a viable hydropower sites. Once a plant has been built, there is also a strong economic incentive to use its full capacity as short run marginal cost for hydro generation are extremely low (assumed here to be 1 US cent per kWh for maintenance and operation. Quite obviously, the economic benefits of selling hydro energy by far outweigh these cost and one way to realise the benefits from incremental power use is to offer it at an attractive price.

Table 5.1: Summary of Operational Financial Results for all Stations, ($SBD) 2003-2007

Operating Performance by Centre (Centre Sales Revenues vs Centre Generation, Distribution, and Administration Costs)

2003 Honiara Auki Malu'u Buala Noro Gizo Munda Tulagi Kirakira Lata Totals Sales Revenues 52,571,870 2,409,001 87,147 479,165 6,337,936 2,926,504 972,256 265,130 576,159 454,074 67,079,243 Expenditures Generation 30,177,208 1,160,751 74,097 250,980 2,863,371 1,757,917 17,208 475,591 421,831 394,094 37,593,049 Distribution 1,682,203 107,262 10,078 7,216 137,443 86,541 72,053 11,536 14,114 2,085 2,130,532 Administration 602,418 86,334 76,691 75,023 187,620 127,314 53,432 68,539 97,342 91,163 1,465,876 Total Expenditures 32,461,829 1,354,347 160,866 333,219 3,188,435 1,971,772 142,694 555,666 533,288 487,343 41,189,457 Surplus/(Loss) 20,110,042 1,054,655 (73,719) 145,946 3,149,502 954,732 829,562 (290,536) 42,871 (33,269) 25,889,785

2004 Honiara Auki Malu'u Buala Noro Gizo Munda Tulagi Kirakira Lata Totals Sales Revenues 72,861,412 2,081,163 57,419 284,355 8,365,774 2,349,985 903,155 478,387 430,832 471,215 88,283,698 Expenditures Generation 41,955,023 2,318,193 75,377 215,835 6,310,212 2,796,086 40,703 649,280 702,120 684,257 55,747,086 Distribution 2,547,417 194,600 10,166 14,526 241,622 152,095 62,408 10,000 28,849 8,645 3,270,329 Administration 573,248 80,778 77,640 73,784 214,296 101,049 52,797 59,160 104,562 78,145 1,415,456 Total Expenditures 45,075,688 2,593,571 163,183 304,145 6,766,130 3,049,229 155,907 718,440 835,530 771,046 60,432,871 Surplus/(Loss) 27,785,724 (512,408) (105,764) (19,790) 1,599,644 (699,244) 747,248 (240,053) (404,698) (299,831) 27,850,827

2005 Honiara Auki Malu'u Buala Noro Gizo Munda Tulagi Kirakira Lata Totals Sales Revenues 85,638,886 3,198,804 79,834 391,055 6,075,052 3,306,926 912,648 732,467 598,304 365,214 101,299,190 Expenditures Generation 64,707,699 2,335,138 229,363 482,630 5,389,899 4,352,133 30,772 1,453,974 1,018,486 866,802 80,866,895 Distribution 3,878,876 243,145 27,357 15,888 352,584 195,884 193,283 30,630 30,097 2,609 4,970,353 Administration 989,991 151,278 150,119 117,102 302,025 238,441 83,267 142,828 157,997 168,904 2,501,951 Total Expenditures 69,576,566 2,729,561 406,839 615,620 6,044,507 4,786,458 307,321 1,627,432 1,206,580 1,038,314 88,339,199 Surplus/(Loss) 16,062,320 469,243 (327,006) (224,566) 30,545 (1,479,532) 605,327 (894,965) (608,275) (673,100) 12,959,991

2006 Honiara Auki Malu'u Buala Noro Gizo Munda Tulagi Kirakira Lata Totals Sales Revenues 88,633,880 6,044,464 272,417 1,577,089 15,353,067 8,100,240 2,754,658 35,489 1,679,318 1,298,119 125,748,741 Expenditures Generation 86,179,308 2,764,243 168,761 905,375 6,597,750 4,085,436 38,493 935,925 975,031 967,330 103,617,652 Distribution 4,323,523 247,690 26,880 15,700 284,101 205,045 204,752 33,088 31,248 2,073 5,374,101 Administration 562,724 72,620 42,888 73,876 145,799 109,807 52,501 39,889 80,967 74,671 1,255,741 Total Expenditures 91,065,555 3,084,553 238,530 994,951 7,027,650 4,400,289 295,746 1,008,902 1,087,246 1,044,073 110,247,494 Surplus/(Loss) (2,431,675) 2,959,912 33,887 582,138 8,325,416 3,699,952 2,458,912 (973,413) 592,072 254,046 15,501,247

2007 Honiara Auki Malu'u Buala Noro Gizo Munda Tulagi Kirakira Lata Totals Sales Revenues 166,723,373 7,639,767 276,374 1,519,596 20,099,763 9,280,945 3,083,356 840,816 1,827,197 1,440,023 212,731,210 Expenditures Generation 103,049,237 3,963,738 253,026 857,046 9,777,851 6,002,943 58,763 1,624,050 1,440,471 1,345,754 128,372,878 Distribution 5,256,972 335,198 31,495 22,552 429,518 270,444 225,170 36,051 44,108 6,517 6,658,024 Administration 779,120 111,657 99,186 97,029 242,653 164,657 69,105 88,643 125,895 117,903 1,895,848 Total Expenditures 109,085,329 4,410,593 383,707 976,627 10,450,021 6,438,045 353,038 1,748,743 1,610,473 1,470,174 136,926,750 Surplus/(Loss) 57,638,044 3,229,173 (107,333) 542,969 9,649,742 2,842,900 2,730,318 (907,927) 216,724 (30,151) 75,804,460

What the available financial information for SIEA’s operation show is that the authority is still financially too weak to subsidize the introduction of hydropower or other renewable energies. If subsidies are being channelled to such an endeavour it has to be external to SIEA’s operation. Hydropower projects can, however, improve SIEA’s energy security by sheltering the utility from fuel price volatility. This distinguishes hydropower from the use of CNO as a fuel substitute that has also been analysed in the framework of this RETA (see separate report).

5.2 Fuel Supply Cost at SIEA Outstations For hydropower to be a financially superior solution for SIEA, it needs to be competitive with other sources of power. At present all sites investigated are fuelled 100% by diesel power. A pilot project in Auki will, however, soon start to test the use of diesel/CNO blends. I.e. supply cost based on diesel or CNO generation is the main benchmark. However, diesel and CNO is not the only competitor against which hydropower needs to measure up. In theory, hydro also needs to be competitive when compared with solar, wind and other biomass technology. In the separate analysis of CNO mentioned above, the consultant concluded that because of a close

31/25866 February 12 Page 30 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro– PRE-FEASIBILITY STUDIES link between fuel price and vegetable oil price development on the world market, CNO does not offer a strategic option for reducing cost to SIEA. At best in can be a financially neutral substitute that enhances energy security and channels economic benefits to the rural producers of copra and CNO. For the purpose of this analysis, supply cost for diesel and CNO (on an energy equivalent basis) are considered identical for the locations under consideration. The following Table 5.2 displays diesel supply cost to selected centres for June 2010. Actual SIEA fuel prices for Taro are not presently available, as it is not an operating SIEA station. As it is fairly remote from the Solomon Islands fuel importing centres of Honiara and Noro/Gizo, it has for present purposes been assumed that the delivered fuel price in Taro will be similar to that for Lata, which shares that characteristic. This assumption will be revised if warranted by new data.

Table 5.2: Delivered Diesel Fuiel Cost by Outstation (SBD$/litre, June 2010)

FOB Freight Honiara Cost Total Auki 6.83 $ 0.43 $ 7.25 Kirakira 6.83 $ 0.90 $ 7.73 Lata 6.83 $ 1.15 $ 7.98 Noro 6.83 $ - $ 6.83 Taro (Choiseul) 6.83 $ 1.15 $ 7.98

In order to make financial projections over 20 years, it is assumed that diesel fuel prices, including the cost of transport of fuel to the outstations, will increase at 3 percent per annum in real terms. This assumption does not purport to be a realistic fuel price forecast; petroleum prices are extremely volatile. A ‘realistic’ fuel price forecast for 20 years or even a much shorter period is not possible. Rather, the 3-percent-real assumption is made simply to place the projections for each outstation on a consistent basis, to enable comparisons. In actual experience during the next 20 years, it is fully expected that fuel price volatility will continue.

5.3 Supply Cost and Benefits of Hydropower The supply cost from a hydropower station is driven by investment cost. In comparison to capital cost, short run marginal costs of hydropower are almost negligible. For the five sites investigated in this study, supply cost vary greatly but are clearly well below the cost of any competitor including diesel, CNO solar or wind. Hydropower is a reliable, low operating and maintenance cost means of supplying electricity 24 hours per day. As it requires no fuel input, energy from hydropower is much less costly than equivalent diesel energy, and completely avoids the expense and insecurity of fuel logistics. It is as effective in rural supply areas as it is in urban supply areas, provided that local topological and hydrological conditions (rainfall, catchment area, runoff) are adequate. Its capital cost varies significantly from site to site, depending upon local topological and geological conditions. In contrast to the introduction of coconut oil (CNO) to displace diesel fuel for power generation in rural areas, introducing small hydropower will not directly generate significant rural employment or incomes (i.e., there will be no equivalent of local copra farmers to supply raw material for fuel). However, in the Solomon Islands, hydropower has considerable potential to provide affordable electricity to rural areas where the physical conditions for it are appropriate, as they appear to be in the above centres. In these centres and perhaps others, hydropower has good potential to turn loss-making rural diesel centres into profitable operations or to create new power centres that are profitable, either for SIEA or for an independent power producer (IPP). Thus hydropower has a role in making reliable electricity accessible to more of the Solomon Islands’s rural population. Assuming that the willingness to pay for electricity in rural areas (the

31/25866 February 12 Page 31 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro– PRE-FEASIBILITY STUDIES assessment of which was beyond the scope of this TA) is at least equal to the national electricity tariff, hydropower will benefit the rural population by raising the quality of life, widening the opportunities for improved social services, and perhaps stimulating commercial development.

5.4 Carbon Finance Clean Development Mechanism (CDM) allows emission reduction projects that assist developing countries in achieving sustainable development and that generate ‘certified emission reductions’ (CER) for use by the investing countries or companies. Mini hydro and biofuel projects could theoretically qualify17 for CDM and projects in Solomon Islands could therefore generate an additional revenue stream from the trade of certified emission reductions. This would not apply for projects that are financed using ODA funds. As the baseline is 100 % diesel, calculating emission reductions from renewable energy contribution is straightforward. The UNEP CDM guidebook suggests an emission co-efficient for small diesel grids of 0.8 kg CO2/kWh generated by renewables. At an assumed average specific fuel consumption of 3.38 kWh per litre of diesel each litre of diesel replaced by hydro equals 2.7 kg of CO2. Small hydro power generation is eligible for carbon credits under the Clean Development Mechanism (CDM) of the Kyoto Protocol of the United Nations, and a number of projects have been accepted as CER sources. Small renewable energy projects enjoy a simplified demonstration of additionality. Small project activities are defined as less than 5MW. They must employ renewable energy as their primary technology and are additional if any one of the conditions below is satisfied:

A the geographic location of the project activity is in one of the Least Developed Countries or the Small Island Countries (LDCs/SIDs) or in a special underdeveloped zone of the host country identified by the Government before 28 May 2010;

B the project activity is an off grid activity supplying energy to households/communities (less than 12 hours grid availability per 24 hours a day is also considered as 'off grid' for this assessment);

C the project activity is designed for distributed energy generation, not connected to a national grid, with both of the below conditions satisfied:

i. each of the independent subsystems/measures in the project activity is smaller than or equal to 1500 kW electrical installed capacity; and

ii. end users of the subsystems or measures are households/communities/SMEs;

D the project activity employs specific renewable energy technologies/measures recommended by the host country DNA and approved by the Board (though the total installed capacity of the technology/measure must contribute less than or equal to 5% to national annual electricity generation)18

In addition to CER, there is also trading in so-called "verified emission reductions" (VERs) in what is commonly referred to as the voluntary carbon market. VERs are not a standardized commodity. While they may eventually become CERs there is a risk that this may not happen and therefore buyers therefore tend to pay a discounted price for VERs, which takes the inherent regulatory risks into account. Such opportunities may also be explored.

17 As a minimum SI government has to establish a Dedicated National Authority (DNA) for CDM. Such a unit is not yet in place but the ADB supports the government in establishing such an institution. 18 http://www.cdmrulebook.org

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The hydropower projects assessed by this TA and discussed below are all financially viable and would make good investments, both to improve the financial position of the project owner (in all cases except Ringgi, the project owner would be SIEA) and to provide a sound electricity supply to rural consumers in the Solomon Islands. The application of CER credits to these schemes would not stimulate additional investment in them, and it is therefore unlikely that the schemes would pass the additionality test for approval of CER credits. In addition, it is not even certain that the benefits from CER would exceed the administrative cost incurred to obtain CER. CER credits have therefore not been included in the analysis in this report.

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Part II

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6. Identification of Sites

6.1 Overview The results of pre-feasibility level investigations for five individual sites are presented in the following Sections. The shortlisted sites have been selected in close co-ordination with the Solomon Island government and SIEA. SIEA senior management expressed a preference for sites that could supply the Noro/Munda system, which is the largest demand center after Honiara. In general, the criteria used for selecting the sites were: • Existing or planned rural electricity supply network (Demand) • Hydro site within a commercially viable range from the demand centre • Cost to supply location with diesel

The following map shows the geographical location of the five sites described in the following Part Two. The sites at Afio, Rualae (Auki) and Lungga (Honiara) are not considered competitive options and have not been analyzed in detail. However, they are briefly described. The Mase river site in New Georgia has been considered as a second option to supply the Noro/Munda grid and appears to be viable.

Figure 6.1: Location of Sites Considered and Studied

Pre - feasibilityPre-feasibility site Site

Taro Site considered for Prefeasibility analysis Ringii

Noro

Auki

Rualae Mataniko Lata

Lungga

Afio

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The Mase river site received a gauging station as it could be a fall-back position in case the Vila/Ringgi project cannot be built to size that would allow to supply the Noro/Munda demand because of environmental concerns. (A larger development could infringe the protected area around the crater of the Komlumbagara volcano. In all other respects, the Vila/Ringgi site is superior. There is a network of good roads on the island, the forest company possesses all heavy construction machinery that would be needed for the construction of a hydropower plant thus reducing construction cost significantly and the transmission line to the demand centers would be shorter and less expensive than for a project on the Mase river. As the scope of this study only forsees five sites to be investigated in detail, the Mase river site is at this stage considered a fall back option in case the Vila/Ringgi site cannot be developed to its full potential.

6.2 Consultations and Preliminary Site Selection During initial meetings with the Permanent Secretary for Ministry of Mines, Energy and Rural Electrification, GSI Energy Unit and SIEA, discussions included (i) the consultant’s ToR and preliminary work schedule, (ii) local regulations and planning standards, (iii) details on existing information and data bases (iv) existing experiences with pre-payment meter systems, (v) financial status of the SIEA’s outstations, (vi) current fuel, operation costs, and tariffs, (vii) current SIEA management structure, and (viii) existing operational procedures and reporting templates. In addition consultations were held with both MMER and SIEA senior staff on the selection of sites to be investigated under the RETA. SIEA management clarified its objectives to reduce supply cost in outer island stations with the aim to establish financial viability across its entire system. SIEA also indicated its preference for projects that are suitable for development through private sector sponsors and/or investors. MMER on the other hand clarified its policy to expand supply areas in order to provide more access to electricity. Information on historic experiences with hydropower was shared with the consultant including more recent lessons learned in the framework of the Tina river hydropower development project on Guadalcanal. Initial consultations yielded a shortlist of project sites to be investigated by the consultant.

6.3 Site Specific Investigations and Field Missions On-site studies were conducted in Lata, Auki, Afio, Ringi, Honiara, Noro/Munda and Taro. They included broadly based stakeholder consultations, surveys of power supply infrastructure, assessment of existing hydropower resources through GPS surveys and discharge measurements, demand surveys of both existing and potential new SIEA customers and specific community consultations and individual interviews on relevant subjects such as pre-payment metering systems, support for data collection (level and rainfall gauging stations), and possible community participations in hydropower development and power system expansion projects. The results of these surveys and consultations were used to develop a load forecast over a 20 year planning horizon for each station. In forecasting loads and energy consumption, the total demand in the area regarded as serviceable through expansions of the system has been taken into consideration. Based on a base-case load forecast, generation and distribution system expansion was designed using standard planning criteria such as N-1 generation reliability. This conventional expansion planning based on diesel is the baseline scenario against which the introduction of hydropower needs to be measured. It was also deemed necessary, as SIEA currently does not have a comprehensive expansion plan for their outstations. Subsequently hydropower contribution to system power and energy demands was determined based on a financial model driven by a variety of load forecast scenarios. No capapcity credit is given to run off river hydro at this stage. I.e. the stations need to be backed up by diesel. This may change during feasibility analysis when a comprehensive evaluation of hydrological data allows determining whether or not the hydro plants can be credited to provide firm capacity. In this regard, assumptions at pre-feasibility level can be considered conservative as potential savings

31/25866 February 12 Page 36 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro– PRE-FEASIBILITY STUDIES in diesel capacity may occur when a thourough hydrological analysis has confirmed capacity credit for the hydro schemes. The following Table 6.1 summarizes the current electrification rates for the provinces under consideration. The table is based on a number of assumptions: It uses the population projections for 2012 published by the GSI statistical office. For every electricity account, be it demestic or commercial, it is assumed that 6 people benefit (mean household size).

Table 6.1: Potential Impact of Hydro Projects on Electrification Rates of Provinces

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7. Auki Malaita

7.1 The Auki Power System Malaita is one of the six main Islands, which make up the Solomon Islands. Malaita is mountainous and is the country’s most populated island, hosting a population of 170,000 according to the 2007 Statistic Office record, or more than a third of the national population. Malaita is about 164 km long and narrow at 37 km wide at its widest point. The largest town is Auki, located on the northwest coast. Population growth is around 3.3% pa. Only approximately 4% of the population of Malaita province currently has access to electricity. In addition to the two SIEA service areas in Malaita, Auki and Malu'u, there are several community type micro hydro projects on the island serving their immediate vicinity with power. The Malu’u system is a diesel/micro hydro hybrid but the hydro plant is currently not operating due to an unresolved land dispute. Auki is the capital of the province and covers an area of approximately 2 km2. The immediate town area has a population of approximately 5,300, with an additional 15,000 living in outlying villages. Auki hosts national and provincial government offices, a hospital, and several primary and secondary schools. It has a lively commercial sector consisting of agriculture, fisheries, forestry and trading activities. There are several commercial banks and a number of small hotels and guest houses. The town is served daily by a fast ferry from Honiara and enjoys regular air service by Solomon Airlines. The town also provides services to a large rural area on the North West coast of Malaita. The bulk of Auki’s population is centred around the south western coastal inlet area with small villages along the northern road towards Kilufu’u and the airport. There is also a sparsely populated region approximately 700 m to the east of the main commercial area.

Generation Auki’s electricity is generated at SIEA’s diesel power plant located on the outskirts of Auki, approximately 500 m west of the town centre. The Auki Power Station was built in 1991 and consists of a concrete block building with a painted sheet metal roof. The building consists of the generator hall, electrical switch room and office / store. The floor of the power station consists of a reinforced concrete slab. The station accommodates three generating sets. The diesel generators currently installed at Auki Power Station are high speed (1,500 rpm) Cummins units operating on base load duty. No.1 set is currently not serviceable. It had a catastrophic failure in March 2010 with major damage to the piston and scoring of the cylinder liners. These have been removed and parts are awaited to rebuild this set. However, this set has already completed at least 43,132 hours (maybe 53,132 hrs) and was installed in 2001. The condition of this set would suggest that rebuilding may not be cost effective as it is likely to require extensive maintenance from this point forward.

Table 7.1: Generation Assets Auki Power Plant, April 2011

No Model Nameplate Derated Available Total Installed Remarks Rating kW kW kW Hours

1 Cummins NT855-G6 252 200 0 43,000 2001 Awaiting Replacement

2 Cummins VTA28G5 512 500 500 8,500 2010 In service

3 Cummins NT855-G6 252 180 180 32,000 2005 In service

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With a current available capacity of 680 kW and a maximum demand of around 350 kW (April 2010) the largest unit is able to meet demand at approximately 65 % loading. However, there is at present no stand-by capacity as the No 3 set can only produce 180 kW which is below even the daytime demand. The No 3 set is going to be replaced in July 2011 within the framework of this RETA and will be used to run biofuel trials. The new set will have a capacity of 360 kW and will be able to supply the system load under most load conditions.

Picture 7.1: Auki Power Generation

Auki Power House, SIWA Tanks Auki Generators Auki Fuel Storage

The generators are controlled by a Cummins PowerCommand (PCCP 3100) control unit that features a digital paralleling capability including load sharing, synchronizing and monitoring. An automatic dispatching and switching unit is installed but is out of operation, i.e. the sets have to be manually started and synchronized automatically after start up.

Figure 7.1: Auki Load Profile

Load Profile Auki April 2010 400 350 300 250 18-Apr

kW 200 19-Apr 150 20-Apr 100 21-Apr 22-Apr 50 23-Apr 24-Apr 0 1 3 5 7 9 11 13 15 17 19 21 23 Hours

Analysis of original power station log sheets suggests that at present, the Auki system has a relatively flat load distribution typical for a smaller commercial centre with a daytime plateau and decreasing demand after 10.00 p.m. Weekend daytime demand is approximately 100 kW lower than weekday demand on Saturday; Sunday loads are even lower. Weekends show a prominent evening peak, typical for small rural systems. Base load is in the order of 250 kW, a value that is typical for the period from 10 p.m. until 7 a.m. Based on Auki station records a fuel efficiency of 3.3 kWh send out per litre of fuel input has been calculated.

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The generators are connected to the system via two 500 kVA, 415V/11kV step up transformers and a 415V switchboard. A single 11 kV bus and switchboard then supplies Auki’s distribution system via two 11 kV overhead feeders (Nos 1 and 2). Station auxiliaries are fed at 415V/240V.

Distribution The current area of SIEA electricity supply to the Auki town area is bounded by Kilu’ufi Hospital, approximately 3.5 km to the west of the town centre, the Kwaibala river and pumping station approximately 1km to the north, and the village of Ambu, some 500 m to the east of the town centre. Power is distributed to consumers in Auki via two overhead 11 kV feeders, 5 11kV/415 substations, and overhead and underground 4-wire 415V/240V low voltage distribution circuits. The 11kV overheads are typically installed on either tapered octagonal or 100mm steel poles, some with pole lengths ranging from 12 – 14 metres. Cross arms are steel. Spans are typically 60 – 70 metres for straight runs, with 3% sag. Insulators are generally of the porcelain pin type. Feeder 1 runs 2.5 km to the Kilu’ufi Hospital and has 3 transformers totalling 250 kVA. Feeder 2 has a length of only 1.1 km and supplies the town centre via 2 transformers totalling 400 kVA. Total present loading of the feeders is approximately 20 - 25 Amps. The uneven phase loading of the feeders observed during field investigations indicate that there is a need for rebalancing loads in order to avoid unnecessary losses. The 415V / 240V Low Voltage system consists of a mixture of overhead (open wire) distribution lines with some short runs of underground cables. In some areas Aerial Bundle Conductors (ABC) are installed at (eg supply to Dukwasi and Molou villages). SIEA’s policy is to progressively install ABC for the overhead 415V system to reduce tree clearing work and to improve reliability of the distribution system. Service connections are generally made via overhead service line to the premise’s distribution and metering board. Service connections from the distribution lines are free if they are less than 20 meters in length, above 20 meters SIEA charge a capital contribution to the new customer. Most of Auki’s 700 SIEA customers are still metered by conventional single phase or three single phase (Ferrari type) kWh meters. However, SIEA has started to install cash power prepayment meters in Auki. As of April 2010 approximately 90 customers use the new system and demand for additional prepayment meters seems to be high. Average demand of prepayment customers in March 2010 was 44 kWh.

Financial Status SIEA Auki Historically, the Auki centre has been one of the three or four “growing” SIEA outstations, with electricity consumption dominated by the commercial sector. The billing records for March 2010 indicate that there are 778 connections in Auki, of which 496 are domestic and 282 commercial. Commercial consumption dominates Auki’s power demand with more than 80 percent of consumption. There is a number of domestic areas that could be connected to the load centre by means of modest extensions (in phases) of the 11 kV and LV networks, the first two of which are included in the proposed project in Auki. No substantial number of new commercial connections are expected. New domestic loads expected in Auki over the planning period are summarised in Table 7.2.

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Table 7.2: New Domestic Loads Expected in Auki following System Extension Consumption New Connec- Power Per First Domestic tions Demand Day Year First Connections (No) (kW) (kWh) (kWh) Year Online Phase I 250 0.21 1.66 151,767 2012 Phase II 20 0.42 3.33 24,283 2012 Phase III 500 0.21 1.66 303,534 2016

Note: for new domestic connections, the power demand and daily kWh consumption are per household. Phase I Western Fishing Village, Phase II new housing estate, Phase III Eastern expansion

The rate of revenue collection (collections as a percentage of total invoices) in Auki is not presently known but is likely to be better than that of Lata, because of the preponderance of the commercial sector. With the exception of 2004, Auki returned an (estimated) operating surplus to SIEA each year between 2003 and 2007. Because Auki already has a 11 kV distribution system (for which appropriate extensions are proposed), distribution network efficiency will not show the same dramatic improvements that characterise Lata. However, in concert with SIEA’s national effort to install prepayment meters in Honiara and in all outstations, revenue collections are bound to improve in Auki in the future (but may already be better than in most other outstations).

7.2 Auki Load Forecast Unfortunately, no consistent and plausible data series on demand and electricity generation is available for Auki. The monthly statistics spreadsheet provided by SIEA does not display any plausible trend for either maximum demand or monthly generation and sales as displayed in the graph below. There is also a long term systematic error in either generation or units sold data (or in both data sets) as over a ten year period, the figures for units sold exceed units generated by more than 10% -- i.e., a projection of historic demand development for load forecasting would lack a trustworthy baseline. The load forecast below is therefore based on standard assumptions with respect to general load growth of 4 %. It also takes into consideration the connection of new consumers through grid extension by the project itself and a later one by SIEA as displayed in Table 7.2 above.

Figure 7.2: Auki Load Forecast

Auki Power System Load Forecast 6,000,000

5,000,000

4,000,000

Sales to Commercial 3,000,000

kWh Sales to Domestic Station and Line Losses 2,000,000

1,000,000

-

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The Auki system load forecast, estimation of generation requirements, projected hydro output and residual diesel or CNO fuel requirements, and a schedule of new generation capacity installations required to meet load demand over the 20-year planning period are summarised in Table 7.3 overleaf. The forecast distinguishes domestic and commercial load. Station use and line losses are also computed separately.

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Table 7.3: Auki System Load Forecast, Generation Requirements, Fuel Requirements and Generator Scheduling

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 8 Load Forecast AAGR Sales = 5.44% Electricity Sales (kWh) Existing Domestic (2010) 359,414 373,790 388,742 404,292 420,463 437,282 454,773 472,964 491,882 511,558 532,020 553,301 575,433 598,450 622,388 647,284 673,175 700,102 728,106 757,230 787,520 New Domestic - - 607,068 631,351 656,605 682,869 710,184 738,591 768,135 798,860 830,814 864,047 898,609 934,553 971,935 1,010,813 1,051,245 1,093,295 1,137,027 1,182,508 1,229,808 Existing Commercial (2010) 1,418,282 1,475,013 1,534,014 1,595,374 1,659,189 1,725,557 1,794,579 1,866,362 1,941,016 2,018,657 2,099,403 2,183,380 2,270,715 2,361,543 2,456,005 2,554,245 2,656,415 2,762,672 2,873,179 2,988,106 3,107,630 New Commercial ------Total Sales 1,777,695 1,848,803 2,529,823 2,631,016 2,736,257 2,845,707 2,959,536 3,077,917 3,201,034 3,329,075 3,462,238 3,600,727 3,744,757 3,894,547 4,050,329 4,212,342 4,380,836 4,556,069 4,738,312 4,927,844 5,124,958

Sales to Domestic 359,414 373,790 995,810 1,035,642 1,077,068 1,120,151 1,164,957 1,211,555 1,260,017 1,310,418 1,362,835 1,417,348 1,474,042 1,533,004 1,594,324 1,658,097 1,724,421 1,793,397 1,865,133 1,939,739 2,017,328 Sales to Commercial 1,418,282 1,475,013 1,534,014 1,595,374 1,659,189 1,725,557 1,794,579 1,866,362 1,941,016 2,018,657 2,099,403 2,183,380 2,270,715 2,361,543 2,456,005 2,554,245 2,656,415 2,762,672 2,873,179 2,988,106 3,107,630 Station and Line Losses 154,582 160,765 219,985 228,784 237,935 247,453 257,351 267,645 278,351 289,485 301,064 313,107 325,631 338,656 352,202 366,291 380,942 396,180 412,027 428,508 445,649

Load Factor 0.60 0.61 0.61 0.62 0.62 0.63 0.63 0.64 0.64 0.65 0.65 0.66 0.66 0.67 0.67 0.68 0.68 0.69 0.69 0.70 0.70

AAGR Generation = 5.44% Generation Requirement (kWh) 1,932,278 2,009,569 2,749,808 2,859,800 2,974,192 3,093,160 3,216,886 3,345,562 3,479,384 3,618,560 3,763,302 3,913,834 4,070,388 4,233,203 4,402,531 4,578,632 4,761,778 4,952,249 5,150,339 5,356,352 5,570,606 Station and Line Losses (kWh) 154,582 160,765 219,985 228,784 237,935 247,453 257,351 267,645 278,351 289,485 301,064 313,107 325,631 338,656 352,202 366,291 380,942 396,180 412,027 428,508 445,649 Peak Demand (kW) 367.63 379.18 514.60 530.83 547.61 564.96 582.90 601.44 620.61 640.43 660.92 682.11 704.02 726.68 750.11 774.33 799.39 825.29 852.08 879.79 908.45 Required Capacity with Reserve (kW) 477.92 492.93 668.98 690.08 711.90 734.45 757.76 781.87 806.79 832.56 859.20 886.75 915.23 944.68 975.14 1,006.63 1,039.20 1,072.88 1,107.71 1,143.73 1,180.98 Fuel Required, All-Diesel Scenario (litres) 579,683 602,871 824,942 857,940 892,258 927,948 965,066 1,003,669 1,043,815 1,085,568 1,128,991 1,174,150 1,221,116 1,269,961 1,320,759 1,373,590 1,428,533 1,485,675 1,545,102 1,606,906 1,671,182

9 Hydro Scenario Generation Calculation Generation Mix with hydro (kWh/year) Hydro - - - - 2,974,192 3,093,160 3,216,886 3,345,562 3,479,384 3,618,560 3,763,302 3,913,834 4,070,388 4,233,203 4,402,531 4,578,632 4,761,778 4,952,249 5,150,339 5,356,352 5,570,606 Diesel 1,932,278 2,009,569 2,749,808 2,859,800 ------Fuel Required, Hydro Scenario (litres) 579,683 602,871 824,942 857,940 ------Fuel Saved by Hydro (litres) - - - - 892,258 927,948 965,066 1,003,669 1,043,815 1,085,568 1,128,991 1,174,150 1,221,116 1,269,961 1,320,759 1,373,590 1,428,533 1,485,675 1,545,102 1,606,906 1,671,182

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 9 Generator Scheduling Existing Unit 1 200 Unit 1 Biofuel 500 500 500 500 500 500 500 500 500 500 Existing Unit 2 500 500 500 500 500 500 500 500 500 500 Existing Unit 3 180 180 180 180 180 Unit 2 Biofuel 500 500 500 500 500 500 500 500 500 500 500 Unit 3 Biofuel 500 500 500 500 500 500 500 500 500 500 Unit 4 Biofuel 500 500 500 500 500 500 500 500 500 500 Unit 5 Biofuel 500 500 500 500 500 Unit 6 Biofuel 500 Unit 7 Biofuel Unit 8 Biofuel Unit 9 Biofuel Total Installed Capacity (kW) 880 1180 1180 1180 1180 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 Firm Capacity Available 380 680 680 680 680 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 Memo: Units Added Small Units (300 kW) ------Large Units (500 kW) - 1 - - - 1 - - - - 1 1 - - - - 1 - - - 1

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7.3 System Expansion Planning Auki

Generation Currently, there is only one generator set in the Auki power station that can meet demand (Cummins VTA28G5). Number 1 set (Cummins NT855-G6) is not serviceable after a catastrophic piston failure and is under repair. The set should be replaced as soon as possible as it is already 10 years old and has done more than 43,000 hours. The nature of the recent failure indicates that the unit will probably continue to cause problems when used for base load supply. In order to provide a minimum of redundancy, the Auki powerhouse needs three reliable generator sets. Figure 7.3 illustrates the generation requirement implied by the load forecast provided above. This expansion plan is based exclusively on high speed diesel generators. The relative position of the proposed hydro scheme is also displayed. It should be noted that at this stage, no capacity credit has been given to hydro. I.e. in the event that the hydro plant is being built, the system is assumed to backed up by a set of diesel generator capable of meeting peak demand in line with the N-1 planning criteria.

Figure 7.3: Auki Capacity Requirements

Auki Capacity Requirements 1,600

1,400 Hydro

1,200

1,000

800 Peak Demand (kW) kW Firm Capacity Available

600 Total Installed Capacity (kW)

400

200

- 2010 2011 2012 2013 2014 2015 2024 2025 2026 2027 2028 2029 2016 2017 2018 2019 2020 2021 2022 2023 2030

Grid Extension The World Bank SKM report ‘Solomon Islands Proposed Power Sector Projects - Outer Islands Generation and Rural Electrification Components’ of 2007 identified 3 potential areas to which the Auki power system could be extended: • Western fishing Village. • Eastern extension area. • Kilufu’u extension area.

All three areas have been surveyed by GHD during field investigation and the Western Fishing village area has been identified as priority candidate for an extension. Electrification of this low-income clusters would have to be included into the development of the hydro scheme. The area closest to the existing system is currently been connected as part of this project. It has the highest density of potential customers and being a village of fisherman shows significant potential for productive electricity use (fish freezing, ice production). The

31/25866 February 12 Page 44 TA 7329- Promoting Access to Renewable Energy in the Pacific CNO – PRE-FEASIBILITY STUDIES area has also experienced substantial growth in recent years with now approximately 250 unserved households. However, the other two extension areas offer similar growth potential at extension cost of approximately US$ 1,100 per household connection. Energy demand surveys performed by GHD revealed that there is keen interest in getting access to the electricity network and current expenditures for kerosene indicate that an average family already spends SBD 180 – 220 per month on kerosene, equivalent to 55 kWh. This is more than the average pre-payment customer in Auki use (45 kWh/month).

7.4 Hydro Options for Malaita Province and Auki

Afio For Malaita Province, three different sites have been considered. MMERE named Afio Island as a potential new project using the Pulalaha stream as a source to electrify Afio station which is the main administration centre of South Malaita, Malaita Province. This project was initially assessed by the Solomon Islands Village Electrification Council (SIVEC) in August 2003 and re-assessed by GHD in 2011. The supply area that could be covered by supplied by a hydro station on the Pulalaha consists of 17 residential houses, a health post, government offices, a Telecom tower, a rest house and a defunct fisheries facility that may be rehabilitated. Table 7.4 depicts an assessment of potential loads. As the Afio center has currently no power supply the initial demand of the centre would be around 200 kWh per day (53,000 kWh per annum).

Table 7.4: Potential Loads in Afio

Quan Potential Consumer Types tity Load (kW) Comments

Domestic houses are mainly houses that accommodate Residential Houses 17 10.5 government workers within the Afio station.

The Provincial Government office at Afio will require the use of Provincial Government equipment such as computers, Air-conditions etc. Administration office 1 4

This is an I8 bed health centre. Currently powered by 480 Watt Health Centre 1 5 Solar Panel purposely to provide lighting.

Power for the Telekom towers is only required for the charging of Our Telekom Tower 1 7 battery banks.

Equipment in this centre is not operational and the facility is being used as a residence now. This facility use to have ice making Fisheries Centre 1 5 equipment, freezers and office facilities.

Rest House is powered by 140 watts Solar Panel and 200 AH Rest House 2 3.0 battery.

Total 36 Total daily energy at 25 % load factor: 210 kWh

The hydro potential of the Pualalaha river has been estimated at 0.1 m3/sec and a gross head of 29 meter resulting in am installed capacity or approx 15 kW. With some demand management the hydro scheme could probably supply Afio without support from a diesel system. However, to harness the small potential a major civil engineering effort would be required. The Pulalaha stream runs through a very steep limestone gorge as shown in Picture 7.2. This morphology would pose be major challenges in the construction of an

31/25866 February 12 Page 45 TA 7329- Promoting Access to Renewable Energy in the Pacific CNO – PRE-FEASIBILITY STUDIES intake canal, sand trap and forebay. A substantial amount of excavation or even blasting of the stream banks would be required. With specific cost estimated to be above US$ 16,000 per kW installed the project is not considered competitive with conventional diesel or even PV based power supply.

Picture 7.2: Pulalaha Limestone Gorge at Afio

Considering the low demand of Afio, the high specific cost for the scheme and the high hydrological uncertainty of a spring based river, it was decided not to investigate the Afio project in more detail.

Ruala’e The Auki area has several rivers with mini hydro potential. MMERE initially shortlisted the Ruala’e scheme to be investigated under this TA. However two hydropower development studies have already been carried for this site. In 1996 SIEA carried out a Pre-feasibility study for the Ruala’e site and Hydro Tasmania updated the study with the 2010 feasibility study. I.e. the project was dropped from the list. The following table summarizes the result of this study performed by Hydro Tasmania:

Table 7.5: Characteristics Ruala’e Site Auki

Rualae Mini Hydropower Scheme, Auki System Key Data Details Location SIEA Auki System, Provincial Capital, Malaita Province Auki township, Kiluufi hospital, planned coastal villages along south road to Main Supply Area Talakali. Name of the River Rualae creek, Kwara’ae, 13 km south of Auki Catchment Area Spring Gross Head 200.0 m Net head 175.0 m Minimum Streamflow Approx. 10 litres/sec (100% exceedance) Design Flow 130 litres/sec Penstock diameter 250 mm Maximum Plant Output 179 kW Transmission Line 11 kV, 13 km long to Auki town

Project Capital Cost SBD $ 4.063 Million (500,000 US$)

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Against the background give above it was decided in consultation with SIEA and MMERE to focus efforts on Malaita on the Fiu scheme which has the potential to meet the entire demand of Auki. This project is analysed below.

7.5 General Description Fiu The Fiu River is passing behind Auki town on its lower part and the potential projects considered are up in the mountains 8-10 km from Auki. 7-8 other potential projects in the MW range on Malaita have been identified, but Fiu is the closest to the demand centre of Auki and easily accessible by road.

Picture 7.3: Fiu River

The project has been studied in 1996 by SIEA with support from German TA. The resulting proposal included a tunnel from an intake higher up in the gorge on Fiu’s probably in an attempt to maximize the head of the scheme and to overcome challenges in canal construction along the sometimes very steep slopes of the Fiu gorge. As tunnelling is normally cost prohibitive for a small hydro project, the project proposal did not go beyond the study. The proposal was based on a larger catchment with inclusion of a major tributary adding about 33% catchment area. However, GPS surveys indicate revealed a deep gorge at the proposed intake, the canal alignment would be on extremely steep cross slope, posing serious construction problems. An alternative with an intake at the site of the AWLR station and a canal on the north river bank does not appear to be competitive with the alternative to establish a project on the steep tributary river joining the Fiu main stream at the previously proposed intake. This solution would have a head of between 250 and 320 m, the last in case the powerhouse would be located at the bottom of the gorge.

Figure 7.4: Location of Fiu

Hydro Station

SIEA Power Station

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The analysis is based on the topography shown on Google Earth and the 1:50,000 maps for intake and canal alignments and the GPS survey around the automatic station, providing a gross head of 314 m with an intake at 400 a.m.s.l. with a catchment size of about 14.6 km2. One or more additional intakes along the canal could add about 5 km2 catchment on the plateau to the north. The critical issue here is the risk of sinkholes diverting the water away from the stream. This has to be verified through survey work in the feasibility analysis.

7.6 Hydrology For the Fiu catchment discharge per km2 has been calculated based on the hydrology of the Lungga Gorge. Figure 7.5 displays the flow duration curve assumed for the Fiu River. This might be a conservative assumption as the Fiu is better exposed from South over West to North West and may receive higher rainfall than Lungga. Data from the AWLR and rain gauge stations will provide more accurate data for a full-scale feasibility analysis. The steep slopes do not offer any opportunity to regulate the flow along the river near the intake. There may be possibilities on the extreme upper end of the river valley above El. 600 m and on the plateau north of the intake canal at about El. 630 m. Providing a certain regulation over the day for peak production may allow significant investment at a later stage, once the capacity is fully utilized. However, sinkholes may prevent establishment of small reservoirs.

Figure 7.5: Flow Duration Upper Fiu River

3.0 2.5 2.0 1.5 m3/s 1.0 0.5 0.0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % of time exceeding

7.7 System Layout The suggested layout of the Fiu scheme is based on an intake at El. 400 meter and a gross head of 260.5 meter. Figure 7.6 displays the profile of the river and the suggested layout of the scheme. A higher head may be feasible by moving the intake up river say to 520 meter.

Figure 7.6: Fiu Branch Profile

500 Fiu Branch Long Profile 400 Fiu Branch Profile 300 Canal

m.a.s.l. 200 Penstock 100 Canyon 0 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

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This would reduce the effective catchment area. The final design will depend on a careful analysis of the impact of sinkholes on the discharge at the various possible intake sites. A higher canal level results in much less steep cross slope allowing easy canal construction. The downside would be a longer winding canal alignment. The advantage of a higher head, at a given power demand, is that a smaller portion of the flow would be used. This not only leaves a higher ‘environmental’ flow in the river but also increases the plant factor of the installation. However, with the projected demand in Auki a gradual development of the Fiu may be the most economical solution. Such a development would increase the number of intakes along the canal in response to demand increases. Additional discharge measurement on the tributary in question would facilitate optimization of the scheme. The scheme lay out selected for this analysis is shown in Figure 7.7. It would have a relatively long canal of 3000 meter and a penstock of 755 meter. The powerhouse would be located at 86 meter elevation. Power extraction would require a 11 kV power line of 9.6 km to the SIEA diesel power station where it would connect to the 11 kV busbar supplying Auki’s two feeders. The installed capacity would be 1,160 kW producing a maximum of 9.8 GWh per year. At full capacity use the plant would only use 50% (0.5 m3/s) of the mean flow and thus leave a substantial environmental flow in the river. In this configuration either a Pelton or a Turgo turbine could be employed. A single jet Turgo wheel which is similar to the Pelton turbine is considered the optimal choice for the given head and flow variability (0.2 – 0.5 m3/s). In a Turgo configuration the jet strikes the plane of the runner at an angle of approx 20°. The water enters the runner on one side and exits on the other, which avoids interference of the discharge with the incoming jet at higher flow rates. The Turgo wheel is a robust design that is suitable for remote locations and for projects with high flow variability.

Figure 7.7: Fiu Hydro Scheme Layout

The hydropower plant would allow supplying Auki’s power requirements completely, i.e. there would be no need to implement the generator sequencing shown in Table 7.3 above.

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7.8 Variations The scheme described above could be designed to produce significantly more peak power and energy. This would only be necessary if power demand in the greater Auki area increased either through the implementation of a significant rural electrification program or the establishment of an industrial power consumer in Auki. The following Table 7.6 depicts a number of variations that could be implemented at the Fiu site.

Table 7.6: Design Variations for Fiu Hydro Site

Qdesign Qdesign Plant avail- Water GWh/yr m3/s /Qavg Pdesign kW ability Utilization Power-house Net GWh/yr 0.5 49.90% 1,160 96.74% 45.82% 9.835 9.814

0.8 79.84% 1,950 82.63% 64.49% 14.123 14.060

1.1 109.79% 2,720 70.97% 77.10% 16.918 16.812

1.4 139.73% 3,370 63.88% 85.47% 18.868 18.849

1.7 169.67% 4,260 53.84% 90.79% 20.102 19.903

2 199.61% 5,110 46.78% 94.49% 20.951 20.704

An analysis of the engineering economics of these variations shows the lowest levelized cost for capacities of approx 2 000 kW for under the assumption that all power potentially generated is used. This is due to the deterioration of the plant factor with increased installed capacity. For the purpose of this analysis it is assumed that the plant will be able to meet both peak and energy demand (900 kW/5.6 GWh) at the end of the planning horizon. In order to achieve this maximization of renewable energy in the Auki system, a plant size above the projected peak load of 900 kW has been selected (1 160 kW). Due to the lack of storage in the run-off river design and uncertainties in the hydrology, an optimized sizing of the plant targeting lowest levelized cost or highest FIRR is not possible at present. A smaller plant size could become an option, when a full hydrological analysis has been prepared.

Figure 7.8: Levelized Cost versus Installed Capacity

0.14 Levelized USD/kWh

Incremental USD/kWh 0.09 USD/kWh

0.04 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 kW Installed

As the design moves to higher installed capacities optimal turbine configurations, penstock and canal characteristics would change as displayed in Table 7.7 below. Beyond an installed capacity of 2 000 kW, levelized electricity production cost tend to increase due more expensive designs.

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Table 7.7: Design Parameters of Variations

Turbine

Qdesign Main Canal Canal Height Penstock loss Penstock m3/s Slope m/km m % Diameter m

Horizontal 1-jet Turgo 0.5 1.72 0.54 4.07% 0.49

Horizontal 2-Jet Pelton 0.8 1.51 0.66 3.92% 0.61

Horizontal 2-Jet Pelton 1.1 1.39 0.75 3.49% 0.70

Horizontal 1-jet Turgo 1.4 1.30 0.83 3.22% 0.78

Horizontal 2-jet Pelton 1.7 1.23 0.91 3.03% 0.85

Vertical. 3-jet Pelton 2 1.18 0.97 2.89% 0.92

7.9 Cost Estimates The analysis of levelized cost displayed above suggests that the lowest cost can be achieved building a relatively small scheme that shows a high plant factor. The projected demand in the Auki area also supports the development of a small scheme in the MW range. The following cost estimates are based on an installed capacity of 1,160 kW. The scheme would initially be oversized for the projected demand but would allow SIEA to supply Auki from hydropower for years to come. A full feasibility analysis would have to confirm the optimal size of the plant. As displayed in Table 7.8 below, total cost amount to US$ 4.2 million or US$ 3,600 per kW. This includes the connection of 1,000 new consumers at US$ 1,100 per connection including prepaid meters. Without the new connections specific investment cost for the plant alone would be US$ 2,650 per kW installed.

Table 7.8: Investment Cost Fiu River Hydropower Scheme

Item US$ SB$ Feasibility Study 100,000 800,000 Development 121,000 968,000 Engineering 180,000 1,440,000 Hydro turbine 629,000 5,032,000 Road construction 288,000 2,304,000 Transmission line 295,000 2,360,000 Substation 20,000 160,000 Penstock 317,000 2,536,000 Canal 285,000 2,280,000 Other Civ Eng 843,000 6,744,000 Rural Electrification 1,100,000 8,800,000 Total Investment 4,178,000 33,424,000 say $4.2 million

The Cost Estimates presented here have been prepared for the purpose of prioritizing sites for further investigation and should not be used for any other purpose. They are subject to the limitations described in Section 1.4. Further detailed investigations, including geotechnical and hydrological investigations, would be required to firm up the cost estimates for budget setting purposes.

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7.10 Financial Analysis In comparison with the all-diesel scenario for Auki, the hydropower scenario results in greatly reduced costs and much higher profitability under the current tariff as illustrated in the following three Figures. The detailed financial projections for Auki are shown in the Annex.

Figure 7.9: Auki Hydro Scenario

Revenues vs Operating Expenses, Auki Hydro Scenario $30.000 $25.000 $20.000 $15.000 Revenues $10.000 SBD millionsSBD Expenses $5.000 $-

Figure 7.10: Auki All-Diesel Scenario

Revenues vs Operating Expenses, Auki All-Diesel Scenario $35.000 $30.000 $25.000 $20.000 $15.000 Revenues

SBD millionsSBD $10.000 Expenses $5.000 $-

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Figure 7.11: Profit/(Loss) after Tax and Finance Charges, Auki

Profit/(Loss) After Tax and Finance Charges, Auki $25.00

$20.00

$15.00

With Hydro $10.00 All Diesel

$5.00

$- 2010 2011 2012 2013 2028 2029 2030 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

$(5.00)

FIRR Analysis The FIRR analysis which is based on avoided cost for diesel fuel also shows promising results. In a comparison of ‘with project’ (hydropower) and ‘without project’ (all-diesel) scenarios, the financial internal rate of return (FIRR) of hydropower investment is evaluated at 34.7%, greatly exceeding the WACC of 5.0%, with a financial net present value (FNPV, discounted at a rate equal to the WACC) of SBD 142.6 million. The high financial performance is due almost entirely to the avoidance of diesel fuel costs, which are 100% displaced by the hydro scheme. The full FIRR/FNPV analysis table is presented in the Annex. Sensitivity analysis has been carried out for increases in costs (capital and O&M) and decreases in benefits (reduction in the rate of real growth in diesel fuel prices, reduction in average annual hydro output, and reduced load forecast). The hydro option was found to be highly robust to changes in any of these parameters, and to an adverse change in all of them simultaneously, as shown in Table 7.9.

Table 7.9: Sensitivity Analysis, Auki

Test Switching Variation Sensitivity Basecase Switching Value Test Case (+/- %) FNPV FIRR Indicator Parameter Value (+/-%) Base (reference case) 142.56 34.7% Increases in Costs 1. Capital Cost (SBD m) 20% 133.77 29.2% 0.31 33.43 141.84 324.3% 2. Hydro O&M Cost (SBD/kWh) 20% 141.85 34.6% 0.03 0.08 3.28 3999.6% Decrease in Benefits 3. Diesel Fuel Cost (real increase/annum) -20% 132.86 33.7% 0.34 3.0% 0.0% -100.0% 4. Hydro Output (capacity factor) -20% 142.55 34.7% 0.00 96.7% 9.4% -90.3% 5. Load Forecast -20% 126.43 33.0% 0.57 4.0% 0.0% -100.0% Initial Costs Increased (+) and Benefits Decreased (-) 20% 108.26 26.6% FNPV = financial net present value, FIRR = financial internal rate of return

The Sensitivity Indicator (SI) is an index of sensitivity, useful for the comparison of the sensitivity of one parameter with another (the higher the index, the higher the sensitivity; an SI of 2.0, say, in the capital cost parameter indicates that a 10% increase in capital cost results in a 20% decrease in the FNPV). The Switching Value (SV) of each parameter is a calculation of the level of the parameter that would result in an FNPV of zero. As Table 7.9

31/25866 February 12 Page 53 TA 7329- Promoting Access to Renewable Energy in the Pacific CNO – PRE-FEASIBILITY STUDIES shows the Fiu project is robust over a wide range of assumptions and should therefore be subjected to a full feasibility study.

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8. Lata, Temotu

8.1 The Lata Power System Lata is the capital of Solomon Islands’ easternmost Temotu province. It is located on the main island of Santa Cruz. There are numerous outlying islands including Reef Island, Duff Islands, Tikopia, Utupua and Vanikoro. 2009 census data are not yet available but according to a recent survey conducted by a Malaria project, Santa Cruz Island has a total population of 9,500. Lata and the adjacent settlements accessible through the existing road network have a population of 3,864 living in approximately 670 households as displayed in Table 8.1.

Table 8.1: Population, Lata

Zone Location Population Households

1 West Lata 622 100

2 Lata Central 1,120 200

3 North Lata 238 50

4 Gracious Bay 1,884 320

Total 3,864 670

Infrastructure services in Lata include a central water supply with a pumping station located at the Southern end of Gracious Bay, landline and cell phone communication, a rural hospital, a police post, schools and basic government services. Internet services are provided at the Telecom head office. A rural internet café operating a V-sat station on solar power in the Gracious Bay area was funded by the European Union and provides comparatively good bandwidth. Lata is serviced by Solomon Airlines with an average of two flights a week; a RAMSI helicopter also calls regularly to supply the RAMSI office. SIEA power supply is restricted to zone 1 (Central Lata) where only 120 customers are connected to the grid. I.e. only 21% of the potential customers within the service area of the SIEA power plant are connected to grid power. At the time of the visit, power quality within the service area was poor with very significant voltage drops experienced at the end of the low voltage feeders. Santa Cruz’s commercial sector consists of timber milling, fisheries and agriculture as primary activities. The forestry sector consists of low level milling using mobile units after large scale clear felling operations by foreign timber companies left very few timber grade trees in accessible areas. In the agricultural sector, the focus of the Ministry of Agriculture is currently on food security. Retailing and construction are also significant activities. Tourism has not been developed, and there are only a few small local guest houses with limited facilities.

Generation Lata’s power house is located in a residential area and consists of an open corrugated iron shed where three high-speed diesel generators (1500 rpm) sit on a concrete slab. At the time of field investigations in March, only unit No 3 (Cummins) was operational. The other two units (Perkins) were dismantled awaiting alternators. In April 2010 the No 3 unit also broke down leaving Lata without SIEA power supply. Dismantling the engine showed

31/25866 February 12 Page 55 TA 7329- Promoting Access to Renewable Energy in the Pacific CNO – PRE-FEASIBILITY STUDIES massive carbon deposits at pistons and cylinder head consistent with the continuous operation of the unit below design loads. SIEA has recently installed two new 140 kW Cummins units in Lata. One of generator sets developed oil pressure problems during the first start up and investigations of the oil sump revealed ground metal residue, probably from a failed bearing. SIEA currently negotiates a solution with the supplier, but the unit is not going to be available for some time.

Table 8.2: Generation Assets - Lata Power Pant

No Model Nameplate Derated Available Total Installed Remarks Rating kW kW kW Hours

1 Cummins GMS 175 140 120 120 1200 2011 Awaiting Repair

2 Cummins GMS 175 140 120 0 0 2011 Break down during commissioning

3 Cummins 103DGE 132 100 0 20,600 2005 Unable to maintain A Voltage

There is no synchronizing board at the powerhouse but there is a double bus bar with switches to allow supply to each of the 3 feeders with any of the existing units. With a present maximum demand of around 70 kW (May 2011), only the new Cummins set is able to supply peak demand. Due to low power quality, present demand is, however, artificially suppressed. The Telecoms station for instance operates their own 30 kVA standby generator during periods of low power quality (voltage, frequency) as telecommunication equipment cannot tolerate the voltage fluctuations experienced in the SIEA system. The standby set automatically isolates the telecoms compound when a set voltage value is reached and switches the 30 kVA unit on.

Load Profile Lata load data show a typical rural load profile on weekends with daily base loads of 30 kW and a peak of 45 kW for two to three hours in the evening. During the week, load conforms to a commercial profile: Base load demand of 35 kW is confined to the early morning hours after which a daytime plateau is reached between 55 and 65 kW. While old the old Cummins 132 kW should be able to supply peak load even after significant de-rating, the station manager reports that it cannot maintain a stable voltage. On the other hand, the new 140 kW unit is typically operating at less than half its rated capacity. This is not conducive to a long engine life and incurs a heavy penalty in specific fuel consumption (SFC). In 2010 the SFC averaged 2.7 kWh per liter and is well below best practice values for small diesel generator sets (3.2 – 3.4 kWh/l).

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Figure 8.1: Load Profiles, Lata

Distribution The existing distribution network in Lata consists of three overhead line feeders powered by the LV (415V AC) generating facility at the SIEA Power House, with feeders 1 and 2 providing power to the town centre’s various commercial, institutional and residential loads. Feeder 3 mostly supplies commercial and institutional loads at the outskirts of Lata. Refer Figure 8.2 below for the existing 415V AC LV distribution single line diagram:

Figure 8.2: Lata Existing 415 V AC LV Distribution Single Line Diagram

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Each of the three distribution feeders typically consists of distribution cross-arm poles carrying four wires of aluminum conductor steel re-enforced (ACSR) bare conductors. Depending on the type of connection (i.e. single phase or three phase), the service line is provided as either a four core or two or three core aerial bundled conductors (ABC) of different size (16 mm2, 25 mm2, or 50 mm2), supported by service line poles of different capacities and connection arrangements. Without the exact records, it was observed that the bare conductors used are either 41.6 mm2 ACSR (Apricot) or 49.5 mm2 ACSR (Apple) bare conductors. SIEA’s current practice uses 77.3 mm2 ACSR (Banana) open conductors for 415V AC backbone distribution network. For future expansions the use of the larger 95 mm2 ABC should now be considered. The existing distribution network suffers from considerable line losses between the generating source and the consumer terminals, due to the length of the distribution lines. This in turn results in unacceptable voltage drops in the entire network. The switching of any electrical equipment at different points within the network is also causing a significant amount of voltage fluctuations that can have a detrimental effect on the operation of electrical equipment connected to the network. There are no records of how the distribution network was designed or if a load flow analysis has been performed. Single phase voltage level measurements at different points within the network found values of less than 200V AC, 20 % less than the standard in a healthy distribution network. Technical distribution losses are estimated to be approximately 30%. Billing data from 2010 show 129 active customers in the Lata system of which nine are three phase (415V AC) type used by the institutional, industrial or commercial consumers and the rest are single phase (240V AC) type used by several commercial and all residential consumers. Meter readings are sent to SIEA headquarters where the billing system generates invoices which are sent back to Lata. Consultations with SIEA customers suggest that this system is believed to incur billing errors on a regular basis.

Financial Status SIEA Lata Being the most remote and currently one of the smallest of SIEA’s outstations, Lata is subject to high costs and has consistently made financial losses on operations, as shown in Annex 8. Financial losses are also due in part to a chronically low rate of revenue collections—it is understood that until recently collections were very poorly enforced and this allowed most consumers in Lata to build up considerable arrears. (Lata billing data for March 2010 indicates that total arrears held by 129 active consumers exceed SBD 260,000, almost SBD 200,000 of which is held by commercial consumers.) It is a credit to current SIEA management in Lata, however, that collection rates have of late been improving and the overhang of arrears is gradually being drawn down. SIEA’s planned prepayment metering program for all outstations is especially timely in Lata’s case and will reduce losses much further in the short term. As discussed elsewhere in this report, the current LV distribution system in Lata severely restricts the spatial extent of electricity distribution, leaving the majority of the population in the surrounding communities unserved (currently active domestic consumers, for example, number only 74 in the March 2010 billing records, whereas it estimated that up to 550 households could be connected if the distribution system were upgraded to 11 kV as recommended).

8.2 Lata Load Forecast Lata is one of SIEA’s smallest systems, mainly because of the limited capacity of the distribution system to serve that relatively highly populated area of Temotu Province. The recommended upgrade of the Lata power system to an 11 kV distribution network and increased generation capacity will permit a very substantial increase in connected load,

31/25866 February 12 Page 58 TA 7329- Promoting Access to Renewable Energy in the Pacific CNO – PRE-FEASIBILITY STUDIES potentially raising the number of domestic connections by more than a factor of 7 and nearly tripling domestic consumption by 2012, while about doubling commercial load. Table 8.3 below summarizes the major new loads expected in Lata once the power system is upgraded. The following load forecast for the Lata system is based on the assumption that power quality can be improved to a level that institutional customers such as telecoms and fisheries department would not have to operate their own generators. It is also assumed that a system expansion based on Option B described below is implemented.

Table 8.3: New Loads expected in Lata following System Upgarde

Consumption Connec- Power Per First First New Domestic and Commercial tions Demand Day Year Year Loads (No) (kW) (kWh) (kWh) Online Church of Melanesia 1 12.00 21 7,665 2012 Water Pump 1 18.50 100 36,500 2011 S I Broadcasting 1 12.00 96 35,040 2011 S I Telekom 1 30.00 82 30,000 2011 Fisheries 1 3.00 36 13,140 2011 CNO Mill (Maximum Consumption) 1 30.00 240 57,600 2014 New Domestic Connections 470 0.10 0.79 135,868 2011 Note: for new domestic connections, the power demand and daily kWh consumption are per household.

Existing loads are expected to grow at 4% per year.19 The Lata system load forecast, estimation of generation requirements, projected diesel fuel requirements and a schedule of new generation capacity installations required to meet load demand over the 20-year planning period are summarised in Table 8.4 overleaf. It is noted that the proposed system upgrade in Lata will greatly improve the overall efficiency of the system, which presently suffers from high line losses due to the heavily overloaded LV distribution system and low thermal efficiency of the diesel generators.

Figure 8.3: Lata Power System Load Forecast

Lata Power System Load Forecast 1,200,000

1,000,000

800,000

600,000 Sales to Commercial kWh Sales to Domestic Station and Line Losses 400,000

200,000

-

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

19 Review of SIEA Base Tariff, Ridgway PIEPSAP 2007

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A proposed 107 kW hydropower scheme adjacent to Lata would provide 791 MWh of electricity per year to Lata and environs, at an initial cost of US$ 2,169,000. The project is assumed to be commissioned in 2014, with hydro output reaching its maximum in 2025. When commissioned, the hydro scheme will not be quite sufficient to supply the entire load in Lata, and increasing amounts of diesel generation to top up supply will be required through the planning period. The proposed hydro scheme would displace initially 98% of the need for diesel generation in Lata immediately after it is commissioned, declining to about 73% by 2030 as illustrated in Figure 8.4.

Figure 8.4: Generation Mix Lata with Hydro

Lata Generation Mix 1,200,000

1,000,000

800,000

600,000 Diesel

kWh/year Hydro

400,000

200,000

- 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

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Table 8.4: Lata System Load Forecast, Generation Requirements, Fuel Requirements, and Generator Scheduling

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 8 Load Forecast AAGR Sales = 7.91% Electricity Sales (kWh) Existing Domestic (2010) 67,572 70,275 73,086 76,009 79,050 82,212 85,500 88,920 92,477 96,176 100,023 104,024 108,185 112,512 117,013 121,693 126,561 131,624 136,888 142,364 148,059 New Domestic - - 135,868 141,302 146,954 152,833 158,946 165,304 171,916 178,792 185,944 193,382 201,117 209,162 217,528 226,230 235,279 244,690 254,477 264,657 275,243 Existing Commercial (2010) 150,864 156,899 163,175 169,701 176,490 183,549 190,891 198,527 206,468 214,727 223,316 232,248 241,538 251,200 261,248 271,698 282,565 293,868 305,623 317,848 330,562 New Commercial - - 122,345 127,239 132,328 137,621 143,126 148,851 154,805 160,998 167,438 174,135 181,100 188,345 195,878 203,713 211,862 220,336 229,150 238,316 247,849 Total Sales 218,436 227,173 494,473 514,252 534,822 556,215 578,463 601,602 625,666 650,693 676,720 703,789 731,941 761,218 791,667 823,334 856,267 890,518 926,139 963,184 1,001,712

Sales to Domestic 67,572 70,275 208,953 217,312 226,004 235,044 244,446 254,224 264,393 274,969 285,967 297,406 309,302 321,674 334,541 347,923 361,840 376,313 391,366 407,021 423,301 Sales to Commercial 150,864 156,899 285,520 296,940 308,818 321,171 334,017 347,378 361,273 375,724 390,753 406,383 422,639 439,544 457,126 475,411 494,427 514,204 534,773 556,164 578,410 Station and Line Losses 100,449 104,467 42,998 44,718 46,506 48,367 50,301 52,313 54,406 56,582 58,845 61,199 63,647 66,193 68,841 71,594 74,458 77,436 80,534 83,755 87,105

Load Factor 0.70 0.69 0.67 0.66 0.64 0.63 0.61 0.60 0.58 0.57 0.55 0.54 0.52 0.51 0.49 0.48 0.46 0.45 0.43 0.42 0.40

AAGR Generation = 6.33% Generation Requirement (kWh) 318,885 331,640 537,471 558,969 581,328 604,581 628,765 653,915 680,072 707,275 735,566 764,988 795,588 827,411 860,508 894,928 930,725 967,954 1,006,672 1,046,939 1,088,817 Station and Line Losses (kWh) 100,449 104,467 42,998 44,718 46,506 48,367 50,301 52,313 54,406 56,582 58,845 61,199 63,647 66,193 68,841 71,594 74,458 77,436 80,534 83,755 87,105 Peak Demand (kW) 52.00 55.27 91.57 97.42 103.69 110.43 117.67 125.46 133.85 142.90 152.67 163.23 174.65 187.04 200.47 215.08 230.97 248.31 267.25 287.98 310.74 Required Capacity with Reserve (kW) 67.60 71.85 119.05 126.64 134.80 143.55 152.97 163.10 174.01 185.77 198.47 212.20 227.05 243.15 260.61 279.60 300.26 322.80 347.42 374.38 403.96 Fuel Required, All-Diesel Scenario (litres) 127,554 132,656 177,365 184,460 191,838 199,512 207,492 215,792 224,424 233,401 242,737 252,446 262,544 273,046 283,968 295,326 307,139 319,425 332,202 345,490 359,310

9 Hydro Scenario Generation Calculation Generation Mix with hydro (kWh/year) Hydro - - - - 571,551 589,888 608,785 628,247 648,277 668,874 690,033 711,748 734,007 756,792 780,080 791,004 791,004 791,004 791,004 791,004 791,004 Diesel 318,885 331,640 537,471 558,969 9,777 14,694 19,980 25,668 31,794 38,401 45,532 53,240 61,581 70,619 80,428 103,924 139,721 176,950 215,668 255,935 297,813 Fuel Required, Hydro Scenario (litres) 127,554 132,656 177,365 184,460 3,226 4,849 6,593 8,470 10,492 12,672 15,026 17,569 20,322 23,304 26,541 34,295 46,108 58,393 71,170 84,459 98,278 Fuel Saved by Hydro (litres) - - - - 188,612 194,663 200,899 207,322 213,932 220,728 227,711 234,877 242,222 249,741 257,426 261,031 261,031 261,031 261,031 261,031 261,031

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 10 Diesel Generator Scheduling Unit 1 (existing) 100 100 100 100 100 100 100 100 100 100 100 Unit 2 (new) 100 100 100 100 100 100 100 100 100 100 Unit 3 (new) 100 100 100 100 100 100 100 100 100 100 Unit 4 (new) 100 100 100 100 100 100 100 100 100 100 Unit 5 (new) 100 100 100 100 100 100 100 100 100 100 Unit 6 (new) 100 100 100 100 100 100 100 100 100 100 Unit 7 (new) 100 100 100 100 100 100 100 Total Installed Capacity (kW) 100 300 300 300 300 300 300 300 300 300 300 300 300 300 400 400 400 400 400 400 400 Firm Capacity Available 0 200 200 200 200 200 200 200 200 200 200 200 200 200 300 300 300 300 300 300 300 Memo: Units Added Small Units (100 kW) - 2 ------3 - - 1 ------Large Units (100 kW) ------

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8.3 System Expansion Planning Lata At present SIEA has no detailed long term expansion plans for their outer island stations. The expansion planning performed below aims to develop such long-range plans based on the analysis of unserved demand and associated load forecasts. While long range expansion planning is a standard practice of power utilities, it should be noted that the forecasts underlying such plans need to be regularly verified and revised if necessary. It is assumed that SIEA and GSI will actively pursue existing opportunities to expand supply areas and develops biofuel and/or mini hydro where the potential exists. If diesel supply is continued, the Lata power system requires a complete refurbishing including powerhouse, generators and most importantly distribution. The current low voltage distribution system does not allow any further expansion; it already incurs technical losses above 30%. The power quality is unacceptable due to voltage drops (down to 190 V at consumer level) and significant voltage fluctuations. In the following it is assumed that funding can be mobilized to install a 11 kV distribution system that covers the current supply area and includes supply to Gracious Bay (water pumping station, schools, residential homes) and to West Lata.

Generation In 2011 SIEA has installed two new 140 kW units at the Lata powerhouse. They replace the two 17 year old Perkins units and operate together with the existing 132 kW Cummins. At present loads, each of the two new generators would be able to supply demand. If load cannot be expanded through improvements in the distribution system the generators would not be adequately loaded and hence would operate at relatively high specific fuel consumption. Under a purely thermal scenario (either diesel or CNO) the next diesel set would have to be installed in 2016, typically another 140 kW unit in order to standardize. Figure 8.5 depicts the changes in installed capacity, firm capacity (capacity minus largest generator set), and peak load implied by the load forecast for Lata. It is assumed that high speed generators are retired after 10 years of base load service and replaced in such a way that a) an acceptable loading (>60%) of the sets is ensured and b) a high level of standardization is achieved (i.e. size variety of generator set is minimized).

Figure 8.5: Lata Peak Load, Installed Capcity and Firm Capacity

Lata Capacity Requirements 700

600

Hydro 500

400 Peak Demand (kW) kW 300 Firm Capacity Available Total Installed Capacity (kW)

200

100

-

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

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For the load forecast above to materialize, the distribution system had to be expanded in line with the recommendations in the following section. The expansion of the supply area would also bring a 11 kV close to the hydro site identified.

Grid Extension and Upgrade The Lata distribution system needs to be upgraded to 11 kV in order to enable SIEA to reduce distribution losses, provide an acceptable power quality to its customers, supply suppressed demand and expand the system to unserved areas. There are two options for such an expansion. Option A would involve upgrading of the existing distribution infrastructure to 11kV without any further expansion. This option would reduce line losses considerably and would allow supplying customers that currently generate their own power due to poor quality of SIEA power. With higher loads in the system, better generator loading could be achieved extending lifetime of engines and reducing specific fuel consumption to acceptable levels. Option B would involve expanding SIEA’s service area considerably beyond its current boundaries to the Gracious Bay and North Lata areas where up to 500 new connections could be established. This upgrade would allow the use of CNO due to considerable increase in loads and would also facilitate the development of the hydropower site identified close to the Southern end point of the new line. Option B is preferable, as it would significantly enhance Lata’s infrastructure, reduce overall cost for energy supply and provide opportunities for economic and social development that are currently out of reach. The two options are not mutually exclusive and a phased approach could be taken if funding constraints dictated such an approach. However, the implementation of Option B is a precondition to the development of the hydro scheme. Annex 4 presents the design of the two options.

Table 8.5: Distribution Cost Summary Option B

Table 8.5 summarizes costing for the Lata system expansion. Specific connection costs are nearly US$ 2,000 per customer.

Financial Performance SIEA Lata Being the most remote and currently one of the smallest of SIEA’s outstations, Lata is subject to high costs and has consistently made financial losses on operations, and this will continue under the current projections in the absence of a real tariff increase. In common with most other outstations, financial losses are also due in part to a chronically poor rate of revenue collections. (Lata billing data for March 2010 indicate that total arrears held by 129 active consumers exceed SBD 260,000, almost SBD 200,000 of which is held by commercial consumers.) SIEA’s planned prepayment metering program for all outstations which will improve revenue collections and eliminate bad debts is especially timely in Lata’s case and will reduce losses much further in the short term.

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8.4 Hydro Options for Lata There are several rivers on the main island of Santa Cruz that have hydro potential. From a pure supply perspective, among a high head site at Noka at the eastern end of the Island might be the most attractive. Unfortunately, most of the rivers in the higher mountains of Eastern Santa Cruz are just too far from the demand centre Lata to be viable options. In the absence of any roads on the Eastern part of the island costs for transmission lines and infrastructure would be extremely high. There is also no demand that could be served in the Eastern part of the island. The JICA Masterplan Study of 2001 identified a hydropower site on the Luembalele river which drains into Gracious Bay close to the end point of the proposed 11 kV distribution line. Based on previous work by GSI Geology Department and GTZ the JICA study provides a preliminary design and cost estimates for the development of the site. The key data for the project are:

Catchment Area: 2.4 km2 Rainfall: 4270 mm/year Head: 35 meters Type: Run off river, reverse pump or cross flow turbine Penstock: 203 m, 400mm diameter Access road: 2.8 km Discharge: 0.24 m3/sec (at 90 % probability) Capacity: 50 kW Energy: 432,000 kWh/year Cost US$: 4,117,000 (Civil works 2,250,000; Transmission line 1,200,000)

Due to the very high specific cost estimate (82,000 US$/kW) the project was not considered economically viable. GHD has surveyed the Luembalele river and has reviewed design and costing for this scheme. The results are presented below.

8.5 General Description Luembalele The general surface geology of the Luembalele River is characterized mainly by limestone formations on the lower part of the river. In the upper part of the catchment solid boulders and pebbles become the dominant geological characteristic of the river. In general landscape and topography in the vicinity of Lata is not very suitable for hydropower development. There are no distinct valley and ridges, rather flat terrain with the watercourses typically cut deep into the limestone forming canyons. These conditions pose challenges in the design of inexpensive intake structures. There are also no natural canal alignments along the rivers. Sink holes which create sub-terrain flow and transfer water from one catchment to another via underground tunnels have also been observed.

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Picture 8.1: Luembelele River, Santa Cruz

Figure 8.6: Location of Luembelele Hydro Site

Demand Centre

Hydro Site

8.6 Hydrology Rainfall is recorded at a met station in Lata at an elevation of 15 meter. At this location the annual rainfall for the preriod 1970-2010 averages at about 4,350 mm. Adjustments have to be made in order to allow for location and orientation of the catchment area for the project. The catchment size is 6.28 km2 with an average elevation of 266 meter. The catchment is oriented towards south (SW-S-SE). Using the change in rainfall pattern observed on the south coast of Guadalcanal an increase of 6.14 mm/year/m elevation increase is assumed. This results in an average annual rainfall of 5,891 mm/year. If evaporation losses are assumed to be in line with those observed for Guadalcanal (2,184 mm/year) the net average annual runoff would be 3,707 mm/year or 429 litres. The average monthly rainfall figures are pretty stable over the year with 30% higher the first 3 months than the rest of the year. In the absence of detailed data showing long term variations it is not possible to establish flow duration curves for the Luembalele. Instead the shape of the duration curve from Lungga Gorge is used, which is considered a conservative assumption for this site. Figure 8.7 below displays the assumed flow duration curve for the Luembelele project.

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Figure 8.7: Assumed Flow Duration Curve for Luembelele

1.400 1.200 1.000 Flow Duration Curve Assumed for Luembalele River Intake 0.800

M3/s 0.600 0.400 0.200 0.000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % of time flow exceding

8.7 System Layout At elevation160 meter a site has been identified were the form of the riverbed allows the construction of an intake. The canal alignment from the intake, unfortunately, moves away from the river quite rapidly creating a canal of 1,160 meters length. This in turn requires a comparatively long penstock of 740 meter that would bring the water back to river and to the powerhouse. Although there is a network of old logging roads leading to the site, these roads need considerable improvement and some new construction in order to access intake, forebay and power house site.

Figure 8.8: System Layout

The plant here is a typical large micro hydro installation and should be installed like that. It is to be installed without traditional hydro/mechanical governor, but instead with a simple electronic governor, which uses dump loads to adjust the voltage. This may typically be in the dispatch center, where the back-up diesel installation may be available too. The spears in the nozzles on the turbine may be controlled by the water level at the forebay, so that it does not suck in air

31/25866 February 12 Page 66 TA 7329- Promoting Access to Renewable Energy in the Pacific CNO – PRE-FEASIBILITY STUDIES with falling water flow. It is assumed provided with a synchronous generator. Table 8.6 summarizes the details. Two types of turbines are available for these conditions, one is horizontal Turgo tubines with 1 jet up to 300 l/s and 2 jet above and the other is a cross flow turbine. The last has typically about 10% less efficiency and with the large investment in penstock on this project, it is not economic to use the cheaper cross flow turbine here. The Turgo is the most robust turbine type on the market.

Table 8.6: General Information - Luembelele Hydro Plant

Intake coordinates 58 L 595,497 m E 8,810,684 m S

Powerhouse coordinates 58 L 594,377 m E 8,810,000 m S

Catchment area km2 6.28

Penstock Length 740 m

Installed Capacity kW 107

Max Annual Energy kWh 791,000

Access Road construction 8000 m

Gross head 54 m

Canal Length 1160 m

11 kV Power Extraction 11.2 km

The hydro site in Lata could be developed up to an installed capacity of approx 300 kW if all water is used. The GWh yield per installed kW would however drop significantly and no environmental flow would remain in the river. In the following the 107 kW variant is analysed for its financial performance.

Table 8.7: Variations

Plant Water GWh/yr Qdesign/ Qdesign Pdesign avail- Utili- Power- Net Turbine Qavg m3/s kW ability zation house GWh/yr

Hor. 1-jet Turgo 50% 0.215 68 97% 46% 0.573 0.573

Hor. 2-jet Turgo 75% 0.322 107 85% 62% 0.792 0.791

Hor. 2-jet Turgo 100% 0.429 147 75% 74% 0.963 0.962

Hor. 2-jet Turgo 125% 0.536 187 67% 82% 1.095 1.093

Hor. 2-jet Turgo 150% 0.644 227 60% 88% 1.190 1.188

Hor. 2-jet Turgo 200% 0.858 307 46% 95% 1.251 1.247

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Canal Qdesign Slope Canal Penstock Penstock m3/s m/km H m loss % Diam m

0.246 2.16 0.38 15.50% 0.37

0.340 1.93 0.45 12.28% 0.45

0.413 1.79 0.50 10.48% 0.52

0.469 1.68 0.55 9.29% 0.58

0.510 1.60 0.60 8.45% 0.63

0.535 1.48 0.68 7.30% 0.73

8.8 Cost Estimates The cost estimates provided below are for the 107 kW hydro component alone, i.e. they include only an 11 kV extraction line up to the point of the drinking water supply station located at the Southern end of the Gracious Bay area. In order to transport electricity generated from the hydro plant to Lata’s demand center the 11 kV line described above needs to be constructed as well at a cost of approximately 1.1 million US$.

Table 8.8: Cost Estimates 107 kW Hydro Scheme Item US$ SB$ Feasibility Study 33,000 264,000 Development 39,000 312,000 Engineering 73,000 584,000 Hydro turbine 179,000 1,432,000 Road construction 55,000 440,000 Transmission line 104,000 832,000 Substation 10,000 80,000 Penstock 288,000 2,304,000 Canal 68,000 544,000 Other Civ Eng 261,000 2,088,000 Rural Electrification 1,059,000 8,472,000 Total Investment 2,169,000 17,352,000 say $ 2.2 Million

The Cost Estimates presented here have been prepared for the purpose of prioritizing sites for further investigation and should not be used for any other purpose. They are subject to the limitations described in Section 1.4. Further detailed investigations, including geotechnical and hydrological investigations, would be required to firm up the cost estimates for budget setting purposes.

8.9 Financial Analysis In comparison with the all-diesel scenario for Lata, the hydropower scenario results in significantly reduced costs and much higher profitability under the current tariff (transforming a loss-making centre into a profitable one) as illustrated in the following three Figures. The detailed financial projections for Lata are shown in the Annex.

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Figure 8.9: Revenue vs Expenses Lata Hydro

Revenues vs Operating Expenses, Lata Hydro Scenario $8.000 $7.000 $6.000 $5.000 $4.000 Revenues $3.000 SBD millionsSBD Expenses $2.000 $1.000 $-

Figure 8.10: Revenue vs Expenses Lata All Diesel

Revenues vs Operating Expenses, Lata All-Diesel Scenario $8.000 $7.000 $6.000 $5.000 $4.000 Revenues $3.000 SBD millionsSBD Expenses $2.000 $1.000 $-

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Figure 8.11: Lata Profit and Loss Diesel and Hydro

Profit/(Loss) After Tax and Finance Charges, Lata $2.50

$2.00

$1.50

$1.00

With Hydro $0.50 All Diesel SBD Million SBD

$- 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

$(0.50)

$(1.00)

$(1.50)

FIRR Analysis In a comparison of ‘with project’ (hydropower) and ‘without project’ (all-diesel) scenarios, the financial internal rate of return (FIRR) of hydropower investment is evaluated at 13.2%, exceeding the WACC of 5.0%, with a financial net present value (FNPV, discounted at a rate equal to the WACC) of SBD 14.7 million. The full FIRR/FNPV analysis table is presented in the Annex. Sensitivity analysis has been carried out for increases in costs (capital and O&M) and decreases in benefits (reduction in the rate of real growth in diesel fuel prices, reduction in average annual hydro output, and reduced load forecast). The hydro option was found to be robust to changes in any of these parameters, and to an adverse change in all of them simultaneously, as shown in Table 8.9. The financial viability of the proposed hydro scheme is most sensitive to a reduction in the load forecast, followed by an increase in capital costs, followed by a reduction in hydro output.

Table 8.9: Sensitivity Analysis Test Basecase Switching Variation Sensitivity Para- Switching Value Test Case (+/- %) FNPV FIRR Indicator meter Value (+/-%) Base (reference case) 14.69 13.2% Incre a se s in Costs 1. Capital Cost (SBD m) 20% 10.13 10.0% 1.55 17.35 28.53 64.4% 2. Hydro O&M Cost (SBD/kWh) 20% 14.57 13.1% 0.04 0.08 1.96 2346.9% Decrease in Benefits 3. Diesel Fuel Cost (real increase/annum) -20% 12.72 12.3% 0.67 3.0% 0.0% -100.0% 4. Hydro Output (capacity factor) -20% 10.20 11.3% 1.53 84.4% 45.7% -45.9% 5. Load Forecast -20% 9.60 10.6% 1.73 4.0% 1.8% -55.7% Initial Costs Increased (+) and Benefits Decreased (-) 20% 1.83 6.0% FNPV = financial net present value, FIRR = financial internal rate of return

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9. Ringgi, Noro and Munda, Western Province

In the western province a hydro site has been identified that has the capacity to supply both the forest company located at Ringi and the SIEA system of Noro and Munda through an undersea cable.

9.1 The Noro/Munda Power System Noro is the industrial centre of the Western province. It is located on the North coast of the island of New Georgia, approximately 50 km East of the provincial capital Gizo. The town features a deep-water harbour with storage facilities on the wharf. Several tuna fishing vessels operate out of Noro and the there is a tuna processing/canning factory. (Soltai) Noro harbour is used for transhipment of timber from logging operations in the area. Munda is located at New Gerogia’s South coast and is connected by a paved road of 16 km to Noro. Munda has a small tourism industry and its airstrip is the gateway to New Georgia. Population estimates for Noro and Munda are 4,500 and 3,000 respectively. Infrastructure services in Noro and Munda include a central water supply, landline and cell phone communication, a rural hospital, a police post, post office, schools and basic government services. Internet services are provided at the Telecom head office. Munda air services are combined with Gizo with several flights a day. Both towns have banking facilities.

Generation Munda and Noro’s electricity supply is provided from the SIEA diesel power generator located on the waterfront at Noro, approximately 1km west of the main port area and adjacent to the Soltai complex, historically the major load centre of the power system. The SIEA powerhouse was build in 1987 and is equipped with 3 medium speed WA Allen diesel generators, also installed in 1987. Power is generated at 11 kV. There is also a 250 kW Detroit stand-by generator in a small shed close to Munda airstrip, which is used to in case of a failure of the 11 kV transmission line between Noro and Munda. Current records are inconclusive with respect to engine hours on the three W.A. Allen sets but it is likely that the sets all have total hours in excess of 60,000 as shown in Table 9.2. The only set in operation is No 2. Set No 1 awaits an overhaul kit for the cylinder heads. Set No 3 has not been operated since 2001 and has been stripped for spare parts. Its wiring is has been heavily corroded and the set is clearly beyond repair. Due to considerable wear the sets only supply a fraction of their nameplate rating. No. 2 can supply a maximum of 400 kW (nameplate 1200 kW). Replacement of the sets would have been due in 2002 and it is unlikely that overhauling these units will result in a reliable and efficient supply.

Figure 9.1: Load Profiles Noro on Two Consecutive Weekdays

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Due to these severe supply constraints SIEA has to cut off the main feeder No 1 (2,000 kVA) to the cannery factory from 10 p.m. to 7 a.m. This is necessary to reduce the load to a level the single generator in operation can provide. The dominance of the fish cannery as a customer and the need to respond to demand increases of the Soltai factory with load shedding creates a somewhat erratic load shape that shows no pattern at all. The August 2010 fuel efficiency calculated on the basis of Noro station records was 3.42 kWh/l and surprisingly high. The poor state of repair of the Noro generators, the low loads and the significant de-rating of the operational No 2 set would suggest a lower efficiency. Again, recording errors and data inconsistency were evident at the station and the results are not considered suitable for planning or decision making purposes. The Noro generators are directly connected to a single 11kV switchboard which supplies the Noro/Munda distribution system via three 11kV overhead feeders (Feeders No. 1, 2 and 3) and one 11kV underground feeder (Feeder No.4).

Distribution The current SIEA electricity supply to the Noro town covers the area; running along the harbour foreshore and up to the fuel terminal, 1.5 km to the west of the main port area, the Baru residential area, approximately 1.5 km to the east of the port area. Power supply also extends approximately 1 km inland to residential and commercial consumers along the main road. Power is distributed to consumers in Noro via a combination of overhead 11kV feeders, and several 11kV/415 substations, and overhead and underground 4-wire 415V/240V (LV) circuits. In Noro almost all existing residential and commercial loads are connected to the SIEA grid. In Munda the supply area includes the foreshore up the hospital, approximately 2.5 km to the west of the town centre a residential area, approximately 700 m to the east of the town centre, and extends approximately a few hundred metres north of the airstrip. The supply also extends slightly to Munda via a 17 km 11kV underground cable. Half way between Noro and Munda a SIWA pumping station is supplied by SIEA. The billing records for August 2010 indicate that there are 396 and 358 connections in Noro and Munda respectively (total 754), of which 298 and 253 respectively are domestic (total 551) and 98 and 105 respectively are commercial, industrial, and government (total 203). Presently about three-quarters of total electricity consumption in the two centres combined is industrial/commercial, and only about 25 percent is domestic. Peak demand is presently about 400 kW, but would be much greater if all loads could connect to the public supply (not possible now because generating capacity in the SIEA is severely constrained).

Ringgi Power System Ringgi on Kolombangara Island in Western Province is the site of a forestry plantation operated by the Kolombangara Forest Products Ltd (KFPL), a joint venture of the Solomon Islands Government and the Tropical Timber Fund. KFPL presently provide for their own power needs by a diesel power plant, which supplies electricity to both KFPL commercial operations and to the community of KFPL workers and their families who live in the area. Power development on the island has been undertaken by KFPL which operates a small diesel powered grid. The current electrical power demand for Ringgi is supplied from a Caterpillar 320 model of 240 kW rating. In addition a 200 kW Cummins machine is available but mostly used as a backup unit.

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9.2 Load Forecast

Noro and Munda Noro-Munda is the second largest SIEA power centre after Honiara. Noro is an international port with deep water, and is strategically placed as a centre for industrial development. Noro receives direct fuel shipments from overseas and thus Noro (and Munda, connected via power and road to Noro) faces no domestic fuel transport costs. With industrial growth, it is expected that the population and number of households connected to the power system will increase greatly. The SIEA power supply in Noro is, however, in a derelict condition. A large fish processing factory (Soltai) is rapidly increasing production following a lengthy downturn earlier in this decade, and reports that they will have a maximum demand of approximately 1 MW once their expansion plans are fulfilled. There is presently no way that such a load could be accommodated by the public supply. The provincial government with support from the Ministry of Commerce is pursuing a new industrial development for which 44 lots have been allocated North of the fuel depot. In order to supply all designated lots of this new development an extension of the SIEA system by approximately 700 meters would be required. Only one lot of this new industrial estate is currently under development (a sheet metal factory) and has been connected to the SIEA system. According to a preliminary development plan, the new industrial area is supposed to attract a variety of industries including metal and woodworking, mechanical repair shops, construction companies, food processing and similar businesses. It is difficult to predict time lines for development at this stage but the fact that one factory is already being developed supports a scenario whereby the area will eventually see some investments. At this stage generic assumptions for loads and energy of new developments are being made: Each site would on average start with an annual peak power demand of 15 kW and a power factor of 20% resulting in an annual energy demand of 26,280 kWh per year in the first year of operation. It is further assumed that each year from 2011 onwards 5 sites come on stream until 2020. At present a Chinese investor is developing a Hotel along the main road in Noro. This development is assumed to have the same characteristic as other industrial developments. In addition there are 12 police houses under development in Noro. The load growth of the new industrial estates is assumed to be 4% p.a. once established. By far the largest demand increase will emerge from the operation and expansion of the Soltai fish processing plant. The factory that employs nearly 800 workers currently processes 60 tonnes of tuna per day and requires 600 kW of load that cannot be supplied by SIEA. According to Soltai’s business plan, the processing target is 150 tonnes per day equivalent of a power need of 1,000 kW at a power factor of 60%. This development alone could increase demand in the Noro system by 5.2 GWh per year. SICE has expressed interest in establishing a CNO mill in Noro. The size of the mill would be determined by the sustainable copra production potential in the Noro catchment area which is estimated at 600 tonnes of dry copra per month. The operation of a new CNO mill with a capacity of 300 kL per months has been assumed. Such a mill would require 396 MWh per year and would have a power factor of 36%. Growth in power demand after establishing the mill is assumed to be 2%.

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Table 9.1: Industrial Demand Growth Noro by end of 2011

Consumption Power Per First New Domestic and Commercial Connec-tions Demand Day Year First Loads (No) (kW) (kWh) (kWh) Year Online New Industrial Zone Enterprises 10 30.00 240 576,000 2012 New Soltai Load 1 850.00 13,600 4,964,000 2012 New Hotels 1 10.00 240 87,600 2012 - - - 2011 Trade Stores 5 3.00 72 86,400 2011 CNO Mill (Maximum Consumption) 1 60.00 480 115,200 2012 New Domestic Connections 200 0.65 5.15 375,804 2012

As shown in Table 9.3, the largest potential load stems from Soltai’s planned expansion of operations (from processing presently 60 tonnes of fish per day to 150 tonnes per day). Existing loads are expected to grow at 4% per year. The new Soltai load is assumed to remain at the indicated level of about 5 GWh per year after the expansion plans are realised.

Ringgi Currently, the KFPL’s workshop and administration centre is the main load centre for the power system during workdays from 7 am – 4pm. Loads during this period are around 80 – 90 kW. After working hours, the load is reduced to the consumption of approximately 50 households that are connected to the low voltage grid. Annually, the generation of KFPL is in the order of 350,000 kWh. However, KFPL management has indicated that the company plans to establish a sawmill at Ringgi in order to add value to their output, which currently consists of unprocessed logs. This development would substantially increase total load to an estimated 700 kW in 2013. Apart from the actual sawmill, the size of the entire operation would have to be increased, more workers would be have to be hired and accommodated and Ringgi would probably see some commercial developments outside KFPL. At an assumed load factor of 0.65 annual generation requirements would than be around 4.3 GWh in 2013.

As the hydro site idendified in Ringgi has the potential to supply both the assumed KFPL load and the load of the SIEA system of Noro and Munda, two variants have been distinguished for the further analysis. Variant A assumes that Ringgi remains an isolated system and only the load on the island has to be met. Variant B assumes an interconnection between the SIEA system Noro/Munda and Ringgi. Variant B therefore combines the load forecasts for the two demand centres. Figure 9.2 below depicts the forecast for the two variants. The tables overleaf show the details of the forecasts.

Figure 9.2: Load Forecasts Variant A and B

Ringgi Generation Mix 9,000,000 Ringgi Power System Load Forecast (Variant B) 30,000,000

8,000,000

25,000,000 7,000,000

6,000,000 20,000,000

5,000,000 Sales to Commercial Diesel 15,000,000 kWh kWh/year 4,000,000 Hydro Sales to Domestic Station and Line Losses 3,000,000 10,000,000

2,000,000 5,000,000

1,000,000

- - 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

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Table 9.2: Ringgi System Load Forecast (Varian A), Generation Requirements, Fuel Requirements and Backup Generator Scheduling

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 8 Load Forecast AAGR Sales = 4.02% Electricity Sales (kWh) Existing Domestic (2011) 1,415,578 1,474,560 1,536,000 1,600,000 1,664,000 1,730,560 1,799,782 1,871,774 1,946,645 2,024,510 2,105,491 2,189,710 2,277,299 2,368,391 2,463,126 2,561,652 2,664,118 2,770,682 2,881,510 2,996,770 3,116,641 New Domestic ------KFPL Consumption (2011) 2,123,366 2,211,840 2,304,000 2,400,000 2,496,000 2,595,840 2,699,674 2,807,661 2,919,967 3,036,766 3,158,236 3,284,566 3,415,948 3,552,586 3,694,690 3,842,477 3,996,176 4,156,023 4,322,264 4,495,155 4,674,961 New Commercial ------Total Sales 3,538,944 3,686,400 3,840,000 4,000,000 4,160,000 4,326,400 4,499,456 4,679,434 4,866,612 5,061,276 5,263,727 5,474,276 5,693,247 5,920,977 6,157,816 6,404,129 6,660,294 6,926,706 7,203,774 7,491,925 7,791,602

Sales to Domestic 1,415,578 1,474,560 1,536,000 1,600,000 1,664,000 1,730,560 1,799,782 1,871,774 1,946,645 2,024,510 2,105,491 2,189,710 2,277,299 2,368,391 2,463,126 2,561,652 2,664,118 2,770,682 2,881,510 2,996,770 3,116,641 Sales to KFPL 2,123,366 2,211,840 2,304,000 2,400,000 2,496,000 2,595,840 2,699,674 2,807,661 2,919,967 3,036,766 3,158,236 3,284,566 3,415,948 3,552,586 3,694,690 3,842,477 3,996,176 4,156,023 4,322,264 4,495,155 4,674,961 Station and Line Losses 307,734 320,557 333,913 347,826 361,739 376,209 391,257 406,907 423,184 440,111 457,715 476,024 495,065 514,868 535,462 556,881 579,156 602,322 626,415 651,472 677,531

Load Factor 0.61 0.63 0.64 0.65 0.67 0.68 0.69 0.71 0.72 0.73 0.75 0.76 0.78 0.79 0.81 0.82 0.84 0.86 0.87 0.89 0.91

AAGR Generation = 4.02% Generation Requirement (kWh) 3,846,678 4,006,957 4,173,913 4,347,826 4,521,739 4,702,609 4,890,713 5,086,342 5,289,795 5,501,387 5,721,443 5,950,300 6,188,312 6,435,845 6,693,279 6,961,010 7,239,450 7,529,028 7,830,189 8,143,397 8,469,133 Station and Line Losses (kWh) 307,734 320,557 333,913 347,826 361,739 376,209 391,257 406,907 423,184 440,111 457,715 476,024 495,065 514,868 535,462 556,881 579,156 602,322 626,415 651,472 677,531 Peak Demand (kW) 658.83 672.28 686.00 700.00 714.00 728.28 742.85 757.70 772.86 788.31 804.08 820.16 836.56 853.30 870.36 887.77 905.52 923.64 942.11 960.95 980.17 Required Capacity with Reserve (kW) 930.96 949.96 969.35 989.13 1,008.91 1,029.09 1,049.67 1,070.67 1,092.08 1,113.92 1,136.20 1,158.92 1,182.10 1,205.74 1,229.86 1,254.46 1,279.55 1,305.14 1,331.24 1,357.86 1,385.02 Fuel Required, All-Diesel Scenario (litres) 1,099,051 1,144,845 1,192,547 1,242,236 1,291,925 1,343,602 1,397,347 1,453,240 1,511,370 1,571,825 1,634,698 1,700,086 1,768,089 1,838,813 1,912,365 1,988,860 2,068,414 2,151,151 2,237,197 2,326,685 2,419,752

9 Hydro Scenario Generation Calculation Generation Mix with hydro (kWh/year) Hydro - - - 4,347,826 4,521,739 4,702,609 4,890,713 5,086,342 5,289,795 5,501,387 5,721,443 5,950,300 6,188,312 6,435,845 6,693,279 6,961,010 7,239,450 7,529,028 7,830,189 8,143,397 8,469,133 Diesel 3,846,678 4,006,957 4,173,913 ------Fuel Required, Hydro Scenario (litres) 1,099,051 1,144,845 1,192,547 ------Fuel Saved by Hydro (litres) - - - 1,242,236 1,291,925 1,343,602 1,397,347 1,453,240 1,511,370 1,571,825 1,634,698 1,700,086 1,768,089 1,838,813 1,912,365 1,988,860 2,068,414 2,151,151 2,237,197 2,326,685 2,419,752

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 10 Diesel Generator Scheduling Unit 1 (existing) 500 500 500 500 500 500 500 500 500 500 500 Unit 2 (new) 500 500 500 500 500 500 500 500 500 500 500 Unit 3 (new) 500 500 500 500 500 500 500 500 500 500 500 Unit 4 (new) 500 500 500 500 500 500 500 500 500 500 Unit 5 (new) 500 500 500 500 500 500 500 500 500 Unit 6 (new) 500 500 500 500 500 500 500 500 500 Unit 7 (new) Total Installed Capacity (kW) 500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 Firm Capacity Available 0 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 Memo: Units Added Small Units (500 kW) - 2 ------1 2 ------Large Units (500 kW) ------

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Table 9.3: Ringgi Noro Munda System Load Forecast (Variant B), Generation Requirements, Fueld Requirements and Backup Generator Scheduling

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 8 Load Forecast AAGR Sales = 4.02% Electricity Sales (kWh) Existing Domestic (2011) 4,600,627 4,792,320 4,992,000 5,200,000 5,408,000 5,624,320 5,849,293 6,083,265 6,326,595 6,579,659 6,842,845 7,116,559 7,401,221 7,697,270 8,005,161 8,325,368 8,658,382 9,004,718 9,364,906 9,739,502 10,129,083 New Domestic ------Existing Commercial (2011) 6,900,941 7,188,480 7,488,000 7,800,000 8,112,000 8,436,480 8,773,939 9,124,897 9,489,893 9,869,488 10,264,268 10,674,839 11,101,832 11,545,905 12,007,742 12,488,051 12,987,573 13,507,076 14,047,359 14,609,254 15,193,624 New Commercial ------Total Sales 11,501,568 11,980,800 12,480,000 13,000,000 13,520,000 14,060,800 14,623,232 15,208,161 15,816,488 16,449,147 17,107,113 17,791,398 18,503,054 19,243,176 20,012,903 20,813,419 21,645,956 22,511,794 23,412,266 24,348,756 25,322,706

Sales to Domestic 4,600,627 4,792,320 4,992,000 5,200,000 5,408,000 5,624,320 5,849,293 6,083,265 6,326,595 6,579,659 6,842,845 7,116,559 7,401,221 7,697,270 8,005,161 8,325,368 8,658,382 9,004,718 9,364,906 9,739,502 10,129,083 Sales to Commercial 6,900,941 7,188,480 7,488,000 7,800,000 8,112,000 8,436,480 8,773,939 9,124,897 9,489,893 9,869,488 10,264,268 10,674,839 11,101,832 11,545,905 12,007,742 12,488,051 12,987,573 13,507,076 14,047,359 14,609,254 15,193,624 Station and Line Losses 1,000,136 1,041,809 1,085,217 1,130,435 1,175,652 1,222,678 1,271,585 1,322,449 1,375,347 1,430,361 1,487,575 1,547,078 1,608,961 1,673,320 1,740,252 1,809,863 1,882,257 1,957,547 2,035,849 2,117,283 2,201,974

Load Factor 0.48 0.49 0.50 0.51 0.52 0.53 0.54 0.55 0.56 0.57 0.59 0.60 0.61 0.62 0.63 0.65 0.66 0.67 0.68 0.70 0.71

AAGR Generation = 4.02% Generation Requirement (kWh) 12,501,704 13,022,609 13,565,217 14,130,435 14,695,652 15,283,478 15,894,817 16,530,610 17,191,834 17,879,508 18,594,688 19,338,476 20,112,015 20,916,495 21,753,155 22,623,281 23,528,213 24,469,341 25,448,115 26,466,039 27,524,681 Station and Line Losses (kWh) 1,000,136 1,041,809 1,085,217 1,130,435 1,175,652 1,222,678 1,271,585 1,322,449 1,375,347 1,430,361 1,487,575 1,547,078 1,608,961 1,673,320 1,740,252 1,809,863 1,882,257 1,957,547 2,035,849 2,117,283 2,201,974 Peak Demand (kW) 2,729.46 2,785.16 2,842.00 2,900.00 2,958.00 3,017.16 3,077.50 3,139.05 3,201.83 3,265.87 3,331.19 3,397.81 3,465.77 3,535.08 3,605.79 3,677.90 3,751.46 3,826.49 3,903.02 3,981.08 4,060.70 Required Capacity with Reserve (kW) 3,856.84 3,935.55 4,015.87 4,097.83 4,179.78 4,263.38 4,348.65 4,435.62 4,524.33 4,614.82 4,707.11 4,801.26 4,897.28 4,995.23 5,095.13 5,197.03 5,300.97 5,406.99 5,515.13 5,625.44 5,737.95 Fuel Required, All-Diesel Scenario (litres) 3,571,916 3,720,745 3,875,776 4,037,267 4,198,758 4,366,708 4,541,376 4,723,031 4,911,953 5,108,431 5,312,768 5,525,279 5,746,290 5,976,142 6,215,187 6,463,795 6,722,346 6,991,240 7,270,890 7,561,726 7,864,195

9 Hydro Scenario Generation Calculation Generation Mix with hydro (kWh/year) Hydro - - - - 14,695,652 15,274,419 15,841,708 16,432,569 17,047,963 17,688,890 18,356,388 19,051,540 19,775,471 20,529,352 21,314,399 22,131,881 22,983,115 23,869,472 24,792,379 25,753,320 26,321,610 Diesel 12,501,704 13,022,609 13,565,217 14,130,435 - 9,059 53,110 98,041 143,872 190,618 238,300 286,935 336,543 387,144 438,756 491,400 545,098 599,869 655,736 712,720 1,203,071 Fuel Required, Hydro Scenario (litres) 3,571,916 3,720,745 3,875,776 4,037,267 - 2,588 15,174 28,012 41,106 54,462 68,086 81,982 96,155 110,612 125,359 140,400 155,742 171,391 187,353 203,634 343,735 Fuel Saved by Hydro (litres) - - - - 4,198,758 4,364,120 4,526,202 4,695,020 4,870,847 5,053,968 5,244,682 5,443,297 5,650,135 5,865,529 6,089,828 6,323,395 6,566,604 6,819,849 7,083,537 7,358,091 7,520,460

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 10 Diesel Generator Scheduling Unit 1 (existing) 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 Unit 2 (new) 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 Unit 3 (new) 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 Unit 4 (new) 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 Unit 5 (new) 2000 2000 2000 2000 2000 2000 2000 2000 2000 2000 2000 2000 2000 2000 2000 2000 2000 Unit 6 (new) 2000 2000 2000 2000 2000 2000 2000 2000 2000 Unit 7 (new) 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 Total Installed Capacity (kW) 1000 4000 4000 4000 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000 Firm Capacity Available 0 3000 3000 3000 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000 Memo: Units Added Small Units (1000 kW) - 3 ------1 ------Large Units (2000 kW) - - - - 1 ------1 ------

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9.3 Noro/Munda System Expansion Planning

Generation In September 2010, available capacity at the SIEA powerhouse was 400 kW. Only one of three 1,200 kW generators was operational derated to a third of its nominal capacity. As a consequence, only a fraction of the demand in the system can currently be met by SIEA. As load approaches 400 kW, the operator disconnects the Soltai cannery feeder and the fish factory starts up one of its three 1,000 kW Mitsubishi sets. All SIEA generators are long overdue for replacement and it is expected that power supply to the Noro/Munda area will further deteriorate if the powerhouse is not refurbished with new generation equipment soon. Lack of reliable power has also become a major obstacle for the implementation of the industrial development plans pursued by the provincial government.20 From the consultant’s perspective, three thermal options exist to secure future power supply in the Noro/Munda system: 1. Upgrade of SIEA generation to meet full future demand 2. Upgrade of SIEA generation to meet future demand exclusive of Soltai cannery 3. Abandon SIEA generation and purchase and distribute power from external generator

The objective of option one would be to establish the Noro/Munda system as a profit centre for SIEA through a comprehensive rehabilitation of the generation. Ideally, this option would include the re-location of the SIEA powerhouse to higher ground in order to protect the facility against damage by seawater in case of storms or a tsunami21 Seawater penetration has already caused damage to the wiring of the powerhouse even without an extreme event. Soltai management has indicated that it would be willing to swap a higher ground plot for the current SIEA location. Based on the load forecast provided in Section 9.4, the powerhouse would be equipped with three sets of 1,500 – 1,800 kW generators in order to provide N-1 redundancy. In order to enhance security of supply further, a special agreement should be established with Soltai which would include a reverse supply from the 3 MW Soltai power station as a back up for SIEA. Such an arrangement would guarantee N-1 redundancy desirable for a system with substantial commercial/industrial load. The generator size for the new powerhouse could be reduced to three synchronized 1,500 rpm 1,000 kW units. Under such an arrangement two generators would have to operate simultaneously, with one unit on stand by. In case of scheduled outages of one engine Soltai’s capacity would be brought in as a reserve. Our costing provided below is based on this least cost arrangement. Option 2 would involve the rehabilitation and development of SIEA’s generation to a level that guarantees reliable power supply for all existing and future demand exclusive of Soltai. Soltai has already considered this option. In a comparative cost analysis, Soltai management discovered that self-generation results in electricity supply cost approximately 25 % lower than SIEA supply. This is surprising as Soltai is charged the uniform national industrial tariff. In addition, Soltai does not enjoy tax-free diesel supply (which SIEA does). However, an examination of Soltai’s claims by the consultant suggests that the company can indeed generate electricity below SIEA supply cost if and when the factory’s loads are above 400 kW at current duty paid supply cost of SB$ 8.38 per litre. Thus, Soltai only buys power from SIEA in low load situations. The reasons for the cost advantage in high load situations are the following: • A well managed and maintained power house allows Soltai to achieve high fuel efficiencies of 3.82 kWh per litre of fuel

20 The Special Provincial Development Officer expressed serious concerns about this issue during consultations with GHD. 21 Such climate proofing is strongly recommended by the consultant

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• Load and generator size are a good match for high load situations (600 kW load for sets with 1000 kW nameplate rating) • There are no transmission and distribution losses • Staff cost are minimal as the operation employs only 3 staff

A complete isolation of Soltai may conflict with the Electricity Act that gives SIEA an excusive right to supply, however, the act may be difficult to enforce as long as SIEA cannot demonstrate that it is able to meet the demand of this industrial client. Soltai is a major employer in the Western province and generates significant foreign exchange for the Solomon Islands. Option 2 would still require SIEA to replace its ageing generators and it would still recommendable to climate proof generation through a relocation of the powerhouse. Option 2 would require the installation of three 1,500 rpm generator sets in the 500 kW class, with subsequent replacements with larger sets in 10 years in line with load growth expected from expansion of the supply area and industrial growth outside Soltai. Option 3 is a fall back position in case SIEA is unable to finance capital investment in Noro. Soltai has indicated that the company would be willing to enter an IPP arrangement with SIEA. Under such an arrangement SIEA would obtain bulk supply from Soltai and be reduced to the role of a distributor of electricity. A long term PPA would be required as Soltai would eventually have to invest in larger generators in order to meet the demand of the system with an acceptable level of redundancy.

Distribution In Munda the existing SIEA 11kV distribution system currently terminates north of the main commercial area and from this point the 415V ABC distribution supplies domestic consumers up to 1,000 meter West from the 11kV end point. Power system studies performed by SKM indicate that the length of the existing 415V system already causes significant voltage drops at the extremities of the line. I.e. there is little room to expand low voltage reticulation further. West of Munda’s main commercial area the 415 supply system ends within 300 meters and leaves an estimated 40 households further West without supply. This area is also a strong candidate for extending the existing network.

Design of Expansion In Munda there are 2 residential low income clusters, which are currently not supplied by SIEA: A small housing cluster to along the shore West of the current supply area (South of the air strip) and a larger cluster to the East of the current supply area. While the western extension could be implemented by extending the existing 415 V supply, the eastern cluster could be connected by extending the 11 kV system in order to avoid unacceptable voltage drops and line losses. In addition, Goldie Island approx 7 km from the SIEA supply area is a potential candidate to be included in the SIEA supply. Currently, approx half of the 80 households on the island are supplied by small private generators. Connecting the island would involve two water crossings one of which is too wide for an overhead line and required an undersea cable. While this may be a long-term option for SIEA, connecting Goldie is currently not considered in the load forecast due to the high cost involved in the installation of an undersea cable. SKM has proposed to extend the existing 11kV system in a ring configuration approximately 2 km east of the main commercial area. This would encompass 4 additional 11kV 415V transformer substations. The proposed system will also remove any existing voltage drop issues. Noro will require a substantial investment to supply power to the new industrial area under development. This will require an extension of SIEA 11 kV grid including several new transformer stations. This expansion should proceed with priority, as the lack of power to the

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9.4 Hydro Options for Western Province Two different hydro sites have been considered for the Noro/Munda/Ringgi area: the Vila river on Kolombangara island and the Mase river on New Georgia. Figure 9.3 depicts these locations. Both projects could be developed either with or without an interconnection by undersea cable. At both sites automatic gauging stations have been installed in order to develop a comprehensive picture of the hydro potential in the Western Province.

Figure 9.3: Mase and Vila Hydro Sites

Vila

Mase

Both projects have the potential to supply a significant share of the power demand in the area. They are however quite distinct in other characteristics. Mase would be a green field project to be constructed in a remote area without any infrastructure. Landowner issues had to addressed and resolved prior to development. In contrast, the Vila project on Kolombangara would not have to address landowner issues as the land belongs to the forest company. In addition, the company already operates all heavy construction equipment that would be necessary for the construction of a mini hydro plant (bulldozers, backhoes, diggers, graders, cranes, flat bed trucks etc). SIEA management on the other hand has expressed a preference for IPP implementation modalities for mini hydro projects feeding the grids of their outstations. For these reasons the Vila project is given priority over the Mase project and will be analysed in detail below. Table 9.4 compares the main characteristics of the two projects.

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Table 9.4: Options for Ringgi, Munda and Noro

Hydro Options Noro/Munda/Ringgi River Mase Vila New Georgia, 33 km north-east Location Ringgi, Kolombangara Island of Noro Catchment Area 23 km2 Gross Head 160 m 200.0 m Design Flow 2.06 m3/sec 130 litres/sec Penstock diameter 1000 mm 250 mm Maximum Plant Output 3.4 MW/16.5 GWh per year 12 MW 33 kV, 40 km 1.1 km 33 kV undersea cable Transmission Line and 21 km transmission line Project Capital Cost 9,200,000 US$

9.5 General Description Vila The Vila River on Kolombangara Island runs on the slope of the dominant volcano towards the South East. It is accessible by roads, established and maintained to a high standard by the Kolombangara Forest Products Limited (KFPL). It seems Vila River seems possible to develop the Vila River as a cascade of hydropower plants starting from 400m above sea level and down to about 79m in 3 steps. A significant part of the catchment is the crater of the volcano, which is assumed to be drained through a natural tunnel starting at around El. 670m at the bottom of the crater and emerging as the Vila River at about El. 590 m. It seems feasible to plug the tunnel entrance by installing a remotely controlled valve to release water in response to the actual power demand of the system. It is assumed here that 30-40% of the total runoff originates from the crater. With a 1,100m sea cable it is possible to cross over to Arundel Island and from there to Noro with a 21 km 33kV feeder. Vila River seems the nearest point from which to provide hydropower for the significant load centers of Noro and Munda which are already interconnected by a 11 kV transmission line. The orientation of the catchment to the South East allows catching the rains coming from SE during the winter resulting in a low variation of rainfall as depicted in Figure 9.4.

Figure 9.4: Rainfall Pattern Ringgi

800 Ringgi monthly rainfall variation over the year 600

400

200

0

mm rainfall month per mm rainfall 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 Jan-Dec

Minimum Average Maximum Standard Deviation

There are numerous technical options for the hydro development on the Vila, i.e. projects can be tuned to any power requirement in the area. Figure 9.5 displays the various options. A small

31/25866 February 12 Page 80 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES development between 700 kW and 1,000 kW is possible with a project just upstream from Ringgi (Vila Low 128 m-79 m). 1,000 kW - 3,000 kW could be harnessed further up the river with Vila Middle 221 m-136 m. The potential of Vila Upper (400 m-221 m) is 2,500 kW - 6,000 kW which can be augmented to 3,000 kW - 7,500 kW by using an additional catchment to the west using a siphon across the river. I.e. the Vila has the potential of supplying not only the future demands of the entire Kolombangara Island but also the load centres of Noro and Munda towns. A sequential development could eventually create up to 12MW installed capacity. The Vila Upper needs further fieldwork to confirm the stability of the side slopes for building the canal. In addition the options for regulating the crater catchment and the transfer of catchment by siphon across the river needs to be carefully studied.

Figure 9.5: Possible Developments on Vila River

450 Vila River Kolombangara Island Scope of Hydropower Development 400

350

300

250

200 Altitude in m

150

100

50

0 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 Horizontal distance in m as measured along the river course

Vila River West ridge East ridge Vila Lower Canal Vila Lower Penstock Vila Middle Penstock Vila Middle Canal Vila Upper steep canal Vila Upper steep Penstock

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Table 9.5 below shows the coordinates for both the various intakes and the individual power houses.

Table 9.5: Location of Intakes and Powerhouses

Project Intake UTM El m Powerhouse UTM El.

Vila Upper 57 L 292100 m E 9113655 m S 400 57 L 292014 m E 9111298 m S 221

Vila 57 L 290875 m E 9112844 m S 405 Transfer

Vila Middle 57 L 292014 m E 9111298 m S 221 57 L 294255 m E 9118365 m S 136

Vila Lower 57 L 294446 m E 9117872 m S 128 57 L 294679 m E 9115628 m S 79

9.6 Hydrology KFPL has operated a rain gauge at Ringgi from 1993-2010. The monthly values are depicted in Figure 9.6 below.

Figure 9.6: Monthly Rainfall for Ringgi Station

800 700 Ringgi, Kolombangara Island, Monthly Rainfall 1993-2010 600 500 400 300 mm/month 200 100 0 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Year y = 2.4994x - 4729

Ringgi monthly rainfall 30 months moving average Linear (Ringgi monthly rainfall)

Analysis reveals a trend through the period with an increase of 2.5 mm per year in monthly rainfall, changing from about 250 to 300 mm/month over 20 years. On the other hand there is no parallel increase in the absolute standard deviation of the monthly values in each year over the period, which indicates that the trend towards higher rainfall is real. Figure 9.7 shows the monthly rainfall values as a duration curve with the average pan evaporation of Honiara included. Rainfall increases with altitude. For Guadalcanal this relationship has been quantified and the same model is applied for the Kolombangara catchments. Adjustments have been made using Ringgi rainfall data: At 35 m the average annual rainfall 2011 is estimated 3,600 mm while the the value for Guadalcanal is 1,963, resulting in a 1,637 mm higher rainfall at Kolombangara than on Guadalcanal. The resulting hydrology for the individual catchments is depicted in Table 9.6.

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Figure 9.7: Rainfall Duration Curve Ringgi

800

600 Monthly rainfall duration curve Ringgi 400

mm/month 200

0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Year

Monthly rainfall duration curve Average pan evaporation Honiara

Table 9.6: Catchment Run Off Vila River

Average Annual Runoff = Average Average Sub Area Elevation Rainfall Shade rain – Runoff Accumulated Catchment km2 m mm Factor Evaporation m3/s m3/s Crater area 14.02 1,080 7,498 70% 3,065 1.362 1.362 Upper outside crater 6.50 935 7,231 100% 5,047 1.040 2.403 Upper Transfer 3.61 676 6,535 100% 4,351 0.498 2.901 Middle 4.50 424 5,587 100% 3,403 0.486 3.386 Lower 5.53 283 4,940 100% 2,756 0.483 3.870

Figure 9.8 below displays the flow duration curves based on the hydrological model of the Lungga Gorge. This may be a conservative estimate, as the Vila catchments do not experience the low winter rainfall that characterizes Lungga. On the other hand, the catchment area is only 10% of Lungga, so the natural groundwater regulation of Lungga may be far more developed than this small and very steep catchment.

Figure 9.8: Flow Duration Curves Vila Catchments

12 11 10 Flow duration Curve Vila Middle (221m.a.s.l.) 9 8 7 Upper 6

m3/s 5 Upper + Transfer 4 3 Middle 2 1 Lower 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % of time with flow exceeding

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9.7 System Layout Given the variety of cascade options that can be developed on the Vila, a design that matches the load forecasts provided earlier needs to be found. The possible power production of the individual schemes is displayed in Table 9.7 are calculated using installed capacities and the flow duration curves shown in Figure 9.8. Two designs have been selected for a detailed analysis here: Variant A would be the smaller of the two configurations and would supply Kolombangara Island only (KFPL commercial demand + communities). The second, ‘Variant B’, would be a much larger scheme capable of supplying Kolombangara Island plus Noro/Munda by undersea cable.

Table 9.7: Capacity and Energy of Vila Options

Under Variant A, a proposed 1,210 kW hydropower scheme would provide 10.4 GWh of electricity per year to KFPL and the Ringgi community. The project is assumed to be commissioned in 2013, with hydro output completely displacing the need for diesel generation from that year forward. Variant B would supply all loads in Ringgi as well as the loads of the Munda and Noro together with possible new electrification in the area. Under Variant B, a proposed 4,320 kW hydropower scheme would provide 26.3 GWh of electricity per annum year to KFPL and the Ringgi community as well as to Noro and Munda. The project is assumed to be commissioned in 2014, with hydro output completely displacing the need for diesel generation in that year but requiring a slight and gradually increasing amount of diesel generation to top up supply to the combined loads in every year thereafter. Figure 9.9 displays the options and their respective catchment areas.

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Figure 9.9: Exploitable Catchments of Vila River

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9.8 Variations and Least Cost Option The selection of the two projects not only aims to match supply and forecasted demand, levelized production costs for the various configurations have also been considered (least cost development) as displayed in Figure 9.9. As displayed in Figure 9.10, the lower Vila scheme would be sufficient to match power demand of Variant A, but would result in levelized production cost significantly higher than a ‘Vila Middle’ option in the same capacity class of 1,200 kW. Specific investment cost for the ‘Vila Lower’ options are significantly higher because the scheme would only be able to harness a head of approximately 40 meters while the middle option would have a head of more than 80 meters using a 2 jet Turgo turbine. Variant B is best matched with a high head option of the ‘Vila Upper and Transfer’ configuration using vertical 3 jet Pelton wheels. These two variants will be analysed further with regard to their financial performance.

Figure 9.10: Levelized Production Cost as a Function of Installed Capacity

0.1000

Levelized Production Cost

0.0800

USD/kWh 0.0600

0.0400 0 1,000 2,000 3,000 4,000 5,000 6,000 Installed Capacity kW

Vila Upper 400-221m Vila Upper + Transfer

Vila Middle 221-136m Vila Lower 128-79m

9.9 Cost Estimates Table 9.8 displays the cost estimates for the two variants. The larger Variant B that supplies both Ringgi and Noro/Munda is clearly a superior choice with specific investment cost below 3,000 US$ per kW inclusive of 33 kW transmission line to Noro and undersea cable. Total cost for variant A is 4.4 million US$ resulting in specific investment cost of US$ 3,600 per installed kW.

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Table 9.8: Cost Estimates

Variant A Variant B US$ SB$ US$ SB$ Feasibility Study 134,000 1,072,000 331,000 2,648,000 Development 161,000 1,288,000 398,000 3,184,000 Engineering 236,000 1,888,000 488,000 3,904,000 Hydro Turbine 1,212,000 9,696,000 3,085,000 24,680,000 Road Const. 52,000 416,000 253,000 2,024,000 Transmission Line Extraction 172,000 1,376,000 252,000 2,016,000 Transmission Noro 33 kV 0 0 588,000 4,704,000 Undersea Cable 33 kV 0 0 300,000 2,400,000 Substation 26,000 208,000 88,000 704,000 Penstock 349,000 2,792,000 1,036,000 8,288,000 Canal 708,000 5,664,000 1,224,000 9,792,000 Other Civil Eng 1,280,000 10,240,000 3,246,000 25,968,000 Total 4,330,000 34,640,000 11,289,000 90,312,000 say $4.4 Million $11.3 Million US$/kW 3,579 2,656 say 3,600 2,700

The Cost Estimates presented here have been prepared for the purpose of prioritizing sites for further investigation and should not be used for any other purpose. They are subject to the limitations described in Section 1.4. Further detailed investigations, including geotechnical and hydrological investigations, would be required to firm up the cost estimates for budget setting purposes.

9.10 Financial Analysis In the following the two Variants will be tested for their financial performance.

Variant A Though the Ringgi hydro power plant would most probably be operated by an IPP, it is assumed for present purposes (to preserve comparability with other hydro schemes assessed in this report) that electricity is sold in Ringgi at the SIEA’s national tariff. In comparison with the all- diesel scenario for Ringgi, the hydropower scenario results in significantly reduced costs and much higher profitability under the current SIEA tariff as illustrated in the following three figures, Figure 9.11, Figure 9.12 and Figure 9.13. The detailed financial projections for Ringgi (Variant A) are shown in the Annex.

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Figure 9.11: Revenues vs Operating Expenses Variant A

Revenues vs Operating Expenses, Ringgi Hydro Scenario $60.000

$50.000

$40.000

$30.000 Revenues

SBD millionsSBD $20.000 Expenses

$10.000

$-

Figure 9.12: Revenues vs Operating Expenses Variant A All-Diesel

Revenues vs Operating Expenses, Ringgi All-Diesel Scenario $60.000

$50.000

$40.000

$30.000 Revenues

SBD millionsSBD $20.000 Expenses $10.000

$-

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Figure 9.13: Profit/Loss Variant A

Profit/(Loss) After Tax and Finance Charges, Ringgi $40.00

$35.00

$30.00

$25.00

$20.00 With Hydro

SBD Million SBD All Diesel $15.00

$10.00

$5.00

$- 2017 2018 2019 2020 2021 2022 2023 2024 2010 2011 2012 2013 2014 2015 2016 2025 2026 2027 2028 2029 2030

FIRR Analysis Variant A In a comparison of ‘with project’ (hydropower, Variant A) and ‘without project’ (all-diesel) scenarios, the financial internal rate of return (FIRR) of hydropower investment is evaluated at 45.1%, greatly exceeding the WACC of 5.5%, with a financial net present value (FNPV, discounted at a rate equal to the WACC) of SBD 200.8 million. The full FIRR/FNPV analysis table is presented in the Annex. Sensitivity analysis has been carried out for increases in costs (capital and O&M) and decreases in benefits (reduction in the rate of real growth in diesel fuel prices, reduction in average annual hydro output, and reduced load forecast). The hydro option was found to be robust to changes in any of these parameters, and to an adverse change in all of them simultaneously, as shown in Table 9.9.

Table 9.9: Sensitivity Analysis, Ringgi (Variant A) Test Switching Variation Sensitivity Basecase Switching Value Test Case (+/- %) FNPV FIRR Indicator Parameter Value (+/-%) Base (reference case) 200.84 45.1% Increases in Costs 1. Capital Cost (SBD m) 20% 191.89 38.1% 0.22 34.64 183.38 429.3% 2. Hydro O&M Cost (SBD/kWh) 20% 200.11 44.9% 0.02 280 14,557 5099.0% Decrease in Benefits 3. Diesel Fuel Cost (real increase/annum) -20% 189.53 44.2% 0.28 3.0% 0.0% -100.0% 4. Hydro Output (capacity factor) -20% 200.83 45.1% 0.00 98.0% 11.2% -88.6% 5. Load Forecast -20% 185.78 44.2% 0.38 4.0% 0.0% -100.0% Initial Costs Increased (+) and Benefits Decreased (-) 20% 165.64 36.2% FNPV = financial net present value, FIRR = financial internal rate of return

Variant B Though Ringgi would be operated by an IPP, it is assumed for present purposes that electricity is sold in Ringgi and in Noro/Munda from the proposed scheme at the SIEA’s national tariff. In comparison with the all-diesel scenario for Ringgi, the hydropower scenario results in significantly reduced costs and much higher profitability at the retail level under the current SIEA

31/25866 February 12 Page 89 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES tariff as illustrated in the following three figures, Figure 9.14, Figure 9.15 and Figure 9.16. The detailed financial projections for Ringgi (Variant B) are shown in the Annex. IPP financial issues and scope to establish a transfer price between the IPP and SIEA that is profitable for both parties is discussed in section 9.11 below.

Figure 9.14: Revenues vs Operating Expenses Variant B

Revenues vs Operating Expenses, Ringgi Hydro Scenario (Variant B) $180.000 $160.000 $140.000 $120.000 $100.000 $80.000 Operating Revenues

SBD millionsSBD $60.000 Expenses $40.000 $20.000 $- 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Figure 9.15: Revenues vs Operating Expenses Variant B All-Diesel

Revenues vs Operating Expenses, Ringgi All-Diesel Scenario (B) $180.000 $160.000 $140.000 $120.000 $100.000 $80.000 Operating Revenues

SBD millionsSBD $60.000 Expenses $40.000 $20.000 $- 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

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Figure 9.16: Profit/Loss Variant B

Profit/(Loss) After Tax and Finance Charges, Ringgi (B) $120.00

$100.00

$80.00

$60.00 With Hydro

SBD Million SBD All Diesel

$40.00

$20.00

$- 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

FIRR Analysis Variant B In a comparison of ‘with project’ (hydropower, Variant B) and ‘without project’ (all-diesel) scenarios, the financial internal rate of return (FIRR) of hydropower investment is evaluated at 46.9%, greatly exceeding the WACC of 5.5%, with a financial net present value (FNPV, discounted at a rate equal to the WACC) of SBD 614.1 million. The full FIRR/FNPV analysis table is presented in the Annex. Sensitivity analysis has been carried out for increases in costs (capital and O&M) and decreases in benefits (reduction in the rate of real growth in diesel fuel prices, reduction in average annual hydro output, and reduced load forecast). The hydro option was found to be robust to changes in any of these parameters, and to an adverse change in all of them simultaneously, as shown in Table 9.10.

Table 9.10: Sensitivity Analysis, Ringgi (Variant B) Test Switching Variation Sensitivity Basecase Switching Value Test Case (+/- %) FNPV FIRR Indicator Parameter Value (+/-%) Base (reference case) 614.05 46.9% Increases in Costs 1. Capital Cost (SBD m) 20% 591.23 40.5% 0.19 90.30 583.14 545.8% 2. Hydro O&M Cost (SBD/kWh) 20% 611.69 46.8% 0.02 280 14,278 4999.2% Decrease in Benefits 3. Diesel Fuel Cost (real increase/annum) -20% 579.36 45.9% 0.28 3.0% 0.0% -100.0% 4. Hydro Output (capacity factor) -20% 573.79 45.8% 0.33 70.7% 8.7% -87.6% 5. Load Forecast -20% 568.96 46.0% 0.37 4.0% 0.0% -100.0% Initial Costs Increased (+) and Benefits Decreased (-) 20% 492.09 37.6% FNPV = financial net present value, FIRR = financial internal rate of return

9.11 IPP Financial Analysis: Bulk Energy Transfer Price The above analysis of the proposed hydro scheme at Ringgi, Variant B, recognises that KFPL is likely to invest in and operate the scheme as an IPP, but essentially considers the operations as if the IPP were essentially in the same position as SIEA (a producer and retailer of energy). This is useful to show the financial performance of the proposed scheme under the same parameters that apply to the other hydro schemes assessed under this TA.

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Given the special circumstances of the Ringgi scheme it is however necessary to ask: is there a bulk energy transfer price that would allow the IPP to earn an adequate return on investment, and also allow SIEA to purchase bulk energy and operate customer service and retail functions in the affected service areas, at a profit? At the present prefeasibility level of analysis, it is desirable to answer this question in an indicative way, leaving a more detailed determination of actual transfer prices between the IPP and SIEA to a future feasibility analysis. To provide an indicative level response to this question, an analysis was undertaken of a transfer price from the IPP that would allow the IPP to make an ‘adequate’ financial return on investment on the basis of bulk sales to SIEA, and assuming that all retail sales of electricity in the affected service areas are under the responsibility of SIEA and are priced at the national tariff. For this purpose, it is assumed that an ‘adequate’ commercial return to the IPP is 15%. A discounted cash flow analysis was conducted to determine the average revenue from bulk energy sales that would be required to produce an FIRR of 15%, as shown in Table 9.11.

Table 9.11: Calculation of a Bulk Energy Price (SBD/kWh) that Achieves FIRR=15%

Revenue per kWh of Bulk Sales (SBD) $ 1.87 Hydro ('With Project') Revenue from Bulk Sales Diesel Diesel & Diesel & Total Fuel Hydro O&M Hydro Depr 'With Project' Energy Sold Revenue Net Financial Year Capital Cost Costs Costs Costs Costs (MWh) (SBD m) Benefit 2012 45.15 28.58 15.60 0.88 90.21 12,480 23.32 $ (66.89) 2013 45.15 30.66 16.25 2.14 94.20 13,000 24.29 $ (69.91) 2014 - - 1.19 3.98 5.17 13,520 25.26 $ 20.09 2015 - 0.02 1.20 3.98 5.20 14,061 26.27 $ 21.07 2016 - 0.13 1.25 3.98 5.36 14,623 27.32 $ 21.96 2017 - 0.24 1.30 3.98 5.52 15,208 28.41 $ 22.89 2018 - 0.36 1.36 3.98 5.70 15,816 29.55 $ 23.85 2019 - 0.49 1.41 3.98 5.88 16,449 30.73 $ 24.85 2020 - 0.64 1.46 3.98 6.08 17,107 31.96 $ 25.88 2021 - 0.79 1.52 4.27 6.58 17,791 33.24 $ 26.66 2022 - 0.95 1.58 4.86 7.39 18,503 34.57 $ 27.18 2023 - 1.13 1.64 4.86 7.63 19,243 35.95 $ 28.33 2024 - 1.32 1.69 4.86 7.87 20,013 37.39 $ 29.52 2025 - 1.52 1.76 4.86 8.14 20,813 38.89 $ 30.75 2026 - 1.74 1.82 4.86 8.42 21,646 40.44 $ 32.03 2027 - 1.97 1.88 4.86 8.71 22,512 42.06 $ 33.35 2028 - 2.22 1.94 4.86 9.02 23,412 43.74 $ 34.72 2029 - 2.48 2.01 4.86 9.35 24,349 45.49 $ 36.14 2030 - 4.31 2.57 4.86 11.75 25,323 47.31 $ 35.56

FIRR = 15.0% FNPVs 87.96 65.76 45.92 46.10 245.74 373.97 128.23

WACC = 5.47%

The bulk energy transfer price that achieves an FIRR of 15%, given the costs of the proposed Ringgi scheme, Variant B, is calculated to be SBD 1.87/kWh, slightly greater than US$0.23/kWh. The analysis indicates that the IPP, by undertaking the investment and charging this price for the output, is financially better off by a net present value of SBD 128.2 million over the planning period. With the financial viability of the IPP investment secured, it now needs to be determined is if SIEA can operate profitably at the retail level if it purchases energy from the IPP at this price?

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Table 9.12: SIEA Analysis, Hydro Energy Purchase from IPP (Ringgi, Variant B)

SBD million 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Total SIEA Revenues from Retail Sales $ 69.210 $ 72.403 $ 75.638 $ 79.032 $ 82.594 $ 86.331 $ 90.255 $ 94.374 $ 98.700 $ 103.243 SIEA Bulk Purchase Cost $ 23.316 $ 24.288 $ 25.259 $ 26.270 $ 27.320 $ 28.413 $ 29.550 $ 30.732 $ 31.961 $ 33.239 SIEA Customer Service & Administration Cost $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 Net SIEA Revenues $ 45.64 $ 47.86 $ 50.12 $ 52.50 $ 55.02 $ 57.66 $ 60.45 $ 63.38 $ 66.48 $ 69.75 SBD per k Wh Average Revenue per kWh from Retail Sales $ 5.55 $ 5.57 $ 5.59 $ 5.62 $ 5.65 $ 5.68 $ 5.71 $ 5.74 $ 5.77 $ 5.80 Average Cost per kWh from Bulk Purchase and Admin $ 1.89 $ 1.89 $ 1.89 $ 1.89 $ 1.89 $ 1.89 $ 1.88 $ 1.88 $ 1.88 $ 1.88 Net SIEA Revenue per kWh $ 3.66 $ 3.68 $ 3.71 $ 3.73 $ 3.76 $ 3.79 $ 3.82 $ 3.85 $ 3.89 $ 3.92

SBD million 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total SIEA Revenues from Retail Sales $ 108.016 $ 113.030 $ 118.300 $ 123.840 $ 129.663 $ 135.787 $ 142.228 $ 149.004 $ 156.134 SIEA Bulk Purchase Cost $ 34.569 $ 35.952 $ 37.390 $ 38.885 $ 40.441 $ 42.058 $ 43.741 $ 45.490 $ 47.310 SIEA Customer Service & Administration Cost $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 $ 0.258 Net SIEA Revenues $ 73.19 $ 76.82 $ 80.65 $ 84.70 $ 88.96 $ 93.47 $ 98.23 $ 103.26 $ 108.57 SBD per k Wh Average Revenue per kWh from Retail Sales $ 5.84 $ 5.87 $ 5.91 $ 5.95 $ 5.99 $ 6.03 $ 6.07 $ 6.12 $ 6.17 Average Cost per kWh from Bulk Purchase and Admin $ 1.88 $ 1.88 $ 1.88 $ 1.88 $ 1.88 $ 1.88 $ 1.88 $ 1.88 $ 1.88 Net SIEA Revenue per kWh $ 3.96 $ 3.99 $ 4.03 $ 4.07 $ 4.11 $ 4.15 $ 4.20 $ 4.24 $ 4.29

In Table 9.12 above it is shown that SIEA’s retail and customer service operations in the affected service areas are profitable over the planning period (differencing retail sales revenue and the sum of bulk energy purchase and customer service/administration costs). The NPV of the operating profit from these operations (calculation not shown) is approximately SBD 780 million over the planning period. This analysis indicates that the Ringgi project is robust under a very wide range of assumptions and its implementation would allow SIEA to create a profit centre in Noro/Munda. The hydro scheme would also allow to completely abandoning the old power station in Noro as the Soltai diesel sets (3 MW) could be used as stand-by units.

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10. Taro

10.1 The Taro Power Supply Taro, the provincial capital of Choiseul, has no SIEA grid. It is situated on a small island approx 1 km from the main island of Choiseul (see Figure 10.1). Taro island hosts the government station, a hospital and residences of government employees. The total population of Taro and the surrounding areas of the main island is estimated at 2,000. There is limited commercial activity in the area, apart from government wages the main cash income of the population comes from copra production. Power is currently supplied by a multitude of small generator sets that provide power to institutions and commercial entities, normally for a limited period of time every day. Most households within the Taro ward are currently without electricity supply. The provincial government believes that the lack of grid power is currently a major obstacle to economic and social development of the greater Taro area and has requested the national government and SIEA to assess possibilities of a grid based supply along the lines of the existing SIEA outstations. SIEA has responded to these requests and will establish a low voltage mini grid that would cover only the island of Taro, but not the settlements on the main island adjacent that are part of the Taro ward. Such a system would, however, not be able to trigger commercial activity as the island of Taro itself is too confined to allow any significant economic activity there.

Figure 10.1: Map Taro

The following table lists existing generation equipment in Taro and their mode of operation. In total, approximately 500 kWh are produced by five individual institutional generators. The

31/25866 February 12 Page 94 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES provincial hospital is the largest consumer. Together the five institutional users are likely to produce a peak in the order of 45 – 50 kW. The table also shows an estimate for electricity consumption under an assumed 24 hour supply regime.

Table 10.1: Installed Generation in Taro

Residential areas on the main island of Choiseul are currently not supplied with any form of power. The only form of lighting available is by kerosene lamps. The following map shows the location of Taro island and the surrounding settlements. In total the Taro ward (including the main island settlements) are home to approximately 470 households of which one hundred live on Taro island itself.

Figure 10.2: Settlements Around Taro

10.2 Load Forecast It is assumed that 295 households could be connected initially, with the remaining 175 households connected in a later second phase by extending the supply area on the main island. There are 5 potential government and commercial connections, as shown in Table 10.1. Most of these already have some form of self-generation capacity. It is assumed that 2013 is the first realistic start year for the new power system. There are no billing records on which to base a demand profile and load forecast for Taro, but the TA consultants have carried out a survey of the proposed service area and estimate that

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295 households can be connected to the system initially (2013) and an additional 175 households can be connected in 2014. A modest amount of commercial consumption from government service agencies, telekom, a fish freezer, and a guesthouse is envisaged as part of load growth after the public power supply is established. It is assumed that initially, energy demand will be in the order of 500,000 kWh per annum. In keeping with the other outstations, it is assumed that load in Taro will grow at 4% per year after the initial connections are made. The Taro system load forecast, estimation of generation requirements, load factors, projected diesel and hydro generation requirements, and a schedule of new diesel generation capacity installations required to provide 100% backup for the system over the 20-year planning period are summarised in Table 10.2. Figure 10.3 illustrates the generation requirement implied by the load forecast. The hydro site identified on the main island would be able to completely meet the forecasted load over a 20 years planning horizon as shown in Figure 10.4.

Figure 10.3: Taro Load Forecast

Taro Power System Load Forecast 1,400,000

1,200,000

1,000,000

800,000 Sales to Commercial kWh 600,000 Sales to Domestic Station and Line Losses

400,000

200,000

-

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Figure 10.4: Taro Generation Mix

Taro Generation Mix 1,400,000

1,200,000

1,000,000

800,000

Diesel kWh/year 600,000 Hydro

400,000

200,000

-

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

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Table 10.2: Load Forecast Taro

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 8 Load Forecast AAGR Sales = 5.13% Electricity Sales (kWh) Initial Domestic (2013) 282,500 293,800 305,552 317,774 330,485 343,704 357,453 371,751 386,621 402,086 418,169 434,896 452,292 470,383 489,199 508,767 529,117 550,282 New Domestic (Phase II) - 95,813 99,645 103,631 107,776 112,087 116,571 121,233 126,083 131,126 136,371 141,826 147,499 153,399 159,535 165,916 172,553 179,455 Initial Commercial (2013) 172,309 179,202 186,370 193,824 201,577 209,640 218,026 226,747 235,817 245,250 255,060 265,262 275,873 286,907 298,384 310,319 322,732 335,641 New Commercial ------Total Sales 454,809 568,814 591,567 615,229 639,838 665,432 692,049 719,731 748,521 778,461 809,600 841,984 875,663 910,690 947,117 985,002 1,024,402 1,065,378

Sales to Domestic 282,500 389,613 405,197 421,405 438,261 455,792 474,023 492,984 512,703 533,212 554,540 576,722 599,791 623,782 648,733 674,683 701,670 729,737 Sales to Commercial 172,309 179,202 186,370 193,824 201,577 209,640 218,026 226,747 235,817 245,250 255,060 265,262 275,873 286,907 298,384 310,319 322,732 335,641 Station and Line Losses 39,549 49,462 51,441 53,498 55,638 57,864 60,178 62,585 65,089 67,692 70,400 73,216 76,145 79,190 82,358 85,652 89,078 92,642

Load Factor - - - 0.60 0.60 0.61 0.62 0.64 0.65 0.66 0.67 0.69 0.70 0.71 0.73 0.74 0.76 0.77 0.79 0.80 0.82

AAGR Generation = 5.13% Generation Requirement (kWh) 494,358 618,276 643,007 668,727 695,477 723,296 752,227 782,317 813,609 846,154 880,000 915,200 951,808 989,880 1,029,475 1,070,654 1,113,480 1,158,020 Station and Line Losses (kWh) 39,549 49,462 51,441 53,498 55,638 57,864 60,178 62,585 65,089 67,692 70,400 73,216 76,145 79,190 82,358 85,652 89,078 92,642 Peak Load on the Generators (kW) 94.06 117.63 119.99 122.38 124.83 127.33 129.88 132.47 135.12 137.83 140.58 143.39 146.26 149.19 152.17 155.21 158.32 161.48 Required Capacity with Reserve (kW) 122.27 152.92 155.98 159.10 162.28 165.53 168.84 172.22 175.66 179.17 182.76 186.41 190.14 193.94 197.82 201.78 205.81 209.93 Fuel Required, All-Diesel Scenario (litres) 141,245 176,650 183,716 191,065 198,708 206,656 214,922 223,519 232,460 241,758 251,429 261,486 271,945 282,823 294,136 305,901 318,137 330,863

9 Hydro Scenario Generation Calculation Generation Mix with hydro (kWh/year) Hydro - 618,276 643,007 668,727 695,477 723,296 752,227 782,317 813,609 846,154 880,000 915,200 951,808 989,880 1,029,475 1,070,654 1,113,480 1,158,020 Diesel 494,358 ------Fuel Required, Hydro Scenario (litres) 141,245 ------Fuel Saved by Hydro (litres) - 176,650 183,716 191,065 198,708 206,656 214,922 223,519 232,460 241,758 251,429 261,486 271,945 282,823 294,136 305,901 318,137 330,863

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 10 Diesel Generator Scheduling Unit 1 (new) 100 100 100 100 100 100 100 100 100 100 Unit 2 (new) 100 100 100 100 100 100 100 100 100 100 Unit 3 (new) 100 100 100 100 100 100 100 100 100 100 Unit 4 (new) 100 100 100 100 100 100 100 100 Unit 5 (new) 100 100 100 100 100 100 100 100 Unit 6 (new) 100 100 100 100 100 100 100 100 Unit 7 (new) Total Installed Capacity (kW) 0 0 0 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 Firm Capacity Available 0 0 0 200 200 200 200 200 200 200 200 200 200 200 200 200 200 200 200 200 200 Memo: Units Added Small Units (100 kW) 3 ------3 ------Large Units (100 kW) ------

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10.3 Taro System Expansion Planning

Generation At this stage, it is therefore only possible to indicate some key characteristics of a future power system in Taro. Generation requirements based on the load forecast provided previously would initially be met by 2 diesel sets of 150 kW each. Later as load grows replacement of the units with larger 250 kW units may be warranted. The hydro site identified on the Sorawe river could be developed in two different ways: As a separate grid supplying consumers on the main island only or as an integrated system that would connect the government headquarters on the island of Taro and the loads indentified on the main island.

Distribution An isolated power supply system for Taro only would be small in comparison to other SIEA outstations, and would not allow a system expansion that included the households of the Taro ward located on the main island. The provincial capital of Taro is on an island which is separated from the main island of Choiseul by a channel that is approx 2 km wide and 80 meters deep. A central power supply would require an 11 kV undersea cable that would connect Taro with the main island. Supplier quotes obtained for such a cable indicate supply cost of US$ 190,000 or US$ 95,000 per km. Installed cost would be in the vicinity of to US$ 280,000. This investment is substantial but for the time being it has been assumed that diesel generation would not be split into two stations, one supplying Taro and another station supplying the settlements on the main island. The capital investment for the undersea cable does significantly increase supply cost as long as the system is operated using thermal generation. This situation changes in the presence of a mini hydro plant on the Sorawe river. The capacity requirements depicted in Figure 10.5 are therefore a preliminary assessment based on the load forecast provided in the previous section and illustrates the generation requirement implied by the load forecast.

Figure 10.5: Taro Capcity Requirements (Entire Taro Ward)

Taro Capacity Requirements 500

450

400 Hydro

350

300

250 Peak Demand (kW) kW Firm Capacity Available 200 Total Installed Capacity (kW)

150

100

50

-

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

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10.4 Hydro Options for Taro The only river that has hydro potential is the Sorawe which discharges east of Taro island into the sea. The river offers a number of options for hydro development. A low head scheme is possible on the bank of the Sorawe using the head of a waterfall at the bottom of the river. This however is limited in capacity and has a higher investment per kW because of the low head. Other opportunities up to 700 kW installed capacity exist on the slope of the higher part of the catchment with development of head between 280 m and 80 m above sea level, which allows for a gradual development in 2 or 3 stages. Figure 10.6 shows the various options

Figure 10.6: Hydro Options Taro

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10.5 Hydrology The rainfall at Taro shows little variation over the year with December and January slightly lower than the other months, when the Taro station area may be in rain shade of the south-easterly rains. The average monthly rainfall is 260 mm/months or 3,200 mm/yr. Assuming the same rainfall gradient as on the northern coast of Guadalcanal and an altitude of 20 m for the Taro rain gauge rainfall can be calculated for the two catchments in question: the larger catchment of the whole river has an average elevation of 146 m the upper catchment shows an average elevation 430 m. Thus annual rainfall figures of 3,845 mm and 5,227 mm respectively can be assumed for the two catchments. Assuming an evaporation of 2,184 mm the resulting average annual runoff of would be 1,662mm and 3,043 mm respectively.

Figure 10.7: Rainfall Taro

400 Taro Monthly Average Rainfall 1975-2009

350

300

250

200

150

Average Rainfall (mm) Rainfall Average 100

50

0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Months for Year 1976-2009

The results of the hydrological analysis for four different hydro options are displayed in Table 10.3 below. At the Sorawe, an automatic gauging stations has been installed as part of this TA and the measurements will allow a more accurate assessment of the run off.

Table 10.3: Calculated Runoff for Sorawe Catchments

Catchment km2 Elevation Rainfall mm/yr Runoff mm/yr Avg. Runoff m3/s

Waterfall at 21m 35.8 146 3846 1662 1.8866

Upper 1 3.7 430 5227 3043 0.3570

Upper(1+ 2) 7.4 430 5227 3043 0.7140

Upper (1+2+3) 10.0 430 5227 3043 0.9649

The potential power production at the two sites is estimated based on the shape of flow duration curve of the Lungga, even though it may prove too conservative. On the other hand, runoff in the upper catchments may be diminished by sinkholes given a geology that is characterised by

31/25866 February 12 Page 100 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES the predominance of soft limestone formations. Future discharge measurements in conjunction with the gauging of the Sorawe will eliminate the remaining uncertainties. Figure 10.8 and Figure 10.9 show the assumed flow duration characteristics for the lower and upper hydro sites.

Figure 10.8: Flow Duration Curve for Lower Catchment

6

5 Assumed Flow duration curve for Surawe River, 4 Downstream Waterfall, Choiseul

3 m3/s 2

1

0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % of Time Exceeding

Figure 10.9: Flow Duration Curve for Upper Catchment

1.2

1.0 Assumed Flow duration curve for Upper 1 Alterative 0.8 280m-80m, Sorawe River,Choiseul

0.6 m3/s 0.4

0.2

0.0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % of Time Exceeding

10.6 System Layout

Lower Alternative at the Waterfall A detailed long profile has been established available from elevation 23.1 m to 0.0 m (Figure 10.10). An intake weir of 0.4 meter would be located at elevation 23.1m where the main course of the river turns south and has little slope. Some additional head may be possible by establishing a higher intake weir, but this would not increase output of the lower option significantly. The low head suggests the use of a double runner Francis turbine. A cross-flow turbine could also be used but the Francis turbine has a much higher efficiency and utilise the full head, while the runner of the cross flow turbine has to be safely above the highest water level of the tidal waters. This would result in a significant loss of head.

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Figure 10.10: Long Profile for Sorawe Lower

25

20 Surawe River Long Profile 15 Downstream Waterfall

m.a.s.l. 10

5

0 0 50 100 150 200 250 300 350 400 450 500 Distance measured along river to the sea level

Main River Penstock Canal

Figure 10.11: Layout Lower Scheme

It appears to be possible to carry a headrace canal on the slope above the river course to a point just above the bottom of the waterfall, which would reduce the length of the penstock to 63 meters and thus reduce cost significantly compared to earlier proposals of establishing penstock from the intake to the powerhouse at a length of 440 meters. An installed capacity of

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150 kW could be established using a 1,000 RPM Francis turbine with a throat diameter of 270 mm. An access road would be constructed first to the powerhouse and further up to the fore bay. Then a road would be constructed with a slope of 1 meter per km between the fore bay and the intake. On this road the canal would be constructed moving from the intake back to the fore bay. Power would be extracted via 6.5 km of 11kV line which would branch into a 2 km undersea cable connecting Taro Island and a 21 km feeder along the road costal road to the communities North of the Sorawe mouth.

Upper Alternative The lower alternative shows high specific investment cost due to the low head that requires a costly turbine installation. It would also have to use a large discharge, which required a large, and costly canal cross-section as well as a larger powerhouse. Further upstream however, another powerhouse location was identified at elevation 80 m above which the river has a very steep slope up to an elevation of 300 m (see Figure 10.12). Apart from the main river, up to 3 smaller streams could be collected at an intake level of 280 m, resulting in a gross head of about 200 meters. As power demand of the Taro area is limited a staged development seems appropriate. The first stage of this may be a canal of 1,200 m to the north (depicted as canal 1 in Figure 10.12 below). From the fore bay a 310 mm penstock with a length of 600 meters would transport the water to the powerhouse at elevation 80. A single jet Turgo turbine would provide an installed capacity of 260 kW.

Figure 10.12: Long Profile Sorawe

350 Surawe River Long Profile 300 from Upper 1

250

200

m.a.s.l. 150

100

50

0 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 Distance measured along river to the sea level

Main River Penstock Canal Lower penstock Lower canal

It is possible that the area will experience a demand growth that required more capacity in 10 or 15 years time. This demand could be met by adding a new canal (canal 2 on Figure 10.13) to the south, along with a new penstock and turbine set. Collecting a 3rd stream to the south could

31/25866 February 12 Page 103 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES develop up to 750 kW, a capacity requirement that is unlikely to develop in the Taro area in the foreseeable future. The upper alternatives have longer access roads, both to reach the powerhouse and from there to the fore bay. The extraction line is only 3.5km or 11% longer than at the lower alternative (see Table 10.4).

Table 10.4: Characteristics of Sorawe Alternatives

Figure 10.13: Sorawe Upper Alternatives

10.7 Cost Estimates The following estimates summarizes cost for the Sorawe option ‘Upper 1’, a scheme that has an installed capacity of 260 kW and is able to supply up to 2.1 GWh per year to Taro island and the surrounding communities on the main island. Specific cost are relatively high which is a consequence of the need to use an undersea cable and relatively long feeders to supply outlaying communities.

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Table 10.5: Cost Estimates Tarp Hydro US$ SB$ Feasibility Study 39,000 312,000 Development 47,000 376,000 Engineering 87,000 696,000 Hydro Turbine 201,000 1,608,000 Road Construction 105,000 840,000 Transmission Line Extraction 295,000 2,360,000 Undersea Cable 33 kV 249,600 1,996,800 Rural Electrification 175,000 1,400,000 Substation 4,000 32,000 Penstock 167,000 1,336,000 Canal 45,000 360,000 Other Civil Eng 283,000 2,264,000 Total 1,697,600 13,580,800 say $1.7 Million US$/kW 6,529 say 6,500

The Cost Estimates presented here have been prepared for the purpose of prioritizing sites for further investigation and should not be used for any other purpose. They are subject to the limitations described in Section 1.4. Further detailed investigations, including geotechnical and hydrological investigations, would be required to firm up the cost estimates for budget setting purposes.

10.8 Financial Analysis The hydro project is assumed to be commissioned in 2014 with diesel facilities commissioned in 2013. When commissioned, the hydro scheme will entirely displace need for diesel generation to meet projected loads throughout the planning period. The hydro scheme, as with the other schemes assessed in this TA, is assumed to have 100% diesel backup capacity. In other words, it is assumed, for present purposes, that Taro is to become an SIEA outstation that will receive the full diesel and distribution facilities required to operate it as an outstation, and that hydro development is being considered as a least-cost option to supply the centre.

Profit and Loss In comparison with the all-diesel scenario for Taro, the hydropower scenario results in significantly reduced costs and much higher profitability under the current tariff as illustrated in the following three Figures. (If Taro were to be constructed and commissioned as an all-diesel centre, it would generate financial losses for SIEA.) The detailed financial projections for Taro are shown in the Annex.

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Figure 10.14: Revenues and Operating Expenses Hydro Taro

Revenues vs Operating Expenses, Taro Hydro Scenario $7.000 $6.000 $5.000 $4.000 $3.000 Revenues

SBD millionsSBD Expenses $2.000 $1.000 $- 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Figure 10.15: Revenues and Operating Expenses Diesel Taro

Revenues vs Operating Expenses, Tar o All-Diesel Scenario $7.000 $6.000 $5.000 $4.000 $3.000 Revenues

SBD millionsSBD $2.000 Expenses $1.000 $- 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

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Figure 10.16: Profit/Loss Hydro and Diesel Taro

Profit/(Loss) After Tax and Finance Charges, Taro $4.50

$4.00

$3.50

$3.00

$2.50

With Hydro $2.00 All Diesel SBD Million SBD $1.50

$1.00

$0.50

$- 2017 2010 2011 2012 2013 2014 2015 2016 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

$(0.50)

FIRR Analysis In a comparison of ‘with project’ (hydropower) and ‘without project’ (all-diesel) scenarios, the financial internal rate of return (FIRR) of hydropower investment is evaluated at 18.4%, greatly exceeding the WACC of 5.0%, with a financial net present value (FNPV, discounted at a rate equal to the WACC) of SBD 22.2 million. The full FIRR/FNPV analysis table is presented in the Annex. Sensitivity analysis has been carried out for increases in costs (capital and O&M) and decreases in benefits (reduction in the rate of real growth in diesel fuel prices, reduction in average annual hydro output, and reduced load forecast). The hydro option was found to be robust to changes in any of these parameters, and to an adverse change in all of them simultaneously, as shown in Table 10.6. The financial viability of the hydro project is most sensitive to a reduction in the projected rate of growth in consumption.

Table 10.6: Sensitivity Analysis, Taro Test Switching Variation Sensitivity Basecase Switching Value Test Case (+/- %) FNPV FIRR Indicator Parameter Value (+/-%) Base (reference case) 22.19 18.4% Increases in Costs 1. Capital Cost (SBD m) 20% 18.61 14.9% 0.81 13.58 30.29 123.1% 2. Hydro O&M Cost (SBD/kW) 20% 22.02 18.3% 0.04 280.00 7,824.60 2694.5% Decrease in Benefits 3. Diesel Fuel Cost (real increase/annum) -20% 20.07 17.6% 0.48 3.0% 0.0% -100.0% 4. Hydro Output (capacity factor) -20% 22.19 18.4% - 90.5% 16.9% -81.3% 5. Load Forecast -20% 15.74 15.3% 1.45 4.0% 0.8% -81.1% Initial Costs Increased (+) and Benefits Decreased (-) 20% 10.26 11.2% FNPV = financial net present value, FIRR = financial internal rate of return

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11. Mataniko and Lungga, Honiara

Options to augment Honiara power supply with smaller scale hydropower IPPs has not originally been part of this TA which focuses on outer island electricity supply. However, SIG (Ministry of Finance) suggested to include an analysis of two projects that have been proposed by a prospective private IPP investor. These projects are both run off river schemes without any storage. They are located at the Lungga River and the Mataniko River which discharges into the sea right in the town of Honiara. While both schemes have been considered and surveyed by the consultant GHD does not believe that the proposed low head Lungga scheme is feasible. Thus, only the Mataniko scheme has been fully analysed below.

11.1 The Honiara Power System Honiara is Solomon Island’s largest town and with a population of approximately 90,000 and a growth of around 4% p.a. Currently approximately 75% of the town population has access to electricity. With steep hills rising within 2 – 5 km from the coast the bulk of the population live along the coast. The coastal plains to the east and west of Honiara show rather low population density and little development. Population growth has mostly occurred in Honiara town itself. I.e. growth has manifested itself mostly by a significant increase in average household size.

Generation Honiara’s electricity supply consists of two SIEA diesel power stations, one located at Lungga, approximately 8 km east of the town centre (Lungga Power Station), and the other in the town centre (Honiara Power Station). These two power stations are interconnected via two 33 kV circuits, one of which is an overhead line and the other an underground cable. Each circuit is approximately 10 km in length. These circuits both terminate at the Honiara Power Station. In addition to these transmission circuits, several 33kV underground distribution cables have recently been installed to supply new 33/11kV zone substations at East Honiara and White River. The diesel engine generators currently installed at Lungga Power Station are a mixture of medium speed units (500, 750 and 1,000rpm) duty. Honiara Power Station established as Honiara’s power supply in the 50ies currently operates a single high speed Perkins 1,500 kW unit de-rated to only 800 kW. Due to the open walled construction of Honiara Power Station and its location behind the town centre, residents have complaint about noise. SIEA intends decommission the station in the next few years. Operational generator units could be relocated to Lungga, leaving the station as a distribution substation only.

In total, available capacity in May 2011 was only 11.6 MW, as displayed in Table 11.1 below. Two major generator sets (L6 and L7) representing a total of 6 MW available capacity are down due to a crankshaft failiure at L6 and a major overhaul of L7. The available capacity is not sufficient to meet a peak demand of over 13 MW and there is no reserve capacity at all. Therefore, load shedding is common in the Honiara system and SIEA has established arrangement with larger customers such as hotels who can operate their stand-by sets in times of power shortage. In 2010, SIEA generated a total of 73.5 GWh in Honiara compared with 69.8 GWh in 2009. Fuel storage capacity at the Lungga station is 200,000 liters in four tanks.

The fuel efficiency of the re-rated generators is comparatively low for the size and design of the generator sets. In 2010 it averaged at 3.8 kWh per liter. It appears that most generators at Lungga station suffer from cooling problems, especially during the hot season.

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Table 11.1: Honiara Generator Status May 2011

Engine Station Make Rated (kW) De-rated (kW) Available (kW) Remarks No

L5 Mirrlees 1500 900 900 In service

L6 Mirrlees 2900 2200 00 Faulty crankshaft

L7 Wartsila 4200 3800 00 Major O/H in progress

Lungga L8 Wartsila 4200 2,900 2,800 In service

Mitsubis L9 4200 3300 3,300 In service hi

L10 Niigata 4200 4000 3,900 In service

H1 Perkins 1500 700 00 Retired

Honiara H2 Perkins 1500 800 700 In service

H3 Perkins 1500 800 00 Faulty radiator fan bearing

Total MW 11,600

Source: Generation Manager SIEA

Distribution Power is distributed to consumers in Honiara via a number of overhead and underground 11kV feeders, 11kV/415 substations, and overhead and underground 4-wire 415V/240V (LV) circuits. Figure 11.1 overleaf displays a simplified single line diagram for the Honiara system.

At the present time, all 11kV feeders emanate from the two power stations. The current area of SIEA electricity supply in Honiara stretches from the White River, approximately 3.5 km to the west of the town centre to Henderson Airport, approximately 10 km to the east of the town centre. Prior to the ethnic tensions, the supply area was greater and extended to the west as far as Mamara and to the east as far as the Solomon Islands Palm Oil estate (SIPL) at Tetere. The transmission line poles for these supply areas are still standing, but conductors, cross arms and transformers have been removed.

SIEA’s Honiara operation suffers from a number of serious problems: Firstly, the system occurs unacceptably high technical and non-technical losses in the order of 25%. A best practice utility the size of SIEA’s Honiara operation would have total losses below 10%. With support from the World Bank SIEA has started to address this issue and has embarked upon a project to fast track pre-payment meters in order to reduce arrears and non-technical losses.

SIEA has also commissioned a loss reduction study that identified numerous options to bring technical losses down to acceptable levels. The lack of adequate capacity is another serious problem for SIEA. At present management investigates options to augment thermal capacity at Lungga. In addition, the Tina River Hydro project is currently being investigated in the framework of a feasibility study financed by the European Investment Bank.

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Figure 11.1: Single Line Diagram SIEA Honiara

Source: SKM SIEA Loss Reduction Study 2011

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11.2 Load Forecast Electricity consumption in Honiara is dominated by the commercial/industrial sector, accounting for approximately 85% of total Honiara electricity generation of 73 GWh in 2010. Load growth in Honiara has historically been higher than has been seen in the outstations, reaching a long- term average of about 5% per year. At present, 100% of generation in Honiara is by diesel and supply is severely constraint due to shortages of generation capacity. A complicating factor in this analysis is that another, much larger, hydro scheme on the Tina River is currently being investigated22. It is understood that the Tina River scheme, as currently proposed, would be commissioned in two phases: phase I would initially provide 56 GWh per year to the Honiara grid in 2015, rising to 61 GWh/year by 2023, and Phase II would provide an additional 73 GWh of energy to the grid beginning in 2019, rising to nearly 86 GWh/year by 2030. The two Phases combined would provide approximately 147 GWh/year to the grid by 2030. However, the Tina River scheme faces severe uncertainties (similar to those that have dogged other large hydro schemes proposed for Guadalcanal in the past). Therefore, in respect of the proposed Mataniko scheme, two cases are considered: (i) assuming that the Tina River scheme is installed and commissioned as currently proposed, and (ii) assuming that the Tina River scheme is not installed.

Existing loads and new domestic, commercial, and industrial loads are expected to grow at 5% per year. The Honiara system load forecast, estimation of generation requirements, load factors, projected diesel and hydro generation requirements, and a schedule of new diesel generation capacity installations required to provide 100% backup for the system over the 20- year planning period are summarised, once for the ‘with Tina’ scenario and once again for the ‘without Tina’ case, in Tables 11.2 and 11.3 respectively. Figure 11.2 illustrates the generation requirements for the Honiara system implied by the load forecast. Figure 11.3 shows a projected generation mix assuming that both Mataniko and Tina went ahead.

Figure 11.2: Generation Requirements Honiara

Honiara Power System Load Forecast 250,000

200,000

150,000

Sales to Commercial MWh Sales to Domestic 100,000 Station and Line Losses

50,000

- 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

22 Tina River Hydropower Development - Phase 1 Optimisation Study, Hydro Tasmania Consulting, 2011 31/25866 February 12 Page 111 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Figure 11.3: Generation Mix With and Without Tina

Honiara Generation Mix 250,000

200,000

150,000

Diesel Tina Hydro MWh/year 100,000 Mataniko Hydro

50,000

-

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Honiara Generation Mix 250,000

200,000

150,000

Diesel Tina Hydro MWh/year 100,000 Mataniko Hydro

50,000

- 2012 2013 2014 2015 2016 2017 2018 2024 2025 2026 2027 2028 2029 2030 2010 2011 2019 2020 2021 2022 2023

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Table 11.2: Honiara System Load Forecast, Generation Requirements, Fuel Requirements, and Backup Generator Scheduling (With Tina)

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 8 Load Forecast AAGR Sales = 4.96% Electricity Sales (MWh) Domestic 10,626 11,153 11,706 12,287 12,897 13,536 14,208 14,913 15,653 16,429 17,244 18,100 18,998 19,940 20,929 21,968 23,057 24,201 25,402 26,662 27,985 New Domestic ------Commercial & Other 62,656 65,764 69,027 72,451 76,045 79,818 83,778 87,934 92,296 96,875 101,681 106,726 112,020 117,578 123,411 129,533 135,959 142,704 149,784 157,215 165,014 New Commercial ------Total Sales 73,282 76,917 80,733 84,738 88,942 93,354 97,986 102,847 107,949 113,304 118,925 124,825 131,018 137,518 144,340 151,501 159,017 166,906 175,186 183,877 192,999

Sales to Domestic 10,626 11,153 11,706 12,287 12,897 13,536 14,208 14,913 15,653 16,429 17,244 18,100 18,998 19,940 20,929 21,968 23,057 24,201 25,402 26,662 27,985 Sales to Commercial 62,656 65,764 69,027 72,451 76,045 79,818 83,778 87,934 92,296 96,875 101,681 106,726 112,020 117,578 123,411 129,533 135,959 142,704 149,784 157,215 165,014 Station and Line Losses 6,372 6,688 7,020 7,369 7,734 8,118 8,521 8,943 9,387 9,853 10,341 10,854 11,393 11,958 12,551 13,174 13,828 14,514 15,234 15,989 16,783

Load Factor 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70

AAGR Generation = 4.96% Generation Requirement (MWh) 79,654 83,606 87,753 92,107 96,676 101,472 106,506 111,790 117,336 123,157 129,267 135,680 142,411 149,476 156,891 164,675 172,844 181,419 190,419 199,866 209,781 Station and Line Losses (MWh) 6,372 6,688 7,020 7,369 7,734 8,118 8,521 8,943 9,387 9,853 10,341 10,854 11,393 11,958 12,551 13,174 13,828 14,514 15,234 15,989 16,783 Peak Demand (MW) 12.99 13.63 14.31 15.02 15.77 16.55 17.37 18.23 19.14 20.08 21.08 22.13 23.22 24.38 25.59 26.85 28.19 29.59 31.05 32.59 34.21 Required Capacity with Reserve (MW) 16.89 17.72 18.60 19.53 20.50 21.51 22.58 23.70 24.88 26.11 27.40 28.76 30.19 31.69 33.26 34.91 36.64 38.46 40.37 42.37 44.47

Fuel Required, Diesel+Tina Scenario (10^3 litres) 22,758 23,887 25,072 26,316 27,622 12,992 14,252 15,583 16,989 - - 178 1,593 3,103 4,892 6,786 8,791 10,911 13,153 15,522 18,025

9 Mataniko Hydro Scenario Generation Calculation Generation Mix with hydro (MWh/year) Tina River Hydro Tina flag = 1 Stage 1 Output (HT Option 6) - - - - - 56,000 56,625 57,250 57,875 58,500 59,125 59,750 60,375 61,000 61,000 61,000 61,000 61,000 61,000 61,000 61,000 Stage 2 Output (HT Option 3) ------73,000 74,154 75,308 76,462 77,615 78,769 79,923 81,077 82,231 83,385 84,538 85,692 Total Existing Hydro (adjusted to load) - - - - - 56,000 56,625 57,250 57,875 110,456 116,566 122,979 129,710 136,775 139,769 140,923 142,077 143,231 144,385 145,538 146,692 Mataniko Hydro - - - - 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 Diesel 79,654 83,606 87,753 92,107 83,975 32,771 37,180 41,839 46,760 0 0 0 0 0 4,421 11,051 18,066 25,487 33,334 41,626 50,388 Fuel Required, Hydro Scenario (10^3 litres) 22,758 23,887 25,072 26,316 23,993 9,363 10,623 11,954 13,360 0 0 0 0 0 1,263 3,157 5,162 7,282 9,524 11,893 14,397 Fuel Saved by Mataniko Hydro (10^3 litres) - - - - 3,629 3,629 3,629 3,629 3,629 (0) (0) 178 1,593 3,103 3,629 3,629 3,629 3,629 3,629 3,629 3,629

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 10 Diesel Generator Scheduling Unit 1 (existing) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 Unit 2 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 Unit 3 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 Unit 4 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 Unit 5 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 Unit 6 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 Unit 7 (new) 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 Total Installed Capacity (MW) 26 26 26 26 26 26 26 26 26 26 26 44 44 44 44 44 44 44 44 44 44 Firm Capacity Available 22 22 22 22 22 22 22 22 22 22 22 36 36 36 36 36 36 36 36 36 36 Memo: Units Added Small Units (4 MW) ------1 ------Large Units (8 MW) ------4 ------

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Table 11.3: Honiara System Load Forecast, Generation Requirements, Fuel Requirements, and Backup Generator Scheduling (Without Tina)

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 8 Load Forecast AAGR Sales = 4.96% Electricity Sales (MWh) Domestic 10,626 11,153 11,706 12,287 12,897 13,536 14,208 14,913 15,653 16,429 17,244 18,100 18,998 19,940 20,929 21,968 23,057 24,201 25,402 26,662 27,985 New Domestic ------Commercial & Other 62,656 65,764 69,027 72,451 76,045 79,818 83,778 87,934 92,296 96,875 101,681 106,726 112,020 117,578 123,411 129,533 135,959 142,704 149,784 157,215 165,014 New Commercial ------Total Sales 73,282 76,917 80,733 84,738 88,942 93,354 97,986 102,847 107,949 113,304 118,925 124,825 131,018 137,518 144,340 151,501 159,017 166,906 175,186 183,877 192,999

Sales to Domestic 10,626 11,153 11,706 12,287 12,897 13,536 14,208 14,913 15,653 16,429 17,244 18,100 18,998 19,940 20,929 21,968 23,057 24,201 25,402 26,662 27,985 Sales to Commercial 62,656 65,764 69,027 72,451 76,045 79,818 83,778 87,934 92,296 96,875 101,681 106,726 112,020 117,578 123,411 129,533 135,959 142,704 149,784 157,215 165,014 Station and Line Losses 6,372 6,688 7,020 7,369 7,734 8,118 8,521 8,943 9,387 9,853 10,341 10,854 11,393 11,958 12,551 13,174 13,828 14,514 15,234 15,989 16,783

Load Factor 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70

AAGR Generation = 4.96% Generation Requirement (MWh) 79,654 83,606 87,753 92,107 96,676 101,472 106,506 111,790 117,336 123,157 129,267 135,680 142,411 149,476 156,891 164,675 172,844 181,419 190,419 199,866 209,781 Station and Line Losses (MWh) 6,372 6,688 7,020 7,369 7,734 8,118 8,521 8,943 9,387 9,853 10,341 10,854 11,393 11,958 12,551 13,174 13,828 14,514 15,234 15,989 16,783 Peak Demand (MW) 12.99 13.63 14.31 15.02 15.77 16.55 17.37 18.23 19.14 20.08 21.08 22.13 23.22 24.38 25.59 26.85 28.19 29.59 31.05 32.59 34.21 Required Capacity with Reserve (MW) 16.89 17.72 18.60 19.53 20.50 21.51 22.58 23.70 24.88 26.11 27.40 28.76 30.19 31.69 33.26 34.91 36.64 38.46 40.37 42.37 44.47 Fuel Required, Diesel Only (No Tina) Scenario (10^3 litres) 22,758 23,887 25,072 26,316 27,622 28,992 30,430 31,940 33,525 35,188 36,933 38,766 40,689 42,707 44,826 47,050 49,384 51,834 54,405 57,105 59,938

9 Mataniko Hydro Scenario Generation Calculation Generation Mix with hydro (MWh/year) Tina River Hydro Tina flag = - Stage 1 Output (HT Option 6) ------Stage 2 Output (HT Option 3) ------Total Existing Hydro (adjusted to load) ------Mataniko Hydro - - - - 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 Diesel 79,654 83,606 87,753 92,107 83,975 88,771 93,805 99,089 104,635 110,456 116,566 122,979 129,710 136,775 144,190 151,974 160,143 168,718 177,718 187,165 197,080 Fuel Required, Hydro Scenario (10^3 litres) 22,758 23,887 25,072 26,316 23,993 25,363 26,802 28,311 29,896 31,559 33,305 35,137 37,060 39,079 41,197 43,421 45,755 48,205 50,777 53,476 56,309 Fuel Saved by Mataniko Hydro (10^3 litres) - - - - 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629 3,629

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 10 Diesel Generator Scheduling Unit 1 (existing) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 Unit 2 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 Unit 3 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 Unit 4 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00 Unit 5 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 Unit 6 (new) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 Unit 7 (new) 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 Total Installed Capacity (MW) 26 26 26 26 26 26 26 26 26 26 26 44 44 44 44 44 44 44 44 44 44 Firm Capacity Available 22 22 22 22 22 22 22 22 22 22 22 36 36 36 36 36 36 36 36 36 36 Memo: Units Added Small Units (4 MW) ------1 ------Large Units (8 MW) ------4 ------

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11.3 System Expansion Planning At present there is insufficient information to determine how Honiara’s generation will be expanded. What is certain is that capacity needs to be increased either through Tina or through an upgrade of the thermal station at Lungga. The proposed Mataniko hydro scheme would displace initially 13% of the need for other generation in Honiara immediately after it is commissioned, declining to about 6% by 2030 as illustrated in Figure 11.3 above showing the contributions to generation under the ‘with Tina’ case and the ‘without Tina’ case, respectively. On the distribution side, SKM identified approximately 1,000 households and businesses that could be connected if the Honiara system was extended to residential areas to the East and the West of the current supply area.

11.4 Hydro Options for Honiara In addition to the Tina project two more hydro options exists to supply the Honiara grid. Figure 11.14 shows the location of the Lungga and the Mataniko projects.

Figure 11.4: Location of Lungga and Mataniko Projects

Mataniko

Lungga

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Lungga The Lungga project which in its original design included a dam and a reservoir as well as tunnelling had to be abandoned after more than 10 years of study because of numerous geotechnical challenges including porous lime stone formations and a very thick layer of alluvium that would render the construction of any larger structure in the riverbed a massive challenge. It has now proposed by a prospective IPP investor to install barrages with low head turbines located in the riverbed. Such a construction has to deal with extreme flooding assumed to be in the range of 5,000 m3/s through the construction of large spillways. An analysis has been carried out with heads varying from 10 to 35m and a capacity of the power plant varying from 15 to 40m3/s. The flow duration curve for the site shows that a typical low flow is in the region of 4 m3/s. This requires turbines to operate at a wide interval of discharge. At the lowest flow, ponding may concentrate the flow in the peak hours of the day, so the minimum discharge would be raised to 8- 10 m3/s. As the possible design flow of 15-40 m3/s is small for a low head scheme, a single Kaplan turbine would be an option, in the lower head interval. With more head and at the less design flow a horizontal axis bulb turbine may be an option as well. With higher heads and smaller design flows, a horizontal axis double runner Francis turbine seems to become least cost option. The calculated levelized cost of energy produced excluding land acquisition and finance cost seems to be about USD 0.18 per kWh at a head of 15 m, a design discharge of 35 m3/s and a generating capacity of 4.46 MW, an average energy production of 22.3 GWh/yr and a direct investment of USD 25 millions. The levelized cost per kWh increases beyond this with head until about USD 0.23 per kWh at a head of 35 m as displayed in Table 11.4.

Table 11.4: Design Variations of Lungga Low Head Scheme

Head Qdesign m3/s MW Production GWh/yr Investment US$ Levelized USD/kWh 10 35 2.91 14.525 17,248,000 0.1846 15 35 4.46 22.261 24,910,000 0.1739 20 40 6.84 31.011 38,082,000 0.1909 25 40 8.60 38.990 50,373,000 0.2008 30 40 10.44 47.333 63,116,000 0.2073 35 35 10.66 53.208 78,371,000 0.2289

Technically the main concern of the proposed scheme is the seepage below the barrage through a thick layer of gravel and limestone and the potential cavities in the limestone formation. It is assumed that an apron is constructed upstream of the barrage and at the edge of that a cut-off wall made to a depth of 8-10 m, below which cement injection is used to reduce the permeability of the sediments and limestone. An additional challenge would be the seismic design of the barrage. As the levelized cost for a low head scheme at the Lungga gorge would be more than double the cost of the competing Mataniko scheme, the Lungga option is not analysed further. The Mataniko scheme on the other hand has its own challenges, but at this stage seems to be a more attractive option and is therefore analysed in detail below.

11.5 General Description Mataniko Mataniko River discharges near the centre of Honiara, which would allow the construction of a powerhouse 3 km from the coastline and about 500 m outside the town boundary. The Project is fairly small, potentially 2-3.5 MW, which means that the power production can be absorbed to 100% into the Honiara which suffers severe shortage of power. It appears very competitive with a levelized cost about 0.085 USD/kWh. The project is simple and allows a short construction period

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(the delivery and installation time for the turbine, which may be about 2 years). There are, however, major obstacles to the development of the site. The most critical is perhaps the land acquisition issue. Landowners in the area have already requested compensation of 1 million SB$ for the installation of a gauging station which was therefore not implemented and future compensation claims may render the project un-feasible.

11.6 Hydrology In the absence of any runoff records for the Mataniko River, it is assumed that it would be 70 % of the specific runoff from Lungga Gorge, a catchment that is only a couple of km from Mataniko (see Figure 11.4). The estimate of 70% is based on the generally lower altitude of the Mataniko catchment and the formula for rainfall versus altitude developed in the Tina hydrology report. Applying these assumptions leads to the flow duration curves shown below. The Mataniko catchment is divided into two areas, one of 22.1 km2 on the main stream and a side catchment of 9.4 km2, which joins the main stream below elevation 120 m. An intake at elevation 162 m is assumed on the mainstream, while the side catchment has to be tapped at Elevation 120 m and pumped up into the main headrace canal when needed.

Figure 11.5: Flow Duration Curves for two Mataniko Catchments

5.0

4.0 Flow duration curves for Mataniko 3.0

M3/s 2.0

1.0

0.0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% % of Time Exceeding

31.5km2 Catchment 22.1km2 Catchment

Assuming a similar extreme flood level as Lungga Gorge measured in m3/s/km2 and about 5,000m3/s at Lungga Gorge, the extreme floods of 485 m3/s could be expected for the Mataniko river. However flood levels would have little impact on the design work for Mataniko HPP. As the intakes are assumed to be constructed as submergible structures, flood levels would only be relevant for the tail water level for the powerhouse.

11.7 System Layout The long profile of the Mataniko River shown in Figure 11.6 reveal the characteristics that determine the layout of the scheme. The bottom profile of the river indicates where the slope of the river is high enough to make hydropower development viable. Typically about 20 m per km at a flow of a few m3/s is considered as the lower limit. In other words it would not economic to push the powerhouse further downstream for the purpose on increased head than what is shown on the chart. At the top of the chart the level of the ridge is shown, which expresses how far a canal can be constructed downstream along the river. As it does not look attractive to move the powerhouse further upstream an intake elevation about elevation 160-165 m seems to be the upper level. The slope towards the river from the ridge is

31/25866 February 12 Page 117 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES very steep in certain areas in the upper part of the gorge. This requires the canal be placed as high up on the ridge as possible above the steepest part of the slope. This would facilitate construction and limited the risk of landslides damaging the canal. At the proposed level about elevation 160 m, a large part of the canal is on the grass covered top of the ridge with easy access for construction and maintenance. The disadvantage of the high canal alignment is that the canal becomes longer, as the contour lines are much less straight as on the steeper part below. At the top of the gorge a tributary joins from the east and only about 230 m from the main stream it divides into several smaller streams. It is not practical to go locate an intake beyond elevation 120 m, from where a short canal would be constructed and the water pumped 41 m up into the main canal through a pump penstock. This is best achieved by using an adjustable flow pump, as the flow to be pumped varies from about 150 to 850 liters/s.

Figure 11.6: Long Profile Mataniko River

200 180 Mataniko Long Profile 160 140 120 100

m.a.s.l. 80 60 40 20 0 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 6,500 7,000 7,500 8,000 8,500 9,000 9,500 Distance in m measured along river to the sea

Main River Penstock Main Canal Side river Side canal Pump Penstock Ridge Level

Road Access For construction and maintenance an access road is constructed to the fore bay at the end of the canal and at the top of the penstock. The road may be rather narrow, but should be paved, as a steep road between 1:10 and 1:8 will suffer heavily from erosion if designed as a gravel road. The road may cross the river either with an Irish Crossing (a concrete ramp going down into the river and up the other side, with some pipes below managing the minimum flow) or with a bridge with sufficient clearance to pass the extreme flow (585 m3/s) along with some large trees floating on the flood. The powerhouse requires its own access road has to be. There are two possibilities: the road can pass the river along with the other road and then follow the bank of the river up to the powerhouse. The last few hundred meters may be quite steep on the slope. The alternative is on the opposite side of the river, where there is significantly less slope. However this option required crossing of two side valleys and a crossing of the river upstream of the powerhouse with an Irish crossing, as the flow there 90 % of the time would not be an obstacle. Under flood condition the powerhouse may be reached on foot from the other access road along the bank. A 2-jet Turgo turbine is considered the optimal solution for all tested design flows. The use of less expensive Francis turbines is not recommendable as Francis turbines cannot operate under about 45% of design load. For Mataniko however, minimum flows are about 7-15% depending on the installed capacity. A double runner Francis would be able to operate down to 22.5% of design flow, while a multi-jet impulse turbine may manage practically any flow. The Turgo turbine requires a

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fairly large turbine hall. For a turbine with a capacity of 3 m3/s and delivering 3.3 MW a turbine hall of 21.6 m x 14 m (301 m2) would be required. The powerhouse would typically be remote controlled through a SCADA system

Figure 11.7: Layout of Mataniko Scheme

Seismic design loads For Honiara about 5 m/s2 design peak ground acceleration with a probability 10% in 50 yrs is assumed. This corresponds with a return period of 475 yrs. The project does not include dams and reservoirs, which in case of failure would result in a flood wave passing through the centre of Honiara. The seismic risk of the run off river design is loss of production until landslides damaging the canal have been repaired. This consideration may require higher design acceleration in the order of 6.5 m/s2. A higher specification impacts on the size of thrust blocks on the steep penstock and may require the use of deep rock anchors. The slope stability around the canal is also affected by seismic events. To mitigate this problem, the canal alignment has been pushed as far as possible up the slope of the gorge, where the slope gradient is lower. On the steeper part, draining off surface flow on the slope and subsurface drains under the canal would significantly reduce the risk of landslides, which are typically triggered is by saturation of and cracks in the soil.

11.8 Variations In order to establish the most economic design cost and energy production analysis has been carried out for 8 different variations whose results are displayed in Figure 11.8 below. Accordingly it appears that an installed capacity of 2.47 MW (design flow 2.0 m3/s), and an average annual production about 12.6 GWh/yr would be the optimal configuration with a total investment of about US$ 6.7 million and levelized energy cost of 0.085 USD/kWh.

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Figure 11.8: Cost and Energy Production Analysis Mataniko Variations

15

14 Annual Production versus Installed Capacity

13

12

GWh/yr 11

10

9

8 1,000 1,500 2,000 2,500 3,000 3,500 4,000 kW Installed

3,900 Investment per kW Installed Capacity 3,700

3,500

3,300

3,100 USD/kW 2,900

2,700

2,500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 kW Installed 0.25 Production cost versus annual production 0.20

0.15 Levelized USD/kWh USD/kWh 0.10

0.05 9 10 11 12 13 14 GWh/yr

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Table 11.5: Technical Characteristics of Mataniko Variations

Penstock Runner Generator Design Canal slope Canal Penstock Diameter diameter output Plant Production/yr flow m/km H m loss m m kW factor GWh/yr 1.067 1.40 0.74 1.53% 0.73 0.50 1,144 0.84546 8.833 1.447 1.29 0.85 1.36% 0.84 0.57 1,636 0.74858 10.583 1.828 1.21 0.93 1.25% 0.93 0.63 2,076 0.65777 11.793 2.194 1.15 1.01 1.18% 0.98 0.69 2,474 0.58605 12.619 2.285 1.14 1.03 1.16% 1.03 0.70 2,572 0.57160 12.785 2.590 1.10 1.08 1.12% 1.08 0.70 2,904 0.53639 13.226 3.047 1.05 1.16 1.06% 1.16 0.74 3,437 0.53639 13.725 3.500 1.01 1.23 1.02% 1.24 0.85 4,045 0.53639 14.027

11.9 Cost Estimates The following Table 11.6 summarizes cost estimates for a scheme at the Mataniko river that has an installed capacity of 2.74 MW and is able to supply up to 12.7 GWh per year to the SIEA system in Honiara. Specific cost are relatively low in comparison with other schemes as there are no long power extraction lines needed.

Table 11.6: Cost Estimates Mataniko Hydro US$ SB$ Feasibility Study 221,000 1,768,000 Development 257,000 2,056,000 Engineering 396,000 3,168,000 Hydro Turbine 1,968,000 15,744,000 Road Construction 164,000 1,312,000 Transmission Line Extraction 60,000 480,000 Substation 36,000 288,000 Penstock 348,000 2,784,000 Canal 1,580,000 12,640,000 Other Civil Eng 2,119,000 16,952,000 Total 7,149,000 57,192,000 say $7.2 Million US$/kW 2,609 say 2,600

The Cost Estimates presented here have been prepared for the purpose of prioritizing sites for further investigation and should not be used for any other purpose. They are subject to the limitations described in Section 1.4. Further detailed investigations, including geotechnical and hydrological investigations, would be required to firm up the cost estimates for budget setting purposes.

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11.10 Financial Analysis For the purpose of the financial analysis it is assumed the project to be commissioned in 2014, with its output representing about 13% of the total generation requirement of the Honiara grid in that year. A complicating factor in this analysis is that another, much larger, hydro scheme on the Tina River is currently being investigated23. It is understood that the Tina River scheme, as currently proposed, would be commissioned in two phases: phase I would initially provide 56 GWh per year to the Honiara grid in 2015, rising to 61 GWh/year by 2023, and Phase II would provide an additional 73 GWh of energy to the grid beginning in 2019, rising to nearly 86 GWh/year by 2030. The two Phases combined would provide approximately 147 GWh/year to the grid by 2030. However, the Tina River scheme faces severe uncertainties (similar to those that have dogged other large hydro schemes proposed for Guadalcanal in the past). Therefore, in respect of the proposed Mataniko scheme, two cases are considered: (i) assuming that the Tina River scheme is installed and commissioned as currently proposed, and (ii) assuming that the Tina River scheme is not installed.

Profit and Loss with Tina In comparison with the Diesel + Tina scenario for Honiara, the Mataniko hydropower scenario results in marginally reduced costs and marginally higher profitability under the current tariff as illustrated in the following three figures, Figure 11.9, Figure 11.10 and Figure 11.11. I.e. in case the Tina project went ahead, Mataniko does not appear to be an attractive option. The detailed financial projections for Honiara under the with-Tina case are shown in the Annex 4 and 5.

Figure 11.9: Revenue versus Operating Expenses Mataniko with Tina

Revenues vs Operating Expenses, Honiara Matakino Hydro Scenario $1,400.00

$1,200.00

$1,000.00

$800.00

$600.00 Operating Revenues

SBD millionsSBD Operating Expenses $400.00

$200.00

$- 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

23 Tina River Hydropower Development - Phase 1 Optimisation Study, Hydro Tasmania Consulting, 2011

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Figure 11.10: Revenue versus Operating Expenses Honiara with Tina

Revenues vs Operating Expenses, Honiara Diesel+Tina Scenario $1,400.00 $1,200.00 $1,000.00 $800.00 $600.00 Operating Revenues

SBD millionsSBD $400.00 Operating Expenses $200.00 $- 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Figure 11.11: Profit/Loss SIEA Honiara with Tina

Profit/(Loss) After Tax and Finance Charges, Honiara $800.00

$700.00

$600.00

$500.00

$400.00 Mataniko + Tina Hydro

SBD Million SBD Diesel + Tina $300.00

$200.00

$100.00

$- 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Profit and Loss without Tina In comparison with the Diesel Alone (without Tina) scenario for Honiara, the Mataniko hydropower scenario results in significantly reduced costs and higher profitability under the current tariff as illustrated in the following three Figures. The detailed financial projections for Honiara under the without-Tina case are shown in the Annex.

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Figure 11.12: Revenue versus Operating Expenses Mataniko without Tina

Revenues vs Operating Expenses, Honiara Matakino Hydro Scenario $1,400.00

$1,200.00

$1,000.00

$800.00

$600.00 Operating Revenues

SBD millionsSBD Operating Expenses $400.00

$200.00

$- 2020 2022 2024 2026 2028 2030 2010 2012 2014 2016 2018

Figure 11.13: Revenue versus Operating Expenses Honiara with Tina

Revenues vs Operating Expenses, Honiara Diesel Alone Scenario $1,400.00 $1,200.00 $1,000.00 $800.00 $600.00 Operating Revenues

SBD millionsSBD $400.00 Operating Expenses $200.00 $- 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Figure 11.14: Profit/Loss SIEA Honiara with Tina

Profit/(Loss) After Tax and Finance Charges, Honiara $200.00

$180.00

$160.00

$140.00

$120.00

$100.00 Mataniko Hydro, No Tina SBD Million SBD $80.00 Diesel Alone (No Tina)

$60.00

$40.00

$20.00

$- 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

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FIRR Analysis with Tina In a comparison of ‘with project’ (Mataniko hydropower) and ‘without project’ (Diesel + Tina) scenarios, the financial internal rate of return (FIRR) of hydropower investment is evaluated at 40.4%, greatly exceeding the WACC of 5.0%, with a financial net present value (FNPV, discounted at a rate equal to the WACC) of SBD 215.7 million. The full FIRR/FNPV analysis table is presented in the Annex. Sensitivity analysis has been carried out for increases in costs (capital and O&M) and decreases in benefits (reduction in the rate of real growth in diesel fuel prices, reduction in average annual hydro output, and reduced load forecast). The hydro option was found to be robust to changes in any of these parameters, and to an adverse change in all of them simultaneously, as shown in Table 11.7 with Tina, the financial viability of the Mataniko scheme is most sensitive to a reduction in the load forecast (as then Tina becomes a larger portion of the total load), followed by a reduction in Mataniko output.

Table 11.7: Sensitivity Analysis, Mataniko (with Tina) Test Switching Variation Sensitivity Basecase Switching Value Test Case (+/- %) FNPV FIRR Indicator Parameter Value (+/-%) Base (reference case) 215.74 40.4% Incre a se s in Costs 1. Capital Cost (SBD m) 20% 200.70 32.3% 0.35 57.19 221.25 286.9% 2. Hydro O&M Cost (SBD/kWh) 20% 213.46 40.0% 0.05 0.08 1.59 1887.0% Decrease in Benefits 3. Diesel Fuel Cost (real increase/annum) -20% 195.65 38.6% 0.47 3.0% 0.0% -100.0% 4. Hydro Output (capacity factor) -20% 162.36 31.1% 1.24 58.6% 14.2% -75.8% 5. Load Forecast -20% 125.52 36.7% 2.09 5.0% 0.0% -100.0% Initial Costs Increased (+) and Benefits Decreased (-) 20% 62.69 17.4% FNPV = financial net present value, FIRR = financial internal rate of return

FIRR Analysis without Tina In a comparison of ‘with project’ (Mataniko hydropower) and ‘without project’ (Diesel Alone (without Tina)) scenarios, the financial internal rate of return (FIRR) of hydropower investment is evaluated at 47.4%, greatly exceeding the WACC of 5.0%, with a financial net present value (FNPV, discounted at a rate equal to the WACC) of SBD 301.5 million. The full FIRR/FNPV analysis table is presented in the Annex. The higher financial performance of the Mataniko project in the without- Tina case in comparison with the with-Tina case is expected, as the project without Tina displaces more diesel generation than it does in the with-Tina case. Sensitivity analysis has been carried out for increases in costs (capital and O&M) and decreases in benefits (reduction in the rate of real growth in diesel fuel prices, reduction in average annual hydro output, and reduced load forecast). The hydro option was found to be robust to changes in any of these parameters, and to an adverse change in all of them simultaneously, as shown in Table 11.8. In the without Tina case, the financial viability of the Mataniko scheme is most sensitive to a reduction in hydro output, but is not at all sensitive to a reduction in the load forecast (because diesel generation is dominant in the total supply).

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Table 11.8: Sensitivity Analysis, Mataniko (without Tina) Test Switching Variation Sensitivity Basecase Switching Value Test Case (+/- %) FNPV FIRR Indicator Parameter Value (+/-%) Base (reference case) 301.49 47.4% Incre a se s in Costs 1. Capital Cost (SBD m) 20% 299.21 47.1% 0.04 57.19 286.45 400.9% 2. Hydro O&M Cost (SBD/kWh) 20% 263.22 42.7% 0.63 0.08 2.19 2637.0% Decrease in Benefits 3. Diesel Fuel Cost (real increase/annum) -20% 276.35 45.6% 0.42 3.0% 0.0% -100.0% 4. Hydro Output (capacity factor) -20% 226.15 37.9% 1.25 58.6% 11.7% -80.0% 5. Load Forecast -20% 301.49 47.4% 0.00 5.0% 0.0% -100.0% Initial Costs Increased (+) and Benefits Decreased (-) 20% 189.17 29.8% FNPV = financial net present value, FIRR = financial internal rate of return

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12. Environmental Aspects

12.1 Methodology In order to assist any subsequent environmental assessment, a narrative description of the environment and of anticipated impacts is provided for each subproject. The ADB’s Rapid Environmental Assessment (REA) checklist for hydropower was used to determine the environmental categorization for each of the six sites selected for this pre-feasibility study. The REA was undertaken by an independent consultant and completed in the period 6 September to 6 October 2011. It involved visits to each proposed location to determine the broad environmental considerations relevant at each site and consultations with intended project beneficiaries and landowners to ensure relevant primary data was collected. During site visis broad stakeholder consultations were held. The following section examines the potential environmental impacts and mitigation measures to be used in the construction and operation of a mini hydropower facility at these sites. A separate REA sheet is provided in Annex 6 for each subproject.

Public Consultation and Information Disclosure Consultations and discussions were held with community groups, Provincial Government officials, community leaders and schoolteachers in each location to raise awareness in the proposed project and the environmental and social impacts that could be expected. In each case, a broad range of questions was asked to prompt discussion on concerns relating to the project. Concerns over the perception that dams or reservoirs were to be constructed and the impact those facilities might have on the water quality and livelihoods were allayed once the proposed hydro system was generally described. Questions were also asked over the presence of sites of cultural or religious significance, wildlife and general community use within the project catchments, which provided information as to the likely environmental impacts from the project. Table 12.1 displays the public consultations held. Annex 6 also contains a list of stakeholders consulted.

Table 12.1: Public Consultations

Site Date Community No. Male Female Persons

Auki 10/9/1 Kwainoa 8 5 3

Lata 26/9/11 Pala 30 18 12

Mase 3/10/11 Mase 45 35 10

The participants in those sites where public consultations were carried out were all in favour of improved electricity supplies because of the improvements it would bring to their ability to develop business opportunities, schools and studies and general reduced reliance on the household use of fossil fuels which are becoming prohibitively more expensive. There were no negative impacts raised from the project and there was an overall desire in all sites to start the works as soon as possible. There were no public consultations at Ringgi as the site is within leasehold land of the forest company. At Taro, there was no village in the vicinity of the proposed project site, and no consultation was carried out at Honiara as landowner issues had already been identified.

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12.2 Project Description The projects considered in this study are small run-of-river hydropower projects with minimum technical complexity. They are similar but vary in size and scale depending on the location. Typically, they will involve the following construction activities at each site, should they satisfy the selection criteria for a more detailed feasibility study and progress to construction. a) Access roads – these will be constructed from the end of any existing roads to the power house and fore bay structure to allow the delivery of construction materials, penstock pipes and electromechanical equipment. b) Intake structures – these are excavated on the river bank to divert run-of-stream flows into a canal using a submerged intake sill to provide sufficient flow into the canal and still provide for fish passage. A minimum stream flow level should be determined for each site. c) Headrace canal and fore bay – the concrete headrace canals are constructed on the contour on an excavated bench on a very low gradient over varying distances from the intake structure to the fore bay structure, which delivers water to the penstocks. d) Penstock – these are prefabricated 250-300 mm steel pipes, buried in a trench or placed on bearer blocks or foundations, which take water directly down slope from the fore bay to the power house. The length of the penstocks varies at each site depending on the available head. e) Power house – generally a small structure located on the river bank at the bottom of the penstock that houses the turbines and electromechanical equipment. Access is by a road to be constructed. f) Transmission lines – deliver the electricity from the power house site to the grid via lines suspended from power poles along a corridor, often an existing road, but also cleared through natural and plantation forest and across garden land.

12.3 Local Environment Auki, Malaita Province

Physical Resources The Fiu River catchment is narrow and elongated and runs in a southeast to northwest direction through predominantly Cretaceous and Tertiary limestone and sedimentary formations. The headwaters arise on the slope of Tolosi Hill, 896 m asl, and run some 24 km to the coast, entering the sea north of Auki. The catchment has a width of around 1 – 2 km in the middle to upper reaches, gradually widening to 2 – 4 km in the lower reaches. It is generally steep terrain with slopes in excess of 35 – 40 degrees arising from the river near the powerhouse site and rising some 120 m and more in altitude within 300 m of the river channel. Numerous ephemeral gullies enter the river system, characterised by large boulders and blocks of limestone, on both sides of the valley. Surface water flows are intermittent during high intensity rainstorm events and often flow underground where there are sinkholes in the limestone formations. Water was observed to enter at river level at many places along the river. Seepage points at higher elevations are used for domestic water supply. The water is very clear with little or no suspended sediments in normal flows. The river passes through a steep sided gorge from below the village of Kwainoa before widening around 1 km upstream from the end of the road. This lower section of the river to the gorge is used for village access before the track climbs up around 80 m above the river. The river channel is stable, with vegetation growing right down to the riverbanks. While high flows of around 4m above normal flow in the gorge near Kwainoa are reported, these peak

31/25866 February 12 128 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES flows are of short duration and generally less than 24 hours. There is no evidence of stream bank erosion and loss of vegetation along the river channel. Tropical cyclones are a regular feature throughout Solomon Islands and can cause wide scale destruction to forest and water resources and infrastructure. Average annual rainfall at Auki is around 3,200 mm with higher monthly values from January to March. An automatic rain gauge has been established near the village of Kwainoa on an exposed limestone outcrop. An automatic water level recorder has been installed on the true left bank on the Fiu River near the proposed power station site and the track linking the village houses on both sides of the river. Both gauging stations were installed as part of the RETA 7329 project in each of the project sites and will provide more reliable data on the hydrological characteristics of the catchment. Earthquakes of a magnitude greater than 5.5 on the Richter scale occur about twelve times each year in the Solomon Islands. Most activity is in Santa Cruz, Makira, the south and south east of Guadalcanal, the Russell Islands, southern New Georgia and the Shortland Islands. Malaita, Santa Isabel and Choiseul are less active24.

Ecological Resources The forest within the middle to upper reaches of the catchment has not been subject to commercial logging operations. Low intensity community logging has resulted in cleared land for agriculture mid slope above the river gorge. Forest species include Canarium indicum and Pometia pinnata, both used for local village construction activity. Some large diameter species were observed within the gorge section, which has generally been untouched by human activity due to it being largely inaccessible. Slopes are stable with little evidence of active land slips or slumping. Garden activity is generally located on mid slopes and does not exhibit soil loss due to rill and gully erosion. The forest is considered generally poor in terms of wildlife for village hunting purposes. Wild pig populations are very low and are not hunted. Bird life was hunted for food, particularly kurkuru (pigeon) but this activity has been discontinued when all privately owned firearms were confiscated ten years ago as a result of civil tensions within the country. Villagers report the pigeon population has increased since the demise of hunting activity. Possum numbers are reported to be plentiful but, for the same reasons, are not hunted. Locals report there are now no large fish species within the catchment, when extensive trapping and netting in the lower reaches resulted in the loss of the fish population some ten years ago. Smaller endemic fish species are plentiful in the river but are not fished by local communities. There is an abundance of amphibian species, with most pools and river margins showing an abundance of frogs and tadpoles. There are no known protected areas within the study area. The local community has ensured the forest has not been extensively logged other than for their own requirements. The river gorge section around the power station site is unlikely to be logged due to the very steep terrain. Access and terrain are the main constraints to commercial logging activities that are common in other catchments on Malaita.

Economic Development The area proposed for this small-scale project lacks any infrastructure. It is remote and there are no roads beyond the end of Fulisango Road, some 8 km from Auki. There is no reticulation of power, water or other services in the project area.

24 Aldrick, John M, 1993. The Susceptibility of Lands to Deterioration in the Solomon Islands, Project Working Paper 12. Ministry of Natural Resources, AIDAB.

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The main economic activity is subsistence agriculture with limited commercial quantities of cocoa and coconut. Commercial crops include cocoa and coconut but distance from the market and the lack of road access has severely restricted development of any activity. Local production of sawn timber is a key activity. Access to the market is a major constraint in the development of livelihoods, and all produce must be taken by foot. There is no supply of crushed aggregate for construction in the vicinity of Auki although there is reported to be gravel extraction from the lower reaches of the Fiu River near the coast. While a mobile crushing plant is potentially available for use on Malaita and a suitable resource has been identified, ongoing landowner issues and subsequent damage to property and machinery have been cited as the reason why there is little interest from local operators to establish one there. A mobile batching plant has been used for a range of recent provincial infrastructure projects, but all crushed aggregate is sourced from Honiara.

Social and Cultural Resources The resident population in this catchment is small. The customary owned land is used for subsistence agriculture and limited scale logging activity for local use. All access to upper catchment villages is by foot. The community have described the presence of numerous tambu sites on the ridge top on the north side of the river. These sites are not located near any proposed construction activity associated with the project. A burial site is located near the village of Kwainoa.

12.4 Local Environment Taro, Choiseul Province

Physical Resources The Sorawe River, the only river that has hydro potential near Taro, is located on the mainland and drains into Choiseul Bay. This river, referred to as Sui River on the 1:50 000 topographic map Taro, arises in karst geology on the northern flanks of Mt Talaevondo, 494m asl, some 10 km east of the river mouth. The lower 3 km of river flows through an undisturbed area of mangrove swamp forest. The river cascades over an exposed limestone rock layer or around 8 – 10 m in height, which marks the end of the navigable waterway a short distance beyond the old log access bridge that spans the river. The water to this point is subject to tidal influences. The northern tributary arises on the slopes of Mount Arara, 224 m asl, some 5 km north east of the junction. Soils in this karst lithology are generally very shallow and in many cases absent, with exposed uplifted limestone deposits. The water runs clear, with no suspended sediment load or significant bed load material, in an incised stream channel. The source of the water is derived both from under ground recharge areas in the limestone formation and run off from hill slopes. Stream flows can also be sourced from underground recharge zones from outside of the catchment boundary in these formations. The proposed power station site is practically at sea level and there are no un-dammed tributaries below this site. The northern tributary river joining the Sorawe below the falls, and only a few hundred metres upstream of the power station site does not contain large quantities of sediments or gravel deposits, despite the extent of previous logging and road construction activities. The stream flows in the upper reaches are reported to be intermittent with many sections being subterranean flows. There is very little river gravel in this part of the island. Some uncrushed river gravel for construction comes from Nukiki, 6km south east along the coast of the main land, with the majority of the aggregate used for building coming by barge from Honiara. Average annual rainfall on the small off shore island of Taro is 3,200 mm, distributed evenly throughout the year, with lower falls in December – January. Rainfall is expected to be higher in the upper catchment of the Sorawe River. An automatic water level recorder has been installed on the true left bank near the proposed water intake point to provide a more reliable

31/25866 February 12 130 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES assessment of discharge from the catchment. An automatic rain gauge has been installed at the site of the old logging camp down river from the powerhouse site. Tsunamis are a threat to the small islands and lower lying areas in Choiseul Bay. The last tsunami in April 2007 resulted in damage in Taro and Gizo. In terms of seismic activity, Choiseul is less active than other areas of Solomon Islands.

Ecological Resources The headwaters of this northern tributary of Sorawe River have been subject to extensive logging in the past by Eagon Resources Development Co Ltd, which has had a long history operating in this part of Choiseul. The forest was mixed lowland forest of Pometia pinnata, Calophyllum spp, Campnospermum brevipetiolata and Vitex cofassus. These species were predominantly exported as round logs with limited in-country processing. A small area of easier accessible land south of the Sorawe River was also logged for swamp forest species. This is the area of the proposed new site for the Government township of Taro, which has been under discussion for some 20 years. Logging did not extend further south or to the upper Sorawe catchment due to the difficult karst terrain, with sharp ridges and numerous sink holes making any logging activity inherently uneconomic and difficult for machines to operate within. Part of the logged area has been established in plantation species ten or more years ago, including Eucalyptus deglupta (kamarere), Acacia mangium and Terminalia brassii. There is no longer any logging activity and the camp has been abandoned, with all buildings in disrepair. The log bridge over the river near the proposed power station site is in a state of near collapse and will eventually fall into the stream channel. Other log bridges in the upper catchment will be of a similar condition. The upper Sorawe catchment will remain in an undisturbed state and will unlikely be subject to any future logging activity due to the difficult karst formations. It will form a significant protection area in the region, extending well beyond the area for the proposed project. This limestone formation, with its specific flora and fauna, is widespread in this part of Choiseul. There are no significant wetlands in the catchment due to the underlying karst formation. The mangrove forest, which extends some 2km upriver from the river mouth, is used for local construction purposes but is generally limited to the harvest of single trees. There is little recent evidence of any harvest of mangrove species. The mangrove forest has not been damaged by the commercial logging activity. Hunting of pigs, flying fox and pigeons is considered difficult in the limestone terrain of the Sorawe catchment, with more animals present in the logged forest and plantation areas to the north where access is easier. The level of hunting activity for these animals generally has significantly reduced as a result of civil tensions within the country when all privately owned firearms were confiscated. Fish are plentiful in Choiseul Bay and the lower reaches on the Sorawe River through the mangrove forest. Salt water species are caught by local people right up near to the waterfall. Freshwater prawns exist in the stream above the waterfall. Saltwater crocodiles exist in the mangrove forest but, by law, are not hunted. There is no known protected area within the catchment but Parama Island in Choiseul Bay is a designated conservation area for the protection of reef fish habitat.

Economic Development The provincial capital of Taro is located on a small offshore island and is the seat of the provincial government departments. It is serviced by regular flights to Honiara via Gizo. The airfield on Taro, one of only two in Choiseul Province, is currently being expanded and strengthened to take larger capacity aircraft.

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The catchment of the Sorawe is not inhabited and the terrain is unsuitable for subsistence agriculture. It is in undisturbed natural forest and is held in customary land ownership. The existing road network established by Eagon has now largely been abandoned since the departure of the camp and has become overgrown in many places. A gravity-feed water supply to provide potable water to the secondary school, located on the coast near the pier, arises from the Sorawe River, which supplies a consistent flow and quality. The intake for this water supply is located some 4 km from the school and above the proposed water intake site for the power project. It consists of 100 mm high density polyethylene pipe buried in a hand-dug trench cut into the limestone substrate, now completely overgrown by trees and ground cover species in the last 20 years since it was installed. The exact location of the pipeline is now difficult to readily identify. The project will not have any impact on the water supply to the school. Future plans to utilise this source for a potable water supply for the planned Taro village relocation site have been investigated. A concrete pier facing Emerald Entrance in Choiseul Bay, a few hundred meters north of the high school, carries the regional tsunami early warning system. The log pond used by Eagon for loading log ships just north of the pier is no longer in use. No new quarry sites are anticipated. Should road construction material be required, there are existing quarry sites developed for the forestry road network that lie outside of the immediate project site which could be utilised.

Social and Cultural Resources While all forest land is used for traditional purposes by customary landowners, access and terrain limits the use of the forest in this location. However, traditional building materials are gathered in the area as they are not readily available in logged areas or those that were established in plantation species. Tambu sites are reported to be on Mt Arara, which is located outside of the Sorawe catchment being considered for the hydro project. There are no reported cultural sites within the Sorawe catchment.

12.5 Local Environment Lata, Temotu Province

Physical Resources The Luembalele River enters the southeastern part of Graciosa Bay, a large deepwater bay extending some 5 km south of the provincial capital of Lata, located on the western side of Ndendo Island (Santa Cruz). The headwaters arise from the southern flanks of the high peak, 461m asl, some 8km from the river mouth. The catchment is narrow with numerous ephemeral gullies along the dissected slopes entering the river system. The water flows initially south down the side of the peak then heads west to enter the bay by way of a steep sided gorge eroded into the raised reef formation. Short duration flash floods are evident in this short catchment. The river mouth was extensively damaged in a recent storm and the access bridge across the river was washed away. The river is now some 50 wide at the mouth, with a large portion of the foreshore on the northern beach extensively eroded. There are no mangroves on the lower river section. The central part of Ndendo Island consists of Miocene basaltic lavas and pyroclastic flows, with the western third of the island covered by an elevated terraced veneer of Quaternary raised coral reef, arising some 150m above the current sea level. Overlying much of the lower limestone formation are residual bauxitic clay soils of varying thickness. The southeast trade winds blow from March to September, the period when cyclone activity can occur. Cyclone Tia caused damage in the province in 1991. Average annual rainfall at Lata is 4270 mm but this is expected to be higher in the upper catchment of the Luembalele River. An automatic rain gauge has been established on the side of a now-overgrown logging

31/25866 February 12 132 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES road near the old skid track heading down to the river. An automatic water level recorder has been installed on the true left bank of the river above the waterfall near the proposed water intake point to provide a more reliable assessment of discharge from the catchment While seismic activity is widespread in Temotu Province, with an active volcano, Tinakulu, lying offshore Ndendo some 25 km north of Lata, the last significant quake was reported in 2010. Subterranean earthquakes can result in tsunamis, with some 13 significant tsunamis being recorded in the Solomon Islands between 1926 and 1982, an average of one every 4.3 years (Aldrick 1993). Older people refer to tsunamis around Ndendo but there have been none reported in recent history. A regional tsunami early warning system is located on the main pier in Graciosa Bay.

Ecological Resources The lowland forest type found on the western side of the island consists typically of Pometia pinnata, Campnospermum brevipetiolata, Dysoxylum excelsum Canarium indicum, Terminalia calamanesii, Eleocarpus, and Endospermum medullosum. Kauri, Agathis macrophylla, found more at the higher altitudes, was the main species logged in earlier times. Many large Agathis trees were retained for habitat and seed sources and seedling regrowth is evident throughout the regenerating forest. The upper catchment of the Luembalele River has not been extensively logged. Allardyce Lumber Co Ltd had established a logging operation in the early 1970s in Temotu Province but had ceased operations on Ndendo some time ago before another company revived operations on the eastern side of Graciosa Bay in 2007. It is reported only two log shipments were loaded out of a log pond located just north of the Luembalele River mouth. The Provincial Government had imposed a ban on round log exports, which resulted in the logging company ceasing its operations after around six months. Pigs and kurukuru (pigeons) were regularly hunted but the level of hunting activity for these animals generally has significantly reduced as a result of civil tensions within the country when all privately owned firearms were confiscated. Hunting continues at a reduced level using traditional means, including bow and arrow. In particular, pigeons are hunted during high winds when they tend to take shelter on the ground. Pigeon meat and coconut crab is regularly sold in the local market Wild fowl (Spanish fowl) are abundant in the forests on Ndendo and are a relic of the explorer Mendana who left them on the island during the 1600s. These are hunted and trapped and kept locally for breeding. Local residents report a decrease in fish stocks in Graciosa Bay. There are freshwater prawns, small fish (sliver fish) and eels in the Luembalele River. Turtles are not found in the area but crocodiles have been reported but, by law, are not hunted. There are reports of people being attacked by crocodiles in the area. Temotu Province does not have any formalised protected area25.Traditional landowners do not report any informal protected area within the Luembalele River catchment.

Economic Development Lata is serviced by regular air and island shipping service from Honiara. It is also a port of call for itinerant yachts as Graciosa Bay provides good deep-water shelter. The Provincial Government has recently signed a Memorandum of Understanding for trade with Vanuatu, which is closer to Temotu Province than is Honiara. The majority of the Luembalele catchment is Government leased land, being LR 716 and LR 836. Only the lower 2 km of river section passes through customary land. Around 300 ha of

25 Temotu Provincial Government, Strategic Development Plan 2011

31/25866 February 12 133 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES plantation forest had been established by Allardyce Lumber as part of requirements of the concession agreement, using predominantly Sweitenia macrophylla (mahogany), Tectona grandis (teak), Campnosperma brevipetiolata and Eucalyptus deglupta (kamarere). The quality and form of the Campnosperma is generally poor, having been extensively damaged by cyclones. Local landowners have subsequently established smaller holdings of plantation species, mostly mahogany, on customary land. The size of this resource was not determined but it is not considered to be extensive. Seven portable sawmilling operations for local construction requirements occur on customary land. Some 20 m3 of Pterocarpus indicus (rosewood) is shipped to Honiara per month for the furniture market, the only species exported from Lata. There is very little river gravel on the island suitable for construction. Coarse sands in Graciosa Bay are used for the production of building blocks for local construction. Most crushed aggregate is sourced from Honiara but some is sourced locally from river mouths on the northern and eastern sides of the island. There is an abundance of limestone for use as a road surfacing material and there are existing quarry sites available outside the proposed project site. Three head of cattle remain on the western side of Ndendo as a result of a 1990s cattle project, with a small number on the eastern side of the island.

Social and Cultural Resources The Luembalele River catchment is not inhabited and the Pala community, the customary landowners of the area, report there are no tambu sites or known items of cultural significance recorded in the vicinity of the project. A spring fed water supply arising from the bottom of the limestone cliffs near the mouth of the Luembalele River provides piped water to Lata and all villages along the shore. A diesel generator pumps water to a reservoir but the use of the pump is limited to twice a day due to fuel rationing. A more reliable source of power would provide an uninterrupted water supply to Lata.

12.6 Local Environment Ringgi, Western Province

Physical Resources The Vila River, the largest catchment on Kolombangara Island, arises from the caldera an extinct Pleistocene volcano, with the highest peak, Mt Veve, being 1,770 m asl. Like all catchments on the island, it is long and narrow and less than 2 km wide. It flows generally south through deeply dissected terrain, forming a large alluvial fan extending into the Blackett Strait. Slopes in the upper catchment above 400 m are steep to precipitous while valleys become well incised with numerous small gullies below this level. Kolombangara Forest Products Ltd (KFPL) has operated a rain gauge at Ringgi since 1993 which shows a mean annual rainfall of 4,000 mm with a monthly average of 250-300 mm. There is a slight drier period in August-September. Kolombangara is located on the northern limit of the tropical cyclone belt. Another rain gauge has been installed near the Imbu Rano Lodge and automatic water level recorder is located on the true right of the Vila River below the lodge to get better hydrological information near the site.

Ecological Resources Kolombangara Island Biodiversity Conservation Association, an independent NGO, jointly manages with KFPL the conservation area above 400m. This designated conservation area, which includes the three highest peaks, covers 28% of the island and is the larges tin the Solomon Islands. The Vila River Reserve is managed by KFPL as wildlife corridors and to preserve water quality for drinking. The Vila River and the crater lie within the KFPL lease.

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As part of Forestry Stewardship Council (FSC) certification, KFPL is progressively working on identifying the High Conservation Value Forest areas within its Fixed Term Estate. The report recommends the riparian buffer zones of the Vila River should be classified as HCVF areas because it hosts two rare freshwater fish species and two endemic freshwater species26. The recent WWF study showed Kolombangara supports more than a 100 bird species, with many restricted ranged species, vulnerable species, endemics of the New Georgian islands, and two island endemics. The IUCN status of two birds found on the island, Aplonis brunneicapillus (White-eyed starling) and Columba pallidiceps (Yellow-legged pigeon) are cited as endangered while Pseudobulweria becki (Beck’s petrel) is critically endangered. Mammals are dominated by bats but also include prehistoric introductions such as the marsupial Phalanger orientalis (Northern common cuscus) some rats, and pigs. Skinks dominate the reptile fauna which are abundant in both open and secondary forests as well as primary forests. Frogs make up some of the most abundant of terrestrial and mid canopy vertebrates and new species are still found in high elevation forests 27. Most of the lowland forests up to 400 m asl have been logged and replanted in commercial plantation species including Eucalyptus deglupta, Gmelina arborea, Swietenia macrophylla and Tectona grandis. Ridge and hill forests extend into montane and cloud forests, mostly clad in lichens, wet moss and epiphytes, at the highest altitudes above 700 m asl.

Economic Development KFPL has recently been sold to a Taiwan based company who have confirmed their commitment to the principles of FSC. As part of the social responsibility component of FSC certification, KFPL has allocated 300 ha in 57 blocks to local landowners to develop their own business enterprises. The Imbu Rano Lodge, on the edge of the Vila River Reserve, is an ecotourism business which provides a range of activities in the areas above 400 m and within the Vila River Reserve. Coastal villagers use the reserves and protected forest areas and above 400 m as their hunting and fishing grounds. There is aggregate suitable for concrete available from the lower Vila River and this would require a crushing and batching plant to operate in close proximity to the river.

Social and Cultural Resources The most important cultural sites are located within the high altitude forests, which is also the source for all water for the local people. Evidence of human settlement on the ridgelines and hill forests above the Imbu Rano Lodge can be observed up to 700 m contour when these were used as shelter during periods of head hunting. These are above the proposed project sites which are below the 400 m contour line.

12.7 Local Environment Mase River, Western Province

Physical Resources The Mase River arises from a remnant volcanic crater some 7 km by 6 km wide in the central part of New Georgia. The headwaters are dominated by two peaks, Mt Mase on the north side of the crater at 910 m asl and Mt Vinarori at the south side at 913 m asl. The river then runs some 20 km from this wide crater through a narrow steep sided gully on deeply

26 Vigulu, V. 2011. The Documentation of High Conservation Value Forest, Standards and Procedures at Kolombangara Forest Products Ltd on Kolombangara Island. 27Pikacha, P and Sirikolo, M. 2010. Biodiversity of the Crater Area and Surrounding Mountain Forests, Kolombanagara. Island. WWF

31/25866 February 12 135 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES dissected terrain on the north western side of the mountain before entering the New Georgia Sound (The Slot) at Mase Inlet. There are a number of tributary streams entering the Mase River below the 200m contour line on the lower flanks of the mountain. Average annual rainfall is around 3,500 – 4,000 mm but this is expected to be significantly higher in the upper catchment where there is frequent cloud cover. An automatic rain gauge water level recorder has been installed to provide more reliable data on the hydrological characteristics of the catchment.

Ecological Resources Much of the forests in New Georgia below the 400 m contour line have been extensively logged in the past 30 years for a range of lowland forest species including Pometia pinnata, Campnospermum brevipetiolata, Canarium indicum, and Terminalia calamanesii. Community forest plantations have been established close to the coast along the western side of the island. There are no known ecological reserves or conservation areas in this part of New Georgia. Studies on the status of freshwater fish in the catchment are unknown but fish are recorded by locals being present in the river.

Economic Development There is an extensive network of old logging roads in various states of repair. All the major ridge lines on the north west of the island have road access, in some cases up to the 500 m contour line. Roads only cross streams near the coastline. There is vehicle access linking Mase with the Noro - Munda Road that could also serve as the transmission line corridor. Aggregate supplies could be available within the catchment but will require further investigation to determine quantities and access options. Pacific Porphyry are currently conducting an exploration drilling program for copper and gold using portable rigs within the Mase caldera. Previous drilling programs have been carried out lower down the catchment and the local community have raised concerns of the impacts on water quality. It was reported the rivers carry a high sediment load during heavy rains, with the consequent build up of sediment in the Mase Inlet. The source of this sediment was not confirmed and could be a result of landslips or previous logging or drilling activities. A gravity fed water supply system was installed at Mase in the mid 1990s. The intake for this system is located in the first major tributary on the true right of the Mase River, some 3 km from the village at an altitude of around 100 m asl28. The water supply will not be impacted by the project.

Social and Cultural Resources There are no permanent settlements in the upper reaches of the Mase River catchment due to the terrain and area being unsuitable for the development of gardens. Nearly all settlements are located close to the coast. There are no known items of cultural significance that are reported by the local community. Tambu sites are noted on the high peaks of the mountain but they will not be impacted by project works.

28 P Woperis, pers comm

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12.8 Local Environment Mataniko River, Guadalcanal

Physical Resources The Mataniko River is a large catchment arising from the Lungga plateau, at an altitude of around 760 m asl some 15 km south west of Honiara. The river flows east through Cretaceous and Tertiary volcanic formations for some 7 km, joined by two other significant steep sided catchments, before joining with a smaller eastern tributary to flow north east through a narrow gorge between the Mbao and Tanda Ridges. Numerous small streams and rivers enter the Mataniko River all the way to Honiara where it enters Iron Bottom Sound near Chinatown This eastern tributary has its headwaters in the Queen Elizabeth National Park, on the ridge dividing it with the large Lungga River catchment which lies immediately to the south of the Mataniko catchment. The Mataniko Waterfall is located on this eastern tributary, made up of three smaller steep catchments. All the tributary streams are incised in narrow steep sided catchments. The northern coast of Guadalcanal lies in a rain shadow, but rainfall is significantly higher in the upper catchments. An automatic water level recorder to determine the hydrological characteristics of the river was planned for installation until landowners made unrealistic compensation claims, a precursor for future claims for any power development within the catchment.

Ecological Resources The area is generally degraded lands with ridge lines in a cover of grass. The gorge and upper catchment area are comprised of lowland hill forest species. These have not been logged due to the terrain. Studies on the status of freshwater fish in the catchment are unknown but fish are recorded by locals being present in the river.

Economic Development The current access road to the Mataniko ends at Tavaruhu village from where local guides are engaged by tourists to visit the Mataniko Waterfall and caves. There are no other infrastructure facilities and little development beyond this village, some 2 km from the coast. Garden activity is confined to the lower slopes near the village. While there is a suitable gravel source within the river system, there is an adequate supply of readily available crushed aggregate in Honiara from an established crushing plant on the nearby Lungga River.

Social and Cultural Resources Tambu sites were not identified but the area contains many historical sites of intense combat during the Battle of Guadalcanal.

12.9 Screening of Environmental Impacts

General The following discussion describes likely impacts and indicates some possible mitigation measures, to guide environmental assessment and EMP preparation when designs for each scheme are in an advanced stage. The construction of the type of run off river project considered here involves excavating or blasting a canal entrance on the bank of the river, with water flow being directed into the headrace canal with large anchored boulders placed below the intake to provide the

31/25866 February 12 137 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES necessary flow. No concrete structures or weirs across the stream channel are proposed. Since there is no barrier to cause mobile sediments and gravels to build up in the streambed, there will be little impact on the stream hydrology as a result of the intake structure. Flow characteristics are currently being determined for each site with automatic water level recorders. Fish passage upstream shouldl not be impacted by the design of this intake structure but fish may end up in the headrace canal. There will be a short-term impact on water quality and sediment loads in the river during the construction of the intake structure but this will be mitigated if the appropriate construction methods are followed. Road construction and associated earthworks provides by far the greatest source of mobile sediments and debris with the resultant reduction in water quality. This is especially so in steeper terrain where higher cut slopes and longer fill slopes are required, unless all excavated material is end-hauled for disposal in another more stable site. Roads must be properly designed, constructed and supervised to mitigate the impacts of sediments and debris entering watercourses. Poorly located and constructed roads generally result in on- going soil erosion and increased sediment loads in adjacent water courses long after the construction period has ended. A robust maintenance program will be necessary to ensure the ongoing integrity of the system and that potential negative environmental outcomes as a result of impaired drainage and surface water runoff are managed. The steeper the terrain on which the road or headrace canal is positioned, the wider the effective cleared corridor through the natural forest becomes. The wider this corridor is, the more unstable any residual trees become, especially when the root plate of trees on the top of the cut slopes is damaged. It would be critical to ensure any large diameter trees are not subject to future toppling in high winds or cyclones as these could cause a major failure of the concrete canal structure should they fall or slip down onto it. While logging of forest land on slopes greater than 30 degrees and above the 400m contour is not permitted under the Forest Act, the removal of trees and vegetation above the river channel without debris and soil entering the watercourse will be feasible if the appropriate technologies are utilised and incorporated into the environmental management plan (EMP). Slips and debris slides along the canal alignment pose a potential risk to the integrity for the canal structure, with the resultant diversion of canal flows into non-stream receiving areas. Gully erosion and potential slope failure below the canal corridor will lead to a massive increase in debris and sediment loads entering the watercourse. The resultant impact on water quality will be ongoing for a considerable period of time until the eroding gully and debris becomes stabilised. This can be mitigated by the installation of automatic shut off gates at the intake. The proposed construction of trenches for the penstocks will be determined by the slope and underlying geology. Any such trenching on steep slopes has the potential for significant soil erosion of the back- filled material from surface water runoff. These factors would have to be taken into consideration during the detailed design phase, with each site posing its own specific technical requirements. The environmental issues raised can be mitigated with the appropriate design and supervision during construction and a robust Environmental Management Plan and Site Specific Management Plans to address each construction activity. Establishing a transmission corridor through primary forest generally requires a wide clearance footprint to reduce the likelihood of power disruption from falling trees and broken branches from wind, a significant cause of power outages. Any earthworks required for the installation of poles will be subject to the conditions of a detailed Environmental Management Plan and is not expected to result in any significant offsite impacts if appropriate water control measures are adopted. Vegetation clearance along the transmission corridors will be an ongoing maintenance matter. This will generally be carried out manually due to the limitation of terrain and access and the activity will not result in any environmental impacts as long as ground cover is retained. The use of Arial Bundle Cables (ABC) for the transmission lines would reduce the need for vegetation management.

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Noise and vibration associated with the machines and construction activity will have no significant impact on any community due to the scale of the work and the fact the areas are relatively uninhabited. There will be no significant impact on air quality apart from the presence of a small number of heavy earthmoving machinery during the construction period. Air quality will improve with the completion of the power project as there will be less demand for fossil fuels with the many small capacity generators. In the following, the screening results for the individual sites will be summarized.

Fiu, Auki, Malaita Province The power station site is located near a steep sided narrow section of the river with slopes in excess of 35 degrees. In order to construct a road into this site, a larger corridor of vegetation clearance will be necessary. Any road line leading down to power station would need to be carefully surveyed to reduce the height of the steep cut slopes, with spoil and vegetation cleared from the road line being end-hauled and disposed of elsewhere to reduce the likelihood of large volumes of sediments entering the Fiu river channel. With an improved road line or powerhouse location and appropriate sediment and erosion control measures incorporated in a detailed EMP, coupled with strong site supervision, the impacts of road construction activities can be mitigated. However, ongoing slips and erosion of the road line can be expected. The headrace canal runs some 3000 m mid slope through predominantly undisturbed forest area and traverses five to six large ephemeral gullies from the intake to the fore bay. The canal will span these gullies, which show evidence of large short-duration flows during rainstorm events. The gullies are generally characterised by the presence of large limestone boulders and sink holes. Water rapidly enters the recharge zone in the limestone formation and enters the river at water level in many parts of the river channel. A consideration at these gully crossings for the canal is to ensure any earthworks required for access do not alter the integrity of the ephemeral gully by blocking sinkholes and fissures with sediments that might affect the intricate network of subterranean flow channels on these steep slopes. The loss of the subterranean flow channels will increase the volume of surface flows and thus the amount of sediment transportation into the river below. For local communities located above the intake site, the 3,000 m headrace canal will become a de facto walking track to the end of the new road in the vicinity of the penstocks and fore bay. This gives rise to the potential for children to play in or fall into the canal. However, community access along the canal can also provide positive impacts and identify blockages or fallen trees. Security fencing to ensure there is no access to the canal near the fore bay is envisaged as part of the design criteria. Community consultation and education on these matters will be necessary. The 755 m long penstock corridor will drop some 260 m in altitude to the river below and, depending on its exact location, will pass through both modified and unmodified natural forest, and possibly some current or old garden sites. Clearing of vegetation will be necessary so that the penstock can be constructed. While there was little evidence of rill or gully erosion associated with the garden activity on the mid slope sections, reducing the amount of mechanical clearing of the penstock corridor and soil disturbance will significantly reduce the risk of accelerated erosion that will impact on downstream water quality. Any earthworks associated with the construction of the thrust blocks and pipe supports should be minimised to ensure the slopes remain stable, and will most likely be carried out manually on very steep slopes. While the exact location of transmission line has yet to be determined, there is not expected any significant environmental impact from the installation of the lines. The delivery of the electricity from the powerhouse to the SIEA power station at Auki would follow the road wherever possible rather than create another corridor through the forest.

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Sorawe, Taro, Choiseul Province An existing road network from the now disused log pond can be upgraded to the site. The log bridge across the Sorawe River will require replacement, as it is close to collapse. A short access to the intake site will require the removal of natural forest vegetation. The main environmental impact will be the clearance of the natural forest cover along the nearly 400m headrace canal and penstock corridor and any trees that may fall onto the structures. However, given the relatively short length of canal at this site, the amount of forest clearance will be minimal. A clear site plan with the width of the construction corridor for the canal will minimise the extent of any vegetative clearance. A major constraint in the construction phase will be getting earthmoving machinery access into the site and being able to operate in karst limestone to clear the vegetation to commence construction of the project components. While the terrain is generally flat, the presence of sink holes, fractures and fissures on the terrace above the stream may result in a wider construction corridor being cleared of vegetation than may be required to ensure machine access is provided. There will be generally little soil erosion as a result of the construction activity on this site as there is very little soil from the intake site to the penstock. There are no high cut slopes that may result in slope failure or slumping along the canal corridor. Any cuttings will generally be in limestone formations and will not result in significant erosion affecting water quality. Due to the porous nature of the limestone, water quality will not be impacted as a result of construction as long as the appropriate erosion control measures within the Environmental Management Plan (EMP) are carried out. Water will be taken from the river and returned to the same river a short distance further down and there is not expected to be any change in water quality over this distance. The reticulation of power from the powerhouse site is expected to follow the existing network of logging roads, and should not result in any further clearance of forest.

Luembalele, Lata, Temotu Province An existing logging road near the proposed intake site can easily be upgraded with relatively little earth works. The overgrown road is on a reasonable gradient and had a surface of limestone. Some short sections of new road construction will be required to the powerhouse, intake structure and fore bay. There is an abundance of limestone for use as a road surfacing material and quarry sites are available in the area. An existing log bridge on the access road will require replacement. An overgrown skid track extends from the logging road down the steep sided valley to the river channel. Road construction within the approximately 1.5 km length of the river in the project location can be carried out with minimal impact on the river channel and receiving waters if the appropriate sediment and erosion control measures are put in place and construction is carefully supervised. This will be an integral part of the EMP. The construction of the intake structure upstream of the 8 - 10 m high waterfall will require drilling and blasting in the volcanic rock outcrop at this site. There is the potential for waste rock and fine sediments entering the watercourse as a result of this process but the extent of the movement of large debris can be contained and removed afterwards. The river does not contain a high volume of fine sediments above this site as they are regularly flushed downstream during peak flows. The fines resulting from drilling will only result in a short term impact due to the significant water flow at the site. There are other streams below the intake, including ground water flows along the river channel. Any intake of water will not dramatically affect stream volumes between the intake and the powerhouse. The river channel is relatively stable and there is no significant stream bank erosion. High short-duration peak flows have resulted in minor erosion in flow paths on the upper banks.

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A feature of all construction activity will be the removal and disposal of vegetation and spoil associated with the 1,200 m headrace canal and 740 m penstock corridor. This can be disposed of in natural depressions well above the peak flood level to ensure sediments are not deposited into the stream channel. This is readily countered with the identification of suitable spoil disposal sites and will be incorporated into the EMP. A key consideration with the location of the canal corridor will be the large kauri trees that have been retained for habitat and seed source purposes. Adjustments to the corridor may be required if it is affected by a number of these habitat trees. Clearance of a power line corridor in this modified forest area will not have a significant environmental impact as long as the principles of surface water management and disposal of vegetation are adhered to and are incorporated in the EMP. The local community are aware that power reticulation will require the removal of trees along the foreshore access road through the various communities but accept this as part of gaining access to electricity. This in itself does not pose an environmental impact but rather an aesthetic impact that can be mitigated by careful line location as far as practicable and replanting of trees.

Vila, Kolombangara, Western Province The most significant environmental impact will come from the considerable construction activities associated with the three proposed stages in the steep sided and incised Vila River Reserve. This will contribute to an increased sediment level into the river system and an ongoing impact on the water quality. Mitigation measures would include end haul of all debris and excavated materials for disposal outside of the catchment, slope stabilisation works and upper slope interception drainage structures. Given this has been designated a reserve area by KFPL as part of its FSC certification process, the status of any proposed project activities on their FSC commitments will require formal clarification by KFPL and FSC. The proposed project sites are located below the 400 m contour within the Vila River Reserve, but access will require significant earthworks in the construction of roads down into the river channel and the head race canals. Detailed survey of the head race canal corridor will need to account for short steep bluffs present above the river where it has eroded down to bedrock. Drilling and blasting could be expected during construction. A broad range of international experts have conducted extensive studies in the biodiversity of Kolombangara, and as a consequence, the project could expect public submissions against any activity within this recognised conservation area, and more particularly in any activity above the 400 m contour. The key issues outside the construction of the project will be the loss or damage to biodiversity and the High Conservation Value Forests (HCVF) within the Vila River catchment. While KFPL have indicated that a project in the Vila River Reserve would not compromise their environmental objectives, a full EIA is expected to be a requirement for this site, especially given the recommendation that the riparian buffer zones of the Vila River be classified as HCVF areas.

Mase, New Georgia, Western Province The similarities in the Vila River catchment and the Mase River, both arising from calderas, are manifold and the environmental impacts during the construction of road and canal access and the headrace canal in the steep terrain are expected to be the same. While the exact location of any facility has yet to be determined, it will still require a significant length of canal construction along the side of a steep hill face. Any earthworks have the potential to result in slope failures and deposition of sediments from the large cut and fill slopes which may eventually have an impact on the river mouth at Mase Inlet over a period of time. Mitigation measures would include end haul of all debris

31/25866 February 12 141 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES and excavated materials for disposal outside of the catchment, slope stabilisation works and upper slope interception drainage structures. The presence of exploration drilling in the upper catchment suggests that a full EIA is warranted to differentiate negative environmental impacts from that activity, particularly so if it develops to the mining stage, and any activity associated with a mini hydro project. The transmission line corridor from Mase to Noro is expected to follow the existing logging road and should not present any significant environmental impacts.

Mataniko, Guadalcanal Province As with other sites on steep terrain, the major environmental impact will come during the construction phase, in particular the head race canal corridor and the roads to service the construction activity. The proposed intake is located above the narrow steep sided gorge section and the canal corridor is at the higher elevations around the160 m contour level on the true left of the Mataniko River, and then along the Galloping Horse Ridge. The canal is around 3.5 – 4 km long and will require a span across a number of small streams and gullies or large culverts under the canal to ensure these flows are not obstructed. The lower part of the canal corridor is located in a grassland environment near the top of a broad ridge. Slope stability issues here are reduced as long as surface water runoff controls from dry grasslands are incorporated into the design. There is greater potential risk of slope failure where the canal is located above the steep gorge and leading to the intake site with an increased amount of excavation required. The impacts of this construction work can be mitigated with the removal of spoil and debris away from the canal corridor and disposed of in a more stable location. Spoil disposal sites will required site-specific erosion control measures which will be incorporated into the EMP. The proposed hydropower project on the Mataniko River would divert a significant quantity of the normal river flow. Depending on the size of the project and the design flow this would have impacts on the recreational quality of the waterfall site. This aspect requires detailed examination in further environmental studies.

12.10 Environmental Management Plan and Monitoring In steep terrain earth flows, soil slips, gully erosion and downward movement of trees and debris onto the headrace canal route and roads are anticipated. These risks need to be addressed in the design brief. A key component of the EMP will be how to address surface water runoff and soil slips from upper slopes along the length of the headrace channels excavated on the contour. The effectiveness of such mitigation works will require ongoing monitoring and will be incorporated into the works maintenance schedule to ensure the integrity of the canals as there is a potential for a significant failure of the canal platform with subsequent extensive gully erosion within non-stream receiving areas. Any roads constructed to the project will require on going maintenance. This will be undertaken by SIEA or by an IPP operator and the maintenance program must include environmental mitigation measures on how to deal with erosion and sediment movement as a result of slope failures and road drainage. These will present a significant on-going activity in those sites on very steep terrain such as in the Fiu catchment in Auki and where there is a considerable distance of new road and headrace canal construction. A specific detailed Environmental Management Plan has not been prepared as part of this pre-feasibility report as the engineering and design components at the proposed sites have not been fully investigated. However, the EMP to be developed as part of a full feasibility analysis will detail the environmental impacts to be monitored, the timing of monitoring activities within the construction schedule, and the mitigation measures required, especially those related to earth works in and around watercourses and on steep slopes. Parameters to be monitored will include, amongst others, stream turbidity and other water quality indicators before, during and after the construction; stream flows; incidence of soil slips, slope failures;

31/25866 February 12 142 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES and changes in land use and forest cover as a result of new access and compliance with the EMP conditions. The EMP will also identify the management structure and define specific responsibilities for environmental monitoring both during and after construction activities. Responsibility for EMP compliance will rest with the contractor who will be monitored by a social and environmental officer to be recruited prior to the award of any civil works contract. The Project Management Consultants shall have an experienced environmental specialist who has relevant expertise in earthworks and civil construction works.

12.11 Conclusion and Recommendations The screening and assessment of environmental issues in all project sites identified in this pre-feasibility study demonstrate that the main impacts will stem from road construction and the clearing of forest vegetation on steep terrain for head race canals, penstocks and ancillary structures. While these are highly significant in those project sites on steeper terrain, ensuring that environmental issues are an integral part of the design criteria can substantially mitigate them. The Environmental Management Plan (EMP) will cover key design considerations related to sound construction and long term serviceability of infrastructure including provisions to mitigate environmental effects during construction such disposal of debris and spoil instep terrain, noise and dust nuisance, and safety. The Monitoring plan provides for community feedback, linkage with ongoing water quality monitoring programs and monitoring for compliance with the EMP. The environmental categorisation of each of the project sites is summarised below and is based on the summary of impacts in the REA checklists. Ringgi and Mataniko are the only sites where there are significant environmental and public interest issues that require special attention. This site has been assessed as a category A and a full EIA is anticipated.

Table 12.2: Environmental Categorisation

Environmental Categorisation Site A B C

Fiu, Auki B

Sorawe, Taro C

Luembalele, Lata B

Vila, Ringgi A

Mase, New Georgia B

Mataniko, Honiara A

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13. Social and Poverty Analysis

13.1 Introduction The ADB’s Country Program Strategy (CPS) seeks to reduce poverty through equitable private-sector-led economic growth by improving transportation infrastructure and services and the business-enabling environment. Harnessing hydropower resources to serve provincial centres and their environs will assist the Strategy by improving living conditions, increasing access to markets and basic services, and creating income-generating opportunities in the provincial centres and their rural hinterlands. Most of the provincial centres where this study focuses on are economically moribund. People are keenly aware of potential opportunities but the lack of electricity is a major constraint. The project is a general intervention (GI) that will reduce poverty of opportunity by improving the enabling environment for pro-poor growth and social development. It will provide wide benefits to the well-being of the communities and also directly benefit some particularly disadvantaged people. Each project site is described in detail below. In all sites, the extension of electricity supply can improve access to and the quality of education, health, water supply, sanitation and other basic services, increase social and economic opportunities especially for small businesses and other forms of income-generation, improve living conditions, and reduce the physical and time workload of women. Full realisation of this potential will not occur automatically, however. In order for it to happen, the enabling environment for inclusive planning, gender equity, community development, small enterprise growth and the like needs to be nurtured through collaboration with other, supporting development programs, some of which are already being implemented in Solomon Islands by provincial and national governments, NGOs and aid partners. While the cost of electricity will be some constraint to its use, all people interviewed believed the opportunities created by a reliable power supply would balance out the costs involved. Even the poorest households may benefit through the lowered cost of lighting and better access to services. Use of pre-payment metering will help households to stay within their means, and has been welcomed by both connected and prospective SIEA customers. Despite its cost, electricity is highly desired by all sections of the community. In regard to household expenses and the proportion of surplus income that could be used to pay for electricity, however, there is no precise answer. The amount spent by households on non- food essentials varies widely between urban (Honiara) households, provincial centre households and rural households.29 The proposed project areas include both the second and third categories. The best indication of affordability is that most households without electricity use kerosene for lighting, a more expensive fuel, and will reduce their expenditure when they are connected to electricity.

13.2 Methodology In September-October 2011, the consultant visited all proposed project sites, undertook community consultations (involving both men and women) to assess interest in access to electricity and types of use of electricity for households' activities; and the amount of income that could be used for monthly payment for electricity, etc., discussions that built on surveys previously conducted by the Project Team in Auki and Lata. These discussions as well as interviews with local government officials, school teachers, health workers and community

29 Solomon Islands Statistical Office, 2006. Household Income and Expenditure Survey 2005/6 – National Report, Department of Finance and Treasury, Honiara . The Basic Needs Poverty Line (BNPL), which includes an allowance for essential non-food expenditure was estimated at SBD998.32 per week for a Honiara household; SBD465.41 for provincial urban households, and SBD225.02 for rural households. Rural areas are more poor but also more equally poor. Urban areas have higher incomes but also greater income inequality.

31/25866 February 12 144 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES organisers also explored views about the advantages or disadvantages of electrification for each region; acquisition of land and use of the river for hydropower; potential participation of local communities, and introduction of pre-payment metering systems. In each province, she discussed the findings of the study with senior members of the provincial governments. In Honiara, the consultant met with SIEA, the Ministry of Provincial Affairs, the World Bank Tina River Project Team, and the UN Country Office; discussed the capacities of SIEA, government and NGO agencies to meet social safeguard standards and assist community participation; and collected current provincial and national reports and other background material. Results of the 2009 national population census are not yet available, an indication perhaps of technical difficulties that may limit the usefulness of census data even after their release. There are also serious constraints on poverty or income data in Solomon Islands. The 2005- 6 Household Income and Expenditure Survey (HIES) report was not disaggregated to any local level or by gender.30 The 2007 Demographic and Health Survey (DHS) produced a wide range of information, including about gender issues, but the report was disaggregated only to the urban/rural level. Other sources of information are ministries of Health and Provincial Affairs databases which are limited in extent and quality. Given the profound changes in Solomon Islands over the past decade, the lack of timely, disaggregated statistics precluded an extensive compilation of socio-economic profiles of women in the project locations, although useful information was collected. Surveys of unserved customers were conducted in low-income housing areas in Auki and Lata to assess energy use and expenditure on kerosene, and their ability to pay for electricity. Most energy expenditure now is on kerosene for lighting, although some households use dry cell batteries, small solar systems or petrol generators. Kerosene is expensive at $17-$18 per litre, or $7-$9 per 300 ml bottle at most rural shops. The surveys found that unserved households spent more on average on kerosene – in Auki, SBD 180– 220 per household per month – than connected households spent on electric lighting. There was clear enthusiasm to connect and pay for electricity, especially through pre-payment metering, and willingness to support electrification through labour, materials and permission for easements.

13.3 Stakeholder Analysis At each site, three groups of stakeholders are primarily involved in the project: households that will gain connections to the electricity supply; already connected households that will gain a more reliable supply; and landowners of the proposed construction sites for hydropower plants. Of institutional bodies, the principal stakeholder is SIEA, a statutory body, which will benefit from having a larger number of clients and a wider economic base in the provincial centres, from cheaper power generation than diesel, and from a more reliable supply. SIEA has well- established standards for working conditions and pay scales in accordance with Solomon Island laws and regulations, and these standards should apply. Construction activities can be expected to comply with national labour laws and regulations, with no risk of forced or compulsory labour, SIEA has had management difficulties but with assistance from the World Bank it has reformed its billing, accounting, and data management systems. As its management improves, SIEA may be able to turn their attention to consumer education, as a necessary part of expanding its client base.

30 Solomon Islands Statistical Office, 2006; ADB, 2005. Private Sector Assessment for Solomon Islands, ADB, Manila. IMF, 2005. Solomon Islands: Selected Issues and Statistical Appendix, IMF Country Report No. 05/364, IMF, Washington DC. Limited data in Solomon Islands makes it hard to measure over time or area. The 2006 HIES cannot be linked to those conducted in 1991.

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The Government encourages women’s increased participation in decision-making and this is a priority of the Ministry for Women, Youth and Children’s Affairs (MWYCA).31 Although the MWYCA is a central agency to encourage gender inclusion, its Women’s Development Division is hampered by its lack of capacity, poor physical facilities and small budget. Opportunities for pro-poor design and social inclusion subcomponents to benefit gender equity also exist in association with other ADB operations, government and NGO programs, and law reforms, in particular programs that are improving women’s access to credit and encouraging their participation in economic activity. A planned business law reform implementation program will be targeted towards women’s businesses and women’s community groups. The expected boost to economic activity in newly electrified areas provides an opportunity to extend these activities to the provincial centres and their hinterlands. The Provincial Governance Strengthening Programme of the Ministry of Provincial Government and Institutional Strengthening, is addressing problems in government systems that have hampered service delivery to the provinces, through local capacity development and inclusive planning, resulting in provincial development plans that involve all local stakeholders. All provincial governments are enthusiastic about collaborating with the project, as is the Provincial Governance Strengthening Programme, which now has established procedures for participatory planning at the local level. Because local ownership is important to the success of this project, a consultation and participation (C&P) plan should be developed in the project design phase, to identify ways to maximise stakeholder engagement throughout the project cycle. Table 13.1 summarizes the result of the stakeholder analysis.

Table 13.1: Summary Stakeholder Analysis

Stakeholder Primary (a) Secondary (b) Key Stakeholders Interest in the Project Unserved households in the X Beneficiaries: new and/or improved electricity provincial centres and their supply vicinity Landowners of hydropower X Beneficiaries of land access/ acquisition plant agreements, new electricity supply; in some cases, improved access. SIEA X Implementing Agency. Also benefit through wider economic base, cheaper power generation; more reliable supply Rest of the provinces involved X Flow-on benefits of increased economic in the project activity and opportunities Government agencies X Provincial governments, the Ministry of Provincial Government, and the MWYCA may be central agencies. Government of Solomon X Important intermediaries in the project delivery Islands and ADB process

13.4 Poverty and social exclusion Although it will principally expand and improve electricity supply to provincial centres and their rural hinterlands, the project will reduce poverty of opportunity by improving the environment for pro-poor growth and social development. Electricity supply can improve access to and the quality of education, health, water supply, sanitation and other basic services, increase social and economic opportunities especially for small businesses and

31 Solomon Islands Government, 2007, Grand Coalition for Change Policy Statement for Women, Youth and Children, Ministry for Women, Youth and Children Affairs, Honiara.

31/25866 February 12 146 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES other forms of income-generation, improve living conditions, and reduce the physical and time workload of women. The wider benefits of the project are in line with the intention of the national development plan to build better lives for all Solomon Islanders, in particular to improve access to income- generating opportunities, improve access to basic services, and provide for an even distribution of the benefits of growth and the development of all provinces. Better electricity systems will link the towns and nearby rural areas and invigorate them both, thereby helping to realise opportunities particularly in the rural agricultural sector for pro-poor growth. The project will contribute to the achievement of MDG-related non-income poverty goals in education; infant and child survival; water and sanitation; and gender equity through greater access for women to health, education and other services and livelihood opportunities, progress that is seriously needed, but lacking, in Solomon Islands. Rather than as a monetary indicator (consumption or income), poverty in Solomon Islands is more usefully defined in terms of lack of access to basic services and income opportunities.32 Throughout the country, poor infrastructure constrains opportunities. Eighty four percent of the population live in rural areas with very little access to education, health or other social services, are serviced by poor or non-existent transport, electricity and telecommunications infrastructure, and have few economic opportunities other than subsistence farming.33 Only 16 percent of the national population have access to electricity, a very low figure by regional standards. Residents of the provincial centres, where government services, businesses and other paid jobs cluster, do better on average in regard to income but also live with unreliable services, transport and power, in stagnant small economies where poverty of opportunity is chronic. Services in rural Solomon Islands are often rudimentary. Many people use kastom (traditional) medicine by choice but distance to clinics, availability of transport and quality of service are significant barriers to people seeking treatment at nurse aid stations, health clinics or hospitals, especially during emergencies. The high incidence of malaria and other infectious diseases and high fertility rates put a particularly heavy burden of illness on infants, children and women. Most clinics and aid posts are poorly equipped and unpowered, making it impossible to store vaccines and difficult to provide emergency services at night. Frequent power fluctuations and cuts affect services at the provincial hospitals and create real difficulty during emergencies. Most schools lack electricity but this is increasingly seen to be necessary, especially at senior residential schools where food storage and night study classes are necessary, where teachers need to prepare lessons in the evenings, or where there is need for copiers, computers, mobile phones and other new technology. Without electricity, senior schools struggle to meet some curricula requirements, especially in science and home economics. Schools with own generators face high costs and often frequent breakdowns, and tightly curtail hours of use.

Economic and Social Benefits of Hydropower The wider economic and social benefits of the project can include: • Unserved communities in and around provincial centres will gain a much desired electricity supply; • Already connected consumers will gain a more reliable and possibly a cheaper supply;

32 Solomon Islands Statistical Office, 2006. D. Abbott and S. Pollard, 2004. Hardship and Poverty in the Pacific: Strengthening Poverty Analysis and Strategies in the Pacific, Pacific Department, Asian Development Bank, Manila. 33 AusAID, 2006. Pacific 2020: Challenges and Opportunities for Growth, Canberra: AusAID; M. Clarke, 2007. A Qualitative Analysis of Chronic Poverty and Poverty Reduction Strategies in Solomon Islands. Canberra: AusAid.

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• Living conditions will improve, especially for lighting and food storage, and especially for women who are responsible for most homework and child and aged care. • In Taro (Choiseul) and Lata (Temotu), the electricity supply will also improve the water supply and potentially also sanitation conditions. • Electricity supply will improve conditions at schools, health clinics, and community facilities, especially in areas of new connection. • Paid employment during construction and to a lesser extent during the operation of the hydropower plants. • Potential for new economic opportunities and higher incomes will be created. Possible activities include better marketing of fish (through fish freezing, ice production), retail activities, local timber milling, furniture making, cooking/catering, sewing, small tourism development etc. In the Noro-Munda region and Gracious Bay in particular, improved electricity supply will support industrial and tourism development. • Cultural activities and church programs are important parts of community life. Many programs such as dance and choir practices, youth group meetings and community functions are held at night. Electric lighting for churches and community centers is seen as a great benefit. Fund-raisers and functions are also important to community life, especially for women. They usually involve food preparation for which it is necessary - but difficult and expensive - to store food in a cool place. • For remote communities in particular, access roads that will be built to service the hydropower plants will significantly improve access to health services and schools. In the upper Fiu Valley (Malaita) for example, all visits to health services and trips to market or to buy essential foods, entail long, difficult and time-consuming journeys. All goods and produce have to be carried in and out by manpower; the track is impassable to animals or vehicles. Few children attend school, and no health services visit the area. The physical and time burdens of everyday work curtail livelihood and all other opportunities, especially for women. The people want electricity but they want the access road and paths that will come with it even more. Possible negative impacts of electrification are the risk of faulty connections, house-fires, electrocution, and other accidents. These risks are minimised through the SIEA requirement for all connections to be made and checked by qualified electricians. Another risk is inefficient and unnecessarily expensive electricity use that drains household budgets. The use of pre-paid meters reduces the risk of household budgets being over-stretched by the new service, or that benefits will flow primarily to non-poor consumers. Community education programs, operated through SIEA, can help people to use electricity in safe and efficient ways.

Gender issues The Government is committed to promoting gender equality but Solomon Islands ranks very low in gender development indices. Women in Solomon Islands perform multiple roles as household managers, subsistence and cash crop farmers, income earners, and active members of churches and community groups. Women have lower literacy rates and less access than men to post-primary education.34 Women’s access to health and family planning services is particularly poor in rural areas. Gender disparity is marked in employment. The 2007 DHS found that nationally only 42% of married women were employed, compared to 87% of married men, and over half (56%) of employed women were not paid at all for their work, either in cash or kind. Often isolated from markets and services, rural women spend much of their time collecting fuel wood and water and providing health care for preventable diseases caused by lack of safe water and sanitation, and thereby experience both income

34 DHS, 2007. Among women and men aged 15–49, 21 percent of women and 11 percent of men cannot read at all.

31/25866 February 12 148 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES and time poverty. Decision-making and control of resources strongly favour men. The traditional obligation system that undermines individual control of resources exacerbates women’s lack of economic power. These obstacles constrain women’s potential social and economic contributions. While the project will benefit the whole community and region, access to electricity supply can particularly benefit women through: (i) Improved living conditions, especially by providing better lighting at night and better food storage through refrigeration. Women are responsible for most household chores and have heavy time and physical work loads. (ii) In some areas, improved water supply and sanitation; (iii) Reduced physical or time burden of some household tasks; (iv) New opportunities for small businesses and other forms of income-generation. Few women work outside the household or for cash but many could identify opportunities that an electricity supply would provide. In all project sites, women expressed enthusiasm in taking up opportunities for income-generation that an electricity supply can support, such as catering, retailing, fish marketing and sewing. Women need to be involved in design and delivery of targeted infrastructure to reduce overwork and increase available time of activities such as community management, local marketing of surplus produce, and developing alternative livelihoods.35 But even when women are present in the different decision-making structures (traditional, contemporary or faith based), their views may be ignored. In both households and communities, decisions are usually made by male leaders.36 This situation may be difficult to change but the benefits of inclusive and equitable development make the effort worthwhile. Because the proposed project has significant potential to directly improve women’s and girls’ access to opportunities, services, assets and resources, further gender analysis is required during the project’s next phase and a gender plan should be incorporated in its design. Inclusion of a GAD Specialist in the design team can foster gender equity in accessing related economic opportunities.

13.5 Management of Social risks and Vulnerabilities

Labour conditions The proposed hydropower plants will be small. Construction activities are likely to engage a small number of expert workers who will be brought into the area, as well as local unskilled and semi-skilled labour (principally men) during the construction phase. Some paid work will also be available during the life of the hydropower plant to maintain the intakes, canals and power house. SIEA has well established standards for working conditions and pay scales in accordance with Solomon Island laws and regulations, and these standards should apply. Construction activities can be expected to comply with national labour laws and regulations, with no risk of forced or compulsory labour.

35 ADB, 2009. Solomon Islands: Interim Country Partnership Strategy, 2009-2011. 36 Maetala, 2007, op.cit. The 2007 DHS found that most women participate in household decisions about major household purchases, daily needs, their own health care and visits to their family, although more than 40 percent do not participate in all these types of decisions.

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Affordability Provision of electricity to unserved communities should reduce, rather than raise, household expenditure on basic energy, now mostly spent on kerosene and dry cell batteries. Already connected consumers will benefit through more reliable supply and reduced future power costs. There is no risk that the access of poor and vulnerable households to related goods and services (either kerosene or electricity) will be worse as a result of the project. The new supply, however, is likely introduce new ‘needs’ such as refrigeration, entertainment, and possibly labour-saving equipment such as washing machines although, given mostly low incomes in the project areas, electricity consumption is unlikely to abruptly jump. The use of pre-paid meters reduces the risk of household budgets being over-stretched by the new service, or that benefits will flow primarily to non-poor consumers. Community education programs, operated through SIEA, can help people to use electricity in safe and efficient ways.

Risk of HIV/AIDS transmission Throughout Solomon Islands, the introduction of outside workers and a sudden inflow of cash (usually in connection with the logging industry) has been associated with social problems, sexual and domestic abuse, sexual exploitation of children, and heightened risk of sexually transmitted disease, including HIV and AIDS.37 The Solomon Islands Government is now preparing legislation to protect children from sexual and other forms of exploitation. GHD has its own child protection policy. SIEA also has responsible worker practices. Community development activities associated with this project should include community awareness about the risk of sexual, domestic and other forms of abuse in cash-rich situations, and ways to address and prevent these situations.38

Social Impacts of Conflicts or Natural Disasters Solomon Islands are now recovering from a destructive period of internal conflict. A positive outcome of this experience has been greater awareness about the risk and triggers of internal conflict and ways to counter them through equitable development and peace-building activities.39 This project will assist achievement of the goal of the National Development Plan to more evenly distribute the benefits of development. The only risk that benefits of the project will be captured by influential stakeholders in the project areas is through failure of landowner agreements. There is no risk that vulnerable groups will be negatively affected by the project, or of any loss of livelihood or employment.

13.6 Social safeguards

Involuntary resettlement In regard to Involuntary Resettlement, the project is categorised as C, with no IR impact expected. The small scale of the proposed hydropower plants, their design and construction requirements, the minor extent of resource diversion, and other environmental impacts are described elsewhere in this report. The only locations where there may be some disruption to food gardens or food trees are the Fiu River, Malaita, and Gracious Bay, Santa Cruz. The

37 See, for example, a report from Makira produced by the Church of Melanesia: T. Herbert, 2007. Commercial Sexual Exploitation of Children in Solomon Islands: A Report Focussing on the Presence of the Logging Industry in a Remote Region. Christian Care Centre, The Church of Melanesia. 38 [SPC/UNFPA report on gender violence in Solomon Islands] 39 For example: Solomon Islands Government Departments of Home Affairs and National Reconciliation, Unity and Peace, National Peace Council, Vois Blong Mere Solomon, Solomon Islands Christian Association, and UNIFEM, 2005. ‘Monitoring Peace and Conflict in Solomon Islands Using Gendered Early Warning Indicators.’

31/25866 February 12 150 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES proposed hydropower sites at Taro, Lata, Ringgi, Mase and Honiara are in uninhabited areas where there are no houses or gardens and only occasional use by hunters or local loggers.

Indigenous People Indigenous people’s issues are significant in the project. Solomon Islanders have a strong attachment to their ancestral lands. In some parts of the country, land has been alienated from traditional to government ownership but even here landowner concerns must be addressed. Of the proposed sites, four are on customary land and two (Ringgi and Lata) are on alienated land. In Lata, the plant will be on alienated land but transmission lines will cross over customary land. In regard to arrangements to be made with landowners of the proposed sites, a recent study noted that since the early colonial period, women’s attachment to and dependence on land has been mostly disregarded.40 Matrilineal descent was once significant in parts of the country (Guadalcanal, Makira and Isabel) although women’s leadership role in land matters was not acknowledged publicly.41 Some women retain important genealogical knowledge. Although men are considered the natural trustees and beneficiaries of royalty payments, without proper consultation with women this has resulted in unequal shares in the benefits, led to false claims of landownership, and created an environment ripe for enmity among clan members.42 It is critical to the progress and sustainability of the project that landowner aspirations for project benefits are fairly met. Project benefits, including as they are perceived by the landowner community, need to be included in the final land access and/or acquisition agreement to be negotiated with the landowners through wide-based community consultations. This agreement needs to acknowledge and calculate a value for the landowner’s contribution to the improved electricity supply and the lower cost of generation. Principal responsibility for these negotiations rests with the provincial governments. Land acquisition processes are complex and have at times frustrated the national and provincial governments in their efforts to acquire land.43 Of all stakeholders in this project, landowners are the only group that could potentially work against it. All discussions and activities to date, however, confirm that there is solid and unanimous support for the projects from traditional leaders and other landowners. There is an important difference between the populations of the landowning group and the village communities. Landownership is based on genealogical descent, which may or may not be recorded in writing. Some of these people will live in the project area. Others will have gone to live elsewhere but can be vocal when ‘compensation’ issues are discussed. The village population will include non-landowners, mainly women who have married in to the community but who would be excluded it project returns only go to landowners. An in-perpetuity return to landowning communities, perhaps in the form of a development trust fund, could enhance both community ownership and participation in the project and

40 E. Huffer (ed.) 2007. Land and Women: The Matrilineal Factor. The Cases of the Republic of Marshall Islands, Solomon Islands and Vanuatu. Pacific Island Forum Secretariat. 41 R. Maetala, 2007. ‘Matrilinieal Land Tenure Systems in Solomon Islands: The cases of Guadalcanal, Makira and Isabel Provinces,’ in E. Huffer, op.cit.; J. Bennett, 2002, Roots of Conflict in Solomon Islands. Though Much is Taken, Much Abides: Legacy of Tradition and Colonialism, State, Society and Governance in Melanesia. Discussion Paper 2002/5. Australian National University.; A. Pollard, 2000, ‘Resolving conflict in Solomon Islands: The Women for Peace Approach’, Development Bulletin, no.53, pp. 44-48.; Sullivan, Marjorie, 2007. Recognition of Customary Land in Solomon Islands: Status, Issues and Options. Resource Management in Asia Pacific, Working Paper 66. Australian National University. 42 Maetala, 2007, op. cit. 43 Temotu Provincial Government, 2011. Strategic Development Plan. Lata: Office of the Premier and Honiara: Ministry of Provincial Affairs.

31/25866 February 12 151 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES provide a fair distribution of returns to all of the community by gender and age, rather than the usual ‘compensation payment’ modality which usually goes in cash to senior men and is often spend on unproductive investments. Whether or not the community agrees with this distribution, it is difficult for them to do anything about it. However, ensuring that proceeds for resource use benefit the whole community would increase the poverty alleviation and inclusive development outcomes of the project. An important element of the feasibility and design phase will therefore involve the securing of legal agreements with the landowners of the project sites, community consultations about expected or desired benefits and, if there is community support, the possible formulation of some type of in-perpetuity development fund arrangement. In summary, the project will require limited land acquisition. No resettlement will be necessary. In Taro, Lata and Mase, the hydropower plants will be built in areas where there is little local use but transmission lines in Lata will run close to settlements and require some clearing of timber and food trees. There will be some disruption to gardens in Auki. In Ringgi and Honiara, there may be some disruption to local ecotourism activities, mainly during construction. Land access and/or acquisition agreements will need to be negotiated with indigenous landowners. This is primarily the responsibility of the provincial governments. The project will impact indigenous peoples but in no negative way. The population of the provincial centres and their environs is almost entirely indigenous. Indigenous landowners will benefit from the agreements referred to above and all other benefits of the project, including the expected stimulus to the local economy. Annex 7 displays questionnaires and screening tables for resettlement categorization.

13.7 Site Specific Findings

Auki, Malaita Province Over a third of the population of Solomon Islands, or around 170,000 people, live on the island of Malaita.44 This is the province with the lowest level of human development in the Solomon Islands, while Solomon Islands has one of the lowest levels of human development in the Pacific island region.45 Much of the coastal fringe of the island is heavily populated, especially around Auki, the provincial capital. The town’s population is around 5,300 people and another 15,000 live in adjacent settlements. The mountainous interior is sparsely inhabited; with few roads, people there have very restricted access to basic services and markets. Only approximately 4% of the population of Malaita Province has access to electricity, mostly in the SIEA service areas of Malu’u and Auki. Even parts of Auki town are unserved.46 The proposed site for the hydropower plant is on the Fiu River, approximately 8-10 km into the mountains behind Auki and approximately 4 km beyond the end of the nearest road. Approximately 100 people live in the vicinity of the proposed hydropower plant in two small hamlets, Kwainoa and Okwaia. The proposed intake is further upstream near Ofenga and other small hamlets. Although the distance from the Fulisango road-head is not great, the arduous walking track along the river, which is impassable to all but the strongest during bad weather, makes these communities very remote indeed.

44 This population figure is an inter-census estimate. A more accurate figure will soon be available from the 2009 national population census. According to the Family Health Card system, in 2009 the total population of Malaita was 132,600. 45 ADB, 2009. Solomon Islands: Interim Country Partnership Strategy, 2009-2011; Ministry of Health, 2009. Family Health Card Consolidated FHC for Malaita Province. Unpubl. The UNDP Human Development Index is a composite measure of access to health and education services and income, specifically life expectancy, infant mortality, school attainment, adult literacy and per capita income. In 2009 only 10% of households in Malaita had adequate sanitation and 50% have piped water, both of which negatively affect household welfare and women’s work. The fertility rate is high (141/1000), modern contraception use is low (17%), and only 76% of live births are delivered in health facilities. Available data cannot be disaggregated to the project area which, being close to Auki, may have better rates overall but areas of deep disadvantage nevertheless. 46 Malaita Provincial Government, 2006. Iumi Tugeta Bildim Malaita: The Strategic Plan of the People of Malaita Province.

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The project will provide electricity to people downstream from the proposed hydropower plant site, covering most areas in and around Auki that are now unserved and also improving the reliability and reducing future costs of the power supply. Because of the cost of running transmission lines back up the valley, people in the upper Fiu valley, in the vicinity of the hydropower plant may need to be served with solar systems instead, but this is yet to be confirmed and community acceptance of this proposal has not yet been ascertained. Communities along the road to Auki and on the coast will gain a much desired electricity supply, including people in the three low-income housing clusters of Western Fishing Village, Eastern Extension Area, and Kilufu’u Extension Area, where most households depend on fishing for their livelihood. As well as improving living conditions, electricity supply will create opportunities for storage and better marketing of fish, and therefore higher incomes.47 Electricity supply will improve conditions at schools and health clinics along Fulisango Road and in other areas of new connection. Poverty By all measures of poverty and social exclusion, people living in the upper Fiu valley are markedly disadvantaged. While they are eager to have electricity, they are also interested in the feeder road that will be constructed by the project for this will address their principal problem of poor access to services and markets. They have abundant good land on which they grow cocoa, with potential for expanded production, but poor market access restricts incomes and livelihood opportunities. All goods and produce have to be carried in and out by manpower; the track is impassable to animals or vehicles. Few children attend school, or at most for a year or two, despite their parents’ expressed desire for their education. Only a child older than 8 or 9 can regularly use the path and then only in good weather. The late start, frequent absences, and hard daily travel discourage them from continuing at school. No health services visit the area. The only health ‘facility’ is a stretcher on which a sick person can be carried out to the road and beyond to medical help. No elderly people beyond the age of 65 or so live in the area. Another potential landowner benefit accrues to kin who now live on the densely populated coast because their use of their traditional land is constrained by its poor accessibility. Residents in the upper Fiu valley look forward to their return as this will add social capital to the small communities there. Involuntary resettlement No resettlement will be required but there may be displacement of some garden plots. Agriculture in the area is mostly on shifting plots although cocoa is an important cash crop. Much of the area is covered in indigenous forest. The population of the area is very small and there is reported to be no shortage of farming land. Small areas of trees will be damaged or removed during construction of the feeder road and canal and some gardens may have to be relocated. Prior to the final project design, it is not possible to know the exact composition of these losses and the extent to which cocoa and other food or economically valuable trees will be affected. Indigenous people: The land is held under indigenous ownership, with boundaries and membership of landowning clans defined by known genealogies. In 2000, the clans organised themselves into the Dalobada Sirahi Tafubala (DST) Tribal Association, which is headed by the traditional leaders of the various sub-clans and meets regularly to deliberate on clan affairs and adjudicate over possible conflicts.48 Members report that disputes are rare. The chiefs and other landowners have expressed their full support for the project.

47 Potential areas for expansion were identified in the 2007 World Bank SKM report ‘Solomon Islands Proposed Power Sector Projects - Outer Islands Generation and Rural Electrification Components’. 48 The formation and self-definition of traditional landowner bodies such as DST is encouraged by the SI Government as a way to build peace and promote development.

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Taro, Choiseul Province Situated on a small island one km from the main island of Choiseul, Taro, the provincial capital, hosts the government station, primary school, the hospital and health clinics, and housing for government employees, The population of the area is approximately 2,000, or 470 households, of which around 100 households live on Taro Island. Of the little commercial activity in the area, most cash comes from government wages and copra production. More than 80 percent of households in Choiseul are active in coconut production and fishing, and more than 90 percent in subsistence gardening or farming.49 The lack of grid power is a major obstacle to economic and social development of the Taro area. Taro has no electricity service but government offices, businesses and a few houses run small generators, which are especially noisy at night. SIEA is now installing a low voltage mini grid to cover Taro Island only but because of its small size the system is not likely to trigger much commercial activity. Taro Island lacks any water supply apart from wells and rainwater tanks. The proposed hydropower plant will also provide a safe piped water supply to the new township site. The proposed site for the hydropower plant is on the Sorawe River, on the main island of Choiseul, almost directly across the bay from Taro Island and close to the proposed site for a new provincial centre. Supported by the national government, the Choiseul Provincial Government plans to relocate Taro to the mainland. The SI Government has allocated $3.5 million p.a. to this scheme and will increase this amount from 2012, and a purchase agreement between the government and local landowners is almost finalised, with the first payments to landowners expected in November, 2011. The move will increase access to government offices and services and reduce the town’s vulnerability to natural disasters, a plan which gained high priority after the 2007 tsunami near Gizo.50 Availability of reliable electricity and water systems, which this project will provide, are essential to the plan. At present, students from the main island travel each day to the primary school on the island, and all secondary students travel back across the bay to the regional secondary school on the main island, or board there. The school operates on a maximum of three hours of electricity a day and suffers frequent breakdowns of its generator. All clinics and aid posts on the main island are unpowered, making it impossible to store vaccines and difficult to provide emergency services at night. Higher-level health services are available only on Taro Island, although periodic visits are made by health staff to villages on the main island. Mainlanders must cross the bay to the island, which is difficult in bad weather, and often face long waits to see a doctor. The economy of Taro is quite stagnant but many people can identify opportunities once electricity is available. Fishing is a major activity but without storage facilities the market is limited. The high demand for fish on the nearby island of Bougainville can be met once refrigeration is available and reliable, by taking small iceboxes across by boat. Furniture making is potentially another local industry. Women recognise cooking, catering and sewing as potential businesses.

Lata, Santa Cruz, Temotu Province Temotu Province, one of the most remote parts of Solomon Islands, has some of the lowest development levels in the country, measured by any of the MDGs. Only 3.6 per cent of the population of the province has electricity supply. The 2009 population census recorded an annual average growth rate of 1.2 per cent over the previous decade, a slower rate than the

49 Choiseul Provincial Government, 2009. Choiseul Province Medium Term Development Plan 2009-2011. Ministry of Provincial Affairs

50 Choiseul Provincial Government, 2011. Provincial Development Plan. Ministry of Provincial Affairs.

31/25866 February 12 15 4 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES national population because of out-migration. The population is mostly young, with 40 per cent under the age of 15 years, and is almost entirely indigenous Solomon Islanders.51 Lata, the provincial capital, is located on the main island of Santa Cruz and accommodates provincial government offices, the provincial hospital, airport, sea port, statutory organizations and NGOs. Most businesses on Santa Cruz, or in Temotu Province, are clustered in central Lata, within the SIEA service area. According to the Ministry of Health, 3,260 people in 600 households live in Lata and villages along the western side of Graciosa Bay.52 Gracious Bay, one of the most densely populated rural areas in Solomon Islands, is entirely without reticulated power. A few shops own generators and a few households have small solar systems for lighting (which do not work well during cloudy periods). Piped water, which is pumped along the coast from Pala at the head of Gracious Bay to Lata using a diesel powered pump, is unreliable. It is rationed to two hours per day (in the early evening) because of the small capacity of the system and high cost of diesel. Outages are common because of budget overruns and breakdowns. Three to four households share a single standpipe. During the short time water is available they must stand about and wait their turn to bathe and collect water. Few households have proper sanitation. People in the community consider that an improved water supply is a principal benefit of the proposed project. The SIEA power supply is very small, supplying only 120 customers in Central Lata. Large voltage drops and power cuts are common. But as Lata is the only place on Santa Cruz (and in Temotu Province) with a regular electricity supply, most businesses are located there. The proposed hydropower plant on Luembalele River and 11 kV distribution system will cover the current supply area and extend power supply to the water pumping station, schools, health clinics and homes in Gracioso Bay and North Lata. The project fits well with the newly formulated Temotu Provincial Development Plan which aims to (i) strengthen the economic base by encouraging and increasing income generating activities; (ii) improve the wellbeing of the population and reduce poverty; and (iii) increase and strengthen health and educational services throughout the province.53 Temotu Province has entered into a trade agreement with nearby Vanuatu and recognises potential in agriculture fishing, tourism, forestry and other wood products. Much of the planned enterprise development will be located on Santa Cruz and especially along Graciosa Bay. The new system will provide electricity to four schools on the west side of Graciosa Bay, namely Kati Primary School (180 primary students) Muna Primary School (290 primary students), Balo Extension School (40 Grade 1 and preschool students) and Graciosa Bay Community High School (90 students in Forms 1, 2 and 3.) if a bridge at the head of the bay was rebuilt and road access restored, electricity supply could possibly extend along the west side of the bay to Palo Luesalo Training Centre (approximately 100 residential students).54 Water is stored at the schools in tanks but lack of water frequently disrupts science and home economics classes. Typing and copying of class materials is difficult and expensive, and requires a trip into Lata where there is power, involving a 7 km return trip by foot or $200 by hired vehicle. Graciosa Bay Community High School will have Form 4 students in 2012 and Form 6 by 2014 but without power there is no capacity to teach courses with computers or other new technology.55

51 Temotu Provincial Government, 2011. Strategic Development Plan. Lata: Office of the Premier and Honiara: Ministry of Provincial Affairs. 52 Lata Hospital data from Malaria Spraying Program, 2011. The villages are Nemu, Mabu, Uta, Nou, Mirnair, Matembe, Banua, Mateabir, Ne’ele, Luepe, Mnaban, Yoo, Nep, Mateone, Balo, Nabanonto, and Nepa. 53 Office of the Premier, 2011. Temotu Provincial Government Strategic Development Plan. 54 The Temotu Provincial Plan notes the importance of the Vocational Training Centre to this remote province where many students drop out early due to remoteness and the cost of sending students elsewhere to study. 55 Graciosa Bay Community High School Board of Management, 2011. School Development Plan. Internet services are sometimes available through a solar powered facility at Kati Primary School.

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A nurse aid post near Kati School, which lacks power supply, serves Gracious Bay. Vaccinations are periodically provided by a mobile team or are otherwise available at the hospital in Lata where there is refrigeration. Without lighting, clinic staff can provide limited service to people who fall sick at night. Frequent power fluctuations and cuts affect services at Lata Hospital which then links into the Telecom generator for essential power needs. Involuntary resettlement The proposed hydropower plant will be on previously logged state land along the Luembalele River which flows into Graciosa Bay. Transmission lines, however, will cross customary land at the end of the Bay and up the coastal road to Lata. Landowners have expressed full support for the project but a legal agreement will need to be negotiated through the Provincial Government for access and use of the land under the transmission corridor. Some timber and food trees will need to be cleared along the route but this is unlikely to affect local food security. Surveys have already been conducted and landowners are aware of and comfortable with this requirement. Indigenous People Land along the transmission route is held under the indigenous ownership of the Mnaban Clan, with boundaries and membership defined by known genealogies. The clan involved with this project site has a good record of cooperation with development activities. It previously leased a logging concession around the proposed plant site to Allardyce Logging Company and Mega Timber. While there were some disputes they were amongst the landowners themselves, did not disrupt logging activities, and were soon resolved. Landowners of this area freely donated the land for Muna School (and now GBCHS) in 1962 for the education of their children.

Ringgi, Kolombangara, Western Province The hydro site identified at Ringgi on Kolombangara is capable of meeting the power requirements of Kolombangara Forest Products Ltd (KFPL), a large plantation based at Ringgi, as well as nearby villages and the SIEA supply area at Noro and Munda on nearby New Georgia, which together comprises a major population hub. Noro, a small industrial centre and port, has a population of around 4,500, an international port with facilities for the transhipment of timber and a tuna processing factory. Munda, with a population of approximately 3,000, is a provincial government sub-station and major airstrip. Infrastructure services in the area include a central water supply, rural hospital, police post, post office, schools and government services. Development plans for the Noro-Munda area, which are now hampered by a severe power shortage, include further industrial growth at Noro and further tourism growth at Munda. Once these plans go ahead, there is likely to be a substantial increase in electricity demand and population. Since the early 20th century, a large proportion of the island of Kolombangara has been plantation forest on land alienated from customary ownership. KFPL is part (40%) owned by the SI government and, since late 2010, majority owned by a Taiwanese company, Nienmade Enterprise. The KPFL estate is of national economic importance and the Company is the major employer on the island and region. Approximately 3000 people live in and around the estate, most in workers’ houses at Ringgi Station. Another 3500 live outside the estate in the south west of the island or in villages along a 500-1000 m wide coastal strip of estate land on which they freely reside, obtain timber and other products from logged forest (such as firewood) and garden. The Ringgi Station has electricity but the hydropower plant will increase its supply and lower costs. Potential enterprises include a sawmill, small- scale furniture making, fish storage and marketing, small retail shops, and selling of cooked food. As part of its valuable Forestry Stewardship Council (FSC) rating, KFPL abides by conditions of social responsibility to its workers and other island residents, which meet international

31/25866 February 12 156 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES standards.56 (Maintenance of the FSC rating was a condition of the recent sale of majority shareholding). KFPL’s Social Management Plan outlines company policies on labour standards, access to social services, gender equity, etc. Outside of the company workforce and their families, each community or village on the island has an elected Resident Advisor who consults with KFPL about community concerns and with the community about company concerns and plans. Resettlement With full support from KFPL, and managed by indigenous communities through the Kolombangara Island Biodiversity and Conservation Association, the island now hosts a major conservation area covering all land above 400 m. asl as well as an ecotourism venture. The proposed hydropower site is on an adjoining protected area. No resettlement of houses or gardens will be required but there may be some disturbance of the ecotourism business during construction, and possibly some resistance from the managers of the protected area. Indigenous People KFPL holds a 75 year lease over most of Kolombangara Island, including the proposed project site. While indigenous owners wish to reclaim their land this is not a matter of immediate dispute, and the national government is unlikely to relinquish their leasehold.

Mase, New Georgia The Mase River provides a possible alternative site to Kolombangara, to supply the Noro- Munda area. Most landowners of the site live at Mase, a large village with a population of more than 500 people on the northern end of New Georgia and with a strong affiliation to the Seventh Day Adventist (SDA) Church. Villagers welcome the project and the possibility of electricity supply, which they look forward to using in their primary school and church, and for lights, video watching, cooking, sewing at night, fish storage, furniture making, and so on. They also anticipate that the access road to the site may join with logging roads on the island and connect through to the services and markets at Noro and Munda, providing a safer and easier trip than by boat. Villagers were however concerned that they only heard the ‘good side’ about future projects, and were anxious to know what impact mineral exploration high in the Mase River catchment is having on the river, believing that chemicals and siltation may be spoiling it. This is unlikely, but their concern needs to be explored and may mask other issues. The proposed hydropower site is away from the village, in a part of the island that is rarely used. The land above the site on which mineral prospecting is being conducted belongs to neighbouring villages which are members of the independent and communally based Christian Fellowship Church (CFC). The CFC was originally led by the charismatic Holy Mama but now by one of his sons (another is the local Member of Parliament) who holds unquestioned power over church members. With its large communal plantations and business ventures, the CFC is a major economic force on New Georgia, investing in businesses that benefit rural people. CFC communities have also been noted for their opposition to large-scale foreign developments in logging and other enterprises but also their support for conservation.57 Mase poses a unique situation, therefore, where support for the project will need to be sought not only from landowners but also the CFC leadership.

56 KFPL, 2010. Social Management Plan, 2011-2015. 1. 57 E. Hviding, 1996. Guardians of Marovo Lagoon: Practice, Place, and Politics in Maritime Melanesia. Honolulu: University of Hawaii Press

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Mataniko River, Honiara, Guadacanal Honiara, the capital and largest city of Solomon Islands, has a population of approximately 90,000 that is growing quickly, at around 4% p.a. Approximately 75% of the town population has access to electricity but demand is also growing quickly. There is a backlist of more than 1,000 households and businesses to be connected if the Honiara system can be extended to residential areas to the east and west of the current supply area. There is no reserve capacity in the diesel power generation, power cuts are common, and there has been interest for some time in hydropower generation. Hydropower development on the neighboring Tina River is being investigated through a study financed by the European Investment Bank. The Mataniko River emerges behind Honiara, through heavily dissected and forested hill country. The river, its gorge and waterfall (above which the intake is planned) is a popular hiking trail and a tourism attraction. There are no people living at the proposed hydropower site although there are a few very small hamlets further up the river. Most landowners live further down the river, on the outskirts of Honiara. They and other potential electricity consumers in Honiara stand to benefit from a more secure electricity supply. The most critical issue is land acquisition. Landowners also expect large payments for access and resource use on their land, and traditional land claims are poorly documented in this area. The Tina River Project recently paid out $200,000 to each of 27 ‘tribes’ with claims to land ownership for investigation access to the area alone. Mataniko landowners have already requested compensation of 1 million SB$ for the installation of a gauging station which was therefore not implemented. Future compensation claims may render the project unfeasible.

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14. Conclusions and Recommendations

Most inhabited islands of the Solomon Islands have hydropower potential. Rainfall in higher catchment areas is evenly distributed over the year and the rivers draining catchments have often sufficient slope to allow the development of high or at least medium head schemes with estimated specific investment cost in the range of 2600 – 3600 US$ per installed kW for plants in the class 1 – 5 MW. Smaller schemes in the 100 kW class are typically costing around US$ 6,000 – 7000 per installed kW but can be significantly higher where conditions are unfavourable. These figures do not include land acquisition cost. Factors limiting hydropower development are unfavourable geological conditions (porous limestone formations and thick layers of unstable alluvium) and high flood levels associated with extreme weather events (cyclones). These constraints can, however, be overcome by appropriate designs that avoid dams and tunnelling. Run off river plants with contour canals and steep, short penstock pipes seem to be cost efficient and environmentally friendly as long as minimum flows are maintained in the respective rivers. Another constraint is landowner resistance or unrealistic compensation claims made by landowners. In addition, there is inadequate hydrological data to accurately forecast river run off and energy potential of specific sites. This lack of data has been addressed in this TA through the installation of 5 automatic river gauging and rainfall recording stations. Costs and Benefits of Mini Hydropower Despite the constraints mentioned above, hydropower is considered viable for most of SIEA’s grids. SIEA’s plants in Buala (Santa Isabel) and Malu (Malaita) have already demonstrated that hydropower is a reliable energy source with low operating and maintenance cost. As it requires no fuel input, electricity from hydropower is in most cases less costly than equivalent diesel energy. It also avoids the expense and insecurity of fuel logistics. It is as effective in rural supply areas as it is in urban supply areas, provided that local topological and hydrological conditions (rainfall, catchment area, runoff) are adequate and landowner issues can be resolved. Its capital cost can vary enormously from site to site, depending upon local topological and geological conditions. For the five sites investigated in this prefeasibility study, hydropower has considerable potential to provide access to affordable, renewable electricity to rural areas. In the investigated load centres and perhaps others, hydropower has good potential to turn loss-making rural diesel stations into profitable operations or to create new rural power supply systems that are profitable, either for SIEA or for an independent power producer (IPP). Assuming that the willingness to pay for electricity it is at least equal to the national electricity tariff, hydropower will benefit the rural population by raising the quality of life, widening the opportunities for improved social services, and perhaps stimulating commercial development. The following Table 14.1 summarises the results of our investigations for the five sites that have been selected in close consultation with SIG and SIEA senior management.

Table 14.1: Summary of Hydro Projects Load Installed Annual Investment Levellized FIRR US$/kW Environmental Center kW GWh US$m US$/kWh % Category Auki 1,160 9.8 4.2 0,08 35% 3,600 B Lata 107 0.8 2.2 0.2 13% 20,300 B Ringgi A 1,210 10.4 4.4 0.07 45% 3,600 A Ringgi B 4,320 26.3 11.3 0.06 47% 2700 A Taro 260 2.1 1.7 0.12 18% 6,500 C Honiara 2,740 12,7 7.2 0.08 40% 2600 A +Tina Honiara - 2,740 12,7 7.2 0.08 47% 2600 A Tina

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These preliminary cost estimates have been prepared for the purpose of prioritizing sites for further investigation and must not be used for any other purpose. They are subject to the limitations contained in section 1.4 of this report. While specific investment cost vary considerably, the results show that for projects above 1 MW, total costs (excluding land acquisition) are below US$ 3,000 per kW which results in robust FIRR values in the 40% range and in levelized energy production cost below 10 US cents per kWh. Sensitivity analysis shows that even under pessimistic assumptions the projects turn out to be competitive with diesel generation for which a real increase in fuel cost of 3% p.a. has been assumed. Hydro development has the potential to fundamentally change SIEA’s financial position in the centres investigated if SIEA invests in the projects. The larger projects (above 1 MW also seem to support development as privately financed IPPs with the benefits shared between a developer and SIEA as an off-taker.

IPP Development SIEA has expressed an interest in leaving hydropower development to private IPP investors. The main reasons for this position are firstly a reluctance of SIEA to deal with landowner issues that will inevitably arise in conjunction with hydro development and secondly the shortage of investment funds. The IPP development modality can indeed overcome these two obstacles. Landowners could be made shareholders in IPP developments with land acquisition compensation paid as dividends tied to the performance of the projects. However, the IPP modality requires effective and efficient risk management and an enabling framework that is able to balance interests of investors, consumers and the off-taker SIEA. Such a framework or a regulatory authority that could address risk management issues does not yet exist. In case the IPP route is chosen for the hydro projects, it seems prudent to aim at preparing the projects in the public sector to an international standard (possibly with TA support from donors) and then competitively procure the projects in international tenders. This means that funding needs to be located to perform the feasibility and preliminary design studies for the priority sites.

Priority Projects From the consultant’s perspective, there is a clear merit order for the projects. The highest priority should be given to the Ringgi project. It is not only the best performer in terms of FIRR, it also has the highest quantitative impact in terms of kWh supplied. An additional advantage is the absence of landowner issues, as the forest company owns the land where the hydropower plant would be installed. It is recommended to focus on a variant that would not only supply the demand of Ringgi, but also the demand of the demand centres Noro and Munda. SIEA will have to restructure its power supply to these centres anyway and instead of building a new diesel power plant, Noro and Munda could be supplied from Ringgi with diesel back-up provided by the 3 MW of diesel capacity installed at the Soltai fish processing company in Noro. An additional advantage of the Ringgi project is that the forest company has already all equipment that would be necessary for the construction of the hydro plants on site. i.e. mobilization cost for construction would be extremely low in comparison with other projects. This project has been classified as a category A project due to environmental concerns related to the High Conservation Value Forests within the Vila River catchment including the riparian buffer zones. Whilst KFPL have indicated that the project would not compromise their environmental objectives, a full EIA would be required. The Mataniko project shows equally high FIRR values, in particular under the assumption that the Tina river project will not go ahead. Developing this project will, however, have to include resolving some critical land acquisition issues as compensation demands for the installation of a simple automatic gauging station were already quite substantial. In addition the project has been classified as a category A project due to environmental concerns related to the potential negative impact on a waterfall site that is regularly visited by tourists.

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The Fiu River hydro scheme on Malaita has the potential to provide low cost electricity for the provincial capital Auki including surrounding areas. At 35% the FIRR is still significantly above the WACC and the project should also be considered as a priority. The smaller projects Lata and Taro show significantly higher specific investment cost and while still viable under standard assumptions taken, they may require some donor support to materialize.

Next Steps Securing a continuation of collection and processing of the hydrological data at five sites is critical as any subsequent study and design work would have to depend on these data. The responsibility for data acquisition should be transferred to SIEA as the utility has already personnel in the provinces that can visit the sites, check the state of the equipment and download the data from the loggers. Site visits should be performed every three months. Data collected should be shared with MMERE’s water and energy departments. It is recommended to prioritize both Fiu (Auki) and the Vila (Ringgi) projects for full feasibility studies. For Ringgi, a full EIA would also be required as part of the feasibility work.

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Annex

Annex 1: Automatic Stations Used on ADB RETA 7329

Background Due to lack of reliable hydrological data for the rivers and catchments analysed under RETA 7329 it was decided to include rainfall and water level recording in the project. 7 automatic water level and rain gauge stations have been procured by GHD for installation on successful projects under pre-feasibility studies.

The “ARG100” Rain Gauges The rain gauges are produced by: Environmental Measurements Ltd. (EML), Business & Innovation Centre, Sunderland Enterprise Park, Sunderland SR5 2TA, U.K., Tel: +44 191 5010064, Fax: +44 191 5010065, Email: [email protected] , Web: www.emltd.net

The rain gauge is a tipping gauge, generating an electric impulse with two magnets passing each others when tipping and it tips about each 0.203 mm (see individual calibration sticker inside the rain gauge) of rainfall. The innovative design of the rain gauge allows catching all rainfall in windy situations. When using conventional cylindrical rain gauges, 15-30% of the rain is lost when wind and rain coincide unless a cylindrical curtain of some sort is established around the gauge with a diameter of 1.5-3 m at about the level of the top of the rain gauge.

The rain gauge has an inbuilt level to support installing the gauge completely horizontal, which is needed to achieve accurate measurements. Levelling is achieved by adjusting the nuts that hold the unit on its steel base plate.

The Solinst “3002 Rainlogger c/w connection cable” shown above has been installed in the gauges. After installation, the time interval between registering observations is set. The logger counts the number of tips in the period and registers the final result at the end of the time interval. The logger has a memory of 32,000 observations and once this has been exceeded, it overwrites the oldest data. If as example the time interval is set to 15 minutes, it will take 333 days before overwriting of data starts. With an interval of 30 minutes, 666 days would pass before overwriting of old data begins. At the initial installation of the stations in Solomon Islands 15 minutes time interval has been selected, which allows almost 11 months in between data collection visits and at the same time provides adequate data resolution for hydro power planning. If a more scientific analysis of extreme rainfall intensity is planned for any other purpose than hydropower (urban runoff from paved areas as example) it would make sense with a shorter interval, otherwise not. The datalogger comes with a connection cable, which has to be joined with the cables mounted inside the rain gauge. After starting the datalogger, using a laptop computer and a communication package, the cap is put back on the data logger and the datalooger is stored

31/25866 February 12 162 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES inside the rain gauge in a way so that the cables don't interfere with the tipping mechanism. If the cap is not put back on, the battery of the logger will be drained, as the optical sensors for communication will be switched on as long as any light reaches the sensors. The inbuilt battery is quoted to have a lifetime beyond 10 yrs at 15 minutes scanning interval.

The Water Level Stations Using Solinst “3001 LT Levelogger Gold M5/F15” and “3001 LT Barologger M1.5/F5”

The water level loggers installed are supplied by:

Solinst Canada Ltd. 35 Todd Road Georgetown, ON, L7G 4R8 Fax: (905) 873-1992 (800) 516-9081 Tel: (905) 873-2255 (800) 661-2023 E-mail: [email protected] Web Site: www.solinst.com

This modern level logging units measure both the pressure of the water above the sensor and the air pressure at the site. The Levelogger is placed in the water, measuring the total of air pressure and the pressure of the water column above the sensor, while the Barologger, placed above the highest water level, is measuring the air pressure, which later has to be deducted from the readings of the Levelogger to calculate the relative water level. Either a staff gauge has to be installed on the site of the Levelogger or a reference point has to be established above normal water levels to take reference water levels at the time of checking the the station and during discharge measurements for the rating curve for the station.

The Levelogger and the Barologger have the same capacity ad the Rainlogger and store the latest 32,000 sets of reading in the memory of the logger. The Levelogger stores pressure and water temperature and with a pressure range from 0 to 5 m absolute water pressure, which for practical purposes means a 4m water level interval. The barologger registers air pressure between 0 and 1.25 m equivalent water pressure and is used to calculate the actual water level. With more Leveloggers in a local area only one Barologger is needed. The Levelogger is set at 15 minutes between measuring water levels, which gives 333 days to fill the memory before over-writing begins. With this frequency the battery time of the loggers should be slightly above 10 yrs. With 15 minutes resolution, it will catch the rapid changes of water levels for streams with small catchments, where flood waves can pass in short periods in the case of a localized rainfall.

Selection of Sites The selection of a suitable site for the station is critical for the cost of maintaining it for getting reliable data.

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Conventional installation require considerable civil works be undertaken for such a station, including building a measuring well in which the Levelogger is installed and the construction of a V-shaped where the slopes on the weir is painted as a staff gauge. Some conventional stations include the construction of a permanent house. This, however, is seen as uneconomical for temporary stations as considered here. A significantly cheaper solution has been used in the project: A stable controlling section downstream of the gauging is identified. A controlling section is a place where the flow to the downstream is super critical (like a rapid or water fall) and to the upstream is subcritical (like a slow flowing stream or a pool). The width of the controlling section should be rather narrow, which result in significant change of water level with changes in discharge, which is critical for the precision of flow measurement. The bottom of the controlling section should be rock or stones which are overgrown with algae, indicating that they are stable on the location. If the cross section is changed during each major flood, a new rating curve has to be established every year as described below and this typically involves 4-5 visits for discharge measurements, incuring significant cost.

Installation The Levelogger is mounted on a significant size steel grill, placed on a protected spot in the pool upstream of the controlling section and covered by large boulders, which will not be washed away. Should extreme floods occur during a major cyclone all stations have to be visited and reinstalled if necessary. A suitable place is either immediately upstream or less ideal downstream of a large boulder or rock, where it will be protected from large tree trunks potentially damaging the station. The Levelogger has to be placed below the lowest occurring water level in the river, which typically represents a significant challenge.

After the establishment of the station the rating curve has to be established by discharge measurements at different water levels. Typically more than 4 – 5 observations are required to document a rating curve. It may expressed as a formula:

Q = a x (H-Ho)^b where:  Q is the discharge in m3/s  a is a constant related mainly to the width of the controlling section  H is the water level as registered by the Levelogger  Ho is the corresponding water level of no flow (according to the formula) in the height interval the formula covers, as on complicated sections, several intervals with each their formula may apply, especially when the section is inundated from sections to the downstream or the width above a certain level becomes large, when the water level exceeds the level of the immediate river bank  b describes the shape of the cross section and may typically be a figure between 1.6 and 2.4, depending on the shape of the cross section (rectangular or V-shaped)

As seen 3 values have statistically to be estimated and initially b may be assumed about the value of about 2.0, leaving a and Ho as the most critical ones at the beginning of the measurements. Ho may be physically assessed as well, but it is difficult to estimate the zero flow level. It is a common mistake to assume that it occurs when zero water level readings are shown in the logged data.

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The Levelogger is connected to the 15m long direct read cable before being fixed on the grill with plastic cable ties. The grill is fixed at a 5mm galvanized steel rope with a loop through the grill and a cable clamp fixing holding it in place. First the 15m long steel cable is connected to the storage box for the Barologger fixed with a galvanized chain in a tree above the highest water level, from where it follows the surface down to the Levelogger. If possible a small trench is made for the cable and covered with rocks after installation of the cable. As the connection to the grill typically is less than the 15m, the excess steel rope follows the direct read cable and the steel rope back towards the storage box, and the direct read cable is placed between the two steel rope cross sections and fixed with cable ties every 250mm.

Discharge measurements There are three types of discharge measurements:  Float method  Salt dilution method  Propeller method

The methods differ in terms of equipment used, cost and accuracy. They are briefly described below:

The float method A measuring tape or steel cable with 1m marks is tied across the stream. At a minimum of 8 sections or for each meter the surface velocity is measured with a floating piece of stick floating down along a measuring stick. The time is recoded for the float to cover the distance for each segment, starting in the middle of the segment below the tape or steel rope. At the same time the depth is taken at every 0.5m, so the average depth for each segment is known as well. Assuming the average velocity is about 0.8 times the surface velocity the discharge per segment is then calculated and the sum is the total discharge. As long as all the details above are maintained the results of such a measurement are of acceptable accuracy. The equipment used is inexpensive and easy to transport. The problem with the method is that people doing it often take shortcuts, simplifying the procedures in order to save time.

The Salt Dilution Method For this a conductivity meter is used (in this case a Hanna HI-8733, which is self calibrating and includes temperature compensation). The probe is kept in the stream so the flow always passes inside the plastic cover passing the sensor and out through the holes on the side. The calibration indicator is set to 2.0, which secures full temperature correction for conductivity with a temperature sensor inbuilt in the probe. Salt, normally 3kg per assumed m3/s of flow (with 100% more in limestone areas), is bought in 500g or 1kg bags in the local shops and spread out across the stream upstream of the measurement spot at a minimum distance of 30 times the average width of the stream. This ensures a good mixing of the salt in the flow. The following 3 conditions for the stretch between the salt spreading spot and the metering spot need to be observed:

 There must be no pools on the stretch, which would delay the passing of the salty water  The stretch has to have turbulent flow for the mixing, typically a number of small rapids between stones  The stream has to maintain only one path, no separation into different parallel streams on the way, which prevents mixing across the total width of the stream.

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Violation of any of those conditions typically leads to serious errors in the range of +/- 50%. The probe is installed in the water before the salt is spread upstream. The instrument first has to stabilize the reading of the background conductivity, which typically will vary from above 50 in volcanic soils to about 350 microSiemens/cm in ground water in limestone areas. If the background is below 100 the scale to 199.9 is used and if higher the scale to 1999 is used. After spreading salt, the time for the salt wave to reach the probe may be vary from 1 to 15 minutes. The background is monitored closely and noted down as it may change while waiting the salt wave. Once the conductivity starts rising, the conductivity is noted every 10 seconds until it is back to the background. After 15 consecutive constant readings above the original background reading, this new level is used as the background value and the measurement is completed. The calculation of the discharge is done in a spreadsheet model where the amount of salt used, the background reading and the observations every 10 seconds are entered. This allows calculating the average concentration in the whole period and knowing the amount of salt used, then the volume of water passing is computed. As the duration is also known the discharge is calculated. The method yields accurate results if the location for the measurement is adequate. It does not require heavy and expensive equipment to be carried and maintained.

The Propeller Method This is the classical method used by professional organizations maintaining a larger network with more than 50 or 100 stations. Propellers are typically expensive in procurement and are extremely demanding in maintenance and use. Lubrication oil typically have to be changed at every use of a propeller and every year it typically has to be sent for re-calibration at a hydraulic laboratory at a cost of about USD 2,000 each time. It has been observed that institutions neither changing oil every time nor have propellers re-calibrated on periodical basis might be operating with systematic errors of up to about - 30% on average and much larger on low velocities. In a small stream 10-20m wide sections are marked as described above for the float method, measuring the depth every 0.5m and measuring the velocity for every 1.0m. If large stones are located in the cross section, the area covered by those have to be effectively deducted from the calculations. If the water depth in a section is above 0.6m the velocity is normally measured in two depths instead of only one. Unless the propeller measurements are carried out in a very disciplined way and the equipment properly maintained, the results from propeller measurements may be very poor.

3001 Direct Read Comm. Package (USB) for the Levelogger For the communication between a laptop computer and the loggers a set of cables and a software package is needed. Two different cables are used for communication. One with a socket for optical communication, where the datalogger is plugged into the socket (Rainlogger and Barologger) and another with a serial interface to the direct read cable used on the Leveloggers. A Windows based communication program installed on a laptop computer is used to upload settings to the dataloggers and to download data.

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Annex 2 Legal Framework for Rural Electrification

General

In the following the legal system of the Solomon Islands relevant to hydro power development and rural electrification is outlined58. The legal system is built on the Constitution, which has primacy, a system of Customary Law deriving from the country’s indigenous traditions, and English Common Law inherited from its colonial past. The National Parliament is empowered under the Constitution to enact laws.

The last fifteen years have seen an overhaul of some parts of the legislative framework to adapt the legal system to cope with the pressures imposed on it by the opening up of the economy to global markets. Foreign investment law, environmental legislation and much of the natural resources legislation is relatively recent and adequate for present purposes, but the Electricity Act, Petroleum Act and other key energy laws date from the sixties and even earlier. These are in need of revision.

Legislation dealing directly or indirectly with rural electrification is outlined in the following sections.

Electricity Act (1969)

The Electricity Act provides for the establishment of SIEA and authorises it to provide electricity to urban and provincial centres and other supply areas as instructed by the Minister.

Electricity supplies provided by anyone other than SIEA must be licensed. The licensing system authorises private and community-based operators to supply rural areas and establishes a mechanism for regulating their activities and maintaining appropriate safety and technical standards. Licences are issued by SIEA. SIEA is also the authority for licensing electricity installations and electricity contractors and electricians.

The licensing regime also applies to back-up plant installed by consumers to counter the effects of frequent load shedding by SIEA but owners are obliged to pay SIEA up to 50% of the value of the electricity they generate during periods when the SIEA supply is available.

Exemptions to the licensing provisions of the Act are specified in the Electricity (Exemptions) Order (1992). Supplies less than 50 kW are exempt (unless they serve hotels, resorts, labour lines or staff quarters) and this puts the majority of rural electrification schemes beyond the control of the licensing system.

The authority to sell electricity under a licence applies only within defined geographical areas specified in the licence. The maximum term for a licence is 21 years unless express approval of the Minister is obtained.

58 Review of Electricity Act, prepared for PIEPSAP by Maunsell, 2007

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The key provisions of the Electricity Act and subsidiary legislation address the following:

(i) Electricity Act

• Establishment of SIEA; • Functions and duties of SIEA; • Financial matters relating to SIEA (borrowing, income tax exemption, subsidies, electricity pricing, expenditures and investments, reporting and auditing); • Licensing others to supply electricity; • Acquisition of land; • General powers of SIEA and licensees (powers of entry, power to inspect, etc.); • Reduction of supply/ disconnection of supply; • Electricity use; • Protection of SIEA power system; • Compensation for damage; • Offences and penalties.

(ii) Electricity (Tariff) Regulations Electricity (Tariff) (Automatic Fuel Price Adjustment) Regulations The Electricity (High Voltage)(Tariff) Order

Tariff regulations are promulgated from time to time through subsidiary legislation to adjust the prices charged by SIEA and licensees for electricity supplied. The adjustments are made to reflect changes in costs of generation and supply (refer §21 of Electricity Act and this §2 of the Tariff Regulations). An automatic fuel price adjustment mechanism provides for a regular 3-monthly adjustment of the retail price of electricity to take account of changes in the price of imported diesel fuel.

(iii) The Electricity Regulations – Arrangement of Regulations (“Electricity Regulations”)

The Electricity Regulations prescribe applicable requirements and procedures in respect of, amongst others:

• Technical standards of electricity supply (voltage, frequency, etc); • Wiring of electrical installations; • Compliance with wiring rules etc; • Licensing of electrical contractors; • Application for supply; • Service connections; • Provision of additional capacity; • Consumers with large demand; • Installation of emergency or standby generating plant; • Metering; • Rates and accounts; • Security deposit and service charges;

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• Liability of consumers; • Power to discontinue or disconnect supplies; • Restrictions on the use of electricity.

The Electricity Act dates from the sixties and a review is overdue. Its principal focus is urban electrification and is not concerned in any specific sense with rural electrification or renewable energy. A possible role for the private sector is recognised in the Act’s licensing provisions, but the conditions for participation are unattractive (refer Section 4).

A State-Owned Enterprises (SOE) Bill is understood to be under preparation. The intention of the legislation is to establish an umbrella framework for the operation of all SOEs, including SIEA. The SOE Act would therefore supersede certain sections of the Electricity Act including those dealing with the Authority’s constitution, legal identity, reporting requirements, etc.

Foreign Investment Act (2005)

The Foreign Investment Bill was presented to Parliament in July 2005 and was assented in December of that year. Foreign Investment Regulations were gazetted recently. The Act seeks to advance the policy objectives of the Government by creating a business environment that facilitates, monitors and controls beneficial investment by foreigners in the Solomon Islands.

Under the Foreign Investment Act (2005), investors must first obtain a Certificate of Registration. A Registrar of Foreign Investment is appointed and will process applications, issue Certificates of Registration, register investment activities, monitor compliance with the Act and keep a register of foreign investment activities.

A Certificate of Registration is a prerequisite for negotiating or entering into any arrangement or agreement in respect of an investment opportunity. The certification process has been streamlined. The foreign investor first makes application to the Registrar in the form prescribed in the Act (the application form comprises two A4 pages) and pays the required fee. Within five days of receiving a correctly completed application, the Registrar will assess the application and give written notice whether it is accepted or rejected. In cases where a decision cannot be made within the five day timeframe, it will be rendered as soon as practicable.

The Registrar may cancel a Certificate of Registration if the foreign investor fails to commence an investment activity within twelve months of receiving the certificate. Other grounds for cancellation are involvement in illegal or prohibited activities, or obtaining a certificate by fraud or misrepresentation.

An Investment Facilitation Committee is established to help investors holding Certificates of Registration to conduct their investment. The Committee is also empowered to review the Registrar’s decisions relating to rejections of investment applications and cancellations of Certificates of Registration.

Some investment activities are reserved for local investors and foreign investors are precluded from participation. These activities are listed on a “Reserved List” and the criteria governing

31/25866 February 12 169 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES their inclusion are specified in §9. The Reserved List is reviewed at least every two years. Any change will require Cabinet approval. It is unclear at this stage whether any activities relating to the electrification of rural communities will be included on the Reserved List.

Environment Act (1998)

The Environment Act (1998) was gazetted in September 2003 but regulations are not yet in place. The objectives of the Act are specified in §3. They are to:

• Provide for and establish integrated systems of development control, environmental impact assessment and pollution control;

• Prevent, control and monitor pollution;

• Reduce risks to human health and prevent degradation of the environment by all practical means, and

• Comply with and give effect to regional and international conventions and obligations relating to the environment.

“Environment” is given a broad definition (§2): it includes “all natural and social systems and their constituent parts, and the interactions of their constituent parts, including people, communities and economic, aesthetic, cultural and social factors”. Rural electrification projects typically involve a complex interaction of these elements.

The Act provides for the establishment of an Environment and Conservation Division (the “Division”) to administer its provisions. The Division is organised under the Ministry of Natural Resources and is responsible for administering environmental approval provisions under the Act. In considering whether to approve a development, the Division must “have regard as far as practicable to the effect such development … would have on the environment”. The Act also provides for the establishment of an Environmental Advisory Committee to advise the Minister and the Division “on any matters connected with the environment and conservation referred to it” (§14).

Part III of the Act defines formal environmental impact assessment procedures. Applications to undertake developments described in a schedule of the Act as “prescribed developments” must be referred to the Director of the Division for approval. Applications must be supported by an environmental report and the Director must advise the developer whether this report should take the form of an EIA. In determining whether an EIA is required, the Director is to take account of the impact that the development is likely to have on the environment and any other factors prescribed by regulation. The required scope of environmental reports and EIAs are outlined in §20 and §23 respectively.

§17 stipulates that a foreign investor must also include with its application a copy of a certificate of approval issued by the Investment Board; however, under the new Foreign Investment Act a Certificate of Registration is probably required instead (refer Section 0).

When the environmental report is completed, it must be brought to the attention of stakeholders who may send written objections to the Director. The Director shall then decide whether to

31/25866 February 12 170 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES consent to the development, or require the developer to produce an EIA, or refuse the application. If the EIA satisfies the requirements of the Act, it will be made available to stakeholders. The Director, after considering written submission, will decide whether to consent to the development or refuse consent. If consent is granted, the developer must carry out the development in accordance with the development consent.

Experience in the operation of the Act is limited. Although it contains no specific requirements for power generation and distribution, fuel storage or other such projects, it is accepted that an EIA would be needed for a significant hydropower development, particularly a storage project such as Lungga. However, it is less clear how the operation of the Act will affect smaller rural electrification projects.

River Waters Act (1964) / Water Resources Bill (2001)

An important source of generation for rural electrification schemes is hydropower. This might be in the form of mini-, micro-, or pico-hydropower and notwithstanding their size and design, each type will have some impact on the river or stream on which they are sited. They must therefore be developed within the constraints of the River Waters Act and, when it passes into law, the Water Resources Act.

The stated purpose of the River Waters Act is “to provide for the control of river waters and for the equitable and beneficial use thereof”. The Act, under §5, requires a developer to obtain a permit and comply with its conditions if it:

“(a) by means of a ditch, drain, channel, pipe or any other means whatsoever, diverts any water from a river;

(b) fells any tree so that it falls into a river or river bed;

(c) in any manner obstructs or interferes with a river or river bed;

(d) builds any bridge, jetty or landing stage over or beside any river;

(e) damages or interferes with the banks of any river; or

(f) contravenes any order made under section 4 of this Act”.

The Minister has powers under §4 of the Act to “prohibit the construction or siting of any building, structure or erection in the flood channel of any river or in any place in which it appears to him that such building, structure or erection may impede, or obstruct, or otherwise affect the flow of a river”. The Minister, under §7, may also “grant to any person a permit to divert water from any river and such permit shall be published in such manner as he may determine” provided that an application has been made in the prescribed form. In approving such development, the Minister is obliged to “have regard to the existing use of water” and to “safeguard such existing use of water as far as appears to him to be practicable and consistent with the provisions and purposes of this Act”.

Ownership of water, as opposed to the common law right of use, is complex and tied to customary land ownership. The Government has the power under the Land and Titles Act to compulsorily acquire water sources in the public interest but, in practice, water rights is a sensitive issue and the Government is reluctant to press matters. Most rivers are situated on

31/25866 February 12 171 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES customary lands and customary land owners are in a position to require reasonable rental payments where water sources are being used. The River Waters Act does not properly address these issues and new legislation is needed that recognises customary water and land rights together in providing a framework for the orderly, equitable and environmentally sustainable development of the country’s river systems.

The Water Resources Bill (2001) has been drafted to fill this need. The stated purpose of the Bill is (refer §1):

“(a) To provide for the integrated management of the water resources of the Solomon Islands.

(b) To promote the most efficient, fair and beneficial use of natural water.

(c) To ensure that natural water resources are available for sustainable use for the benefit of all present and future Solomon Islanders.

(d) To provide for the protection of natural watercourses and water catchments.

(e) To provide for the control of activities occurring over or beside waterways or watercourses.”

The Bill recognises that all natural water within the territory of the Solomon Islands is dedicated to the use of the people and that the right to control, manage and administer water resources is vested in the Government.

The Bill would establish a licensing regime to control the utilisation of water and would prohibit anyone from abstracting or diverting or damming natural water without a license. Domestic uses would not require a license and people with customary rights to the land and water would be exempt from the need to obtain a licence for subsistence irrigation and raising livestock. The licensing provisions set forth in Parts 5 and 6 of the Bill specify the institutional arrangements and procedures for granting, registering, altering, suspending, revoking a licence.

Provincial Government Act (1981)

The Provincial Government Act establishes provincial administrations in the Solomon Islands. The legislation defines a framework for the creation and operation of Provincial Assemblies, with each assembly made up of elected representatives from electoral wards within each province. The Provincial Assembly may enact ordinances within its legislative competence (as specified in the Act), such ordinances being consistent with Government policy for the Solomon Islands as a whole.

The Act provides for the creation of a Provincial Executive to undertake the functions and exercise the powers as set out in schedules to the Act and as ordered by the Minister.

With respect to the supply of electricity, §35(5) states that a Provincial Executive may provide services for the province in respect of any of the matters listed in a schedule to the Act (Schedule 6, Provincial Services). Schedule 6 includes: “Supply of electricity outside supply areas (within the meaning of the Electricity Act).” It is not clear in practice, though, how this might work and whether a provincial government has any say in the selection and sequencing

31/25866 February 12 172 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES of rural electrification projects. As the tier of Government closest to the remote rural constituents most affected by such decisions, it might be argued that provincial assemblies should have a direct role. However, their capacity in such matters is understood to be weak and the quality of decision making might be correspondingly poor.

Land Tenure Legislation

Land in the Solomon Islands is a sensitive issue; group and individual identity are defined by their relationship with the land. Two distinct systems of land tenure operate:

• Alienated land, comprising 13% of total land area. Alienated land was procured during colonial times and its boundaries are surveyed and registered.

• Customary land, comprising 87% of total land area. Customary ownership of land is based on traditional tenure and boundaries are fixed by geographical features such as rivers and ridges. Ownership of customary land may in some cases be officially clarified but not in others. Customary land is defined in the Land and Titles Act as “any land (not being registered land, other than land registered as customary land, or land in respect of which any person becomes or is entitled to be registered as the owner of an estate pursuant to the provisions of Part III) lawfully owned, used or occupied by a person or community in accordance with customary usage, and shall include any land deemed to be customary by paragraph 23 of the Second Schedule to the repealed Ordinance.”

Key land tenure legislation is outlined:

(i) Land and Titles Act (1969)

Land is defined as including “land covered by water, all things growing on land and buildings and other things permanently fixed to land but does not include any minerals (including oils and gases) or any substances in or under land which are of a kind ordinarily worked for removal by underground or surface working”. Under the Lands and Titles Act and its thirteen amendments, no person other than a Solomon Islands citizen can hold perpetual title to registered land. The Act allows a person to convert customary land into registered land.

The Act is administered by the Commissioner of Lands. His duties and powers include advising the Minister on land policy and dealing in land on behalf of the Government and executing any instrument relating to any interest in land. The Commissioner has the authority to grant or transfer an interest in land and to register leases. The rights and obligations of lessor and lessee are defined in the Act.

The Act provides for the compulsory acquisition of alienated or customary land for a public purpose and specifies the procedures to follow. An amendment to the Act also allows the Minster to designate any area as a land settlement area where there is a need to resettle people from one location to another.

All transactions relating to any land are recorded and kept in the Land Registry. The Act sets forth the procedure for registering an interest in land.

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(ii) Customary Land Records Act (1994)

The purpose of the Customary Land Records Act is to provide a mechanism for recording customary land boundaries. The Act is administered by the Commissioner of Lands and is assisted by the Registrar of Titles and other lands officers. The duties and powers of the Commissioner of Lands include advising the Minister on any matters concerning land policy. He holds and deals in any land for and on behalf of the Government and, subject to any general or special direction from the Minister, execute for and on behalf of the Government any instrument relating to and interest in land.

Since its introduction, the Customary Land Records Act has not operated as intended. No customary land has been recorded under the Act, a failure attributed to the Act’s complexity and a lack of effective institutional backing.

The current system for resolving land disputes involves a hierarchy of chief’s committees, local courts, Customary Lands Appeal Court and the High Court. The Customary Lands Appeal Court was established for the specific purpose of hearing appeals from the Local Courts related to customary lands disputes.

A number of commentators have identified land tenure as a significant obstacle for infrastructure development generally and, more specifically, for private sector involvement. This may apply to rural electrification schemes, particularly those involving hydropower generation, although there should be no difficulties where schemes are located on customary land that is owned by the village(s) that will benefit. Land reform proposals have been put forward but no Government policy has yet emerged. 59

Consumer Protection Act (1996) and Price Control Act (1975)

The Consumer Protection Act was enacted to regulate aspect of business conduct. Specifically, the objectives of the Act are to protect the rights of consumers and establish standards of conduct by those engaged in the production, sale and distribution of goods and services to consumers. For the purposes of the Act, "goods" include the supply of gas, electricity, water and telecommunications, and "services" include any “rights, benefits privileges and facilities that are, or are to be provided, granted or conferred under a contract for, or involving, the provision of gas, electricity, water or telecommunications”.

The Consumer Affairs Division is constituted under the Act to protect of the interests of consumers and see that manufacturers and traders offer goods that meet reasonable standards and are suited for the purpose for which they are intended.

The legislation seeks to protect the rights of consumers by:

• Prohibiting supply of goods that are below approved standard; • Prohibiting hoarding of goods;

59 For instance: Solomon Islands – Rebuilding an Island Economy, Economic Analytical Unit, Department of Foreign Affairs and Trade, Australian Government, 2004, p 90, and Private Sector Assessment for Solomon Islands, ADB, 2005, p48.

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• Enforcing prices of goods prescribed under the Price Control Act; • Requiring traders to display prices and issue receipts; • Prohibiting misleading or deceptive conduct; • Prohibiting exclusive dealing and discrimination in the pricing of goods of like grade and quality • Prohibiting the exploitation of monopoly power to eliminate or substantially to damage a competitor.

The Price Control Act was enacted to require persons who sell certain goods or services to clearly display prices, and to empower the Minister to restrict prices or charges. The Act also provides for the establishment of a Prices Advisory Committee (PAC) to keep prices under review and from time to time to consider what prices or charges should be restricted how the restriction should be framed.

The products and services to which price controls apply are listed in Schedule 1 of Subsidiary Legislation; they are listed under the following product categories: milk, meat, fish, sugar, flower, soap, rice, cooking oil, curry powder, biscuits, LPG, petroleum products, bread, electricity and water. Products within each category are referred to in the legislation by their specific brand names and the legislation has not been updated to amend the list to remove products no longer available or add equivalent products that have since entered the market and are now retailed free of price restraint. Price limits that apply to products are listed in Schedules 2 to 6 but these schedules are silent on electricity charges. The prices of other products may be dealt with if consumer complaints are received.

In practice, only petroleum products and LPG are systematically controlled. Of the liquid fuels, this control can extend only to petroleum motor spirit, distillate, kerosene and outboard motor fuel (as these are the only such products listed in the relevant schedule) and the legislation would need to be amended to bring bio-fuels within its ambit. Electricity, too, is price-controlled, but this derives from the operation of the Electricity Act rather than the Price Control Act. SIEA’s electricity charges are set by tariff regulations, while pricing for licensed electricity supplies may be fixed in the form of a licence condition. The Price Control Act could be activated to regulate electricity supplies that are exempted from the licensing provisions of the Electricity Act (refer §2 or §3 of the Electricity (Exemptions) Order, 1992).

The Price Control Act is outdated and the price controls unworkable in their current form, not least because the fines imposed are too low to be effective. The PAC has advised the Government that the Act should be updated and revised.

Companies Act (1961)

The role to be played by the private sector in the expansion of electricity access to rural areas is important and the companies and associations formed to facilitate the development and operation of rural electrification will be regulated by the Companies Act and other commercial and industrial legislation.

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The Companies Act establishes a framework for setting up, administering and winding up trading companies. The legislation dates from the sixties. The key provisions of the Act deal with the following:

• Incorporation of companies • Share capital and debentures • Charges and mortgages • Management and administration • Winding up • Receivers and managers • Off-shore companies

Labour Legislation

The workforce in the Solomon Islands is regulated under a number of laws, including the following:

• Employment Act (Chapter 72) • Labour Act (Chapter 73) • Safety at Work Act (Chapter 74) • Trade Disputes Act (Chapter 75) • Trade Unions Act (Chapter 76) • Unfair Dismissal Act (Chapter 77) • Worker’s Compensation Act (Chapter 78)

A number of restrictive regulatory and cultural factors limit labour market flexibility and constrain general economic development. Among the issues potentially retarding the performance of rural electrification companies and associations are:

• Shortage of trained, experienced and qualified workers, particularly those with electrical skills; • Legal and cultural barriers to redundancy and dismissal; • High labour overhead costs associated with contributions to the National Provident Fund, and payment of medical, transport, clothing and housing allowances.

Petroleum Act (1939)

The Petroleum Act regulates the storage and handling of petroleum. It sets forth rules for transporting and storing petroleum products and establishes a licensing regime to control the possession of petroleum.

The legislation was introduced in 1939 and is now sadly out of date. The existing Petroleum Act defines "petroleum" as being of mineral extraction, i.e. “any oil, liquid or spirit derived wholly or in part from any petroleum, shale, coal, peat, bitumen or similar substance, but does not include any oil ordinarily used for lubricating purposes or having a flash-point above two hundred degrees Fahrenheit”. The emerging bio-fuel industry promises to revolutionise the liquid fuels

31/25866 February 12 176 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES sector, a development of particular relevance to the electricity sector, but bio-fuels currently fall outside the ambit of the Act.

The Petroleum Act and other agricultural, industrial and energy legislation needs to be revised to broaden and adapt the legal framework to provide for the regulation of production, storage, transport and marketing of bio-fuels.

Town and Country Planning Act (1980)

The Town and Country Planning Act, together with the Environment Act, provide a legal framework for the regulation of national and provincial level planning, providing for the preparation of local planning schemes and the control and development of land.

The Act is administered through the Physical Planning Division of the Ministry of Lands, but physical functions under the Act devolve to Town and Country Planning Boards established within the Honiara Town Council and each Provincial Assembly. The Board is responsible for preparing Local Planning Schemes to facilitate orderly development of an area.

Permission of the Board is also required for any “development” that is carried out within any area of land governed by the Act. “Development”, for the purposes of the Act, is defined as “the carrying out of building, engineering, mining or other operations in, on, over or under land, or the making of any material change in the use of any buildings or other land”. Some exceptions are made, including “the use of any land for the purposes of agriculture, livestock keeping, fishing and forestry”.

The provisions of the Act overlap with those sections of the Environment Act dealing with the development of land. The Town and Country Planning Board is not obliged to consider environmental matters in preparing a Local Planning Scheme or considering development applications, although the requirements of the Environmental Act will prevail over those of the Town and Country Act.

In practice, the Town and Country Act is generally applied only in relation to urban matters and there is very little formal planning in rural areas. This is perhaps explained, at least in part, by the lack of authority of the Town and Country Planning Board over customary lands. As such, the Act may not apply to many rural electrification developments.

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Annex 3: Risk Analysis for Hydropower IPP in SI CONSEQUENSES OF RISK MANAGEMENT ACTION TYPE OF RISK EVENT RISK MANAGEMENT GOVERNMENT SIEA SPONSORS/INVESTORS LENDERS EPC CONTRACTOR

• Regulatory • Change-in-law and Extension of • Liability for losses due to • Possible adjustment to • Compensation for regulatory • Debt service capacity of • Possible adjustment to EPC Sovereign/ Changes Time clauses in concession regulatory changes electricity prices changes available under Project Co. protected by contract price agreement, PPA, EPC contract • Possible extension of • Possible delay in commercial contract contractual remedies • Possible extension of Time Political commercial operation date operation; extension of PPA • Possible delay in commercial and concession term term operation; extension of PPA term Risk • Government guarantee • Liability for claims under • No effect • Compensation for regulatory • Debt service capacity of • Capacity of Project Co. to guarantee changes available under Project Co. supported by meet EPC progress payments guarantee. guarantee supported by guarantee • Political risk insurance or MLA • Government liable for MLA • No effect • Costs of political risk • Debt service obligations • Capacity of Project Co. to (Also applicable for partial risk guarantee guarantee claims under insurance and MLA guarantee secured by insurance or meet EPC progress payments Operation Phase ) counter-guarantee • MLA guarantee conditional on guarantee. improved by proceeds of high project implementation insurance and guarantee standards • Expropriation, • Government guarantee • Government liable under • Cancellation of PPA and • If government defaults and • If government defaults and • If EPC contract terminated, Nationalization or guarantee for compensating possible delay to commercial Project Co. terminates, Project Co. terminates, debt guarantee support improves Cancellation of investor’s losses operation date due to compensation payable under service covered by prospects of recovering Concession ownership transition guarantee. guarantee. outstanding money. • Loan default if guarantee not honored.. • Political risk insurance or MLA • Government liable for MLA • Cancellation of PPA and • If government defaults and • If government defaults and • If EPC contract terminated, partial risk guarantees guarantee payments under possible delay to supply due Project Co. terminates, Project Co. terminates, debt insurance and guarantee counter-guarantee to ownership transition compensation payable under service covered by proceeds support improves prospects insurance. of insurance or guarantee of recovering outstanding money. • Default, termination and • Government contractually • Termination of PPA and • If government defaults and • If Project Co. terminates, • Compensation through back- disposal of assets clauses in liable for compensating possible delay to supply due Project Co. terminates, loans repaid from to-back provisions of EPC Project Agreements investor’s losses (e.g. buy- to ownership transition government contractually compensation contract and concession out) liable to compensate. agreement • Inadequate • Transparent, independent • Recognition of international • Recognition of international • Enforceability of awards • Debt service capacity of • Enforceability of awards Contract dispute resolution procedures arbitration for concession arbitration for PPA ensures effectiveness of Project Co. underpinned by ensures effectiveness of Enforcement agreement contractual remedies . enforceability of awards. contractual remedies . • Sound legal, regulatory & instit- • Framework development to • Sound framework encourage • Sound framework gives • Sound framework gives • Sound framework gives utional framework increase investor confidence lower prices and simpler greater predictability and greater predictability and greater predictability and contracts comfort about contract comfort about contract comfort about contract enforceability enforceability enforceability • Economic • Rise and fall and foreign • Foreign currency adjustments • If electricity price linked to • EPC price adjustment may • If EPC price increases, may • EPC contractor indemnified Problems exchange adjustment formulas may affect central bank and EPC cost, price may be result in increased capital mobilize stand-by loans from inflation and/or currency (e.g. high inflation, in EPC contracts macroeconomy. adjusted. cost, requiring stand-by movements (to extent defined currency • Higher EPC cost reduces finance in formulas) realignments) profitability of Project Co. • Increase in EPC price will hence less tax receipts. affect profitability of Project Co. • Ensure adequacy of • Framework deficiencies to be • Consequences of mismatch • Project Co. is exposed to • Lenders are exposed those • No effect. macroeconomic framework and remedied to reduce investor between electricity purchase those economic risks that economic risks that are not fundamentals risk and encourage lower commitments and demand cannot be transferred to transferred to others or prices others or mitigated. mitigated under the Security Package • Maximize local contribution in • No effect • No effect • Higher risk associated with • Higher risk associated with • Higher potential for revenues construction work local contractors and lenders local contractors and lenders

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Table 1 b: Pre-Operation Phases

CONSEQUENSES OF RISK MANAGEMENT ACTION TYPE OF RISK EVENT RISK MANAGEMENT GOVERNMENT SIEA SPONSORS/INVESTORS LENDERS EPC CONTRACTOR

Completion • Non-Political • Force Majeure clauses in • Government’s contractual • Delay in completion defers • Delay in completion defers • Interruption in debt service – • Delay in completion Risk Force Majeure concession, off-take and O&M obligations suspended for delivery of electricity revenue stream no recourse against Project • EPC contractor’s contractual (e.g. major flood, agreements period of force majeure event • SIEA’s PPA obligations • Project Co.’s contractual Co. obligations suspended for earthquake, fire) • Terminate if event is major suspended but no recourse obligations suspended but no period of force majeure event against Project Co. recourse against parties. • Terminate if event is major • Terminate if event is major • Terminate if event is major • Insure against insurable non- • No effect • No effect • Indemnity from insurable risks • Debt service capacity of • Indemnity from insurable political Force Majeure events • Higher costs associated with Project Co. protected by construction risks insurance premiums insurance indemnities • Contractor’s All Risk premiums • Unforeseen • Thorough site investigations • If government is responsible, • If SIEA is responsible, it • If investors are responsible, • Reliance on stand-by finance • Good quality site investig- Conditions and appropriate low risk project it must bear high front-end bears high front-end cost of they bear high front-end costs reduced with better site ations reduce EPC risk and design cost of investigations and investigations and studies but of investigations and studies information encourage lower EPC prices studies lower off-take prices but lower EPC contract price • Arrange stand-by finance, • No effect • No effect • Costs incurred for stand-by • Provide stand-by finance for • No effect emergency equity and/or finance and insurance possible increase in EPC insurance • Increased equity commitment costs • Transfer risk to EPC contractors • Indemnified against • Greater certainty in • Indemnified against • Indemnified against • Bears risk of losses due to through fixed price & fixed date unforeseen conditions commercial operation date unforeseen conditions unforeseen conditions unforeseen conditions contracts with liquidated and final off-take price • Pays a premium on EPC cost • Premium included in EPC damages price to cover risk of unforeseen conditions • Transfer risk to SIEA through • Indemnified against • Off-take price may change • Indemnified against • Increased importance of • Additional costs and lost time off-take price adjustment and unforeseen conditions • Commercial Operation Date unforeseen conditions stand-by finance to cover due to unforeseen conditions extension of time clauses in may be extended possible increases in EPC are “pass-throughs” PPA costs • Transfer risk to government • Government tax or royalty • Greater certainty in • Indemnified against • Increased importance of • Additional costs and lost time through adjustments in taxes or receipts reduced if unfore- commercial operation date unforeseen conditions stand-by finance to cover due to unforeseen conditions royalties for higher EPC costs seen conditions encountered and final off-take price possible increases in EPC are “pass-throughs” • Commercial operation date costs may be extended • Cost and Time • Contractual remedies: • Indemnified from late • Indemnified from late • Premium on EPC contract • Indemnified from late • Liable for liquidated damages Overrun on EPC completion by liquidated completion by liquidated price for fixed price and date completion by provisions in for late completion Contract - Fixed price/date EPC contract damages in concession damages in PPA. • Indemnified from late loan agreements Back-to-back liquidated agreement completion by liquidated damages in project contracts damages in EPC contract • Contingency finance measures: • No effect • No effect • Higher financing cost • Provide stand-by finance for • Capacity of Project Co. to - emergency equity • Increased equity commitment possible increase in capital meet increased project - stand-by finance costs financing requirements • Environmental and • Good quality EIA/SIA, Action • If government responsible for • If SIEA responsible for • If investors responsible for • Better understanding of • Greater certainty in Social Impacts, Plans and Management Plans reports, high front-end Studies, high front-end reports, high front-end environmental impacts/risks environmental scope landowner outlays. outlays. outlays. resistance • Better understanding of • Better understanding of • Better understanding of environmental impacts/risks environmental impacts/risks. environmental impacts/risks • Landowner compensation or • High upfront cost in case of • SIEA indemnified from • Reduced risk for majority • Need to finance landowner • No effect landowner shareholding landowner compensation landowner claims shareholder equity (by MLA) • Dividend for landowners • Environmental obligations and • Indemnified against • Higher electricity prices to • Enforceable environmental • Comfort in enforceability of • Enforceable environmental constraints specified in Project environmental claims cover environmental scope. obligations environmental obligations obligations Agreements • Additional costs for environ- • Higher EPC contract price to mental scope passed on in cover environmental scope form of higher power price • Performance of • Performance damages in • No effect • Reduced quantity or quality of • Reduced revenue stream if • Project Co.’s debt service • Rectification of plant non- Plant and Project Agreements project output. plant under-performs. capacity protected by EPC conformances Equipment • Indemnified by performance • Indemnified by performance performance indemnities • Liability for damages for plant clauses in PPA. clauses in EPC contract under-performance

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Table 2 a: Pre-Operation Phases

CONSEQUENSES OF RISK MANAGEMENT ACTION TYPE OF RISK EVENT RISK MANAGEMENT GOVERNMENT SIEA SPONSORS/INVESTORS LENDERS EPC CONTRACTOR

Commercial • Insolvency of • Default, termination and • Termination of concession • Termination of PPA • Disposal of assets (e.g. sale • Disposal of assets (e.g sale • Disposal of assets (e.g sale Risk Project Co. disposal of assets clauses in • Mechanisms for smooth • Mechanisms provide for or buy-out) provide for or buy-out) provide for or buy-out) provide for Project Agreements ownership transition, e.g. smooth ownership transition, recovery by investors recovery by lenders recovery by crediters through sale or buy-out e.g. through sale or buy-out • Lenders’ Step-in Rights • Government’s interests • Supply from project assured • Control of project transferred • Lenders may “step-in” to • Role of “Employer” in EPC served by lender intervention by lenders’ intervention to lenders or their nominees assume control of project contract transferred • Collateral Arrangements • Government may novate EPC • No effect • Project Co.’s subcontracts • Lenders may novate EPC • EPC contract novated to contract to nominee (e.g. EPC contract) novated to contract to nominee another party nominated by others Government or lenders

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Table 2 b: Risk Analysis and Assignment Matrix Operation Phase

14.1.1.1.1 CONSEQUENSES OF RISK MANAGEMENT ACTION TYPE OF RISK EVENT RISK MANAGEMENT GOVERNMENT SIEA SPONSORS/INVESTORS LENDERS O & M CONTRACTOR

• Regulatory Changes • Change-in-law and Extension of • Liability for losses due to • Possible adjustment to • Compensation for regulatory • Debt service capacity of • Possible adjustment to O&M Sovereign/ Time clauses in concession regulatory changes electricity prices changes available under Project Co. protected by contract prices agreement and PPA. • Possible extension of • Possible extension of PPA contract contractual remedies Political concession term term • Possible extension of PPA term • Government guarantee • Liability for claims under • No effect • Compensation for regulatory • Guarantee supports debt • Guarantee supports capacity Risk guarantee changes available under service capacity of Project of Project Co. to pay periodic guarantee. Co. O&M contract payments • Political risk insurance or MLA • Government liable for PRG • Insurance and PRG reduce • Costs of political risk insur- • Debt service obligations • No effect partial risk guarantee (PRG) pay-outs under terms of a reliance on “capacity-type” ance and PRG secured by insurance or (Also applicable for counter-guarantee tariff structure to secure debt • PRG conditional on project guarantee. Pre-Operation service.. Phase) implementation to MLA standards • Expropriation, • Government guarantee • Government liable under • Cancellation of PPA and • If government defaults and • If government defaults and • Likely termination of O&M Nationalization or guarantee for compensating possible disruption to supply Project Co. terminates, Project Co. terminates, debt Agreement Cancellation of investor’s losses during ownership transition compensation payable under service secured by • Must recover outstanding Concession guarantee. guarantee. money from Project Co. • Political risk insurance or MLA • Government liable for PRG • Insurance and PRG reduce • If government defaults and • If government defaults and • Likely termination of O&M partial risk guarantee (PRG). pay-outs under terms of reliance on “capacity-type” Project Co. terminates, Project Co. terminates, debt Agreement counter-guarantee tariff structure to secure debt compensation payable under service covered by proceeds • Must recover outstanding service. insurance. of insurance or PRG money from Project Co. • Default, termination and buy-out • Government contractually • Cancellation of PPA and • If government defaults and • If Project Co. terminates, • Likely termination of O&M provisions in Project liable for compensating possible disruption to supply Project Co. terminates, loans secured by Project Agreement Agreements investor’s losses during ownership transition government contractually Co.’s contractual remedies • If Project Co. terminates, liable to compensate. O&M payments secured by contractual remedies • Inadequate Contract • Transparent, independent • Recognition of international • Recognition of international • Enforceability of awards • Debt service capacity of • Enforceability of awards Enforcement dispute resolution procedures arbitration for concession arbitration for PPA ensures effectiveness of Project Co. underpinned by ensures effectiveness of agreement contractual remedies . enforceability of awards. contractual remedies . • Sound legal, regulatory & • Framework development to • Sound framework encourage • Sound framework gives • Sound framework gives • Sound framework gives institutional framework increase investor confidence lower prices and simpler greater predictability and greater predictability and greater predictability and contracts comfort about contract comfort about contract comfort about contract enforceability enforceability enforceability • Economic Problems • Rise and fall and foreign • May increase foreign • SIEA is exposed to the extent • PPA price adjustment • No effect – terms of debt • Project Co. is exposed to the (e.g. high inflation, exchange adjustment formulas currency requirements – that the adjustment formulas indemnifies Project Co. for service fixed extent that adjustment currency realignments) in PPA and O&M Agreement to effect on central bank and on transfer inflation and currency part or all of inflation and formulas transfer the risk cover inflation and currency macroeconomy. risks currency risks realignments. • Insurance instruments to protect • No effect. • No effect • Premiums and fees of • Debt service payments are • No effect. debt service capacity instruments Increase secured by instruments. financing cost • Ensure adequacy of macro- • Framework deficiencies to be • Unrealized electricity demand • Insure, transfer, mitigate • Maximize protection in economic framework and remedied to reduce investor projections would leave SIEA macroeconomic risks where Security Package and bear fundamentals risk and encourage lower committed under PPA to possible. remaining unprotected risks electricity prices unwanted power. • Bear unprotected risks

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Table 2 b: Operation Phase (cont)

CONSEQUENSES OF RISK MANAGEMENT ACTION TYPE OF RISK EVENT RISK MANAGEMENT GOVERNMENT SIEA SPONSORS/INVESTORS LENDERS O & M CONTRACTOR • Under-estimation of long • Quality hydrological analysis • If Government does studies: • If SIEA does studies: high • If Project Co. does studies: • Greater reliability of Project • No effect Hydrological term mean monthly and using reliable data and indepen- high front-end outlays front-end outlays high front-end outlays Co.’s debt service capacity annual flows dent self-checking • Less likelihood of Project Co. • Reliable estimates of capacity • Improved estimates of project and Water failing and energy revenues • Adjustment to concession terms • Reduction in taxes or royalties • No effect • Return on Equity underwritten • Government relief improves • No effect Management to compensate for long term • Extension of concession term by government Project Co. debt service hydrological variances capacity • Minimum payment to guarantee • Higher electricity prices may • “Capacity-type” payment • Debt service payments • Debt service payments • No effect Risk debt service involve political repercussions untied to energy sales secured by “capacity-type” secured by “capacity-type” payment payment • Variations in flow about • Optimize reservoir to ensure • No effect • Greater firm capacity and • Greater cashflow reliability • Greater debt service reliability • No effect the mean carry-over of water from surplus minimum energy • Avoidance of penalties to deficit periods • Minimum payment to guarantee • Higher electricity prices may • “Capacity-type” payment • Debt service payments • Debt service payments • No effect debt service involve political repercussions untied to energy sales secured by “capacity-type” secured by “capacity-type” payment payment • Adjustment to concession terms • Reduction in taxes or royalties • No effect • Annual revenues underwritten • Government support • No effect to compensate for annual by government improves Project Co. debt hydrological variances service capacity • Declining catchment • Contractual safeguards on • Enforcement of watershed • Capacity and energy from • Greater cashflow reliability • Greater debt service reliability • No effect yield catchment management and protection project sustained over • Improves likelihood of use • Economic opportunity cost of concession term achieving Return on Equity alternative catchment uses • Avoidance of penalties Operating • Non-political Force • Force Majeure clauses in • Government’s contractual • Interruption to supply • Interruption to supply excused • Interruption in debt service – • O&M contractor’s contractual Risk Majeure (major flood, concession, off-take and O&M obligations suspended for excused for duration of Force during Force Majeure event. no recourse against Project obligations suspended for earthquake, fire, etc.) agreements. period of Force Majeure event Majeure event. • Revenue stream interrupted Co. period of Force Majeure event • Terminate if event is major • Terminate if event is major. • Terminate if event is major. • Terminate if event is major. • Insure against insurable non- • No effect • No effect • Indemnity from insurable risks • Debt service capacity of • Indemnity from insurable risks political Force Majeure events • Higher costs associated with Project Co. secured by • Higher costs associated with insurance premiums insurance indemnities. insurance premiums. • Interruptions due to • Employ an experienced and • No effect • Greater reliability of supply • Greater reliability of project • Greater reliability of debt • Only reputable and effective O&M Contractor default reputable O&M operator from project revenues service O&M contractors considered • May pay more under the O&M for the role. Agreement • Liquidated damages remedies • No effect • Liquidated damages payable • Indemnified by back-to-back • Debt service capacity of • Damages for breach payable by Project Co. for interruption liquidated damages in Off- Project Co. secured by to Project Co. to supply Take and O&M agreements damages payable by O&M contractor to Project Co. • Lenders step-in–rights in • No effect • Temporary loss of supply • Lenders may bypass Project • Execute step-in-rights against • Role suspended, possible chronic cases from project Co. in remedying problem Project Co. termination of contract. with O&M contractor • Include design safeguards to • No effect • Greater reliability of supply • Higher capital cost of project • Debt service payments less • Fewer problems and outages reduce plant and transmission from project • Greater reliability in project susceptible to problems in • Lower O&M risks, hence. line outages operation and revenues project operation. lower O&M contract price.

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Table 2 b: Operation Phase (cont)

CONSEQUENSES OF RISK MANAGEMENT ACTION TYPE OF RISK EVENT RISK MANAGEMENT GOVERNMENT SIEA SPONSORS/INVESTORS LENDERS O & M CONTRACTOR • O&M agreement to specify high • No effect • Greater reliability of supply • Grater reliability of supply. • Debt service payments less • High standards demanded. maintenance standards and from project • Non-performance by O&M susceptible to problems in • Penalty/bonus performance clear penalties and bonuses. contractor is compensated. project operation. incentives provided. • Insure against O&M contractor • No effect • Likelihood of recovery of • Cost of insurance premiums. • Debt service capacity of • Debt service capacity of default O&M damages improved if • Indemnified from default by Project Co. secured by Project Co. secured by Project Co. insured. O&M contractor. insurance indemnities. insurance indemnities. Market • Ethnic tensions, • Tariff structure to secure debt • Higher electricity prices may • SIEA assumes market risk, • Reduced revenue but debt • Debt service payments • Power station dispatch Risk Reduced demand service revenues (e.g. “take-or- involve political repercussions creating obligation to pay for service revenues secured secured against market risks arrangements reflect tariff pay” or capacity-type charge) electricity not needed. against market risks structure • Conflict over dispatch • Minimum payment mechanism • Higher electricity prices may • Dispatch priorities not based • Revenues insulated against • Debt service payments • Power station dispatch (Take-or-Pay, capacity-type involve political repercussions on merit order dispatch economics and secured against dispatch arrangements reflect tariff charge) policy uncertainties structure • A well structured grid code to • No effect • Connection and dispatch • Connection and dispatch • No effect • Connection and dispatch control system operation and standards, policy and standards, policy and standards, policy and dispatch arrangements defined arrangements defined arrangements defined Commercial • Assurance of adequate • Structure project and financing • No effect • May involve tariff front-ending • SIEA may require Project Co. • Minimum debt service • No effect Risk debt service coverage plan to achieve acceptable Debt to boost debt service to guarantee the tail-end of coverage ratio must be met. Service Coverage Ratio coverage. any front-ended tariff. • Maintenance of debt service • No effect • No effect • Debt service reserve reduces • Provides for debt service for • No effect cash reserve net profit over the period it is given period (6 mths) if building up. project revenues interrupted • Insolvency of Project • Default, termination and • Termination of concession • Termination of PPA • Disposal of assets (e.g. sale • Disposal of assets (e.g sale or • Disposal of assets (e.g sale Co. disposal of assets clauses in • Mechanisms for smooth • Mechanisms for smooth or buy-out) provide for buy-out) provide for recovery or buy-out) provide for Project Agreements ownership transition, e.g. ownership transition, e.g. recovery by investors by lenders recovery by subcontractors through sale or buy-out through sale or buy-out • Lenders’ Step-in Rights • Government interests served • Of=Taker’s interests served • Control of project transferred • Lenders may “step-in” to • O&M Agreement terminated by lender intervention in by lender intervention in to lenders or their nominees assume control of project or transferred to another party maintaining project operation maintaining project operation • Collateral Arrangements • Government may novate • No effect • Project Co.’s subcontracts • Lenders may novate O&M • O&M Agreement novated to O&M Agreement to nominee (e.g. O&M Agreement) Agreement to nominee another party nominated by novated to others Government or lenders • Inability of SIEA to • Enhance creditworthiness of • Ensure conducive commercial • Structure and manage SIEA • Check credit-worthiness of • Check credit-worthiness of • No effect make payment SIEA. and regulatory environment. to earn credit rating. SIEA. SIEA. • Allow economic tariff-setting • Government guarantee of SIEA • Required to indemnify Project • Liable to compensate • Indemnified from SIEA non- • Government guarantee • No effect obligations (including payment). Co. against SIEA default government for payments payment by government secures Project Co. debt made under government guarantee. service capacity guarantee. • MLA partial risk guarantee • Government liable for any • PRG reduces reliance on • PRG reduces reliance on • PRG secures Project Co. debt • No effect (PRG) to secure debt service PRG payment under terms of “capacity-type” tariff structure “capacity-type” tariff structure service capacity payments counter-guarantee to secure debt service. to secure debt service. Foreign • Availability of foreign • Analysis of economic indicators • No effect. • No effect. • Bears the cost and risk of • Bears the cost and risk of • No effect. Exchange exchange for foreign including ability to generate for- economic analysis. economic analysis. debt service and eign exchange to match Rate Risk repatriation of profits payment obligations. • Government guarantee of • Project Co. indemnified by • SIEA liable to government for • Government guarantee • Government guarantee • No effect currency convertibility and government in event of SIEA compensation for payments secures PPA payment secures Project Co. debt foreign exchange availability. default of PPA payment made under government obligations, including currency service capacity provisions. guarantee. of payment. • MLA partial risk guarantee • Under terms of counter- • Ability to pay debt service • PRG secures debt service • PRG secures debt service • No effect (PRG) to secure debt service guarantee, government liable portion in foreign exchange payments. payments. payments. for any PRG payment according to terms of PPA Table 2 c: Operation and Transfer Phases

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CONSEQUENSES OF RISK MANAGEMENT ACTION TYPE OF RISK EVENT RISK MANAGEMENT GOVERNMENT SIEA SPONSORS/INVESTORS LENDERS O & M CONTRACTOR • Maximize local contribution in • No effect • Higher risk associated with • Higher risk associated with • No effect No effect construction work local contractors and lenders local contractors and lenders • Devaluation of the local • Match PPA payment currencies • Government to ensure • May involve acceptance of • Debt service objective • Matching PPA payment • No effect currency to financing package availability of foreign some exchange rate risk secured by matching revenue currencies to debt service exchange for PPA payments hedges foreign exchange risk • Hedging of debt service portion • No effect. • No effect. • Increased financing cost • Hedging secures debt service • No effect. of electricity payments with against currency re- financial instruments alignments. Environmental • Environmental impact • EIA, Environmental Monitoring • If Government does studies: • If SIEA does studies: high • If Project Co. does studies: • Lenders derive comfort from • Implement environmental and Social on river and Plan and Environmental high front-end outlays. front-end outlays. high front-end outlays. clear identification of impacts management (e.g. pattern of surrounding Management Plan to • Environmental management • Less controversy • Implementation of Env. and avoidance of controversy releases) and monitoring. Risks environment development agency standards and monitoring Management Plan • Re-regulation of power station • Reduced impacts in the river • Latitude in operating patterns • Greater operating flexibility • Less controversy • Latitude in operating patterns releases. downstream (peak/base/spinning reserve) giving higher revenues. (peak/base/spinning reserve) • Less controversy without increasing impacts. • Higher capital cost without increasing impacts. • Less controversy • Less controversy • Less controversy • Reservoir clearing • Improved water quality • Less controversy • Improved water quality. • Less controversy • Less controversy • Less controversy • Higher capital cost • Less controversy • Variable level intake structures • Improved water quality • Less controversy • Improved water quality. • Need to finance landowner • Draw-off level must be for improved water quality • Less controversy • Higher capital cost equity monitored • Less controversy • Less controversy • Social impacts • Compensation to development • Management of • No effect • Higher capital cost • Less controversy • No effect agency standards compensation process. • Local support for project. • Landowner shareholding • Regional development initiatives • Management of regional • No effect • Higher capital cost • Less controversy • No effect in vicinity of project development initiatives. • Local support for project. • Negative media and • Implementation of project to • Management of • Operating constraints to meet • Higher capital cost • Less controversy • Operating constraints NGO coverage development agency standards environmental and social social and environmental • Operating constraints • Wider support for project. .programs objectives • Wider support for project. Transmission • Lightning strikes • Protection design • No effect • Minimizes interruptions to • Higher capital cost • Minimizes impact on debt • Minimizes interruptions Line Security supply • Minimizes loss of revenue service capacity • Liquidated damages for • No effect • Compensated for inter- • Liable for liquidated damages. • Back-to-back recovery from • Liable for liquidated damages interruptions ruptions to supply • Back-to-back recovery from O&M Contractor secures for interruptions to supply O&M Contractor Project Co.’s debt service capacity • Operation and • A well structured grid code to • No effect • Connection and dispatch • Connection and dispatch • No effect • Connection and dispatch Maintenance of Line control system interconnection, standards, policy and standards, policy and standards, policy and operation and dispatch arrangements defined arrangements defined arrangements defined

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Annex 4 Financial Analysis Profit and Loss Auki

Auki Profit & Loss (SBD million) 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Operating Revenues $ 7.934 $ 10.261 $ 14.087 $ 14.711 $ 15.366 $ 16.053 $ 16.774 $ 17.531 $ 18.326 $ 19.160 $ 20.035 $ 20.955 $ 21.922 $ 22.937 $ 24.004 $ 25.125 $ 26.304 $ 27.544 $ 28.848 $ 30.220 $ 31.664 Hydro Scenario Historical Projected ------> 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Generation Mix (kWh) Diesel 1,576,459 1,932,278 2,009,569 2,749,808 2,859,800 ------CNO ------Hydro - - - - - 2,974,192 3,093,160 3,216,886 3,345,562 3,479,384 3,618,560 3,763,302 3,913,834 4,070,388 4,233,203 4,402,531 4,578,632 4,761,778 4,952,249 5,150,339 5,356,352 5,570,606 Total 1,576,459 1,932,278 2,009,569 2,749,808 2,859,800 2,974,192 3,093,160 3,216,886 3,345,562 3,479,384 3,618,560 3,763,302 3,913,834 4,070,388 4,233,203 4,402,531 4,578,632 4,761,778 4,952,249 5,150,339 5,356,352 5,570,606

Generation Mix (%) Diesel 100% 100% 100% 100% 100% 100% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% CNO 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Hydro 0% 0% 0% 0% 0% 0% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Total 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Load Factor 0.60 0.61 0.61 0.62 0.62 0.63 0.63 0.64 0.64 0.65 0.65 0.66 0.66 0.67 0.67 0.68 0.68 0.69 0.69 0.70 0.70 Peak Load (kW) 367.6 379.2 514.6 530.8 547.6 565.0 582.9 601.4 620.6 640.4 660.9 682.1 704.0 726.7 750.1 774.3 799.4 825.3 852.1 879.8 908.4 Operating Expenditures Auki Share of HQ Expenses $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 Fuel Diesel (litres) 579,683 602,871 824,942 857,940 ------Delivered Diesel Price (SBD/litre) $ 7.26 $ 7.48 $ 7.70 $ 7.93 $ 8.17 $ 8.42 $ 8.67 $ 8.93 $ 9.20 $ 9.47 $ 9.76 $ 10.05 $ 10.35 $ 10.66 $ 10.98 $ 11.31 $ 11.65 $ 12.00 $ 12.36 $ 12.73 $ 13.11 Diesel Fuel Cost (SBD million) $ 4.21 $ 4.51 $ 6.35 $ 6.81 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - CNO (litres) ------Delivered CNO Price (SBD/litre) $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - CNO Fuel Cost (SBD million) $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - Total Fuel Cost (SBD million) $ 4.21 $ 4.51 $ 6.35 $ 6.81 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - Non Fuel Generation O&M $ 2.22 $ 2.31 $ 3.16 $ 3.29 $ 0.24 $ 0.25 $ 0.26 $ 0.27 $ 0.28 $ 0.29 $ 0.30 $ 0.31 $ 0.33 $ 0.34 $ 0.35 $ 0.37 $ 0.38 $ 0.40 $ 0.41 $ 0.43 $ 0.45 Distribution O&M $ 0.00 $ 0.00 $ 0.00 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 $ 0.06 Administration and Payroll $ 0.19 $ 0.20 $ 0.20 $ 0.20 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26

Total Operating Expenditure Before Depreciation and Bad Debts $ 6.67 $ 7.11 $ 9.87 $ 10.44 $ 0.59 $ 0.60 $ 0.61 $ 0.62 $ 0.63 $ 0.64 $ 0.65 $ 0.66 $ 0.67 $ 0.69 $ 0.70 $ 0.72 $ 0.73 $ 0.75 $ 0.76 $ 0.78 $ 0.79 Depreciation $ - $ 0.33 $ 0.33 $ 0.33 $ 1.27 $ 1.38 $ 1.38 $ 1.38 $ 1.38 $ 1.38 $ 1.49 $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.72 $ 1.72 $ 1.72 $ 1.72 $ 1.83 Provision for Bad Debts $ 2.38 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - Total Operating Expenses $ 9.05 $ 7.44 $ 10.20 $ 10.78 $ 1.85 $ 1.98 $ 1.99 $ 2.00 $ 2.01 $ 2.02 $ 2.14 $ 2.27 $ 2.28 $ 2.29 $ 2.31 $ 2.32 $ 2.45 $ 2.46 $ 2.48 $ 2.49 $ 2.62

Operating profit/(loss) $ (1.11) $ 2.82 $ 3.89 $ 3.94 $ 13.51 $ 14.08 $ 14.79 $ 15.53 $ 16.32 $ 17.14 $ 17.89 $ 18.69 $ 19.64 $ 20.64 $ 21.70 $ 22.81 $ 23.86 $ 25.08 $ 26.37 $ 27.73 $ 29.04

Net finance charges Interest on Long-Term Loans ------(0.29) (0.28) (0.27) (0.26) (0.25) (0.23) (0.22) (0.21) (0.19) (0.18) (0.17) (0.15) Principal Repayments ------(0.42) (0.43) (0.44) (0.45) (0.47) (0.48) (0.49) (0.50) (0.52) (0.53) (0.55) (0.56) Total Debt Service ------(0.71) (0.71) (0.71) (0.71) (0.71) (0.71) (0.71) (0.71) (0.71) (0.71) (0.71) (0.71)

Taxable Income $ (1.11) $ 2.82 $ 3.89 $ 3.94 $ 13.51 $ 14.08 $ 14.79 $ 15.53 $ 16.32 $ 16.85 $ 17.61 $ 18.42 $ 19.38 $ 20.40 $ 21.47 $ 22.59 $ 23.65 $ 24.89 $ 26.19 $ 27.56 $ 28.89

Taxation $ - $ 0.71 $ 0.97 $ 0.98 $ 3.38 $ 3.52 $ 3.70 $ 3.88 $ 4.08 $ 4.21 $ 4.40 $ 4.60 $ 4.85 $ 5.10 $ 5.37 $ 5.65 $ 5.91 $ 6.22 $ 6.55 $ 6.89 $ 7.22

Profit/(loss) after taxation $ (1.11) $ 2.12 $ 2.92 $ 2.95 $ 10.13 $ 10.56 $ 11.09 $ 11.65 $ 12.24 $ 12.64 $ 13.21 $ 13.81 $ 14.54 $ 15.30 $ 16.10 $ 16.94 $ 17.74 $ 18.67 $ 19.64 $ 20.67 $ 21.67 Operating profit/(loss) per kWh billed (SBD) $ (0.63) $ 1.14 $ 1.15 $ 1.12 $ 3.70 $ 3.71 $ 3.75 $ 3.79 $ 3.82 $ 3.80 $ 3.82 $ 3.84 $ 3.88 $ 3.93 $ 3.97 $ 4.02 $ 4.05 $ 4.10 $ 4.15 $ 4.19 $ 4.23

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Lata

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Revenues $ 0.976 $ 1.259 $ 2.808 $ 2.930 $ 3.058 $ 3.192 $ 3.332 $ 3.480 $ 3.635 $ 3.798 $ 3.968 $ 4.148 $ 4.336 $ 4.535 $ 4.743 $ 4.962 $ 5.192 $ 5.434 $ 5.688 $ 5.956 $ 6.237 Hydro Scenario Historical Projected ------> 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Generation Mix (kWh) Diesel 246,346 318,885 331,640 537,471 558,969 9,777 14,694 19,980 25,668 31,794 38,401 45,532 53,240 61,581 70,619 80,428 103,924 139,721 176,950 215,668 255,935 297,813 Hydro - - - - - 571,551 589,888 608,785 628,247 648,277 668,874 690,033 711,748 734,007 756,792 780,080 791,004 791,004 791,004 791,004 791,004 791,004 Total 246,346 318,885 331,640 537,471 558,969 581,328 604,581 628,765 653,915 680,072 707,275 735,566 764,988 795,588 827,411 860,508 894,928 930,725 967,954 1,006,672 1,046,939 1,088,817

Generation Mix (%) Diesel 100% 100% 100% 100% 100% 100% 2% 2% 3% 4% 5% 5% 6% 7% 8% 9% 9% 12% 15% 18% 21% 24% 27% Hydro 0% 0% 0% 0% 0% 0% 98% 98% 97% 96% 95% 95% 94% 93% 92% 91% 91% 88% 85% 82% 79% 76% 73% Total 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Load Factor 0.70 0.69 0.67 0.66 0.64 0.63 0.61 0.60 0.58 0.57 0.55 0.54 0.52 0.51 0.49 0.48 0.46 0.45 0.43 0.42 0.40 Peak Load (kW) 52.0 55.3 91.6 97.4 103.7 110.4 117.7 125.5 133.9 142.9 152.7 163.2 174.7 187.0 200.5 215.1 231.0 248.3 267.2 288.0 310.7 Operating Expenditures Lata Share of HQ Expenses $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 Fuel Diesel (litres) 127,554 132,656 177,365 184,460 3,226 4,849 6,593 8,470 10,492 12,672 15,026 17,569 20,322 23,304 26,541 34,295 46,108 58,393 71,170 84,459 98,278 Delivered Diesel Price (SBD/litre) $ 7.98 $ 8.22 $ 8.47 $ 8.72 $ 8.98 $ 9.25 $ 9.53 $ 9.81 $ 10.11 $ 10.41 $ 10.72 $ 11.05 $ 11.38 $ 11.72 $ 12.07 $ 12.43 $ 12.81 $ 13.19 $ 13.59 $ 13.99 $ 14.41 Diesel Fuel Cost (SBD million) $ 1.02 $ 1.09 $ 1.50 $ 1.61 $ 0.03 $ 0.04 $ 0.06 $ 0.08 $ 0.11 $ 0.13 $ 0.16 $ 0.19 $ 0.23 $ 0.27 $ 0.32 $ 0.43 $ 0.59 $ 0.77 $ 0.97 $ 1.18 $ 1.42

Non Fuel Generation O&M $ 0.37 $ 0.38 $ 0.62 $ 0.64 $ 0.06 $ 0.06 $ 0.07 $ 0.08 $ 0.09 $ 0.10 $ 0.11 $ 0.12 $ 0.13 $ 0.14 $ 0.15 $ 0.18 $ 0.22 $ 0.27 $ 0.31 $ 0.36 $ 0.41

Distribution O&M $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 $ 0.24 Administration and Payroll $ 0.19 $ 0.20 $ 0.20 $ 0.20 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 Total Operating Expenditure Before Depreciation and Bad Debts $ 1.62 $ 1.71 $ 2.65 $ 2.78 $ 0.62 $ 0.64 $ 0.67 $ 0.70 $ 0.73 $ 0.76 $ 0.80 $ 0.85 $ 0.89 $ 0.95 $ 1.01 $ 1.14 $ 1.35 $ 1.57 $ 1.81 $ 2.07 $ 2.36

Depreciation $ - $ 0.06 $ 0.49 $ 0.49 $ 0.97 $ 0.97 $ 0.97 $ 0.97 $ 0.97 $ 0.97 $ 0.97 $ 1.06 $ 1.06 $ 1.06 $ 1.09 $ 1.09 $ 1.09 $ 1.09 $ 1.09 $ 1.09 $ 1.09 Provision for Bad Debts $ 0.29 $ 0.38 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -

Total Operating Expenses $ 1.91 $ 2.14 $ 3.14 $ 3.27 $ 1.59 $ 1.61 $ 1.64 $ 1.67 $ 1.70 $ 1.73 $ 1.77 $ 1.91 $ 1.95 $ 2.01 $ 2.10 $ 2.23 $ 2.44 $ 2.66 $ 2.90 $ 3.16 $ 3.44

Operating profit/(loss) $ (0.94) $ (0.89) $ (0.33) $ (0.34) $ 1.47 $ 1.58 $ 1.69 $ 1.81 $ 1.94 $ 2.06 $ 2.19 $ 2.24 $ 2.38 $ 2.53 $ 2.65 $ 2.73 $ 2.75 $ 2.77 $ 2.79 $ 2.79 $ 2.79

Net finance charges Interest on Long-Term Loans ------0.15 0.15 0.14 0.13 0.13 0.12 0.11 0.11 0.10 0.09 0.09 0.08 Principal Repayments ------0.22 0.22 0.23 0.24 0.24 0.25 0.25 0.26 0.27 0.28 0.28 0.29 Total Debt Service ------0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37

Taxable Income $ (0.94) $ (0.89) $ (0.33) $ (0.34) $ 1.47 $ 1.58 $ 1.69 $ 1.81 $ 1.94 $ 1.91 $ 2.05 $ 2.10 $ 2.25 $ 2.40 $ 2.52 $ 2.62 $ 2.65 $ 2.67 $ 2.69 $ 2.71 $ 2.71

Taxation $ - $ - $ - $ - $ 0.37 $ 0.39 $ 0.42 $ 0.45 $ 0.48 $ 0.48 $ 0.51 $ 0.53 $ 0.56 $ 0.60 $ 0.63 $ 0.65 $ 0.66 $ 0.67 $ 0.67 $ 0.68 $ 0.68

Profit/(loss) after taxation $ (0.94) $ (0.89) $ (0.33) $ (0.34) $ 1.10 $ 1.18 $ 1.27 $ 1.36 $ 1.45 $ 1.43 $ 1.54 $ 1.58 $ 1.69 $ 1.80 $ 1.89 $ 1.96 $ 1.99 $ 2.01 $ 2.02 $ 2.03 $ 2.04

Operating profit/(loss) per kWh billed (SBD) $ (4.29) $ (3.90) $ (0.67) $ (0.66) $ 2.06 $ 2.13 $ 2.19 $ 2.26 $ 2.32 $ 2.20 $ 2.27 $ 2.24 $ 2.30 $ 2.36 $ 2.39 $ 2.38 $ 2.32 $ 2.25 $ 2.18 $ 2.11 $ 2.03

31/25866 February 12 186 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Mataniko, With Tina

Honiara Profit & Loss (SBD million)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Operating Revenues $ 321.59 $ 422.02 $ 445.23 $ 469.78 $ 495.75 $ 523.23 $ 552.31 $ 583.09 $ 615.68 $ 650.19 $ 686.74 $ 725.45 $ 766.46 $ 809.92 $ 855.98 $ 904.81 $ 956.58 $ 1,011.48 $ 1,069.72 $ 1,131.50 $ 1,197.05 Mataniko Hydro Scenario Historical Projected ------> 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Generation Mix (MWh) Diesel 79,654 83,606 87,753 92,107 83,975 32,771 37,180 41,839 46,760 - - - - - 4,421 11,051 18,066 25,487 33,334 41,626 50,388 Tina River Hydro - - - - - 56,000 56,625 57,250 57,875 110,456 116,566 122,979 129,710 136,775 139,769 140,923 142,077 143,231 144,385 145,538 146,692 Mataniko Hydro - - - - 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 Total 79,654 83,606 87,753 92,107 96,676 101,472 106,506 111,790 117,336 123,157 129,267 135,680 142,411 149,476 156,891 164,675 172,844 181,419 190,419 199,866 209,781 Generation Mix (%) Diesel 100.0% 100.0% 100.0% 100.0% 86.9% 32.3% 34.9% 37.4% 39.9% 0.0% 0.0% 0.0% 0.0% 0.0% 2.8% 6.7% 10.5% 14.0% 17.5% 20.8% 24.0% Tina River Hydro 0.0% 0.0% 0.0% 0.0% 0.0% 55.2% 53.2% 51.2% 49.3% 89.7% 90.2% 90.6% 91.1% 91.5% 89.1% 85.6% 82.2% 79.0% 75.8% 72.8% 69.9% Mataniko Hydro 0.0% 0.0% 0.0% 0.0% 13.1% 12.5% 11.9% 11.4% 10.8% 10.3% 9.8% 9.4% 8.9% 8.5% 8.1% 7.7% 7.3% 7.0% 6.7% 6.4% 6.1% Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Load Factor 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 Peak Load (MW) 13.0 13.6 14.3 15.0 15.8 16.5 17.4 18.2 19.1 20.1 21.1 22.1 23.2 24.4 25.6 26.9 28.2 29.6 31.1 32.6 34.2 Operating Expenditures Honiara Share of HQ Expenses $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 Fuel Diesel (10^3 litres) 22,758 23,887 25,072 26,316 23,993 9,363 10,623 11,954 13,360 - - - - - 1,263 3,157 5,162 7,282 9,524 11,893 14,397 Delivered Diesel Price (SBD/litre) $ 6.83 $ 7.03 $ 7.25 $ 7.46 $ 7.69 $ 7.92 $ 8.16 $ 8.40 $ 8.65 $ 8.91 $ 9.18 $ 9.45 $ 9.74 $ 10.03 $ 10.33 $ 10.64 $ 10.96 $ 11.29 $ 11.63 $ 11.98 $ 12.34 Diesel Fuel Cost (SBD million) $ 155.44 $ 168.04 $ 181.67 $ 196.41 $ 184.44 $ 74.14 $ 86.63 $ 100.41 $ 115.59 $ - $ - $ - $ - $ - $ 13.05 $ 33.60 $ 56.57 $ 82.21 $ 110.74 $ 142.44 $ 177.59

Non Fuel Generation O&M $ 91.60 $ 96.15 $ 100.92 $ 105.92 $ 97.59 $ 43.18 $ 48.30 $ 53.71 $ 59.42 $ 11.54 $ 11.68 $ 11.82 $ 11.96 $ 12.11 $ 17.28 $ 25.00 $ 33.16 $ 41.78 $ 50.90 $ 60.53 $ 70.70

Distribution O&M $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - Administration and Payroll $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 Total Operating Expenditure Before Depreciation and Bad Debts $ 257.25 $ 274.40 $ 292.85 $ 312.59 $ 292.29 $ 127.58 $ 145.20 $ 164.39 $ 185.27 $ 21.80 $ 21.94 $ 22.08 $ 22.23 $ 22.37 $ 40.59 $ 68.86 $ 99.99 $ 134.25 $ 171.90 $ 213.23 $ 258.55

Depreciation $ - $ - $ - $ - $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 Provision for Bad Debts $ 32.16 $ 42.20 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -

Total Operating Expenses $ 289.41 $ 316.60 $ 292.85 $ 312.59 $ 293.89 $ 129.18 $ 146.80 $ 165.99 $ 186.87 $ 23.40 $ 23.54 $ 34.27 $ 34.41 $ 34.55 $ 52.78 $ 81.04 $ 112.18 $ 146.44 $ 184.09 $ 225.42 $ 270.74

Operating profit/(loss) $ 32.19 $ 105.42 $ 152.38 $ 157.19 $ 201.86 $ 394.05 $ 405.51 $ 417.11 $ 428.81 $ 626.79 $ 663.19 $ 691.18 $ 732.05 $ 775.37 $ 803.20 $ 823.77 $ 844.40 $ 865.04 $ 885.63 $ 906.08 $ 926.32

Net finance charges Interest on Long-Term Loans ------0.50 0.48 0.46 0.44 0.42 0.40 0.38 0.35 0.33 0.31 0.28 0.26 Principal Repayments ------0.72 0.74 0.76 0.78 0.80 0.82 0.84 0.86 0.89 0.91 0.93 0.96 Total Debt Service ------1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22

Taxable Income $ 32.19 $ 105.42 $ 152.38 $ 157.19 $ 201.86 $ 394.05 $ 405.51 $ 417.11 $ 428.81 $ 626.29 $ 662.71 $ 690.72 $ 731.61 $ 774.95 $ 802.80 $ 823.39 $ 844.05 $ 864.71 $ 885.32 $ 905.80 $ 926.06

Taxation $ 8.05 $ 26.36 $ 38.09 $ 39.30 $ 50.46 $ 98.51 $ 101.38 $ 104.28 $ 107.20 $ 156.57 $ 165.68 $ 172.68 $ 182.90 $ 193.74 $ 200.70 $ 205.85 $ 211.01 $ 216.18 $ 221.33 $ 226.45 $ 231.51

Profit/(loss) after taxation $ 24.14 $ 79.07 $ 114.28 $ 117.89 $ 151.39 $ 295.53 $ 304.13 $ 312.83 $ 321.61 $ 469.72 $ 497.04 $ 518.04 $ 548.71 $ 581.21 $ 602.10 $ 617.54 $ 633.03 $ 648.53 $ 663.99 $ 679.35 $ 694.54 Operating profit/(loss) per kWh billed (SBD) $ 0.33 $ 1.03 $ 1.42 $ 1.39 $ 1.70 $ 3.17 $ 3.10 $ 3.04 $ 2.98 $ 4.15 $ 4.18 $ 4.15 $ 4.19 $ 4.23 $ 4.17 $ 4.08 $ 3.98 $ 3.89 $ 3.79 $ 3.69 $ 3.60

31/25866 February 12 187 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Mataniko, Without Tina

Honiara Profit & Loss (SBD million)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Operating Revenues $ 321.59 $ 422.02 $ 445.23 $ 469.78 $ 495.75 $ 523.23 $ 552.31 $ 583.09 $ 615.68 $ 650.19 $ 686.74 $ 725.45 $ 766.46 $ 809.92 $ 855.98 $ 904.81 $ 956.58 $ 1,011.48 $ 1,069.72 $ 1,131.50 $ 1,197.05 Mataniko Hydro Scenario Historical Projected ------> 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Generation Mix (MWh) Diesel 79,654 83,606 87,753 92,107 83,975 88,771 93,805 99,089 104,635 110,456 116,566 122,979 129,710 136,775 144,190 151,974 160,143 168,718 177,718 187,165 197,080 Tina River Hydro ------Mataniko Hydro - - - - 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 12,701 Total 79,654 83,606 87,753 92,107 96,676 101,472 106,506 111,790 117,336 123,157 129,267 135,680 142,411 149,476 156,891 164,675 172,844 181,419 190,419 199,866 209,781 Generation Mix (%) Diesel 100.0% 100.0% 100.0% 100.0% 86.9% 87.5% 88.1% 88.6% 89.2% 89.7% 90.2% 90.6% 91.1% 91.5% 91.9% 92.3% 92.7% 93.0% 93.3% 93.6% 93.9% Tina River Hydro 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Mataniko Hydro 0.0% 0.0% 0.0% 0.0% 13.1% 12.5% 11.9% 11.4% 10.8% 10.3% 9.8% 9.4% 8.9% 8.5% 8.1% 7.7% 7.3% 7.0% 6.7% 6.4% 6.1% Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Load Factor 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 Peak Load (MW) 13.0 13.6 14.3 15.0 15.8 16.5 17.4 18.2 19.1 20.1 21.1 22.1 23.2 24.4 25.6 26.9 28.2 29.6 31.1 32.6 34.2 Operating Expenditures Honiara Share of HQ Expenses $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 $ 9.60 Fuel Diesel (10^3 litres) 22,758 23,887 25,072 26,316 23,993 25,363 26,802 28,311 29,896 31,559 33,305 35,137 37,060 39,079 41,197 43,421 45,755 48,205 50,777 53,476 56,309 Delivered Diesel Price (SBD/litre) $ 6.83 $ 7.03 $ 7.25 $ 7.46 $ 7.69 $ 7.92 $ 8.16 $ 8.40 $ 8.65 $ 8.91 $ 9.18 $ 9.45 $ 9.74 $ 10.03 $ 10.33 $ 10.64 $ 10.96 $ 11.29 $ 11.63 $ 11.98 $ 12.34 Diesel Fuel Cost (SBD million) $ 155.44 $ 168.04 $ 181.67 $ 196.41 $ 184.44 $ 200.82 $ 218.58 $ 237.81 $ 258.66 $ 281.24 $ 305.70 $ 332.19 $ 360.89 $ 391.96 $ 425.61 $ 462.04 $ 501.48 $ 544.19 $ 590.41 $ 640.45 $ 694.61

Non Fuel Generation O&M $ 91.60 $ 96.15 $ 100.92 $ 105.92 $ 97.59 $ 103.10 $ 108.89 $ 114.97 $ 121.35 $ 128.04 $ 135.07 $ 142.44 $ 150.18 $ 158.31 $ 166.83 $ 175.79 $ 185.18 $ 195.04 $ 205.39 $ 216.26 $ 227.66

Distribution O&M $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - Administration and Payroll $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 $ 0.66 Total Operating Expenditure Before Depreciation and Bad Debts $ 257.25 $ 274.40 $ 292.85 $ 312.59 $ 292.29 $ 314.19 $ 337.73 $ 363.05 $ 390.27 $ 419.54 $ 451.03 $ 484.90 $ 521.33 $ 560.53 $ 602.71 $ 648.09 $ 696.93 $ 749.49 $ 806.07 $ 866.97 $ 932.53

Depreciation $ - $ - $ - $ - $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 $ 12.19 Provision for Bad Debts $ 32.16 $ 42.20 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -

Total Operating Expenses $ 289.41 $ 316.60 $ 292.85 $ 312.59 $ 293.89 $ 315.79 $ 339.33 $ 364.65 $ 391.87 $ 421.14 $ 452.63 $ 497.08 $ 533.52 $ 572.72 $ 614.89 $ 660.27 $ 709.11 $ 761.67 $ 818.25 $ 879.15 $ 944.71

Operating profit/(loss) $ 32.19 $ 105.42 $ 152.38 $ 157.19 $ 201.86 $ 207.44 $ 212.98 $ 218.45 $ 223.81 $ 229.05 $ 234.11 $ 228.36 $ 232.94 $ 237.20 $ 241.09 $ 244.54 $ 247.47 $ 249.81 $ 251.47 $ 252.34 $ 252.34

Net finance charges Interest on Long-Term Loans ------0.50 0.48 0.46 0.44 0.42 0.40 0.38 0.35 0.33 0.31 0.28 0.26 Principal Repayments ------0.72 0.74 0.76 0.78 0.80 0.82 0.84 0.86 0.89 0.91 0.93 0.96 Total Debt Service ------1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22 1.22

Taxable Income $ 32.19 $ 105.42 $ 152.38 $ 157.19 $ 201.86 $ 207.44 $ 212.98 $ 218.45 $ 223.81 $ 228.55 $ 233.63 $ 227.90 $ 232.50 $ 236.78 $ 240.69 $ 244.16 $ 247.11 $ 249.48 $ 251.16 $ 252.06 $ 252.08

Taxation $ 8.05 $ 26.36 $ 38.09 $ 39.30 $ 50.46 $ 51.86 $ 53.24 $ 54.61 $ 55.95 $ 57.14 $ 58.41 $ 56.98 $ 58.13 $ 59.20 $ 60.17 $ 61.04 $ 61.78 $ 62.37 $ 62.79 $ 63.02 $ 63.02

Profit/(loss) after taxation $ 24.14 $ 79.07 $ 114.28 $ 117.89 $ 151.39 $ 155.58 $ 159.73 $ 163.84 $ 167.86 $ 171.41 $ 175.22 $ 170.93 $ 174.38 $ 177.59 $ 180.52 $ 183.12 $ 185.34 $ 187.11 $ 188.37 $ 189.05 $ 189.06 Operating profit/(loss) per kWh billed (SBD) $ 0.33 $ 1.03 $ 1.42 $ 1.39 $ 1.70 $ 1.67 $ 1.63 $ 1.59 $ 1.56 $ 1.51 $ 1.47 $ 1.37 $ 1.33 $ 1.29 $ 1.25 $ 1.21 $ 1.17 $ 1.12 $ 1.08 $ 1.03 $ 0.98

31/25866 February 12 188 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Ringgi (Variant A)

Ringgi Profit & Loss (SBD million)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Revenues $ 15.807 $ 20.362 $ 21.297 $ 22.279 $ 23.275 $ 24.319 $ 25.415 $ 26.565 $ 27.772 $ 29.040 $ 30.371 $ 31.769 $ 33.237 $ 34.780 $ 36.402 $ 38.106 $ 39.898 $ 41.782 $ 43.764 $ 45.849 $ 48.043 Hydro Scenario Historical Projected ------> 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Generation Mix (kWh) Diesel 3,846,678 4,006,957 4,173,913 ------Hydro - - - 4,347,826 4,521,739 4,702,609 4,890,713 5,086,342 5,289,795 5,501,387 5,721,443 5,950,300 6,188,312 6,435,845 6,693,279 6,961,010 7,239,450 7,529,028 7,830,189 8,143,397 8,469,133 Total 3,846,678 4,006,957 4,173,913 4,347,826 4,521,739 4,702,609 4,890,713 5,086,342 5,289,795 5,501,387 5,721,443 5,950,300 6,188,312 6,435,845 6,693,279 6,961,010 7,239,450 7,529,028 7,830,189 8,143,397 8,469,133

Generation Mix (%) Diesel 100% 100% 100% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Hydro 0% 0% 0% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Total 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Load Factor 0.61 0.63 0.64 0.65 0.67 0.68 0.69 0.71 0.72 0.73 0.75 0.76 0.78 0.79 0.81 0.82 0.84 0.86 0.87 0.89 0.91 Peak Load (kW) 658.8 672.3 686.0 700.0 714.0 728.3 742.8 757.7 772.9 788.3 804.1 820.2 836.6 853.3 870.4 887.8 905.5 923.6 942.1 960.9 980.2 Operating Expenditures

Fuel Diesel (litres) 1,099,051 1,144,845 1,192,547 ------Delivered Diesel Price (SBD/litre) $ 7.13 $ 7.34 $ 7.56 $ 7.79 $ 8.02 $ 8.27 $ 8.51 $ 8.77 $ 9.03 $ 9.30 $ 9.58 $ 9.87 $ 10.17 $ 10.47 $ 10.78 $ 11.11 $ 11.44 $ 11.78 $ 12.14 $ 12.50 $ 12.88 Diesel Fuel Cost (SBD million) $ 7.84 $ 8.41 $ 9.02 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -

Non Fuel Generation O&M $ 4.42 $ 4.61 $ 4.80 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.34

Distribution O&M $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - Administration and Payroll $ 0.19 $ 0.20 $ 0.20 $ 0.20 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 Total Operating Expenditure Before Depreciation and Bad Debts $ 12.46 $ 13.22 $ 14.08 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.60

Depreciation $ - $ 0.29 $ 0.29 $ 1.22 $ 1.22 $ 1.22 $ 1.22 $ 1.22 $ 1.22 $ 1.22 $ 1.22 $ 1.37 $ 1.66 $ 1.66 $ 1.66 $ 1.66 $ 1.66 $ 1.66 $ 1.66 $ 1.66 $ 1.66 Provision for Bad Debts $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -

Total Operating Expenses $ 12.46 $ 13.51 $ 14.37 $ 1.82 $ 1.82 $ 1.82 $ 1.82 $ 1.82 $ 1.82 $ 1.82 $ 1.82 $ 1.97 $ 2.26 $ 2.26 $ 2.26 $ 2.26 $ 2.26 $ 2.26 $ 2.26 $ 2.26 $ 2.26

Operating profit/(loss) $ 3.35 $ 6.85 $ 6.92 $ 20.46 $ 21.46 $ 22.50 $ 23.60 $ 24.75 $ 25.95 $ 27.22 $ 28.55 $ 29.80 $ 30.98 $ 32.52 $ 34.14 $ 35.85 $ 37.64 $ 39.52 $ 41.50 $ 43.59 $ 45.78

Net finance charges Interest on Long-Term Loans ------Principal Repayments ------Total Debt Service ------

Taxable Income $ 3.35 $ 6.85 $ 6.92 $ 20.46 $ 21.46 $ 22.50 $ 23.60 $ 24.75 $ 25.95 $ 27.22 $ 28.55 $ 29.80 $ 30.98 $ 32.52 $ 34.14 $ 35.85 $ 37.64 $ 39.52 $ 41.50 $ 43.59 $ 45.78

Taxation $ 0.84 $ 1.71 $ 1.73 $ 5.11 $ 5.36 $ 5.62 $ 5.90 $ 6.19 $ 6.49 $ 6.81 $ 7.14 $ 7.45 $ 7.74 $ 8.13 $ 8.54 $ 8.96 $ 9.41 $ 9.88 $ 10.38 $ 10.90 $ 11.45

Profit/(loss) after taxation $ 2.51 $ 5.14 $ 5.19 $ 15.34 $ 16.09 $ 16.87 $ 17.70 $ 18.56 $ 19.46 $ 20.42 $ 21.41 $ 22.35 $ 23.23 $ 24.39 $ 25.61 $ 26.88 $ 28.23 $ 29.64 $ 31.13 $ 32.69 $ 34.34

Operating profit/(loss) per kWh billed (SBD) $ 0.71 $ 1.39 $ 1.35 $ 3.84 $ 3.87 $ 3.90 $ 3.93 $ 3.97 $ 4.00 $ 4.03 $ 4.07 $ 4.08 $ 4.08 $ 4.12 $ 4.16 $ 4.20 $ 4.24 $ 4.28 $ 4.32 $ 4.36 $ 4.41

31/25866 February 12 189 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Ringgi (Variant B)

Ringgi Profit & Loss (SBD million)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Operating Revenues $ 51.366 $ 66.171 $ 69.210 $ 72.403 $ 75.638 $ 79.032 $ 82.594 $ 86.331 $ 90.255 $ 94.374 $ 98.700 $ 103.243 $ 108.016 $ 113.030 $ 118.300 $ 123.840 $ 129.663 $ 135.787 $ 142.228 $ 149.004 $ 156.134

Hydro Scenario Historical Projected ------> 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Generation Mix (kWh) Diesel 12,501,704 13,022,609 13,565,217 14,130,435 - 9,059 53,110 98,041 143,872 190,618 238,300 286,935 336,543 387,144 438,756 491,400 545,098 599,869 655,736 712,720 1,203,071 Hydro - - - - 14,695,652 15,274,419 15,841,708 16,432,569 17,047,963 17,688,890 18,356,388 19,051,540 19,775,471 20,529,352 21,314,399 22,131,881 22,983,115 23,869,472 24,792,379 25,753,320 26,321,610 Total 12,501,704 13,022,609 13,565,217 14,130,435 14,695,652 15,283,478 15,894,817 16,530,610 17,191,834 17,879,508 18,594,688 19,338,476 20,112,015 20,916,495 21,753,155 22,623,281 23,528,213 24,469,341 25,448,115 26,466,039 27,524,681

Generation Mix (%) Diesel 100% 100% 100% 100% 0% 0% 0% 1% 1% 1% 1% 1% 2% 2% 2% 2% 2% 2% 3% 3% 4% Hydro 0% 0% 0% 0% 100% 100% 100% 99% 99% 99% 99% 99% 98% 98% 98% 98% 98% 98% 97% 97% 96% Total 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Load Factor 0.48 0.49 0.50 0.51 0.52 0.53 0.54 0.55 0.56 0.57 0.59 0.60 0.61 0.62 0.63 0.65 0.66 0.67 0.68 0.70 0.71 Peak Load (kW) 2,729.5 2,785.2 2,842.0 2,900.0 2,958.0 3,017.2 3,077.5 3,139.1 3,201.8 3,265.9 3,331.2 3,397.8 3,465.8 3,535.1 3,605.8 3,677.9 3,751.5 3,826.5 3,903.0 3,981.1 4,060.7 Operating Expenditures

Fuel Diesel (litres) 3,571,916 3,720,745 3,875,776 4,037,267 - 2,588 15,174 28,012 41,106 54,462 68,086 81,982 96,155 110,612 125,359 140,400 155,742 171,391 187,353 203,634 343,735 Delivered Diesel Price (SBD/litre) $ 6.95 $ 7.16 $ 7.37 $ 7.59 $ 7.82 $ 8.06 $ 8.30 $ 8.55 $ 8.80 $ 9.07 $ 9.34 $ 9.62 $ 9.91 $ 10.21 $ 10.51 $ 10.83 $ 11.15 $ 11.49 $ 11.83 $ 12.19 $ 12.55 Diesel Fuel Cost (SBD million) $ 24.82 $ 26.63 $ 28.58 $ 30.66 $ - $ 0.02 $ 0.13 $ 0.24 $ 0.36 $ 0.49 $ 0.64 $ 0.79 $ 0.95 $ 1.13 $ 1.32 $ 1.52 $ 1.74 $ 1.97 $ 2.22 $ 2.48 $ 4.31

Non Fuel Generation O&M $ 14.38 $ 14.98 $ 15.60 $ 16.25 $ 1.19 $ 1.20 $ 1.25 $ 1.30 $ 1.36 $ 1.41 $ 1.46 $ 1.52 $ 1.58 $ 1.64 $ 1.69 $ 1.76 $ 1.82 $ 1.88 $ 1.94 $ 2.01 $ 2.57

Distribution O&M $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - Administration and Payroll $ 0.19 $ 0.20 $ 0.20 $ 0.20 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 Total Operating Expenditure Before Depreciation and Bad Debts $ 39.40 $ 41.81 $ 44.44 $ 47.17 $ 1.45 $ 1.48 $ 1.63 $ 1.80 $ 1.98 $ 2.16 $ 2.36 $ 2.57 $ 2.79 $ 3.02 $ 3.27 $ 3.53 $ 3.81 $ 4.11 $ 4.42 $ 4.75 $ 7.15

Depreciation $ - $ 0.88 $ 0.88 $ 2.14 $ 3.98 $ 3.98 $ 3.98 $ 3.98 $ 3.98 $ 3.98 $ 3.98 $ 4.27 $ 4.86 $ 4.86 $ 4.86 $ 4.86 $ 4.86 $ 4.86 $ 4.86 $ 4.86 $ 4.86 Provision for Bad Debts $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -

Total Operating Expenses $ 39.40 $ 42.69 $ 45.32 $ 49.31 $ 5.43 $ 5.46 $ 5.61 $ 5.78 $ 5.96 $ 6.14 $ 6.34 $ 6.84 $ 7.65 $ 7.88 $ 8.13 $ 8.40 $ 8.67 $ 8.97 $ 9.28 $ 9.61 $ 12.01

Operating profit/(loss) $ 11.96 $ 23.48 $ 23.89 $ 23.10 $ 70.21 $ 73.57 $ 76.98 $ 80.55 $ 84.30 $ 88.23 $ 92.36 $ 96.40 $ 100.37 $ 105.15 $ 110.17 $ 115.44 $ 120.99 $ 126.82 $ 132.95 $ 139.39 $ 144.13

Net finance charges Interest on Long-Term Loans ------Principal Repayments ------Total Debt Service ------

Taxable Income $ 11.96 $ 23.48 $ 23.89 $ 23.10 $ 70.21 $ 73.57 $ 76.98 $ 80.55 $ 84.30 $ 88.23 $ 92.36 $ 96.40 $ 100.37 $ 105.15 $ 110.17 $ 115.44 $ 120.99 $ 126.82 $ 132.95 $ 139.39 $ 144.13

Taxation $ 2.99 $ 5.87 $ 5.97 $ 5.77 $ 17.55 $ 18.39 $ 19.24 $ 20.14 $ 21.07 $ 22.06 $ 23.09 $ 24.10 $ 25.09 $ 26.29 $ 27.54 $ 28.86 $ 30.25 $ 31.70 $ 33.24 $ 34.85 $ 36.03

Profit/(loss) after taxation $ 8.97 $ 17.61 $ 17.92 $ 17.32 $ 52.66 $ 55.18 $ 57.73 $ 60.41 $ 63.22 $ 66.18 $ 69.27 $ 72.30 $ 75.27 $ 78.86 $ 82.63 $ 86.58 $ 90.74 $ 95.11 $ 99.71 $ 104.54 $ 108.09 Operating profit/(loss) per kWh billed (SBD) $ 0.78 $ 1.47 $ 1.44 $ 1.33 $ 3.89 $ 3.92 $ 3.95 $ 3.97 $ 4.00 $ 4.02 $ 4.05 $ 4.06 $ 4.07 $ 4.10 $ 4.13 $ 4.16 $ 4.19 $ 4.23 $ 4.26 $ 4.29 $ 4.27

31/25866 February 12 190 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Taro

Taro Profit & Loss (SBD million)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Revenues $ 2.499 $ 3.151 $ 3.292 $ 3.439 $ 3.593 $ 3.755 $ 3.925 $ 4.104 $ 4.292 $ 4.489 $ 4.696 $ 4.914 $ 5.144 $ 5.384 $ 5.638 $ 5.904 $ 6.185 $ 6.480 Hydro Scenario Historical Projected ------> 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Generation Mix (kWh) Diesel 494,358 ------Hydro - 618,276 643,007 668,727 695,477 723,296 752,227 782,317 813,609 846,154 880,000 915,200 951,808 989,880 1,029,475 1,070,654 1,113,480 1,158,020 Total 494,358 618,276 643,007 668,727 695,477 723,296 752,227 782,317 813,609 846,154 880,000 915,200 951,808 989,880 1,029,475 1,070,654 1,113,480 1,158,020

Generation Mix (%) Diesel 100% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Hydro 0% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Total 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Load Factor 0.60 0.60 0.61 0.62 0.64 0.65 0.66 0.67 0.69 0.70 0.71 0.73 0.74 0.76 0.77 0.79 0.80 0.82 Peak Load (kW) 94.1 117.6 120.0 122.4 124.8 127.3 129.9 132.5 135.1 137.8 140.6 143.4 146.3 149.2 152.2 155.2 158.3 161.5 Operating Expenditures Taro Share of HQ Expenses $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 $ 0.04 Fuel Diesel (litres) - - - 141,245 ------Delivered Diesel Price (SBD/litre) $ 7.98 $ 8.22 $ 8.47 $ 8.72 $ 8.98 $ 9.25 $ 9.53 $ 9.81 $ 10.11 $ 10.41 $ 10.72 $ 11.05 $ 11.38 $ 11.72 $ 12.07 $ 12.43 $ 12.81 $ 13.19 $ 13.59 $ 13.99 $ 14.41 Diesel Fuel Cost (SBD million) $ - $ - $ - $ 1.23 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -

Non Fuel Generation O&M $ 0.57 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07 $ 0.07

Distribution O&M $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - Administration and Payroll $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 $ 0.26 Total Operating Expenditure Before Depreciation and Bad Debts $ 2.09 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37 $ 0.37

Depreciation $ 0.09 $ 0.47 $ 0.47 $ 0.47 $ 0.47 $ 0.47 $ 0.47 $ 0.47 $ 0.47 $ 0.47 $ 0.56 $ 0.56 $ 0.56 $ 0.56 $ 0.56 $ 0.56 $ 0.56 $ 0.56 Provision for Bad Debts $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -

Total Operating Expenses $ 2.18 $ 0.83 $ 0.83 $ 0.83 $ 0.83 $ 0.83 $ 0.83 $ 0.83 $ 0.83 $ 0.83 $ 0.92 $ 0.92 $ 0.92 $ 0.92 $ 0.92 $ 0.92 $ 0.92 $ 0.92

Operating profit/(loss) $ 0.32 $ 2.32 $ 2.46 $ 2.60 $ 2.76 $ 2.92 $ 3.09 $ 3.27 $ 3.46 $ 3.65 $ 3.77 $ 3.99 $ 4.22 $ 4.46 $ 4.72 $ 4.98 $ 5.26 $ 5.56

Net finance charges Interest on Long-Term Loans ------0.12 0.11 0.11 0.10 0.10 0.09 0.09 0.08 0.08 0.07 0.07 0.06 Principal Repayments ------0.17 0.17 0.18 0.18 0.19 0.19 0.20 0.20 0.21 0.22 0.22 0.23 Total Debt Service ------0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29

Taxable Income $ 0.32 $ 2.32 $ 2.46 $ 2.60 $ 2.76 $ 2.92 $ 2.97 $ 3.16 $ 3.35 $ 3.55 $ 3.67 $ 3.90 $ 4.13 $ 4.38 $ 4.64 $ 4.91 $ 5.20 $ 5.50

Taxation $ 0.08 $ 0.58 $ 0.61 $ 0.65 $ 0.69 $ 0.73 $ 0.74 $ 0.79 $ 0.84 $ 0.89 $ 0.92 $ 0.97 $ 1.03 $ 1.09 $ 1.16 $ 1.23 $ 1.30 $ 1.37

Profit/(loss) after taxation $ 0.24 $ 1.74 $ 1.84 $ 1.95 $ 2.07 $ 2.19 $ 2.23 $ 2.37 $ 2.51 $ 2.66 $ 2.76 $ 2.92 $ 3.10 $ 3.28 $ 3.48 $ 3.68 $ 3.90 $ 4.12

Operating profit/(loss) per kWh billed (SBD) $ 0.52 $ 3.05 $ 3.12 $ 3.17 $ 3.23 $ 3.29 $ 3.22 $ 3.29 $ 3.35 $ 3.42 $ 3.40 $ 3.47 $ 3.54 $ 3.61 $ 3.67 $ 3.74 $ 3.80 $ 3.87

31/25866 February 12 191 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Annex 5: Financial Internal Rate of Return Auki FIRR/FNPV Calculation

Hydro ('With Project') Diesel ('Without Project') Total Total Diesel Diesel & Diesel & 'With 'Without Net Fuel Hydro O&M Hydro Depr Project' Non-Fuel Diesel Depr Project' With Project' Financial Year Capital Cost Costs Costs Costs Costs Fuel Costs O&M Costs Costs Costs CER Credits Benefit 2013 33.43 6.81 3.29 0.33 43.85 6.81 3.29 0.33 $ 10.43 - $ (33.43) 2014 - - 0.24 1.27 1.51 7.29 3.42 0.33 $ 11.04 - $ 9.54 2015 - - 0.25 1.38 1.63 7.81 3.56 0.44 $ 11.81 - $ 10.18 2016 - - 0.26 1.38 1.64 8.37 3.70 0.44 $ 12.51 - $ 10.87 2017 - - 0.27 1.38 1.65 8.96 3.85 0.44 $ 13.25 - $ 11.61 2018 - - 0.28 1.38 1.66 9.60 4.00 0.44 $ 14.05 - $ 12.39 2019 - - 0.29 1.38 1.67 10.28 4.16 0.44 $ 14.89 - $ 13.22 2020 - - 0.30 1.49 1.79 11.02 4.33 0.56 $ 15.90 - $ 14.11 2021 - - 0.31 1.60 1.92 11.80 4.50 0.67 $ 16.97 - $ 15.05 2022 - - 0.33 1.60 1.93 12.64 4.68 0.67 $ 17.99 - $ 16.06 2023 - - 0.34 1.60 1.94 13.54 4.87 0.67 $ 19.08 - $ 17.13 2024 - - 0.35 1.60 1.96 14.50 5.06 0.67 $ 20.24 - $ 18.28 2025 - - 0.37 1.60 1.97 15.54 5.27 0.67 $ 21.47 - $ 19.50 2026 - - 0.38 1.72 2.10 16.64 5.48 0.78 $ 22.90 - $ 20.80 2027 - - 0.40 1.72 2.11 17.83 5.70 0.78 $ 24.30 - $ 22.19 2028 - - 0.41 1.72 2.13 19.10 5.92 0.78 $ 25.80 - $ 23.67 2029 - - 0.43 1.72 2.15 20.46 6.16 0.78 $ 27.40 - $ 25.25 2030 - - 0.45 1.83 2.27 21.91 6.41 0.89 $ 29.21 - $ 26.94

FIRR = 34.7% FNPVs 33.43 6.81 6.85 17.38 64.47 145.65 54.53 6.85 207.03 - 142.56

WACC = 5.03% Lata FIRR/FNPV Calculation Hydro ('With Project') Diesel ('Without Project') Diesel & Diesel & Total Total With Diesel Hydro Hydro 'With Non-Fuel Diesel 'Without Project' Net Capital Fuel O&M Depr Project' Fuel O&M Depr Project' CER Financial Year Cost Costs Costs Costs Costs Costs Costs Costs Costs Credits Benefit 2013 17.35 1.61 0.64 0.49 20.09 1.61 0.64 0.49 $ 2.74 - $ (17.35) 2014 - 0.03 0.06 0.97 1.06 1.72 0.67 0.49 $ 2.88 - $ 1.82 2015 - 0.04 0.06 0.97 1.08 1.85 0.70 0.49 $ 3.03 - $ 1.95 2016 - 0.06 0.07 0.97 1.11 1.98 0.72 0.49 $ 3.19 - $ 2.08 2017 - 0.08 0.08 0.97 1.13 2.12 0.75 0.49 $ 3.36 - $ 2.22 2018 - 0.11 0.09 0.97 1.17 2.27 0.78 0.49 $ 3.54 - $ 2.37 2019 - 0.13 0.10 0.97 1.20 2.43 0.81 0.49 $ 3.73 - $ 2.53 2020 - 0.16 0.11 0.97 1.24 2.60 0.85 0.49 $ 3.94 - $ 2.69 2021 - 0.19 0.12 1.06 1.37 2.79 0.88 0.57 $ 4.24 - $ 2.87 2022 - 0.23 0.13 1.06 1.42 2.99 0.91 0.57 $ 4.48 - $ 3.06 2023 - 0.27 0.14 1.06 1.47 3.20 0.95 0.57 $ 4.73 - $ 3.25 2024 - 0.32 0.15 1.09 1.56 3.43 0.99 0.60 $ 5.02 - $ 3.46 2025 - 0.43 0.18 1.09 1.70 3.67 1.03 0.60 $ 5.30 - $ 3.61 2026 - 0.59 0.22 1.09 1.90 3.93 1.07 0.60 $ 5.61 - $ 3.70 2027 - 0.77 0.27 1.09 2.13 4.21 1.11 0.60 $ 5.93 - $ 3.80 2028 - 0.97 0.31 1.09 2.37 4.51 1.16 0.60 $ 6.27 - $ 3.91 2029 - 1.18 0.36 1.09 2.63 4.83 1.20 0.60 $ 6.64 - $ 4.01 2030 - 1.42 0.41 1.09 2.91 5.18 1.25 0.60 $ 7.03 - $ 4.12

FIRR = 13.2% FNPVs 17.35 5.28 2.28 12.01 36.93 34.42 10.66 6.54 51.62 - 14.69

WACC = 5.03%

31/25866 February 12 192 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Mataniko FIRR/FNPV Calculation, With Tina

With Tina? Yes Hydro ('With Project') Diesel ('Without Project') Total Total With Diesel Diesel & Diesel & 'With 'Without Project' Net Capital Fuel Hydro O&M Hydro Depr Project' Non-Fuel Diesel Depr Project' CER Financial Year Cost Costs Costs Costs Costs Fuel Costs O&M Costs Costs Costs Credits Benefit 2013 57.19 196.41 105.92 - 359.52 196.41 105.92 - $ 302.33 - $ (57.19) 2014 - 184.44 97.59 1.60 283.63 212.33 96.57 - $ 308.91 - $ 25.28 2015 - 74.14 43.18 1.60 118.92 102.87 42.17 - $ 145.04 - $ 26.12 2016 - 86.63 48.30 1.60 136.54 116.23 47.29 - $ 163.52 - $ 26.98 2017 - 100.41 53.71 1.60 155.73 130.90 52.69 - $ 183.59 - $ 27.87 2018 - 115.59 59.42 1.60 176.61 146.99 58.40 - $ 205.39 - $ 28.78 2019 - - 11.54 1.60 13.14 - 10.52 - $ 10.52 - $ (2.62) 2020 - - 11.68 1.60 13.28 - 10.66 - $ 10.66 - $ (2.62) 2021 - - 11.82 12.19 24.01 1.68 10.80 10.58 $ 23.07 - $ (0.94) 2022 - - 11.96 12.19 24.15 15.51 10.95 10.58 $ 37.04 - $ 12.89 2023 - - 12.11 12.19 24.29 31.12 11.09 10.58 $ 52.80 - $ 28.51 2024 - 13.05 17.28 12.19 42.52 50.54 16.27 10.58 $ 77.39 - $ 34.87 2025 - 33.60 25.00 12.19 70.78 72.21 23.98 10.58 $ 106.78 - $ 36.00 2026 - 56.57 33.16 12.19 101.92 96.35 32.14 10.58 $ 139.07 - $ 37.16 2027 - 82.21 41.78 12.19 136.18 123.17 40.77 10.58 $ 174.53 - $ 38.35 2028 - 110.74 50.90 12.19 173.83 152.94 49.88 10.58 $ 213.40 - $ 39.58 2029 - 142.44 60.53 12.19 215.15 185.90 59.51 10.58 $ 256.00 - $ 40.84 2030 - 177.59 70.70 12.19 260.48 222.36 69.68 10.58 $ 302.62 - $ 42.15

FIRR = 40.4% FNPVs 57.19 979.75 555.54 75.93 1,668.41 1,282.14 544.11 57.91 1,884.15 - 215.74

WACC = 5.03% Mataniko FIRR/FNPV Calculation, Without Tina

With Tina? No Hydro ('With Project') Diesel ('Without Project') Total Total With Diesel Diesel & Diesel & 'With 'Without Project' Net Capital Fuel Hydro O&M Hydro Depr Project' Non-Fuel Diesel Depr Project' CER Financial Year Cost Costs Costs Costs Costs Fuel Costs O&M Costs Costs Costs Credits Benefit 2013 57.19 196.41 105.92 - 359.52 196.41 105.92 - $ 302.33 - $ (57.19) 2014 - 184.44 97.59 1.60 283.63 212.33 96.57 - $ 308.91 - $ 25.28 2015 - 200.82 103.10 1.60 305.53 229.55 102.09 - $ 331.64 - $ 26.12 2016 - 218.58 108.89 1.60 329.07 248.17 107.88 - $ 356.05 - $ 26.98 2017 - 237.81 114.97 1.60 354.38 268.30 113.95 - $ 382.25 - $ 27.87 2018 - 258.66 121.35 1.60 381.61 290.06 120.33 - $ 410.39 - $ 28.78 2019 - 281.24 128.04 1.60 410.88 313.58 127.02 - $ 440.60 - $ 29.72 2020 - 305.70 135.07 1.60 442.37 339.01 134.05 - $ 473.06 - $ 30.69 2021 - 332.19 142.44 12.19 486.82 366.50 141.43 10.58 $ 518.51 - $ 31.69 2022 - 360.89 150.18 12.19 523.26 396.23 149.17 10.58 $ 555.98 - $ 32.72 2023 - 391.96 158.31 12.19 562.45 428.36 157.29 10.58 $ 596.23 - $ 33.78 2024 - 425.61 166.83 12.19 604.63 463.10 165.82 10.58 $ 639.50 - $ 34.87 2025 - 462.04 175.79 12.19 650.01 500.65 174.77 10.58 $ 686.01 - $ 36.00 2026 - 501.48 185.18 12.19 698.85 541.26 184.16 10.58 $ 736.01 - $ 37.16 2027 - 544.19 195.04 12.19 751.41 585.15 194.03 10.58 $ 789.76 - $ 38.35 2028 - 590.41 205.39 12.19 807.99 632.61 204.38 10.58 $ 847.57 - $ 39.58 2029 - 640.45 216.26 12.19 868.89 683.91 215.24 10.58 $ 909.73 - $ 40.84 2030 - 694.61 227.66 12.19 934.45 739.37 226.64 10.58 $ 976.60 - $ 42.15

FIRR = 47.4% FNPVs 57.19 4,184.17 1,743.66 75.93 6,060.95 4,572.30 1,732.23 57.91 6,362.44 - 301.49

WACC = 5.03%

31/25866 February 12 193 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Ringgi (Variant A) FIRR/FNPV Calculation

Hydro ('With Project') Diesel ('Without Project') Total Total With Diesel Diesel & Diesel & 'With 'Without Project' Net Fuel Hydro O&M Hydro Depr Project' Non-Fuel Diesel Depr Project' CER Financial Year Capital Cost Costs Costs Costs Costs Fuel Costs O&M Costs Costs Costs Credits Benefit 2012 34.64 9.02 4.80 0.29 48.76 9.02 4.80 0.29 $ 14.11 - $ (34.64) 2013 - - 0.34 1.22 1.56 9.68 5.00 0.29 $ 14.97 - $ 13.41 2014 - - 0.34 1.22 1.56 10.37 5.20 0.29 $ 15.86 - $ 14.30 2015 - - 0.34 1.22 1.56 11.11 5.41 0.29 $ 16.81 - $ 15.25 2016 - - 0.34 1.22 1.56 11.90 5.62 0.29 $ 17.81 - $ 16.25 2017 - - 0.34 1.22 1.56 12.74 5.85 0.29 $ 18.89 - $ 17.33 2018 - - 0.34 1.22 1.56 13.65 6.08 0.29 $ 20.03 - $ 18.47 2019 - - 0.34 1.22 1.56 14.62 6.33 0.29 $ 21.24 - $ 19.68 2020 - - 0.34 1.22 1.56 15.66 6.58 0.29 $ 22.54 - $ 20.98 2021 - - 0.34 1.37 1.71 16.78 6.84 0.44 $ 24.06 - $ 22.35 2022 - - 0.34 1.66 2.00 17.97 7.12 0.74 $ 25.83 - $ 23.82 2023 - - 0.34 1.66 2.00 19.25 7.40 0.74 $ 27.39 - $ 25.39 2024 - - 0.34 1.66 2.00 20.62 7.70 0.74 $ 29.06 - $ 27.05 2025 - - 0.34 1.66 2.00 22.09 8.01 0.74 $ 30.83 - $ 28.83 2026 - - 0.34 1.66 2.00 23.67 8.33 0.74 $ 32.73 - $ 30.72 2027 - - 0.34 1.66 2.00 25.35 8.66 0.74 $ 34.74 - $ 32.74 2028 - - 0.34 1.66 2.00 27.16 9.00 0.74 $ 36.90 - $ 34.89 2029 - - 0.34 1.66 2.00 29.09 9.36 0.74 $ 39.19 - $ 37.19 2030 - - 0.34 1.66 2.00 31.16 9.74 0.74 $ 41.64 - $ 39.63

FIRR = 45.1% FNPVs 34.64 9.02 8.49 15.42 67.58 186.12 76.99 5.32 268.42 - 200.84

WACC = 5.47% Ringgi (Variant B) FIRR/FNPV Calculation

Hydro ('With Project') Diesel ('Without Project')

Diesel Diesel & Diesel & Total Total 'Without Fuel Hydro O&M Hydro Depr 'With Project' Non-Fuel Diesel Depr Project' With Project' Net Financial Year Capital Cost Costs Costs Costs Costs Fuel Costs O&M Costs Costs Costs CER Credits Benefit 2012 45.15 28.58 15.60 0.88 90.21 28.58 15.60 0.88 $ 45.06 - $ (45.15) 2013 45.15 30.66 16.25 2.14 94.20 30.66 16.25 0.88 $ 47.79 - $ (46.41) 2014 - - 1.19 3.98 5.17 32.84 16.90 1.47 $ 51.21 - $ 46.04 2015 - 0.02 1.20 3.98 5.20 35.18 17.58 1.47 $ 54.23 - $ 49.03 2016 - 0.13 1.25 3.98 5.36 37.69 18.28 1.47 $ 57.44 - $ 52.08 2017 - 0.24 1.30 3.98 5.52 40.37 19.01 1.47 $ 60.85 - $ 55.33 2018 - 0.36 1.36 3.98 5.70 43.25 19.77 1.47 $ 64.49 - $ 58.79 2019 - 0.49 1.41 3.98 5.88 46.32 20.56 1.47 $ 68.36 - $ 62.47 2020 - 0.64 1.46 3.98 6.08 49.62 21.38 1.47 $ 72.48 - $ 66.40 2021 - 0.79 1.52 4.27 6.58 53.16 22.24 1.76 $ 77.16 - $ 70.58 2022 - 0.95 1.58 4.86 7.39 56.94 23.13 2.35 $ 82.42 - $ 75.03 2023 - 1.13 1.64 4.86 7.63 60.99 24.05 2.35 $ 87.40 - $ 79.77 2024 - 1.32 1.69 4.86 7.87 65.34 25.02 2.35 $ 92.71 - $ 84.83 2025 - 1.52 1.76 4.86 8.14 69.99 26.02 2.35 $ 98.36 - $ 90.22 2026 - 1.74 1.82 4.86 8.42 74.97 27.06 2.35 $ 104.38 - $ 95.97 2027 - 1.97 1.88 4.86 8.71 80.31 28.14 2.35 $ 110.80 - $ 102.09 2028 - 2.22 1.94 4.86 9.02 86.03 29.27 2.35 $ 117.65 - $ 108.62 2029 - 2.48 2.01 4.86 9.35 92.15 30.44 2.35 $ 124.94 - $ 115.59 2030 - 4.31 2.57 4.86 11.75 98.72 31.65 2.35 $ 132.72 - $ 120.97

FIRR = 46.9% FNPVs 87.96 65.76 45.92 46.10 245.74 589.61 250.21 19.97 859.79 - 614.05

WACC = 5.47%

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Annex 6: Rapid Environmental Assessment Checklists The ADB’s Rapid Environmental Assessment (REA) checklist for hydro power was used to determine the environmental categorization for each of the six sites selected for this pre- feasibility study. Fiu River, Malaita

Instructions:

(i) The project team completes this checklist to support the environmental classification of a project. It is to be attached to the environmental categorization form and submitted to the Environment and Safeguards Division (RSES) for endorsement by Director, RSES and for approval by the Chief Compliance Officer.

(ii) This checklist focuses on environmental issues and concerns. To ensure that social dimensions are adequately considered, refer also to ADB's (a) checklists on involuntary resettlement and Indigenous Peoples; (b) poverty reduction handbook; (c) staff guide to consultation and participation; and (d) gender checklists.

(iii) Answer the questions assuming the “without mitigation” case. The purpose is to identify potential impacts. Use the “remarks” section to discuss any anticipated mitigation measures.

Country/Project Title: Solomon Islands, RETA 7329 Mini hydro Pre-feasibility Study

Sector Division:

A. Basic Project Design Data Fiu River, Auki, Malaita,

1. Dam height, m = no dam

2. Surface area of reservoir, (ha) = no reservoir

3. Estimated number of people to be displaced = nil

4. Rated power output, (MW) = 1160kW

Other Considerations:

1. Water storage type: run of river

2. River diversion scheme: in-stream flow regulation

3. Type of power demand to address: base load

195 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS B. Project Location Is the dam and/or project facilities adjacent to or within any of the following areas? . Unregulated river X Natural river on customary land . Undammed river tributaries below the proposed dam X Numerous streams enter along the Fiu River including many large ephemeral waterways where groundwater discharge enters the river channel at the water’s edge . Unique or aesthetically valuable land or water form X Natural forest and garden activity in the upper catchment is similar to nearby catchments . Special area for protecting biodiversity X No known area in the catchment . Protected Area X No known area in the catchment . Buffer zone of protected area X None known . Primary forest X Catchment has not been commercially logged but is used for local village consumption and cleared for garden activity . Range of endangered or threatened animals X None known . Area used by indigenous peoples X For traditional building materials and garden activity . Cultural heritage site X Tambu sites along northern ridge of catchment . Wetland X None reported . Mangrove X None reported . Estuary X None reported

C. Potential Environmental Impacts Will the Project cause… . short-term construction impacts such as soil erosion, deterioration of water and air quality, X High likelihood of soil erosion on steep slopes as a result of road construction and clearance of the noise and vibration from construction equipment? penstock and canal corridors. Water quality will be impacted . disturbance of large areas due to material quarrying? X No quarrying required. Existing quarry for road surface material is located on road out of Auki

. disposal of large quantities of construction X Spoil disposal during road construction will be spoils? critical on the access road to the power house . clearing of large forested area for ancillary facilities and access road? X There is currently no road access in the catchment. A new access road is required. Clearing forest for some 3000m canal corridor and 750m of penstock corridor is required. Minimise width of corridor where appropriate. . impounding of a long river stretch? X River will not be impounded

. dryness (less than 50% of dry season mean flow) X The system returns the flow back to the river over a long downstream river stretch? some 3000m from the intake

196 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS . construction of permanent access road near or through forests? X New roads will be required to access the power station and penstock corridor. Reduce clearance of undisturbed forest where possible . creation of barriers for migratory land animals X Crossing points under or over the 3000m canal and 750m penstock can be created where there is evidence of wildlife movement.

. loss of precious ecological values due to flooding X There is some potential for the loss or destruction of agricultural/forest areas, and wild lands and to fish habitat from construction activity which can wildlife habitat; destruction of fish be mitigated with appropriate construction spawning/breeding and nursery grounds? methods and road location . deterioration of downstream water quality due to anoxic water from the reservoir and sediments X No reservoir. due to soil erosion? . significant diversion of water from one basin to X The water used in the project is returned to the another? same river system

. alternating dry and wet downstream conditions X The water used in the project is returned to the due to peaking operation of powerhouse? same river system

. significant modification of annual flood cycle X Flood flows result in high short duration peak affecting downstream ecosystem, people’s discharges, and will not be modified as there is no sustenance and livelihoods? dam. Bed load material will not be impacted

. loss or destruction of unique or aesthetically X The river system is not unique in Malaita valuable land or water forms? . proliferation of aquatic weeds in reservoir and downstream impairing dam discharge, irrigation X No reservoir and no dam discharge systems, navigation and fisheries, and increasing water loss through transpiration? . scouring of riverbed below dam? X No dam

. downstream erosion of recipient river in trans- X No trans basin diversion basin diversion? . increased flooding risk of recipient river in trans- X No trans basin diversion basin diversion?

. decreased groundwater recharge of downstream X Numerous ephemeral gullies enter the river areas? system below the power house site

. draining of downstream wetlands and riparian X No wetlands and riparian areas involved areas? . decline or change in fisheries below the dam due to reduced peak flows and floods, submersion of X No dam. River stretches not submerged river stretches and resultant destruction of fish breeding and nursery grounds, and water quality changes? . loss of migratory fish species due to barrier X No dam imposed by the dam? . formation of sediment deposits at reservoir entrance, creating backwater effect and flooding X No reservoir and waterlogging upstream? . significant disruption of river sediment transport X No reservoir downstream due to trapping in reservoir? . environmental risk due to potential toxicity of X No dam sediments trapped behind the dams? . increased saltwater intrusion in estuary and low X No reduction in river flow lands due to reduced river flows? . significant induced seismicity due to large reservoir size and potential environmental hazard X No reservoir or dam from catastrophic failure of the dam?

197 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS . cumulative effects due to its role as part of a X No dams in river system cascade of dams/ reservoirs? . depletion of dissolved oxygen by large quantities of decaying plant material, fish mortality due to X No reservoir or dam, run of river water used in reduced dissolved oxygen content in water, algal project blooms causing successive and temporary eutrophication, growth and proliferation of aquatic weeds? . risks and vulnerabilities related to occupational health and safety due to physical, chemical, X Physical hazards with machine operation and biological, and radiological hazards during project construction activities on steep slopes can be construction and operation? mitigated with appropriate HSE plan . large population influx during project construction and operation that causes increased burden on X Small scale construction using local labour where social infrastructure and services (such as water possible supply and sanitation systems)? . creation of community slums following construction of the hydropower plant and its X Small scale project with no large work force facilities? • social conflicts if workers from other regions or X A core specialist construction team with local countries are hired? labourers . uncontrolled human migration into the area, made possible by access roads and transmission X Not anticipated in this customary land lines? . disproportionate impacts on the poor, women, children or other vulnerable groups? X No negative impacts are expected. Project will have positive impacts on these groups by providing regular power supply to the community . community health and safety risks due to the transport, storage, and use and/or disposal of X Not anticipated as construction materials used in materials likely to create physical, chemical and this project are similar to that already in the region biological hazards? • risks to community safety due to both accidental X Potential for accidental falls into headrace canal and natural hazards, especially where the and fore bay increased to presence of villages structural elements or components of the project and use of canal corridor for access. Awareness (e.g.,dams) are accessible to members of the campaign required. affected community or where their failure could result in injury to the community throughout Slope failure along canal corridor could result in project construction, operation and diversion of canal flow into non-stream receiving decommissioning? areas resulting in significant erosion and slope failures

198 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Sorave River Choiseul

Instructions:

(i) The project team completes this checklist to support the environmental classification of a project. It is to be attached to the environmental categorization form and submitted to the Environment and Safeguards Division (RSES) for endorsement by Director, RSES and for approval by the Chief Compliance Officer.

(ii) This checklist focuses on environmental issues and concerns. To ensure that social dimensions are adequately considered, refer also to ADB's (a) checklists on involuntary resettlement and Indigenous Peoples; (b) poverty reduction handbook; (c) staff guide to consultation and participation; and (d) gender checklists.

(iii) Answer the questions assuming the “without mitigation” case. The purpose is to identify potential impacts. Use the “remarks” section to discuss any anticipated mitigation measures.

Country/Project Title: Solomon Islands, RETA 7329 Mini hydro Pre-feasibility Study

Sector Division:

A. Basic Project Design Data Sorawe River, Taro, Choiseul Bay

1. Dam height, m = no dam

2. Surface area of reservoir, (ha) = no reservoir

3. Estimated number of people to be displaced = nil

4. Rated power output, (MW) = 150kW

Other Considerations:

1. Water storage type: run of river

2. River diversion scheme: in-stream flow regulation

3. Type of power demand to address: base load

199 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS B. Project Location Is the dam and/or project facilities adjacent to or within any of the following areas? . Unregulated river X Natural river on customary land, source of school water supply . Undammed river tributaries below the proposed dam X Another tributary arising from the north through logged over forest, joining below the waterfall, with upper reaches being subterranean flow . Unique or aesthetically valuable land or water form X Extensive undisturbed forest in karst formation in upper catchment of Sorawe River . Special area for protecting biodiversity X Mangrove forest in estuary in Choiseul Bay. Upper forest catchment has a range of flora and fauna species which will remain undisturbed due to difficult karst terrain . Protected Area X There is no known protected area in the catchment but Parama Island in Choiseul Bay is a designated conservation area for the protection of reef fish habitat . Buffer zone of protected area X None known . Primary forest X The forest in the upper catchment is undisturbed due to extensive karst formation . Range of endangered or threatened animals X None known . Area used by indigenous peoples X Limited use for hunting, building materials, no garden activity . Cultural heritage site X None reported within the Sorawe River catchment where the intake is planned but sites exist on Mt Arara in the northern tributary catchment . Wetland X No wetlands exist in karst formations . Mangrove X Mangrove forest in the lower reaches below the proposed power station site remains undisturbed except for some minor local use. . Estuary X Sorawe River enters Choiseul Bay through a tidal mangrove lined channel

C. Potential Environmental Impacts Will the Project cause… . short-term construction impacts such as soil erosion, deterioration of water and air quality, X No deterioration of water quality during construction due to limestone formation and noise and vibration from construction equipment? relief. Little impact from soil erosion due to lack of soil. Drilling and blasting required for intake structure . disturbance of large areas due to material quarrying? X No quarrying required.

200 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS . disposal of large quantities of construction X Small quantities of spoil can be easily disposed spoils? of alongside the construction corridor in naturally formed depressions and sinkholes In the karst formation. . clearing of large forested area for ancillary facilities and access road? X A small amount of natural forest will be cleared along the narrow corridor of the canal and the penstock and the power station site. . impounding of a long river stretch? X No dam or reservoir . dryness (less than 50% of dry season mean flow) over a long downstream river stretch? X The system returns the flow back to the river a short distance from the intake . construction of permanent access road near or through forests? X Existing logging roads will be upgraded and used as much as possible. Reduce clearance of undisturbed forest where possible . creation of barriers for migratory land animals X None expected . loss of precious ecological values due to flooding of agricultural/forest areas, and wild lands and X No flooding in this catchment. No loss of wildlife wildlife habitat; destruction of fish habitat due to small scale activity. Fish can not spawning/breeding and nursery grounds? go beyond the waterfall. . deterioration of downstream water quality due to anoxic water from the reservoir and sediments X No dam or reservoir. The river channel is due to soil erosion? incised in limestone with no in-stream bed load material. Construction will not result of significant quantities of sediments . significant diversion of water from one basin to another? X The water used in the project is returned to the same river system . alternating dry and wet downstream conditions due to peaking operation of powerhouse? X The powerhouse is located at sea level . significant modification of annual flood cycle affecting downstream ecosystem, people’s X The water is returned at sea level sustenance and livelihoods? . loss or destruction of unique or aesthetically valuable land or water forms? X The catchment area associated with the project is well represented in this part of Choiseul . proliferation of aquatic weeds in reservoir and downstream impairing dam discharge, irrigation X No reservoir and no dam discharge systems, navigation and fisheries, and increasing water loss through transpiration? . scouring of riverbed below dam? X No dam . downstream erosion of recipient river in trans- basin diversion? X No trans basin diversion . increased flooding risk of recipient river in trans- basin diversion? X No trans basin diversion . decreased groundwater recharge of downstream areas? X No risk . draining of downstream wetlands and riparian areas? X The proposed power station is at sea level . decline or change in fisheries below the dam due to reduced peak flows and floods, submersion of X No dam. The waterfall prevents fish access and river stretches and resultant destruction of fish no breeding areas are impacted breeding and nursery grounds, and water quality changes? . loss of migratory fish species due to barrier imposed by the dam? X No dam

201 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS . formation of sediment deposits at reservoir entrance, creating backwater effect and flooding X No reservoir and water logging upstream? . significant disruption of river sediment transport X No reservoir. No sediment in generally smooth downstream due to trapping in reservoir? limestone river channel . environmental risk due to potential toxicity of X No dam sediments trapped behind the dams? . increased saltwater intrusion in estuary and low X The water is returned to the river where it is lands due to reduced river flows? already subject to tidal influence . significant induced seismicity due to large reservoir size and potential environmental hazard X No reservoir or dam from catastrophic failure of the dam? . cumulative effects due to its role as part of a cascade of dams/ reservoirs? X No dams in river system . depletion of dissolved oxygen by large quantities of decaying plant material, fish mortality due to X No reservoir or dam, run of river water used in reduced dissolved oxygen content in water, algal project blooms causing successive and temporary eutrophication, growth and proliferation of aquatic weeds? . risks and vulnerabilities related to occupational health and safety due to physical, chemical, X Physical hazards associated with working on biological, and radiological hazards during project hard limestone during construction can be construction and operation? mitigated with appropriate HSE plan. SIEA committed to socially responsible working conditions . large population influx during project construction and operation that causes increased burden on X Small scale construction using local labour social infrastructure and services (such as water where possible supply and sanitation systems)? . creation of community slums following construction of the hydropower plant and its X Small scale project with no large work force facilities? • social conflicts if workers from other regions or X SIEA is committed to socially responsible countries are hired? working conditions . uncontrolled human migration into the area, made possible by access roads and transmission X Not anticipated in this customary land lines? . disproportionate impacts on the poor, women, children or other vulnerable groups? X No negative impacts are expected. Project will have positive impacts on these groups by providing regular power supply to the community . community health and safety risks due to the transport, storage, and use and/or disposal of X No negative impacts are expected materials likely to create physical, chemical and biological hazards? • risks to community safety due to both accidental X Potential for accidental falls into canal and fore and natural hazards, especially where the bay is unlikely due to remote location of facility. structural elements or components of the project Community awareness program required. (e.g.,dams) are accessible to members of the affected community or where their failure could result in injury to the community throughout project construction, operation and decommissioning?

202 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Luembalele River, Lata, Santa Cruz

Instructions:

(i) The project team completes this checklist to support the environmental classification of a project. It is to be attached to the environmental categorization form and submitted to the Environment and Safeguards Division (RSES) for endorsement by Director, RSES and for approval by the Chief Compliance Officer.

(ii) This checklist focuses on environmental issues and concerns. To ensure that social dimensions are adequately considered, refer also to ADB's (a) checklists on involuntary resettlement and Indigenous Peoples; (b) poverty reduction handbook; (c) staff guide to consultation and participation; and (d) gender checklists.

(iii) Answer the questions assuming the “without mitigation” case. The purpose is to identify potential impacts. Use the “remarks” section to discuss any anticipated mitigation measures.

Country/Project Title: Solomon Islands, RETA 7329 Mini hydro Pre-feasibility Study

Sector Division:

A. Basic Project Design Data Luembalele River, Lata, Santa Cruz

1. Dam height, m = no dam

2. Surface area of reservoir, (ha) = no reservoir

3. Estimated number of people to be displaced = nil

4. Rated power output, = 107 kW

Other Considerations:

1. Water storage type: run of river

2. River diversion scheme: in-stream flow regulation

3. Type of power demand to address: base load

203 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS B. Project Location Is the dam and/or project facilities adjacent to or within any of the following areas? . Unregulated river X Natural river with no other activity . Undammed river tributaries below the proposed dam X No dam. A number of perennial streams enter the river below the intake site. Flash flood water rise high up the stream banks . Unique or aesthetically valuable land or water form X Small steep catchments on the island with similar land form and hydrology well represented on island . Special area for protecting biodiversity X Forest type typical of upper slopes of the central mountain area well represented on island . Protected Area X No formalised protected areas on the island but many similar catchments on the mountain slopes . Buffer zone of protected area X No formalised protected areas, previous logging subject to river buffer zone requirements under Forest Act . Primary forest X Undisturbed on upper slopes but logged on easier terrain near river channel

. Range of endangered or threatened animals X None known . Area used by indigenous peoples X Limited use for hunting, building materials, no garden activity

. Cultural heritage site X None reported in area

. Wetland X No wetlands in the reef limestone

. Mangrove X No mangroves in river

. Estuary X River flows directly into Graciosa Bay

C. Potential Environmental Impacts Will the Project cause… . short-term construction impacts such as soil erosion, X Drilling and blasting required for intake deterioration of water and air quality, noise and structure in basalt formation above vibration from construction equipment? waterfall. . disturbance of large areas due to material quarrying? X No quarrying required. . disposal of large quantities of construction spoils? X Disposal of material from headrace canal corridors but suitable locations available nearby that will not result in debris entering watercourse . clearing of large forested area for ancillary facilities and access road? X Clearing of logged natural forest and plantation for headrace canal and penstock corridors. Minimise width of corridor where appropriate and avoid habitat trees where practicable

204 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS . impounding of a long river stretch? X No dam or reservoir . dryness (less than 50% of dry season mean flow) over a long downstream river stretch? X None expected with other perennial flows entering river channel below intake structure . construction of permanent access road near or through forests? X Use of existing logging roads for much of the access with some new roads required. Reduce clearance of undisturbed forest where possible . creation of barriers for migratory land animals X Not expected. Limited pig population will not have impeded access

. loss of precious ecological values due to flooding of X No flooding of lands due to incised river agricultural/forest areas, and wild lands and wildlife channel. No loss of wildlife habitat due habitat; destruction of fish spawning/breeding and to small scale activity. Fish not reported nursery grounds? above waterfall

. deterioration of downstream water quality due to anoxic X No dam or reservoir, natural intake from water from the reservoir and sediments due to soil existing deep pool above water fall erosion?

. significant diversion of water from one basin to X The water used in the project is another? returned to the same river system

. alternating dry and wet downstream conditions due to X The water used in the project is peaking operation of powerhouse? returned to the same river system . significant modification of annual flood cycle affecting downstream ecosystem, people’s sustenance and X Flood flows result in high short duration livelihoods? peak discharges nd will not be modified as there is no dam. Bed load material will not be impacted . loss or destruction of unique or aesthetically valuable land or water forms? X The catchment area associated with the project is well represented in this part of Santa Cruz . proliferation of aquatic weeds in reservoir and downstream impairing dam discharge, irrigation X No reservoir and no dam discharge systems, navigation and fisheries, and increasing water loss through transpiration? . scouring of riverbed below dam? X No dam, existing waterfall over basalt formation with a deep plunge pool

. downstream erosion of recipient river in trans-basin X No trans basin diversion diversion? . increased flooding risk of recipient river in trans-basin X No trans basin diversion diversion? . decreased groundwater recharge of downstream X No risk areas?

. draining of downstream wetlands and riparian areas? X No risk . decline or change in fisheries below the dam due to X No dam. The waterfall prevents fish reduced peak flows and floods, submersion of river access and no breeding areas are stretches and resultant destruction of fish breeding and impacted nursery grounds, and water quality changes?

. loss of migratory fish species due to barrier imposed by X No dam, existing waterfall is natural the dam? barrier to fish passage . formation of sediment deposits at reservoir entrance, creating backwater effect and flooding and X No reservoir waterlogging upstream?

205 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS . significant disruption of river sediment transport X No reservoir. Sediment transport will not downstream due to trapping in reservoir? be impacted . environmental risk due to potential toxicity of sediments X No dam trapped behind the dams? . increased saltwater intrusion in estuary and low lands X Water is returned to the river, no due to reduced river flows? significant reduction in flow due to other perennial stream flows . significant induced seismicity due to large reservoir size and potential environmental hazard from catastrophic X No reservoir or dam failure of the dam? . cumulative effects due to its role as part of a cascade of X No dams in river system dams/ reservoirs? . depletion of dissolved oxygen by large quantities of decaying plant material, fish mortality due to reduced X No reservoir or dam, run of river water dissolved oxygen content in water, algal blooms used in project causing successive and temporary eutrophication, growth and proliferation of aquatic weeds? . risks and vulnerabilities related to occupational health and safety due to physical, chemical, biological, and X Physical hazards related to drill and radiological hazards during project construction and blast of volcanic rock at intake structure operation? can be mitigated with appropriate HSE plan. SIEA committed to socially responsible working conditions . large population influx during project construction and operation that causes increased burden on social X Small scale construction on remote infrastructure and services (such as water supply and island using local labour where possible sanitation systems)? . creation of community slums following construction of the hydropower plant and its facilities? X No risk. Small scale project with no large work force • social conflicts if workers from other regions or countries

are hired? . uncontrolled human migration into the area, made possible by access roads and transmission lines? X No resettlement will occur. Small local population in remote location . disproportionate impacts on the poor, women, children or other vulnerable groups? X No negative impacts are expected. Project will have positive impacts on these groups by providing regular power supply to the community . community health and safety risks due to the transport, storage, and use and/or disposal of materials likely to X No negative impacts are expected create physical, chemical and biological hazards? • risks to community safety due to both accidental and X Potential for accidental falls into canal natural hazards, especially where the structural and fore bay is unlikely due to remote elements or components of the project (e.g.,dams) are location of facility. Community accessible to members of the affected community or awareness program required. where their failure could result in injury to the community throughout project construction, operation and decommissioning?

206 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Vila River, Ringgi, Kolombangara

Instructions:

(i) The project team completes this checklist to support the environmental classification of a project. It is to be attached to the environmental categorization form and submitted to the Environment and Safeguards Division (RSES) for endorsement by Director, RSES and for approval by the Chief Compliance Officer.

(ii) This checklist focuses on environmental issues and concerns. To ensure that social dimensions are adequately considered, refer also to ADB's (a) checklists on involuntary resettlement and Indigenous Peoples; (b) poverty reduction handbook; (c) staff guide to consultation and participation; and (d) gender checklists.

(iii) Answer the questions assuming the “without mitigation” case. The purpose is to identify potential impacts. Use the “remarks” section to discuss any anticipated mitigation measures.

Country/Project Title: Solomon Islands, RETA 7329 Mini hydro Pre-feasibility Study

Sector Division:

A. Basic Project Design Data Vila River, Ringgi, Kolombangara

1. Dam height, m = no dam

2. Surface area of reservoir, (ha) = no reservoir

3. Estimated number of people to be displaced = nil

4. Rated power output, (MW) = 12MW, 3 stages

Other Considerations:

1. Water storage type: run of river

2. River diversion scheme: in-stream flow regulation

3. Type of power demand to address: base load

207 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS B. Project Location Is the dam and/or project facilities adjacent to or within any of the following areas? . Unregulated river X Steep river catchment with no other activity . Undammed river tributaries below the proposed dam X No dam, numerous lateral gullies and small perennial watercourses . Unique or aesthetically valuable land or water form X Largest catchment on Kolombangara arising from caldera, high biodiversity . Special area for protecting biodiversity X Area above 400m contour designated as conservation area by KIBCA/KFPL . Protected Area X Area above 400m contour designated as conservation area by KIBCA/KFPL . Buffer zone of protected area X Vila River Reserve from below 400m contour to ring road to protect water quality . Primary forest X In Vila River catchment from lowland forest to cloud forest . Range of endangered or threatened animals X Endangered species indicated by recent biodiversity and High Conservation Value Forest studies as part of FSC certification . Area used by indigenous peoples X Ecotourism enterprise and local hunting . Cultural heritage site X Upper catchment of Vila River . Wetland X . Mangrove X . Estuary X Small estuary at river mouth

C. Potential Environmental Impacts Will the Project cause… . short-term construction impacts such as soil erosion, deterioration of water and air quality, noise and X Drilling and blasting required for intake structure and where head race canal vibration from construction equipment? corridor passes through volcanic outcrops and bluffs . disturbance of large areas due to material quarrying? X Potential source of aggregate in lower reaches of river for construction .Will require care in removal in order to retain hydrological characteristics . disposal of large quantities of construction spoils? X Spoil and vegetation from 3 design stages in catchment will require careful disposal to reduce the amount of debris and sediment into water course . clearing of large forested area for ancillary facilities and access road? X Linear clearance of forest for canal and penstock corridors on steep slopes.

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SCREENING QUESTIONS Yes No REMARKS . impounding of a long river stretch? X Steep catchment, no dam or reservoir . dryness (less than 50% of dry season mean flow) over a long downstream river stretch? X None expected . construction of permanent access road near or through forests? X To each of three power house sites plus construction of canal and penstock corridors . creation of barriers for migratory land animals X Not expected . loss of precious ecological values due to flooding of agricultural/forest areas, and wild lands and wildlife X Rare fish species reported in Vila River. habitat; destruction of fish spawning/breeding and nursery grounds? . deterioration of downstream water quality due to anoxic water from the reservoir and sediments due to soil X No dam or reservoir. Increased erosion? sediments due to soil erosion at 3 construction sites . significant diversion of water from one basin to another? X The water used in the project is returned to the same river system . alternating dry and wet downstream conditions due to peaking operation of powerhouse? X The water used in the project is returned to the same river system . significant modification of annual flood cycle affecting downstream ecosystem, people’s sustenance and X Flood flows result in high short duration livelihoods? peak discharges, and will not be modified as there is no dam. Bed load material will not be impacted . loss or destruction of unique or aesthetically valuable land or water forms? X Change in condition of Vila River Reserve due to construction works . proliferation of aquatic weeds in reservoir and downstream impairing dam discharge, irrigation X No reservoir and no dam discharge systems, navigation and fisheries, and increasing water loss through transpiration? . scouring of riverbed below dam? X No dam . downstream erosion of recipient river in trans-basin diversion? X No trans basin diversion . increased flooding risk of recipient river in trans-basin diversion? X No trans basin diversion . decreased groundwater recharge of downstream areas? X No risk . draining of downstream wetlands and riparian areas? X No risk . decline or change in fisheries below the dam due to reduced peak flows and floods, submersion of river X No dam. stretches and resultant destruction of fish breeding and nursery grounds, and water quality changes? . loss of migratory fish species due to barrier imposed by the dam? X No dam . formation of sediment deposits at reservoir entrance, creating backwater effect and flooding and water X No reservoir logging upstream? . significant disruption of river sediment transport X No reservoir. Sediment transport will not downstream due to trapping in reservoir? be impacted . environmental risk due to potential toxicity of sediments X No dam trapped behind the dams?

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SCREENING QUESTIONS Yes No REMARKS . increased saltwater intrusion in estuary and low lands X Water is returned to the river, no due to reduced river flows? significant reduction in flow due to other perennial stream flows . significant induced seismicity due to large reservoir size and potential environmental hazard from catastrophic X No reservoir or dam failure of the dam? . cumulative effects due to its role as part of a cascade of dams/ reservoirs? X A series of three systems within the catchment will increase the risk of sediment loads in streams and increase the amount of forest clearance for the corridors . depletion of dissolved oxygen by large quantities of decaying plant material, fish mortality due to reduced X No reservoir or dam, run of river water dissolved oxygen content in water, algal blooms used in project causing successive and temporary eutrophication, growth and proliferation of aquatic weeds? . risks and vulnerabilities related to occupational health and safety due to physical, chemical, biological, and X Physical hazards related to drill and radiological hazards during project construction and blast of volcanic rock at intake structure operation? can be mitigated with appropriate HSE plan. Under FSC, KFPL is committed to socially responsible working conditions . large population influx during project construction and operation that causes increased burden on social X No risk. Small scale project with no infrastructure and services (such as water supply and large work force sanitation systems)? . creation of community slums following construction of the hydropower plant and its facilities? X No risk. Small scale project with no large work force • social conflicts if workers from other regions or countries X Under FSC, KFPL is committed to are hired? socially responsible working conditions . uncontrolled human migration into the area, made possible by access roads and transmission lines? X No resettlement will occur . disproportionate impacts on the poor, women, children or other vulnerable groups? X No negative impacts are expected. Project will have positive impacts on these groups by providing regular power supply to the community . community health and safety risks due to the transport, storage, and use and/or disposal of materials likely to X No negative impacts are expected create physical, chemical and biological hazards? • risks to community safety due to both accidental and X Potential for accidental falls into canal natural hazards, especially where the structural and fore bay is unlikely due to remote elements or components of the project (e.g.,dams) are location of facility. Community accessible to members of the affected community or awareness program required. where their failure could result in injury to the community throughout project construction, operation and decommissioning?

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Mase River, Western Province

Instructions:

(i) The project team completes this checklist to support the environmental classification of a project. It is to be attached to the environmental categorization form and submitted to the Environment and Safeguards Division (RSES) for endorsement by Director, RSES and for approval by the Chief Compliance Officer.

(ii) This checklist focuses on environmental issues and concerns. To ensure that social dimensions are adequately considered, refer also to ADB's (a) checklists on involuntary resettlement and Indigenous Peoples; (b) poverty reduction handbook; (c) staff guide to consultation and participation; and (d) gender checklists.

(iii) Answer the questions assuming the “without mitigation” case. The purpose is to identify potential impacts. Use the “remarks” section to discuss any anticipated mitigation measures.

Country/Project Title: Solomon Islands, RETA 7329 Mini hydro Pre-feasibility Study

Sector Division:

A. Basic Project Design Data Mase River, Western Province

1. Dam height, m = no dam

2. Surface area of reservoir, (ha) = no reservoir

3. Estimated number of people to be displaced = nil

4. Rated power output, (MW) = 3.5 MW

Other Considerations:

1. Water storage type: run of river

2. River diversion scheme: in-stream flow regulation

3. Type of power demand to address: base load

211 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS B. Project Location Is the dam and/or project facilities adjacent to or within any of the following areas? . Unregulated river X Natural river arising from the caldera on New Georgia . Undammed river tributaries below the proposed dam X No dam. Small catchment in lower reaches . Unique or aesthetically valuable land or water form X Largest river on island arising for the caldera on the top of the island. . Special area for protecting biodiversity X None reported . Protected Area X None reported . Buffer zone of protected area X Riparian zones on steep sides of river retained as part of logging requirements . Primary forest X Ridge systems generally logged, no logging in steep river catchments

. Range of endangered or threatened animals Check on this from ecological studies . Area used by indigenous peoples X Limited use for hunting, building materials, no garden activity

. Cultural heritage site X None reported in area

. Wetland X

. Mangrove X

. Estuary X

C. Potential Environmental Impacts Will the Project cause… . short-term construction impacts such as soil erosion, X Construction of head race canal on deterioration of water and air quality, noise and steep slopes vibration from construction equipment? . disturbance of large areas due to material quarrying? X No quarrying required. . disposal of large quantities of construction spoils? X Disposal of material from headrace canal corridors but suitable locations available nearby that will not result in debris entering watercourse . clearing of large forested area for ancillary facilities and access road? X Clearing of natural forest for headrace canal and penstock corridors. Minimise width of corridor where appropriate

. impounding of a long river stretch? X No dam or reservoir . dryness (less than 50% of dry season mean flow) over a long downstream river stretch? X None expected with other perennial flows entering river channel below intake structure

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SCREENING QUESTIONS Yes No REMARKS . construction of permanent access road near or through forests? X Use of existing logging roads for much of the access with some new roads required into steep sided valley. Reduce clearance of undisturbed forest where possible

. creation of barriers for migratory land animals X Not expected . loss of precious ecological values due to flooding of X No flooding of lands due to incised river agricultural/forest areas, and wild lands and wildlife channel. No loss of wildlife habitat due habitat; destruction of fish spawning/breeding and to small scale activity. nursery grounds? . deterioration of downstream water quality due to anoxic water from the reservoir and sediments due to soil XS No dam or reservoir erosion? . significant diversion of water from one basin to X The water used in the project is another? returned to the same river system

. alternating dry and wet downstream conditions due to X The water used in the project is peaking operation of powerhouse? returned to the same river system . significant modification of annual flood cycle affecting downstream ecosystem, people’s sustenance and X Flood flows result in high short duration livelihoods? peak discharges, and will not be modified as there is no dam. Bed load material will not be impacted

. loss or destruction of unique or aesthetically valuable X The river system is not unique in New land or water forms? Georgia . proliferation of aquatic weeds in reservoir and downstream impairing dam discharge, irrigation X No reservoir and no dam discharge systems, navigation and fisheries, and increasing water loss through transpiration? . scouring of riverbed below dam? X No dam . downstream erosion of recipient river in trans-basin X No trans basin diversion diversion? . increased flooding risk of recipient river in trans-basin X No trans basin diversion diversion? . decreased groundwater recharge of downstream X No risk areas?

. draining of downstream wetlands and riparian areas? X No risk . decline or change in fisheries below the dam due to reduced peak flows and floods, submersion of river X No dam. stretches and resultant destruction of fish breeding and nursery grounds, and water quality changes? . loss of migratory fish species due to barrier imposed by X No dam the dam? . formation of sediment deposits at reservoir entrance, creating backwater effect and flooding and X No reservoir waterlogging upstream? . significant disruption of river sediment transport X No reservoir. Sediment transport will not downstream due to trapping in reservoir? be impacted . environmental risk due to potential toxicity of sediments X No dam trapped behind the dams? . increased saltwater intrusion in estuary and low lands X Water is returned to the river, no due to reduced river flows? significant reduction in flow due to other perennial stream flows

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SCREENING QUESTIONS Yes No REMARKS . significant induced seismicity due to large reservoir size and potential environmental hazard from catastrophic X No reservoir or dam failure of the dam? . cumulative effects due to its role as part of a cascade of X No dams in river system dams/ reservoirs? . depletion of dissolved oxygen by large quantities of decaying plant material, fish mortality due to reduced X No reservoir or dam, run of river water dissolved oxygen content in water, algal blooms used in project causing successive and temporary eutrophication, growth and proliferation of aquatic weeds? . risks and vulnerabilities related to occupational health and safety due to physical, chemical, biological, and X Physical hazards related to drill and radiological hazards during project construction and blast of volcanic rock at intake structure operation? ad canal corridor can be mitigated with appropriate HSE plan. SIEA is committed to socially responsible working conditions . large population influx during project construction and operation that causes increased burden on social X No risk. Small scale project with no infrastructure and services (such as water supply and large work force sanitation systems)? . creation of community slums following construction of the hydropower plant and its facilities? X No risk. Small scale project with no large work force • social conflicts if workers from other regions or countries X SIEA is committed to socially are hired? responsible working conditions

. uncontrolled human migration into the area, made X No resettlement will occur possible by access roads and transmission lines? . disproportionate impacts on the poor, women, children or other vulnerable groups? X No negative impacts are expected Project will have positive impacts on these groups by providing regular power supply to the community . community health and safety risks due to the transport, storage, and use and/or disposal of materials likely to X No negative impacts are expected create physical, chemical and biological hazards? • risks to community safety due to both accidental and X Potential for accidental falls into canal natural hazards, especially where the structural and fore bay is unlikely due to remote elements or components of the project (e.g.,dams) are location of facility. Community accessible to members of the affected community or awareness program required. where their failure could result in injury to the community throughout project construction, operation and decommissioning?

214 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Mataniko River, Honiara

Instructions:

(i) The project team completes this checklist to support the environmental classification of a project. It is to be attached to the environmental categorization form and submitted to the Environment and Safeguards Division (RSES) for endorsement by Director, RSES and for approval by the Chief Compliance Officer.

(ii) This checklist focuses on environmental issues and concerns. To ensure that social dimensions are adequately considered, refer also to ADB's (a) checklists on involuntary resettlement and Indigenous Peoples; (b) poverty reduction handbook; (c) staff guide to consultation and participation; and (d) gender checklists.

(iii) Answer the questions assuming the “without mitigation” case. The purpose is to identify potential impacts. Use the “remarks” section to discuss any anticipated mitigation measures.

Country/Project Title: Solomon Islands, RETA 7329 Mini hydro Pre-feasibility Study

Sector Division:

A. Basic Project Design Data Mataniko River, Honiara

1. Dam height, m = no dam

2. Surface area of reservoir, (ha) = no reservoir

3. Estimated number of people to be displaced = nil

4. Rated power output, (MW) = 2 – 3.5

Other Considerations:

1. Water storage type: run of river

2. River diversion scheme: in-stream flow regulation

3. Type of power demand to address: base load

215 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS B. Project Location Is the dam and/or project facilities adjacent to or within any of the following areas? . Unregulated river X Natural river . Undammed river tributaries below the proposed dam X A number of perennial streams enter the river below the intake site. Flash flood water rise high up the stream banks . Unique or aesthetically valuable land or water form X Queen Elizabeth National Park and Mataniko waterfall are tourist sites . Special area for protecting biodiversity X Queen Elizabeth National Park

. Protected Area X Queen Elizabeth National Park

. Buffer zone of protected area X None known

. Primary forest X Undisturbed in upper river sections

. Range of endangered or threatened animals X None known

. Area used by indigenous peoples X Up to gorge section

. Cultural heritage site X WW2 battlefield sites on ridges

. Wetland X

. Mangrove X

. Estuary X

C. Potential Environmental Impacts Will the Project cause… . short-term construction impacts such as soil erosion, deterioration of water and air quality, noise and X Drilling and blasting required for head race canal corridor and intake vibration from construction equipment? . disturbance of large areas due to material quarrying? X No quarrying required. . disposal of large quantities of construction spoils? X Disposal of material from headrace canal corridors which runs above steep sided gorge . clearing of large forested area for ancillary facilities and access road? X Modified forest and grasslands on ridges . impounding of a long river stretch? X No dam or reservoir . dryness (less than 50% of dry season mean flow) over a long downstream river stretch? X None expected with other perennial flows entering river channel below intake structure . construction of permanent access road near or through forests? X Access to intake above gorge section . creation of barriers for migratory land animals X Not expected

216 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS . loss of precious ecological values due to flooding of agricultural/forest areas, and wild lands and wildlife X No flooding of lands due to incised river habitat; destruction of fish spawning/breeding and channel. No loss of wildlife habitat due nursery grounds? to small scale activity. . deterioration of downstream water quality due to anoxic water from the reservoir and sediments due to soil X No dam or reservoir erosion? . significant diversion of water from one basin to another? X The water used in the project is returned to the same river system . alternating dry and wet downstream conditions due to peaking operation of powerhouse? X The water used in the project is returned to the same river system . significant modification of annual flood cycle affecting downstream ecosystem, people’s sustenance and X Flood flows result in high short duration livelihoods? peak discharges, and will not be modified as there is no dam. Bed load material will not be impacted . loss or destruction of unique or aesthetically valuable land or water forms? X Impact on waterfall and sink hole as tourist attractions . proliferation of aquatic weeds in reservoir and downstream impairing dam discharge, irrigation X No reservoir and no dam discharge systems, navigation and fisheries, and increasing water loss through transpiration? . scouring of riverbed below dam? X No dam . downstream erosion of recipient river in trans-basin diversion? X No trans basin diversion . increased flooding risk of recipient river in trans-basin diversion? X No trans basin diversion . decreased groundwater recharge of downstream areas? X No risk . draining of downstream wetlands and riparian areas? X No risk . decline or change in fisheries below the dam due to reduced peak flows and floods, submersion of river X No dam stretches and resultant destruction of fish breeding and nursery grounds, and water quality changes? . loss of migratory fish species due to barrier imposed by the dam? X No dam . formation of sediment deposits at reservoir entrance, creating backwater effect and flooding and water X No reservoir logging upstream? . significant disruption of river sediment transport X No reservoir. Sediment transport will not downstream due to trapping in reservoir? be impacted . environmental risk due to potential toxicity of sediments X No dam trapped behind the dams? . increased saltwater intrusion in estuary and low lands X No risk due to reduced river flows? . significant induced seismicity due to large reservoir size and potential environmental hazard from catastrophic X No reservoir or dam failure of the dam? . cumulative effects due to its role as part of a cascade of dams/ reservoirs? X No dams in river system . depletion of dissolved oxygen by large quantities of decaying plant material, fish mortality due to reduced X No reservoir or dam, run of river water dissolved oxygen content in water, algal blooms used in project causing successive and temporary eutrophication, growth and proliferation of aquatic weeds?

217 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

SCREENING QUESTIONS Yes No REMARKS . risks and vulnerabilities related to occupational health and safety due to physical, chemical, biological, and X Physical hazards related to drill and radiological hazards during project construction and blast of volcanic rock at intake structure operation? and canal above gorge can be mitigated with appropriate HSE plan. SIEA committed to socially responsible working conditions . large population influx during project construction and operation that causes increased burden on social X SIEA committed to socially responsible infrastructure and services (such as water supply and working conditions. Close to Honiara sanitation systems)? . creation of community slums following construction of the hydropower plant and its facilities? X No risk, close to Honiara • social conflicts if workers from other regions or countries X SIEA is committed to socially are hired? responsible working conditions . uncontrolled human migration into the area, made possible by access roads and transmission lines? X No resettlement will occur. Close to Honiara

. disproportionate impacts on the poor, women, children X No negative impacts are expected. or other vulnerable groups? . community health and safety risks due to the transport, storage, and use and/or disposal of materials likely to X No negative impacts are expected. create physical, chemical and biological hazards? • risks to community safety due to both accidental and X Potential for accidental falls into canal natural hazards, especially where the structural and fore bay as site is very close to elements or components of the project (e.g.,dams) are Honiara. River is a popular tourist site. accessible to members of the affected community or Community awareness program where their failure could result in injury to the community required. Land slips into gorge as result throughout project construction, operation and of canal failure decommissioning?

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Contacts During Environmental/Social Field Mission

Date Honiara, Guadalcanal

7 Sept Mr Henry Pika Permanent Secretary, Energy, Mines and Rural Electrification

Mr Mark France Manager, Tina River Project

Mr Norman Nichols General Manager, SIEA

Auki, Malaita

10 Sept Mr David Maudua Chief, Kwainoa village, Fiu River

Mr David Maudua Jnr Villager, Kwainoa village, Fiu River

Mr John Wali Villager, Kwainoa village, Fiu River

12 Sept Ms Clara Rikimani Desk Officer, Women’s Development Division

Mr Patrick Talaboe Interim Director, Malaita Chazan Authority

Mr Whitlam Saeni Culture and Values Exchange Centre

Taro, Choiseul Province

13 Sept Mr Alpha Kimata Deputy Premier, Choiseul Province

Ms Helen Nowak Desk Officer, Women’s Development Division

Mr Graham Qaqava Forest Officer, Department of Forestry

Mr Nathan Kiloe Works Officer, Department of Public Works

Mr Joel Dereveke Principal, Choiseul Bay High School

Lata, Temotu Province

20 Sept Mr Bruno Forau Acting Provincial Secretary, Chief Planning Officer

Mr Richard Teao Senior Works Officer, Department of Infrastructure

Mr Harry Mallock Senior Forest Officer, Department of Forestry

21 Sept Mr Edward Daiwo Chairman, Town and Country Planning Board, Provincial Assembly Member Ward 2

Mr Albert Toata Senior Physical Planning Officer

23 Sept Mr Lionel Vaonelua Head teacher, Kati School

Mr John Metailyi Senior School Inspector, Lata

Pastor Sanders Bok Chairman, BOM, Graciosa Bay Community High School

Mr Daiton Mekai Board of Management, GB Community High School

Mr Dudley Kiobe Board of Management, GB Community High School

Mrs Roselyn Lemoba Principal. Mona Community High School

Mr Peter Menivi

Mrs Jennifer Menivi Teacher, Mona Community High School

219 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Ms Rosemary Metopa Mona Community High School

26 Sept Pala Village Community Mathias Wale, John Tauto, Susana Inarepa, Charles Meeting (30) Menagle, Ida Inagu, Hugo Menateti, Titus Balo, John Tauto, Veronica Ikap, Smith Meaio, Issack Meako, Marriam Ihoka, Rose Inone, John Yade, Elsie Iwakania, Albert Melabar, Allan Medaka, Rose Inava, Henry Memuape, Wilfred Meapali, Mark Kapu, Mary Iguai, Albert Melaba, James Lengi, Joel Mali, Dianna Ihahepa, James Bose, Clera Inep, Elisabeth Ilo, Clera Inariki.

28 Sept Mr Philip Arofa Principal Education Officer

Nargiza Gherman Provincial Advisor – Temotu, UNDP Provincial Government Strengthening Program

Buddley Ronnie Provincial Advisor – Temotu, UNDP Provincial Government Strengthening Program

30 Sept Dr Jackson Rakeu Lata Hospital

Mr Augustine Bilve Director of Nursing, Lata Hospital

Ringgi, Western Province

2 Oct Mr Rocky Waete Imbu Rano Lodge, Vila River, Kolombangara Mr Kenneth Etupio Mr David Paenai Mr Chite Silas Mr Figert Roger KFPL, Manager, Forest Resources and Research

Mr Mason

Mase, New Georgia

3 Oct Mr Sale Tupitu Headman, Mase Village plus 45 community members

Honiara, Central Province

5 Oct Mr Kang Yun Jong Chief of Field Office, UNICEF Pacific – Solomon Islands

Mr Fakri Karim Local Capacity Development Specialist, UNDP PGSP

Mr Berni Galgo Provincial Advisor – Malaita, UNDP PGSP

Mr Raj Krishnashrestha Provincial Advisor – Choiseul, UNDP PGSP

220 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Annex 7: Social Analysis This annex contains supporting information to the social and poverty analysis in section 13.

221 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Screening Questions for Resettlement Categorization Probable involuntary resettlement effects Auki Taro Lata Ringgi Mase Honiara Comments Will the project involve any physical √ √ √ √ √ √ Construction of feeder road, canal, small construction work? power house, transmission lines Does the project involve upgrading or X X X X X X No pre-existing physical works rehabilitation of existing physical works? Are any project effects likely to lead to loss of Possible X Removal or Some Possibly some Some use of No housing displacement, some housing, other assets, resource use or displacement trimming of disturbance to interference river for local disturbance to other economic activities incomes/livelihoods? of some some trees conservation with mineral tourism & farming plots, along trans- and ecotourism prospecting hiking removal of mission line area some trees Is land acquisition likely to be necessary? √ √ Along trans- No. Land under √ √ To formalise and maintain access to site mssion line secure lease according to indigenous land traditions; no only by KFPL exclusion of local people. Is the site for land acquisition known? √ √ √ NA √ √ Detailed survey of project area in final design phase Is the ownership status and current usage of √ √ √ √ √ √ Defined traditional boundaries and the land known? ownership Will easements be utilized within an existing X X √ X X X Transmission lines along existing roads right of way? where possible Will there be loss of housing? X X X X X X For most projects, no settlement in vicinity of project site Will there be loss of agricultural plots? An area of X X X X X Only to a small extent in the Auki project shifting plots and no land shortage; disruption minimal Will there be losses of crops, trees and fixed Loss of some Loss of some Along trans- Loss of some Loss of some Loss of some Planned hydro-power plants are small and assets? trees and some trees but in mssion line trees in a trees but in trees but in losses of trees will be restricted to feeder crops little used area and road conservation little used area little used area road and canal construction and clearance area for transmission lines. Will there be losses of businesses or X X X Possibly X Possibly enterprises? Will there be losses of incomes or livelihoods? X X X Possibly X Possibly Will people lose access to facilities, services X X X Possibly X Possibly Very little change to river flow. People are or natural resources? more likely to gain access to services and facilities

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Probable involuntary resettlement effects Auki Taro Lata Ringgi Mase Honiara Comments Will land-use related changes affect any social Feeder road Area already Some loss of Established Area already Area used for . or economic activities? and canal way logged, little food trees conservation logged, little some local will improve local use. and ecotourism local use. tourism access in the area area If involuntary resettlement effects are NA NA NA NA NA NA No involuntary resettlement effects expected: expected • Are local laws and regulations compatible with ADB’s policy on involuntary resettlement? • Will coordination between Provincial Governments responsible for government agencies be required to land negotiations deal with land acquisition? • Are sufficient skilled staff available NA NA NA NA NA NA No involuntary resettlement effects in the executing agency for expected resettlement planning and implementation? • Are training and capacity-building NA NA NA NA NA NA No involuntary resettlement effects interventions required prior to expected resettlement planning and implementation?

31/25866 November 2010 Page 224 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES

Initial Poverty and Social Analysis (IPSA) Report

RETA 7329: PROMOTING ACCESS TO RENEWABLE ENERGY IN THE PACIFIC: Country/Project Title: SOLOMON ISLAND COMPONENT

Lending/financing

Modality Dept/Division: Energy

I. POVERTY ISSUES

A. Linkages to the National Poverty Reduction Strategy and Country Partnership Strategy 1. Based on the country poverty assessment, the country partnership strategy, and the sector analysis describe how the project would directly or indirectly contribute to poverty reduction and how it is linked to the poverty reduction strategy of the partner country.

The principal purpose of the project is to extend electricity supply to provincial centres and their environs, and improve its reliability and cost, but the project will provide wider benefits in the form of equitable and sustainable improvements to the well- being of various groups of people. The project carries minimal risk of creating social costs for, or marginalizing, vulnerable people, but instead has real potential to mitigate existing disadvantages. The wider benefits of the project are in line with the intention and purpose of the national development plan, of building better lives for all Solomon Islanders, in particular to improve access to income-generating opportunities, improve access to basic services, and provide for an even distribution of the benefits of growth and the development of all provinces.60 ADB’s Country Program Strategy (CPS) notes that the Solomon Island economy is based on primary commodities from agriculture, forestry, and fishing, and alternative income-generating opportunities are scarce in rural areas. The CPS seeks to reduce poverty by promoting equitable private-sector-led economic growth through improved transportation infrastructure and services and a stronger business enabling environment. Development of hydropower resources to serve provincial centres and surrounding communities will assist the Strategy by increasing income-generating opportunities, improving access to markets and basic services and improving living conditions, especially for women. Project activities and outcomes will contribute to progress on several MDGS, in particular 1, to reduce poverty; 2. to increase primary school attendance; 3. to reduce infant mortality; and 4. to improve gender equity by increasing women’s access to reproductive health, education and other opportunities.

B. Targeting Classification 1. Select the targeting classification of the project:  General intervention  I ndividual or Household (TI -H);  Geographic (TI -G);  N on-income MD Gs (TI -M1, M 2, etc.) 2. E xplain the basis for the targeting classification: The proposed project is classified in the energy sector and by subthemes as inclusive social development and sustainable economic growth. The targeting classification is geographic, as the project focuses on developing renewable electricity systems for populations in and around under-served provincial centres and addresses a significant constraint on development of these areas. The project requires a more extensive Social Analysis (SA) report in the project design stage, with special attention to poverty, gender, consultation, other social safeguard issues, involuntary resettlement and indigenous peoples.

C. Poverty Analysis 1. If the project is classified as TI-H, or if it is policy-based, what type of poverty impact analysis is needed?

2. What resources are allocated in the project preparatory technical assistance (PPT A)/due diligence?

3. If GI, is there any opportunity for pro-poor design (e.g., social inclusion subcomponents, cross subsidy, pro-poor governance, and pro-poor growth)? The proposed project provides significant opportunities for pro-poor design, social inclusion subcomponents and pro-poor growth. By developing a renewable energy source, it will provide more reliable and cost-effective power, extend these power systems to under-served areas, including poor and disadvantaged households, meanwhile addressing other forms of disadvantage such as poor access to markets and basic services and the poverty, gender inequalities and other issues that extend from this poor access. Full realisation of this potential will not occur automatically, however. In order for it to happen, the enabling environment for inclusive planning, gender equity, community development, small enterprise growth and the like will

60 Solomon Island Government, 2010. Framework for the National Strategic Plan for the Solomon Islands: Building Better Lives for All Solomon Islanders.

31/25866 November 2010 TA 7329- Promoting Access to Renewable Energy in the Pacific Mini Hydro PRE-FEASIBILITY STUDIES need to be nurtured through other supporting development programs, some of which are already being implemented in Solomon Islands by provincial and national governments, NGOs and aid partners. II. SOCIAL DEVELOPMENT ISSUES

A. Initial Social Analysis Based on existing information: a. Who are the potential primary beneficiaries of the project? How do the poor and the socially excluded benefit from the project? • .

b. What are the potential needs of beneficiaries in relation to the proposed project? • Consumer education, so that people can use the electricity supply in efficient and safe ways. • Community development, to maximise the potential for new livelihood development, especially in disadvantaged communities and among disadvantaged groups, such as women and youth. • Establishment of a legal agreement with landowners that recognises their contribution of resources to the project as well as to the lower cost structure of hydro-electricity compared to diesel generated electricity. Rather than a one-off payment (which usually goes only to senior men and on non-productive assets) the landowner community’s share in the financial benefit of improved efficiency of production (yet to be calculated) could be provided in perpetuity through a development trust fund type arrangement. The landowner agreement and the proposed trust fund need to be formulated in a consultative and socially inclusive way between the landowners, the government and SIEA. c. What are the potential constraints in accessing the proposed benefits and services, and how will the project address them? The cost of electricity can inhibit its use, especially in poor households. • Use of hydropower, instead of diesel generation, provides for lower cost and more reliable electricity supply. These potential cost benefits will be passed on to SIEA in the first instance. SIEA will decide whether and how they will be incorporated into a common national tariff or apply to a particular area or group of consumers. • Consumer education will help people use electricity in efficient and safe ways, and the capacity of SIEA to provide this will be strengthened. • People expect that new economic opportunities will make electricity affordable, and are prepared to pay for improved living conditions. • The use of prepaid meters will help households to stay within their means. New livelihood opportunities may not be evident or accessible, particularly to disadvantaged communities and groups. • Many potential economic opportunities have been identified in provincial development plans, and by communities and individuals. Present economic stagnation disadvantages the entire community. • Community and small enterprise development programs to maximise the potential for new livelihood development will be conducted through local NGOs, government agencies or finance institutions. • Small-scale credit modalities will be explored, including through the GAD action plan. • B. Consultation and Participation 1. Indicate the potential initial stakeholders • Landowners who will enter into a legal agreement with the SI Government and SIEA providing for use of their land resources and a share of the potential cost benefits of hydropower generation, proposed here to be in perpetuity through a development trust fund type arrangement. • Households in areas in and around the provincial centres that will gain electricity supply. •

2. What type of consultation and participation (C&P) is required during the PPT A or project processing (e.g., workshops, community mobilization, involvement of nongovernment organizations [NGOs] and community-based organizations [CBOs], etc.)? • Formulation of legal agreement between landowners, the SI Government and SIEA. • Proposed formulation of a development trust fund type arrangement with the landowner community, to be conducted in a collaborative and socially inclusive manner. • Community development or mobilization programs, involving local NGOs, government, or finance institutions. • Community education programs on efficient and safe electricity use, involving SIEA.

3. What level of participation is envisaged for project design?

 Information sharing  Consultation  Collaborative decision making  Empowerment7

4. Will a C&P plan be prepared?  Yes  No Please explain.

C. Gender and Development

1. What are the key gender issues in the sector/subsector that are likely to be relevant to this project/program?

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2. Does the proposed project/program have the potential to promote gender equality and/or women’s empowerment by improving women’s access to and use of opportunities, services, resources, assets, and participation in decision making?9  Yes  No Please explain. {If yes, a gender action plan should be prepared during PPT A/due diligence.}

5. Access to electricity supply brings particular benefits to women. It can improve family living conditions by providing better lighting at night and better food shortage through refrigeration. It can also reduce the physical or time burden of some household tasks, and create opportunities for small business and other forms of income-generation. While the cost of electricity can be a constraint to household use, many people interviewed believed that the opportunities created by a reliable power supply could balance out the costs involved. Despite its cost, electricity is a very desired good. 6. Difficulties of access to services and markets particularly disadvantage women.

3. Could the proposed project have an adverse impact on women and/or girls or to widen gender inequality?  Yes  No Please explain {If yes, actions/measures should be prepared during PPT A/due diligence.} The project is more likely to reduce all forms of disadvantage and thereby reduce gender disparities in access to basic services and economic and social resources. The project has potential to improve conditions for women, reduce the physical and time burdens of their household work and improving living conditions, and reduce gender inequality by providing better access to health and education services and increasing livelihood opportunities.

III. SOCIAL SAFEGUARD ISSUES AND OTHER SOCIAL RISKS11 Issue Nature of social issue Significant/Limited/ Plan or other action required No impact/ Not known

Involuntary resettlement No involuntary resettlement No impact  Full plan involved, other than some disturbance to garden plots in  Short plan Fiu Valley, Malaita  Resettlement framework  No action  Uncertain

Indigenous peoples Indigenous ownership of Significant.  Plan access to and use of land Landowner agreement to be resources negotiated  Other action16  Indigenous peoples framework  No action  Uncertain Better access to markets Labor Potential for wider economic  Plan and social participation for GAD Plan to increase access  Employment opportunities both men and women to new livelihood  Other action18  Labor retrenchment opportunities  No action  Core labor standards  Uncertain

Affordability Necessity to ensure that low Consumer education  Action income households benefit activities to encourage from new service efficient, safe use of  No action elelctricity  Uncertain

Other risks and/or Some risk of social Community and gender  Plan disturbance by outsider development programs vulnerabilities workers and new inflow of operating through existing  Other action cash government and NGO   HIV/AIDS programs No action  Human trafficking  Uncertain  Others (conflict, political instability, etc.), please specify IV. PPTA/DUE DILIGENCE RESOURCE REQUIREMENT

1. Do the terms of reference for the PPT A (or other due diligence) include poverty, social, and gender analyses and the relevant specialist/s?  Yes  No If no, please explain why.

2. Are resources (consultants, survey budget, and workshop) allocated for conducting poverty, social and/or gender analysis, and C&P during the PPT A/due diligence?  Yes  No If no, please explain why.

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Involuntary Resettlement Impact Categorization Checklist

Probable Involuntary Resettlement Effects Not Yes No Remarks Known

Involuntary Acquisition of Land

x Land access and use agreements 1. Will there be land acquisition? will be negotiated with indigenous landowners.

x Sites have been identified. Exact 2. Is the site for land acquisition known? areas will be known at the next stage of project design.

x In regard to being either indigenous owned or alienated land, ownership status is well known. Discussions held with landowner groups found 3. Is the ownership status and current usage of land to be support for the project. However, for acquired known? most sites the genealogies from which land ownership is claimed are undocumented. Uncertainty about this can complicate land-use negotiations.

X Where possible, access roads and transmission lines will follow existing 4. Will easement be utilized within an existing Right of Way roads, often remnants of logging (ROW)? operations. However, these are not necessarily legally recognised ROW.

5. Will there be loss of shelter and residential land due to land x Apart from Auki, the proposed sites are in areas where there are no acquisition? residents.

x Not for most sites. In Auki, there will be some disturbance of trees and 6. Will there be loss of agricultural and other productive assets displacement of gardens. The full extent will be known at the next due to land acquisition? design phase. In Lata, timber and food trees will be cleared along the transmission line route.

X Not for most sites. In Auki, there will be removal of some timber and food 7. Will there be losses of crops, trees, and fixed assets due to trees and displacement of gardens. In Lata, timber and food trees need land acquisition? to be cleared along the transmission line route. The full extent will be known at the next design phase.

X No. There may however be some 8. Will there be loss of businesses or enterprises due to land disruption during construction to a neighbouring ecotourism business acquisition? on Ringgi, and to hiking trail along Mataniko River.

X Not for most sites. For Auki and 9. Will there be loss of income sources and means of Lata, in respect of some timber and livelihoods due to land acquisition? food trees and displacement of gardens.

Involuntary restrictions on land use or on access to legally designated parks and protected areas

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x The Ringgi site is in a recognised conservation area. There may be 10. Will people lose access to natural resources, communal some disruption during construction facilities and services? to a neighbouring ecotourism business, and also to a hiking trail along Mataniko River.

11. If land use is changed, will it have an adverse impact on X No long-term land use change is social and economic activities? anticipated.

X Residents will not be excluded from 12. Will access to land and resources owned communally or acquired areas for traditional by the state be restricted? purposes such as hunting or vegetation harvesting.

Information on Displaced Persons:

Any estimate of the likely number of persons that will be displaced by the Project? [ ] No [ X ] Yes If yes, approximately how many? ______None_____

Are any of them poor, female-heads of households, or vulnerable to poverty risks? [x] No [ ] Yes

Are any displaced persons from indigenous or ethnic minority groups? [x] No [ ] Yes

Note: Additional information on the project is provided in Section 13 of the report.

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INDIGENOUS PEOPLES IMPACT CATEGORIZATION

Date: _October, 2011______

A. Instructions (i) The project team completes and submits the form to the Environment and Safeguards Division (RSES) for endorsement by RSES Director, and for approval by the Chief Compliance Officer (CCO). (ii) The classification of a project is a continuing process. If there is a change in the project components or/and site that may result in category change, the Sector Division submits a new form and requests for recategorization, and endorsement by RSES Director and by the CCO. The old form is attached for reference. (iii) The project team indicates if the project requires broad community support (BCS) of Indigenous Peoples communities. BCS is required when project activities involve (a) commercial development of the cultural resources and knowledge of indigenous peoples, (b) physical displacement from traditional or customary lands; and (c) commercial development of natural resources within customary lands under use that would impact the livelihoods or the cultural, ceremonial, or spiritual use that define the identity and community of indigenous peoples. (iv) In addition, the project team may propose in the comments section that the project is highly complex and sensitive (HCS), for approval by the CCO. HCS projects are a subset of category A projects that ADB deems to be highly risky or contentious or involve serious and multidimensional and generally interrelated potential social and/or environmental impacts.

B. Project Data

Country/Project No./Project : RETA 7329: PROMOTING ACCESS TO RENEWABLE ENERGY IN THE PACIFIC: Title SOLOMON ISLAND COMPONENT

Department/ Division :

Processing Stage : Pre-feasibility

Modality :

[ ] Project Loan [ ] Program Loan [ ] Financial Intermediary [ ] General Corporate Finance [ ] Sector Loan [ ] MFF [ ] Emergency Assistance [ ] Grant [ ] Other financing modalities:

C. Indigenous Peoples Category

[ X ] New [ ] Recategorization ― Previous Category [ ]

[ ] Category A [ ] Category B [ ] Category C [ ] Category FI

D. Project requires the broad community support of [ X ] Yes [ ] No affected Indigenous Peoples communities.

E. Comments

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Project Team Comments: RSES Comments: The Solomon Islands population is almost entirely indigenous and most land is traditionally owned. Landowners are therefore not minority groups and their rights are acknowledged and respected in Solomon Islands law. Two proposed sites, at Lata (Temotu Province) and Ringgi (Kolombangara Island) are on – or partly on - land that in the past was alienated from indigenous ownership and is now under State and KFPL leasehold, respectively. This tenure is known and not disputed. For the other four sites (and for the transmission line route at Lata) land access and use agreements need to be negotiated with indigenous landowners. Principal responsibility for these negotiations lies with the provincial governments. At this stage of project preparation, all landowning groups have expressed full support for the project. However, land-use negotiations in Solomon Islands can be complex and difficult. Excessive demands for financial compensation could make development of some sites unfeasible, as may already be the case for the Mataniko River site.

F. Approval

Proposed by: Reviewed by:

Project Team Leader, {Department/Division} Social Safeguard Specialist, RSDD/RSES

Date: Date:

Endorsed by:

Social Development Specialist, {Department/Division} Director, RSES

Date: Date:

Endorsed by: Approved by: Highly Complex and  Sensitive Project

Director, {Division} Chief Compliance Officer

Date: Date:

Indigenous Peoples Impact Screening Checklist

KEY CONCERNS NOT YES NO Remarks (Please provide elaborations KNOWN on the Remarks column)

A. Indigenous Peoples Identification

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KEY CONCERNS NOT YES NO Remarks (Please provide elaborations KNOWN on the Remarks column)

1. Are there socio-cultural groups present in or use the X The SI population is almost project area who may be considered as "tribes" (hill entirely indigenous, and most tribes, schedules tribes, tribal peoples), "minorities" land is traditionally owned. (ethnic or national minorities), or "indigenous Landowners are therefore not minority groups. communities" in the project area?

2. Are there national or local laws or policies as well as X The rights of indigenous anthropological researches/studies that consider these landowners are acknowledged groups present in or using the project area as belonging and respected in SI law, but to "ethnic minorities", scheduled tribes, tribal peoples, they are not considered to be minority groups. national minorities, or cultural communities?

X SI is a cultural diverse country, in a Melanesian context. 3. Do such groups self-identify as being part of a distinct Landownership is based on genealogical descent which social and cultural group? may include social identity, but not as a distinct minority group.

4. Do such groups maintain collective attachments to X In all parts of the country, Solomon Islanders have a distinct habitats or ancestral territories and/or to the strong attachment to their natural resources in these habitats and territories? ancestral land.

5. Do such groups maintain cultural, economic, social, X Indigenous identity and land – and political institutions distinct from the dominant society ownership is usual in SI, not and culture? an exceptional situation

X Many languages are spoken in SI, distinguished more by 6. Do such groups speak a distinct language or dialect? island or district than by descent group, but distinct dialects may exist.

7. Has such groups been historically, socially and X Indigenous landownership economically marginalized, disempowered, excluded, does not denote minority and/or discriminated against? status in SI

8. Are such groups represented as "Indigenous Peoples" X SI has a culturally diverse, or as "ethnic minorities" or "scheduled tribes" or "tribal predominantly indigenous populations" in any formal decision-making bodies at the population and this is reflected national or local levels? in its system of government

B. Identification of Potential Impacts

X SI has a predominantly indigenous population. Landowner groups at project 9. Will the project directly or indirectly benefit or target sites will benefit from project Indigenous Peoples? outcomes and also from land access/use agreements to be negotiated through provincial governments.

10. Will the project directly or indirectly affect Indigenous X Peoples' traditional socio-cultural and belief practices? (e.g. child-rearing, health, education, arts, and governance)

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KEY CONCERNS NOT YES NO Remarks (Please provide elaborations KNOWN on the Remarks column)

11. Will the project affect the livelihood systems of X By providing electricity, the Indigenous Peoples? (e.g., food production system, project will potentially increase natural resource management, crafts and trade, access to social and economic employment status) opportunities

X Although ancestral domain, most project sites are in little 12. Will the project be in an area (land or territory) used areas, away from occupied, owned, or used by Indigenous Peoples, and/or residences and gardens. Care claimed as ancestral domain? will be taken not to disturb Tabu sites (places of cultural significance).

C. Identification of Special Requirements

Will the project activities include:

13. Commercial development of the cultural resources X and knowledge of Indigenous Peoples?

X No displacement is involved, 14. Physical displacement from traditional or customary nor any future exclusion from lands? hydropower sites and transmission routes.

X The small hydropower plants 15. Commercial development of natural resources (such proposed will use (and as minerals, hydrocarbons, forests, water, hunting or replace) river water as well as fishing grounds) within customary lands under use that small areas of land, but in ways that at most would only would impact the livelihoods or the cultural, ceremonial, minimally impact local spiritual uses that define the identity and community of livelihoods. Landowners may Indigenous Peoples? benefit from improved access to markets and services.

16. Establishing legal recognition of rights to lands and X territories that are traditionally owned or customarily used, occupied or claimed by indigenous peoples ?

X Legal agreements to access and use areas of indigenous- owned land will be negotiated 17. Acquisition of lands that are traditionally owned or according to SI law and practice, through provincial customarily used, occupied or claimed by indigenous governments. This will be for peoples? construction and maintenance of the hydropower plants and will not entail future exclusion of landowners from the areas.

D. Anticipated project impacts on Indigenous Peoples

Project component/ Anticipated positive effect Anticipated negative effect activity/ output

1. Legal agreements to access and use areas of Landowners get financial and Excessive demands for financial compensation indigenous- owned land to be negotiated development benefits from their land could make projects unfeasible, as may already according to SI law and practice. holding, optimally as an in-perpetuity be the case for the Mataniko River site. arrangement that recognises the cost-

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saving created by hydropower generation, Capture of benefits by a small group of senior and that invests in community assets. men could prevent wider distribution of benefits to the landowning community.

2. Construction of the hydropower plants Paid employment for landowners and Some possible disruption to the community by other people from local communities. construction activities, the presence of a small group of expert workers, and a sudden inflow of cash into the area.

3. Operation of the hydropower plants A small amount of paid employment for No negative effects anticipated landowners or other community people to monitor and maintain the intake, canals and power-house.

The benefits of electrification for the community and individual households. Possibly improved access to services and markets using access roads built during the construction of the hydropower plant or maintained along transmission routes.

Note: Additional information on the project and each proposed site is provided in Section 13 of the full report.

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Annex 8 Stakeholder Analysis

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