ADB veitnam

Asian Development Bank Electricity of Vietnam

TA 4625-VIE Song Bung 4 Hydropower Project

Phase II

Main Report

January 2007

Fina

l Rep

ort

ASIAN DEVELOPMENT BANK

ELECTRICITY OF VIETNAM

TA 4625-VIE Song Bung 4 Hydropower Project, Phase II

FINAL REPORT

MAIN REPORT

January 2007

Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report Report Structure

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Song Bung 4 Hydropower Project Phase II, TA No. 4625-VIE

Final Report

Report Structure Main Report

Environmental Impact Assessment (EIA)

Resettlement and Ethnic Minority Development Plan (REMDP)

Volume 1: Cross Cutting Issues Volume 2: Reservoir Resettlement and Development Plan Volume 3: Project (Construction) Lands Resettlement Plan Volume 4: Down/Upstream Mitigation and Resettlement Plan

Social Management Plan Gender Action Plan

Consultation Report Annex: Social Reports from the Local Consultants

Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report- Main Report Table of Content

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Song Bung 4 Hydropower Project Phase II, TA No. 4625-VIE

Final Report

Main Report

Table of Contents

1 INTRODUCTION 1 1.1 BACKGROUND 1 1.2 1.2.1 1.2.2 1.2.3

THE ENERGY SECTOR IN VIETNAM Institutional Background Generation System Energy and Power Demand

2223

1.3 1.3.1 1.3.2 1.3.3 1.3.4 1.3.5 1.3.6

THE PPTA General Phase I of the PPTA Overall Objective Objective of Draft Final Report Summary of Activities Acknowledgement

4455668

1.4 1.4.1 1.4.2 1.4.3

OVERVIEW OF HYDROPOWER DEVELOPMENT IN VU GIA-THU BON RIVER BASIN General Existing and Hydropower Projects under Construction Planned Hydropower Projects

889

10

2 SONG BUNG 4 HYDROPOWER PROJECT 16 2.1 GENERAL 16


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2.2 2.2.1 2.2.2 2.2.3 2.2.4 2.2.5 2.2.6 2.2.7 2.2.8 2.2.9 2.2.10 2.2.11 2.2.12 2.2.13

PROJECT COMPONENTS ACCORDING TO FEASIBILITY STUDY General Reservoir Dam Structure Spillway Intake Headrace Tunnel Surge Tank Penstock Power Station and Switchyard Tailrace Canal Transmission Line Access Roads Relocation of Highway 14 D

1919191920202020202021212121

2.3 2.3.1 2.3.2 2.3.3 2.3.4 2.3.5

COMMENTS AND SUGGESTED MODIFICATIONS Estimated Inflow for Song Bung 4 Hydropower Project Technical Issues Minimum Operating Level Compensation Flow Energy Production

212123242525

2.4 2.4.1 2.4.2 2.4.3

LIKELY OPERATION REGIME OF SONG BUNG 4 HPP General Seasonal Reservoir Operation Daily Reservoir Operation

26262728

2.5 2.5.1 2.5.2 2.5.3

DOWNSTREAM HYDROLOGICAL REGIME General Changes in the Seasonal Regime Changes in the Daily Regime

29292932

2.6 MULTIPURPOSE ASPECTS 34


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2.7 RISKS 35 3 TECHNICAL REVIEW OF FEASIBILITY STUDY 35 3.1 3.1.1 3.1.2

OVERALL LAYOUT General Consideration on the Installed Capacity

353536

3.2 REVIEW OF GEOLOGICAL & GEOTECHNICAL CONDITIONS 373.2.1 3.2.2 3.2.3 3.2.4 3.2.5 3.2.5

Introduction Geological Conditions in the Project Area Considerations on the Design of the Rock Support in Tunnels Considerations Regarding Unit Rates of Underground Works Construction Material Conclusions and Recommendations

374346515254

3.3 3.3.1 3.3.2 3.3.3 3.3.4 3.3.5 3.3.6 3.3.7 3.3.8 3.3.9 3.3.10 3.3.11

REVIEW OF DAM STRUCTURE Review of Dam Site and Dam Type Selection Gravity Dam Design Review of Spillway Diversion Arrangements RCC Mix Design Construction Methodology Placement Rates and Plant Capacity RCC Manufacture, Transport and Placement Foundation Treatment Comments on Unit Rates on RCC Arrangements for Dam Safety Monitoring

545456656667697375797980

3.4 3.4.1 3.4.2 3.4.3 3.4.4

REVIEW OF WATERWAY Intake Headrace Tunnel Surge Tank Penstock

8383838485


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3.5 REVIEW OF POWER STATION 863.5.1 3.5.2 3.5.3 3.5.4

Layout in the Feasibility Study Number of Units Engineering Geological Features Considerations Regarding Location of an Underground Powerhouse

86888889

3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6 3.6.7 3.6.8 3.6.9

REVIEW OF ELECTROMECHANICAL EQUIPMENT Gates Turbines Hydraulic Stability Auxiliary Equipment in the Power Station Single Line Diagram Generators Generator Transformer 220 kV Switchgear Auxiliary Power Systems

91919192939394949595

3.7 3.7.1 3.7.2

REVIEW OF TRANSMISSION General Transmission Line

959595

4 TENTATIVE CONSTRUCTION SCHEDULE 96 4.1 DAM STRUCTURE AND RIVER DIVERSION 96 4.2 WATERWAY 96 4.3 POWER STATION AND EQUIPMENT INSTALLATION 97 4.4 TRANSMISSION 97 4.5 INITIAL FILLING OF SONG BUNG 4 RESERVOIR 97 4.6 OVERALL TENTATIVE CONSTRUCTION SCHEDULE 98


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5 TENTATIVE COST ESTIMATE

98

5.1 REVIEW OF COST ESTIMATE IN FEASIBILITY STUDY 985.1.1 Preparatory Works 985.1.2 5.1.3 5.1.4 5.1.5

Civil Works Mechanical and Electrical Works Transmission Engineering and Administration

9999

100100

5.2 ENVIRONMENTAL MANAGEMENT COSTS 100 5.3 RESETTLEMENT AND SOCIAL MITIGATION COSTS 100 5.4 IMPLEMENTATION SUPPORT 100 5.5 COST STRUCTURING 100 5.6 TENTATIVE TOTAL INVESTMENT COST 101 6 IMPLEMENTATION AND PROCUREMENT 102 6.1 6.1.1 6.1.2 6.1.3

PROJECT IMPLEMENTATION Implementation Schedule Implementation Agency Project Implementation

102102103106

6.2 PROCUREMENT PLAN 107 7 ECONOMIC ANALYSIS 108 7.1 GENERAL 108 7.2 7.2.1

MACROECONOMIC AND SECTOR CONTEXT Macroeconomics

108108


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7.2.2 Power Sector Issues and Challenges 109 7.3 DEMAND ANALYSIS 110 7.4 LEAST COST SYSTEM EXPANSION PLAN OF THE VIETNAM

POWER SECTOR 113

7.4.1 7.4.2

General Existing Generating System

113113

7.4.3 7.4.4 7.4.5

Options for Expansion of the Generation System System Planning Methodology Least-Cost Expansion Generation Plan up to 2025

113114115

7.5 ECONOMIC VALUATION OF COSTS AND BENEFITS OF SONG

BUNG 4 HYDROPOWER PROJECT 116

7.5.1 7.5.2 7.5.3

General Costs Benefits

116116117

7.6 SENSITIVITY ANALYSIS 123 7.7 CONCLUSION 125 8 FINANCIAL ANALYSIS 125 8.1 INTRODUCTION 125 8.2 8.2.1 8.2.2

COST ANALYSIS OF PROPOSED INVESTMENTS Cost Estimates Financing Plan

125125128

8.3 8.3.1 8.3.2 8.3.3 8.3.4

FINANCIAL ANALYSIS OF PROPOSED INVESTMENT Capital Costs Output and Tariffs Operating Costs Weighted Average Cost of Capital

130131131131132


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8.3.5 8.3.6 8.3.7

FIRR Calculation Sensitivity Analysis Financial Statement for Song Bung 4 Hydropower Project

132133134

8.4 8.4.1 8.4.2 8.4.3 8.4.4 8.4.5 8.4.6 8.4.7 8.4.8

PAST FINANCIAL PERFORMANCE OF EVN Introduction Historical Performance Sales and Income Production and Supply Operating Costs Capital Expenditure Overall Position Compliance with Covenants

135135135136137139139139140

8.5 8.5.1 8.5.2

FUTURE FINANCIAL PERFORMANCE OF EVN General Outline of New Business Model

140140141

8.6 8.6.1 8.6.2 8.6.3 8.6.4 8.6.5 8.6.6 8.6.7 8.6.8 8.6.9 8.6.10 8.6.11 8.6.12 8.6.13

FINANCIAL MANAGEMENT CAPABILITY OF EVN/HPPMB3 Introduction Executing and Implementing Agency Flow of Funds Repaying the Loan Staffing Accounting Policies Budgeting System and Payments Policies and Procedures Cash and Bank Safeguard over Assets Reporting Internal Audit and External Audit Conclusions and Recommendations

144144145147148149150151151152152152153154


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List of Annexes Annex 1 EVN's Historical Financial Statements

Annex 2 Details of EVN’s Business Model

Annex 3 Data Input for EVN’s Business Model

Annex 4 Business Model of EVN-User Guide

Annex 5 Financial Management Assessment Questionnaire

Annex 6 Examples of Job Descriptions in Finance Department of HPPMB3

Annex 7 List of Documents Prepared for ISO 9001

List of Tables Table 1 Monthly Energy Production at Song Bung 4 Hydropower Project

Table 2 Tentative Cost Estimate

Table 3 Power Demand Forecast - Master Plan VI

Table 4 Existing Generating Capacity

Table 5 Power Projects Considered in Master Plan VI and Scheduled Commissioning

Table 6 Forecast Profit and Loss Statement in USD for Song Bung 4 Hydropower Project,2008-2047

Table 7 Forecast Balance Sheets in USD for Song Bung 4 Hydropower Project,2008-2047

Table 8 Forecast Cash Flow Statements in USD for Song Bung 4 Hydropower Project,2008-2047

Table 9 Forecast Profit and Loss Statement in VND for Song Bung 4 Hydropower Project,2008-2047

Table 10 Forecast Balance Sheets in VND for Song Bung 4 Hydropower Project,2008-2047

Table 11 Forecast Cash Flow Statements in VND for Song Bung 4 Hydropower Project,2008-2047

List of Figures

Figure 1 Location of Hydropower Plants in Vietnam

Figure 2 Tentative Construction Schedule

Figure 3 Tentative Implementation Schedule

Figure 4 Organization Chart for Project management of Song Bung 4 Hydropower Project

Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report-Main Report List of Abbreviations

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Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report Main Report

List of Abbreviations % percent 3D Three Dimension AC Aluminium Conductor ADB Asian Development Bank b.c.m Billion Cubic Meters B/C Benefit Cost BL Base Line Bn Billion BOT Build Operate and Transfer DAF Development Assistance Fund DARD Department of Agriculture and Rural Development DONRE Department of Natural Resources and Environment EC Export Credit EIA Environmental Impact Assessment ElRR Economic Internal Rate of Return EMP Environmental Management Plan ENS Energy Not Served ERA Electricity Regulatory Authority EVN Electricity of Vietnam EVN HQ Electricity of Vietnam Headquarter FIRR Financial Internal Rate of Return FS Feasibility Study FSL Full Supply Level GAF Generation and Fuel GDP Gross Domestic Product GoV Government of Vietnam GWh Gigawatt hour HH Household HPP Hydropower Project HPPMB3 Hydro Power Project Management Board No. 3 HV High Voltage IAS International Accounting Standard ICB International Competitive Bidding ICM Independent Creditors Model IDC Interest during Construction IOE Institute of Energy IPP Independent Power Producer IRR Internal Rate of Return JBIC Japan Bank for International Cooperation JV Joint Venture km Kilometre km2 Square Kilometre Kv Kilovolt kWh Kilowatt Hour


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kPa Kilo Pascal kV Kilovolt kWh Kilowatt hour LCB Local Competitive Bidding LF Load Factor LFA Load Factor Adjustment LOLE Loss of Loss Expectation LRMS Long Run Marginal Cost m Meter m.a.s.l Metre above sea level m³ Cubic metre m³/s Cubic metre per second mm Millimetre m3 Cubic metres Mm3 Million cubic metres MOF Ministry of Finance MOI Ministry of Industry MOL Minimum Operating Level MoNRE Ministry of Natural Resources and Environment MUSD Million US Dollar MW Megawatt NGO Non Governmental Organisation NIAPP National Institute of Agriculture Planning and Projection NPPMB Northern Project Power Management Board NPV Net Present Value NTFP Non-timber forestry products O&M Operation and Maintenance ODA Official Development Assistance PC3 Power Company 3 PCR Project Completion Report PECC3 Power Engineering Consulting Company No. 3 PFS Pre-Feasibility Study PMB Project Management Board PP Power Plants PPTA Project Preparation Technical Assistance Q Tunnelling Quality Index QCBS Quality Cost Based Selection RCC Roller Compacted Concrete REMDP Resettlement Ethnic Minority Development Plan RRP Report and Recommendations to President SB4HPC Song Bung 4 Hydro Power Company SB4HPP Song Bung 4 Hydro Power Project SERF Shadow Exchange Rate Factor SIA Social Impact Assessment SIDA Swedish International Development Authority SIWRR Southern Institute of Water Resources Research SOE State Owned Enterprise T&D Transmission and Distribution ToC Table of Content TPS Thermal Power Station TWh Terawatt hours UNDP United Nations Development Program USc US cent


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USD US Dollar VAT Value Added Tax VND Vietnamese Dong WACC Weighted Average Cost of Capital WB DSM World Bank Demand Side Management WRRC Water Resource Review Committee WVF World Village Foundation WWF World Wildlife Foundation


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Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report

Main Report

1 Introduction

1.1 Background Vietnam stretches over 1,600 km along the eastern cost of the Indochina Peninsula with an area of nearly 330,000 km2. In 2001, Vietnam’s population was estimated at nearly 80 million, making it the 13th most populous country in the world. Some 80% of the population is ethnic Vietnamese while the rest is made up of over 50 ethno-linguistic groups.

Three-quarters of Vietnam consists of mountains and hills, and the country has an abundance of water with the total annual water resources estimated at 880 billion m3. The tropical monsoon climate, however, profoundly affect the quantity and distribution of water. Rainfall is highly uneven, causing frequent and often disastrous floods. Mean rainfall is about 2,000 mm, but most accumulates between May and November when about 70-75% of the annual flow is generated.

The mountainous topography and the abundance of water create the possibility of hydropower development to cover the future energy demand for a sustainable economic development of the country.

Vietnam is well endowed with rivers with the Red River in the north and the Mekong River in the south ranking among the largest rivers in the world. Hydropower potential in the Red and Mekong rivers is limited apart from the Red River tributaries of Da and Lo-Gam-Chay that exhibits large hydropower potentials. Vu Gia-Thu Bon River Basin in the central part of the country also exhibits considerable hydropower potential.

Vietnam has an estimated hydropower potential of about 20,600 MW, of which some 4,200 MW have so far been developed. The current hydropower capacity is nearly 40% of the current total installed capacity of the interconnected system of nearly 11,400 MW. Some 15 medium to large hydropower plants are currently under construction, and an additional 30 medium to large hydropower plants are planned to be commissioned before 2015, among them the Song Bung 4 Hydropower Project.

Vietnam is experiencing a period of unprecedented economic growth, accompanied by an average annual growth rate of electricity demand of over 15%. The demand will, according to the latest demand forecast, continue to grow at a steady high to moderate pace in the years to come, and is estimated to grow from the present (2004) 40 TWh to nearly 300 TWh in the year 2020. Ensuring continued, secure and adequate energy supply will be a major factor in sustaining economic growth, creating nonagricultural jobs, and reducing poverty.

Conventional power development plans, based primarily on the economics of alternative power generation sources and fuel availability, indicate that hydropower will continue to play a significant role in generation expansion over the next two decades. These plans envisage that hydropower will provide some 13,000 MW (38%) of the additional 34,000 MW of capacity that is foreseen to be required by the year 2020.

It is estimated that EVN will need to spend at least 21 billion USD up to 2010, comprising 10


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billion USD on new generation, 5 billion USD on transmission and distribution, and 6 billion USD on debt service.

1.2 The Energy Sector in Vietnam

1.2.1 Institutional Background

Vietnam's power supply system is operated by Electricity of Vietnam (EVN) under the Ministry of Industry (MOI). EVN was established in 1995 and is responsible for generation, transmission and distribution of electricity in Vietnam.

The Institute of Energy (IE), an agency under EVN, carries out the future electric power development planning in Vietnam.

For the development of hydropower and thermal projects in Vietnam, PECC1, PEEC2, PECC3 and PECC4, four independent accounting agencies under the authority of EVN, are in charge of project planning, investigation and design.

EVN divides its transmission system into four geographic areas with four regional Power Transmission Companies (PTC); PTC1 in Hanoi, PTC2 in Da Nang, PTC3 in Nha Trang and PTC4 in Ho Chi Minh City. In 1994, a single-circuit 500 kV transmission line was completed, interconnecting the power systems in the northern, central and southern regions of the country, and a second line is under commissioning.

Nine Power Companies (PC), PC1, PC2, PC3, Hanoi PC, Ho Chi Minh City PC, Hai Phong PC, Ninh Binh PC, Hai Dzuong PC and Dong Nai PC (independent accounting agencies under the authority of EVN), purchase bulk power and operate separate regional, medium and low voltage distribution networks. The areas in the north, except around Hanoi, Hai Phong, Ninh Binh and Hai Dzuong, are served by PC1, while PC2 is responsible for the southern part of the country except for Ho Chi Minh City and Dong Nai Province. The central region of the country is served by PC3.

1.2.2 Generation System

1.2.2.1 General As of 2004, the total installed capacity in the country amounted to 11,340 MW, an increase of 1,444 MW (nearly 15%) from the previous year. Hydropower amounted to nearly 37% of the total installed capacity and 38% of the total power production of 46,201 GWh, an increase of 5,376 GWh (nearly 14%) from the previous year, as seen from the table below:

Source Capacity MW

Capacity %

Production GWh

Production %

Hydropower 4,155 36.6 17,635 38.2 Coal-fired 1,245 11.0 7,015 15.2 Oil-fired 198 1.8 602 1.3 Gas-fired 2,939 25.9 14,881 32.2 Diesel 285 2.5 42 0.1 IPP 2,518 22.2 6,026 13.0 Total 11,340 100 46,201 100

It is estimated that some 34,000 MW, excluding power purchase from other countries, will be developed up to 2020, when the composition of thermal power is estimated to increase to 56% and hydropower is estimated to decrease to 36%, with the balance of 8% (4,000 MW)


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taken by import from Laos, Cambodia and China.

1.2.2.2 The Thermal Generation System Existing Plants

The existing thermal power generation plants in the northern region are conventional coal-fired thermal steam units with a total installed capacity of 1,245 MW. In the southern region, the thermal generation facilities are conventional oil-fired thermal steam units with a total installed capacity of 198 MW, gas turbines (both gas and oil) of 5,457 MW and diesel power generation of 194 MW. In the central region the thermal generation facilities are small-scale diesel power plants scattered throughout the region with a total installed capacity of 245 MW, however, with an available capacity estimated at about 91 MW only.

Planned Projects

According to the latest power development plan, a total of 24,000 MW of thermal power is expected to be developed from present to 2020. In the northern region of Vietnam, thermal power development is based on the coal resources in Quang Ninh Province. The fuel resources for thermal generation in the southern region are offshore natural gas and oil associated gas.

1.2.2.3 The Hydropower Generation System Existing Hydropower Plants

The existing hydropower generation facilities in the northern region have a total installed capacity of 2,040 MW, consisting of Hoa Binh (1,920 MW) and Thac Ba (120 MW) hydropower plants. In the southern region the total installed capacity amounts to 1,213 MW, consisting of Da Nhim (167 MW), Tri An (420 MW), Thac Mo (150 MW), Ham Tuan (300 MW), Da Mi (176 MW) and Can Don (78 MW) hydropower plants. In the central region the corresponding figure is 856 MW, consisting of Yali (720 MW), Vinh Son (66 MW) and Song Hinh (70 MW) hydropower plants. Some 500 small hydropower plants, with a total production of some 4 GWh/year, generate the balance of 46 MW. The location of the main hydropower facilities is shown on Figure 1.

Hydropower Development

According to the latest power development plan, some 13,000 MW of hydropower is expected to be developed from present to 2020, being nearly 65% of the economic viable hydropower potential in the country.

The location of hydropower projects under construction, committed, or planned in the latest power development plan covering the period 2005-2020, of which Song Bung 4 Hydropower Project is planned for year 2011, are shown on Figure 1.

1.2.3 Energy and Power Demand

Institute of Energy has recently submitted “Master Plan Study on Electric Power Development in Vietnam, Stage VI”, including a power demand forecast covering the period 2005-2025 for three economic growth scenarios, High Case, Base Case and Low Case, see details in Section 7.3.


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1.3 The PPTA

1.3.1 General

The Contract for Consultant’s Services for this PPTA was signed between ADB and SWECO International on 3rd November 2005, and Notice to Proceed was given four days later. The commencement date was agreed to be 14th November 2005.

The Study Team from SWECO International consists of the following positions and members: Position Name International Consultants Team Leader Göran Lifwenborg Engineering Hydrologist Leif Basberg Geotechnical Engineer Anders Heiner Dam Design Engineer Ole Berthelsen Mechanical-Electrical Engineer Ove Brattberg Finance/Power Sector Reform Specialist William Pemberton Resettlement Planning Specialist Chris Flint Ethnic Minority Development Planning Specialist Anders Hjort Public Health Impact Specialist Anders Norman Gender Specialist TiiaRiita Granfelt Consultation Specialist Dan Rocovitz Environmental Planner Jan-Petter Magnell Terrestrial Ecologist/Forestry Specialist Shivcharn Dhillion Aquatic Ecologist Dag Berge Tim McGrath Livelihood Team Leader Domestic Consultants Hydropower Planning Engineer Phan Ky Nam Geotechnical Engineer Nguyen Cong Man Mechanical-Electrical Engineer Phan Xuan Huy Power System Economist Nguyen Tien Nguyen Financing Expert Pham Ngoc Thang Resettlement Planning Specialist Vu Cong Lan Resettlement Field Planner 1 Le Trung Thong Resettlement Field Planner 2 Nguyen Ha Hue Resettlement Infrastructure Engineer Nguyen Xuan Khuong Resettlement DTM/GIS Expert Vu Huy Hoang Upland Irrigation Engineer Nguyen Ngoc Khanh Ethnic Minority Development Planning Specialist Bui Van Dao Ethnic Minority Field Planner 1 Dao Huy Khue Ethnic Minority Field Planner 2 Dang Minh Ngoc Public Health Impact Specialist Nguyen Thi Lien Huong Gender Specialist Vu Thi Ngoc Tran Consultation Specialist Pham Thi Bich Ngoc Environmental Planner Dang Kim Nhung Terrestrial Ecologist/Forestry Specialist Phan Ke Loc Fauna Specialist Nguyen Quang Truong Aquatic Ecologist Ho Than Hai Road Engineer Vu Van Thi Mining Engineer Pham Thai Nam GIS Expert Nguyen H Quyen Livestock and Forages Specialist Bui Minh Hanh Forestry and NTFP Specialist Tran Thi Binh Agriculture Specialist Lam Quang Hinh Fishery Specialist Phan Thi Ngoc Diep


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According to the Contract the PPTA is divided into the following phases:

• Inception Phase, including initial review of the Feasibility Study and detailed work plan.

• First Interim Phase, including detailed technical review of the Feasibility Study, results from the hydrological/hydrodynamic modeling study, and results from the EIA/SIA baseline studies.

• Second Interim Phase, including Draft Resettlement Plan, Draft EIA Report, cost estimates, economic/financial analyses, and the first review of Technical Design.

• Draft Final Phase, including Final Resettlement Plan, Final EIA Report, and draft of other safeguard documents, Draft RRP, and institutional review.

• Final Phase, including final of other safeguard documents, Final RRP, and the second review of Technical Design

The Inception Report was submitted on 12th December 2005, and was discussed in a Tripartite Meeting in Da Nang on 13th December 2005 between ADB, the Implementing Agency and the Consultant. The First Interim Report was submitted on 10th March 2006, and was discussed in a Tripartite Meeting in Da Nang on 13th March 2006 between ADB, the Implementing Agency and the Consultant. An Addendum to the First Interim Report was submitted on 24th April 2006 following comments from ADB. The Second Interim Report was submitted on 12th June 2006, and was discussed in a Tripartite Meeting in Da Nang on 13th June 2006 between ADB, the Implementing Agency and the Consultant.

1.3.2 Phase I of the PPTA

Phase I of the PPTA was completed in May 2005 as an initial step in ADB’s planning and appraisal process of the Project and focused on issues related to water resources planning and management in the river basin, and environmental and social issues.

The scope of Phase I of the PPTA on Song Bung 4 Hydropower Project (ADB TA 4475-VIE) included the following:

• Institutional framework for management of water resources in the basin.

• Identification of stakeholders involved in planning and management of basin water resources.

• Issues related to participatory watershed management.

• Preliminary identification of social and environmental impacts.

• Identification of threats to protective areas.

• Outline of a consultation strategy.

• Consideration of the scope of livelihood development support.

• Capacity building for implementation of environmental and social mitigation measures.

1.3.3 Overall Objective

The overall objective of this PPTA (ADB TA 4625-VIE) is to prepare for ADB financing of the proposed Song Bung 4 Hydropower Project in Vu Gia-Thu Bon River Basin in Quang Nam Province in the central part of Vietnam, see a general description of the Project in Chapter 2.

In general terms, the PPTA consists of the following parts:


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• Technical/Engineering Review of the Project to review the Feasibility Study on the Project prepared by PECC3, and the subsequent Technical Design.

• Economic and Financial Analysis to assess the Project’s economic and financial viability and confirm that the Project is part of the least cost expansion plan for meeting the future electricity demand in Vietnam.

• Social Assessment to ensure compliance with ADB’s social safeguard policies and guidelines, and still being acceptable to the Government of Vietnam and feasible within the Vietnamese context.

• Environmental Assessment to ensure compliance with ADB’s environmental policies and guidelines.

1.3.4 Objective of Draft Final Report

The objective of this Draft Final Report is to summarize all studies performed during the PPTA, and to present draft safeguard documents, as follows:

• To report on the layout of Song Bung 4 Hydropower Project as presented in the Feasibility Study, and suggested modifications, as reported in Chapter 2 of this Main Report.

• To report on the detailed technical review of the Feasibility Study, as reported in Chapter 3 of this Main Report.

• To report on the tentative Construction Schedule for the Project, as reported in Chapter 4 of this Main Report.

• To report on the Cost Estimate of the Project, as reported in Chapter 5 of this Main Report.

• To report on the Implementation and Procurement of the Project, as reported in Chapter 6 of this Main Report.

• To report on the Economic Analysis of the Project as reported in Chapter 7 of this Main Report.

• To report on the Financial Analysis as reported in Chapter 8 of this Main Report.

• To present the Environmental Impact Assessment (EIA) Report.

• To present the Resettlement and Ethnic Minority Development Plan (REMDP) in four volumes.

• To present the Social Mitigation Plan

• To present the Gender Action Plan.

• To present the Consultation Report.

• To present the Social Reports from the Local Consultants as reported in the Annex.

1.3.5 Summary of Activities

The main activities during the PPTA are summarized in the table below:


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Dates Activity International Consultant’s Involved

Inception Phase 14 Nov 2005 Commencement of Study - 14 – 25 Nov 2005 Initial Technical Review of Feasibility Study (FS) Lifwenborg 21 Nov – 2 Dec 2005 Initial Works on Hydrological Modeling Study Basberg 21 Nov – 1 Dec 2005 Review of Resettlement Plan in FS Flint 21 Nov – 1 Dec 2005 Review of EIA in FS Magnell 25 – 27 Nov 2005 Meeting with ATD3 and short site visit Flint 28 Nov – 1 Dec 2005 Preparation of Activities and Detailed Work Plan Lifwenborg, Flint, Hjort,

Magnell, Rocovitz 28 Nov – 1 Dec 2005 Drafting of Inception Report Lifwenborg, Flint, Magnell,

Basberg 2 Dec 2005 Submission of Inception Report - First Inception Phase

12 – 19 Dec 2005 ADB Mission, Discussions on Inception Report - Jan 2006 Detailed Technical Review of Feasibility Study Lifwenborg, Berthelsen,

Heiner, Brattberg First Interim Period Hydrological Modeling Study Basberg Jan 2006 Planning for Environmental Field Work and Studies Magnell, Berge, Dhillion Jan 2006 Planning for Social Field Work and Studies Flint, Hjort, Granfelt, Rocovits,

McGrath Jan 2006 Initial Work on Economic Analysis - Jan 2006 Initial Work on Financial Analyses Pemberton 10 Feb 2006 First EIA Workshop Lifwenborg, Magnell, Flint,

Granfelt, Rocovits, McGrath Feb 2006 Environmental Field Work and Base-line Studies Magnell Feb 2006 Social Field Work and Base-line Studies Flint, Hjort, Granfelt, McGrathFeb 2006 Drafting of Inception Report Lifwenborg, Flint, Magnell,

Basberg, Pemberton 10 Mar 2006 Submission of First Interim Report - Second Inception Phase

10 – 17 Mar 2006 ADB Mission, Discussions on First Interim Report - Second Interim Period

Work on Implementation and Procurement, Cost Estimates and Operation of the Project

Lifwenborg

Second Interim Period

Financial Analysis and EVN’s Business Model Pemberton

Second Interim Period

Social Assessment and Assessment of Resettlement Sites

Flint, Hjort, Granfelt, McGrath

April-May 2006 Environmental Assessment Magnell, Berge, Dhillion 24-26 April 2006 ADB Mission, Discussions on Resettlement Sites Lifwenborg, Flint, Hjort,

Granfelt, McGrath 27 April 2006 Second Stakeholder Consultation Workshop Lifwenborg, Flint, Magnell

Granfelt, McGrath May 2006 Drafting of Second Interim Report All 2 June 2006 Submission of Second Interim Report-Digital - 12 June 2006 Submission of Second Interim Report-Hard Copy - Draft Final Phase 12-16 June 2006 ADB Mission, Discussions on Second Interim

Report Lifwenborg, Flint, Granfelt

21 June-2 July Final Village Consultation - 26 June-7 July Community Based Forest Development Plan -


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8-10 July ADB Mission, Discussions on Village Consultation Lifwenborg, Flint Draft Final Period Drafting of Draft Final Report, including

environmental and social safeguard documents All

15 July Submission of Draft Final Report-Digital - October Submission of Draft Final Report-Hard Copy - December Submission of Final Report-Hard Copy -

1.3.6 Acknowledgments

In presenting this Final Report, the Consultant wishes to respectfully acknowledge its gratitude for all the co-operation, assistance, advice and hospitality given to the Consultant by all parties concerned with this PPTA. Special thanks are due to ABD, its Team Leader Mr. Pradeep Perera and its Team Members of this PPTA, the Hydro Power Project Management Unit No. 3 and EVN, and last but not least the local sub-consultants for the PPTA.

1.4 Overview of Hydropower Development in Vu Gia-Thu Bon River Basin

1.4.1 General

Song Bung 4 Hydropower Project is part of a plan to develop a number of hydropower projects in Vu Gia-Thu Bon River Basin as seen in Figure 1-1 below. The river basin consists of two main rivers, Vu Gia River and Thu Bon River, and three main tributaries, Dak Mi River, Bung River and Tranh River. Figure 1-1. Location of Hydropower Projects in Vu Gia-Thu Bon River Basin

The total theoretical and economic hydropower potential of Vu Gia – Thu Bon River Basin in Central Vietnam is estimated at some 1,300 MW and 1,000 MW, respectively, and the annual energy potential at about 6 TWh and 4.6 TWh, respectively, representing a considerable resource for hydropower development compared to other river basins in Vietnam.


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A River Basin Plan for Vu Gia – Thu Bon was carried out by PECC1 in 2002, in connection with the Feasibility Study on A Vuong Hydropower Project, to investigate the hydropower potential of the river basin.

The Vu Gia-Thu Bon River Basin was studied in Stage 2 of the National Hydropower Plan (NHP) Study (November 2005), and the hydropower projects descried below were included in the NHP Study and are also relevant for this PPTA.

1.4.2 Existing and Hydropower Projects under Construction

There are no significant hydropower projects in operation in the river basin, while A Vuong and Song Tranh 2 hydropower projects are currently under construction with the location according to Figure 1-1.

1.4.2.1 A Vuong Hydropower Project Construction of A Vuong Hydropower Project started in 2003 and is located on A Vuong River, about 10 km upstream of the confluence with Bung River and 80 km west from Da Nang.

The A Vuong Hydropower Project comprises an 80 m high RCC dam with a gated spillway located in the central part of the dam. The waterway comprises a 5.3 km long headrace tunnel and a 520 m long surface penstock. The powerhouse will be constructed in an excavated pit and equipped with two Francis units of 105 MW, totalling 210 MW. The Project has a fairly large reservoir with an area of 9 km2 that will provide an active storage of 267 Mm3, corresponding to some 21% of the mean annual inflow of 40 m3/s.

According to the Technical Design prepared by PECC2 the main project parameters for A Vuong Hydropower Project are as follows:

Item Unit A Vuong Catchment Area km2 682 Mean Annual Flow m3/s 39.8 Full Supply Level, FSL m.a.s.l 380 Reservoir Area at FSL km2 9.1 Minimum Operating Level, MOL m.a.s.l 340 Reservoir Area at MOL km2 4.3 Reservoir Regulation m 40 Reservoir Total Storage Mm3 343.6 Reservoir Active Storage Mm3 266.5 Spillway Design Flood m3/s 5,730 Maximum Tail Water Level m.a.s.l 86.6 Normal Tail Water Level m.a.s.l 58 Maximum Head m 320 Design Head m 300 Minimum Head m 265 Total Turbine Design Discharge m3/s 78.4 Installed Capacity MW 210 Firm Capacity MW 66.9 Annual Average Energy Potential (PECC2) GWh 815


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1.4.2.2 Song Tranh 2 Hydropower Project The construction of Song Tranh 2 Hydropower Project started in 2006 and is located on Tranh River and situated about 6 km west of Tranh My Town.

The Song Tranh 2 Hydropower Project incorporates a RCC dam of some 95 m height with a spillway in the river channel, and an intake on the right bank. A 1.8 km long pressure tunnel will convey the flow to the surface power station equipped with two Francis turbines, with a total installed capacity of 162 MW. The Project has a large reservoir with an area of 22 km2

that will provide an active storage of 520 Mm3, corresponding to about 16% of the mean annual inflow of 106 m3/s.

According to the Feasibility Study prepared by PECC1 the main project parameters for Song Tranh 2 Hydropower Project would be as follows:

Item Unit Song Tranh 2 Catchment Area km2 1,100 Mean Annual Flow m3/s 106 Full Supply Level, FSL m.a.s.l 175 Reservoir Area at FSL km2 21.5 Minimum Operating Level, MOL m.a.s.l 140 Reservoir Area at MOL km2 9.3 Reservoir Regulation m 35 Reservoir Total Storage Mm3 733.4 Reservoir Active Storage Mm3 521.1 Spillway Design Flood m3/s 11,069 Maximum Tail Water Level m.a.s.l 87.5 Normal Tail Water Level m.a.s.l 71 Maximum Head m 102.3 Design Head m 88.3 Minimum Head m 62.9 Total Turbine Design Discharge m3/s 209.7 Installed Capacity MW 162 Firm Capacity MW 41.2 Annual Average Energy Potential (PECC1) GWh 620.7

1.4.3 Planned Hydropower Projects

1.4.3.1 General A number of hydropower projects have been identified in the Vu Gia-Thu Bon River Basin, and the following projects have been studied to different levels by Vietnamese agencies:

Basin Sub-basin Project Catchment Area Km2

FSL m

Installed Capacity MW

Vu Gia Bung Song Bung 2 334 605 100 Bung Song Bung 4 1,467 222.5 156 Bung Song Bung 5 2,380 60 85 Dak Mi Dak Mi 1 397 845 215 Dak Mi Dak Mi 4 1,125 258/106 141/39 Con Song Con 2 248 275 46


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The location of the above hydropower projects is shown in Figure 1-1, and described in more details below, apart from Song Bung 4 Hydropower Project that is described in Chapter 2.

1.4.3.2 Song Bung 2 Hydropower Project The Song Bung 2 Hydropower Project would be the most upstream in a cascade of hydropower development proposed along Bung River, and is located in Nam Giang District of Quang Nam Province.

The Bung River originates in the mountainous area between Laos and Vietnam. The dam site of the Song Bung 2 Hydropower Project would be located some 12 km from the Laotian border.

The general layout of Song Bung 2 Hydropower Project comprises of the following parts according to the Feasibility Study by PECC3 (June 2005):

• A 100 m high and 350 m long Concrete Faced Rockfill Dam (CFRD) with the crest at +607.5 m.

• Three surface spillways with radial gates, width 15 m and height 16 m.

• A 9.1 km long TBM pressure tunnel with a diameter of 4 m.

• A 850 m long penstock with a diameter of 2.6 m

• A surface power station housing two 50 MW Francis units.

• A 1.1 km long tailrace tunnel with a diameter of 4.8 m.

• A 15 km long 220 kV, AC 240, transmission line with double circuits.

• A 25 km long new road will be constructed from Cha Val town towards Zu Oih village and further to the powerhouse area and dam site.

The Project has a reservoir with an area of 2.9 km2 that will provide an active storage of 69 Mm3, corresponding to about 8% of the mean annual inflow of 29 m3/s.

The salient features of Song Bung 2 Hydropower Project given in the Feasibility Study are outlined in the table below:

Item Unit Song Bung 2 Catchment Area km2 324 Mean Annual Flow m3/s 18.9 Full Supply Level, FSL m.a.s.l 605 Reservoir Area at FSL km2 2.9 Minimum Operating Level, MOL m.a.s.l 565 Reservoir Area at MOL km2 1.0 Reservoir Regulation m 40 Reservoir Total Storage Mm3 87.2 Reservoir Active Storage Mm3 69.2 Maximum Tail Water Level m.a.s.l 242.8 Normal Tail Water Level m.a.s.l 224.6 Design Head m 330.5 Total Turbine Design Discharge m3/s 34.8 Installed Capacity MW 100 Annual Average Energy Potential (PECC3) GWh 415


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In the NHP Study it was concluded that the recommended development of Song Bung 2 Hydropower Project would be economically viable. No additional benefits in respect of flood storage protection and supply of irrigation water to downstream users would result from the Project. The environmental and social issues are small with no identified people for resettlement and no inundation of agricultural land.

1.4.3.3 Song Bung 5 Hydropower Project The Song Bung 5 Hydropower Project would be situated some 10 km northwest of Tanh My City and some 10 km upstream of the confluence between Bung and Cai rivers on the border between Hien and Nam Giang districts.

The Song Bung 5 Hydropower Project is the most downstream project on a cascade development of Bung River, and is recommended to provide re-regulation of the intermittent outflow from Song Bung 4 and A Vuong hydropower projects.

The general layout of Song Bung 5 Hydropower Project comprises of the following parts according to the Pre-feasibility Study by PECC3 (September 2005):

• A 50 m high and 280 m long concrete gravity dam with the crest at +62.0 m.

• A surface spillway with six radial gates, width 15 m and height 16 m.

• A short concrete-lined waterway.

• A surface power station housing two 42.5 MW Kaplan units.


• 15 km of new road from Linh Hiep on Highway No. 14B.

The Project has a small reservoir for daily re-regulation.

The salient features of Song Bung 5 Hydropower Project given in the Pre-feasibility Study are outlined in the table below:

Item Unit Song Bung 5 Catchment Area km2 2,388 Mean Annual Flow m3/s 139 Full Supply Level, FSL m.a.s.l 60 Reservoir Area at FSL km2 2.6 Minimum Operating Level, MOL m.a.s.l 58 Reservoir Area at MOL km2 2.1 Reservoir Regulation m 2 Reservoir Total Storage Mm3 39.2 Reservoir Active Storage Mm3 4.6 Maximum Tail Water Level m.a.s.l 40.3 Normal Tail Water Level m.a.s.l 18.2 Design Head m 39.8 Total Turbine Design Discharge m3/s 250 Installed Capacity MW 85 Annual Average Energy Potential (PECC3) GWh 371

In the NHP Study it was concluded that the recommended development of Song Bung 5 Hydropower Project would be economically viable. No additional benefits in respect of flood storage protection and supply of irrigation water to downstream users would come out of the


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Project. The environmental and social impact would be small with an estimated resettlement of 195 people and inundation of some 16 ha of agricultural land.

1.4.3.4 Dak Mi 1 Hydropower Project The Dak Mi 1 Hydropower Project would be situated some 30 km south of Kham Duc in Phuc Son District.

The general layout of Dak Mi 1 Hydropower Project comprises of the following parts according to the NHP Study:

• An 82 m high and 370 m long (dam 2A), and a 71 m high and 320 m long (dam 2B) rockfill dams with the crest at +851.0 m and +849.7 m, respectively.

• Four surface spillways with radial gates, width 15 m and height 16 m.

• A 10.7 km long headrace tunnel and a 6.6 km long tailrace tunnel, both concrete-lined and with a diameter of 5.9 m.

• A 1 km long concrete-lined underground penstock with a diameter of 3.6 m.

• An underground power station housing two 107.5 MW Francis units.


• 10 km of new constructed road from the new Ho Chi Minh Highway.

The Project has a reservoir with an area of 4.6 km2 that will provide an active storage of 93 Mm3, corresponding to about 11% of the mean annual inflow of 26 m3/s.

The salient features of Dak Mi 1 Hydropower Project given in the NHP Study are outlined in the table below:

Item Unit Dak Mi 1 Catchment Area km2 396.8 Mean Annual Flow m3/s 26.4 Full Supply Level, FSL m.a.s.l 845 Reservoir Area at FSL km2 4.6 Minimum Operating Level, MOL m.a.s.l 810 Reservoir Area at MOL km2 1.4 Reservoir Regulation m 35 Reservoir Total Storage Mm3 116.1 Reservoir Active Storage Mm3 93.4 Maximum Tail Water Level m.a.s.l 258 Normal Tail Water Level m.a.s.l 252 Design Head m 552 Total Turbine Design Discharge m3/s 44 Installed Capacity MW 215 Annual Average Energy Potential GWh 824

In the NHP Study it was concluded that the recommended development of Dak Mi 1 Hydropower Project would be economically viable, with some benefits in respect of flood storage protection and supply of irrigation water to downstream users. The social issues at stake would be small with no resettlement and inundation of some 75 ha of agricultural land. The environmental impact would be tangible, mainly because of the proximity to protected areas. In the overall assessment in the NHP Study, taking into account technical/economic


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and environmental/social preferences, Dak Mi 1 Hydropower Project was categorized as a project with reservations/low interest.

1.4.3.5 Dak Mi 4 Hydropower Project The Dak Mi 4 Hydropower Project would be situated some 5 km north-east of Kham Duc town in Phuc Son District.

The Dak Mi 4 Hydropower Project would be the most downstream project in Dak Mi River, and the rationale of Dak Mi 4 Hydropower Project is a river diversion from Dak Mi River to the upper Thu Bon River.

The general layout of Dak Mi 4 Hydropower Project consists of an upper scheme, an intermediate reservoir and a lower scheme, and comprises the following parts according to the Feasibility Study by PECC2 (July 2005):

• A 90 m high and 430 m long RCC dam with the crest at +263.2 m. Lower control dams are situated at the intermediate reservoir and at the intake pond for the lower scheme.

• A surface spillway with 5 radial gates, width 20 m and height 15 m.

• A 2,2 km long concrete-lined transfer tunnel, and a 1,8 km long embedded penstock with a diameter of 5.6 m connected to the upper power station.

• A 240 m long surface penstock with a diameter of 6.0 m to the lower power station.

• A surface power station housing three 47 MW Francis units in the upper power station, and a lower power station housing three 13 MW Francis or Kaplan units.


• 10 km of access roads from National Road 14 E.

The Project has an upper reservoir with an area of 10.4 km2 that will provide an active storage of 158 Mm3, corresponding to about 7% of the mean annual inflow of 68 m3/s.

The salient features of Dak Mi 4 Hydropower Project given in the Feasibility Study are outlined in the table below:

Item Unit Dak Mi 4

Upper Dak Mi 4 Lower

Catchment Area km2 1,125 29 Mean Annual Flow m3/s 67.8 1.1 Full Supply Level, FSL m.a.s.l 258 106 Reservoir Area at FSL km2 10.4 0.45 Minimum Operating Level, MOL m.a.s.l 240 105 Reservoir Area at MOL km2 7.0 0.4 Reservoir Regulation m 18 1 Reservoir Total Storage Mm3 310 2.6 Reservoir Active Storage Mm3 158 0.6 Maximum Tail Water Level m.a.s.l 108 71.5 Normal Tail Water Level m.a.s.l 106 67.5 Design Head m 135 37.5 Total Turbine Design Discharge m3/s 121 122 Installed Capacity MW 141 39 Annual Average Energy Potential (PECC2) GWh 582 161


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Item Unit Dak Mi 4

Combined Installed Capacity MW 180 Average Annual Energy Production GWh 743

In the NHP Study it was concluded that the recommended development of Dak Mi 4 Hydropower Project would be marginally economically viable, with some benefits in respect of flood storage protection and supply of irrigation water to downstream users. The social impact would be small with an estimated resettlement of 126 people and inundation of some 139 ha of agricultural land. The downstream environmental impact would be tangible due to the diversion of water from Dak Mi River. In the overall assessment in the NHP Study, taking into account technical/economic and environmental/social preferences, Dak Mi 4 Hydropower Project was categorized as a project with reservations/low interest.

1.4.3.6 Song Con 2 Hydropower Project The Song Con 2 Hydropower Project would be located on the Song Con tributary, some 20 km upstream of the confluence with Vu Gia River and some 12 km south-west of Mang May village in Hien District.

The general layout of Song Con 2 Hydropower Project comprises of the following parts according to the Pre-feasibility Study by PECC3 (July 2003):

• A 30 m high and 148 m long concrete gravity dam with the crest at +283.0 m.

• A 120 m wide un-gated spillway.

• A 4.2 km long headrace tunnel with a diameter of 2.5 m.

• A 650 m long surface penstock with a diameter of 2 m.

• A surface power station housing two 23 MW Francis units.


• 22 km of new road from the Ba Lien village on Highway No 4. The powerhouse area would also be connected to Highway No. 4 from Cau Ha Tan.

The Project has a small reservoir for daily regulation only.

The salient features of Song Con 2 Hydropower Project given in the Pre-feasibility Study are outlined in the table below:

Item Unit Song Con 2 Catchment Area km2 248 Mean Annual Flow m3/s 13.2 Full Supply Level, FSL m.a.s.l 275 Reservoir Area at FSL km2 0.13 Minimum Operating Level, MOL m.a.s.l 274 Reservoir Area at MOL km2 0.12 Reservoir Regulation m 1 Reservoir Total Storage Mm3 0.78 Reservoir Active Storage Mm3 0.1 Maximum Tail Water Level m.a.s.l 29.7


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Normal Tail Water Level m.a.s.l 18 Design Head m 215 Total Turbine Design Discharge m3/s 22.8 Installed Capacity MW 46 Annual Average Energy Potential (PECC3) GWh 168

In the NHP Study it was concluded that the recommended development of Song Con 2 Hydropower Project would be economically viable. No additional benefits would result from the Project in respect of flood storage protection and supply of irrigation water to downstream users. The environmental and social would be small with an estimated resettlement of 60 people and inundation of some 12 ha of agricultural land.

2 Song Bung 4 Hydropower Project

2.1 General

The Song Bung 4 Hydropower Project would be built on Bung River, a tributary of Vu Gia River, in Zuoih and Ta Bhing communes of Nam Giang District, Quang Nam Province, some 100 km west of Da Nang City, see Figure 2-1 below:


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Figure 2-1. Location of Proposed Song Bung 4 Hydropower Project

Da Nang

Sg. Thu Bon

Sg. C¸ i

Sg. Vu Gia

Sg. Thanh

Sg. TraVinh

Sg. BungSg. Vinh

Sg. Vu Gia

Dien Ban

Tam Ky Town

Duy Xuyen

Thang Binh

Tien PhuocHieo Duc

Nui Thanh

Dai Loc

Que So n

Phuoc So n

Tr a My

Giang

Hien

Da Nang

HOI AN

Ngoc Linhnat ur e r eser ve

Song Thanh nat ur e r eser ve

Song Bung 4

LEGEND

Reservoir of Song Bung 4 project

Catchment of Song Bung 4

Catchment of Vu Gia Thu Bon

Nature Reserves

RiverMain Road

N

4 0 4 8 Kilometers

750000

750000

800000

800000

850000

850000

900000

900000

1700

000 1700000

1750

000 1750000

The key features of the Project include a dam, a reservoir, an underground water conveyance system and a surface power station, with the general layout according to the Feasibility Study as shown in Figure 2-2.


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Figure 2-2. General Layout of Song Bung 4 Hydropower Project According to Feasibility Study


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2.2 Project Components According to Feasibility Study

2.2.1 General

The main features and components of Song Bung 4 Hydropower Project according to the Feasibility Study is summarized in the table below and described in more detail in the following:

Main Features and Components of Song Bung 4 Hydropower Project According to FS

The project description below is based on information given in the Feasibility Study and could be modified in the Technical Design Phase of the Project. Modification of certain features has also been suggested in this PPTA as summarized in Section 2.3.

2.2.2 Reservoir

The Full Supply Level (FSL) of the reservoir will be at El. 222.5 m that will create a lake with an area of 15.8 km2 and store a total volume of water of 493 million m3. The drawdown of the reservoir to the Minimum Operating Level (MOL) at El. 195 m will be 27.5 m. At the MOL the area would be 7.8 km2 and the volume of water some 173 million m3. The volume of water to be used for electricity generation, between FSL and MOL, would be 320 million m3.

2.2.3 Dam Structure

The reservoir will be formed by the construction of a RCC (Roller Compacted Concrete) gravity dam on Bung River. The dam will have a crest length of some 370 m and a maximum height of 110 m from the deepest foundation level to the crest level of +227.5 m.

The foundation of the dam structure will be grouted for seepage control and for consolidation of the bedrock, and the dam will include inspection and drainage galleries, and be equipped with instrumentation consistent with modern international dam safety practice.

Main Features Unit Song Bung 4 Main Components Unit Song Bung

4 Catchment Area km2 1,477 Dam Type - RCC Mean Annual Flow m3/s 88.2 Dam Height m 110 Full Supply Level, FSL m.a.s.l 222.5 Crest Length m 370 Reservoir Area at FSL km2 15.8 Crest Level m.a.s.l 227.5 Minimum Operating Level, MOL m.a.s.l 195 Spillway Gates Nos 6 Reservoir Area at MOL km2 7.8 Tunnel, Length m 3,050 Reservoir Regulation m 27.5 Tunnel Diameter m 6.8 Reservoir Total Storage Mm3 493.3 Penstock, Length m 270 Reservoir Active Storage Mm3 320.7 Penstock, Diameter m 5.2 Spillway Design Flood m3/s 20,000 Maximum Tail Water Level m.a.s.l 125 Normal Tail Water Level m.a.s.l 96.5 Design Head m 104.9 Total Turbine Design Discharge m3/s 172.7 Installed Capacity MW 156 Annual Average Energy Potential GWh 618


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2.2.4 Spillway

The spillway will have five radial gates that will be incorporated in the dam structure, and is designed for a 5,000-year flood (check flood) of some 15,500 m3/s. The spillway chute will terminate in a ski-jump that will throw the water into a pre-excavated plunge pool in the river downstream of the dam where the energy will be dissipated.

The floods will be attenuated when passed through the reservoir giving an outflow from the spillway of some 12,800 m3/s at the 5,000-year flood. The spillway is designed to work effectively for smaller floods than the design flood, by operating the spillway gates to control the water level in the reservoir.

During maintenance of the spillway gates, stoplogs will be placed in front of the intake.

An acoustic warning system will be recommended to be installed from the dam down to the confluence with Cai River to warn people when the spillway gates will be opened.

2.2.5 Intake

A freestanding 50 m high intake structure will be constructed some 400 m to the south of the dam to convey the water to the headrace tunnel. The intake will have one opening and be equipped with a downstream service gate and an upstream guard gate. The opening will be equipped with trash racks and mechanized trash-cleaning rakes. For maintenance of the guard gate, stoplogs may be placed in front of the intake. For dewatering of the water conveyance system during inspection and maintenance, both the services and guard gates will be closed.

2.2.6 Headrace Tunnel

A nearly horizontal headrace tunnel, with a total length of some 3 km and an inner diameter of 6.8 m, will be excavated from the intake to the surge tank. The tunnel will be concrete lined and supported by steel-ribs or other strengthening measures when the tunnel encounters week rock formations.

Construction of the headrace tunnel will be through two adits, one at the upstream end and one at the downstream end.

2.2.7 Surge Tank

At the downstream end of the headrace tunnel, a 75 m high (54 m below ground and 21 m above ground) surge tank will be constructed to reduce pressure transients created by start-up and load rejection operations of the turbine-generator units. The surge tank will be concrete lined and have an internal diameter of 24 m above ground and 15 m below ground.

Construction of the surge tank will be through the adit at the downstream end of the headrace tunnel and from above ground.

2.2.8 Penstock

Downstream of the surge tank, an underground penstock, with a total length of some 270 m and a diameter of 5.2 m, will be constructed, being horizontal for the first part followed by a vertical part and finally a horizontal part towards the power station.

Construction of the penstock will be through two adits, one utilizing the adit at the downstream end of the headrace tunnel and one at the downstream end of the penstock.

2.2.9 Power Station and Switchyard

The powerhouse will be located close to Bung River, some 5 km downstream of the dam, and consists of a 68 m high, 58 m long and 24 m wide surface structure. The structure will house


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two turbine-generator units with a total capacity of 156 MW, an erection bay, and auxiliary facilities for operation and maintenance. Two 3-phase transformers will be placed outside at the back of the powerhouse.

The control building, for operation of the Project, will be located adjacent to the powerhouse structure.

The buildings will be placed at El. 125 m being 0.5 m above the level for a 5,000-year flood.

The transformers at the powerhouse will be connected to the transmission lines via a switchyard, with dimensions 70 m x 143 m, located some 500 m downstream of the powerhouse.

2.2.10 Tailrace Canal

A 20 m long tailrace canal will divert the water back to Bung River.

2.2.11 Transmission Line

The power generated at Song Bung 4 Hydropower Project will be connected to the national grid via a some 35 km long double circuit 220 kV transmission line to the existing 220/110 kV substation at Thanh My.

In addition, it is proposed to construct a 35 kV transmission line from an existing low voltage substation at Thanh My to the project site for electricity supply during construction of the Project. This line, with a length of some 38 km, will follow Highway 14 D and the access road to the project site.

2.2.12 Access Roads

For the construction of Song Bung 4 Hydropower Project, a considerable amount of materials need to be transported from Da Nang City, some 100 km to the east. The existing Highway 14D is reported to be adequate for this purpose, and no additional upgrading of this road is foreseen. For transport of heavy equipment, such as the generators, at least the last part from Nam Giang would probably need to be closed during the transportation.

From Highway 14D an estimated 5.4 km long access road will be constructed to the dam site along the right edge of Bung River. The standard of the road will be Grade 4 in mountainous areas with asphalt coating.

A number of access roads will be constructed within the project site, to be used both during construction and operation.

A 100 m long temporary bridge across Bung River is planned some 400 m downstream of the dam, to be used during the construction of the dam structure and thereafter removed. Permanent access across the river will be through the crest of the dam.

2.2.13 Relocation of Highway 14D

A some 6 km long stretch of Highway 14 D needs to be relocated due to the impoundment of Song Bung 4 Reservoir, and a 350 m long and 60 m high bridge will be constructed over Tru Vinh, a tributary to Bung River.

2.3 Comments and Suggested Modifications

2.3.1 Estimated Inflow for Song Bung 4 Hydropower Project

The estimated inflow for Song Bung 4 Hydropower Project given in the Feasibility Study has been reassessed based on rainfall-runoff modeling of the catchment area as given in the


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Hydrological and Hydrodynamic Modeling Studies (Volume VII of the Second Interim Report).

It should, however, be noted that the basis for estimates of the inflow at Song Bung 4 site are very poor as no gauging station with long records exist for the catchment area of Bung River, but in nearby catchments with different rainfall and run-off characteristics. Water level and discharge measurements are, however, ongoing at Song Bung 4 site that will provide a much better basis for the estimated inflow once a sufficient length of records are obtained. In that case correlations with the discharge recorded at Thanh My can be used to prolong the recorded discharges at Song Bung 4 site.

The estimated inflow given below should therefore be seen as preliminary and indicative only, and it is recommended that a new estimate of the inflow is performed during the Technical Design Phase when more data are available from the gauging station at Song Bung 4 site.

The tentative annual average discharge at Song Bung 4 site is now estimated at 72 m3/s, as seen from the monthly discharges for the period 1978-2004 given below, compared to 88 m3/s in the Feasibility Study. Tentative Monthly Discharges in m3/s for Song Bung 4 Hydropower Project

Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Mean Min Max1978 45 20 25 27 65.8 44 61 39 182 193 158 127 81.96 20 193 1979 54 41 33 24 70.8 185 50 60 48 93 93.6 44 66.37 24 185 1980 27 20 15 11 15.4 102 61 78 223 250 458 130 115.9 11 458 1981 97 68 49 51 63.3 89 57 42 53 353 335 186 120.2 42 353 1982 90 69 50 72 47.2 54 34 29 136 63 85.8 32 63.56 29 136 1983 27 17 13 9.6 7.15 48 38 28 30 222 240 88 63.92 7.1 240 1984 54 40 30 24 49.7 40 30 34 29 149 176 80 61.16 24 176 1985 40 29 22 24 32.1 56 27 20 60 121 175 134 61.55 20 175 1986 50 37 28 21 49.2 39 24 25 12 133 50 96 46.87 12 133 1987 30 22 19 12 11.8 39 16 29 155 39 186 52 50.97 12 186 1988 55 32 21 16 19.1 17 15 8.7 26 212 91.8 51 47.13 8.7 212 1989 44 23 19 14 61.8 37 42 23 26 28 44.5 20 31.75 14 61.81990 11 8.4 6.1 4.5 9.75 4.6 6.8 15 52 322 246 86 64.4 4.5 322 1991 61 47 36 31 28.1 17 16 21 26 170 68 82 50.26 16 170 1992 35 24 18 14 15.8 42 23 52 45 282 126 80 62.93 14 282 1993 47 33 25 19 67.5 45 42 21 73 179 83.9 130 63.76 19 179 1994 45 34 25 19 34.2 28 15 15 141 113 108 87 55.25 15 141 1995 37 27 20 15 28.2 25 27 29 69 307 217 118 76.54 15 307 1996 60 49 33 26 42.9 37 20 14 118 306 300 151 96.52 14 306 1997 90 64 46 44 53.7 34 26 16 138 96 104 58 64.11 16 138 1998 31 23 18 13 24.8 25 43 49 97 125 353 135 77.99 13 353 1999 105 75 58 62 127 92 44 49 47 142 461 256 126.5 44 461 2000 105 78 55 76 101 67 58 100 66 276 199 146 110.7 55 276 2001 86 56 59 38 49.1 43 22 102 45 181 105 115 75.23 22 181 2002 48 34 27 23 20.6 32 17 83 163 168 132 78 68.96 17 168 2003 41 31 23 19 21 38 28 43 151 147 143 102 65.57 19 151 2004 53 35 32 33 26.7 55 49 101 89 85 207 80 70.33 27 207

Mean 54 38 30 27 42 49 33 42 85 176 183 102 71.9 Min 11 8.4 6.1 4.5 7.15 4.6 6.8 8.7 12 28 44.5 20 4.5 Max 105 78 59 76 127 185 61 102 223 353 461 256 461


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A comparison of the average monthly discharges given above with the Feasibility Study is shown in the table below: Comparison of Average Monthly Discharges in m3/s

Study Jan Feb Mar Apr May June July Aug Sep Oct Nov Dec YearPPTA 54 38 30 27 42 49 33 42 85 176 183 102 71.9 FS 75 47 33 29 39 42 32 38 66 205 277 176 88.2 Difference -21 -9 -3 -2 +3 +7 +1 +4 +19 -29 -94 -74 -16.3

As seen in the table above, the main differences are in the wet season, while the dry season discharges are fairly consistent for the two studies.

2.3.2 Technical Issues

A number of technical issues and suggested modifications that are recommended to be studied in the Technical Design Phase are discussed in Chapter 3 and summarized in the table below: Structure Item Issue Reference Reservoir Inflow Update Section 2.3.1 Minimum Operating Level Review when new inflow data Section 2.3.3 Initial Filling Planning Section 4.5 Dam Design Proposed changes Section 3.3.2 RCC Trial Mix Program Section 3.3.6 RCC Source of Pozzolan Section 3.2.5.5 Monitoring Update Section 3.3.12 PMF Stability Section 3.3.3.1 Diversion Arrangements

Cofferdam Lower level Section 3.3.5.1

Diversion culvert Capacity Section 3.3.5.1 Closure Planning Section 3.3.5.3 Spillway Model Tests Section 3.3.3 Gantry Crane Omission Section 3.3.3.2 Chute Aeration device Section 3.3.3.5 Chute Dividing walls Section 3.3.3.6 Plunge-pool Dimensions Section 3.3.3.3 Plunge-pool Support of banks Section 3.3.3.4 Headrace Tunnel Support System Unlined Sections 3.4.2 Surge Arrangement

Support System Unlined Section 3.4.3.2

Stability Analyses Section 3.4.3.1 Penstock Diameter Increased Section 3.4.4.1 Location Relocation Section 3.4.4.2 Steel-lining Reduced length Section 3.4.4.2 Support System Concrete lining Section 3.4.4.2 Powerhouse Location Underground Alternative with

short Headrace Tunnel Section 3.5.4

Location Structure cast against the cut slope and bifurcation in rock

Sections 3.5.3.2


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Installed Capacity Review when new inflow data Section 3.1.2 Energy Generation Review when new inflow data Section 2.3.5 Dimensions and

Functions Modifications and relocation if

Surface Alternative Section 3.5.1

2.3.3 Minimum Operating Level

In the Feasibility Study a Minimum Operating Level (MOL) of +195 m is proposed for Song Bung 4 Hydropower Project, i.e. a reservoir regulation of 27.5 m. The average monthly energy generation for different minimum operating levels (based on daily values for the 27-year period 1978-2004 and assuming inflow according to Section 2.3.1) is given in the table below: Average Monthly Energy Production, GWh, Without Compensation Flow

MOL m

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year

+195 44.9 33.3 32.1 31.2 34.6 35.1 31.8 35.2 42.6 68.0 80.5 67.8 537.1+200 43.8 38.9 33.5 29.5 36.2 40.7 31.4 34.0 37.4 71.1 84.8 65.7 546.9+205 44.0 35.3 30.6 27.4 40.5 39.4 30.6 34.1 39.8 74.1 87.3 67.8 550.8+210 44.1 35.3 27.0 28.0 34.8 41.0 29.3 33.2 42.9 80.0 86.0 71.9 553.4+215 44.1 31.6 27.2 20.9 36.1 35.9 30.4 35.0 49.4 82.9 85.9 73.9 553.2+220 44.1 27.9 23.6 21.2 33.0 36.5 27.0 32.4 51.9 82.8 87.2 76.2 543.7

As seen in the table above the maximum average annual energy generation is delivered at a minimum operating level at around +215 m, with 553 GWh/year or 16 GWh/year higher than for a MOL of +195 m. The reason for a higher energy generation at a higher minimum operating level is that the loss in head due to higher drawdown of the reservoir is not compensated by the increased discharge due to the additional storage capacity.

Based on the average annual energy generation only, a higher minimum operating level at +215 m should have been selected. The main difference between minimum operating levels of +215 m and +195 m is however the higher firm capacity that can be provided at the lower minimum operating level. This is evident from the table below showing the minimum monthly capacity during the dry season for minimum operating levels of +195 m and +215 m: Minimum Monthly Capacity, MW, Without Compensation Flow

MOL m

Feb Mar Apr May Jun Jul Aug Sep

+195 40.0 17.4 17.6 18.8 14.9 18.9 16.8 11.2 +215 14.7 11.3 4.1 12.2 4.3 12.4 14.1 6.5 Diff 25.3 6.1 13.5 6.6 10.6 6.5 2.7 4.7

The firm capacity (the capacity at 90% reliability) amounts to 40 MW for a minimum operating level of +195 m compared to 21 MW for +215 m. Taking into account the firm capacity, or firm energy, in an economic evaluation gives a considerable higher viability for a minimum operating level of +195 m. The MOL of +195 m as proposed in the Feasibility Study is therefore supported.

The proposed Minimum Operating Level at Song Bung 4 Hydropower Project needs to be updated in the Technical Design Phase when more data are available from the gauging station at Song Bung 4 site. Due to the fairly small active storage, the energy production calculations need to be carried out with daily time steps as with monthly time steps the energy generation will be overestimated by some 10%.


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2.3.4 Compensation Flow

As mentioned in the EIA Report a compensation flow bypassing the dam is recommended for environmental reasons, however, there is insufficient baseline data and analysis of aquatic and riparian ecosystems, and affected livelihoods on which to take an informed decision on a compensation flow. A one-year baseline study has therefore been commissioned to determine the fish catch of migratory species that would give a better understanding of the environmental and social benefits of a compensation flow release.

In the following no release of compensation flow is assumed. Should however the study mentioned above show a need for a compensation flow, the main part of the lost energy (due to the compensation flow) can be regained by a small power plant at the foot of the dam, or with the installation of a small third unit in the powerhouse should a compensation flow be required only downstream of the power station.

2.3.5 Energy Production

The energy production of Song Bung 4 Hydropower Project has been calculated based on daily discharge values for the 27-year period 1978-2004 and the seasonal reservoir operating rules for a MOL of +195 m given in Section 2.4.2. For the fairly small active storage of Song Bung 4 Reservoir, it is important to use daily values in the energy production calculations instead of monthly as in the Feasibility Study, as monthly values will underestimate the spilling and thus overestimate the energy production. It is estimated that the energy production is overestimated by as much as 10% by using monthly values.

The average monthly energy production for the period 1978-2004 is given in Table 1, giving the following average monthly energy production: Average Monthly Energy Production, GWh

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year44.9 33.3 32.1 31.2 34.6 35.1 31.8 35.2 42.6 68.0 80.5 67.8 537.1

As seen in the table above, the average energy production amounts to 537 GWh/year, while the firm capacity is estimated at 40 MW giving the following firm and secondary energies: Firm and Secondary Energy, GWh/year

Firm Secondary Total 351 186 537

The energy production of Song Bung 4 Hydropower Project will be increased to 541 GWh/year, i.e. with 4 GWh/year, should the Song Bung 2 Hydropower Project be implemented due to better regulation of Bung River.

The regulation with Song Bung 4 Reservoir will also have a positive effect on the energy production for Song Bung 5 Hydropower Project should it be implemented, and is estimated to increase by 9 GWh/year.

The energy generation from Song Bung 4 Hydropower Project needs to be updated in the Technical Design Phase when more data are available from the gauging station at Song Bung 4 site.


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2.4 Likely Operation Regime of Song Bung 4 Hydropower Project

2.4.1 General

The operating regime of Song Bung 4 Hydropower Project have been studied in the Feasibility Study, based on the hydrological pattern of the inflow and in the context of the power system, however, different operating regimes are given in different versions of the Feasibility Study.

It should be noted that there is a difference between “hydrological-operation” and “demand-operation” of a power plant. In “hydrological-operation” the power and energy output from a power plant is determined by:

• Inflow to the reservoir

• Water stored in the reservoir

• Reservoir operation rules that determine how much water should be released to the power station, and is based on historical data and modeling to optimize the output.

The “hydrological-operation” determines the amount of water that is available for generation over a certain period (day, week, month), but not how this water should be distributed over the period. In the case of a daily period, this amount of water is equal if say 25 m3/s is generated during 24 hours, or 50 m3/s during 12 hours, or 100 m3/s during 6 hours. The actual operation, for instance over a day, is normally determined by the “demand-operation” that is based on, at each instance, the energy requirements in the power system.

Even planned “demand-operation” changes, such as for the following reasons:

• Other power stations in the power system have to shutdown and other power stations have to cover the deficit in supply.

• Varying hydrological conditions in the country may change the operation pattern for some hydropower plants.

• Over the years, when new power plants are being commissioned, the operation pattern for older hydropower plants may change.

• When a power market is established in Vietnam it will be more profitable for the hydropower plants to operate at intermediate and peak loads, rather than at base load, as hydropower have the flexibility to operate according to the highest tariff.

It should be kept in mind that one of the advantages with hydropower is the flexibility in operation where the load can be increased or decreased in a very short time to respond to variations in demand.

The energy calculations in the Hydrological and Hydrodynamic Modeling Studies (Volume VII of the Second Interim Report) have shown that it is possible to operate the Song Bung 4 Power Station for 24 hours/day for most of the time. This means that for most of the dry season, 40 MW can be produced contiguously. This is probably not a realistic scenario for the following reasons:

• One turbine needs to operate at 50% load for long periods that is not economical due to low efficiency.

• It is not consistent with the variation of the demand over the day, as in a national perspective hydropower aims at covering the intermediate and peak loads, and in the Central region base, intermediate and peak loads.

Consequently, it is prudent to allow for the possibility of “peaking operation” of Song Bung 4 Hydropower Project on a daily basis, weather for 6, 15 or 20 hours, and study and mitigate for the impacts this will cause in terms of varying downstream water levels. As it is not possible to


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study all alternative “peaking” scenarios, with different natural water levels at the onset of “peaking”, a number of representative cases have been studied in the Hydrological and Hydrodynamic Modeling Studies (Volume VII of the Second Interim Report), see also Section 2.5.3.

An alternative could possible be to install one smaller and one larger turbine-generator units in the power station, where the smaller unit would be designed for the flow during the dry season. The disadvantages would be higher costs for the electromechanical equipment (10-15%) and that there could be a need to close down the power station during maintenance of the smaller unit.

Possible mitigation measures for varying downstream water levels could include the following:

• Construction of Song Bung 5 Hydropower Project for re-regulation of the intermittent outflow from A Vuong and Song Bung 4 hydropower projects. This would, however, not mitigate the variations of the some 10 km long river stretch between the power station and the rim of Song Bung 5 Reservoir.

• Warning system along Song Bung where the water level variations are the highest. Downstream of the confluence with Song Cai, the water level variations are probably acceptable for the safety of humans.

2.4.2 Seasonal Reservoir Operation

For Song Bung 4 Hydropower Project with a fairly small active storage, 320 Mm3 at a MOL of +195 m and corresponding to 14% of the mean annual inflow, the possibilities for seasonal regulation is limited. Daily regulation is, however, possible throughout the year giving flexibility on a daily basis.

The reservoir will be operated on a seasonal pattern aiming at filling the reservoir up to the FSL at the end of the wet season, and utilize the storage down to the MOL at the end of the dry season to complement the natural inflow to the reservoir. A typical variation of the reservoir water level during the year and the monthly average inflow is given in the figure below: Figure 2-3. Monthly Average Inflow and Typical Variation of Reservoir Water Level

195

200

205

210

215

220

225

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

35

70

105

140

175

210

Reservoir level Mean inflow

m a.s.l m3/sSong Bung 4 Reservoir


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Different reservoir operation rules have been investigated in the Hydrological and Hydrodynamic Modeling Studies (Volume VII of the Second Interim Report), and the following reservoir operation rule is recommended:

• The reservoir water level for each month should aim at keeping the following minimum levels:

Month Reservoir Water Level, m Month Reservoir Water Level, m January +220 July +198 February +213 August +195 March +211 September +198 April +208 October +203 May +205 November +212 June +202 December +220

• A target power output of 40 MW on a 24-hour daily basis can be produced if the actual reservoir water level is on par with the target water levels above. If the actual reservoir water level is higher or lower than the target water levels, the power output may be increased or decreased, respectively, compared to 40 MW on a 24-hour daily basis.

2.4.3 Daily Reservoir Operation

The operation rules given above are on a seasonal basis, but the storage may also be used for daily regulation, i.e. the 40 MW on a 24-hour daily basis mentioned in Section 2.4.2 may be distributed during the day such that 80 MW may be produced during 12 hours, or the installed capacity of 156 MW during some 6 hours, in accordance with the demand.

In the latest version of the Feasibility Study, the anticipated daily operation of Song Bung 4 Power Station is given for different months and scenarios as follows: Daily Operating of Song Bung 4 Power Station, Hours/Day

Month 2011 Dry

Basic

2011 Normal Basic

2011 Dry

High

2011 Normal

High

2015 Dry

Basic

2015 Normal Basic

2015 Dry

High

2015 Normal

High Jan 19 20 19 19 15 17 15 15 Feb 18 19 17 18 15 15 15 15 Mar 16 18 16 18 15 17 15 15 Apr 19 21 18 20 17 17 16 17 May 19 18 18 17 17 17 16 15 June 20 24 19 24 18 15 17 15 July 24 17 24 17 15 15 15 15 Aug 24 16 21 16 19 15 17 15 Sep 19 16 19 24 17 15 17 15 Oct 18 24 17 24 15 19 15 20 Nov 18 24 18 24 15 24 15 24 Dec 18 22 17 22 15 22 15 22

As seen in the table above, the operation hours varies between 15 hours/day and 24 hours/day. As, however, mentioned in Section 2.4.1 the actual daily operation pattern may vary depending on the actual demand in the power system, and it is prudent to allow for the possibility of “peaking operation” of the power station also for shorter operating hours.

It should be noted that the downstream water level variations are mainly dependent on the following:

• The difference in turbine outflow during “peaking”.


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• The natural water level in the river at the onset of “peaking”.

Consequently, the duration of the peaking is not important as even with a 20-hour “peaking” mode the water level at least down to Hoi Khach goes down to the “natural water level” before the onset of the next “peaking” period. The natural water level at the onset of “peaking” is important as the river channel widens at higher elevations and thus creates less water level variations. This would mean that “peaking” in the dry season gives higher water level variations compared to the wet season.

2.5 Downstream Hydrological Regime

2.5.1 General

The Final Report on the Hydrological and Hydrodynamic Modeling Studies was given in Volume VII of the Second Interim Report dated June 2006. In the following, a summary of the downstream hydrological regime is given with focus on Song Bung 4 Hydropower Project.

The construction of Song Bung 4 Hydropower Project, and the regulation of Bung River with Song Bung 4 Reservoir, will have effects on the hydrological regime downstream of the dam and power station, both on the seasonal pattern and on the daily pattern.

In this PPTA, the downstream impacts have in all aspects been limited down to the confluence between Vu Gia and Thu Bon rivers, based on the following:

• The Song Bung 4 Hydropower Project will have very little impact on both the water flow and water level downstream of this confluence.

• Downstream of the confluence to the coast there is a large variety of human activities, which create erosion and pollution, and which makes it impossible to assess any water quality impacts from Song Bung 4 Hydropower Project alone.

• The impacts on water flow and water levels downstream of the confluence are so marginal that they don’t have any impact on stationary aquatic life.

• As long as the other rivers in Vu Gia – Thu Bon River Basin are accessible for migratory fish species, Song Bung 4 Hydropower Project will marginally impact the migratory fish fauna downstream of the confluence.

• The wetland area between the rivers, which are flooded every year, is the lowermost spawning area for downward migrating fish from Song Bung.

• There are a large variety of activities in the area downstream of the confluence, which means that people living here are not so dependent on fish from the river, as people further upstream. It is easy to find an alternative support for life if the fishery for some reason should fail.

However, when the whole planned hydropower development in Vu Gia – Thu Bon River Basin is implemented (8 projects), there will be impacts at least on fish biodiversity and fish production also in the river reach downstream of the confluence.

2.5.2 Changes in the Seasonal Regime

2.5.2.1 General As with all hydropower projects with a seasonal storage, the flow downstream of Song Bung 4 Hydropower Project increases in the dry season and is reduced in the wet season. The increase and reduction depends on the size of the active and flood control storages, respectively, and how the storages are operated.


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2.5.2.2 Seasonal Changes in the Dry Season The increase in the downstream dry season flow is illustrated by the following two duration curves assuming a compensation flow of 10% of the mean annual flow: Figure 2-4. Duration Curves Downstream of Song Bung 4 Power Station

1

10

100

1000

10000

0%10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

P

Q(m

³/s)

BLBL+SB4BL+SB4+SB2

Figure 2-5. Duration Curves at Hoi Khach Downstream of the Confluence with Song Cai

10

100

1000

0%10%

20%

30%

40%

50%

60%

70%

80%

90%

100%P

Q(m

³/s)

BL

BL+SB4

BL+SB4+SB5

BL+SB4+SB2

Note: In the duration curves above, “BL” denounces the baseline conditions with A Vuong Hydropower Project being constructed


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As seen from the duration curves above, the regulation of Song Bung 4 Reservoir increases the downstream flow in the dry season (flow with high duration). This is also evident from the table below showing discharges for different durations according to the figures above: Discharges for Different Durations in m3/s

Duration, % Downstream of Song Bung 4 Power Station

Downstream of the Confluence with Song Cai

Baseline Discharge

After Song Bung 4

Difference Baseline Discharge

After Song Bung 4

Difference

95 15 13 2 50 59 9 90 18 37 19 61 85 24 85 21 48 27 68 94 26 80 23 48 25 76 99 23 70 29 48 19 93 110 17 60 37 49 12 115 124 9 50 45 51 6 141 143 2

2.5.2.3 Seasonal Changes in the Wet Season In the NHP Study, a Flood Control Level of +221.8 m was suggested for Song Bung 4 Hydropower Project, i.e. a drawdown with 0.7 m during the wet season to mainly accommodate smaller floods. The level, with a Flood Control Volume of 11 Mm3, was optimized considering lost energy production and benefits in reduced flood damages.

In this PPTA, the reduction in floods due to Song Bung 4 Reservoir has been investigated for two floods, one in November 1999 with an extreme peak flow of some 4,000 m3/s at Song Bung 4 and one in October 2002 with a normal peak flow of some 550 m3/s.

The reduction in outflow from Song Bung 4 Reservoir during the two flood events are given in the figures below: Figure 2-6. Discharge Downstream of Song Bung 4 Dam – November 1999

Baseline ּס Baseline + Bung 4


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Figure 2-7. Discharge Downstream of Song Bung 4 Dam – October 2002

Note: In the hydrographs above, “Baseline” denounces the baseline conditions with A Vuong Hydropower Project being constructed

The water level at Hoi Khach, downstream of the confluence with Song Cai, is hardly reduced for an extreme event as the flood in November 1999, while for the normal flood in October 2002, the reduction is some 0.2 m. Using a Flood Control Level of +221.8 m at Song Bung 4 Reservoir gives an attenuation of the flow in a normal year, but the effects during extreme flood events are marginal.

2.5.3 Changes in the Daily Regime

As mentioned in Section 2.4.3, the Song Bung 4 Power Station will most probably be operated during part of the day only, implying that downstream water levels will vary on a daily basis depending on the outflow from the power station.

As the variation of the downstream water level depends on a number of factors, such as the size of the outflow and the water level at the onset of the flow, a number of different scenarios have been studied in the Hydrological and Hydrodynamic Modeling Studies (Volume VII of Second Interim Report). A further complication is the unknown operation pattern of A Vuong Power Station that, if operated simultaneous with Song Bung 4 Power Station, could create large water level variations further downstream.

The result of the studies on downstream water level variations is summarized in the table below, for details see the Hydrological and Hydrodynamic Modeling Studies (Volume VII of the Second Interim Report): Case Downstream of A Vuong

Power Station Hoi Khach, D/S of the

Confluence with Song Cai Al Nghia, D/S of the

Confluence with Thu Bon Water Level

Variation, m Max. Water Level Rise in 1 hour, m

Water Level Variation, m

Max. Water Level Rise in 1 hour, m

Water Level Variation, m

Max. Water Level Rise in 1 hour, m

1 0.92 0.42 0.32 0.15 2 0.58 0.49 0.15 0.12 3 2.03 1.28 0.62 0.37 0.14 0.08 4 3.41 1.63 1.00 0.48 5 1.78 1.00 0.53 0.30

Baseline ּס Baseline + Bung 4


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The different cases above are defined in the following table: Case Month Song Bung 4 A Vuong

Outflow m3/s

Operation Hours

Compensation Flow, m3/s

Outflow m3/s

Operation Hours

Compensation Flow, m3/s

1 July 1990 37 6 0-7.2 0 - 3 2 July 2002 37 20 0-7.2 19 24 3 3 July 2002 147 5 0-7.2 19 24 3 4 July 2002 147 5 0-7.2 78 6 3 5 Dec 2002 147 13 0-7.2 78 24 3

Longitudinal plots of the maximum changes of downstream water levels are shown for some cases below: Figure 2-8. Longitudinal Plot of Maximum Water Level Variations Downstream of Song Bung 4 Power Station to Hoi Khach for Case 1

Figure 2-9. Longitudinal Plot of Maximum Water Level Variations Downstream of Song Bung 4 Power Station to Al Nghia for Case 3


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Figure 2-10. Longitudinal Plot of Maximum Water Level Variations Downstream of Song Bung 4 Power Station to Hoi Khach for Case 4

Figure 2-11. Longitudinal Plot of Maximum Water Level Variations Downstream of Song Bung 4 Power Station to Hoi Khach for Case 5

As seen above, “peaking” operation of the power stations significantly influences the water level variations in the downstream reaches of Song Bung 4. This is especially the case upstream of the confluence between Song Bung and Song Cai. Downstream of the confluence the effect is reduced, as the discharge from Song Cai and the wider cross-section of the river alleviate the water level variations.

The water level variations can increase or decrease depending upon the operation of the A Vuong Power Station. It is suggested that the operation of the two power stations are closely coordinated as changes due to “peaking” in the dry season have significant impact on the downstream reaches. Starting the turbines of the two power stations at the same time this will be the worst case, causing a rapid water level variation. Starting the turbines at the two power stations sequentially and in a stepwise manner would alleviate rapid water level variations further downstream.

2.6 Multipurpose Aspects The multipurpose aspects of Song Bung 4 Hydropower Project were studied in the NHP Study as summarized below:

• The irrigation benefit, due to increased flow in the dry season, was estimated at 0.2 MUSD/year.


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• The flood control benefits, assuming a Flood Control Level of +221.8 m and a corresponding Flood Control Volume of 11 Mm3, was estimated at 0.3 MUSD/year

2.7 Risks Song Bung 4 Hydropower Project will have several types of risks, including geotechnical, hydrological, and financial risks, and the design has taken appropriate steps to avoid or minimize all of them. In general, the design of the various project components is traditional and within accepted norms and practices. The dam height is in the mid range for this type of dam (RCC dams have been built higher than 190 m), and turbines with the proposed range of head and discharges have been installed in many projects before Song Bung 4.

The hydrological risk during construction would be minimal as overtopping of an RCC dam is quite normal and construction can proceed once the flood has passed. Extreme floods normally last for less than one week in the wet season from September to December. The spillway of the Project is designed to pass the estimated Probable Maximum Flood (PMF). The power station will, at least during the dry season, be operated during parts of the day that could cause rapid variations in downstream water levels. Adequate measures have been proposed to mitigate these effects.

The geotechnical risk at dam site, tunnel and powerhouse site is expected to be manageable due to the rather good geological conditions in the project area. During excavation of the tunnel, week rock formations may be expected in some areas where additional strengthening in the form of steel ribs will be required.

Financial risks have been analyzed in the financial sensitivity analysis of the Project in respect of reduction in selling price, increase in capital cost, delay of commencement, reduction in selling price and reduced energy generation due to hydrological factors, and are manageable.

3 Technical Review of Feasibility Study

3.1 Overall Layout

3.1.1 General

In general, the layout of Song Bung 4 Hydropower Project as proposed in the Feasibility Study is well conceived by utilizing a sharp bend in Bung River downstream of the dam and creating a natural head of some 27 m by the 3.3 km long waterway. The natural length of the river from the dam site to the power station is some 5 km giving a gradient of 0.5%

One may argue if this fairly low gradient of the river warrants the cost for the proposed waterway and an alternative with a power station at the foot of the dam was investigated in the updated Feasibility Study, and the proposed location of the power station was found to be more economic viable.

There may be a possibility to move the power station further downstream by some 1.2 km before the river makes a sharp turn to the northeast. In this case the waterway need to be prolonged by some 250 m, that tentatively may cost an additional 1.8 MUSD, or an additional 1% of the total investment cost, given that all other costs are equal. According to the Feasibility Study the average head is 113.4 m, indicating that a downstream located power station could be viable if the difference in natural water level, between the proposed power station and the site some 1.2 km further downstream, would be higher than say 1.2 m. Water level measurements at these two locations have been carried out by PECC3, however, indicating a difference of only some 1.0 m.


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A number of alternative dam sites have been investigated both in the Pre-feasibility Study and in the Feasibility Study. In the Pre-feasibility Study by PECC3 from May 2004, 5 alternative dam sites were investigated, of which three (Dam Site Nos. 1, 2 and 3) were located in the vicinity of the now proposed dam site and two further upstream (Dam Site Nos. 4 and 5). Dam Site No. 1 and No. 2 were found to be the most viable, while Dam Site Nos. 4 and 5 were found non-viable, and were further studied in the Feasibility Study, where it was concluded that Dam Site No. 1B is the most viable.

The proposed Full Supply Level of +222.5 m may be argued to be the practical maximum full supply level as the tail water level of the power station for the proposed upstream-located Song Bung 2 Hydropower Project is in that region, and power generation system simulations in the NHP Study also supported this level. The Song Bung 2 Hydropower Project utilizes a U-turn in Bung River and the proposed location of the power station gives the shortest waterway and hence the lowest cost. Relocation of that power station further upstream, to allow a higher undisturbed FSL for Song Bung 4 Hydropower Project, would only increase the cost and decrease the energy production of Song Bung 2 Hydropower Project.

The Song Bung 4 Hydropower Project is designed in accordance with Vietnamese standards that would facilitate construction according to normal practice among Vietnamese contractors. Although the proposed Project would be feasible to construct, possible technical modifications have been suggested as given below that are recommended to be further studied in the Technical Design Phase of the Project. When designed properly and with the right construction methods, it is believed that new solutions on some of the components of the Project would improve the economy of the Project.

3.1.2 Considerations on the Installed Capacity

As mentioned in Section 2.3.1, the average discharge at Song Bung 4 dam site is now estimated at 71.9 m3/s, being nearly 20% lower compared to the average discharge estimated in the Feasibility Study of 88.2 m3/s. It should however be noted that the differences are mainly in the wet season.

It may therefore be argued if the recommended installed capacity should still remain at 156 MW. In the table below the average annual energy production for Song Bung 4 Hydropower Project is given for the now estimated average discharge, for installed capacities of 156 MW and 180 MW, minimum operating levels of +195 m and +220 m, and compensation flows by-pass the dam of 0%, 5% and 10% of the average discharge:

Minimum Operating Level

m

Compensation Flow

% of 71.9 m3/s

Installed Capacity

MW

Energy Production GWh/year

Incremental Energy Production

GWh/year 195 0 156 537.9

0 180 553.2 15.3 5 156 508.6 5 180 522.6 14.0 10 156 479.3 10 180 492.4 13.1

220 0 156 525.4 0 180 542.9 17.5 5 156 494.5 5 180 511.2 16.7 10 156 463.4 10 180 479.4 16.0


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In the NHP Study, the total investment cost for Song Bung 4 Hydropower Project were estimated for different installed capacities at a FSL of +222.5 m and a MOL of +195 m. Using the incremental total investment cost from the NHP Study and the incremental energy production in the table above, an economic evaluation using a discount rate of 10% and an energy value of 0.05 USD/kWh gives the following results:

Minimum Operating Level m

Compensation Flow

% of 71.9 m3/s

Installed Capacity

MW

Energy Production GWh/year

Incremental Energy

Production GWh/year

Incremental Cost

MUSD

B/C Ratio

195 0 156 537.9 0 180 553.2 15.3 7.2 0.90 5 156 508.6 5 180 522.6 14.0 7.2 0.80 10 156 479.3 10 180 492.4 13.1 7.2 0.74

220 0 156 525.4 0 180 542.9 17.5 7.2 0.99 5 156 494.5 5 180 511.2 16.7 7.2 0.95 10 156 463.4 10 180 479.4 16.0 7.2 0.91

As seen in the table above it is not viable to increase the installed capacity to 180 MW, as the maximum B/C ratio amounts to 0.99. It may therefore be concluded that the recommended installed capacity of 156 MW in the Feasibility Study should be maintained, however, this should be confirmed in the Technical Design Phase when new estimates of the inflow to Song Bung 4 site are available.

3.2 Review of Geological and Geotechnical Conditions

3.2.1 Introduction

3.2.1.1 General The investigations in the pre-feasibility stage comprised five alternative locations of the dam axes of which Dam Sites No.1 and No.2 were selected for further study in the feasibility stage that resulted in Dam Site No. 1B being selected.

The reservoir and headwork area is located on the eastern part of the Truong fold zone on the northern margin of the Quang Nam structural zone belonging to the northern margin of the Kon Tum uplift.

The geological structure of the Project Area consists of the following formations:

• Nui Vu (PR3-ε1nv)

• Song Bung (T1-2sb)

• An Diem (T3nad)

• Igneous intrusions

• Quaternary loose sediments (aQiv)

Within the area of the headwork, the Song Bung lower sub-formation is encountered. The


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other formations are present in the reservoir area.

3.2.1.2 Regional Geological Setting General

The topography is originated from denudation, the slopes are inclined from about 350 to 450, and in some areas more gentle slopes are present varying from about 200 to 250. The level of the denuded mountainous surface in the region is on average about +800 m.

Formations Present in the Region

According to the regional Geological Map in scale 1:200,000, the distribution of the strata in the reservoir and headworks areas can be summarized as follows:

• The igneous sediment complex of the A Vuong (ε2 – O1) formation. The rocks types are widely distributed in the area. The formation includes quartzite-like sandstone schist, cherty schist, basic effusive, and acidic effusive sediments. The rocks are strongly folded.

• Upper Devon Complex

The Upper Devon Complex is distributed in narrow mountain gorges, largely distributed upon the A Vuong stratum. It un-conformably covers more archaic formations. This complex consists of granitoid formations of Lower Devonian – Dai Loc Complex. The thickness is more than 700 m.

Formations of this age include:

- Upper Paleozoic Granite – granodiorite igneous formations (PZ3) of Ben Giang-Que Son Complex, outcropping to the south of the dam site area.

- Lower Mesozoic formations. Largely distributed on Song Bung zone with total thickness of about 3,000 m, consisting of igneous sediments of Lower Triassic (T1-2). According to geological data, they are at the south-western part of Song Bung synclinal striking SW-NE.

- Upper Triassic (T3) - Nong Son Formation. Consisting of molasse formations rich in coal. The thickness is about 1,400 m and un-conformably covering archaic formations.

- Upper Mesozoic formations of An Diem Formation (J3nad). Consisting of terrestrial and terrigenous deposits, with a total thickness of over 1,500 m, and un-conformably covering archaic formations.

- Kainozoic formations consisting of granite, alaskite granite of the Ba Na Complex; basalt effusive and loose Quaternary sediments. In limited areas, Kainozoic formations develop in deposits of alluvium, proluvium and deluvium with limited thickness.

Hydrogeology

According to the results of the Feasibility Study, the difference in hydro-geological conditions between the three alternative dam sites (1A, 1B and 2) is similar and can be summarized as follows:

• The climate in the area is hot and humid with heavy rains, so the vegetation cover is abundantly developed creating thick aquifers (near the surface ground water table) in the wet season.


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• The thickness of the aquifers varies from 15 m to 30 m between the wet and dry seasons. The aquifers are generally unconfined and their drainage is fast due to the topography.

• The chemical composition of the aquifers is generally similar and has small mineralization level, not larger than 300 mg/l, in the Calcium-Magnesium Hydro-carbonate or Sodium-Potassium Hydro-carbonate forms. The chemical composition of the ground water makes it non aggressive to concrete.

3.2.1.3 Tectonic Structure The Song Bung 4 Hydropower Project is located on the eastern margin of the Truong Son geoanticline, near the Tha Khet-Tra Bong fault. This fault resulted in three tectonic structures: the Truong Son zone, the Kaledonite-Sekong structural zone and the Kon Tum uplift. Figure 3-1 below shows a tectonic map covering the area: Figure 3-1 Tectonic Setting


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The Project Area is bounded by four deep faults that could be the source of seismic activity: Rao Quan–A Luoi (Grade IIC), Truong Son fault in the West, An Diem – Hoi An (Grade IIC) in the North and Tam Ky – Phuoc Son (Grade IIIC) in the South as given below:

• The Rao Quan-A Luoi fault, with a length of about 100 km, is located along the young valley of A Luoi extending to Song Bung in a Northwest – Southeast direction. This fault manifests high activity, with uplift - extended crust mechanism prone to cause moderate earthquakes, however, landslides might be triggered. The dam area is located about 4 km from the Rao Quan – A Luoi and Dak Krabat faults and the power house some 7 km from the Rao Quan – A Luoi fault.

• The Tam Ky – Phuoc Son fault extends along a direction sub parallel to the latitude from Song Bung to Phuoc Hao, striking in a Northwest – Southeast direction and going along the Song Chang valley to the north of Tam Ky Town to the Eastern Sea. The total length of the fault zone is more than 125 km. The shortest distance from Song Bung 4 Hydropower Project is about 3 km.

• The An Diem – Hoi An fault extends about 125 km and is characterized by changes in the strike direction. It has a 650 North-eastern strike going through A-So to Tam-Prang. Thereafter the fault changes direction and goes parallel to the latitude to Thanh Den. From Thanh Den to Song Vu Gia, the fault again strikes along a 300 north-western direction, finally returns and goes parallel to the latitude from Ha Nha through Ai Nghia and out to the Eastern Sea. The depth of the fault is about 30 km.

Within the Project Area there are other faults classified as grade III and IV and fractures of grade V, VI and VII according to the classification system in the table below: Classification of Faults and Fractures

Grade Type and Character of Fault Length Width Zone of Influence

I-II Regional Tens of km Hundreds of m Hundreds of m III Large Km-tens of km Tens of m 10-100 m IV

Faults

Medium 200-3,000 m 0.5-2.5 m 10 m V Small faults or

large fractures 100-1,000 m 2-50 cm 0.5-1.5 m

VI Medium 10-100 m 2-20 mm VII Small 1-3 m 0.5-2 mm VIII

Joints of various gengsis Very small <1 m <0.5 mm

In the headwork area there are two tectonic fractural zones of grade IVa (IVa-1 and IVa -2) and 31 tectonic fractural zones of grade IV.

In addition the activity of faults has resulted in volcanic activity forming effusive mafic rocks, primarily concentrated to the Triassic period.

3.2.1.4 Seismicity

General

The assessment of the earthquake activity at the Project Area should be based on the Conclusion and Recommendation in the report “The Assessment of earthquake intensity at the area of Song Bung 2 and 4 Hydroelectrical Project” (October 2004), compiled by Institute of Geophysics.


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According to this report, three conclusions are stated as follows:

• The headworks of Song Bung 4 Hydropower Project are located at a structural zone fairly stable on tectonics and geodynamics. All tectonic faults passing through the project area of Song Bung 4 Hydropower Project manifest low activity.

• The geological, tectonic and geodynamic conditions of the project area of Song Bung 4 Hydropower Project are feasible for the construction of hydropower projects.

• The middle zone of the central part of Vietnam is located in the stable continental region - extended crust - with low earthquake activity. According to historically recorded data from the year 1666 until present, only 17 earthquake events with magnitude equal to or greater than M = 4.0 (Richter) have occurred, in which the strongest was M > 5.0 (Richter) (M= 5.7 according to calculation by Institute of Geophysics occurring at a distance of about 300 km from the dam site). No recorded earthquakes with magnitude M > 4 (Richter) have occurred within a radius of 50 km from Song Bung 4 dam site.

Comments

Based on the prevailing situation described above, it is recommended that the MCE (Maximum Credible Earthquake) of this area should be M = 5.7 (Richter).

The following data are recommended to be used in the design of Song Bung 4 Hydropower Project:

• The MDE (Maximum Design Earthquake), corresponding to a return period of 2,000 years, should be:

PGA (Peak Ground Acceleration) = 126.6 cm/sec2 (0,127g), corresponding to grade VII - MSK – 64, to be used for foundation on rock.

• The OBE (Operating Basis Earthquake), corresponding to a return period of 145 years, should be:

PGA (Peak Ground Acceleration) = 42.5 cm/sec2 (0,043g), corresponding to grade VI – MSK – 64, to be used for foundation on rock.

3.2.1.5 Slope Stability in the Project Area General

The main cut slopes in the Project Area will be excavated at the following locations:

• In the area of dam abutments

• In the area of the intake of the headrace tunnel

• In the area of the surge shaft

• In the area of the powerhouse

The different strata in a rock-soil formation and their denomination are presented below:

• edQ = Residual soil

• IA1 = Completely weathered rock

• IA2 = Highly weathered rock


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• IB = Weathered rock

• IIA1 = Slightly weathered, fractured rock

• IIA2 = Fresh, slightly fractured rock

• IIB = Fresh rock

In the investigations, the strength properties of the soil and rock strata have been determined. The strength parameters proposed to be used in the design of the cut slopes are presented in the table below: Strength Properties of the Soil and Rock Strata

Formation Stratum tgφ Cohesion, kPa edQ 0.36 22 IA 0.45 25 IB 0.70 150

IIA1 0.75 200 IIA2 0.80 250

T1-2sb12

IIB 0.85 300 edQ 21 IA 0.45 25 IB 0.65 120

IIA1 0.70 150

T1-2sb13

IIA2 0.75 200

The slope inclinations adopted for the various strata are as follows:

• edQ: 1:2

• IA: 1:1

• IB, IIA and IIB: 1:0.6-0.7

Comment

The design of the slopes is considered appropriate and will give a reasonable factor of safety. It is, however, important that measures are taken in order to drain the slopes and take care of the surface water. Diverting water away from the slope by introducing ditches is often feasible.

3.2.1.6 Performed Investigations General

The investigations performed in the pre-feasibility and feasibility stages are as listed below: Performed investigations

Items Unit Pre FS Pre FS Supplementary

FS Total

Geological Mapping Scale 1:50,000 km2 120 33 153 Scale 1:10,000 km2 25 25 50 Scale 1:2,000 km2 2.4 2.4 Drilling m 693.7 940 2100 3733.7 On land m 500 700 1940 3140 In water m 93.7 240 Quarries: 160 493.7 Excavation m3 1631 1635 878.9 4144.9 Geophysical Exploration Point 362 1192 845 2399 Traverse Resistivity Point 182 817 500 1499 Seismic Refraction Point 180 375 345 900


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Vertical Electrical Sounding Point 760 186 153 1099 Permeability Testing Lugeon Section 48 100 161 309 Pouring in borehole Time 10 40 30 80 In test pit Time 49 70 60 179 Laboratory Testing Undisturbed soil samples No 59 70 32 161 Intact rock samples No 81 85 83 249 Water samples No 40 22 17 79 Rock samples for lithological analysis

No 71 44 100 215

Sand and gravel No 19 4 23 Remoulded samples No 20 20 20 60 Compaction No 9 10 20 39 Spectrum analysis No 5 5 Simple chemical analysis No 5 5

Grain size analysis No 9 9 Installing standpipe No 158 180 80 418 Comments

The performed investigations are considered to give a good overview of the geological conditions within the Project Area. All core-drilled boreholes are vertical and the prevailing fault systems are also nearly vertical, thus the drillings are not giving accurate information on the nature and width of the faults. It is proposed that, in the Technical Design Phase, inclined holes are drilled in the dam axis from the riverbanks penetrating the rock below the riverbed. Further, the width and nature of the grade IVa-1 fault should be determined by drilling an inclined hole. It is recommended that the drilling be performed using double core barrel in order to obtain good quality cores, especially in sections with weaker rock. Along the tunnel only one drill hole has been performed, and it is proposed that some more holes are drilled in order to establish the distribution of strata IB, IIA and IIB. An inclined hole is recommended to be drilled on the grade IVa-2 fault in order to determine its width and nature.

Investigation on possible sources of pozzolan, and testing its properties, should also be performed in the Technical Design Phase.

3.2.2 Geological Conditions in the Project Area

3.2.2.1 General The project area is located in the lower part of the Song Bung formation of Lower-Medium Triassic. Three members are present as follows:

• T1-2sb13, Member 3, encountered in the northern part where the powerhouse is located.

The material is violetish brown sandy siltstone with inter-bedded bluish grey sandstone (40%).

• T1-2sb12, Member 2, encountered in the intermediate part affecting dam site

alternatives 1A, 1B and the headrace tunnel. The material is bluish grey sandstone with inter-bedded violetish brown sandy siltstone (25%).

• T1-2sb11, Member 1, encountered in the southern part where dam site alternative 2 is

located. The material is bluish grey sandstone with inter-bedded violetish brown sandy siltstone (10%).

The prevailing geology within the Project Area, with the competent sandstone and siltstone of


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the Song Bung formation, is favourable for the construction of a hydropower project. The investigations have been performed having in mind that various dam types may be considered. Foundation conditions, as well as availability of borrow areas and quarry sites, have been investigated such that different alternatives could be compared.

3.2.2.2 Dam Sites General

Three alternative dam sites (1A, 1B and 2) have been studied in the Feasibility Study, all located along a 700 m long section of the river. They are located in Member 1, T1-2sb1

1, of the lower part of the Song Bung formation. All three sites are affected by the fault zone IVa-1. The northern site 1A is also affected by the fault IV-2. The intermediate site 1B is also affected by the fault IV-1. The upstream site 2 is in addition to IVa-1 also affected by the faults IV-8, IV-12, IV-13 and IV-15.

Weathering Profiles

Dam Site 1A

The thickness of the superficial strata, edQ and IA, varies between 10 and 30 m in the abutments. The underlying stratum IB has a thickness in the order of 20 m. This stratum outcrops in the riverbed. Stratum IIA is encountered at a depth of 35-50 m in the abutments and between 20 and 30 m in the riverbed.

Dam Site 1B

The thickness of the weathered strata, edQ and IA, varies between 10 and 20 m in the abutments. The underlying stratum IB has a thickness varying between 20 and 30 m in the abutments and 10 m in the riverbed where it is outcropping. Stratum IIA is encountered at a depth of 45-50 m in the abutments and at a depth of 10-15 m in the riverbed.

Dam Site 2

In the left abutment the thickness of edQ and IA is in the order of 10 m, and in the right abutment in the order of 20 m. The thickness of stratum IB is in the order of 20-25 m in the abutments and in the order of 10-15 m in the riverbed where it is outcropping. The depth to stratum IIA is in the order of 35 m in the abutments and 10-15 m in the riverbed.

Comments

The geological conditions at the three dam sites are similar considering rock formation and weathering profile.

3.2.2.3 Power Waterway General

As Dam Site 1B was selected in the Feasibility Study, see Section 3.3.1.4, the shorter tunnel (alternative 1) will be valid. The tunnel will have a length of 3,046 m. The blasted tunnel will have a horseshoe section with a span of 7.5 m. The intake and upstream part of the tunnel will be located in Member 1, T1-2sb1

2 of the lower part of the Song Bung formation and the downstream part of the tunnel will be located in Member 3, T1-2sb1

3. One drill hole with a depth of 70 m has been sunk reaching the tunnel elevation, about 680 m from the intake. At a depth of 50 m a grade IV fault (IV-3) was encountered in which the rock of stratum IIA was heavily fractured with a RQD of 50%. Along the tunnel alignment a total of 9 faults of grade IV and one fault of grade IVa (IVa-2) are present. Several grade V fracture zones will be penetrated.


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Comments

The tunnel will be located in the fresh rock of strata IIA and IIB, which is considered favorable from tunneling point of view. The grade IV and V faults, which will be penetrated, will require more support and might to some extent reduce the progress rate of the tunnel excavation. However, the faults are not expected to cause any major problems.

3.2.2.4 Power House General

The powerhouse will be located in Member 3, (T1-2sb13), of the lower part of the Song Bung

formation. It is planned to be an aboveground structure. The downstream part of the powerhouse foundation will be affected by a grade IV fault (IV-1).

Comments

The foundation conditions for the aboveground powerhouse are considered favorable with the structure founded in stratum IIA. Other solutions as to the location of the powerhouse are discussed in Section 3.5.3.

3.2.2.5 Reservoir Area Water Tightness of the Reservoir

The rock formations present in the reservoir area are the Nui Vu, Song Bung, An Diem and the Ben Giang-Que Son.

The oldest formation encountered within the reservoir area is the Nui Vu formation consisting of schist, quartz schist. The Song Bung formation comprises bluish grey sandstone interbedded with violetish brown siltstone. The An Diem formation consists of quartz arkose sandstone and gritstone. The Ben Giang-Que Son formation consists of igneous rock, mainly granodiorite.

No limestone formations are present within the reservoir area. The weathering zones in the formations have thickness as indicated below: Thickness of Weathering Zones

Thickness, m Formation eQ IA

Nui Vu 2-4 8-10 Song Bung 5-10 10-15 An Diem 2-5 10-12 Ben Giang-Que Son 3-5 10-12

The permeability of eluvial-deluvial and eluvial soils is in the order of 3x10-6 m/s, in sandy soils 3x10-4 m/s. The permeability of the fractured rock is in the order of 2x10-6 m/s. However, some fault zones belonging to grade III and IV cut across the reservoir area and might cause zones of higher permeability.

On the left side of the reservoir the valley of A Vuong River is located. The distance to the water divide is between 1 and 5 km. The ground water level at the divide is located between El. 750 m and El. 770 m, thus at a considerably higher elevation than the reservoir.

The valley of Thanh River is located on the right side of the reservoir. The ground water level at the divide is located at an elevation higher than El. 1,000 m, i.e. above the reservoir level.

Leakage from the reservoir is therefore restricted to the abutments and the foundation of the dam where high gradients are present.


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Preliminary calculations indicate that the leakage in this area will be in the order of 120 m3/day provided a grout curtain is installed. This leakage is in the order of 0.2‰ of the expected evaporation from the reservoir.

Landslides in the Reservoir

The occurrence of landslides is mainly affected by:

• Inclination of slope

• Soil properties

• Variation in water level

• Wave height

In general the slopes have an inclination of 30-35º, but within some areas they are flatter, 20-25º. The strength of the alluvial soils is in the order of φ=18º and cohesion of 20 kPa. The maximum wave height is in the order of 1.8 m.

Four areas are considered most exposed to sliding with the following estimated volumes:

• Area 1 on the left bank opposite the Nang stream with a length of 1 km. The inclination of the slope is in the order of 20-30º and the wave height 1.8 m. Preliminary calculations indicate that the width of the slide area is in the order of 10.5 m and the depth 2.5 m involving a slide volume of 21,000 m3 after 10 years. After 100 years the width has increased to 120 m and the depth to 4.5 m, with a slide volume of 540,000 m3.

• Area 2 on the right bank of the reservoir and on the left bank of Ta Vin stream with a length of 1 km. The inclination of the slope is 25-32º and the maximum wave height 1.8 m. Preliminary calculations indicate that the width of the slide area is in the order of 12.5 m and the depth 2 m involving a slide volume of 25,000 m3 after 10 years. After 100 years the width is 108 m, the depth 5.5 m and the slide volume 575,000 m3.

• Area 3 on the right bank of the reservoir and on the right bank of Ta Vin stream with a length of 1 km. The inclination of the slope is 20-40º and the maximum wave height 1.5 m. After 10 years the width of the slide area is 10 m, the depth 2 m and the slide volume 20,000 m3. After 100 years the width is 120 m, the depth 3.5 m and the slide volume 425,000 m3.

• Area 4 on the right bank of the reservoir is located 1 km upstream of dam axis 2 with a length of 1 km. The inclination of the slope is 30-35º and the maximum wave height 1.5 m. The width of the slide area is 12 m, the depth 2 m and the slide volume 24,000 m3 after 10 years. After 100 years the width of the slide is 105 m, the depth 4-5 m and the slide volume 490,000 m3.

The total slide volume after 10 years may be estimated at some 150,000 m3 and after 100 years at some 3 million m3. Considering the large dead storage of some 170x106 m3 this should be acceptable.

3.2.3 Considerations on the Design of the Rock Support in Tunnels

3.2.3.1 General The rock support described in the following is the temporary support required to stabilize the rock surrounding the opening prior to the installation of a cast concrete lining. In case no cast lining is considered, the walls and roof are proposed to be covered by a layer of fiber- reinforced shotcrete giving a minimum thickness of 50 mm.


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As a basis for the design of the support the rock mass is divided in rock classes with each class requiring a specified support. Normally 4-5 rock classes are introduced. The most common classification systems are the RMR and Q systems.

In the RMR system the following classes might be defined:

• Rock class I, RMR=100-81, very good rock

• Rock class II, RMR=80-61,good rock

• Rock class III, RMR=60-41, fair rock

• Rock class IV, RMR=40-21, poor rock

• Rock class V, RMR<20, very poor rock

The support input in the various classes might be as described below. It should however be noted that the proposed support is tentative and might have to be adjusted to fit the geological conditions encountered during construction.

Rock Class

Crown Walls

I Bolts l=3m c/c 3.5m, shotcrete 30mm where required

Spotbolting l=3m

II Bolts l=3m c/c 2.5m, shotcrete 30-60mm Spotbolting l=3m III Bolts l=3m c/c 2m, shotcrete 60mm

reinforced by mesh or fibers Bolts l=3m c/c 2m, shotcrete 60mm

reinforced by mesh or fibers IV Bolts l=4m c/c 1.8m, shotcrete 100mm

reinforced by mesh or fibers Bolts l=4m c/c 2m, shotcrete 100mm

reinforced by mesh or fibers V Bolts l=4m c/c 1.5m, shotcrete 150mm

reinforced by mesh or fibers Bolts l=4m c/c 1.5m, shotcrete

150mm reinforced by mesh or fibers All bolts should be fully grouted and have a diameter of 25 mm. The shotcrete should have a compressive strength of at least 25 MPa.

In Rock Class V additional reinforced shotcrete arches or steel sets might be required, also a temporary invert slab might have to be introduced, see below.

The mesh mentioned in the table above is φ 6 mm c/c 150 mm and the fiber content giving equal bearing capacity is 60 kg/m3.

The major part of the tunnels is considered to be located in rock belonging to rock classes II-III and can be excavated with normal lengths of the rounds of about 3 m. The progress per heading is dependent on the equipment available, but can be expected to be in the order of 20-30 m/week at each heading. In case poor rock conditions are encountered the advance will be reduced. Weak rock might be encountered at the adit tunnel portals and for limited parts of the headrace tunnel where it is cut by grade IV faults.

3.2.3.2 Support and Excavation Technique in Class V Rock Rock belonging to Class V might be encountered in the faulted zone IVa-2 and in the portal areas. In order to perform the excavation as fast and economically as possible, various support methods have to be used and the design of the support has to be adjusted to the actual conditions. A key to successful excavation in weak rock is the use of observations. In front of the tunnel, probe holes are drilled in order to establish the presence of weak zones before they are reached by the tunnel front. The behavior of the installed support should be kept under observation. Further monitoring of the deformation pattern of the walls might be introduced.

Four factors that will be discussed in the following are of importance when excavating in poor rock, namely:


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• Reduced advance

• Reduced section

• Spiling

• Timing

It should be noted that Rock Class V covers a wide range of rock conditions with highly varying stand-up times. The support measures indicated above are to be regarded as guidelines.

3.2.3.3 Active Span and Stand-up Time While performing an excavation in poor rock, the advance rate is limited by the stand-up time of the rock mass and the maximum active span. With stand-up time is meant the time an unsupported excavation remains stable without any downfall. A design criterion can be stated as:

Time before stabilization < Stand-up time

Active span is the shortest distance between two active supports in an excavation. These supports are normally either the tunnel walls or the tunnel face and the end of the installed support.

Bieniawski has compared the stand-up times for unsupported excavation spans predicted by Scandinavian, South African and Austrian rock mass classification systems. The indicated ratings are according to the RMR-system, see the figure below. If a prediction of the stand-up time for an excavation is required, then the actual RMR value has to be determined initially. Stand-up time and the maximum unsupported span might then be estimated by interpolation in the following graph:

3.2.3.4 Stability of Excavation due to Separate Factors In poor and very poor rock it is often one single property that determines the behaviour of a rock mass rather than the overall rating. While excavating Class IV-V rock, it is important to be observant on sudden variations in ground conditions. Properties that may vary considerably in


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the same rock mass are clay content, amount of active clays, amount of crushed material, amount of water and water pressure. All these parameters can affect both the long and short-term stability.

Concerning the short-term stability of an excavation, special attention should be paid to the water pressure. A local concentration of pore water pressure might build up behind more impervious strata. This pressure might force the rock material into the tunnel and cause a running-like failure.

In case of crushed or gouge material, a very short stand-up time can be expected and a running or flowing failure might follow immediately after the blasting.

Ravelling and slaking might also occur if clays are present in joints.

Considering the long-term stability, effects causing creep are of most concern.

3.2.3.5 Support Methods In Class IV-V rock, the method of advance has to be chosen carefully in order to fit current rock conditions.

In the following, methods to excavate and support poor rock are discussed. A difference has been made between ”normal” and ”special” conditions. With”special” condition is meant a condition where the tunneling has to be carried out extra cautiously.

Rock Support under Normal Conditions

The first step to increase the stability in poor rock is to reduce the advance. The advance is governed by the stand-up time of the rock and the time it takes for the installed support to get sufficient strength. In very poor rock the advance might have to be reduced to 1 m or even less. When tunnelling Class V rock of better quality with reduced advance, it is normally sufficient to use ordinary support with systematic bolting and shotcrete. Use of reduced advance may also be necessary in Class IV rock of poor quality.

Spiling

In order to increase the stand-up time, spiling is recommended. Un-tensioned rock bolts are normally used as spiles with a distance between centers equal to 30-50 cm. It is recommended to install spiles with a length of 4-6 m, where possible. Shorter spiles might be required in case the holes do not stand open. If very weak rock is encountered it might be possible to hammer the bolts in place. The spiles should be inclined about 15° from the tunnel axis. Where stability problems occur in the walls, also these should be protected by spiling, Spiling cannot serve as a primary support on its own, but has to be supported at the tunnel face by shotcrete arches or steel sets.

Divided Front and Support by Arches

If instability of the front occurs, a significant improvement can be achieved by dividing the front into gallery and bench. It is suitable to make the bench at least some 10 m long.

In weak rock, systematic bolting and shotcreting may not be sufficient and arches have to be installed. The arches might either be shotcreted or consist of steel sets. The shotcrete arches might be reinforced in various ways. The possibilities are fiber reinforcement, a combination of fibers and wire mesh, reinforcement bars or lattice girders. It should be noted that fibers should not be used in the same layers that are reinforced by nets or bars.

If the stand-up time is too short to allow the shotcrete to harden, steel sets have to be used. They should be erected as close to the face as possible and placed on an axial beam fastened to the tunnel wall. When the bench is excavated the forces are transferred down through the axial beam until vertical beams have been placed immediately under the steel arch.


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An improvement of the stability situation might be achieved by introducing invert struts.

Multiple Drifts

For extremely poor conditions with very short stand-up time and problems with the stability of the face, multiple drifting might be necessary.

In this excavation method the gallery is divided into parts. Regarding the excavation of the gallery, the following method could be used: when one part is excavated, lattice girders or ordinary steel sets should be installed as primary support at the periphery wall as soon as possible. The wall facing the rock mass that is about to be excavated can be stabilized with a shotcrete lining. While part two is excavated, the shotcrete wall is left as a pillar support in the middle. In some situations it may be necessary to use a temporary invert strut to stabilize the floor of the gallery. When the entire gallery is excavated and primary or permanent support is erected, the shotcrete wall is removed.

The bench should be excavated in a way that allows installation of the final support to form a closed section. Since the bench stabilizes the face, the length should always be at least 10 m.

Rock Support under Special Rock Conditions

Flowing Ground

When high water pressures with large amounts of water are built up in the rock mass, flowing ground might be a problem. Flowing ground might occur in zones with heavily crushed material. Since the damage caused by flowing ground can be extensive, it is important to analyze correctly the information obtained from the feeler holes drilled in front of the tunnel.

Stabilization of flowing ground is a very difficult work, which normally is performed in three steps. If the water flow is too intense to allow grouting, drainage of the rock must be performed as a first step. When reasonable pressure and flow are achieved, grouting can be performed. For safety reasons it is important to make sure that a good grouting result is achieved fairly far into the rock mass before further excavation is performed. As a last step the actual excavation is carried out. Normally, the use of multiple drifts is recommended for this kind of rock. The monitoring of water pressure, grouting results and water flow is important in order to secure a safe excavation.

In the zone of the grade IVa-2 fault a rapid installation of the support might be required and then installation of steel sets might be suitable. The steel sets should be completely covered by fiber reinforced shotcrete. The thickness of the invert slab should be in the order of 300-500 mm.

3.2.3.6 Excavation and Support at Tunnel Portals When planning the excavation for a tunnel portal it is important that a feasible location in plan has been established by drillings. In order to reduce support requirements, the portal should be located in IB rock or preferably in II rock. Should the selected portal location be found to be located in poor rock, then either re-excavation starting from the top or time consuming tunnel excavation with heavy support has to be carried out.

In the following it is assumed that rock of acceptable quality has been reached. The first step is to create a rock surface from which the tunnel excavation can start. The inclination of the slope above the portal area should be chosen in a way giving an over-all factor of safety of 1.5 for permanent slopes and 1.3 for temporary slopes. The cut slope in rock forming the portal rock should be stabilized. The inclination of this slope should be selected considering the rock conditions. Normally slopes steeper than 5:1 should be avoided. In order to stabilize the slope and thus preventing rock falls it is advisable to apply a layer of shotcrete with a thickness of 30-50 mm. If the slope is of limited height, say 5-10 m, netting might be possible for temporary slopes. Rock-bolting may be required.

When the rock face is stabilized the preparations for the portal can proceed as follows:


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• Start with shotcreting a 1m wide zone along the arch and wall perimeters of the portal. The shotcrete should preferably be reinforced with fibers (60 kg/m3 shotcrete) and the thickness of this shotcrete layer should be 100 mm.

• The next step will be the installation of spiling bolts along the perimeter of the arch. The spiling bolts should be placed 0.2 m outside the opening proper. The spiling bolts should have a length of 4 m, be spaced 0.5 m and be inclined 15-20° from the tunnel opening. The bolt diameter should be in the order of φ 25 mm and be fully grouted.

• The excavation can now start with drilling of the first round. The round should be given a length of maximum 2 m. Drilling and charging should be performed carefully resulting in smooth blasting, which should result in a minimum disturbance of the rock.

• The tunnelling muck is now removed and scaling carried out. After this operation, shotcrete with fibers with a layer thickness of 100 mm is applied in the arch and 50-100 mm on the walls. Another set of spiles with a length of 4 m is then installed from the face.

• The second round is also given a length in the order of 2 m and after blasting, mucking, scaling and supporting this round it can be decided whether it is necessary to continue with installation of spiles. If spiles are discontinued, it is recommended to proceed with reduced length of rounds for at least 5 additional rounds. Installation of bolts should be carried out in accordance with the rock support classes presented above. It is, however, recommended that the thickness of the shotcrete be kept as for the initial rounds.

A prerequisite for this method of starting the tunnelling work is that the rock mass has a stand-up time allowing the installation and curing of the shotcrete. In case the rock quality is so poor that the required stand-up time is not available, a method that gives more or less immediate support is required. The support method then to be considered is installation of steel sets. The preparation of the portal surface should be performed as described above. Also installation of spiling to the same length of 4 m is recommended. The length of the rounds has to be reduced to tentatively 1 m, which will also be the tentative spacing of the steel sets. The excavation has to be performed carefully as it is important that the sets have contact with and supports the rock. The rock between the sets is preferably supported with shotcrete. Is this not feasible, lagging has to be installed as support of the rock.

When planning the excavation of the tunnel it is important that the required space is available for the temporary support with shotcrete and steel sets and the permanent lining.

3.2.3.7 Comment It is recommended that the rock be classified according to the RMR or Q system. The temporary support is proposed to be given a design in accordance with that indicated above. It should be noted that the suggested support is tentative and has to be adjusted to the conditions encountered.

3.2.4 Considerations Regarding Unit Rates of Underground Works

The unit rates for underground works may be estimated as follows assuming international competitive bidding:

Item Sub-item Unit Unit Rate, USD Raise Boring Establishment 25,000 Boring m 2,000 Stoping m3 60 Tunnel Excavation m 3,125 Fiber-reinforced Shotcrete m3 375 Bolts m 12.5


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3.2.5 Construction Material

3.2.5.1 General Investigations have been performed in order to establish that sufficient quantities of material for the different dam types are available. For the selected alternative with a RCC dam in the Feasibility Study, the types of materials required are cohesive soil and rock-fill for cofferdam construction, rock for production of coarse aggregates (and possible fine) for the concrete, and sand to be used as fine aggregate for the concrete.

3.2.5.2 Performed Investigations The investigations performed in order to establish the quality and quantity of the alluvial soil have comprised the excavation of 30 test pits to depths varying in the range of 3.5-4.5 m.

The rock quarry site was investigated by means of 4 core-drilled holes, drilled to a depth of 40 m each, and two geological sections have been constructed. Eight samples were extracted for laboratory testing.

The sand borrow area was investigated earlier for the A Vuong Hydropower Project by PECC2. The area is located on Cai River at a distance of 25-30 km from the power station area. The length of the area is in the order of 5-10 km and the width some 100 m. The area was investigated by 60 drill holes with depths varying between 3 to 5 m.

3.2.5.3 Borrow Areas General

Soil borrow area A is located on the right bank upstream of dam site 2. It is located on a hillside between El. 350 m and El. 550 m with an area of 49.2 ha. The thickness of the topsoil to be removed is 0.5 m and the thickness of the layer to be explored is in the order of 3.5 m. The available quantity is 1.7 Mm3.

Soil borrow area B is located on the left bank upstream of dam site 2. It is located on a hillside between El. 180 m and El. 280 m with an area of 4.32 ha. The average thickness of the topsoil is 0.5 m and the thickness of the layer to be explored is 3.5 m. The available quantity is 150,000 m3.

Soil borrow area C is located on the left bank to the left of dam site 1B. It is located on a hillside with a slope inclination varying between 30º and 40º between El. 160 m and El. 280 m. The area is 4.6 ha with a topsoil thickness of 0.5 m and a thickness of the layer to be explored in the order of 3.5 m. The available quantity is 160,000 m3.

The soil of the three borrow areas is alluvial material on bedrock of Members 1 and 2 of the Song Bung lower formation. Their soil mechanical properties are similar. Examples on values determined in the laboratory are given in the table below:

Atterberg Limits Proctor Compaction Shear Strength wl % Ip % Optimum Water

Content, % Dry Density

t/m3 Cohesion

kPa Friction Angle

Degrees Max 42.4 18.8 23.1 1.83 27 21 Average 38.1 15.2 20.1 1.70 24 18.4 Min 31.1 11.7 16.4 1.64 22 16.9

Comment

The soil is considered suitable to use as impervious fill in cofferdams. Rock fill will be obtained from required excavations.


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3.2.5.4 Concrete Aggregates Coarse Aggregate

General

The coarse aggregate is planned to be extracted from a quarry located on the right side of the river located some 4 km from the dam site close to National Highway14D. The quarry is located in granodiorite belonging to phase 2 of the Ben Giang-Que Son formation. The elevation of the ground surface within the area varies between El. 500 m to El. 800 m. The area of the quarry site is 73 ha (1.2x0.6 km) and the thickness of the overburden to be removed (alluvium and IA) is 10 m on average (6-18 m). The total quantity of material available, and suitable for aggregate production (IB and II), is in the order of 43x106 m3, i.e. essentially unlimited. Typical values determined in the laboratory testing are presented in the table below:

Compressive Strength, MPa Rock Type Dry Density t/m3

Specific Gravity, g/cm3

Porosity, %

Air Dry Saturated Granodiorite IB and II

2.66-2.68 2.70 0.84 105 >95

Comment

The material is considered suitable for production of coarse aggregate to be used in concrete.

Fine Aggregate

General

The area considered for extraction of sand has a length of 4.6 km. The average thickness is 3.9 m. The total available quantity of sand within the area is in the order of 1.4x106 m3.

Two layers are present as follows:

• The upper layer 1 consists of yellowish grey – brownish grey fine sand with a fineness modulus varying in the range of 1.3-2.0. The thickness of the layer varies from 0.5 m to 5.0 m with the average thickness 1.7 m. The major constituent of the material is quartz. The content of silt and clay is 2.5%, the content of mica less than 0.3% and the content of salt and organic material is insignificant.

• Layer 2 is normally encountered below layer1, but reaches the surface in some places. It consists of yellowish grey – brownish grey medium to coarse sand with gravel. The fineness modulus of the sand varies between 2.2 and 2.9 with an average of 2.6. The average thickness is 2.2 m. The major constituent is quartz. The content of silt and clay is 1%, content of gravel 26%, content of mica <0.2% and the content of salt and organic material is insignificant.

Comment

The main part of the sand is finer than 1 mm and there is a deficiency of 1-5 mm size material. Milling rock in the crusher plant can produce the missing coarser sand. It is also desirable to have a sand material with up to 15% of non-plastic fines (<0.075 mm) in order to reduce the RCC paste demand. A proportion of these fines might be obtained from crusher dust.

3.2.5.5 Pozzolan General

The investigations in order to find suitable sources of pozzolan are in progress but no testing has yet been performed specially for this Project.


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Pozzolan is present in the weathering crust of Proterozoic metamorphic rock of the Ngoc Linh formation (RR1nl). The components are sillimanite schist and sillimanite-gneiss-biotite schist.

Another origin of pozzolan is basaltic rock, basalt volcanic tuff and basalt pumice from Mu Rua. A third source is fly ash from coal-fired power plants.

Comment

A number of sources of natural pozzolan have been mentioned in the Feasibility Report. The results of tests made for A Vuong dam on three natural pozzolans have been examined. Of these it appears that pozzolan from Mu Rua has given good results whereas pozzolan from Son Tinh and Phong My have given poor to indifferent results, possibly due to a highly variable source and poor pozzolanic activity. Based on this it would seem prudent to focus attention in further studies on Mu Rua pozzolan and only consider the other two sources if they can be conclusively demonstrated to have consistent and good pozzolanic properties.

Good quality fly-ash is available from power stations on Luzon (Philippines) and to a limited extent also from Vietnamese power stations

3.2.6 Conclusions

The geological conditions within the Project Area are considered favorable for the construction of a hydropower project. The studies performed in the pre-feasibility and feasibility stages have involved comparison of different dam types, different dam sites, different waterway tunnels, aboveground and underground powerhouse locations.

The geological conditions at the three dam sites investigated in the Feasibility Study are similar considering rock formation and weathering profile.

The geology is suitable for the RCC gravity dam chosen for Song Bung 4 Hydropower Project.

The investigations performed in order to establish sources for construction material has resulted in borrow areas in alluvial soil for cofferdam construction located at convenient distances from the dam axis. A rock quarry located some 4 km from the dam has been found in an igneous rock formation consisting of granodiorite. A sand borrow area located some 20-30 km downstream of the power station has been investigated earlier for A Vuong Hydropower Project. There is a deficiency of 1 to 5 mm size material, which is considered possible to obtain by milling rock at the crusher plant. Non-plastic fines reducing the RCC paste demand might be obtained from the crusher dust. The quantities available in borrow areas and in the quarry are sufficient to cover the demand for the construction of the Project. Investigations of sources of pozzolan are ongoing. It is recommended that trial mixes be tested as soon as possible in order to make it possible to decide whether natural sources of pozzolan or fly-ash should be used.

3.3 Review of Dam Structure

3.3.1 Review of Dam Site and Dam Type Selection

3.3.1.1 Introduction This section reviews the dam site and dam type selection set out in the draft Feasibility Study dated May 2005. A full supply level for the reservoir of +222.5 m has been adopted.

3.3.1.2 Topography Topographical maps at a scale of 1:2,000 with a contour interval of 1 m have been used to evaluate the dam axes and dam types.


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The valley and future reservoir are narrow with steep valley sides as can bee seen from the valley cross-section at the dam site in Figure 2-5.

The Pre-feasibility Report shows that 5 sites have been evaluated, Sites 1 to 3 for CFRD and Sites 4 and 5 for RCC gravity dam options. This report recommended a CFRD at Site 1 with a maximum normal reservoir level of +230 m. Only Axes 1 and 2 are shown on the drawings.

Three potential dam axes have been identified in the draft Feasibility Report, numbered 1A, 1B and 2. Axis 1B is about 200 m upstream of 1A and Axis 2 is a further 450 m upstream.

3.3.1.3 Selection of Dam Types Given a reasonably strong rock foundation a CFRD and RCC gravity dam are typically the competing lowest cost options. These two dam types have been studied. The geological investigations have shown that the foundation conditions are suitable for any of the considered dam types. Also the availability of construction material makes all the considered dam types technically feasible.

Drawing of Compared Alternatives, Book 2, dated March 2005, show an RCC dam on Axis 1A, a CFRD on Axis 1B, and an RCC dam on Axis 2. Book 1 of the same date, Drawings of Proposed Alternative, shows an RCC dam on Axis 1B. The full supply level is shown as +222.5 m. An RCC gravity dam has been shown on each of the three axes and the lowest cost option has been selected.

The final selection of dam type and site is based on cost estimates. The ratio of costs between the two dam types accords with experience from other studies. Any errors in the cost of cementitious materials for the RCC dam options are unlikely to change the ranking.

The spillway capacities for the RCC and CFRD are shown as being the same as are their free-boards. As a CFRD cannot be safely over-topped during a flood, its free-board should be increased to give a dam of safety equivalent to that of the RCC dam. This is important given the short hydrological time series for the river and the attendant uncertainties in the flood estimates. If this were taken fully into account, the cost of the CFRD options would increase, thus making the RCC alternatives even more attractive.

We concur with the RCC gravity dam as the choice of dam type, and is also supported from a geological point of view.

3.3.1.4 Selection of Dam Site The dam site has been selected on the basis of cost estimates. The costs have been estimated as follow:

Site 1A 1B 2 109 VND 3145.71 3038.37 3124.38 106 USD 199.1 192.3 197.7

Cost Ratio 1.035 1 1.028 NPV, 109VNĐ 283.42 367.09 283.19

1 US$ = 15,800 VND.

The estimate shows the best overall economy for Site 1B which has therefore been selected. However, the plunge-pool for the spillway for Site 1B is complicated as its exit is asymmetrical. Model tests are required to define the geometry, and the spillway chute may have to be constructed such that the water is ejected at an angle to the dam. Dividing walls between each of the five outlets might be required. The additional costs could be of the order of 2 to 3 million USD making the difference in price between Sites 1A and 1B smaller, maybe less than 4 million USD which is about 10% of the cost of the dam with diversion and spillway. It seems improbable that any additional costs required to achieve a well-engineered spillway at Site 1B


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would exceed the current cost difference. In terms of a rock excavation, it would represent some 1 million m3. We therefore agreed with the selection of Site 1B, but budgets should be included to cover additional costs which might arise because of the plunge-pool configuration. That can be defined only after model testing.

3.3.1.5 Dam Foundation The dam will be founded in stratum IB after removing the overlying strata eQ, IA1, IA2 and 2 m of stratum IB. The foundation grade is called IIA1 and is considered adequate from bearing capacity point of view.

The final exaction of the dam foundation has to be made with careful blasting, rock breakers and other means which will minimize disturbance to the foundation rock.

In fault zones of grade IV the gouge material has to be removed to a depth of 1-3 times the width of the zone and replaced by concrete.

The inclination of the cut slopes should not be steeper than 1:2 in soil, 1:1 in stratum IA and 1:(0.6-0.7) in strata IIA and IIB. Cuts of limited height may be steeper and even vertical, but support measures may be required. Other cut slope angles may be adopted subject to satisfactory stability analysis. The specification for dam excavation will give detailed shaping criteria.

Minor inflow of water is expected and has to be controlled by canalization and pumping.

Recommendations regarding foundation treatment and grouting are given in Section 3.3.9.

3.3.2 Gravity Dam Design

3.3.2.1 General The general layout shown on the drawings is satisfactory. Comments on details of the layout and the dam cross-sections are given below.

3.3.2.2 Design Standards and Design Criteria The dam has been designed using Vietnamese standards TCXD VN 285:2002. This design standard has not been studied in detail, but the results show that the presented design is conservative as the various calculated factors are well within the allowable ranges.

Further checks have been presented employing CDSA 1995, USACE 1995, FERC 1991, FERC 1999, and USBR 1987. These various codes reflect methods and standards of design which are employed extensively by international consultants and embody sound design principles. These codes include recommendations on loads and load combinations as well as acceptance criteria. The check calculations presented using these standards also show that the presented design is conservative and that there is room for optimization.

Most of the detailed dam stability estimates made to date, examine the dam body as a whole resting on a rock foundation. Design checks are required for each layer in the dam, as has been done in the CADAM dam stability software.

The shear strength of the dam/foundation interface has been set low with the shear coefficient f = 0.75 (φ = 37º) and c = 0.2 MPa. When using the above Canadian and American standards and codes, the foundation/rock shear strength must be set more realistically. Given the high rock strength at the site, the governing strength is probably the lift joint strength, the strength between RCC lifts. However, this should be checked using the orientation of the joints in the rock and joint shear strengths if joint orientations should be critical. For feasibility design purposes the following concrete cylinder strengths may be used:


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Proposed RCC Strengths for Feasibility Design

Concrete Parent Concrete Lift Joints Design Compressive Strength 15 MPa 15 MPa Design Tensile Strength 1.6 MPa 1.3 MPa Cohesion, Friction Angle Peak 1.5 MPa / 45o 1.1 MPa / 45o Residual 0 MPa / 45o 0 MPa / 45o

For normal load combinations the allowable tensile stresses should be taken as zero. Note that the design tensile strength for lift joints should be assumed to operate over 80% of the area.

3.3.2.3 Comments on the Draft Feasibility Design Cross-sections The proposed upstream view and cross-section of the non-overflow dam is shown in Figure 3-2 and Figure 3-3, respectively. The slopes of the dam may not be fully optimized, but are not unreasonable. The crest width has been set to 10 m. Unless 10 m is required for operational reasons, it can be reduced to 8 m which is the minimum width for effective RCC construction. The width of 10 m may be related to the upstream reinforced concrete which is shown as 3 m thick and which would give an effective RCC placement width of 7 m at the top of the dam.

It is strongly recommended that the reinforced concrete facings be deleted and that GE-RCC be used instead (Grout-Enriched RCC, see description of this technology below). The GE-RCC would be a facing only, ensuring a fair finish to the dam. Water-tightness would be taken care of by the RCC in the dam. The objections to the reinforced concrete shown are that it has a high cost, slows RCC placement with attendant cost and quality implications, and it is not required with high paste RCC. Most dams are now being built using GE-RCC (or GEVR, Grout Enriched Vibratable RCC) for reasons of cost and quality. GE-RCC would be used also on the downstream face of the dam instead of the reinforced concrete shown.

The reinforced concrete shown at the base of the dam should be deleted. At the lowest section of the dam, un-reinforced levelling concrete (CVC, Conventionally Vibrated Concrete) is required to give a starting platform of adequate size to allow effective RCC placement. The contact between the RCC and the rock foundation outside this area may be made using GE-RCC or a bedding mix. GE-RCC is now increasingly used also for this purpose. The upstream face of the galleries in the RCC should be set at 8 m from the upstream face of the dam. This will give the required space for effective RCC placement in this area. This factor is important as the RCC in this 8 m band forms the principal water barrier in the dam.

Unless earthquake loads dictate otherwise, gravity dams are normally built with vertical upstream faces. The theoretical benefits of sloping the upstream face are marginal and do not offset the additional complexities of building the sloping face. A vertical upstream face is recommended given the relatively low seismic design coefficients applicable to this site.

The proposed cross-section at the spillway is shown in Figure 3-4. The comments made on the non-overflow section apply also to this section. The lip of the spillway protruding downstream of the vertical face of the dam serves no purpose, is costly and should be deleted or at least substantially reduced. The thickness of the spillway chute slab is shown as 3 m. This may be reduced to 1.2 m or even 0.9 m. The slab should be anchored to the underlying RCC as if the RCC were rock, i.e. with anchor bars either drilled and grout into the RCC or installed as horizontal bars between the RCC layers as they are placed. The shown extension of the piers downstream of the gate bearings may be larger than structurally required. To ensure stability of the crest block with gates it may be necessary to increase the participating mass. This may be done by drilling anchor bars into the top of the RCC and by providing a reinforced vertical down-stand at the upstream face of the dam as indicated on the cross-section. Hydraulic aspects of the spillway design are given below.


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Figure 3-2 Upstream View of Dam, Current Design

292.00

Exisitng ground level


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Figure 3-3 Current Design of Dam Cross-Section

2.80

2.00

10.00

RCC 0.7

63.02 23.09 3.91

3.00

10.00

2.90

12.00

2.80

2.00

3.50 4.104.20

3.00


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Figure 3-4 Current Design of Dam Cross-section at Spillway

The foundation galleries are shown as being 3 x 3.5 m (w x h) which is exceptionally large. A common gallery size is 2.4 x 2.7 m (w x h) which may be adopted also here. However, the contractor may be given some choice in selecting the final size of the galleries to suit his equipment and method of working. The other galleries (drainage galleries) would normally be

3.50

4.20

3.00

4.10

2.00

15deg 0min 0.0000sec

32.66

5.0019.008.66

8.9818.04

51deg 52min 38.6396sec

3.00

2.80

2.00

12.00

3.00

2.90

RCC

3.00

2.00


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made the same size as the foundation galleries, i.e. 2.4 x 2.7 m. The lower galleries will be below the tailwater level during floods. Consideration should be given to providing a pump sump and pumps to maintain the galleries dry during such periods. Security of instrumentation and other electrical installations needs to be taken into account. Access to the galleries should be above the 5,000-year (0.02%) flood level. Pumping may be required in any case to maintain the lowest part of the foundation gallery free of standing water.

3.3.2.4 Free-board The free-board in the draft feasibility design has been set from the 5,000-year (0.02%) flood with an allowance for waves. Economic advantage may be taken of the ability of this type of dam to withstand over-topping, both by waves and from floods, without impairing safety. Consideration may be given to using a parapet wall to prevent intermittent over-topping by waves under normal operating conditions. One option is to make the top of the dam coincide with the design flood level (1,000-year, 0.1%) and provide a 1.2 m high parapet wall on top of it to take care of waves. The exact elevations would have to be checked, but a reduction in dam height by about 3.5 m might be possible. A crest level of +224.5 m with a 1.2 m parapet wall would contain the design flood and would give 0.3 m overtopping of the wall at the control flood level (5,000-year, 0.02%, flood). Depending on the design of the wall, it may be damaged, but this is acceptable for a flood of such rarity.

3.3.2.5 Joint Spacing Induced contraction joints are shown at 40 m spacing except under the spillway where a maximum spacing of 57 m is shown. The 40 m spacing may be a reasonable guess for feasibility design and is the same as was estimated for Ban Ve dam. However, within the 57 m bay there is the diversion culvert. If no further provision is made, a crack will most probably occur emanating for the protruding corner of the culvert. A joint should be provided at this location to prevent uncontrolled cracking and leakage. A study is required to find a sound configuration of the induced joint, the diversion culvert and the spillway bays. It would be beneficial to re-align the diversion culvert such that it would run normal to the dam axis. Reinforced concrete sections are occasionally used to limit crack propagation. This may be considered, but requires analysis to find the optimal location and extent. Such reinforcement might be most effective when installed well above the foundation where external and internal restraint is small.

3.3.2.6 Recommended Design The cross-sections of the dam made in accordance with the above recommendations are shown in Figure 3-5 and Figure 3-6. Figure 3-7 shows a plan of the dam and associated works. The downstream face slope has, from experience, been set at 0.8:1 (H:V). The sections should not be taken as final proposals, but as a starting point for further design development and optimization.

The entire cross-section is built using RCC technology except for the spillway crest, chute and ski-jump liner. The spillway piers and chute walls will be built in conventional concrete.


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Figure 3-5 Proposed Revision to the Design of the Non-overflow Cross-section

RCC

SECTION 2-2

8.00

8.00

40

8.00

NWL = 222.5

FWLC = 225.97

DWL = 195.0

120.7

Max tailwater = 149.5

224.5

218.7

211.8

225.7

35.0

0

198.5

189.5

123.5

33.0

0

5.60

156.5

33.0

0


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Figure 3-6 Proposed Revision to the Design of the Spillway Cross-section

SECTION 3-3

RCC

8.00

8.00

8.00

1.20

28.00

R 25.00

106.

53

80.5

0

5.00

To b

e de

term

ined

2.70

Thickness to bedetermined

Pier width to bedetermined

1.50

Aeration slot

Optimal angle tobe determined

Covered slot in bridgefor stop-logs

118.0121.0

40

225.7224.5

NWL = 222.5

FWLC = 225.97

DWL = 195.0

206.5

198.5

177.5

Max tailwater = 149.5

156.5

2.40

189.5

35.5

033

.00

35.0

0

Compensationoutlet


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Figure 3-7 Proposed Revision to Layout of Dam


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3.3.3 Review of Spillway

3.3.3.1 Design Criteria The spillway comprises a gated overflow on top of the RCC dam with a downstream ski-jump and plunge-pool. The spillway has been designed for the following floods:

• Design Flood, p=0.1% (1,000-year flood)

- Maximum flood: 12,363 m3/s

- Design flood level: 223.86 m

- Maximum discharge: 10,750 m3/s

• Control Flood, p = 0.02% (5,000-year flood)

- Maximum flood: 15,509 m3/s

- Control flood level: 225.97 m

- Maximum discharge: 12,763 m3/s

The size and number of gates have been optimized and the general arrangements seem sound. The design flood for the spillway follows Vietnamese standard, however, it is recommended to verify the stability of the dam in the event of a PMF during the technical design phase.

3.3.3.2 Stop-logs and Stop-log Handling The section appears to shown a gantry crane for stop-log handling. Stop-logs will be used only on very rare occasions, maybe every 30 to 50 years, and installation of a gantry crane for this purpose would be an unwarranted capital cost and would require regular maintenance. Stop-logs can be handled by a mobile crane. The crest road is currently shown dog-legged over the spillway. With some adjustments the bridge may be placed upstream of the radial gates and run in a straight line from abutment to abutment. The gates would be assembled using a mobile crane set up on the bridge and the same arrangement would be used for any maintenance. A slot with cover-slab could be provided in the roadway to coincide with the stop-log slots in the piers.

Stop-logs would normally be stored on one of the abutments, suitably protected against damage and corrosion.

3.3.3.3 Plunge-pool The depth of the plunge-pool has been estimated in Calculation Appendix 3 - Spillway. The depth of the plunge-pool seems small and further checks should be made with alternative formulae. An estimate using Marten’s equation gives an ultimate plunge-pool erosion depth some 15 m deeper than shown in the appendix and on the drawings. Other equations give depths even greater than this (e.g. Mason, Vernonese). These and other empirical equations give the depth of ultimate plunge-pool development. The floods may have a high peak intensity but they are of relatively short duration and it will take time for the plunge-pool to reach its ultimate size. Pre-forming the plunge-pool to an estimated ultimate depth and extent may not be warranted, but at least some of the plunge-pool should be pre-excavated and to a larger extent than shown on the drawings. Further work is required to define the size of the pre-excavated plunge-pool, including hydraulic model tests, but one might consider as a starting point the elevation given by the Mason formula for a 10-year flood which is 97.5 m or about 20 m lower than currently shown on the drawings.


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3.3.3.4 Ski-jump and Model Studies The exit of the ski-jump is shown as being horizontal. It is necessary to increase this angle to avoid a single hydraulic jump forming in the plunge-pool, see also comments in Section 3.3.3.5. Hydraulic model studies are required to give a final definition of the spillway shape and the size and shape of the plunge-pool. In this context the exit from the plunge-pool is asymmetric which makes a model study all the more important. Due to the rather narrow section of the river at the location of the plunge pool, high backwater velocities may be expected under certain conditions.

3.3.3.5 Cavitation and Aeration The peak water velocity on the chute is of the order of 30 m/s. Cavitation can occur at such velocities unless the spillway concrete is constructed to a very high standard with respect to both strength and flatness. Consideration should be given to providing aeration to the flow. This could be via an aeration gallery or might be arranged at the tail end of the piers without a gallery. In this case the lower part of the piers could be extended downstream in order to optimize the location of air injection. The efficiency of the aeration can be checked in a physical model provided it is of sufficiently large scale.

It may be advantageous to raise the level of the ski-jump to reduce the water velocities. The distance to the plunge-pool could be largely maintained by increasing the exit angle from the ski-jump to 30 or 35 degrees. It may then be possible to dispense with aeration. The volume and cost of spillway concrete and underlying RCC would probably be increased which might negate any cost advantage gained in omitting aeration.

3.3.3.6 Piers and Dividing Walls The piers are shown as 3 m thick which should be adequate for the size of spillway given the relatively low earthquake accelerations. The upstream-downstream width shown seems large and investigations should be made to see if they might be shortened. No significant depth of concrete is required downstream of the gate trunnions for their support. The downstream end of the piers would be cut off square without hydraulic fairings.

If the spillway is constructed with the general configuration shown, dividing walls between the spillway sections would not be required. However, if model tests show that the flow has to be turned to align it better with the river downstream of the dam, then such dividing walls would be required.

3.3.4 Diversion Arrangements

3.3.4.1 Diversion Capacity The planned diversion comprises a twin box culvert with each opening being 7 x 9 m (w x h).

The size of the diversion is related to the flood frequencies, size and duration and the size and duration of acceptable over-topping of the dam.

The 10-year (10%) flood has been used as a basis for the presented assessments. Overtopping of the dam is envisaged and the schedule apparently shows the RCC placement operation closed for the first wet season.

Values for the 2-year and 5-year floods have not been found in the reports. To give preliminary assessments related to floods corresponding to these return periods, the flood-return period graph has been extrapolated using a logarithmic relationship. The resulting peak floods are then 2,450 and 3,950 m3/s, respectively.

If the initial placement of RCC were started at the beginning of the dry season (1 January),


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some 50 m height of dam could be placed within 6 to 7 months, i.e. prior to the onset of the wet season. Were a 2-year flood to occur at this time, the dam would not be over-topped and delays in placement would be due entirely to rainfall. With a RCC elevation of about +173 m, the dam would not be over-topped in a 5-year flood. A 10-year flood would be contained by a dam at elevation +175 m. It should be possible to attain this level of RCC construction by about mid-June in the first RCC construction season which is before the onset of the flood season.

The upstream cofferdam height is currently shown at +139.5 m, about 20 m above the riverbed. If the dam can be constructed at the rates indicated above, the cofferdam could be constructed to contain the early dry-season peak flow only, which is about 300 m3/s for the first 3 months of the year (p=10%). The cofferdam crest level could then be set at, say +127 m. Note that the figures given above are indicative only and a more detailed analysis may give slightly different results.

Consideration should be given to constructing a diversion that is smaller than the one currently shown in order to save costs, providing risks to the dam construction remain manageable. For example, preliminary calculations suggest that by reducing the diversion capacity to 2/3 of that shown would require a dam elevation of about +176 m to prevent over-topping of the 10-year flood. A further reduction of current capacity to 50% would require an RCC level of +177 m to prevent overtopping by the same flood. The height of the cofferdams would, however, have to be increased to maintain a reasonable level of risk. Halving the capacity of the diversion culvert might require an upstream cofferdam height at +131 m to provide protection during the first 3 months of RCC construction. Although these figures are all rough and preliminary, they show that an option with a reduced diversion culvert capacity should be examined.

3.3.4.2 Diversion and Cofferdam Construction The drawings show the excavation for the culvert extending beyond it on the abutment side of it. The cut for the culvert should be excavated by smooth-blasting (or pre-splitting) and made as near vertical as possible. The right-hand wall of the culvert would then be cast directly against rock. The smooth-blasted surface may require temporary support with shotcrete and rock bolts as needed.

3.3.4.3 Diversion Closure Diversion closure is shown as stop-logs inserted at the upstream end of the culvert. In the current design each of the culverts is 7 m wide. The details of the diversion closure require detailed study, but only when the size of the diversion culvert has been finalized. If two culvert openings are used, it would be normal to close one of them early in the dry season and then cast a plug thereafter. The plug would normally require cooling to near ambient long-term temperature and subsequent grouting before it could be put into service. Final closure would then be made of the remaining opening by means of stop-logs or a gate and a plug cast. The gate or stop-logs could then be salvaged. When designing the closure, the rate of rise of the water has to be considered and a system has to be proposed which takes this into account.

3.3.5 RCC Mix Design

The RCC proposed for Song Bung 4 Hydropower Project should be a high paste mixture which is designed to be watertight without the need for an upstream waterproof membrane. A high paste RCC is classified as a mixture with more than 150 kg of cementitious material. The cementitious materials will be Ordinary Portland Cement and a pozzolan. The pozzolan may be fly-ash, a natural pozzolan or ground granulated blast-furnace slag. In addition, inert filler can be used. The filler may be crusher dust or imported fines which typically display little or no pozzolanic activity. The addition of pozzolan has the desirable effects of reducing cement


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content, thus lowering costs and reducing the heat of hydration and giving slower strength development which benefits bonding of RCC layers and reduces thermal stresses. The paste/mortar ratio is increased, thus reducing the potential air voids in the concrete. The inclusion of pozzolan in the concrete also prevents alkali-silica reaction where this might be a problem.

Any good quality Portland cement may be used. Low or intermediate heat of hydration cements is desirable to reduce the temperature rise in the dam. Portland pozzolanic cement is suitable, but its use reduces the opportunity for adjustment of the pozzolan content of the concrete unless pozzolan is also stored on site. Portland blast furnace slag cement is a further option. Commercial pozzolanic and slag cements can vary in their composition which is undesirable when used for RCC.

Consistency of the cement properties during dam construction is important in ensuring a good and uniform dam concrete. Cement should ideally be delivered from a single manufacturer with proven ability to deliver a consistent product. It is sound commercial practice not to determine this single source prior to tender for dam construction. Several sources of cement may have to be investigated and approved prior to tender and concrete mix proportions determined for each.

The most common pozzolan is fly-ash. Fly-ash properties vary with source. Differences in the origin of the coal and in power station design and operation can yield substantial differences in the physical and chemical properties of the ash. As for cement, prior approval of sources of fly-ash is needed. Nearly all fly-ash used in RCC dams has been ASTM Type F fly-ash.

The RCC has to be designed to be not susceptible to segregation. Segregation can give porous layers at the base of lifts with ensuing water leakage. Segregation is aggravated by a large maximum size of aggregate (MSA). The MSA is often limited to 40 mm for natural (rounded) aggregate and 60 mm for crushed aggregate. On some dams the MSA is set at 40 also for crushed aggregate. In the core of very large dams, where bond and water-tightness may be less important, an MSA of up to 75 mm has been used, but this is not applicable to a dam the size of Song Bung 4. A cohesive mix also helps to prevent segregation. Cohesiveness in the fresh concrete is helped by a high paste content and a reasonably workable mix.

The grading of the aggregate has to be tightly controlled and should be close to the theoretical optimal grading. Three sizes of coarse aggregate and one or two sizes of fine aggregate (sand) are commonly required to achieve this.

The consistency of the fresh RCC has to be such that it can be compacted by heavy vibrating rollers and such that the rollers will not sink into it. Consistency is measured using the modified VeBe apparatus. VeBe times of 12 to 20 seconds commonly give the desired compaction properties for a modern 10 to 15 tonne single drum vibrating roller and are typical for mixes with little segregation.

The RCC is compacted to high densities with the air void content being 2% or less.

The permeability of completed dams using mixes as described above has been shown to be low, less than 10-8 m/s, provided the cementitious content exceeds 150 kg/m3, see ICOLD Bulletin 123, State-of-the-art of roller compacted concrete dams. For higher dams a lower permeability is desirable and the cementitious content should be 180 to 200 kg/m3. Other criteria may give higher cementitious contents than these.

The strength of the RCC is given by requirements derived from the stress and stability analysis of the dam. Tensile strength is commonly the critical parameter where tensile strength of the lift joints is the most important. However, the seismic design loads for this site are low, some 0.04 g for the OBE, and earthquake-induced tensile stresses are likely to be low. Tensile strength is related to compressive strength and the latter is used for primary


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design and quality control.

The presence of pozzolan leads to slow rates of strength gain. The design strength is commonly taken as the 90 to 365-day strength with 180-day and 365-day strengths often used for large dams. Many RCC dams have shown significant strength gain for several years after construction.

RCC mixes are initially designed based on experience. For tender design a trial mix programme has to be made where a range of mix proportions are tested for fresh concrete and hardened concrete properties. In the absence of test data the cementitious content of the RCC has to be set conservatively high. For this review the following mix proportions are suggested: Initial RCC Mix Design for Feasibility Study Purposes

Material Content, kg/m3

Coarse aggregate 1,431

Fine aggregate 717

Cement 100

Pozzolan 120

Water 126

Air-entrainment 0

Water reducing/ retarding admixture 4

The amounts of cement and pozzolan are at the upper end of what might be expected. RCCs of a similar strength have been made with less than 80 kg cement and 100 kg of fly-ash. If the sand is deficient in any fraction, particularly fines, then the pozzolan content may be increased and it then act partly as filler. Water reducing agent may be required to achieve the necessary workability.

Air entrainment agents may be used in the RCC as a workability aid but their cost may not be warranted.

The tabulated quantities have been set to achieve a design compressive strength estimated to be 15 MPa at 180-day maturity. The dam volume is such that it is probably not economic to use more than one RCC mixture.

3.3.6 Construction Methodology

3.3.6.1 Transport and Placement Methods RCC is normally placed in continuous layers extending from abutment to abutment. Speed of construction is an important factor as each layer of concrete needs to be placed on the underlying layer before the latter has aged to such an extent that a good bond between the layers cannot be achieved.

The concrete is commonly transported to the dam using conveyors and may be placed directly by a conveyor or may be transferred to trucks for final placement. The concrete is spread in layers, normally 30 cm thick, using bulldozers and is compacted by 10 to 15 tone vibrating rollers.

Until recently, all RCC was placed in horizontal layers. The capacity of the concrete manufacturing plant is then geared to placing the largest lift in the dam within one day, commonly 14 or 16 hours and such that the next lift can be placed within 24 hours. Regular,


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time-consuming and expensive lift joint treatment is avoided with this procedure. The sloped layer method has now been developed. In this method the RCC layers are placed on a slope as shown in Figure 3-8. The size of the layer is such that the next layer can be placed before its initial set. The total height of the lift, which may be 1.2 m or more, then gives the slope angle. With this method it may take several days to complete one lift from abutment to abutment. Each lift is homogeneous as each layer is placed on fresh concrete. The top surface, however, becomes a cold joint and requires treatment to ensure a good bond with the next lift. The methods of joint treatment are the same as for conventional concrete and give a similarly good bond. The cleaning and preparation of these surfaces is not on the critical path. The method has several further advantages. In the event of any disruption to the RCC production or delivery, the exposed surface is at any time relatively small and can more easily be prepared as a cold joint. (On a single horizontal layer the entire area from abutment to abutment would have to be prepared.) The requirement to place a minimum of one 30 cm lift per day, or about 10 m per month, no longer applies. Instead of the concrete manufacturing and transport plant being designed for placing the largest layer in one day, the plant can be designed for a desired typical placement rate.

Figure 3-8 Sloped Layer Method of Construction

3.3.6.2 Forming the Faces of the Dam The faces of the dam can be formed using various methods. Slip-formed kerbs have been used, but more often formwork is the chosen option. RCC can be placed directly against formwork or conventionally vibrated concrete (CVC) can be used. In the latter case CVC is placed against the formwork just in advance of the RCC layer. In recent years the GE-RCC (Grout Enriched RCC) has been developed. A variant is the GEVR (Grout Enriched Vibratable RCC) method. In the former the grout is placed on top of the fresh RCC adjacent to the formwork. In the latter grout is placed adjacent to the formwork just in advance of the RCC placement. The RCC thus enriched with grout is then consolidated using poker vibrators. Either method can work well and produce a fair face to the dam without honeycombing or voids. This method, in its two variants, has proven to be the lowest cost option for most dams where it has been used. Figure 3-9 and Figure 3-10 show the extent of GE-RCC (or GEVR) on the downstream and upstream faces, respectively. At the location of water-stops at the upstream face, the thickness of grout enriched RCC is increased to encompass the water-stop and drain assembly.

The downstream face will be formed in steps. The steps might be 0.6 m high if horizontal lifts are used and may be 1.2 or 1.5 m high for the sloped layer method. The GE-RCC should in each case be of sufficient width for the entire step width (“tread”) to be formed in GE-RCC.

Previous lift


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Figure 3-9 GE-RCC on the Downstream Face of the Dam, Sloped Layer Method

Figure 3-10 GE-RCC on the Upstream Face of the Dam, Sloped Layer Method

3.3.6.3 Leveling Concrete and Bedding Mix In order to start RCC construction, a flat platform has to be made at the bottom of the dam. It needs to be of sufficient area to allow effective use of the placing and compacting machinery. The platform is made with CVC - leveling concrete.

The contact with the rock abutments can be formed with a layer of conventional concrete

1.20

m

0.96m

0.8

1.0 GE-RCC0.40m

Lift boundary

Layer boundary

Nominal face of dam

Formwork

0.30

m

1.20

m

GE-RCC0.40m

Lift boundary

Layer boundary Formwork

0.30

m

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(bedding mix) or, now increasingly, using GEVR or GE-RCC. In all cases, except the leveling concrete, the contact concrete is placed just in advance of the RCC placement and is consolidated with it.

3.3.6.4 Forming Galleries Galleries can be formed by various methods. An effective method is to use GE-RCC against formwork and pre-cast beams for the roof. Gallery widths are commonly made 2.4 m which with 3 m long roof elements gives a bearing of 30 cm on each side. The roof elements are normally 30 cm thick to coincide with the RCC lift thickness. Wider galleries would require thicker, heavier and more costly roof elements.

3.3.6.5 Lift Joint Treatment Hot joints, joints where the RCC of a subsequent lift will penetrate its surface during compaction, will require no treatment other than removing free water and debris.

Cold joints will require exposure of aggregate using green-cutting or other techniques and a bedding mix will be required. The bedding mix will be a mortar with a maximum size of aggregate less than 5 mm which would be spread immediately prior to being covered by RCC.

3.3.6.6 Crack Control by Means of Induced Joints and Waterstops Cracking of the dam due to thermal effects has to be controlled. This is done in part by placing cooled concrete, which reduces the cracking potential and by inducing cracks (joints) at regular intervals in the upstream-downstream direction. These contraction joints may be formed by introducing a crack inducer into the freshly placed RCC lift. This may be done by vibrating a steel plate into the RCC. Waterstops and a joint drain would be installed at the upstream end of the crack inducers as shown in Figure 3-11. At higher heads, two water-stops may be required upstream of the joint drain. The joint drains are formed by slip-forming a void as the RCC increases in height. The joint spacing can be obtained from thermal stress analysis of the dam body. Spacings vary with placement temperatures and climate. In this case the designs show a typical spacing of 40 m which is reasonable for the climatic conditions and assuming some pre-cooling of the concrete. Further joints are required at abrupt changes in foundation profile such as the outer edge of the diversion culvert.

3.3.6.7 Internal Drainage As with all concrete dams, internal drainage is required to ensure that the design assumptions for internal pore pressures are valid. The drainage consists of drilled drain holes located near the upstream face of the dam. The holes are drilled between the galleries which form part of the drainage system. The galleries are located not less than 8 m from the upstream face of the dam and are spaced at not more than 35 m or possibly 40 m. The limit on vertical spacing is required to ensure that the drains drilled at low cost will emerge into the gallery below. Hole diameters of 75 to 150 mm are used, but a minimum diameter of 100 mm is recommended.

The joint drains are led to the galleries using PVC conduit. These drains are indicators of the effectiveness of the water-stops and afford means of access for grouting any deficiency.


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Figure 3-11 Typical Water-stop and Joint Drain Detail

3.3.6.8 Recommended Methods of Dam Construction The following methods are proposed for Song Bung 4 Dam:

• Placing: Sloped layer method

• Forming faces: GE-RCC against formwork

• Forming galleries: GE-RCC against formwork with pre-cast beam elements in the roof.

• Rock contact: GE-RCC

• Leveling concrete: CVC

3.3.7 Placement Rates and Plant Capacity

The placement methods are described in outline in Section 3.3.6.1. To date most dams have been built using horizontal lifts. The RCC manufacturing and placement capacity then has to be designed to place the maximum lift in one working day, here taken as 14 effective hours. Figure 3-12 shows the volume of 30 cm thick lift plotted against elevation. The maximum lift volume is about 2,600 m3 at elevation +155 m. Increasingly, the sloped layer method is coming into use and it does not have this constraint on it. The area of each layer within a lift is then dependent on the lift thickness, the width of the lift, the setting time of the RCC and the rate of RCC delivery to the dam. The method lends itself to an even production with good plant utilization.

700m

m

200m

m25

0mm

250m

m

300m

m

300mm

Crack inducer, 2mm thick HDPEsheet

Crack director. 20 cmhigh galvanised steelplate

GE-RCC

RCC

400m

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Figure 3-12 Lift Volume Versus Elevation

The following options have been examined:

a) Horizontal layer (lift) placement raising the dam 10 m per month with an effective plant capacity of 200 m3/h

b) Horizontal layer (lift) placement with an effective plant capacity of 200 m3/h.

c) Sloped layer placement in 1.5 m lifts with an effective plant capacity of 200 m3/h.

d) Sloped layer placement in 1.5 m lifts with an effective plant capacity of 175 m3/h.

e) Sloped layer placement in 1.5 m lifts with an effective plant capacity of 150 m3/h.

The rated plant capacity will be higher than the required effective capacity. Rated capacities may be 1.5 to 1.7 times the effective (actual) capacity.

RCC placement schedules have been made for the above options. To some extent the schedules can be steered to accommodate important project milestones. In the horizontal layer placement a delay of 24 hours for every 6 days has been incorporated to allow for unexpected down-time. In the sloped layer options a delay of 24 hours has been incorporated for every 1.5 m lift for similar reasons. In all options, placement is assumed to continue at the given rate for 14 hours a day. When placement reaches the bottom of the spillway ogee block, placement is assumed to continue on the right abutment with the remaining RCC on the left abutment being completed thereafter. For the purposes of this section of this review no account has been taken of any seasonal effect on placement rates. Horizontal layer placements have been limited to 3 per day as moving formwork may well be on the critical path.

The table below shows the time estimates for the various options. Option b) is probably not realistic as formwork movement is likely to be critical and would delay the programme. Any of the other options could be adopted, but the sloped layer method, option e), at 150 m3/h may

110

120

130

140

150

160

170

180

190

200

210

220

230

0 500 1000 1500 2000 2500 3000

30 cm layer volume, m3

Elev

atio

n, m


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be optimal. Estimated Net Times for RCC Placement (Excludes Delays for Flood and Rain)

Estimated Net Time, Months Option Method Time to

+198.5 m Right

Abutment Left

Abutment Suma 10 m/month Horizontal layer 8.0 2.8 2.8 13.6

b 200 m3/h Horizontal layer 7.2 1.1 1.0 9.3

c 200 m3/h Sloped layer 8.7 1.3 1.5 11.5

d 175 m3/h Sloped layer 9.7 1.5 1.7 12.9

e 150 m3/h Sloped layer 11.1 1.6 1.8 14.5

The construction schedule is discussed further in Section 4.1.

3.3.8 RCC Manufacture, Transport and Placement

3.3.8.1 Aggregate Aggregate can be derived from gravel and sand deposits and from quarried rock. For minimizing segregation, the angular particles obtained from crushing quarried rock are often preferred and this is proposed in the current design. A suitable quarry has been located in granodiorite some 4 km upstream on the right side of the valley. Sand has been located in the river some 20 to 30 km downstream which is suitable for RCC. The transport cost, which might be 0.05 USD/tone and kilometer, is much less than the quarrying and process costs which might be in the region of 8 to 10 USD/tone of sand.

Metamorphosed sandstone with some intercalated siltstone is present extensively and this rock may be suitable for RCC aggregate. This source should be investigated further.

Aggregate production should start well in advance of RCC placements. Up to one third of the required aggregate is commonly produced in advance. This has the advantage of reducing the size of the aggregate plant and ensuring that aggregate production is not on the critical path for dam construction. There is limited space available for aggregate storage and a smaller initial reserve may be optimal.

The aggregate plant would comprise a large jaw crusher and probably at least three cone and impact crushers. Three screening towers may be required. The capacity of the plant must be sufficient for the RCC and all the conventional concrete to be used in the project. Assuming aggregate production to be spread over 2 years, the required plant capacity of RCC and CVC in the dam alone might be 130 ton/hour (at 16h/day, 6 d/week, 48 weeks /year).

The following three sizes of coarse aggregate are proposed: Proposed Sizes of Coarse Aggregate

The fine aggregate, sand, is proposed to be taken from the river some 20 to 30 km downstream of the dam. This sand is mostly finer than 1 mm and there is a deficiency of 1 to 5 mm size material (Engineering Geology Report, Figure 6.6). It is likely that coarser sand will

60 mm MSA 40 mm MSA

40 to 60 mm 20 to 40 mm

20 to 40 mm 10 to 20 mm

5 to 20 mm 5 to 10 mm


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have to be produced by milling rock in the aggregate plant. It is also desirable to have sand with up to 15% non-plastic fines (<0.075 mm) which reduces the RCC cementitious material demand. Some or most of these fines may be crusher dust. The natural and manufactured sands will require separate stockpiles and will be batched separately.

3.3.8.2 Aggregate Stockpiles for RCC If the aggregate production were spread over 2 years, full production would start 9 months before RCC placement. The volume produced in this time, amounting to perhaps 270,000 m3, would have to be stockpiled in three separate sizes, with each pile being 50,000 to 130,000 m3 depending on the RCC mix proportions and the stacked density. Storage areas at suitable locations have to be identified and prepared in advance. Drawing 12006C-TD-TCTC-K-02 shows an area designated for the crusher plant where some of the aggregate may be stored. An area of at least 50,000 m2 may be required for coarse aggregate storage, preferably immediately adjacent to the aggregate plant, but the topography might dictate that the storage be split between different locations. Overall economy with the shortest and flattest possible haul roads is important in planning these storage areas.

Manufactured sand will have to be stockpiled in parallel with the coarse aggregate. For preliminary estimation purposes, natural sand is assumed to constitute 2/3 of the fine aggregate and manufactured sand the remainder. The volume of manufactured sand produced prior to commencement of RCC placement might be of the order of 50,000 to 60,000 m3 which would have to be stockpiled. The natural sand will presumably be processed near the borrow pit and stockpiles might be distributed between this area and the dam site. At the start of RCC placement there should be a volume already processed corresponding to at least 3 month RCC production available of which at least 1/3rd should be stockpiled at the dam site.

The size of the aggregate storage at the batch plant should be sufficient for at least one day’s production, and preferably two days worth, provided reliable haul roads and trucks are provided to maintain daily production rates.

3.3.8.3 Batching and Mixing Batch-type twin-axle pug-mill mixers specifically developed for RCC are now commonly used and are recommended for Song Bung 4 Hydropower Project. Continuous feed pug-mill mixers give a greater variability in concrete strength and are not favored. Drum mixers have been used and may be appropriate for smaller dams where the investment in batch-type twin-axle pug-mill mixers cannot be justified.

Batching is done is a conventional weigh-batching plant.

Ice and chilled water may be required to control concrete temperature in the summer months. For the purposes of this review, a flake ice and chilled water plant has been an assumed requirement.

Water for mixing and cooling may be derived from the river or perennial streams. Settling ponds will be required to remove the sand and silt load.

The batch plant and mixing station would be located in proximity to the dam. An area some 400 m upstream of the dam has been identified. This area would also contain day-storage for aggregate as well as silos for cement and pozzolan. Aggregate would be transported by truck from the main stockpiles at the quarry site on a daily basis. If the cement and pozzolan is delivered in bulk, the silo capacity at the site will have to be sufficient for at least 2 week’s production. For the various placement options, see the table in Section 3.3.8 and the RCC mix proportions in the table in Section 3.3.6, the site storage would be as follows:


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Estimated Silo Storage Requirements

Placement Rate Cement Storage Pozzolan Storage Total m3/h Tones Tones Tones 150 2,500 3,000 5,500 175 2,900 3,600 6,500 200 3,400 4,000 7,400

These quantities are required to ensure that RCC production and placement can proceed independently of interruption to supplies.

As indicated above, cement could also be transported in big-bags if available. These could be stored under cover at site and broken and blown into silos for use. This could substantially reduce the required silo capacity.

3.3.8.4 Transport RCC would be transported from the mixers to the dam with conveyors. From the site for the mixing station currently identified, the distance is about 400 m which is suitable. Transport on the dam may be with dumpers or the RCC may be placed directly from conveyors or a combination of both. Crane-supported conveyors are now in common usage. These are supplied by Potain, Rotec and others. The typical reach of suitable equipment is shown in Figure 3-13. In this review the use of one such crane is proposed. Most of the RCC can then be placed directly with minimal truck transport, mainly high on both abutments. Truck transport can be eliminated if two placing cranes are used. The choice will ultimately be that of the contractor.

Tower cranes are assumed for placing conventional concrete in the spillway as well as handling its formwork and reinforcement.

3.3.8.5 Placing and Compacting Delivery of the RCC is described above. The RCC is dumped on the dam on to previously placed fresh RCC and is bulldozed into place in the required layer thickness. After being tracked in by the bulldozer, compaction is effected by heavy vibrating rollers. Grout for the GEVR (or GE-RCC) can be produced in a grout mixing plant and pumped or carried to the point of placement. The GEVR is compacted using poker vibrators after the RCC has been placed. Smaller hand-guided compactors will be required adjacent to formwork and confined areas, but usually not where GEVR is used.

3.3.8.6 Curing and Protection of RCC Placed RCC requires curing with water for at least 30 days after placement or until covered by fresh RCC, whichever is shorter.

In summer the air temperatures are high and night-time placements will probably be required to minimize environmental heat gain. Temperatures of the RCC surface can be controlled using water misters and sprays. Free water has to be kept clear of RCC which is being worked.


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Figure 3-13 Plan of Dam Showing Reach of a Large RCC Placing Crane

Reach of a large RCCplacing crane


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3.3.8.7 Placing Schedule The RCC would be placed as continuously as possible for the base of the dam to the crest. The spillway structure in conventional concrete would be constructed after completion of the RCC but the CVC in the ski-jump and the lower part of the chute may be started earlier as an operation independent of the RCC placements. There would be breaks in RCC placement due to rain and possible over-topping of the dam where the probability, frequency and duration of the latter would depend on the size of diversion culvert adopted.

3.3.9 Foundation Treatment

3.3.9.1 Consolidation Grouting The purpose of the consolidation grouting is to ensure that the foundation has reasonable uniform stiffness without significant soft areas. Such areas might arise where the rock contains significant open joints or where blasting during foundation excavation has loosened the rock. In-filled joints (joints which contain clay and other soft material) should not be present to any significant extent as these are confined mostly to the near surface, abutment zone which will be excavated. Tentatively, a depth of grout hole of 3 m set at a spacing of 4 m may be estimated.

3.3.9.2 Dental Concrete Dental concrete should be cast on the foundation where holes have developed as a consequence of the foundation excavation process, and may include areas where the rock is heavily sheared or fractured. The purpose of such concrete is to regularize and shape the foundation. The foundation shape should be such that the RCC can be readily compacted in its vicinity.

3.3.9.3 Grout Curtain and Foundation Drainage The results of the permeability tests are discussed in “Report on The Evaluation of Alternative Dam Axes and The Selection of Dam Type”. The overall impression is of rock which will in general have low to moderate gout takes, but with some 10% to 15% of the rock absorbing larger volumes.

The grout curtain will be installed from the galleries provided in the dam and abutments. The holes should be angled so as to give the best intercept of the fissures and should in any case be angled in the upstream direction to create some distance from the drainage holes. In this case the joints would be oriented such that the holes may be vertical in a plane along the dam axis. A grout curtain corresponding to 0.6 x the local reservoir depth may be assumed subject to a minimum depth of 20 m. Curtain grouting is normally performed in one row down to a depth where the Lugeon values are 3 or lower. It is suggested that the holes in the grout curtain are inclined 15º towards upstream

The drainage holes will also be installed from the galleries and will be angled in the downstream direction. Tentatively, the holes should be drilled at 6 m centers and be 100 to 150 mm diameter. The depth of the curtain may be assumed at 40% of the local reservoir head at the gallery subject to a minimum of 15 m.

3.3.10 Comments on Unit Rates on RCC

A unit rate of 564,707 VND/m3 (35.74 USD/m3) has been used in the cost estimates in the Feasibility Study. This includes provision of the all the concrete constituents, mixing, transport and placing. It is not clear how much cement and pozzolan has been allowed for.


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The unit price for cement is 789,000 VND/tone (50 USD/tone) including transport. A unit rate for pozzolan has not been found. The cost of RCC is commonly estimated on the basis of the cost of

a) Providing the aggregate, batching and mixing, transport and placing

b) The cost of cement and pozzolan

c) Facing costs

The cost of item a) is mainly dependent on the size of the dam as RCC construction is capital intensive and varies little with local costs. For a dam of this size, employing crushed coarse aggregate and natural sand, item a) might be about 20 USD/m3. If the price of pozzolan is set to be the same as cement (typically is has a lower cost than this) and allowing 200 kg/m3 for cement and pozzolan combined, the unit rate for the RCC would be 30 USD/m3.

Facing costs depend strongly on the methods used. If GE-RCC is to be employed, a budget rate might be 40 USD/m2. As set out above, the reinforced concrete facing to the dam would be eliminated.

When these adjustments are made to the cost estimates, the overall cost of the dam is reduced by about 6% compared to the cost estimate in the Feasibility Study.

3.3.11 Arrangements for Dam Safety Monitoring

3.3.11.1 Monitoring Instruments Dam instrumentation is required to verify the design assumptions and demonstrate that the dam is functioning normally and within accepted safety margins. The extent of instrumentation and the frequency of readings should be such that these objectives are achieved but should not be more than necessary. Excessive data collection can negate the main objectives because of the burden of collection and reporting tend to delay reporting, possibly of important event and these event may be obscured by the sheer volume of data.

The following dam monitoring instruments and installations are recommended, but the quantities should be reviewed in the Technical Design Phase:

• Seepage monitoring

Total seepage from the galleries should be measured in a weir box installed at a suitable location. If the seepage water is pumped, the weir box should be installed at the pump outlet. All drainage wells and any internal drainage holes that yield water should be monitored individually.

• Pore pressures in the foundation

Electrical piezometers should be installed in the foundation under the dam including the concrete–rock interface. They would be drilled in to various depths and the leads connected to monitoring boards with the galleries. Standpipe piezometers should be installed from the foundation galleries to various depths. Some 25 electrical piezometers and 15 standpipe piezometers might be allowed for.

• Tilt of the dam

The tilt of the dam should be measured using a combination of pendulums and inverted pendulums. The anchorages for the inverted pendulums should be drilled into the foundation to a depth of at least 20 m. The pendulums would be installed in small shafts formed in the RCC and the spillway concrete. One set of pendulums would be installed in each of the proposed instrumented sections.

Studs are required on the crest of the dam for monitoring dam deflections by precise


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survey. At least two studs are required on each of the RCC blocks defined by their induced contraction joints as well as on each of the spillway piers.

• Opening of induced cracks

At the location of induced joints within the galleries and at the dam crest, devices should be installed which can measure the joint opening and any horizontal or vertical displacement across the joint. The installation is, at it simplest, studs on each side of the joint where their distance can be measured with a suitable caliper type instrument. Forty such installations may be required.

• Concrete temperature

The temperature in the concrete should be monitored to verify the design estimates. Temperature sensors are required at selected locations and these are incorporated in the RCC as it is placed. Some 30 to 50 instruments may be required.

• Earthquake accelerations

Two strong motion accelerometers should be installed with one on the crest of the dam and one in the bottom gallery.

Two principal instrumented cross-sections are proposed. One would be located in the non-overflow section where the dam is at its maximum height and one would be roughly centered on the spillway but coinciding with a pier.

There are many options for monitoring the various instruments. The instrument leads can be all brought to a central monitoring station where reading can be made automatically or manually. At the other extreme, instrument leads can be collected to a number of terminal boards and read manually. During construction many instruments will be read wherever the cable ends happen to be whereas later the instrument leads would be brought to one or more terminal boards. As indicated above, crack monitoring is proposed to be done manually which has the advantage that the instrumentation readers observe the crack each time it is being measured. Automated electrical measurement is also possible. At the tender design stage the costs and merits of alternative concepts and methods of measurement should be evaluated.

3.3.11.2 Measurements General

A monitoring schedule will be required to cover the construction period, first filling and normal operation. This will form part of the operations and maintenance manual for the Project. It will include inspections, data collection from installed instruments, survey and record keeping. Inspections will be prescribed for the interior and exterior of the dam, the spillway and plunge-pool and the dam abutments, as well as the reservoir slopes. Actions to be taken in the event of unusual instrument readings or occurrences will also be described. This would inter alia give instructions for monitoring and survey after a major flood or earthquake, and would include a spillway and plunge-pool condition survey.

The monitoring schedule should be prepared as part of the tender design and it should be revised and finalized before the end of construction.

Measurements during Construction and First Filling

The primary purpose of these measurements is immediate safety. Yet, they may also bring out interesting details in the overall behavior of the dam and its foundation due to complex factors, sometimes hardly known or scarcely considered in the design.

During the construction period the dam will be exposed to high floods. It is essential to take the opportunity of monitoring the behavior of the dam and its foundation during these peak


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floods. The type of instrumentation to be considered is piezometers in the foundation and in the dam and joint and stress meters in the dam.

Moreover, measurements carried out during the floods and the first filling will provide starting points for evaluation of the importance and severity of any variations in the behavior of the dam and its foundation.

Measurements during Operation Period

These measurements should provide information on the behavior of the structure both as a whole and at particular points. Their main purpose is to give a reliable picture of all evolutions, both favorable and such which might cause concern.

3.3.11.3 Frequency of Measurements General

Monitoring frequencies will depend on many factors and will vary over time. Instruments will be read from their time of installation to verify their function and to give base-line data. Regular reading will be made during construction, typically weekly. During first filling, monitoring of many instruments may be daily but may depend on the rate of filling. During the first year of operation most instruments will be read on a weekly or monthly basis, but in subsequent years the frequency may be decreased. Seepage monitoring is likely to remain frequent and possibly continuous throughout the life of the dam. Monitoring frequencies may change in response to observations and occurrences.

First Filling All measurements should be made before filling is started (initial operation). The dates of the successive measurements will depend on the level the water has reached in the reservoir. The closer the water is to the full supply level, the shorter will be the interval between the measurements. A series of measurements carried out with the proper instruments should be carried out as follows:

• When the water reaches ¼ of the total height

• When the water reaches mid-height

• Every tenth of the total height for the third quarter of the total height

• Every 2 m of variation for the fourth quarter of the total height

In addition to this, some simple measurements can be carried out daily, such as visual examination of dam faces and abutments, leakage, downstream resurgent springs, pendulums and drainages.

During Operation Measurements should be more frequent in the years immediately following the first filling, when active settlement is in progress. The following might apply:

• Settlement Period: - Topometry: four surveys every year

- Pendulums: weekly measurements

- Strain gauges: twice weekly measurements

- Piezometers: weekly measurements

- Leakage, drainage: daily measurements

- Continuing monthly measurements of temperature measurement devices


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• Normal Operation (after Stabilization of Settlement): - The above frequencies can be reduced by half. Not only the frequencies of

measurements, but also the number of instruments read can be reduced according to what is learned during the first years of operation.

The cables from the instrumentation in the foundation should preferably be drawn to a central station located in the grouting and drainage tunnel.

In order to check scour in the plunge pool, depth measurements by eco-sounding or plumb line should be performed after large discharges over the spillway (> 4,900 m3/s).

3.4 Review of Waterway

3.4.1 Intake

The intake structure as proposed is well conceived and should under normal operational conditions be functional. The air vent should end in a bend or to the side of the structure to prevent objects being sucked to the opening.

The intake structure will be founded in rock belonging to stratum IB, the quality of which is considered adequate. The inclination of the cut slopes should be 1:2 in the edQ stratum, 1:1 in the IA strata and 1:0.75 in stratum IB.

3.4.2 Headrace Tunnel

3.4.2.1 General The about 3 km long headrace tunnel will have a rock cover in the range of 45 m to 450 m. It will be excavated in Members 2 and 3 of the lower Song Bung formation in rock belonging to strata IIA and IIB (the main part), and it will be affected by one fault zone of grade IVa (IVa-2) and 9 grade IV faults. It is estimated that about 5% of the tunnel will be excavated through tectonically disturbed rock.

The invert of the excavated tunnel will have a width of 5 m. The span of the horseshoe shaped tunnel will be 7.6 m. In the Feasibility Study it is assumed that the entire tunnel will be concrete lined with a thickness of the reinforced lining of 0.6 m. Consolidation grouting will be carried out along the tunnel from the intake to the surge tank, in a staggered pattern with five 3 m long holes in sections spaced at 3 m. In a normal section of the tunnel, bolts of Φ25 mm with a length of 3 m will be placed in a grid pattern # 1.5x1.5 m, which gives10 bolts in each section. A 100 mm thick layer of shotcrete will cover the walls and roof of the tunnel.

When passing faults of grade IV the same support will be installed, but the shotcrete will be reinforced by a net Φ 6 mm # 100x100 mm.

In the grade IVa-2 fault zone the above support will be applied with the addition of steel sets H200 spaced 1 m.

Two adits are considered for the headrace tunnel, one adit 370 m downstream of the intake structure and one adit 42 m upstream of the surge shaft. The distance between the adits will be 2,638 m. With a progress of 20 m per week and considering a reduced progress when penetrating the fault zones, it should be possible to complete the tunnel excavation between the adits in a period of some 70 weeks. It might be possible to avoid the upstream Adit 1 and just have Adit 2 in the downstream end and perform the excavation from the upstream end through the intake. Such a solution would, however, interfere with the construction of the intake structure.


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3.4.2.2 Comment The proposed support is considered conservative and is assumed to accommodate both outer and inner water pressure without considering the rock medium. The outer water pressure will not put any load on the lining if the lining is drained by penetrating holes placed in sections spaced 3 m with three holes in each section, and drilled 1 m into rock.

The inner water pressure can be taken by the rock mass provided that the minor principal stress is larger than the inner water pressure or if the ground water table is located at a higher elevation than the pressure line in the tunnel. If this is not the case some leakage from the tunnel will take place. The stress situation in the rock surrounding the tunnel can be determined by means of hydraulic fracturing tests performed from the tunnel as excavation proceeds.

The headrace tunnel is recommended to be furnished with a permanent support of fiber-reinforced shotcrete, in lieu of cast reinforced concrete lining, except in the upstream 100 m where a cast reinforced concrete lining is proposed to be installed. The permanent shotcrete lining should have a minimum thickness of 50 mm. Where the temporary support already have this thickness, no extra shotcrete is required. The shotcrete lining has to be drained in order to prevent the build-up of outer water pressure. Three drain holes should be installed in sections spaced 3 m. The holes should be drilled 0.5 m in rock.

3.4.3 Surge Tank

3.4.3.1 General The calculations contained in Volume 9, Book 3, Part 3 of the Feasibility Study have been briefly evaluated as basis for the review of the proposed surge arrangements.

The proposed surge arrangements, comprising a 15 m diameter shaft with throttle and a 24 m diameter surge tank on top, appears to be well conceived. The shaft diameter is designed with a safety factor of at least 1.5 to the Thoma criteria.

The nominal acceleration time of the waterway from the turbine to the surge tank is more than 2 seconds, which is in the high range. Stability calculations are not contained in the Feasibility Report. It is recommended that possible stability problems be evaluated in more detail in the Technical Design Phase, where the weight of the generating units (mass of inertia) needs to be considered.

3.4.3.2 Engineering Geological Features General

In the Feasibility Study the center of the surge shaft is located 42 m downstream of the point where Adit 2 joins the headrace tunnel. The lower 6 m of the shaft has an excavated width of 6 m. From El. 168 m the width is increased to 17 m up to El. 221.5 m. From this elevation the shaft consists of a freestanding cylinder with an inner diameter of 24 m. The part of the shaft located in rock is excavated in rock strata IB and IIA. The support to the surge shaft indicated in the Feasibility Study is consolidation grouting in 3 m deep holes placed in a staggered pattern of 3x3 m, 100 mm of shotcrete and a 1 m thick cast concrete lining.

The slopes in the open cut from the ground surface down to El. 221.5 m should be given the following inclinations:


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Inclination of Cut Slopes

Stratum Inclination edQ 1:2 IA 1:1 IB 1:0.6

The benches have heights in the order of 10-12 m and are separated by 3 m wide berms. The space between the toe of the slope and the freestanding part of the shaft at El. 222.5 m is given a width of 6 m.

Comment

The location of the surge shaft is considered appropriate allowing the excavation of the vertical shaft to be located in IB and IIA rock strata.

A convenient way to excavate the shaft in rock is to start by raise-boring a central hole from the tunnel up to El. 221.5 m. The drilling of the rounds can then be performed from a platform, the blasted rock is then stoped into the central hole, mucked out in the tunnel and transported out through Adit 2. Installation of rock support is successively performed as the excavation progresses. The type of support considered is 3 m long fully grouted bolts in the small diameter part and 5 m long bolts where the diameter is 17 m, placed in a grid spaced 3 m and covering the walls with 100 mm of fiber-reinforced shotcrete. The shotcrete should be penetrated by drainage holes placed in a pattern spaced 4 m, and drilled 1 m into rock.

Installation of a reinforced cast concrete lining below some +221.5 m is at present not considered necessary. In order to establish the rock stress situation around the shaft it is, however, advisable to perform hydraulic fracturing tests.

3.4.4 Penstock

3.4.4.1 General The diameter of the penstock is undersized and results in a water velocity of 9.5 m/s at full load. Normal velocity for a penstock would be in the range of 6-7 m/s. A narrow penstock would result in unnecessary losses and pressure rise due to water hammer. The pressure rise of the penstock due to water hammer appears to be high and is partly a result of the proposed narrow penstock. The propagation velocity of the pressure wave in the penstock is specified at 771 m/s, which appears to be low. Normal velocity would be more in the range of 1,100-1,200 m/s.

3.4.4.2 Engineering Geological Features General

In the present design the penstock starts at the centre line of the surge shaft and the same dimension as for the headrace tunnel (inner diameter of 6.8 m) is kept for 10 m. From this point, the inner diameter is reduced to 5.2 m over a 10 m long section. This inner diameter is maintained for the rest of the penstock up to the bifurcation. At a distance of 67.9 m a vertical part is introduced between El.155 m and El. 90 m. The lower part of the penstock is inclined 1‰ towards downstream and has a length of 108.4 m to the bifurcation. The bifurcation is currently located outside the cut slope where two pipes with an inner diameter of 3.4 m conveys the water to the powerhouse

The rock is supported by 4 m long bolts placed in a staggered pattern, spaced 3 m in the larger sections and by 3 m long bolts in the same pattern in the bifurcations. Cast concrete linings with thickness of 0.3 m and 0.5 m are considered. In addition the penstock is


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proposed to be steel lined.

Comment

A vertical penstock underground is easier to excavate than an inclined penstock. The economical evaluation in the Feasibility Study also showed that a vertical penstock is more feasible and is supported.

The steel lining of the whole length of the penstock is considered conservative.

The present location of the vertical part of the penstock gives the shortest distance between the bend and the ground surface of some 45 m. For preliminary planning purposes, the required cover to prevent hydraulic fracturing of the rock mass in an unlined tunnel can be determined using the formula:

CRM = hS x γW x F / γR x cosβ

Where:

CRM = minimum rock cover hS = static head γW = unit weight of water γR = unit weight of rock β = slope angle F = safety factor

Usually a safety factor F=1.5 is selected. With a static head of 71 m, a unit weight of rock of 2.65 t/m3, and a slope angle of 40º, the minimum required rock cover can be calculated to be 52 m. Thus it is recommended that the vertical part of the penstock be shifted 35 m towards upstream.

From a hydraulic point of view it might be feasible to install a thin (250 mm) concrete lining with drainage holes. Only the part of the penstock located closer to the powerhouse than 75 m is considered necessary to steel line. To verify this assumption the stress situation should be established by means of hydraulic fracturing tests.

The excavation of the vertical part of the penstock is suggested to be performed by means of raise-boring. It is considered possible to support the rock in this part by means of spot bolting and shotcrete. The location of the powerhouse is recommended to be maintained, but the cut slope should be shifted towards downstream making it possible to cast the concrete against the rock. The angle of the cut slopes should be optimized, as it may be optimal to make vertical cuts supported with rock bolts and shotcrete. With such a solution the bifurcation will be placed inside the rock

3.5 Review of Power Station

3.5.1 Layout in the Feasibility Study

3.5.1.1 General In general the layout of the surface powerhouse is well conceived. The layout is to a large extent given by the choice to excavate from the surface to locate the turbines. This gives a very high powerhouse as all transports will arrive on the surface and the equipment has to be brought down to their respective locations. See also the comments regarding the possibilities for an underground location of the powerhouse in Section 3.5.4.

The ground area of the powerhouse is given by the location of the units and the inlet valves, in addition to the space necessary for transport and assembly. There is ample space for the rest of the equipment due to the additional height of the powerhouse, which provides for


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more floors than usual.

The design of the power station is of the outdoor type comprising a superstructure and a substructure founded on competent rock. The superstructure provides protective housing for the generator and control equipment as well as structural support for the main crane of the machine hall. The superstructure is prolonged and provides for an erection bay that protects component assemblies during inclement weather. The substructure or foundation of the powerhouse consists of concrete necessary to form the draft tube, support the turbine stay ring and generator, and encase the spiral case of the Francis type turbines.

By utilizing the room at elevation +121.2 m in the erection area as an erection pit, the total height of the surface structure can be reduced by some 4 m.

3.5.1.2 Width of Powerhouse Minimizing the dimensions is one important principle of controlling cost and construction schedule of a powerhouse. The minimum possible width of a powerhouse is determined by the space needed by the turbine or generator with added necessary space for the construction and operation, concrete walls, and space for transport and erection.

For Francis units in the lower speed range (here 250 rpm), the generator enclosure with corridor on one side will determine the minimum width of the powerhouse. The width of the corridor has been selected at 3.75 m, but could be reduced to about 2 m. The corridor is used for communication, electric panels, etc.

The turbine inlet valves are normally placed inside the machine hall with easy access for installation and maintenance by the main crane. To ensure safe erection and dismantling it is recommended that the center of gravity of the valves is located within covering range of the main crane. With this layout, the turbine valves may require some space outside the boundary of the machine hall. The solution is to establish local alcoves for the valves. The size of such alcoves depends on the angle of intersection between the inlet pipe and the machine hall wall. Considering all design objectives, the optimum angle between the inlet pipe and the machine hall wall will be about 60 degrees.

3.5.1.3 Powerhouse Orientation By giving the powerhouse a positive rotation of some 20 degrees, the powerhouse would be oriented more in parallel with the contour lines of the surrounding terrain. The advantage would be less excavation, more straight tailrace canal and the possibility of reducing the powerhouse width as discussed in the section above.

3.5.1.4 Structural Concrete The concrete walls of the powerhouse are generally very thick, varying from 1.9 to 2.1 m. It is believed that the concrete quantities can be reduced by making use of concrete with higher strength thus reducing the thickness of the walls.

Dynamic loads from the generating units are being transferred to the superstructure. If natural frequencies of structural components coincide with frequencies generated by the units, vibration problems may occur.

3.5.1.5 Location of Transformers The suggested location of the main transformers in the open air at elevation +125.5 m has resulted in very long high amperage busbars. Locating the transformers at a lower level and closer to the generators can save both losses and costs. The room between elevation +101.4 m and +112.25 m at the upstream wall could be modified to house the transformers. The


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transformers can be transported and lifted through the machine hall.

3.5.1.6 By-pass Arrangement The drawings do not show any by-pass arrangements in the powerhouse.

In a situation where the waterway needs to be emptied, the powerhouse would need to have a by-pass arrangement. A normal arrangement would be to install a pipe from upstream of the turbine valve to the tailrace canal.

3.5.2 Number of Units

For a given installed capacity the optimum number of units depends on a number of factors, such as (i) size of the units in the total power system, (ii) construction cost, (iii) energy loss during maintenance, and (iv) turbine efficiency.

In the case of Song Bung 4 Hydropower Project two and three units were investigated in the Feasibility Study at least taken items (ii) and (iv) above into account, giving an optimum for two units. The proposal of two units is supported as item (i) above is hardly applicable due to the small size of the units, less than 100 MW, compared to the total system capacity of over 11,000 MW, and item (iii) can be alleviated if maintenance is performed during the dry season when only one unit is normally operated.

3.5.3 Engineering Geological Features

3.5.3.1 General Different layouts for the powerhouse have been considered, and both underground and surface locations have been studied in the Feasibility Study. The rock of the Song Bung formation is competent and in case the foundation of the aboveground structure is placed on rock belonging to stratum IIA, no problems are to be expected from a stability point of view. The same is the case for an underground solution. If the cavern is located in stratum IIA, it is considered possible to excavate and support it with a reasonable support.

3.5.3.2 Surface Powerhouse The selected solution in the Feasibility Study is an aboveground powerhouse. As mentioned above the competent rock conditions of the area with the foundation located in IIA rock makes this alternative feasible. The extensive excavation with rock fill placed in an area between the cut slope and the concrete structure is not considered appropriate. A better solution would be to move the cut slope towards downstream and make the part against which the powerhouse structure will be cast nearly vertical. In order to make this possible it is necessary to support the slope with bolts and shotcrete, successively as the excavation proceeds. The excavation should be carried out by means of smooth-blasting and the support of 4-6 m long grouted bolts placed in a grid 3x3 m. The rock surface should be covered with a 50-100 mm thick layer of fiber-reinforced shotcrete. With this solution the bifurcation would be located inside the rock.

3.5.3.3 Underground Powerhouse An underground powerhouse can convey the large forces from the generating equipment to the surrounding rock mass. In the case with the competent rock of the Song Bung formation this can be accommodated without problems. An underground location is also favorable in case the Project is exposed to seismic loads and also reduces the exposure to large variations in tail water levels.


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The type of support that may be required to stabilize the excavation is 6 m long grouted bolts in the roof placed in a grid with 3 m side. In the upper parts of the walls, 2 to 3 rows of longer (9 m) bolts might be required. The main support of the walls should also be 6 m long bolts spaced in a grid with 3 m side. The roof should be covered with a 200 mm thick layer of fiber-reinforced shotcrete while the thickness on the walls could be in the order of 100 mm.

3.5.4 Considerations Regarding Location of an Underground Powerhouse

3.5.4.1 General Layout In the Feasibility Study the location of an alternative underground powerhouse has been located in the downstream end of the tunnel. A possibility is, however, to place an underground powerhouse in the upstream part with a short headrace tunnel and a long tailrace tunnel. In this way the major part of the tunnel will be un-pressurized, and have a larger cover and to a greater extent be located in IIB rock. With such a solution the surge shaft upstream of the powerhouse can be eliminated. The short headrace tunnel is in this case suggested to be concrete lined with reinforced concrete preventing leakage. The vertical penstock and the lower horizontal part would be steel lined. The bifurcation would be located in the lower part of the tunnel.

With this solution, a tunnel located at the present Adit 1 would serve as the main access tunnel to the powerhouse and from this tunnel construction tunnels will be excavated. An example on this type of solution is given in Figure 3-14 and Figure 3-15 below. In this case an underground transformer hall was constructed. The construction tunnels will be:

• From the main access tunnel, construction adits leading to the galleries of the powerhouse and transformer halls cavern as well as to the draft tube gate hall will be excavated.

• A continuation of the main access tunnel after passing the powerhouse cavern will lead to the lower part of the vertical penstock.

• A tunnel from the main access tunnel to the tailrace tunnel and the lower part of the cavern.

Figure 3-14 Example of Design of Underground Power Station-Plan


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Figure 3-15 Example of Design of Underground Power Station-Section The construction tunnel down to the tailrace tunnel will serve as a surge tunnel (it should be noted that a construction tunnel with an area of say 50 m2 and an inclination of say 1:10 would give a surge area of 50 x 10 = 500 m2), and it is important that the portal of this tunnel is located at an elevation high enough to prevent the surge water from reaching the main access tunnel and flood the powerhouse. The tunnel will also serve as a construction adit for the upstream part of the tailrace tunnel. In Figure 3-15 a surge chamber is also shown, which is required in case the surge tunnel is insufficient.

The cable tunnel can be vertical and equipped with an elevator for emergency use.

As an alternative to the transformer hall indicated on Figures 3-14 and 3-15 an aboveground location of the transformer is possible

The powerhouse cavern will be excavated starting with the top heading, with a span in the order of 8 m and a height of 8 m, being taken out. When the roof of this tunnel has been supported in accordance with the description above, the rock on both sides of this top heading is stoped out to the full width of the cavern and supported. The remainder of the cavern will be excavated by benching down from this top heading. The spoil would be transported out via the top heading or the main powerhouse access tunnel as appropriate. The material from the lower part of the cavern and the upstream part of the tailrace tunnel will be taken out through the future surge tunnel. As the excavation progresses, the walls have to be supported successively by bolts and shotcrete as stated above.

The tailrace tunnel is recommended to be supported by means of bolts and shotcrete in accordance with Section 3.2.3. Drainage holes should penetrate the shotcrete layer in order to prevent the build-up of outer water pressure when the tunnel is emptied.

In the downstream end of the tailrace tunnel a tunnel has to be excavated down to the tailrace. From the upper part of this adit, a small cavern from which stop-logs can be placed in the tunnel will be constructed according to Figure 3-16 below:


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Figure 3-16 Example of Design of Downstream End of Tailrace Tunnel for Underground Power

Station

As an alternative to the stop-log chamber indicated on Figure 3-16 an aboveground concrete structure connected to the tunnel with a shaft might be feasible. A further option might be an outlet structure in open cut.

3.5.4.2 Comment It is recommended that an alternative with an underground powerhouse located in the upstream end be studied in the Technical Design Phase. The main advantage with this location is that the surge shaft upstream of the powerhouse can be avoided. Further the extensive excavation for the aboveground powerhouse is not required, but only minor excavations for the tailrace outlet..

3.6 Review of Electromechanical Equipment

3.6.1 Gates

The following gates have been proposed for the spillway and intake: Item Spillway Intake Type Radial Fixed Wheel Plate Number of Units 5 1 Dimensions, m 15.0 x 16.0 6.2 x 6.2 Design Head, m 16 50 Weight per Unit, tones 145 55

All gates are proposed to be operated by hydraulic cylinders.

Similar gates have been used in other hydropower projects in Vietnam in recent years, and we concur with these proposals.

3.6.2 Turbines

The main parameters chosen for the turbine are as follows:

• Number of units: 2

• Type of turbine: Francis with vertical shaft

• Turbine output: 80 MW

• Rated head: 105.5 m


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• Nominal runner diameter: 2.8 m

• Rated speed: 250 rpm

• Maximum flow rate: Qt = 85.88 m3/s

• Suction head: Hs = -5.0 m

• Setting elevation: m∇ = 90

The height of the draft tube is 3.6 m and the length is 14 m. The outlet section of the draft tube is divided into two orifices with dimensions (w x h) 3.65 x 3.85 m.

The runner will be made of high durable stainless steel, possible arc-welding or casting. Two servomotors drive the guide vanes of the turbine.

The turbine will be equipped with a electric-hydraulic governor, digital with PID regulator rule and oil pressure class 6.3 MPa.

The main data given seems reasonable. The rated speed could possibly be chosen as 300 rpm, but there are only marginal differences and we concur with the selected parameters.

3.6.3 Hydraulic Stability

3.6.3.1 General The Consultant has calculated surges and hydraulic stability with the simulation program ALAB. The conclusion is that the power plant is designed in a conservative and relatively safe manner, and the surges are within safe limits.

Turbine Parameters:

• Turbine closing and opening time: 8 seconds

• Maximum water level of the reservoir: +227.5 m

• Water level at outlet: +96.0 m

• Flow before load rejection: 172 m3/s

3.6.3.2 Results Full Load Rejection

Two units operating at full load at load rejection gives the following results:

• Maximum surge level (in surge tank): +241 m

• Maximum spiral casing pressure: 154 m

• Runaway speed: 383 rpm

• Runaway speed with locked servomotors: 489 rpm

Start-up of one unit and full load rejection

One unit is operating at full load and unit 2 is started and loaded up to full load. A full load rejection after about 2 minutes gives the following results:

• Maximum surge level (in surge chamber): +242.2 m

• Maximum spiral casing pressure: 153 m

• Runaway speed: 383 rpm


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3.6.3.3 Comments The chosen values for the waterway and turbine seem to function well. The maximum upsurge is 2 m lower than the top level of the surge tank of +244 m. With 8 seconds closing time of the turbine guide vanes, the maximum waterhammer pressure is 154 m. The static head in front of the turbine is 137 m, which gives a pressure increase of 24%. An increase of the closing time of the turbines can reduce the waterhammer pressure.

Hydraulic stability of the waterway and the two units is controlled and hydraulic stability seems to be acceptable.

3.6.4 Auxiliary Equipment in the Power Station

Preliminary descriptions and data are given for the following auxiliary systems:

• Water supply system

• Fire fighting system

• Air compression system

• Water drainage and dewatering systems

• Oil pressure system

• Hydraulic measurement system

These will all be specified in the Technical Design Phase, but we concur with the data and descriptions given at this stage.

3.6.5 Single Line Diagram

The overall single line diagram of Song Bung 4 Hydropower Project have been based on two generator-turbine units, with a rated capacity of 92 MVA (78 MW), connected to a 220 kV power system through two step-up transformers 13.8/230 kV with a rated capacity of 100 MVA.

The use of generator-transformer block diagram gives a flexible and simple operation. It is proposed to make synchronization possible both at the generator circuit breaker and at the 220 kV unit circuit breaker. The latter is deemed unnecessary, but is according to Vietnamese standard and gives only a minor extra complication of the control system and can thus be accepted.

220 kV is proposed as the transmission voltage and the power will be transferred to the nearby Thanh My 220/110 kV substation over a 220 kV double circuit over-head transmission line. 110 kV is also a viable transmission voltage, but we agree to the proposed voltage of 220 kV, as the main bulk of the produced power will be transferred over a longer distance.

The 220 kV switchyard is arranged in a double busbar scheme with a bus coupler and an bypass disconnecting switch on the outgoing feeders. The bypass switches is not deemed strictly necessary, but gives an extra flexibility at a marginal cost. We concur to the proposed alternative.

Auxiliary power supply is proposed to be supplied by two auxiliary power distribution transformers connected to each unit. Backup will be provided from the 35 kV transmission line reused after construction. There will also be an emergency diesel generator. This is deemed to be a normal solution of auxiliary power supply for a power station of this size.


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Excitation power for the generators will be provided from the generator unit voltage system through the excitation transformer.

We concur with the general layout proposed for the main single line diagram.

3.6.6 Generators

The power rating of the generators is determined of the rating of the hydraulic turbines.

A normal generator voltage would be in the range of 10 kV to17.5 kV, based on nominal isolation of stator winding, number of pole pairs and rated current of the conductor in stator winding. At this stage a generator voltage of 13.8 kV is proposed, corresponding with generator voltage levels of existing hydropower plants in the system. This value will, however, be determined in the Technical Design Phase.

The main specifications of the generator are as follows:

• Type: Three phase, synchronous, vertical shaft

• Rated power: 92 MVA (78 MW)

• Power factor: 0.85

• Rated voltage: 13.8 kV

• Speed: 250 rpm

• Insulation class: F

• Frequency: 50 Hz


The excitation system of the generator is of the static type using 3-phase thyristor bridge rectifier supplied by an excitation transformer.

The total weight of the generator is estimated to 560 metric tones, including a rotor weight of 280 metric tones. This is far heavier than would be expected from a recognized international supplier. The rotor weight is dimensioning for the powerhouse overhead traveling crane and for the civil support structure of the crane. It is in our opinion important that the technical specification opens for different designs (e.g. not include requirements for large moments of inertia, which will inevitably make for a heavy rotor). This item should be verified before the design of the powerhouse is finally determined.

We concur with the main data of the generators, but not with the weight estimates with subsequent design requirements of the powerhouse crane with its civil support structure.

3.6.7 Generator Transformer

The generator transformer is of the 3-phase type with two windings, outside placement, natural oil cooling, forced air cooling (ONAF), and equipped with an off load tap changer, and with the following specifications:

• Rated power: 100 MVA

• Off-load tap changer range: 230±2x2.5%/13.8 kV

• Vector ground: Ynd-11

• Percent short circuit voltage: 12%



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The Feasibility Study actually proposes an on-load tap changer, but this is probably a misprint as the specification is typical for an off-load, and it should anyhow be an off-load.

The rated power of the transformer is somewhat higher than the generator to cover for the maximum continuous output.

We concur with the proposed main data of the generator transformer.

3.6.8 220 kV Switchgear

A conventional air insulated switchgear is proposed, located at some distance from the powerhouse, where a flat area suitable for the purpose can be obtained. A gas insulated switchgear could be an option as it could be located at the powerhouse, but is most probably much more expensive and we thus concur with the proposed alternative.

The main switchgear equipment will have the following data:

• 220 kV circuit breaker: SF6 type, 245 kV, 1,250 A, 31.5 kA/3s

• 220 kV disconnecting switch: 245 kV, 1,250 A, 31.5 kA/3s.

• 220 kV current transformer: 245 kV, 200-400/5 A (for main transformer circuit),

and 400-800/5 A (for 220 kV circuit).

• 220 kV voltage transformer: 230: 3 /0.11: 3 /0.11: 3 kV

• Lightning arresters: Zinc oxide type – 192 kV, 10 kA

Numerous switchgears of this type at power stations and substations have been erected in Vietnam, and it is recommended to use the standardized solutions developed for these.

3.6.9 Auxiliary Power Systems

The auxiliary power consists of a 400 V AC system and a 220 V DC system. These are described in single line diagrams 12006C-TD-NM-D06 and –D05, respectively. Both are built with backup in mind and we do not have any objections to these proposals.

3.7 Review of Transmission

3.7.1 General

A short, some 35 km long, double circuit 220 kV overhead transmission line from Song Bung 4 Power Station to a new substation at Thanh My is proposed in the Feasibility Study. Included in the cost of the transmission line is also the two receiving 220 kV switchgear feeders at Thanh My. These will most probably be designed in a similar way as the 220 kV switchgear at Song Bung 4 Power Station.

3.7.2 Transmission Line

The basic data of the transmission line are as follows:

• Type of line: Double-circuit line

• Rated voltage: 220 kV

• Conductor: ACSR-300 or equivalent

• Overhead Ground Wire: OPGW-70 or equivalent + GSW-70

• Length of line’s route: 33.8 km


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• Insulator: Glass or porcelain

• String of suspension insulators: 16 disc (70daN)

• String of tension insulators: 17 disc (160daN)

• String of jumper suspension insulators: 16 disc (70daN)

• String of tension insulators for lightning: 1 disc

• Tower: Steel tower for double circuit line

• Foundation: Reinforced concrete, casted in place.

No technical problems are foreseen for the transmission line.

4 Tentative Construction Schedule

An outline of a tentative construction schedule is given in Figure 2 showing major items that are on the critical path.

4.1 Dam Structure and River Diversion The item for the diversion culvert in Figure 2 includes temporary cofferdams required for its construction, excavation and concrete placement with subsequent removal of the temporary cofferdams.

The foundation excavation item covers excavation, dental concrete, consolidation grouting and initial clean-up.

The grout curtain, foundation drainage curtain and internal drainage holes would be made from the galleries and would not be on the critical path.

The foundation preparation in the riverbed would be completed in 2009 to allow a prompt start of RCC placements in early 2010. This may entail constructing the cofferdams of limited height earlier than shown on the schedule, but with risk of these being lost in a flood. Cofferdams have been constructed with RCC and this may be considered also here. The foundation preparation would consist of removal of loose blocks, dental concrete, leveling concrete and consolidation grouting.

The diversion closure is shown as a milestone signifying the start of reservoir filling. Following detailed analysis, the diversion closure may possibly start earlier than shown to ensure filling of the reservoir by mid 2012. It is also a lengthy process where typically one of the two diversion culverts is closed initially and fitted with a concrete plug followed by plugging the second culvert, which has to be done behind stop-logs. Time has to be allowed for casting the plugs, cooling and grouting them. This process might take as much as 3 months per plug.

The last activity would be the pre-excavation of the plunge pool downstream of the dam and spillway structure. The excavation would be carried out in dry conditions during the filling of the reservoir, for a period of some 3 months, and should start immediately after diversion closure.

4.2 Waterway The open-air work at the intake (earth and rock excavation) is estimated to be performed during a period of some 8 months. The time required for casting of the structure is estimated to be in the order of 1 year.


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Open-air work at the portals of the adits will be carried out during a three-month period. The time required for the excavation of the adit tunnels (Adit 1 and Adit 2 on the headrace tunnel and Adit 3 on the lower part of the penstock) is estimated to be 2 months assuming a rate of 20 m/week. The tunneling proper of the headrace tunnel can start 5 months after the start of the open excavation from Adit 1 and after 4.25 month from Adit 2. The tunneling rate in the headrace tunnel proper is estimated to be in the order of 20-30 m/week, which means that the headrace tunnel can be completed after some 15 months.

The excavation of the surge shaft down to El. 222.5 m is estimated to be carried out during a 9-month period. Raise-boring the central hole with a length in the order of 68 m, from the tunnel up to El. 222.5 m, is estimated to be possible to perform during a 4-week period. The excavation is then carried out by stoping the blasted rock, through the central hole. The walls of the shaft are successively supported as the excavation proceeds. The stoping of the shaft is estimated to be possible to perform within a 4-month period.

The horizontal parts of the penstock are considered possible to excavate at a rate of 20 m/week which means that the excavation can be completed in a period of 1 month if excavation is carried out on two fronts in the lower part. The vertical part will preferably be excavated using raise-boring. The required time to excavate and support this part might be in the order of 3 months. The installation of lining and steel lining of the penstock might require a 6-month period.

The construction schedule in Figure 2 assumes concrete lining of the headrace tunnel in accordance with normal Vietnamese practice. As, however, mentioned in Section 3.4.2 an unlined tunnel is recommended that will shorten the construction time of the tunnel by over one year.

4.3 Power Station and Equipment Installation The construction schedule in the Feasibility Study is divided into thee parts; hydro-mechanical equipment, electromechanical equipment and electrical equipment at the 220 kV switchyard. The first two are consecutive and estimated at 5 and 12 months, respectively. That is deemed as reasonable assumptions.

The construction time of the 220 kV switchyard equipment is estimated at 7 months and this is also a reasonable assumption. This construction is also to a large extent independent of the powerhouse construction and is not on the critical line.

4.4 Transmission The construction time of the 220 kV transmission line is estimated at 5 months and that is deemed reasonable. Acquiring right-of-way is usually critical for building of large overhead transmission lines, but there should be ample time to do all the necessary preparations as the transmission line should not come on the critical line.

4.5 Initial Filling of Song Bung 4 Reservoir With the current construction schedule, see Figure 2, commissioning of the first unit is assumed at the beginning of July 2012 when the reservoir should be filled to the Full Supply Level of +222.5 m. Filling of the reservoir should be carried out during the last dry season for better control of the rate of filling and for excavation of the plunge pool in dry conditions.

Based on 28 years of historical data (1977-2004), filling of the reservoir up to +222.5 m by July can be achieved for 18 years (64 %) if the filling commences at the beginning of December and a compensation flow of 7.2 m3/s (10% of mean annual flow) is by-passed the dam. For 8 of the remaining years the reservoir would be almost filled up to +222.5 m, but for the two driest year on record, 1982 and 1989, the reservoir would only be filled up to some


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+206 m and +170 m, respectively, at the beginning of July.

For the year 1982, the reservoir would be filled up to +222.5 m in time for commissioning of the second unit at the beginning of October, while for a dry year like 1989 the reservoir would not be filled at all during the year.

In spite of the small probability of not reaching the Full Supply Level before the commissioning of the two units, it is tentatively recommended that filling of the reservoir should commence at the beginning of December in the last dry season.

A plan for filling of the reservoir needs to be studied in the Technical Design Phase to amongst others take the following into account:

• Provision of water downstream of the dam during filling.

• Controlled raise of the water level, i.e. filling during the dry season if possible.

• Construction of the plunge pool in dry conditions.

For provision of compensation flow downstream of the dam during impounding of the reservoir, a valve could be installed in the first plug of the diversion culverts and connected downstream of the plunge pool excavation with pipes.

4.6 Overall Tentative Construction Schedule The tentative construction schedule for Song Bung 4 Hydropower Project shown on Figure 2 gives a total construction period of 3.75 years after commencement of the main works. The critical path of the construction will essentially be the following:

• Construction of the power station and erection of the electromechanical equipment.

• Completion of the dam and spillway structure, except for the spillway gates, by the end of 2011 to allow filling of the reservoir during the last dry season.

• Excavation of the plunge pool in dry conditions.

5 Cost Estimate

5.1 Review of Cost Estimate in Feasibility Study

5.1.1 Preparatory Works

5.1.1.1 Access Roads Unit rates for access roads varies to a large extend depending on the local conditions, such as topography, geological conditions, need for bridges, etc. In the Feasibility Study a common unit rate of 8 billion VND/km was assumed, and considering the conditions in the Project Area, this unit rate seems realistic.

This item should also include the relocation of National Road No. 14 D that was estimated at 9.30 million USD in the Feasibility Study

5.1.1.2 Site Preparations This cost item includes leveling of sites, electrical and mechanical works for the site, communications for the site, temporary houses for EVN, etc, and the cost given in the Feasibility Study of 5.10 million USD seems realistic.


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5.1.2 Civil Works

A comparison with the main unit rates agreed in the construction contract for the nearby located Song Tranh 2 Hydropower Project, signed in August 2005, reveals that the unit rates adopted in the Feasibility Study on Song Bung 4 Hydropower Project, with a similar layout, are reasonable as seen in the table below: Cost Item Unit Rate

FS, USD Unit Rate

Song Tranh 2, USD Difference

USD Structural Concrete, Open-air, M200 49.2-56.6/m3 51,8/m3 -2.6-4.8/m3 Structural Concrete, Open-air, M250 52.4-61.6/m3 55.2/m3 -2.8-6.4/m3 Structural Concrete, Open-air, M300 66.6/m3 64.7/m3 1.9/m3 RCC 35.7/m3 34.1/m3 1.6/m3 Tunnel Lining 85.6-86.1/m3 85.0/m3 0.6-1.1/m3 Reinforcement, Open-air 627/ton 650/ton -23/ton Reinforcement Underground, Tunnel 763/ton 845/ton -82/ton Steel Ribs 837/ton 950/ton -113/ton Tunnel Excavation, Large Tunnel 27.1/m3 29,3/m3 -2.2/m3 Tunnel Excavation, Small Tunnel 37.3/m3 40/m3 -2.7/m3

In the cost estimate for civil works for Song Bung 4 Hydropower Project it is recommended that the unit rates applied in the Feasibility Study are maintained apart for the following items:

• Reinforcement underground to be increased to 850 USD/ton, in accordance with the table above.

• Steel ribs to be increased to 950 USD/ton, in accordance with the table above.

• Tunnel excavation for large tunnels to be increased to 30 USD/m3, in accordance with the table above.

• Tunnel excavation for small tunnels to be increased to 40 USD/m3, in accordance with the table above.

• Raise Boring is increased to 2,000 USD/m, in accordance with Section 3.2.4.

• Ankerbolts is increased to 12.5 USD/m, in accordance with Section 3.2.4.

In the cost estimate for civil works, the following items are included:

• Temporary works by the civil works contractors, such as services roads and auxiliary works (camps. workshops, storages, etc.), and the costs given in the Feasibility Study have been adopted.

• Operation building located close to the power house, and other works in the power house.

5.1.3 Mechanical and Electrical Works

A review of the estimated costs for the mechanical and electrical works have been made in this PPTA based on various cost data and assuming international competitive bidding, with the following costs compared to the Feasibility Study: Cost Item PPTA MUSD FS MUSD Hydro-mechanical Equipment 15.08 7.36 Power Station Equipment 32.16 32.68

As seen in the table above, the estimated costs for the power station equipment (turbines, generators, transformers, etc.) is nearly identical, but the estimated costs for the hydro-


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mechanical equipment (gates, penstock, etc.) are considerable lower in the Feasibility Study.

The estimated cost for the power station equipment given in the Feasibility Study is maintained. The estimated cost for the hydro-mechanical equipment given in the Feasibility Study is also recommended to be maintained, as most of this equipment can be manufactured in Vietnam while the review assumed foreign suppliers and international competitive bidding.

5.1.4 Transmission

The costs for Transmission given in the Feasibility Study is recommended to be used as these costs are site specific and therefore realistic.

5.1.5 Engineering and Administration

The costs for Engineering and Administration of 11.38 million USD given in the Feasibility Study is recommended to be used, as these costs are specified in detail and therefore realistic, but excluding the costs for supervision consultant that is included in Section 5.4, and including a contingency of 10%, giving a total of 12.52 million USD.

5.2 Environmental Management Costs The Environmental Management Costs for Song Bung 4 Hydropower Project is estimated at 0.62 million USD, including 10% contingencies, according to the Environmental Impact Assessment (EIA) Report.

5.3 Resettlement and Social Mitigation Costs The Resettlement and Social Mitigation Costs for Song Bung 4 Hydropower Project are estimated at 19.83 million USD, including 10% contingencies but excluding Independent Monitoring Services included in Section 5.4, according to the Resettlement and Ethnic Minority Development Plan (REMDP) Report.

5.4 Implementation Support As mentioned in Section 6.1.3.3, it is intended that international and domestic consultants will be recruited to assist in the implementation of the Project for the following services with an estimated cost of 5.10 million USD, including 10% contingencies:

• Implementation Supervision Consultant, with an estimated cost of 4.95 million USD.

• Independent Monitoring Services, with an estimated budget of 150,000 USD.

5.5 Cost Structuring In the Feasibility Study a flat rate of 11% is added for contingencies of the total of all cost items, but it is recommended that the following percentages are used for contingencies and miscellaneous costs:

Project Component Sub-component Contingencies, % Miscellaneous, % Preparatory Works 10 Civil Works 10 Preliminary Works 10 Dam (RCC) 5 Spillway 5 Waterway (Underground) 10 Power Station (Surface) 15


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Switchyard 5 Mechanical Equipment 5 Electrical Equipment 5 Transmission 7 Engineering and Administration

10

Environmental Management Costs

10

Resettlement and Social Mitigation Costs

10

Implementation Support

10

5.6 Tentative Total Investment Cost A tentative cost estimate for Song Bung 4 Hydropower Project is given in Table 2 based on the estimates outlined above. The total investment cost is estimated at 206.8 million USD including physical contingencies, but excluding price contingencies, taxes and financial costs, as summarized in the table below: Estimated Investment Cost in Million USD

Cost Item Cost in MUSD Preparatory Works 23.8 Civil Works 95.6 Electrical and Mechanical Works 42.0 Transmission 7.3 Environmental and Social Mitigation Costs 20.5 Engineering and Administration 12.5 Implementation Support 5.1 Total Investment Cost 206.8

The estimated total investment costs given in the table above do not include for the following recommended or commented technical issues given in Chapter 3: Part Sub-part Item Estimated Cost MUSDDam RCC Redesign -5.8 Cofferdam Reduced Level -0.2 Spillway Chute Dividing Walls +2.5 Plunge Pool Deeper Level +1.5 Plunge Pool Support of banks +0.7 Headrace Tunnel Rock Support Unlined -6.5 Surge Arrangements

Rock Support Unlined -0.4

Penstock Diameter Increased +0.6 Length Reduced steel-lining and

reduced concrete lining -1.4

Powerhouse (Surface)

Overall Dimensions and Rearrangements

-0.5

Total -9.5


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The recommended omission of the gantry crane at the spillway is not included in the table above, as it seems not to have been included in the cost estimates in Volume 7 of the Feasibility Study.

A possible cost saving by an underground powerhouse has not been accounted for, as this alternative will be investigated by PECC3 in the Technical Design Phase.

The total cost of Song Bung 4 Hydropower Project, including price contingencies, taxes and financial charges, are accounted for in Chapter 8.

6 Implementation and Procurement

6.1 Project Implementation

6.1.1 Implementation Schedule

Loan consideration by the ADB Board is scheduled for December 2006. Preconstruction activities, such as detailed design, preparation of bidding documents, tendering and awarding of supply and construction contracts should be completed by December 2008. Preliminary construction activities are planed to be started in January 2008. Construction of the main components of the Project will commence at the beginning of 2009 and take 3.5 years until commissioning of the first unit and another 3 months for commissioning of the second unit for commercial operation by mid 2012.

An Implementation Schedule for Song Bung 4 Hydropower Project has been prepared, based on current information, as shown in Figure 3 with the following milestones:

• Approval of the Feasibility Study by November 2006.

• Approval of the loan by ADB’s Board by mid-December 2006.

• Preparation and approval of the Technical Design and Bidding Documents by March 2008.

• Recruitment of Implementation Supervision Consultant by February 2008.

• Signing of contracts for civil works by December 2008.

• Signing of contracts for electromechanical works by December 2008.

• Commencement of main construction works by January 2009.

• Commissioning of the Project by mid 2012.

The activity on the critical path is the approval of the Technical Design and Bidding Documents, and any delay would also delay the completion of the Project. It should be noted that commencement of the main works in January have some advantageous as follows:

• The works will start at the onset of the dry season when excavation works will be prominent.

• The filling of the reservoir can be scheduled for the last dry season for better control of the rate of filling, and for excavation of the plunge pool in dry conditions.


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6.1.2 Implementation Agency

6.1.2.1 General The Implementing Agency for the proposed ADB loan for Song Bung 4 Hydropower Project will be Hydropower Project Management Board No. 3 (ATD3) in Da Nang, a project management unit within EVN responsible for development of hydropower projects in Central Vietnam. ATD3 reports to EVN’s Vice President for Generation Construction.

ATD3 is authorized by EVN to carry out project management of new hydropower plants in Central Vietnam from the initial stages of river resource planning, pre-investment work, and construction until the plant becomes operational.

Since its inception in 1995, ATD3 has managed several projects funded by international donors, including SIDA and JBIC. In addition it has managed other investment projects funded by EVN. Similar project management boards manage other investments in generation, transmission and distribution projects in other parts of Vietnam.

The following is an organizational chart of ATD3:

Director Tran Van Hai

Department of Environment & Resettlement

Deputy Director Tran Ngoc An

Technical Department

Deputy Director Le Duong Thuan

Department of Investments in HP (Vu Gia Thu Bon

rivers) Deputy Director Nguyen Van Le

Department of Investments in HP

(Song Ba) Deputy Director Dang Van Tuan

Project Department Nguyen Van

Chuang

Planning & Economic

Department Trinh The Dung

Organisation-administrative

Department Vu Duc Toan

Finance & Accounting

Department Le Nhu Thiep

Materials & Equipment Department

Nguyen Van Son

ATD3 currently has around 130 employees, with specialists in engineering, environmental, resettlement, economic and finance, of which some 100 have management experience from previous hydropower projects in Vietnam. Presently, ATD3 is managing four hydropower projects under construction: A Vuong, Song Ba Ha, Song Tranh 2 and An Khe-Ka Nak.

A brief description of the various departments within ATD3, relevant to the implementation of Song Bung 4 Hydropower Project, is given below apart from the Finance and Accounting Department that is given in Section 8.6.

6.1.2.2 Environmental and Resettlement Department The Environment and Resettlement Department act as an advisory body to the Director of ATD3, and the compensation committees, for management of compensation, resettlement and environmental issues of the hydropower projects under management of ATD3. Other responsibilities include coordination with local government agencies in related issues and handing over possession of sites to contractors.

The department has a total staff of 35 divided into the following specialties:


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Specialty Number of Staff Hydraulic Construction Engineers 7 Road Construction Engineers 6 Civil Engineers 4 Electrical Engineers 2 Mechanical Engineer 1 Economist 1 Surveyors 2 Electrician 1 Accountant 1 Construction Technicians 2 Unskilled 5

Mr. Le Trung Thanh, who is assisted by two deputy managers, heads the department. The qualification of the senior staff of the department is summarized below: Manager Deputy Manager Deputy Manager Name Le Trung Thanh Nguyen Minh Chien Nhuyen Binh Year of Birth 1959 1969 1977 Education Bachelor in Business

Administration Bachelor in Hydraulic

Construction Bachelor in Hydraulic

Construction Years in Present Position

7 4 0

Previous Work Deputy Manager of General Affairs for Song Hinh

Supervisor Expert in the Department

6.1.2.3 Technical Department The Technical Department is responsible for the management of technical activities related to planning, investment preparation, construction and commissioning of Song Ba Ha and An Khe-Ka Nak hydropower projects in Ba River Basin.

The department has a total staff of 29 divided into the following specialties: Specialty Number of Staff Hydraulic Construction Engineers 10 Hydrologists 2 Civil Engineers 3 Road Engineers 2 Geologist 1 Power Economist 1 Mechanical Engineer 1 Surveyors 1 Electrician 1 Accountant 1 Unskilled 2

The department is headed by Mr. Vo Van Tri, who is assisted by three deputy managers. The qualification of the senior staff of the department is summarized below: Manager Deputy Manager Deputy

Manager Deputy Manager

Name Vo Van Tri To Hoang Nam Nguyen Minh Van

Nhuyen Dinh Vu

Year of Birth 1958 1960 1965 1970 Education Bachelor in

Hydrology Bachelor in Electronics

Bachelor in Mining

Bachelor Electricity


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Years in Present Position

3 3 0 0

Previous Work Manager of Technical Dept. for

Song Hinh

Deputy Manager of Technical Dept. for

Song Hinh

Expert Technical

Department

Expert in the Department

6.1.2.4 Project Department The Project Department is responsible for the management of technical activities related to planning, investment preparation, construction and commissioning of A Vuong, Song Tranh 2, Song Bung 2, Song Bung 4, Dak Mi 1 and Dak Mi 4 hydropower projects.

The department has a total staff of 45 divided into the following specialties: Specialty Number of Staff Hydraulic Construction Engineers 15 Hydrologists 10 Civil Engineers 5 Road Engineers 1 Geologist 1 Electrical Engineer 2 Mechanical Engineer 1 Economist 1 Surveyors 1 Planner 1 Unskilled 3

The department is headed by Mr. Nguyen Van Chuong, who is assisted by three deputy managers. The qualification of the senior staff of the department is summarized below: Manager Deputy Manager Deputy

Manager Deputy Manager

Name Nguyen Van Chuong

Nguyen Xuan Binh Vuong Thanh Chuong

Tran Dinh Phi

Year of Birth 1964 1973 1970 1978 Education Bachelor in

Hydraulics Bachelor in Hydrology

Bachelor in Mechanics

Bachelor in Hydraulics

Years in Present Position

2 0 0 0

Previous Work Deputy Manager of Technical Dept.

Expert of Project Department

Expert of Project

Department

Expert of Project Department

6.1.2.5 Materials and Equipment Department The Materials and Equipment Department is responsible for management of materials and equipment, preparation of bidding documents, negotiations, signing of contracts, follow-up of supply and installation schedules, and follow-up of payments for contracts.

The department has a total staff of 18 divided into the following specialties: Specialty Number of Staff Electrical Engineers 7 Translators 7 Economist 1 Administration 1


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Mr. Nguyen Van Son, who is assisted by one deputy manager, heads the department. The qualification of the senior staff of the department is summarized below: Manager Deputy Manager Name Nguyen Van Son Nguyen Van Lan Year of Birth 1955 1972 Education Bachelor in Mechanics Bachelor in Electricity Years in Present Position

1 0

Previous Work Deputy Manager of Planning Department

Expert in the department

6.1.3 Project Implementation

6.1.3.1 Executing and Implementing Agencies EVN will be the Executing Agency (EA) responsible for the overall implementation of the Project. The Hydropower Project Management Board No. 3 (ATD3) will be the Implementing Agency (IA). ATD3 will coordinate and monitor all construction activities of Song Bung 4 Hydropower Project. A Project Director, directly reporting to one of the vice-presidents of EVN, will be responsible for overall project management, approval of contracts, and payments. A Project Manager from ATD3 will be responsible for physical implementation activities on a day-to-day basis and for the preparation of progress reports, supported by staff from the Finance and Accounting, Project, Materials and Equipment, and Environmental and Resettlement departments.

The organization chart for management of the Project is found in Figure 4.

6.1.3.2 Implementation of Resettlement The Environment and Resettlement Department within ATD3 will facilitate land acquisition as well as social and environmental mitigation measures, and ensure that local concerns are adequately addressed. The following authorities will organize the implementation of the compensation and resettlement programs for the Project:

• At provincial level the Directorate Committee headed by the Deputy Chairman of the PPC.

• At district level the Compensation, Support and Resettlement Council headed by the Deputy Chairman of the DPC, which also includes representatives from ATD3.

• The Implementation Team with representatives from the villages, communes, districts and ATD3, assisted by (i) Finance Officer, (ii) Land Administration Officer, (iii) Ethnic Minority representative, (iv) Irrigation Engineer, (v) Agriculture Engineer, and (vi) representatives from Women’s Union, Youth Union and APs.

6.1.3.3 Implementation Support General

To assist in the implementation of the Project, it is intended that international and domestic consultants will be recruited in accordance with ADB’s Guidelines on the Use of Consultants to provide the following services:

• Implementation Supervision Consultant, to work under ATD3’s Project Department and being responsible for the daily supervision of civil works and erection of the equipment as the Engineer, as well as monitoring the environmental protection measures during construction.


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• Independent Monitoring Services, to monitor the conduct, progress and outcome of the relocation and livelihood restoration of people affected by the Project

Budgets

The budget for the Implementation Supervision Consultant is estimated at 4.95 million USD with the following cost breakdown: Item No of Staff Person-months Average Rate

US$/Month Cost US$

Fee for International Consultants 9 121 22,562 2,730,000 Fee for Domestic Consultants 39 1,129 1,190 1,343,500 Reimbursables 432,600 Contingencies 443,900 TOTAL 4,950,000

The budget for the Independent Monitoring Services is estimated at 150,000 USD with the following cost breakdown: Item No of Staff Person-months Average Rate

US$/Month Cost US$

Fee for Domestic Consultants

2 126 733 92,400

Reimbursables 42,700 Contingencies 14,900 TOTAL 150,000

6.2 Procurement Plan As mentioned in Chapter 8, the following parts of Song Bung 4 Hydropower Project are anticipated to be financed by Asian Development Bank (ADB) following discussions with EVN:

• Preliminary civil works (river diversion, adit tunnels, etc.).

• Civil works construction of dam structure, including monitoring equipment.

• Civil works construction of spillway.

• Civil works construction of water conveyance system (intake, headrace tunnel, surge tank, and penstock), including steel lining of the penstock.

• Civil works construction of power station (powerhouse, tailrace canal and switchyard).

• Electromechanical equipment for the power station (turbines, generators, transformers, control equipment, switchyard equipment, etc.).

• Hydro-mechanical equipment (gates, etc.), excluding steel lining of the penstock.

• Transmission Line.

• Relocation of Highway 14D.

• Implementation Supervision Consultant.

• Independent Monitoring Services.

The remaining parts of the Project, such as access roads, environmental and social costs, and engineering and administration costs, are anticipated to be financed by EVN.


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The parts of the Project to be financed by ADB are anticipated to be divided into the following contract packages: Contact Package

Contract Description Estimated Cost Million US$

Procurement Method

Package I Lot I.01

Civil works construction for Preliminary Works, Dam, Spillway, and Monitoring Equipment for the Dam

50.39 ICB Works

Package I Lot I.02

Civil works construction for Intake, Headrace Tunnel (including Adits), Surge Tank, Penstock (including steel-lining of Penstock), and Power Station (including Tailrace Canal and Switchyard)

38.27 ICB Works

Package II Electromechanical Equipment 32.68 ICB Goods Package III Hydro-mechanical Equipment 5.64 ICB Goods Package IV Transmission Line 6.81 ICB Package V Relocation of Highway 14D 9.30 ICB Works Package VI Lot IV.01

Implementation Supervision Consultant 4.5 QCBS

Package VI Lot IV.02

Independent Monitoring Services 0.14 CQS

Note: Price and physical contingencies, taxes and financing charges are not included, see Chapter 8.

The civil works contracts will be unit rate type of contracts, and the general conditions will be according to “Conditions of Contract for Construction for Buildings and Engineering Works Designed by the Employer, Multilateral Development Bank Harmonized Edition 2005” prepared by FIDIC (FIDIC MBD version 2005).

7 Economic Analysis

7.1 General The Economic Analysis of Song Bung 4 Hydropower Project has been prepared by ADB Staff, and Sections 7.2 to 7.4 has partly been based on data presented in the First Interim Report.

7.2 Macroeconomic and Sector Context

7.2.1 Macroeconomics

By consistently pursuing a wide range of reform policies, especially reform of state-owned enterprises (SOE), by encouraging domestic as well as foreign investment, and by expanding the private sector, and aided by a stable political environment Vietnam continued to achieve remarkable economic growth during the last 5 years. The five-year average GDP growth reached 7.3% per annum for the period 2000-2005, with the growth of the following year higher than the preceding one. In 2005, GDP growth was 8.5%. Industry and services together accounted for nearly 80% of GDP and was the main driver of economic growth. These two sectors recorded 10.3% and 7.5% growth, respectively, while agricultural sector expanded at 3.3%. The average inflation for 2005 was around 8%, slightly higher than in 2004. Broad money supply and credit growth have recorded 28% and 36%, respectively, driven by the broad based economic growth. The fiscal deficit was maintained at 3.8%, being below the government’s target of 5%. The fiscal position is expected to remain expansionary, but manageable, to cover the investments in infrastructure and adjustment cost of structural reforms. The average economic growth for the period 2006 – 2010 is expected to be around 8.5% (5-year average) with industry and services to grow at the rates of 11% and 8.0%,


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respectively. The key development challenges of Vietnam are to sustain the high economic growth and reduce the inequality between urban and rural areas through targeted poverty reduction. To increase the competitiveness and maintain high GDP growth of 8.5%, Vietnam needs to maintain an investment level of more than 35% of GDP for a period of time mainly to develop necessary physical infrastructure, amongst them, infrastructure in the energy and power sector.

7.2.2 Power Sector Issues and Challenges

The ADB Energy Roadmap for Vietnam, which constitutes a part of the Country Strategy and Program for the period 2006-2010, identifies key issues and challenges of the power sector. These issues are briefly summarized in paragraphs that follow.

Demand for electricity is projected to grow at a very high rate (e.g. 15%/year till 2010 and 11 %/year till 2015). Meeting this rapidly growing demand in order to ensure uninterrupted supply for economic production, as well as for satisfying the population needs, is the most challenging task facing the power sector in Vietnam. To meet this challenge requires mobilizing adequate capital for investment in generation, transmission and distribution; implementing an appropriate tariff structure so as to stimulate rational consumption pattern; reforming the sector to facilitate competition; creating appropriate regulatory mechanism to manage the sector under a more competitive environment; managing environmental impacts while ensuring financial viability of the utility.

Maintain adequate investments to meet the rapid growth in demand for electricity is a formidable task. According to the draft 6th Master Plan1 the total investment requirement of the power sector for the period 2006-2010 is estimated to be 24.2 billion US$ consisting of 17.1 billion US$ for generation and 7.1 billion US$ for transmission and distribution network. Electricity of Vietnam (EVN) is expected to invest about 16 billion US$ and the remaining will be invested by non-EVN sources. A similar level of investment is required for the period 2011-2015. It is estimated that EVN's internal cash generation during the period 2006-2010 will reach 8 billion US$, thus EVN’s net borrowings are expected to be 8 billion US$ in order to make up the total investment requirement of 16 billion US$ during the period 2006-2010. In spite of the ambitious plans to divest most of EVN’s owned power plants and distribution assets, the bulk of new investments will be financed through borrowings on commercial terms. The availability of concessionary ODA sources and domestic funds through the government financed Development Assistance Fund (DAF) is limited, and EVN is increasingly resorting to borrow on commercial terms from Export Credit Agencies and from ADB on OCR terms.

The development of a competitive power market as envisaged in the Electricity Law (effective July 2005) is to develop a power market on the principles of transparency and competition to achieve economic efficiency, to attract investments from both state and non–state sectors and to ensure the legitimate rights of the consumers and the investors. The Law states that the state monopoly would be limited to power transmission, national load dispatch and strategically important large power plants. This leaves the power distribution and non-strategic power generation to potential private sector investors. The Law specifically encourages investments from foreign private investors, and joint ventures between foreign investors and domestic enterprises. Subsequent to the enactment of the Electricity Law, the Electricity Regulatory Authority (ERA) for the power sector has been established.

As the first step toward a competitive power market, EVN will be converted to a holding company. Most of EVN owned power plants will be equitized. However, the three multipurpose hydropower projects and the transmission network (220 kV and 500 kV) will be

1 Draft Master Plan VI has been completed in December 2005. It is now awaiting comments from line ministries and to be approved by the Government before June 2006.


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retained within EVN. This equitization of key subsidiaries of EVN (i.e. power plants and provincial power distribution units) started in 2005 and is expected to be completed by 2008. EVN’s stakes in the equitized provincial distribution utilities would be held through the eight existing regional Power Companies. EVN’s cooperate restructuring program would be completed by 2008, before the establishment of wholesale competitive power market in 2009.

For a long period of time the cross sector average electricity tariff stood at 0.052 US$/kWh, significantly below the long-run marginal cost of supply (LRMC was estimated to be 7.5 US cents/ kWh). EVN has planned to raise the tariff to the level that sustains the investment in system capacity, but the government requires that tariff increase should be gradual to avoid general inflation. In 2006, an 8.8% tariff increase had been approved, bringing the cross sector average tariff to 0.057 US$/kWh.

In general the power sector in Vietnam is developing strongly. There are issues and challenges which are being addressed by the Government, MOI and EVN. The Song Bung 4 Hydropower Project helps to partly meet the challenges by adding new generating capacity to meet the national demand.

In parallel with expanding the supply system, the Government is pushing ahead the national program on energy/electricity conservation. Since early 1990s, several projects had been carried out with assistance from bilateral as well multilateral cooperation. Energy conservation and demand side management are among the key components of the national programs titled "Development of national strategies and policies for sustainable energy future" and "Comprehensive program on energy efficiency and conservation in Vietnam" being implemented by the Ministry of Industry and Ministry of Science and Technology. The first phase of the World Bank sponsored demand side management project was completed in 2002. The project assessed the potential of electricity conservation from the end-use side, focusing on the household consumption. A survey of household electricity consumption was carried out, which identified the major end uses with significant potential for conservation, e.g. lighting (19.2% of the total household electricity consumption); electric rice cooker (18.1%); refrigerators (15.5%), etc. Examples of international cooperation in the area of demand side management include the UNDP/GEF project on efficient public lighting, EC-ASEAN sponsored project on cogeneration, and WB DSM project second phase. All of these aims to help reduce peak demand and lessen the pressure on the supply side investment.

Renewable electricity is also given due attention, even though it will take time for renewable electricity to gain a considerable share in the generation mix. The development of renewable electricity is more advantageous in the remote areas, such as mountainous districts or islands. Mini and micro hydropower is being utilized intensively in the northern and central mountains. A couple of wind farms are in operation on Bach Long Vy Island, providing round-the-clock electricity for the population on the island. In the future the government plan to increase the share of renewable energies in the country capacity mix.

7.3 Demand Analysis Vietnam had sustained a high growth of 14.2% in electricity demand during the period 1990 – 2003 and during the recent times (i.e. 2000 – 2005) the growth rate has further increased to 15.2%. Electricity consumption in 2005 was 44.96 TWh, being 13.3% higher than 2004.

Electricity demand in Vietnam will continue to grow with this high rate to support economic expansion and improvement of the standard of living. Under the preparation of Mater Plan VI, a new projection of electricity demand for the period 2006-2025 has been conducted. The Institute of Energy (IOE), a system planning organization of EVN, has been entrusted with the task of projecting country demand and system expansion planning. IOE prepares country master plan for power sector development every five years.


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IOE has used a combination of projection methods in order to prepare the load/demand forecast. Within the short-term future (e.g. up to 5 year) demand and load projections were estimated based on the so-called direct method. This direct estimation is based on surveys of all registered new demand of committed or planned expansion, or newly created, industrial and economic zones together with major urban centers collected on province-by-province basis. The provincial demands were estimated first, and then the regional and then country demands were carried out by adding up the provincial demands. Such direct survey and demand estimation is considered to be appropriate as it closely follow the economic development plans at the provincial level, which are prepared not only for the purpose of electricity demand projection, but taking into account multi-facets of developments. For the longer-term future, i.e. 10 years and beyond, provincial economic development plans are less definitive, so IOE uses a regression analysis. The regression analysis takes into consideration elasticity factors, tendency of electricity intensities of major consumers and past statistic data. IOE has carefully analyzed the statistical data and also elasticity coefficients. Future electricity demand is projected for three regions (e.g. northern region, central region and southern region) and combined to get a country projection. This combination of methods for demand projections has been used in the past for all master plans. The results of demand projections have been reviewed and commented on by various government agencies, and normally approved by the Prime Minister as part of an overall Master Plan. The table below contains main indicators of the demand projection resulted from Master Plan VI. A full table of demand forecast by regions is given in Table 3. Main Indicators, of the IOE's Demand Forecast 2005-2025

Year 2005 2010 2015 2020 2025 Annual demand, GWh 44,96 97,11 164,96 257,26 381,16 5-year growth rate, % 16.3% 11.2% 9.3% 8.2% Per capita consumption, kWh 549 1106 1774 2629 3703 T&D losses and own-use, % 14.7 13.8 13.2 12.5 11.7 Peak load, MW 9512 19553 32196 48642 71416

Source: IOE 2005, Master Plan VI (final draft) Hanoi. According to Mater Plan VI in the table above, the electricity demand will grow at 16.3% per annum from now until 2010 and 11.2 % thereafter until 2015. The demand growth is driven by rapid growth in industrial and commercial sectors, increase in electrification from less than 40% in 1990 to over 88 % in 2005, urbanization and increased living standards with domestic demand growing at 19%. The demand for electricity and the corresponding peak load are expected to reach 97.11 TWh and 19,553 MW in 2010, and 165 TWh and 32,200 MW in 2015, compared to 39.7 TWh and 8,400 MW in 2004. The system losses would be reduced from 14.7% in 2004 to 13.8% in 2010 and 12.3 % in 2015, and the load factor will increase to 68.4% in 2010 and 69.1% in 2015 from 65.7% in 2004.

Over time, demand projections are by necessity adjusted to be in harmony with the economic development scenarios. The graph in Figure 7-1 below demonstrates the relative accuracy of the electricity demand projection made by IOE as compared with the actual levels of energy consumption.


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Figure 7-1 Comparison of Demand Projection by IOE with Actual Historical Data

0

10,000

20,000

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40,000

50,000

60,000

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

GW

h MP VIMP VActual

Source: IOE 2005, Master Plan VI (final draft) Hanoi. The graph clearly shows that the IOE projection is in good matching with the actual data. Master Plan IV accurately predicted the demand for 1995-1996. Due to the impacts of the Asian financial crisis, the actual electricity demand in Vietnam is lower then the projection of Master Plan IV as seen by the gap between actual demands and projected demands for the period 1998- 2000. Master Plan V took into consideration the impacts of the financial crisis which predicted slightly lower then actual demand (strong recovery). Subsequent update of Master Plan V closely followed the actual demand (e.g. for the period 2004-2005). Figure 7-1 above thus shows that the IOE projection is in good matching with the actual data.

The demand projection in Master Plan VI takes into consideration evolution of demand load factor (LF) by the northern, central and southern regions. Over the years, load factors in all three regions have been improving from 0.61 in 1996 to 0.64 in 2004. The southern region has the highest LF, followed by the central region and then the northern region. In 2004, these LF are 67.8%, 58.5% and 57.2% for the southern, central and northern regions, respectively. The higher LF for the southern region is induced by the higher share of electricity consumption for industrial production. Such share was more than 50% for the southern region, while it was below 40% for the northern region. A typical daily load curve also experiences a positive shift: as the difference between maximum load and minimum load has been reduced. In addition the daily peak (at around 11 am) is getting closer to the evening peak (at 19 – 20 pm) reflecting the fact that the electricity consumption in industrial and commercial sectors play more and more dominant role.

Regarding the structure of the demand, before 2004 households represented the largest consumer followed by industry, commercial and then agricultural sectors. Recently, the industrial sector consumption surpassed that of the household and become the largest consumer. In 2005, the shares of the industry, household, commercial and agricultural sectors were 45.8%, 44.2%, 8.6% and 1.4%, respectively.

During the period 1996-2004 the growth rate of electricity consumption of the industry was also remarkable at 16.3% per year. Even though the share of the commercial sector remains small, its growth rate was as high as 16.5% per year during 2000-2005. Compared to the industrial and commercial sectors, household growth rate of electricity consumption was somewhat lower, however, it was more than 15% per year for the period 2000-2005.


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7.4 Least Cost System Expansion Plan of the Vietnam Power Sector

7.4.1 General

Every five year, IOE prepares a Master Plan, which looks into all aspects of the power system development. A Master Plan normally covers demand forecast, least cost expansion plan, transmission expansion plan, fuel supply assessment, rural electrification program, investment requirement and others. Master Plan VI also includes regional interconnection and power trade with neighboring countries, environmental aspect of system development, and organizational reform of the power sector. Master Plan VI plans for the development between 2006 and 2015 with outlook to 2025. Thus the horizon of the least cost expansion planning is to 2025.

7.4.2 Existing Generating System

At present the Vietnam electricity system is a well developed unified system stretching over the country with the backbone being a 1,700 km long high voltage (500 kV) transmission line connecting all load and generation centers between northern and southern parts of the country. The northern region has abundant coal resources, whereas the southern region is endowed with off-shore gas for electricity generation. Hydropower resources are available throughout the country with the most concentrated potential on Da River in the North. The Red River delta and Mekong River delta are the concentrated demand centers, both growing rapidly in recent years.

By the end of 2005, the total installed generating capacity of the power system in Vietnam amounted to 11,386 MW. The breakdown of this capacity by fuel type is given in the table below. During the last few years, there was a noticeable shift from dominant role of hydro-based capacity to gas-based capacity. The structure of the generating capacity will continue to evolve, as coal capacity will be added significantly during the next five years. Similarly, with Son La Hydropower Project coming online, the share of hydropower will be significant again for a period of time. Installed Capacity in MW and their Share, End of 2005

Type of Capacity EVN Non-EVN Total Share Hydro 4069 150 4219 37.1% Coal 1245 210 1455 12.8% Oil 200 389 589 5.2% Gas 3037 1841 4878 42.8% Diesel 245 245 2.2% Total 8796 2590 11386 100%

The existing capacity comprises of generating capacity of EVN power plants, and those outside EVN (called non-EVN). At present, non-EVN capacity already accounts for 22.7 % of the total system capacity (see the table below). Non-EVN power plants in turn consist of IPP, BOT and power plants owned by other enterprises in Viet Nam (e.g. VinaCoal). Details of the existing generating capacity are given in Table 4.

7.4.3 Options for Expansion of the Generating System

The options for future development of the power system, without looking at other system constraints, and investment requirements, are derived from the following considerations:

• Availability of domestic fuel supply.

• Availability of domestic renewable energy resources.


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• Possibility of importing fuels.

• Power trade (import/export) with neighboring countries.

Vietnam has considerable domestic energy resources for power generation, including hydropower, coal, natural gas and oil, and some potential of renewable energy sources. The hydropower potential in Vietnam, based on survey of 87 rivers, is estimated at 308 TWh/year with a capacity of 70,000 MW, while the economic potential is estimated at 120 TWh/year and a capacity of 30,000 MW. Taking into account the environment and social criteria, the feasible hydropower potential is estimated to be 20,750 MW and 83TWh. In the future, hydropower projects over the whole country, i.e. northern, central and southern regions, are considered as candidates for system expansion. The full list of hydropower projects considered in the planning exercise is given in Table 5.

Thermal generating capacity in the future will rely on coal in the North and gas in the South. The expansion planning also considers importing coal (from Indonesia and Australia) for producing electricity in the later part of 2020’s. In addition, nuclear energy will also be a possible candidate for meeting high electricity demand in far future.

The availability of coal with various quality in the Quang Ninh geological basin and under the Red River delta makes it possible to develop a sizable coal-fired power capacity in the North, particularly in Quang Ninh, Cam Pha, Hai Phong, Ninh Binh, and Uong Bi. Coal power stations can also be built in the central region, for which candidates under consideration are Nghi Son and Vung Anh power plants.

Off-shore crude oil, associated gas and natural gas have been exploited since early 1990’s. A large portion of collected gas has been used for electricity generation, notably in the South, given the proximity to the gas production location. In the future, candidates under consideration include power stations in Ca Mau, Omon, and extension of the existing Phu My power plants. New sties will be investigated for more plants. Candidate power plants and their main characteristics are shown in Table 5.

The table below summarizes the projection of supply of hydrocarbon fuel in Vietnam and the corresponding total demand of the country. The table shows that after 2025, Vietnam will not be able to meet its energy demand using only domestic resource and it will become a net energy importer. Supply and Demand of Hydrocarbon Fuel toward 2025

2005 2010 2015 2020 2025

Supply 29.2 32.91 41.42 60.75 64.54 Coal (Million tons) Demand 13.62 22.41 33.93 62.95 100.13

Supply 17.8 20.36 19.34 19.48 18.62 Oil (Million tons) Demand 11.0 18.29 29.97 44.56 54.6

Supply 6.5 8.52 13.96 14.39 16.2 Gas (Billion m3) Demand 4.5 8.31 14.46 14.91 16.34

Source: IOE 2005, Master Plan VI (final draft) Hanoi.

7.4.4 System Planning Methodology

The starting point is Master Plan V, but with extended planning horizon to 2025. The planning exercise is formulated based on the set of candidate plants and taking into consideration constraints that reflect the fuel availability and system reliability criteria (power plant outage, maintenance requirement, transmission line reliability rule, etc.). Two possibility of gas supply were considered, 14 billion cubic meters (b.c.m) and 10 b.c.m per year during 2020-2025. The two most important reliability criteria are the loss of load


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expectation (LOLE) criteria, applied to the whole generation system, and the rule n -1 applied to the transmission capability. The LOLE criterion stipulates that the expected loss of load should not exceed 24 hour per year (LOLE < 24 per year). The n-1 rule takes into account the situation when one circuit of the double circuit 500 kV transmission line is not functioning and the whole system still works stably.

System optimization was carried out using the software STRATEGIST. It is a tool for dynamic programming optimization based on the lowest total discounted system costs. STRATEGIST's approach is similar to the previously used WASP model, but allowing for taking into study the transmission system with interchange between sub-systems (up to 15 systems can be considered and three systems were actually considered in Master Plan VI, North, Central and South). STRATEGIST operates by taking as input the load demand via a module LFA (Load Forecast Adjustment). The second module, GAF (Generation And Fuel) simulates the dispatch of all thermal and hydropower units and linkages. The PRV (PROVIEW) then finds the optimal system configuration through a dynamic programming process. Apart from demand data, other important inputs for optimization are (i) technical and finance econimic data of all generation sources, fuel types, fuel price, investment cost, O&M cost, efficiency, load factor, failure frequences, etc., (ii) investment cost, voltage, length, O&M cost, losses, failure frequences, etc. for transmission lines, and (iii) fuel supply availability/limitation, and fuel costs. Fuel costs are forecasted taking into account international projections. O&M costs are based on national/international practices. The costs are economic costs without provision of taxes and environmental costs are not included.

7.4.5 Least-cost Expansion Generation Plan up to 2025

The optimization of the system expansion results in a optimal schedule of new capacities to be added to the system for the whole period 2005-2025. Graphically, the peak load and the system aggregated capacity are shown in Figure 7-2 below. The numerical values and reserve margins are tabulated in the table below. It may be noted that the reserve margin is small for 2006 and 2007, before new capacity coming online. The reserve margin will reach 26.6% in 2011 and then slightly decline, but will still remain at a level of 20%. This is due to the reliability constraint of the 500 kV transmission line. After 2020, new capacity will have quite large unit size (e.g. 600 MW) leading to correspondingly robust margin requirement. Figure 7-2 Evolution of Peak Demand and Available System Capacity over the period 2006-2025

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A full list of new capacity and the schedule of their coming online is documented in Table 5. The optimal expansion plan confirms that the Song Bung 4 Hydropower Project is part of the optimal schedule and will be commissioned in 2012.

The optimal system expansion is a combination of all types of generating capacities reflecting the resource base of the country. Hydropower will continue to be developed. Thermal power, such as gas and coal based, will also have their share in the generation mix. It is noticeable that contribution to the system from renewable sources will become more and more significant. The mix of small and mini hydropower and wind power represent renewable energy sources with increasing value of capacity. By 2011, renewable capacity will reach only 100 MW, but will increase to 500 MW in 2015 and to about 1,000 MW in 2025. Generating Capacity vs. Peak Demand of the System, 2006-2025

Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Demand MW 11160 12966 15115 17349 19689 21987 24352 26622 29251 32077Capacity MW 12107 14397 18312 22524 26157 29975 33206 35930 38035 40337Reserve 7.8% 9.9% 17.5% 23.0% 24.7% 26.6% 26.7% 25.9% 23.1% 20.5%Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Demand MW 34980 37994 41208 44693 48541 52571 56882 61485 66256 71208Capacity MW 44993 50195 53695 57145 62765 65265 71846 76646 82296 88096Reserve 22.3% 24.3% 23.3% 21.8% 22.7% 19.4% 20.8% 19.8% 19.5% 19.2%

The demand forecast in Section 7.3 shows that the central region has lower demand compared to the demands in the North and South, however, in the next 25 years demand in the central region will grow with the highest rate. Song Bung 4 Hydropower Project, being located in Quang Nam Province, is an important generation source to meet this fastest growing demand in the central region.

7.5 Economic Valuation of Costs and Benefits of Song Bung 4 Hydro Power Project

7.5.1 General

According to the ADB Guideline on Economic Analysis of Projects, the economic viability of Song Bung 4 Hydropower Project (SB4 HPP) was examined by comparing the two scenarios of ”with" SB4 HPP and "without" SB4 HPP. The comparison takes into account the costs as well as the benefits to the society in these two scenarios. The basis of comparison is that both scenarios face the same projected electricity demand as detailed in Section 7.3 above.

7.5.2 Costs

The costs to the society are the investment and the operating costs of Song Bung 4 Hydropower Project, and the costs of social and environmental mitigations. Investment costs in turn can be categorized into equipment costs (including cost of the 220 kV transmission line connecting Song Bung 4 Hydropower Project with the national network), construction costs, engineering, administrative and management costs related to the construction of the power plant. The costs also include physical contingencies, but exclude the interest during construction and price contingency.

In this analysis domestic price numeraire is used. For ease of presentation, US dollar is chosen as unit of currency, and all values in Vietnamese Dong (VND) are converted to USD using the exchange rate of 1 USD = 15,800 VND. Equipment costs are estimated based on


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international experience and is quoted in USD (world price). To reflect the social value of the Project, based on the domestic price numeraire, a shadow exchange rate factor is used (SERF = 1.1 for Viet Nam2). Construction costs and administrative costs are estimated based on domestic unit rates (available to PECC3 as well as SWECO) and are quoted as domestic price level numeraire. Summary of the cost components are tabulated in the table below: Investment Costs of Song Bung 4 Hydropower Project in Economic Terms

Items MUSD SERF Shadow Value

MUSD Cost of construction 108.54 1 108.54 Cost of equipment 40.04 1.1 44.04 Admin & other costs 17.62 1 17.62 Cost of transmission line 6.81 1.1 7.49 Physical contingency 13.33 1.1 14.66 Env./Social mitigation costs 20.45 1 20.45 Total Investment w/o IDC 206.79 212.80

Source: ADB estimate based on PECC3, SWECO International

7.5.3 Benefits

7.5.3.1 General According to the least cost expansion plan of Master Plan VI (MP VI) Song Bung 4 Hydropower Project will be brought online in 2012, generating about 537 GWh of electricity. It will be connected to the national transmission network via a 220 kV transmission line in the central region. At present the electricity system in Vietnam is a unified system stretching over the country with the backbone being a 1,700 km long high voltage (500 kV) transmission line connecting all load and generation centers between the northern and southern parts of the country. The central region has lower demand compared to the demands in the North and South, however, in the next 25 years, demand in the central region will grow with the highest rate. Song Bung 4 Hydropower Project, being located in Quang Nam Province, is an important generation source to meet this fastest growing demand in the central region.

More importantly, Song Bung 4 Hydropower Project helps to increase the reliability of the 500 kV transmission line, the back-borne of the transmission network. As described above, the 500 kV connection stretches over 1,700 km. Technically, for reliable operation of this long high voltage transmission link, it is necessary with a boot up voltage centre in the middle of the line. So far the Yaly Hydropower Power Plant plays that role. As the power transfer between North and South grows, Song Bung 4 Hydropower Project will contribute to the voltage stabilization of the double circuit 500 kV transmission line. Thus "without" SB4 HPP the entire system will be more vulnerable to the voltage variation. This is a non-quantifiable benefit of having Song Bung 4 Hydropower Project.

The study by the Institute of Energy shows that, during the next 25 years, the economics of the system operation dictates that electricity is being transported from the North (where cheap domestic coal is available) to the South (where gas supply is limited). Thus having Song Bung 4 Hydropower Project in the system reduces the amount of transferred electricity thereby increasing the reliability of the system as a whole.

Other non-quantifiable benefits include flood control on Vu Gia River and irrigation benefits resulting from the regulating capacity of the Song Bung 4 dam.

In order to compare the system behavior in the "with" and "without" scenarios, the power- 2 See RRP No. 38196:"Proposed Loan Socialist Republic of Viet Nam: Northern Power Transmission Expansion Sector Project" Asian Development Bank, November 2005, Manila.


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planning tool of Institute of Energy (STRATEGIST) was used to simulate the production and power exchange between regions. First the optimal expansion plan of Master Plan VI was simulated, which corresponds to the "with" SB4 HPP scenario. As a result, plant generation and power transfer among regions, and loss of load expectation (LOLE), are calculated. The "without" SB4 HPP scenario is simulated by taking out the SB4 HPP from the system while keeping unchanged other generation sources. Since production of hydropower stations are dependent on water availability and regulation of water due to other duty of such hydropower plants, their production levels in case of "without" SB4 HPP were kept the same as in the "with" SB4 HPP case. Without SB4 HPP, the system load will be met by increased production from thermal power plants to the extent possible. If it is not met by increased production of thermal power plan it is considered curtailment of the consumer demand.

The result of the simulation of the "with" SB4 HPP scenario shows that the system dispatches 537 GWh from the Song Bung 4 Hydropower Project every year. In the "without" SB4 HPP scenario, LOLE increased quite substantially, see the table below. More importantly, the LOLE increased not for the central region, where it would have been expected, but in the northern and southern regions, where the demands are higher and reserve capacities are smaller. The shortage of electricity in the North and South will cause more damages with concentrated industrial and commercial businesses. Changes of LOLE (hour/year) in the three Regions

Year North Central South ENS wSB4 woSB4 wSB4 woSB4 wSB4 woSB4 GWh 2012 0.43 0.76 0.31 0.71 19.06 23.50 56.63 2013 0.34 0.87 0.12 0.39 16.18 20.47 62.29 2014 1.40 1.94 0.35 0.53 20.03 24.84 75.53 2015 21.97 25.42 7.87 15.56 23.24 26.48 123.62 2016 21.61 25.91 0.00 0.00 22.29 25.51 117.55 2017 21.53 25.02 0.09 1.69 23.02 27.39 142.73 2018 22.92 26.38 1.64 8.84 21.26 24.85 164.85 2019 20.38 24.21 4.76 7.70 20.11 25.54 203.96 2020 21.68 25.51 23.84 30.52 22.81 27.58 226.94 2021 22.04 25.51 14.09 18.52 24.35 28.93 219.38 2022 20.84 23.37 13.38 14.29 22.45 27.77 211.31 2023 22.21 25.60 25.91 27.46 22.89 27.48 233.83 2024 20.96 25.29 11.41 15.80 24.41 26.86 233.16 2025 20.61 24.29 14.72 21.12 23.87 27.69 294.93

Note: wSB4 – LOLE in the "with" Song Bung 4 Hydropower Project calculation woSB4 – LOLE in the "without" Song Bung 4 Hydropower Project calculation Source: Model simulation results, IOE, March 2006 It is noted that the LOLE in the Southern region exceeds the national standard starting from 2014 and the LOLE of the Northern region exceeds the limit of 24 hour/year starting from 2015. For the central region, the rate of LOLE increase is high but the absolute value of LOLE change is small, and LOLE for the "without" SB4 HPP scenario does not exceed reliability standard for most of the years during the expansion planning period.

The increase of the LOLE between the "with" and "without" SB4 HPP scenarios is a measure of the expected energy not served (ENS in the last column of the table above) had the same values of LOLE been kept in both scenarios. The other part of shortage due to “without” SB4 HPP is partly covered by the increased production of thermal power plants both in the


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Northern and Southern regions.

In this analysis, the economic value of electricity generated by Song Bung 4 Hydropower Project is measured by the costs to the society of not having it. This cost comprises the costs of sub-optimal operation of thermal power plants to partly replace Song Bung 4 Hydropower Project and the costs to the consumers (industrial, residential, commercial) due to unserved electricity (ENS). In other words, the benefits of having Song Bung 4 Hydropower Project is the sum of two components: the non-incremental benefits accrued by not having to run thermal power plants at their sub-optimum; and the incremental benefits accrued to the consumers by having sufficient supply of electricity to their satisfaction.

7.5.3.2 Non-incremental Benefits The extra amounts of thermal production in the Northern and Southern regions vary year by year as shown in the table below. The IOE model considers the three regions of the country, therefore allowing knowledge about thermal production of power plants that produce to offset Song Bung 4 Hydropower Project. Increased Production of Thermal Power Plants to Offset Song Bung 4 Hydropower Project, GWh

Year By Coal By Gas/Oil Total 2012 270.75 197.69 468.44 2013 182.01 279.70 461.71 2014 163.25 284.28 447.53 2015 59.77 339.79 399.56 2016 88.51 318.80 407.31 2017 86.36 294.91 381.27 2018 81.30 278.64 359.94 2019 86.46 233.58 320.04 2020 86.14 210.92 297.06 2021 245.50 59.12 304.62 2022 116.89 195.21 312.11 2023 214.37 75.79 290.17 2024 87.47 203.37 290.84 2025 78.69 149.95 228.64

Source: Model simulation results, IOE, March 2006 The extra production by power plants in the Central and Northern regions is coal-based and in the South gas and/or furnace oil based. The capacity factor of Song Bung 4 Hydropower Project (156 MW, 537 GWh) is about 39 %. With this capacity factor, Song Bung 4 Hydropower Project will likely be operating at the shoulder regime. It is considered that the thermal power plants that will cover the load of Song Bung 4 Hydropower Project will also be operating at the shoulder load regime. For the northern region these will be domestic coal power plants and for the southern region these will be gas-fired power plants. The corresponding average costs are 0.0474 USD/kWh for coal and 0.0528 USD/kWh for gas, see Table 8. These production costs are used to value the benefits of Song Bung 4 Hydropower Project by non-incremental benefits in terms of avoided costs of running thermal power plants outside their optimal regime.

7.5.3.3 Incremental Benefits As thermal power plants cannot cover all the shortage of electricity due to the”without" SB4 HPP scenario, final consumers suffer expected power shortage. This represents the incremental value of benefits of having Song Bung 4 Hydropower Project. The shortage of


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electricity supply due to "without" SB4 HPP causes different costs to different consumer categories. The household consumer will likely have to curtain their consumption, whereas industrial/commercial consumers will use alternative generating sources to replace shortage of electricity.

The household consumer electricity demand function is assumed to be of the natural logarithm function (Choynowsky, 2002)3:

ln(Q) = a + b*P

where:

Q is the electricity consumption level of an individual household,

P is the corresponding price of electricity

a and b are the coefficients specific to a given situation.

With such a demand function, the loss of consumer welfare due to a reduction of consumption from level Q1 to level Q2 (Q2 < Q1) is measured by:

HH_loss = ∫1

2

Q

Q

Pdq

Or after integrating over the Q2 – Q1 range:

HH_loss = Q1 * (P1-1/b) – Q2 *(P2-1/b)

where: P1 is the price level at Q1 and P2 is the willingness to pay for an extra kWh while consuming at Q2 (to reach a higher consumption level). For small changes in consumption level (e.g., Q1 ~ Q2) it can be assumed that P1 ~ P2 and the above equation is simplified to:

HH_loss = (Q1 – Q2) * (P1-1/b)

In the "without" SB4 HPP case, part of demand will be covered by extended thermal generation as shown in Section 7.5.3.2. The remaining represents shortage to the consumer. For the period 2011 – 2025 this shortage is shown in the table below for three consumer groups namely Household, Commercial and Industry (inclusive of agriculture). As can be seen, demand curtail for household sector is relatively small (because of the small size of Song Bung 4 Hydropower Project and also owing to ability of some thermal power plants to partly cover the shortage). The equation for benefits calculation presented above is applicable for an individual household. In this analysis such equation is being applied for an average household in Vietnam. Shortage of Electricity Supply (GWh) due to without SB4 HPP by Consumer Categories

ENS-HH GWh/a

ENS per HH kWh/a

ENS-IND GWh/a

ENS-COM GWh/a

Total ENS GWh/a

22.21 0.977 22.21 11.11 55.53 24.92 1.084 24.92 12.46 62.29 30.60 1.316 30.60 15.30 76.50 49.79 2.118 49.79 24.89 124.47 46.66 1.963 46.66 23.33 116.66 57.09 2.376 57.09 28.55 142.73 65.61 2.701 65.61 32.81 164.03 81.59 3.322 81.59 40.79 203.96 90.78 3.656 90.78 45.39 226.94 87.75 3.495 87.75 43.88 219.38

3 P. Choynowski 2002, Measuring Willingness to Pay for Electricity, ERD Technical Note No.3, Asian Development Bank, Manila.


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84.77 3.340 84.77 42.38 211.92 93.53 3.645 93.53 46.77 233.83 93.27 3.595 93.27 46.63 233.16 118.16 4.505 118.16 59.08 295.39

Source: Model simulation results, IOE, March 2006 Numerical Coefficients of the Typical Household Demand Function

Year P0 Q0 P1 Q1 Coeff a Coeff b 2008 5127 119 768 1378 7.659918 -0.00056 2009 5127 119 779 1485 7.755385 -0.00058 2010 5127 119 790 1593 7.845926 -0.0006 2011 5127 119 802 1655 7.899698 -0.00061 2012 5127 119 812 1707 7.943688 -0.00062 2013 5127 119 823 1747 7.979367 -0.00062 2014 5127 119 835 1773 8.005962 -0.00063 2015 5127 119 846 1792 8.027019 -0.00063

Source: RRP 38196 and ADB staff calculation In 2004, the population of Vietnam stood at 83.2 million, with the average household size of 4.5 people there were 18.5 million households. Using a population growth rate of 1.12%/year (decreasing over time to 1.09%/year) and average household size decreasing from 4.5 to 3.8, it is possible to estimate the number of households in Vietnam for the whole study period. Dividing the electricity shortage by the number of households yields the level of electricity curtail per household, which can be used for calculation of welfare loss. It can be seen from the table above that the amount of shortage that an average household suffers is relatively small compared to the average consumption level of 120 kWh. Thus the equation with small changes can be used to simplify the calculation process.

Using data from previous sources4 the values of coefficients a and b of the demand function are estimated for a typical household in Vietnam (see the table above). As a result, the following equation represents quite well the electricity demand function for a typical household:

ln(Q) = 8 – 0.0006 P

Figure 7-3 below shows the demand function expressed by this equation:

4 see RRP No. 38196 "Proposed Loan Socialist republic of Viet Nam: Northern Power Transmission Expansion Sector Project", ADB November 2005


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Figure 7-3 Typical Household Electricity Demand Curve

0

1,000

2,000

3,000

4,000

5,000

6,000

0 500 1,000 1,500 2,000 2,500

Q, kWh

P, V

ND

/kW

h

Source: Based on Choynowski, 2002 and ADB staff calculation Applying the actual demand function and taking the integral of the household loss (the equations above), given that the current tariff of electricity is 853 VND/kWh5, the economic value to the household consumer would be 2,520 VND per kWh at the consumer end. Since Song Bung 4 Hydropower Project is a generation project, in order to attribute the consumer welfare benefit to Song Bung 4 Hydropower Project, a portion of benefit pertaining to T&D should be excluded. The ratio between generation to T&D costs in the power system of Vietnam is about 80:20, resulting in the economic value of not having a kWh of 2,020 VND/kWh or 0.128 US$/kWh at the generation level, i.e. the benefits of Song Bung 4 Hydropower Project.

The cost to the industrial and commercial consumers is the cost of alternative generations. According to the experts of Institute of Energy, a most popular replacement for grid electricity is the stand-alone diesel generator, capacity from 150 kW to 5 MW. The levelized costs of diesel generation is 0.01445 US$/kWh.

The table below summarizes the results of the benefit calculation. The table contains the economic value of electricity from Song Bung 4 Hydropower Project looking from the consumer perspective. The total economic values of Song Bung 4 Hydropower Project is a sum of the avoided costs of operating thermal power plants at sub-optimum, avoided costs to the industrial consumers who have to use more expensive source of electricity (diesel generators), and welfare loss of household consumers who have to reduce their consumption involuntarily.

The project life is 40 years, starting from mid 2012. However the planning period ends in 2025, thus the level of benefits after 2025 needs to be estimated. In this analysis it is assumed that the level of thermal electricity replacement, as well as not served electricity, remain approximately as in 2025 thereafter. The flow of the net benefits, comparing the "with" and the "without" SB4 HPP, can thus be obtained, which allow calculating the lifetime net present value of net benefits, which amounts to 51.06 million US$ and the economic internal rate of return to 14.95 %.

5 This is the approved average price of electricity averaged across the consumer categories to be effective since March 1, 2006.


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Economic Benefits of SB4 HPP Valued by Consumer Categories, MUSD

Avoided Costs of Thermal Power

Benefits to Household Consumers

Benefits to Industrial

Consumers

Benefits to Commercial Consumers

Total Benefits

2012 23.92 2.90 3.28 1.64 31.73 2013 24.05 3.19 3.60 1.80 32.65 2014 23.41 3.87 4.37 2.18 33.83 2015 21.45 6.33 7.15 3.58 38.50 2016 21.70 6.02 6.80 3.40 37.92 2017 20.34 7.31 8.26 4.13 40.03 2018 19.24 8.44 9.54 4.77 41.98 2019 17.10 10.44 11.80 5.90 45.24 2020 15.89 11.62 13.13 6.56 47.19 2021 15.39 11.23 12.69 6.34 45.65 2022 16.51 10.82 12.22 6.11 45.66 2023 14.80 11.97 13.52 6.76 47.06 2024 15.55 11.94 13.49 6.74 47.72 2025 12.31 15.10 17.06 8.53 53.00

Source: ADB Staff calculation

7.6 Sensitivity Analysis The sensitivity of the resulted NPV and EIRR with respect to main input parameters has been analyzed by using the @RISK program. The main input parameters subject to the sensitivity analysis include the generation level of Song Bung 4 Hydropower Project, the capital investment costs, and the values that household, industrial and commercial consumers attach to the un-served electricity. Variation of these parameters and corresponding variation of NPV and EIRR are shown in the table below. Sensitivity of NPV and EIRR Relative to Key Input Parameters

NPV ($51.06 m) EIRR (14.95 %)

Parameter Low Base High Low

(Million US$)

High (Million

US$) Low High

Capital, MUS$ -7% 217.97 20% $54.34 $4.11 15.26% 12.20% Generation, GWh -10% 524 3% $28.75 $52.77 13.64% 14.99% HH_WTP, US$/kWh -20% 0.128 9% $38.50 $51.98 14.20% 14.96% Non HH_WTP, US$/kWh -3% 0.145 24% $40.50 $60.13 14.30% 15.28%

Source: ADB staff calculation using @RISK The cumulated probability distribution of EIRR and NPV with 1,000 Monte Carlo simulation using @RISK is shown in Figures 7-4 and 7-5 below. The result of simulation shows that the Project is economically robust. With a wide range of input variation, according to the table above, there is a 99 % probability that EIRR equal or exceeds 12 %. Similarly there is only a 1% probability (out of 1,000 simulations) that NPV goes below zero (EIRR <12%). This conclusion is further confirmed by data in the table below.


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Figure 7-4 Cumulated Probability Distribution of EIRR (1,000 Simulations)

sensitivity_allCumulative Distribution of EIRR

0%

20%

40%

60%

80%

100%

10.00% 11.00% 12.00% 13.00% 14.00% 15.00% 16.00% 17.00%

prob

abili

ty

Source: ADB staff calculation using @RISK

Figure 7-5 Cumulated Probability Distribution of NPV (1,000 Simulations)

sensitivity_allCumulative Distribution of NPV

0%

20%

40%

60%

80%

100%

($10.00) $0.00 $10.00 $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00

prob

abili

ty

Source: ADB staff calculation using @RISK


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Expected Values and Standard Deviation of EIRR and NPV EIRR NPV

Expected value 13.74% 32.09 MUSD Standard deviation 0.94% 15.85 MUSD Minimum 11.77% -4.84 MUSD Maximum 15.87% 67.44 MUSD Coefficient of variation 0.068 0.494 Probability of negative outcome 0.0% 0.6%

Note: Expected value is different from the base value Source: ADB staff calculation using @RISK

7.7 Conclusion The analysis presented so far demonstrates that there is a fast growing demand for electricity between 2005 and 2025, especially the demand in central region, where Song Bung 4 Hydropower Project is to be constructed, grows fastest. The analysis also shows that Song Bung 4 Hydropower Project is part of a vigorously planned schedule of capacity addition, and is scheduled to be added to the grid in 2012. The economic robustness of Song Bung 4 Hydropower Project has been confirmed by economic valuation of cots and benefits of the Project with extensive sensitivity analysis. The Song Bung 4 Hydropower Project yields an EIRR of 14.95 % and a corresponding NPV of 51.06 million US$ over the project lifetime of 40 years.

8 Financial Analysis

8.1 Introduction This Chapter gives an account of the financial analysis of the PPTA on Song Bung 4 Hydropower Project, Phase II. It is divided into the following sections:

• Section 8.2: Cost analysis of proposed investment.

• Section 8.3: Financial analysis of proposed investment.

• Section 8.4: Past financial performance of EVN.

• Section 8.5: Future financial performance of EVN.

• Section 8.6: Financial management capability of EVN/ATD3 to administer proposed loan.

8.2 Cost Analysis of Proposed Investment As part of their expansion program to meet expected future demand, EVN are planning to build a number of new power stations in the next few years. One of these is Song Bung 4 Hydropower Project in Central Vietnam. Part of the construction of this plant is expected to be funded by ADB, with EVN providing the remainder of the funding from its own resources and by a loan from Vietnam Development Bank for the resettlement costs.

8.2.1 Cost Estimates

The cost estimates for the civil works, equipment supply, transmission, and consultancy services are given in Section 5.6. The cost of environmental and social mitigation measures is included in these costs, as well as for engineering and administration.


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All the required work to complete Song Bung 4 Hydropower Project has been grouped into packages, and each package will be funded by either ADB or EVN. The cost analysis has been carried out in 2005 USD terms. Local currency costs are shown in current VND using an exchange rate of 15,800 VND/USD.

EVN will have the pay VAT on certain materials, equipment and services, and this is shown separately, though ATD3 has indicated that EVN will eventually be able to recover all the VAT associated with expenditure on Song Bung 4 Hydropower Project. Import duty and other taxes payable on imported equipment, which EVN cannot be reimbursed, are identified separately. It is assumed that EVN will pay all taxes, including taxes on procurement packages funded by ADB.

The phasing of the actual expenditure has been estimated, and physical contingencies have been estimated as follows:

• Equipment – 5%

• Transmission– 7%

• Civil works construction– 10%.

• Engineering & Administration - 10%.

• Implementation support, and environmental & social mitigation – 10%.

The cost contingencies for local and foreign cost expenditure (including physical contingency) in each year have been estimated using the ADB methodology as follows:

• International inflation: assumed to be 1.2 to 2.8 % per annum according to the table below.

• Local inflation: 4% per annum, as per ADB guidelines.

• Rate of exchange: No real appreciation or depreciation in the VND/USD exchange rate.

2007 2008 2009 2010 2011 2012 International (USD) inflation 2.8% 1.2% 1.2% 1.2% 1.2% 1.2%

Vietnamese (VND) inflation 4% 4% 4% 4% 4% 4% Rate of exchange (VND/USD) 15994 16437 16891 17359 17839 18333 Source: EVN, Consultants estimates

It is assumed that ADB and EVN will finance the following components of the Project:

Component ADB EVN Civil Works-Dam and Spillway Yes No Civil Works-Waterway and Power Station

Yes No

Electromechanical Equipment Yes No

Hydro-mechanical Equipment Yes No

Environmental Mitigation Cost No Yes Resettlement and Social Mitigation Cost

No Yes

Relocation od Highway 14D Yes No Implementation Supervision Consultant

Yes No

Independent Monitoring Yes No


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Preparatory Works No Yes

Transmission Line Yes No

Engineering and Administration No Yes

IDC on ADB loan Yes No

ADB Commitment fee Yes No

Taxes and VAT Yes Yes

The foreign and local currency component of each item has been estimated.

IDC has been calculated on the following assumptions:

• All moneys required to meet planned expenditure in a particular year are assumed to be disbursed in the middle of the appropriate year (i.e. only a half year’s interest is charged in the first year of disbursement).

• No loan repayments are assumed to take place before 2012.

• IDC is calculated on the closing balance of each loan at the end of the year.

• All interest payable over the period 2008-2011 is assumed to be IDC.

• Physical and cost contingencies are included in IDC calculations.

ADB charge an annual commitment fee of 0.75% on the difference between actual cumulative disbursements and the following assumed disbursement schedule:

2008 2009 2010 2011+ Proportion of undisbursed loan liable for commitment fee charge

15% 45% 85% 100%

Source: ADB Operations Manual bank Policies 29 Oct 2003

The table below gives a summary of the cost of the proposed investments by procurement package.

Summary of Cost of Investments

Total (M USD)

A. Base cost 1 1 Civil Works-Dam and Spillway 50,39 2 Civil Works-Waterway and Power Station 36,55 3 Electromechanical Equipment 32,68 4 Hydro-mechanical Equipment 7,36 5 Environmental Mitigation Cost 0,56 6 Conservation Off-set 9,30 7 Resettlement and Social Mitigation Cost 18,03 8 Implementation Supervision Consultant 4,54 9 Advisory Project Management Consultant 0,00 10 Implementation Resettlement Consultant 0,00 11 Panel of Experts 0,00 12 Third Pary Monitoring 0,10 13 Preparatory Works 12,29 14 Transmission Line 6,81 15 Engineering and Administration 11,38 16 VAT and other taxes 15,25


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Sub-total A 205,24 B. Contingencies 30,10 C. Financing charges during implementation 2 18,44 Total 253,78

1 Based on 2005 prices and an exchange rate of 1USD=15800 VND 2 Includes interest and commitment charges.IDC has been computed at an interest rate of 6.36%

for the ADB Loan and at 7.80% for the VND Loan Source: consultants estimates

The table below gives a summary of the cost of the proposed investments by component, and foreign and local cost in USD and VND terms.

Summary of Cost of Investments (by sub project)

Foreign Local Total of base cost Foreign Local Total % of base cost

A. Investment costs a

1 Civil Works-Dam and Spillway 240,4 560,8 801,2 24,6% 15,12 35,27 50,39 24,6%2 Civil Works-Waterway and Power Station 174,3 406,8 581,1 17,8% 10,97 25,59 36,55 17,8%3 Electromechanical Equipment 441,7 77,9 519,6 15,9% 27,78 4,90 32,68 15,9%4 Hydro-mechanical Equipment 99,5 17,6 117,0 3,6% 6,26 1,10 7,36 3,6%5 Environmental Mitigation Cost 0,0 8,9 8,9 0,3% 0,00 0,56 0,56 0,3%6 Realignment of Highway 14 D 0,0 147,8 147,8 4,5% 0,00 9,30 9,30 4,5%7 Resettlement and Social Mitigation Cost 0,0 286,6 286,6 8,8% 0,00 18,03 18,03 8,8%8 Implementation Supervision Consultant 50,5 21,7 72,2 2,2% 3,18 1,36 4,54 2,2%9 Advisory Project Management Consultant 0,0 0,0 0,0 0,0% 0,00 0,00 0,00 0,0%

10 Implementation Resettlement Consultant 0,0 0,0 0,0 0,0% 0,00 0,00 0,00 0,0%11 Panel of Experts 0,0 0,0 0,0 0,0% 0,00 0,00 0,00 0,0%12 Third Pary Monitoring 0,0 1,6 1,6 0,0% 0,00 0,10 0,10 0,0%13 Preparatory Works 0,0 195,4 195,4 6,0% 0,00 12,29 12,29 6,0%14 Transmission Line 0,0 108,3 108,3 3,3% 0,00 6,81 6,81 3,3%15 Engineering and Administration 0,0 180,9 180,9 5,5% 0,00 11,38 11,38 5,5%16 VAT and other taxes 0,0 242,4 242,4 7,4% 0,00 15,25 15,25 7,4%

Sub-total (A) 1006,4 2256,9 3263,3 100,0% 63,30 141,94 205,24 100,0%

B. Recurrent costs[None] 0,0 0,0 0,0 0,0% 0,00 0,00 0,00 0,0%

Sub-total (B) 0,0 0,0 0,0 0,0% 0,00 0,00 0,00 0,0%

Total Base case 1006,4 2256,9 3263,3 100,0% 63,30 141,94 205,24 100,0%

C. Contingencies1 Physical b 73,6 216,8 290,3 8,9% 4,63 13,63 18,26 8,9%2 Price c 184,9 337,8 522,6 16,0% 3,90 7,94 11,84 5,8%

Sub-total (C) 258,4 554,5 813,0 24,9% 8,53 21,58 30,10 14,7%

D. Financing charges during implementation1 Interest during construction 245,0 58,7 303,7 13,91 3,38 17,292 Commitment charges 19,7 0,0 19,7 1,15 0,00 1,153 Foreign exchange losses 0,0 368,6 368,6 0,00 0,00 0,004 Front end fees 0,0 0,0 0,0 0,00 0,00 0,00

Sub-total (C) 264,7 427,3 692,0 15,06 3,38 18,44

Total Project costs 1529,5 3238,7 4768,2 86,88 166,90 253,78

a

b

c Assuming annual cost inflation of 1.2-2.8% (foreign currency) and 4% (local currency in USD terms)

Based on 2006 prices and an exchange rate of 1USD=15800 VNDComputed as 10% for all items except Electro-mechanical equipment 5%, hydro-mechanical equipment 5.0% and transmission line 7%.

bn VND M USD

8.2.2 Financing Plan

It is assumed that ADB will fund all the components involving foreign currency costs. Foreign currency costs cover the cost of equipment that need to be imported into Vietnam (provided it is sourced from a ADB member country) plus any equipment and/or works that is procured


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under ADB ICB rules and may actually be carried out by an eligible Vietnamese company. The foreign currency cost estimates include such works.

EVN is assumed to fund all the local currency costs from its own internal resources. It is assumed that there is no money from GoV, and no increase in EVN’s share capital to cover the cost of Song Bung 4 Hydropower Project.

The table below shows the finance plan for the planned investments discussed in Section 8.2.1.

Finance Plan

Total (M USD) %

Asian Development Bank 196,44 77,4%VND Loans 19,90 7,8%EVN 37,44 14,8%

Total 253,78 100,0% Source: Consultants estimates, ADB

In total ADB would provide 196.4 million USD, EVN would provide 57.3 million USD, of which 37.4 million USD will come from their own internal sources and 19.9 million USD from the VND loan. ADB would fund about 77% of the total cost and the remaining 23% would be funded by EVN.

The table below gives the financing plan for each component by funder.


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Finance Plan for each Component Total ADB EVNM USD M USD M USD

A. Investment costs1 Civil Works-Dam and Spillway 50,39 50,39 0,002 Civil Works-Waterway and Power Station 36,55 36,55 0,003 Electromechanical Equipment 32,68 32,68 0,004 Hydro-mechanical Equipment 7,36 7,36 0,005 Environmental Mitigation Cost 0,56 0,00 0,566 Realingment of Highway 14D 9,30 9,30 0,007 Resettlement and Social Mitigation Cost 18,03 0,00 18,038 Implementation Supervision Consultant 4,54 4,54 0,009 Advisory Project Management Consultant 0,00 0,00 0,00

10 Implementation Resettlement Consultant 0,00 0,00 0,0011 Panel of Experts 0,00 0,00 0,0012 Third Pary Monitoring 0,10 0,10 0,0013 Preparatory Works 12,29 0,00 12,2914 Transmission Line 6,81 6,81 0,0015 Engineering and Administration 11,38 0,00 11,3816 VAT and other taxes 15,25 11,45 3,80

Sub-total (A) 205,24 159,18 46,06

B. Recurrent costs[None] 0,00 0,00 0,00

Sub-total (B) 0,00 0,00 0,00

Total Base case 205,24 159,18 46,06

C. Contingencies 30,10 22,20 7,90

D. Financing charges during implementation 18,44 15,06 3,38

Total Project costs 253,78 196,44 57,34% of project cost 77,4% 22,6%

The table below shows the disbursement schedule of the funds by each funder over the period 2007-2014.

Disbursement of Loans Funding 2007 2008 2009 2010 2011 2012 2013 2014 Total

ADB Loan M USD 0,00 0,50 33,12 52,04 105,58 5,19 - - 196,44VND Loan M USD - 7,26 4,57 2,76 4,71 0,42 0,09 0,09 19,90EVN M USD - 12,72 8,57 5,75 9,38 0,72 0,15 0,15 37,44Total M USD 0,00 20,49 46,27 60,56 119,66 6,33 0,24 0,24 253,78

8.3 Financial Analysis of Proposed Investment In this Section a financial analysis of the construction of Song Bung 4 Hydropower Project is undertaken on the assumption that it is a stand-alone project selling bulk electricity to the power market at a fixed price.


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8.3.1 Capital Cost

The capital cost of Song Bung 4 Hydropower Project is as given in Section 8.2. The analysis is performed over a 40-year period, the expected lifetime of the mechanical equipment. However, the civil works are expected to have a lifetime of 50 years and so after 40 years there is some residual value in the plant that could be of interest to an investor wishing to refurbish Song Bung 4 Hydropower Project. The residual value is assumed to be 30% of the total cost of the civils work (28.7 million USD)

8.3.2 Output and Tariffs

The following table summaries the expected saleable output and bulk tariff in each season from Song Bung 4 Hydropower Project.

Season Output (GWh) Selling price (Us Cents/kWh)

Dry 427.5 4.50

Wet (July, Aug and Sep) 109.6 4.20

Total 537.1 4.44 Source: EVN Feasibility study, consultants estimates

Full production is assumed to start in 2013 (the year after construction finishes). Output in the final year of construction is assumed to be 50% of full production.

Although in theory Vietnam has created a power market for setting the price of bulk electricity, selling prices are still set primarily in relation to costs rather than market conditions. The selling prices are set to cover costs and provide a satisfactory return on the investment, so it is hardly surprising when the project achieves the desired rate of return. There are two issues; first the methodology used by to calculate the tariff, and whether the calculated price will actually be implemented. However 4.2 USc/kWh is consistent with expected tariff for other new hydropower plants and the expected selling price of bulk electricity from future non-EVN hydropower plants.

8.3.3 Operating Costs

The operating costs of Song Bung 4 Hydropower Project are estimated to be as follows:

Component Asset value (M USD) O & M Costs (as a % of asset

value)

Annual O & M (M USD)

Civils 95.63 0.5% 0.48

Mechanical & Electrical

42.04 1.0% 0.42

Transmission 6.81 1.5% 0.10

Total 144.48 0.69% 1.00 Source: Consultants estimates

In addition the cost of environmental monitoring is assumed to be 11,000 USD/annum over the period 2012-2016. A hydro tax of 14 VND/kWh is also payable on all output from Song Bung 4 Hydropower Project.


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8.3.4 Weighted Average Cost of Capital

The cost of equity in Vietnam is difficult to estimate because the capital market is still in its infancy. EVN has only recently started to raise small amounts of capital on the Vietnamese capital markets and so there is little track record of what the cost of capital to EVN has been. In March 2006 it issued 22 million USD in a bond issue at an interest rate of average deposit rate + 1.2%. Further issues are expected in the year. EVN is said to be considering issuing international bonds, but has not done so to date. In the absence if any firm information on likely cost of raising money on the international money markets, the cost of capital has been built up from general country data.

The existing risk-free interest rate determined by the rates of 10-year treasury bonds issued in VND is about 8.5% for bonds, corresponding to about 3.5% in USD terms assuming current inflation of 5%. The risk rate is estimated at 11% based on the rate for Indonesia, Philippines and Cambodia. The asset beta for Vietnam is assumed to be 0.4, giving an equity beta of 0.85 based on EVN’s current equity/long term debt ratio of approximately 29:33. This equity beta compares with an estimated equity beta of about 0.9 for Turkish power companies. Thus the cost of equity (in VND terms) is as follows:

8.5% + (11*0.85)% = 8.5% + 9.4% = 17.9%.

Moody’s quote a typical interest rate of 10.6%, and a country risk premium of 6% on government bonds for Vietnam, giving a total of 16.6%.

An Vietnamese inflation rate of 5% per year, an inflation rate of 0% for the ADB loan, and a tax rate of 28% have been assumed for the Weighted Average Cost of Capital (WACC) calculation.

The table below shows the WACC calculation, based on the sample finance plan given in Section 8.2.1, is 4.32%. A minimum test rate of 1.8% has been assumed.

Weighted Average Cost of Capital

Amount (M USD) Weighting

Nominal Cost Tax Rate

Tax Adjusted

Cost

Average Inflation

Rate Real CostActual Rate*

Weighted Component

ADB 196,44 84,0% 6,36% 28,00% 4,58% 0,00% 4,58% 4,58% 3,85%EVN Capital 37,44 16,0% 13,50% 13,50% 5,00% 8,10% 8,10% 1,30%Total 233,9 4,32%

* c/f minimum rateMinimum interest rate 1,80% Source: Consultants estimates, ADB

8.3.5 FIRR Calculation

The table below shows the FIRR analysis based on the above assumptions. The NPV, assuming a WACC of 4.32%, is 94.8 million USD before tax, or 76.5 million USD after tax. This shows that under these assumptions, Song Bung 4 Hydropower Project is financially viable.


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FIRR Analysis for Song Bung 4 Hydropower Project

Sales RevenueCapital

expenditureOperating

costsTotal

expenditureNet cash flow

(Pre tax) Profits taxNet cash flow

(Post tax)GWh M USD M USD M USD M USD M USD M USD M USD

2007 0 0,00 0,00 0,00 0,00 0,00 0,00 0,002008 0 0,00 19,48 0,00 19,48 -19,48 0,00 -19,482009 0 0,00 42,37 0,00 42,37 -42,37 0,00 -42,372010 0 0,00 52,16 0,00 52,16 -52,16 0,00 -52,162011 0 0,00 103,17 0,00 103,17 -103,17 0,00 -103,172012 269 11,92 5,88 1,25 7,13 4,79 0,00 4,792013 537 23,84 1,48 1,48 22,36 0,00 22,362014 537 23,84 1,48 1,48 22,36 0,02 22,332015 537 23,84 1,48 1,48 22,36 0,20 22,152016 537 23,84 1,48 1,48 22,36 0,39 21,972017 537 23,84 1,47 1,47 22,37 0,57 21,792018 537 23,84 1,47 1,47 22,37 0,76 21,612019 537 23,84 1,47 1,47 22,37 0,94 21,432020 537 23,84 1,47 1,47 22,37 1,13 21,242021 537 23,84 1,47 1,47 22,37 1,31 21,062022 537 23,84 1,47 1,47 22,37 1,47 20,902023 537 23,84 1,47 1,47 22,37 1,61 20,762024 537 23,84 1,47 1,47 22,37 1,75 20,622025 537 23,84 1,47 1,47 22,37 1,89 20,482026 537 23,84 1,47 1,47 22,37 2,03 20,342027 537 23,84 1,47 1,47 22,37 2,17 20,202028 537 23,84 1,47 1,47 22,37 2,31 20,062029 537 23,84 1,47 1,47 22,37 2,45 19,922030 537 23,84 1,47 1,47 22,37 2,59 19,782031 537 23,84 1,47 1,47 22,37 2,73 19,642032 537 23,84 1,47 1,47 22,37 2,87 19,502033 537 23,84 1,47 1,47 22,37 3,01 19,362034 537 23,84 1,47 1,47 22,37 3,15 19,222035 537 23,84 1,47 1,47 22,37 3,29 19,082036 537 23,84 1,47 1,47 22,37 3,43 18,942037 537 23,84 -43,47 1,47 -42,00 65,84 6,26 59,57

Total 179,59

Discount rate 4,32% Discount rate 4,32%(WACC) (WACC)

NPV (MUSD) 94,8 NPV (MUSD) 76,5

IRR 7,91% IRR 7,37%

Cash Flow - Song Bung 4 HPP

Before tax After tax

8.3.6 Sensitivity Analysis

The FIRR has been recalculated for five scenarios under the following changes to the previous assumptions:

• Dry season selling price reduced to wet season price of 4.2 US cents/kWh.

• 20 % Increase in capital cost.

• Start date of full production delayed until 2013 (no change in phasing of Capital expenditure).

• Output from power plant reduced by 20%.

• 20% increase in O& M costs.

The table below gives the new NPV for each of the above scenarios, and the breakeven value (i.e. the value required for the IRR to equal the WACC)


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Sensitivity Analysis

Pre tax Post tax Sensitivity

NPV IRR Breakeven NPV IRR

Base case 94.8 7.9% 0 76.5 7.4%

1. Reduction in selling price 79.3 7.4% 3.0 USc/kWh 64.6 6.9%

2. 20% increase in capital cost 57.3 6.2% 50.6% 39.1 5.7%

3. Start date delayed until 2013 77.8 7.1% 2018 31.7 5.6%

4. Output reduced by 20% 38.2 5.9% -33% 30.9 5.6%

5 20% increase in O & M costs 92.3 7.8% 750% 74.6 7.3%

Of the scenarios examined, the FIRR analysis is most sensitive to a reduction in output, and least sensitive to an increase in O&M costs. Output has to reduce by 33% for the NPV to become zero, while O& M costs would need to increase by 750%. Capital costs would have to increase by 50%, or for a 6-year delay before starting production, for Song Bung 4 Hydropower Project to become financially unviable.

8.3.7 Financial Statements for Song Bung 4 Hydropower Project

On the basis of the assumptions about sales, tariffs and operating costs given in the previous section, forecast Profit and Loss, Balance sheets and cash flow statements have been prepared on the assumption that Song Bung 4 Hydropower Project is a stand-alone entity.

It is assumed that Song Bung 4 Hydropower Project is 100% owned by EVN and that EVN’s capital contribution to the construction of Song Bung 4 Hydropower Project is in the form of equity. It is assumed that EVN takes all the profit after tax as dividend payment since there is little need to build up capital for further investment in Song Bung 4 Hydropower Project once it start operations (these dividend payments can be used to fund other subsequent investments in EVN).

The following assumptions are made regarding balance sheet items:

• Depreciation period – 25 years (this is a compromise between the expected life of Song Bung 4 of 40-50 years and the short depreciation period currently used by EVN for hydropower stations).

• Tax rate – 28%

• Delay in paying operating costs - 1 month

• Delaying receiving payment for electricity sales – 1 month

• Stocks of spare parts – 2% of equipment value

Tables 6, 7, and 8 give the forecast Profit and Loss Statements, Balance Sheets and Cash Flow statements, respectively, for the period 2008-2047 in USD. Tables 9, 10, and 11 give the same information in VND.


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8.4 Past Financial Performance of EVN

8.4.1 Introduction

Electricity of Vietnam (EVN) was founded in 1995 as a result of a Government decision in 1994 as the merger between nationwide power producers and distributors. EVN is under the direct control of the prime minister and competent State Management Agencies. Since its creation in 1995, GoV exerts has undue influence over its operations of EVN in a number of ways. GoV can use EVN as a way of implementing government policies, such as to request EVN to provide cheaper electricity to certain categories of customers, employ more staff to provide employment, provide various social services, and procure materials and services from other state owned enterprises (SOEs). GoV also determines the electricity tariff that directly affects EVN’s financial performance. Thus GoV, as EVN’s owner, can influence its financial performance, where shareholders in a normal company do not enjoy this privilege.

The financial performances and projections of EVN were assessed from the consolidated financial statements of all of its entities and activities. EVN’s financial statements are a consolidation of the financial statements of its component entities, including 15 independent accounting entities, 20 dependent entities, six administration units, and 14 construction/project management units. The consolidated financial statements include subsidiaries and joint ventures which the company controls more than 50% of the voting power. Significant balances and transactions between consolidated subsidiaries have been eliminated in consolidation.

Since 1998, EVN has taken out a number of large loans from international and local financiers, and plans to continue to do so in the foreseeable future in order to finance its capital expenditures. As well as ensuring these loans get repaid, most international financiers have a wider agenda in promoting the economic reform process in general within Vietnam, and in particular to assist EVN to move forwards operating as a profitable, commercially oriented company. Therefore in the previous projects, EVN has been requested to establish relevant financial reporting measures, such as self-financing ratio, debt service coverage ratio, and return on assets. These measures were included as part of loan covenants.

8.4.2 Historical Performance

The table below summarizes the main financial results over the last six years. A summary of the profit and loss statements, balance sheets and cash flow statements can be found in Annex 1.


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Summary of EVN’s Financial Performance 1998-2004 1998 1999 2000 2001 2002 2003 2004

Sales (GWh) GWh 17709 19531 22398 25843 30257 34907 39696 Increase in sales % 10% 15% 15% 17% 15% 14%

Revenue bn VND 13472.7 14121.6 16510.4 19209.7 23565.5 30245.7 34530.2 Average revenue VND/kWh 761 723 737 743 779 866 870

Operating expenses bn VND 11496.5 12024.6 14562.8 17081.9 20435.1 27364.8 30481.7 Profit before interest and tax bn VND 1976.2 2097.0 1947.6 2127.8 3130.5 2880.8 4048.5 Interest payments bn VND 417.5 363.7 550.4 587.3 782.6 1032.4 1313.0 Profits tax bn VND 535.1 644.8 514.5 541.5 676.3 19.9 296.5 Profit after tax bn VND 1023.6 1088.5 882.7 999.0 1671.5 1828.5 2439.0

Net fixed assets bn VND 28995.2 36676.9 45959.2 51204.7 58687.1 65735.3 74236.4 Equity bn VND 25199.4 27090.7 28366.1 28747.2 34175.6 36749.1 40540.6 Long term borrowing bn VND 12824.7 19064.1 25565.2 26601.3 32644.8 39349.8 45308.6

Funds from operations bn VND (2808.1) 5882.7 7571.4 6739.9 8413.1 10903.8 10654.4 Capital expenditure (net) bn VND 4530.8 11586.8 13939.4 9206.6 9915.4 13329.4 16256.5 Debt service bn VND 417.5 1254.6 2036.5 3811.6 2823.5 2719.7 4503.0

Cash from internal sources bn VND (4468.4) 3019.5 4082.6 3478.2 6279.4 9155.7 7385.1

Return on assets % 6.8% 5.7% 4.2% 4.2% 5.3% 4.4% 5.5%Return on equity % 4.1% 4.0% 3.1% 3.5% 4.9% 5.0% 6.0%Operating ratio % 85.3% 85.2% 88.2% 88.9% 86.7% 90.5% 88.3%Self financing ratio* % 30% 35% 32% 58% 70% 37%* The 2004 self financing ratio is based on forecast capital expenditure of 30455.5 bn VND in 2005

Source: EVN, consultant’s calculations

8.4.3 Sales and Income

During the seven year period 1998-2004, volumes of electricity sales have more than doubled to just under 40,000 GWh. Income has more than doubled from 13,472 billion VND in 1998 to 34,500 billion VND in 2004. Average revenue per kWh increased significantly in 2003 compared to 2002, as a result of the tariff increase. However there has been no tariff increase since then and average revenue per kWh increased only slightly in 2004 to 870 VND/kWh. Figure 8-1 shows the increase in sales and revenue per kWh.


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Figure 8-1 Summary of EVN’s Sales and Revenue per kWh 1998-2004

0

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10000

15000

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25000

30000

35000

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45000

1998 1999 2000 2001 2002 2003 2004

Sale

s (G

Wh)

0

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200

300

400

500

600

700

800

900

1000

Rev

enue

(VN

D/k

Wh)

Sales (LH scale) Revenue VND/kWh - RH scale Source: EVN annual report, consultant’s calculations

Over 90% of EVN’s revenue comes from electricity sales, and 8% from other services and product. Income from the telecommunications business at 232 billion VND in 2004 is less than 1% of total EVN income.

The proportion of electricity sales in the residential sector fell slightly from 46% in 2003 to 44.5% in 2004, while sales in the industrial sector increased from 44% to 45.2%. The impact of this change is reflected in the slightly higher income/kWh since industrial customers pay more for their electricity. The remaining 10% of sales are in the agriculture, business services and other categories. There are no significant exports of electricity.

8.4.4 Production and Supply

In 2004, EVN produced over 40,000 GWh at its own power stations and purchased a further 6,000 GWh from IPPs. Figure 8-2 shows the breakdown of supply of electricity by type of plant in 2004.


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Figure 8-2 Summary of Electricity Supply 2004

Hydropower39%

Coal fired TPS15%

Oil fired TPS1%

Gas turbine32%

Diesel0%

IPP13%

Source: EVN annual report

In 2004, the largest source of power was hydro electricity (39%), followed by gas turbines (32%) and coal-fired power stations (16%). IPPs (includes imports) accounts for 13% of total supply. There has been a significant change in the generation pattern compared to 2003, as summarized in the table below, which has implications for costs.

Summary of Electricity Supply (GWh) 2003, 2004 2003 2004 % change

Hydropower 18971 17635 -7.0%Coal fired TPS 7223 7015 -2.9%Oil fired TPS 891 602 -32.4%Gas turbine 12131 14881 22.7%Diesel 45 42 -6.7%IPP 1564 6026 285.3%Total 40825 46201 13.2%

The total supply has increased by 13%, compared to an increase in sales of 14%, the difference being explained by a reduction in losses. However, hydropower has declined by 7% due to lack of water, and the resulting deficit has been made up primarily from gas-fired power stations, and by a huge increase in power purchases from IPPs. The cost of this “replacement” power will be significantly more expensive than generating it at hydropower stations. It is understood that hydropower output continued to be below expectation in 2005, and that EVN had to further increase output at thermal power stations and increase imports, particularly from China, which adds to EVN’s operating costs.

Losses have reduced slightly from 12.23% in 2003 to 12.09%. The scope for further significant reductions in losses in the future will be limited.


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8.4.5 Operating Costs

A detailed breakdown of operating costs for 2004 is not yet available. However, total operating costs increased from just under 22,000 billion VND to almost 26,500 billion VND, an increase of 20%. Similar sized increases in selling and administration costs also occurred.

Depreciation is one of the largest operating costs for EVN, accounting for over 30% of its operating costs. Under VAS, depreciation period are in general shorter than those allowed under IAS, which accounts for the relatively high levels of depreciation. EVN also rely on these high levels of depreciation to help fund their future capital expenditure program. The other high costs are fuel for thermal power stations and power from IPPs. At present EVN is paying less than the market price for its coal, but gas is procured on long term contract in USD. Coal prices are expected to increase in real terms as the GoV pursues its policy of making Vinacoal self financing.

Other operating costs fell from 4,250 billion VND in 2003 to 1,780 billion VND in 2004, mainly as a result of much lower foreign exchange losses. This is because the USD/VND and JPY/VND exchange rates were fairly stable during 2004.

EVN receives no direct subsidies from GoV to cover its operating costs. However, the GoV does inject additional capital to help finance capital expenditure, and other indirect subsidies (such as cheap coal, access to loans from State owned banks) are available.

8.4.6 Capital Expenditure

During 2004, EVN invested over 16,000 billion VND in new capital work, an increase of 3 billion VND compared to 2003. Since 2000, EVN has invested over 90 billion VND in new generation capacity, new transmission lines and distribution networks. Approximately 50% of this expenditure has been financed by taking out additional long-term loans, and the remainder has been financed from its own resources and capital injections by the Government. Total outstanding loans increased by 6,000 billion VND in 2004 to over 45,000 billion VND.

During 2004 the Government injected 46 billion VND of additional capital to help finance new capital expenditure, compared to 196 billion VND in 2003. In total since 1998, the GoV has invested an additional 8,000 billion VND, representing about 9% of EVN’s capital expenditure.

Various transmission and distribution networks in rural areas have been transferred to EVN’s balance sheet (both as assets and as a contribution to capital) at no actual cost to EVN. This is an indirect subsidy to EVN since it charges depreciation on these assets (at a fairly high rate), but does not need to repay the cost of obtaining these assets. EVN is expected to inherit more such lines in subsequent years as local communes find it difficult to finance the repair and upgrading of such assets.

8.4.7 Overall Position

Overall EVN is in a healthy financial position, and it managed to increase its post tax profit in 2004 by over 80%, in spite of no increase in tariffs and a large increase in its operating costs. The additional profit is mainly due to an increase in sales and a reduction in foreign exchange losses. It has regularly made a profit and is generating sufficient cash to fund its current operations. However, significant changes in operating costs will occur in future years (e.g. real increases in price of coal, purchasing more electricity from IPPs, and higher cost of electricity from new plants) mean that without significant tariff increases the present level of profits can not be maintained. The proposed equitisations will provide some funds, but this is a one off exercise and only delays the need for real tariff increases.

EVN recorded a revaluation of certain assets of Vinh Son-Sing Hinh hydropower plants,


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Khanh Hoa Power Company (belonging to PC3) and the Electrical Equipment Manufacturing Company. The Auditors remark that this selective revaluation of certain assets in a particular asset class is not in accordance with IAS reporting standards, which require the revaluation of fixed assets to be recognized for the entire category of assets, and not just certain ones6.

8.4.8 Compliance with Covenants

The Auditors stated in the 2004 accounts that EVN complied with the Self financing ratio covenant, i.e. the self financing ratio was at least 30%. The table in Section 8.4.2 shows that in 2004 it was 37%.

8.5 Future Financial Performance of EVN

8.5.1 General

EVN is a large and financially complex entity operating in a rapidly changing business organizational and institutional environment. It operates under a set of often conflicting objectives than can make it difficult to plan and operate effectively. At one level it is responsible for providing electricity, a basic necessity both for the population and industry, and is heavily criticized when it fails to do so. However, the Government uses electricity tariffs as a form of social policy and thus the income EVN receives is not necessarily that required to cover all its costs. The Government has realized that this situation can not continue and that the power sector needs to be run and operated on a more commercial and business orientated basis. To this end it is planning to establish some sort of electricity market in generation and supply to encourage greater efficiency. However it will be some time before this is established and functioning, and in the mean time the pressure is on EVN to become more responsive to the needs of the country and end users.

It is important that EVN remains financially viable in the future if it is to fulfil its role of being the main supplier of electricity to end users in Vietnam and provide the necessary energy to enable the economy to grow. The existing system is currently operating at maximum capacity and there is little or no slack to meet additional demand. Without a reliable supply of electricity in the future there is real danger that the economic growth will slow down or living standards will decline due to frequent and prolonged power cuts. It is therefore vital that EVN is able to fund its future operations.

EVN’s major costs in the future are fuel for thermal power stations, power purchases from non-EVN owned power stations, capital expenditure to replace worn out overloaded assets and provide additional capacity to meet expected demand, and repaying existing and future loans that it has taken out to fund capital expenditure. It is vital therefore that the future tariffs cover not only the operating costs of EVN, but also the cost of the necessary investments, including repaying the loans EVN needs to help fund this expenditure. Also EVN has to ensure that it has sufficient funds to comply with any loan covenants. Without sufficient money, EVN will be unable to fund the necessary capital expenditure and so the reliability of supply will fall. To assist with financial planning a computer financial model has been written to enable EVN to evaluate the financial implications of different assumptions about future operations.

To this end a new business model of EVN has been developed to assist EVN evaluate the impact of changes, in respect of the following:

6 The Auditors made a similar comment on the 2002 accounts regarding the revaluation of Hoa Binh HPP.


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• Future Costs. The cost structure of EVN will change significantly in future years. The cost of fuel will continue to be a significant cost and so EVN’s future costs are closely linked to changes in the cost of buying coal, gas and fuel oil. EVN is also planning on purchasing significant volumes of electricity from IPPs in the future, which will make this a significant additional cost. EVN is embarking on an ambitious capital expenditure plan to install the necessary capacity to meet future demand, and obviously this has to be paid for. Much of this expenditure will be financed by taking out loans, and thus the cost of servicing these loans will increase overall costs. It is important that EVN has a realistic estimate of all future costs, and the factors that drive these costs.

• End User Tariffs. These determine EVN’s income and hence its profitability and viability. End user tariffs will need to cover these future operating costs together with the cost of funding the capital expenditure program, servicing the loans and complying with loan covenants. If tariffs are set too low then EVN will not have the necessary funds to operate and expand the system, resulting eventually in power shortages. However tariffs need to be set on the basis that EVN operates in an as efficient way as possible by eliminating unnecessary expenditure and getting best value from money from its expenditure.

• Institutional Aspects. The structure of EVN, and the power market in general, is changing, and this will increase pressure on EVN to be financially and commercially viable. The unbundling of EVN into separate generation, transmission and distribution entities will increase transparency and reduce the scope for implicit cross subsidies. The planned equitisation process will only be a success if the new shareholders obtain a satisfactory return on their investment. Finally the introduction of a power market into Vietnam will mean EVN will be subject to commercial or regulatory pressure to be more competitive.

The existing financial model (Independent Creditors Model - ICM) is more of an accounting model than a business model and as such not really suitable for examining the issues described above. The emphasis in the existing model is on producing consolidated financial statements rather than modeling the main processes driving the business. The consolidated data required by the existing model is not readily available, and the results not useful in monitoring and controlling the main business activities. The existing model does not look at the various existing or proposed new entities within EVN, even though some of these are significant businesses in their own right.

Many of the assumptions (such as the capital expenditure plan) are “hard wired” into the existing model, making it very difficult to evaluate the impact of changes in these assumptions. Others issues, such as equitisation are omitted altogether. It is difficult to carry out meaningful sensitivity analysis of a particular set of assumptions

8.5.2 Outline of New Business Model

8.5.2.1 General The main driver for the model is the demand forecast defining how much electricity different categories of consumer require, and the associated capital expenditure and generation schedule to meet this demand. The information given in the draft Master Plan VI is planned to be used since this gives the latest demand forecasts and associated investment plan and generation schedule. The links between demand, capital expenditure program and generation schedule are complex and these will not be modeled within the existing business plan. Instead the demand forecasts, capital expenditure plan and generation schedule will be assumed fixed. In order to perform sensitivity analysis on these key variables, various


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different scenarios will be included (e.g. 10% reduction in demand, 1 year delay in capital expenditure program). From this information an energy balance can be obtained and this will be used to determine the expected revenues and cost of generating, transmitting and distributing this electricity.

The main modules in the model are as follows:

• Distribution Companies. Each of the planned new 58 equitised provincial distribution companies and the existing ones that are not planned to be equitised are modeled separately. The cost of operating the 110 kV network is excluded from the model of each equitised distribution company; instead it will be included in the single buyer entity since not all the new PCs will operate the 110 kV network.

• Power Plants. Each existing and planned EVN power plants, including JVs where EVN has a majority shareholding (referred to as “EVN JV Power plants”, to distinguish them from other JV where EVN is a minority shareholder), is modeled separately. It is assumed that each power station sells its electricity to the Single Buyer Entity.

• Single Buyer Entity. This entity serves two purposes in the proposed model. First, it acts as single buyer of electricity by buying electricity from all EVN power stations (including EVN JV PP), Other JVs, IPPs, and imports, and then selling bulk electricity to each Power Company. Second, it operates the HV transmission network, and the three hydropower plants (Hoa Binh, Tri An and Yaly) that are planned to stay in total EVN ownership. The costs of the Single Buyer are the cost of buying electricity from other power stations, the cost of operating the 110 kV and above transmission network, and the operating costs of Hoa Binh, Tri An and Yaly hydropower plants.

In addition there are simple modules for the non-core businesses: Telecom, the Electrical and Mechanical Manufacturing Companies, and the Consulting Companies.

Figure 8-3 illustrates the main cash flows between the various modules:


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Figure 8-3 Summary of Main Cash Flows Between Entities Equitisation

Dividends Proceeds Dividends

Non Core Businesses Operating Costs

egWages,

Materials,Services,Finance

costs.

EVN Single64 Buyer of

End Power Electricity EVNUsers Companies (Including Equitised

HV Transmission and CoalHoa Binh, EVN JV Gas

Tri An Power Oiland Yaly HPP) Plants

IPPs +Imports

Other JVs

Customers

Loans, loan repayments

The main cash flows are for the core business. End users pay the Power Company for the electricity supplied and used. The Power Company in turn pays its own operating costs (e.g. wages, materials, interest on money it has borrowed). It also pays the Single Buyer for the supply of bulk electricity. The Single Buyer then pays all the Power Plants for the electricity they have generated at the appropriate tariff. The EVN Power Stations use this money to pay for the fuel (coal, etc) and their own operating costs.

Also shown are the expected flows from the core activities to the non-core businesses, which will also have their own customers for their services and products, and their own operating costs. Some of their income will come from the core business entities in EVN.

The cash flows of loans to finance the capital expenditure program of each entity, and the interest and loan repayments are also shown.

Equitisation proceeds from the sale of shares in equitised Power Companies and Power Plants, and Non-EVN contributions to EVN JVs flow into EVN (represented here by the Single Buyer) These Entities will also pay dividends to their shareholders. EVN will also receive a proportion of the profits from Other JVs it has invested in.

The Model is described in more detail in Annex 2.

It is important to realize the limitations of such a model. EVN is a large and complex organization, with over 150 separate entities, each of which is a significant business in its


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own right. The model is by necessity an approximation of EVN’s actual operations.

The model requires a lot of data initially to seed the model, some of which is readily available, or only available with considerable effort. Where relevant data is not readily available, sensible estimates have been used until more accurate data become available.

8.5.2.2 Key Inputs The key inputs to the model are:

• End–user demand, capital expenditure plan, generation schedule (from Master Plan VI).

• Financing of capital expenditure (split of expenditure by foreign and local currency, % of financing by loans, interest rate, repayment period).

• Planned equitisations (entity, timing, expected % to be equitised).

• Future end-user tariffs by major category.

• EVN Joint Ventures Power Plants (timing, amount of EVN contribution).

• Future fuel costs, cost of power purchases.

• Other operating costs by entity.

• Information of Other JVs (total cost, EVN’s share, expected return)

Further details of the inputs are given in Annex 3.

8.5.2.3 Outputs The main outputs are:

• Financial statements and performance indicators for each entity.

• Consolidated financial statements and performance indicators for Core Business.

• Consolidated financial statements and performance indicators for EVN as a whole.

• Sensitivity results.

• Internal transfer prices.

8.5.2.4 Results The User Guide for the Business Model is given in Annex 4.

8.6 Financial Management Capability of EVN/ATD3

8.6.1 Introduction

This Section describes the financial management capability of EVN to deal with the proposed ADB loans for the Song Bung 4 Hydropower Project. It addresses some of the financial management issues and requirements associated with the proposed loans, and whether EVN has the necessary capability to manage the proposed loans in a satisfactory way to meet ADB requirements.

The analysis has been divided into two parts; the arrangements for receiving and repaying the loan by EVN, and the monitoring and control of expenditure financed within EVN.

ADB plan to make the proposed loan direct with EVN, rather than with the MoF. This implies that the procedures for receiving, and more importantly repaying the loan will be different


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from previous loans, where the MoF was responsible for making timely repayments of interest and principal to ADB. Instead this responsibility will now fall on EVN.

The ADB Financial Management Assessment Questionnaire was used as the basis for obtaining the information together with information obtained when doing similar assessment in the Northern Power Project Management Board in 2005. The questionnaire is given in Annex 5.

8.6.2 Executing and Implementing Agency

EVN, the Executing Agency for the proposed loan, was founded by decision no 562/TTG dated 10 October 1994 issued by the Prime Minister, and Government decrees 14/CP dated 27 January 1995, and is under the direct control of the Prime Minister and competent State Management Agencies. EVN is a vertically integrated electricity utility responsible for:

• The production, transmission, and supply of electricity.

• The design and construction of projects.

• The manufacture of electrical equipment.

• Providing related services to customers.

EVN is an independent legal entity acting as a holding company overseeing various business units, consisting of 15 independent accounting entities, 20 dependent accounting units, 14 construction/management boards, six administrative units and subsidiaries where EVN holds more than 50% of the voting power.

The table below lists major projects managed by EVN: Summary of Major Projects Managed by EVN

Project Loan External Financiers

Amount

($Million)

Year

Power Distribution and Rehabilitation Project ADB $80.00 1995

Central and Southern Viet Nam Power Distribution ADB $100.00 1997

Northern Power Transmission Sector Project ADB $120.00 2004

Phu My Thermal Power Plant Project JBIC ¥61,932.00 1993–1998

Pha Lai Thermal Power Plant Project JBIC ¥72,826.00 1993–1998

Ham Thuan-Da Mi Hydropower Project JBIC ¥53,074.00 1993–1997

Da Nhim Power System Rehabilitation Project JBIC ¥7,000.00 1996

O Mon Thermal Power Plant and Mekong Delta Transmission Network Project

JBIC ¥43,819.00 1997–2002

Dai Ninh Hydropower Project JBIC ¥14,030.00 1998–2002

Phu My-Ho Chi Minh City 500 kV Transmission Line Project

JBIC ¥13,127.00 2000

Transmission and Distribution Project WB $199.00 1998

Rural Energy Project WB $150.00 2000

System Energy, Equitization and Renewable Energy Project

WB $225.00 2002


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The Implementing Agency for the proposed ADB loan will be Hydropower Project Management Board No. 3 (ATD3) in Da Nang, a project management unit within EVN that is responsible for the development of hydropower projects in Central Vietnam. ATD3 reports to EVN’s Vice President for Generation Construction.

ATD3 is an administrative unit of EVN formed in accordance with Decision No 176 NL/TCCB-LD dated 1 April 1991 by the former Ministry of Energy (now MoI). Later on it was renamed to ATD3 with decision no 361 DV/TCCB-LD dated 27 May 1995, and Decision 295 /QD-EVN-HDQT dated 13 November 2002 by EVN.

ATD3 is authorized by EVN to carry out project management of new hydropower plants in Central Vietnam from the initial stages of river resource planning, pre-investment work, and construction until the plant becomes operational.

The principle activities of the finance department of ATD3 are:

• Obtaining detailed information on planned source of investment capital (including funds from State Budget, EVN, loans and donors) for each investment, and using these funds according to the investment loan plan.

• Recording the cost of the actual work done.

• Reviewing and monitoring ATD3’s compliance with the State Standard and Regulation for construction and investment, and monitoring the management and usage of materials and assets.

• Authorizing payments to the contractors.

• Preparing financial statement for senior management and other relevant agencies.

• Preparing and submitting a report when the project is completed.

• Controlling the internal finances of ATD3.

The following table summarizes the main projects ATD3 has worked on: Summary of Major Projects Managed by ATD3

Name of Project Main Donor Value Status

Song Hing SIDA 1860 bn VND Yes

A Vuong JBIC 3 860 bn VND Ongoing

Song Ba Ha Chinese bank 3 715 bn VND Ongoing

An Khe – Kanak 3 755 bn VND Ongoing

Song Tranh 2 4 152 bn VND Ongoing

EVN and ATD3 have experience of implementing major investment projects funded by international donors. Since its inception in 1995, ATD3 has managed several projects funded by international donors, including SIDA and JBIC. In addition it has managed other investment projects funded by EVN. Similar project management boards manage other investments in generation, transmission and distribution projects in other parts of Vietnam.

ATD3 can provide related services, such as construction supervision of hydropower and transmission projects, appraisal and evaluation of cost estimates for power projects, consulting services in preparation of bidding documents, and evaluation of bids.

The following is an organizational chart of ATD3:


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Director Tran Van Hai

Department of Environment & Resettlement

Deputy Director Tran Ngoc An

Technical Department

Deputy Director Le Duong Thuan

Department of Investments in HP (Vu Gia Thu Bon

rivers) Deputy Director Nguyen Van Le

Department of Investments in HP

(Song Ba) Deputy Director Dang Van Tuan

Project Department Nguyen Van

Chuang

Planning & Economic

Department Trinh The Dung

Organisation-administrative

Department Vu Duc Toan

Finance & Accounting

Department Le Nhu Thiep

Materials & Equipment Department

Nguyen Van Son

ATD3 is registered under IS09001 since 2004.

8.6.3 Flow of Funds

There are two planned sources of funds for the proposed investment; ADB and EVN. The funds from each source will be used to fund the following activities.

Type of Expenditure ADB EVN

Equipment packages procurement by ICB √ Direct purchase packages (Foreign equipment) √ Civil works packages (ICB) √ Local overheads, project preparation, administration √ International consultants (ICB) √

Local consultants √ √

Resettlement costs √

Contingency √ √ Interest during construction (ADB Loan) √ Taxes √ √

Disbursements of ADB loan for civil works and equipment procured under ICB, direct purchase and LCB will be through direct payment procedures in accordance with ADB’s Loan Disbursement Handbook. Payment for other services funded by ADB will be via a local impress account held by EVN HQ (and not under the control of ATD3). Payments to be funded by EVN will be via a dedicated bank account under the control of ATD3, funded by EVN HQ.

The following diagram shows the expected flow of funds from EVN and ADB:


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Figure 8-4 Funds Flow Arrangements

EVN HQ HPPMB3 Taxes

EVN'sretained Project Overheadsearnings Bank a/c etc

ExpensesFunded by EVN

Impress Local account Expenses

funded by ADB

SupplierADB Funded by ADB

Cash flows Co-ordination

Foreign and local equipment procured by either ICB or LCB under the loan will be paid directly by ADB after approval from EVN (who will be advised by ATD3). For local works to be paid for under the ADB loan, EVN HQ (and NOT ATD3) will establish and control an impress account. EVN (at ATD3’s behest) will request payments from ADB into this account as required, depending on expected phasing of this expenditure. ATD3 will be responsible for checking invoices etc, and requesting payments from this account, but EVN HQ would actually make the payments. For expenditure not covered by the ADB loan, ATD3 will establish a separate bank account into which EVN will transfer the necessary funds as required. ATD3 would make payments from this account as necessary.

8.6.4 Repaying the Loan

EVN intend to establish a new company, Song Bong 4 Hydropower Company (SB4HPC) to own and run the Song Bung 4 Hydropower Plant. The proposed ADB loan would appear on SB4HPC’s balance sheet, but the exact form depends on the future legal status of SB4HPC. If it is an independent entity (similar to Cao Tho) with EVN owning all the shares, then an internal on lending agreement between EVN and SB4HPC will probably be required, since ADB’s agreement will be with EVN and not SB4HPC. However, if SB4HPC is equitised like other power plants, then the loan could appear directly on SB4HPC’s balance sheet. Either way, SB4HPC would be responsible within EVN for repaying the loan and the interest.

SB4HPC will have to repay the loan via the income it receives from selling its electricity in the proposed bulk power market. Although some work has been done on designing and developing this market, it is not functioning at present and is unlikely to do so for another year or so due to delays in establishing the necessary communication systems.


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The ability of SB4HPC to repay the loan depends on many factors, including:

• Setting of cost reflective end user tariffs that will enable EVN to recover sufficient money to cover all its costs. Without this (and assuming no Government subsidy) some parts of EVN will not have enough money to cover their costs.

• Setting cost reflective bulk supply tariffs. It is important that the price paid by distribution companies covers the cost of supplying bulk power; otherwise there will be insufficient money to pay all suppliers.

• SB4HPC must be allowed to set a cost reflective tariff for selling its bulk electricity that will cover not only the operating costs, but also the debt servicing costs. This tariff needs to be robust enough to provide sufficient income in dry years. Also some adjustment mechanism to the tariff to compensate for any adverse change in the VND/USD rate of exchange.

• The whole system must be liquid in the sense that distribution companies must collect all the money that is owed to them in a prompt and timely way. Also there need to be a proper functioning settlements system in place between the various distribution and power companies.

It would be appropriate for ADB to include a covenant in the proposed loan agreement saying that ADB requires to see the proposed charter of the new SB4HPC before it is enacted, and also review any proposed on-lending agreement between EVN and SB4HPC.

8.6.5 Staffing

ATD3 currently has around 100 employees, with specialists in engineering, environmental, resettlement, economic and finance. The Director, Mr Tran Van Hai, is in overall responsibility for ATD3, and reports to EVN’s Vice President for General Construction. The head of ATD3’s finance and accounting department, Mr Le Nhu Thiep, reports direct to Mr Hai, Director of ATD3, and he has one deputy. The accounting section is responsible for record keeping and the production of reports. The finance section is responsible for identifying the sources of funds, signing contracts, and making disbursements. The finance department has a total of 8 staff plus.

Most of ATD3’s financial staff are accountants or economists trained to record the various transactions incurred by ATD3 in implementing its projects. Most of the senior accounting staff worked in other parts of EVN before transferring to ATD3. The following table summarizes the qualifications of the senior ATD3 financial staff:

Head of Finance Deputy Manager (Finance)

Name Le Nhu Thiep Nguyen Dinh Phuc

Age, years 41 35 Qualification BA Finance BA Economics Time in present post, years

19 15

Previous work None None Source: Finance Department, ATD3

Written specific job descriptions for each position exist, and four are given in Annex 6. Detailed day-to-day work and priorities is determined by the head of Finance or his deputy. The staff work to the detailed rules, procedures and methodologies set by the GoV (and issued by the MoI and MoF) regarding the keeping of accounts.


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ATD3 finance staff claim that they have sufficient staff to carry out all their tasks and meet deadlines. Most of the staff has Vietnamese accounting, finance, and economic or similar degree qualification. The ATD3 finance staff has considerable experience of working with projects funded by donor loans, and senior staff are familiar with the needs of such organizations. No specific training scheme or program exists for ATD3 finance staff. Some staff attended a course run by ADB at Hoi An earlier in the year.

No specific or formal anti-corruption or conflict of interest measures exist within EVN or ATD3. ATD3 employees can report any suspicions to the Inspectorate department who will investigate and report back. Vietnamese law expects people who suspect others of participating in corrupt practices to report them to the “appropriate” authorities. ATD3 (and EVN) follows the GoV system of adequate safeguards to protect State owned assets from fraud, waste, abuse, and corruption. Measures taken include the issue of the Anti-corruption Ordinance dated 26 February 1998. The Ordinance defines the corruption activities, and prescribes rights and responsibilities of the Standing Committee of the National Assembly, State Management Agencies, and other organizations in detecting corruption. Solutions for preventing and detecting corruption, and penalties for corruption, are also included. This legislation - coupled with the determination and strictness of law enforcement agencies in recent corruption cases - has restored some degree of confidence in the law and justice systems regarding anti-corruption measures.

All additions or amendments to ATD3’s payroll have to be approved by the director of ATD3.

8.6.6 Accounting Policies

EVN is required by GoV to comply with the Vietnamese Accounting Standards (VAS). Accordingly, EVN has adopted, for all its business units, uniform accounting policies and procedures, documentation of transactions, and charts of accounts suitable to power sector. EVN’s system is designated as a “mixed” accounting system whereby: (i) centralized accounts are maintained for the generation and transmission of electricity (including for the Project); (ii) distribution companies are independent accounting units, and; (iii) consolidation of accounts take place only at the EVN level as a whole. The consolidated accounts are later converted to IAS.

EVN and ATD3 implement GoV accounting policies and procedures that ensure that costs allocations to the various funding sources can readily be identified. This system allows for the proper recording of project financial transactions, including the allocation of expenditures to the respective cost components, disbursement categories, and sources of funds. Controls are in place concerning the preparation and approval of transactions. The systems used are adequate to properly account and report on project activities and disbursement categories. ATD3 use EVN’s recently introduced computerized finance system which means it should be easily possible to reconcile the General Ledger at EVN and subsidiary ledgers at ATD3. All the accounting and supporting documents are retained by ATD3 on a permanent basis.

The Director of ATD3 has full authorization to execute all transactions under the projects. The Financial Director delegates authorities to his deputy and finance and account staff to prepare the recording of the transactions, including the custody of assets involved in the transactions. Project management staff orders and monitors all goods and services, and all payments are prepared by account staff. Bank reconciliation is prepared by account staff and approved by the Director of ATD3.

ATD3 has prepared 61 manuals relating to the control of their work, and these are given in Annex 7. ATD3 plan to issue further ones dealing with the specific requirements of the planned ADB loan.


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8.6.7 Budgeting System and Payments

EVN and ATD3 have proven experience in the efficient management, budgeting, and disbursement of funds in previous projects. The Project’s budgets, including physical and financial targets, will be prepared in sufficient detail for all significant activities under each project component. The actual expenditures should be compared to the budget at least on a quarterly basis, and explanations prepared for significant variations from the budgets. The procedures are in place to plan project activities, collect information from EVN and ATD3. Historically, project plans and budgets have been realistic, having been based on valid assumptions, and developed by knowledgeable individuals (ADB staff, consultants, EVN and ATD3 staff). Approvals for budget variations should be obtained in advance, though the facility for retrospective authorization does exist in Vietnamese regulations. ATD3 can approve deviations of up to 30 billion VND, and any amount over this needs EVN approval.

EVN has implemented the following invoice-processing procedures. Project management staff prepares copies of purchase orders and contracts, and receive dispatch and delivery notes. The project management staff and accounting staff check invoices for ATD3, account staff compares invoice quantities, prices and terms, with those indicated on the purchase order and with records of goods and services actually received and check the accuracy of calculations. Sometimes ATD3 employs a bank to check the details of invoices supplied by foreign companies, particularly to check that taxes, duty, shipping costs, insurance and other costs are consistent with the contract. Information on approvals etc is not recorded on the invoice itself, but in a separate file. ATD3 claims the computer system makes it is impossible for an invoice to be paid twice. However, this system makes it difficult for somebody who is not very familiar with ATD3’s systems to audit a particular payment. All the relevant paper work is stored as required under Vietnamese law.

Each year ATD3 staff prepares a budget of the likely work that they are responsible for, taking into account the overall project timetable, work done to date, remaining funds and priority and critical items. This is then sent to EVN for approval, and the resulting budget forms the plan for that year, and is the basis against which actual progress and expenditure is made.

8.6.8 Policies and Procedures

ATD3 and EVN follow Vietnamese Accounting Standards (VAS). EVN has an adequate policy and procedures manual to guide activities and ensure staff accountability. In March 1998, ADB worked with MOF in developing a manual entitled “Manual on Project Accounting and Disbursement Procedures under ADB Financed Project.” EVN uses this manual and updates as necessary in accordance with the changes required by ADB and GOV. The procedures exist to ensure that only authorized persons (MOF) can alter or establish a new accounting principle, policy or procedure to be used by EVN and ATD3. The written policies and procedures have covered all routine financial management and related administrative activities.

ATD3 uses EVN’s new computerized finance system (developed with WB funding) to record all transactions. This is a sophisticated system that allows invoice details to be input, payments to be authorised and management reports produced. Summary information is transferred electronically to EVN HQ on a monthly basis

The adequacy of the existing accounting policies and financial procedures for EVN and its business units has been assessed by the World Bank7 in light of the VAS and International Accounting Standards (IAS). A comparison of major accounting policies between VAS and

7 World Bank, 1997, Project Appraisal Document for Viet Nam: Transmission, Distribution, and

Disaster Reconstruction Project


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IAS shows that, for most part, the Business Accounting Policies promulgated by MoF for all Vietnamese enterprises and adopted by EVN, conforms with IAS. However, it should be noted that certain policies are still at variance with IAS, particularly: (i) accounting for foreign currency/translation, (ii) fixed asset capitalization, (iii) fixed asset depreciable amount, rate, and method, (iv) amortization of intangible assets, (v) amortization of organization expenses, (vi) long-term investment, (vii) reporting requirement, (viii) accounting frameworks, and (ix) audit. EVN prepares its annual financial statements in accordance with IFRS/IAS and that these are audited in accordance with ISA.

8.6.9 Cash and Bank

The Director of ATD3 and the Deputy Director of Finance are the authorized signatories in the bank accounts. There is no income or receipts directly associated with the project and so no need to review procedures for depositing monies. EVN has its own established procedures and mechanisms for collecting money from end users in payment of their electricity bills

Bank statements are reconciled every month by the deputy head of finance and the appropriate ATD3 project manager. All unusual items on the bank reconciliation are reviewed and approved where appropriate by the ATD3 Director and the Finance Director.

8.6.10 Safeguard over Assets

ATD3 is responsible only for implementing the Projects. Once complete the hydropower plant is handed over to another part of EVN who will be responsible for its operation and maintenance.

8.6.11 Reporting

EVN and ATD3 are able to maintain separate accounts for the Project. ATD3, through EVN, will need to submit regular progress reports to ADB on a quarterly basis. The reports should provide a narrative of progress made during the period, changes in the implementation schedule, problems or difficulties encountered, and the work to be carried out in the next period. The progress reports should also include a summary financial account for the investment component, consisting of project expenditures during the period year to date, and total expenditure to date. The quarterly progress reports should be submitted to ADB within one month of the end of each quarter8. ATD3 should be able to prepared these financial reports automatically from their finance system, but some assistance will probably be required initially to ensure the reports are providing the necessary information and that all the information balances.

In addition to the quarterly reports, within six months of the close of the financial year, ATD3 through EVN should submit to ADB annual audited accounts of EVN, and annual audited financial statements of the Project. The annual project accounts should contain detailed descriptions of the fund sources and expenditures. The annual financial statements of EVN should consist of an income statement, balance sheet, cash flow statement, and related notes to financial statements. The annual financial statements will be a consolidated of all EVN’s operations. ADB will review the implementation and operation of the Project based on these reports and meet with EVN, ATD3 and the GOV annually to discuss project progress. A project completion report (PCR) should be submitted to ADB within three months of project completion.

ADB loan funds and local counterpart funds are transferred to EVN to carry out the Project.

8 EVN’s progress reports for previous projects have been submitted on time and the quality of these reports was adequate


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Although ATD3 is not a separate stand-alone company, it produced its own annual financial reports. Its balance sheet is incorporated on EVN’s consolidated balance sheet. When ATD3 procures new assets for a particular project, these are added to ATD3’s balance sheet. When a project is complete, the assets associated with the Project are removed from the ATD3’s balance sheet and transferred to EVN’s entity (or entities) that will operate and maintain the Project.

8.6.12 Internal Audit and External Audit

Financial statements of EVN and ATD3 are currently audited annually by independent auditors. Experiences from the previous projects indicated that there were no delays in the audit of EVN and ATD3 since 1999. The audit reports are normally issued annually on 31 May. The audit of EVN was conducted mostly in accordance with the International Standards on Auditing for public institutions.

During 2001, EVN discovered that certain costs were improperly included as part of construction in progress as at 31 December 2000. This led to the financial statements for 2000 being restated. In 2002, EVN revalued some of its power station assets. The external auditors commented that this revaluation was against IAS principles because any revaluation should be applied to the whole class of assets, and not just a sub set. This revaluation increased the value of assets by about 3,000 billion VND. Otherwise the auditors have made no significant qualification to EVN’s accounts during the last five years. The external auditors have commented that generally EVN, and all of its units keep, their accounts in a proper manner consistent with Vietnamese laws and regulations. The auditors have commented on that the units of EVN have improved the speed with which they produce their accounts over the last few years, and that fewer management letters have noted improved procedures in recent years with fewer significant internal control issues identified, while the number of qualified audit opinions has been reducing.

EVN established its Internal Audit Department in March 1998. It is headed by a chief of internal audit supported by five professional accountants. Currently, EVN relies heavily on direct supervision, detailed reporting, and authorization from top management for internal control. This internal audit ensures proper checks and balances and delineation of responsibilities. Internal reviews are conducted as follows: (i) inspection on compliance with EVN policies and GOV rules and regulations are done by the Inspection Department with a team composed of selected representatives from the various business units, (ii) inspections for certain activities of business units by an “ad hoc” inspection team selected by the Director General, (iii) accounting supervision by the Finance and Accounting Department team, and (iv) inspections by the Management Board and by the Control Section of the Board. Inspections are conducted based on the guidelines of the GOV and focused on the reviews of plans, expenditures, contracts and compliance. ATD3 has not yet been subject to an internal audit report.

The consolidated financial accounts of EVN are submitted to the Ministry of Industry (MOI), MOF and Tax Department for review and approval. MOF audits are used to determine tax liabilities, scheduled payments of “state-rented” capital, and other financial matters. The revision committee of the Ministry of Finance has the right to audit any part of EVN, but so fat ATD3 has not been subject to such an audit.

EVN prepared financial statements of its previous projects in accordance with Vietnamese’s Accounting Standard (VAS). Simple financial statements are prepared by ATD3 system on monthly basis and the reporting should be adopted to report on this Project. Although it could be useful to try to link physical progress with financial progress so as to predict estimated completion date and total cost, to a large extent this is not necessary. Most contracts let by ATD3 are fixed cost contracts where the contractor is paid a predetermined amount when he completes a specific amount of physical work. Only in exceptional circumstances is it


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necessary to amend the contact because of unforeseen circumstances.

Financial reports clearly compare the actual expenditures with budgeted and programmed allocations. The financial reports are prepared by automated accounting systems using spreadsheets and other proper computerized programs. Under the current accounting system, all EVN’s dependent units, including ATD3, prepare and submit monthly accounting, financial statements and other financial reports to EVN. Independent accounting units on the other hand submit their reports quarterly. EVN’s Accounting Department reviews the reports prior to submission to EVN’s Management Board for consolidation. EVN’s computerized accounting system, while currently in use, is still under evaluation and improvements are being introduced as necessary. Financial statements prepared by ATD3 focus on maintaining separate records and accounts adequately. It could identify goods and services financed from the proceeds of the loan, the other financing resources received, the expenditures incurred in the Project, audit of resettlement expenditures, and the uses of local funds. ATD3 has used the computerized financial management system that can produce the necessary project financial reports. EVN’s and ATD3’s finance and account staff has been adequately trained to maintain the systems. The management organization and processing system have safeguarded the confidentiality, integrity and availability of the data.

EVN will need to prepare terms of reference acceptable to ADB for the annual project audit. The auditing company should inspect and substantiate the accuracy and sustainability of accounting documents and figures, and other accounting finalization reports kept by EVN and ATD3.

8.6.13 Conclusion and Recommendations

In general ATD3 appears as a fit and proper body to administer the propose ADB loan for the Song Bung 4 Hydropower Project. In general the assessment identified no weak points. The staff will require training in ADB procedures, but they should have little difficulty in understanding and implementing these. Two minor points were identified:

• Although the computer system is backed up on a regular basis, the backups themselves are stored on ATD3’s premises, rather than on a remote site

• ATD3 has no specific experience of administering an ADB loan and it could be useful if somebody from a PMB that has ADB loan experience (e.g. NPPMB) could visit them to discuss the details of administering the loan.

Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report Main Report - Annex 1

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Annex 1

EVN’S HISTORICAL FINANCIAL STATEMENTS


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Balance sheets

bn Dong 31/12/1998 31/12/1999 31/12/2000 31/12/2000 31/12/2001 31/12/2002 31/12/2003 31/12/2004Assets (restated)

Non-current assetsFixed assets 18213.36 18747.19 23716.11 23716.11 30914.52 45082.39 49121.67 56064.55Construction in progress 10738.89 17807.39 22103.52 20971.16 15926.11 9069.96 10983.85 12704.29Deferred tax assets 609.70 304.80Investments in Associates 119.08 197.80Other non-current assets 42.94 122.28 139.60 4157.04 4364.05 4534.76 4900.95 4964.93Total 28995.19 36676.85 45959.23 48844.31 51204.68 58687.12 65735.25 74236.36

Current assetsBank balances and cash 4.00 5306.47 6693.53 6693.53 7653.08 10791.67 12855.32 12232.24Trade and other receivables 5467.38 3919.57 2619.07 2619.07 2665.28 4075.45 5748.96 7395.68Inventories 3952.14 5123.20 5392.14 1374.70 1731.36 2298.71 2859.22 3777.41Other current assets 709.51 513.82 503.87 503.87 670.29 463.36 518.11 797.95Total 10133.04 14863.07 15208.61 11191.17 12720.01 17629.18 21981.62 24203.28

TOTAL ASSETS 39128.22 51539.92 61167.84 60035.48 63924.69 76316.30 87716.87 98439.65

Equity and LiabilitiesEquity

Capital & fundsCapital 24073.52 25503.64 26542.23 26073.46 26831.34 28729.63 32698.53 35540.12Fixed assets revaluation reserve 3154.31 3154.31 3689.37Funds and reserves 1108.85 1399.19 1761.32 1761.33 1850.625 2012.34 1875.42 1721.76Undistributed profit 17.06 187.88 62.57 62.57 65.20 279.36 (979.15) (410.63)Total 25199.43 27090.71 28366.12 27897.36 28747.16 34175.64 36749.11 40540.63

Minority Interest 22.35 57.14

Long term borrowing 12824.69 19064.11 25565.18 25565.18 26601.32 32644.79 39349.76 45308.56

Curent liabilitiesTrade and other payables 4544.31 4290.35 5112.56 5217.00 6843.02 7717.75 8670.97 8917.60Short term loans 44.84 43.96 68.29 68.29 112.84 136.35 146.70 391.96Current portion of LT borrowings 10.41 494.22 1287.65 1287.65 1620.35 1641.77 2777.98 3223.76Other current liabilies 585.97 556.57 768.04Total 5185.54 5385.10 7236.54 6572.94 8576.21 9495.87 11595.65 12533.32

TOTAL EQUITY & LIABILITIES 43209.65 51539.92 61167.84 60035.48 63924.69 76316.30 87716.87 98439.65

Profit and Loss Statements

bn Dong 1998 1999 2000 2001 2002 2003 2004

Net sales from operations 13472.73 14121.58 16510.35 19209.71 23565.52 30245.65 34530.17Cost of sales (10913.54) (10929.89) (13574.15) (15958.78) (19068.00) (21886.66) (26452.00)Gross profit 2559.19 3191.69 2936.21 3250.93 4497.53 8359.00 8078.17Selling expenses (204.96) (253.99) (335.70) (405.11) (476.77) (655.35) (747.66)General & administration expenses (577.58) (644.50) (673.53) (904.70) (1092.02) (1302.31) (1501.40)Net operating profit 1776.65 2293.19 1926.97 1941.12 2928.73 6401.33 5829.11Other profit/(loss) - net (217.94) (559.90)Other income 271.03 552.84 580.48 729.20 892.30Other expenses (800.81) (366.22) (378.75) (4249.70) (1780.60)Profit from operations 1558.72 1733.30 1397.20 2127.74 3130.46 2880.83 4940.80Finance cost (587.28) (782.64) (1032.42) (1312.99)Profit before tax 1558.72 1733.30 1397.20 1540.46 2347.82 1848.41 3627.81Corporate income tax (535.14) (644.83) (514.48) (541.46) (676.30) (19.92) (296.49)Profit after tax 1023.58 1088.46 882.72 999.01 1671.53 1828.49 3331.33


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Cash Flow Statement

bn VND 1998 1999 2000 2000 2001 2002 2003 2004(Restated)

Cash flows from operating activitiesProfit before tax 1558.72 1733.30 1397.20 1397.20 1540.46 2347.82 2880.82 4940.80Adjustment for

Depreciation 3121.71 3988.50 4462.05 4462.05 5134.51 7056.00 8375.51 8084.73Interest expense 365.27 405.86 550.40 550.40 587.28 782.64Gain from sale of fixed assets (1.23) (4.00) (2.27) (2.27) 6.51 (8.68) (3.22) (28.58)Loss on foreign exchange 100.87 520.69 153.69 153.69 245.90 313.59 3087.96 1500.43Allowance for slow stock etc 55.72 41.93 30.05 30.05 (90.93) (34.90) (1.82) (10.51)Allowance for bad debts (6.30) 33.47 (10.45) (10.45) (11.28) 32.81 (0.10) (18.37)Sub total 5194.76 6719.74 6580.67 6580.67 7412.45 10489.28 14339.15 14468.49

(Increase)/decrease in receivables 5122.33 1514.35 1310.95 1310.95 (34.93) (1375.27) (1643.30) (1628.35)Increase/(decrease) in inventories (931.15) (1212.99) (298.99) (24.13) (265.73) (600.16) (875.45) (1068.13)Deacrease/(increase) in other current assets (202.77) 195.69 9.95 9.95 (166.42) 161.83 (22.62) (67.28)Increase/(decrease) in payables (10892.48) (287.34) 947.81 913.91 1258.22 1342.06 844.18 1004.39Increase/(decrease) in other currrent liabilities (110.10) (82.17) 208.88Increase in non current assets (292.18) (207.00) (170.72) (7.98) (138.29)Interest paid (317.78) (353.09) (547.81) (547.81) (577.65) (769.86) (1015.50) (1282.54)Corportation income tax paid (670.89) (611.46) (640.09) (640.09) (678.99) (664.04) (714.65) (633.94)Sub total (8002.84) (837.01) 990.70 730.59 (672.50) (2076.16) (3435.32) (3814.13)

Net cash flow from operating activities (2808.07) 5882.73 7571.37 7311.25 6739.94 8413.12 10903.83 10654.35

Cash flow from investing activitiesAcquisition of fixed assets (1716.46) (4898.14) (9601.60) (13869.47) (9218.51) (9930.01) (13347.61) (16298.00)

Increase in investment accounts (192.67) 24.29Proceeds from disposal of fixed assets 449.46 379.80 172.91 172.91 11.89 14.575 18.24 41.52Disbursement for construction in progress (3263.76) (7068.50) (4510.67)Purchase of other non-current assets (9.02) (79.34) (17.33)

Net cash flow from investing activities (4539.78) (11666.17) (13956.68) (13696.56) (9206.62) (9915.43) (13522.03) (16232.18)

Cash flow from financing activitiesLoans obtained* 7295.61 7092.63 8865.79 8865.79 6131.63 6507.86 6336.86 8184.73Repayment of loans* (890.96) (1486.12) (1486.12) (3224.29) (2040.83) (1687.24) (3190.02)Capital injections 1822.60 3154.93 2568.24 2568.24 568.28 281.31 110.16 80.78Other increase in funds + undisbursed profit 23.26 23.26 0.44Capital asset reduction+ to State budget (1118.02) (1724.81) (1835.40) (1835.40) (49.83) (107.44) (79.10) (120.74)Disbursement of funds for intended use (610.28) (318.26) (1.13) (1.13)Disbursement of profit (381.45) (309.04) (362.28) (362.28)Interest payment

Net cash flow from financing activities 7008.46 7004.49 7772.37 7772.37 3426.23 4640.90 4680.70 4954.75

Net increase/decrease in cash (339.39) 1221.05 1387.05 1387.06 959.56 3138.59 2062.49 (623.08)

Cash at start of year 4424.82 4.00 5306.47 5306.47 6693.53 7653.08 10791.67 12855.32Cash at end of year 4.00 5306.47 6693.53 6693.53 7653.08 10791.67 12855.32 12232.24

Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report Main Report – Annex 2

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U:\Documents and Settings\MMJ\My Documents\SEID\PRADEEP\FINAL DEC 2006-NO TRACKS\Main Report\Business Model.doc 04/09/2007

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Annex 2

DETAILS OF EVN’S BUSINESS MODEL


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Outline The model is build up from a number of small models of individual entities as follows:

• Large Power companies - PC Dong Noi, PC Hoa Duong, PC HCMC, PC Hanoi, PC Hai Phong, PC Ninh Binh.

• Small Power Companies - 58 provincial level PCs that are planned to be equitised – 25 in region formerly covered by PC1, 20 in region formerly covered by PC2 region, and13 in region formerly covered by PC 3. (PC1, PC2, PC3 are referred to as parent PC). Note that there is no specific modelling of PC1, PC2 or PC3.

• EVN Power Plants – each of the existing and planned 87 EVN power plant is modelled separately. These include those that are never to be equitised (Hoa Binh, Tri An, Yaly, collectively referred to as the “3 HPPs”), new or existing plants that might be equitised, and JVs where EVN will be the major shareholder (referred to as EVN JV Power Plants).

• Non-core activities. – EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co and Consulting (PECC1, PECC2, PECC3, PECC4 combined) are each modelled separately.

• Transmission Entity – Combination of the existing four power transmission entities.

Each of the above entities initially modelled as a stand-alone separate entity, in which EVN initially holds all of the shares. This is not meant to represent the actual legal structure of each entity, but rather it is a convenient and realistic way of modelling each entity in a similar way (developing a separate model for each of the above 166 entities would be impossible). These entities are then successively aggregated as shown in diagram and at each aggregation inter entity transfers are eliminated. All profit attributed to EVN as a shareholder of the modelled entity is assumed to remain as retained profit.

EVN JV Power Plants, where EVN is the majority shareholder are modelled as if they are an EVN entity that is to be equitised in 2005, with the % to be equitised being equal to the non-EVN shareholding1. Other JVs, where EVN is the minority shareholder, are not specifically modelled, but EVN’s shareholding and share of its profits are incorporated in the consolidated results. In the remaining part of this documentation, unless otherwise clarified, Other JV refers to a power plant in which EVN is the minority shareholder.

Each entity is modelled on its own worksheet, and these are then aggregated as follows:

• Power Companies – sum of results of all 64 PCs (no consolidation)

• Main EVN PP– sum of results of all Main EVN PP plus EVN JVs (no consolidation)

• 3 HPPs – sum of results of Hoa Binh, Tri An and Yaly (no consolidation)

• Non-core Business – aggregate of EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co and Consulting (PECC1, PECC2, PECC3, PECC4 combined) (no consolidation)

• Note that Transmission still remains a separate entity at this stage.

1 From a modelling point of view this is fine for JVs where EVN will hold the majority of shares, since these assets will appear on EVN’s consolidated balance sheet and the partners shares will be a minority interest. In the case of JVs where EVN is the minority shareholder, a different approach is required since here the assets should NOT appear on EVN’s balance sheet, but EVN’s share of the profit from these JVs will appear in the P&L as share of profit from other sources.


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• Single Buyer – consolidation of results from Transmission, 3 HPPs and the inclusion of power purchases from Other JVs, IPPs and imports.

• Core Business – consolidation of results from Single Buyer, Power Companies and Main EVN PP.

• EVN Consolidated – consolidation of Core Business and Non-core Business. It is at this stage that the equitisation proceeds, GoV capital injections, EVN’s contribution to, and its share of profit from, Other JVs are included.

The generation schedule is in terms of output from units, and Power stations can be composed of a number of specified units (eg Units Uong Bong 1 & 2 are combined to form one entity).

The following diagram illustrates the relationship between the entities and their aggregation and consolidation.

Existing EVN PP

New EVN PP

EVN JVs

Yaly

Tri An

Hoa Binh

Transmission

6 Large PCs

58 Small PCs

EVN Telecomm

Thu Duc Co

Equip Man Co

4 PECCS

EVN Consolidated

Total Non-core

Power companies

Single Buyer

3 HPPsCore Business

Main EVN PP

Energy Balance The starting point for estimating future demand is energy balances prepared by IoE. Unfortunately these do not go into the necessary detail and so some extrapolation is necessary

Three sets of data are used:


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• Estimates of regional (North, Central and South) sales by main category, losses, self-consumption and total generation for 2005, 2010 and 2015.

• Actual sales in each of the 64 PCs in 2005.

• Annual gross production in each year 2006-2012 given in the generation schedule.

It is assumed that these are all internally consistent and that there is no unsatisfied demand; in particular the expected generation in years for which there are no sales forecasts is just sufficient to cover demand in those years, once losses etc have been taken into account.

Estimate sales (and losses) (by category and by region) in intermediate years by assuming constant growth.

Apply respective regional annual growth rates for each customer category to the actual 2005 sales for each customer category in each PC.

Estimate distribution losses for each PC (based on specified distribution loss for each PC).

Add distribution losses to total sales to give total requirement for each PC.

Add transmission losses to distribution requirement (based on loss % given in IoE energy balance).

Add self consumption (either global figure given in IoE balance or calculated from plant specific self consumption data).

This gives the gross generation requirements.

Pro rata all data (sales, losses, self consumption) to match output in generation schedule.

Capital Expenditure The model divides EVN’s existing and future assets into different categories to reflect the different characteristics (from financial modelling point of view) of these assets

• HV transmission

• LV distribution

• Thermal power plants (TPP)

• Hydro power plants (HPP)

• EVN Telecom

• Other Non-core entities

In some cases these are further split as follows:

• HV transmission - 500 kV, 220 kV and 110 kV

• LV distribution - LV distribution networks and LV rural electrification.

• Other Non-core entities – investments in Thu Duc Co, Equipment Manufacturing Co, Consulting

Capital expenditure is funded by four possible sources: USD loans, VND loans, capital injections into EVN, and EVN’s own resources. The calculation of loan repayments and interest payments are modelled in a conventional way. The difference between the capital expenditure and the total amount borrowed in loans in a particular year is assumed to be a capital injection into the relevant entity by EVN ie EVN’s own contribution plus any capital (ie GoV) injection into EVN is assumed to be an EVN injection into the modelled entity, and appears as additional equity for that entity.


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Equitisation The equitisation of an entity is modelled as follows:

Assume x% (which is <50%) is to be equitised in year N. Then at the end of year N, x% of the total equity in the entity (ie sum of EVN equity, retained profits, other funds, revaluation fund) is split (1-x%) to EVN, and x% to other shareholders, and the retained profits, other finds, revaluation fund set to zero.

In this (and subsequent year), y% of profits after tax is distributed as dividends to shareholders (and shown in P&L statement), and the remaining profit retained by the entity as retained profits. Dividends to non-EVN Shareholders are assumed to be paid in cash, whereas the dividend to EVN is assumed to remain within EVN at the consolidation level

After equitisation, further capital injections to finance the CAPEX program are assumed to be split between EVN and the new shareholders.

This reallocation of equity in the year of equitisation can be difficult to see in the model because other adjustments are made at the same time, so the following illustrates what occurs.

Bal

ance

at e

nd o

f Ye

ar N

-1

Re

allo

catio

n of

eq

uity

due

to

equi

tisat

ion

Cap

ital i

njec

tions

(To

finan

ce C

APEX

)

Allo

catio

n of

reta

ined

pr

ofits

Bal

ance

at e

nd o

f ye

ar N

EquityEVN Equity bn VND 500.0 480.0 +60.0 540.0Other shareholders bn VND 0.0 320.0 +40.0 360.0Total share capital bn VND 500.0 800.0 +100.0 0.0 900.0Retained profits bn VND 100.0 0.0 50.0 50.0Other funds bn VND 100.0 0.0 0.0Revaluation reserve bn VND 100.0 0.0 0.0Total equity bn VND 800.0 800.0 100.0 50.0 950.0

Adjustments

The first column shows the equity part of the balance sheet at the end of year N-1.

The second column shows the result of equitising 40% of the entity in year N (EVN retains 60% of total equity, new shareholders obtain 40%).

The third column shows new capital injections required under the financing assumptions to finance CAPEX in year N. Total injection of 100 bn VND is required in this example.

The fourth column shows the allocation of retained profit (the dividend payments have already been deducted from then profit in the P&L statement)

The fifth column shows the resulting equity part of the balance sheet at the end of Year N.

The proceeds from equitisation are incorporated in the EVN consolidated financial statements, not in the entity’s financial statement.

Rates of Exchange and Inflation The model works primarily in VND, but some costs are expressed in USD and it is necessary to convert these into appropriate VND. There are 3 factors at work

USD inflation – the change prices expressed in USD due to USD inflation


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VND inflation - the change in prices expressed in VND due to VND inflation

VND/USD exchange rate – this can either mirror changes in USD and VND inflation or there might be a real change in the exchange rate (ie a change that can not be accounted for purely in terms of changes in USD and VND inflation rates. At present it is assumed there is no real change in exchange rates

Exchange rate in year i (RoEi ) = RoEi-1 * (1+real change in exchange rate in year i)*(1+USD inflation in year i)/(1+VND inflation in year i). This is used to convert USD costs to VND in year i


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Financial Statements (Individual Entities) The following tables summarise the way the P&L and balance sheets for each type of entity are complied. Items highlighted in bold italic font are parameters than can be changed (see later) Profit & Loss Power companies Existing power plants New power plants Transmission Non Core

Main Income Tariff * sales Selling price to Single buyer * net output

Selling price to Single buyer * net output

Assumed to equal total costs

Annual increase in sales

Other income % of main income Zero Zero Zero 2004 actual % of main income

O&M 2004 actual % of Gross asset value

2004 actual % of Gross asset value

HPP - 0.67% of gross asset value TPP – 2.5% of Gross asset value

1.5% of gross asset value

EVN Telecom - 20% annual increase Other – 8% annual increase

Selling costs 2004 actual % of total sales

Zero Zero Zero 2004 actual % of total sales

Admin costs 2004 actual % of total sales


Power purchase Bulk supply tariff * total requirement

N/a N/a Transmission losses * average cost of bulk electricity

N/a

Fuel costs N/a HPP – n/a TPP – gross output * fuel burn (units/GWH) * unit fuel price

N/a N/a

Hydro tax N/a HPP – Gross output * hydropower tax TPP – n/a

N/a N/a

Depreciation % of gross asset value


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Profit & Loss Power companies Existing power plants New power plants Transmission Non Core

Foreign exchange losses /gains

Increase/decrease in closing value of USD loans (both new and existing) at year end

Interest Calculated on average of opening and closing balances of for new loans+ actual values for existing loans

Corporate tax % of gross profit

Dividends For equitised entities, profit after tax * % Equitised, otherwise zero N/a N/a

Balance sheet Power companies Existing power plants New power plants Transmission Non Core

Cash Calculated from cash flow statement

Receivables from outside EVN

Total sales * delay in non-EVN customers paying

N/a N/a N/a Total sales from non-EVN sources* delay in non-EVN customers paying

Receivables from inside EVN

N/a

Total sales * delay in paying for bulk power Total sales from EVN sources * delay in paying for bulk power2

Inventories % of gross asset value

Other current assets

2004 value (ie no change)

Fixed assets Gross asset value – accumulated depreciation

2 Note these do not appear as payables within EVN on other entities balance sheets.


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CIP New CAPEX + any IDC is recorded under CIP for duration of construction period, then transferred to Fixed Assets

New CAPEX + any IDC is recorded under CIP until completion of construction, then transferred to Fixed assets


New CAPEX + any IDC is recorded under CIP for duration of construction period, then transferred to Fixed assets


Construction materials


Other non current assets


Payables – outside EVN

(O&M + selling + admin costs) * delay in paying other costs

HPP - (O&M + hydro tax) * delay in paying other costs TPP – (O&M * delay in paying other costs) + (fuel cost * delay ion paying fuel costs)

O&M * delay in paying other costs


Payables – inside EVN

Power purchase costs * delay in paying for bulk power

N/a Power purchase costs * delay in paying for bulk power

N/a

Short term Loans 2004 value (ie no change)

Current portion of LT loans

For year N, calculate repayments for Year N+1

LT Loans Total loans (new existing, USD, VND) - Current portion of LT loans

Other Lt Liabilities


EVN Share capital

EVN’s assumed share capital in entity, plus any EVN capital injections for CAPEX minus any shares sold under equitisation process

Other share capital

Equitised shares plus any proportion of capital injection from new shareholders to finance CAPEX


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Retained profits Profit from P&L

Other reserves 2004 value (ie no change)

Revaluation reserve


2004 balance sheet data

For large PCs the appropriate balance sheet data for 2004. The 2004 balance sheets for PC1, PC2 and PC3 are adjusted for the transferred of 110 kV assets to transmission (see later)3 For small PCs, either balance sheet data for 2004 prepared for equitisation process, or pro rated from adjusted balance sheet for parent PC

2004 balance sheets. Payables to EVN are adjusted to match known loans. 2004 Balance sheet data for some small power plants (3 diesel plants, Can Tho, Dray Hling, Na Loi, Nam Mu, Ry Ninh, Srok Phu Mieng, Suoi Sap, Suoi Vang, Thu Duc) is not yet available and so these are included in transmission

Zero Residual of 2004 consolidated balance sheet is assigned to Transmission. That is balance sheet items that can not be allocated either to a large PCs, PC1, PC2 or PC3, an existing power plant , EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co PECC1, PECC2, PECC3, or PECC4 is included in transmission4.

As per appropriate 2004 balance sheets

3 Note there is an inconsistency here. For PC1, PC2 and PC3 110 kV assets are transferred to transmission, but remain on balance sheets of Large PCs. However the model assumes all new CAPEX in 110 kV is in transmission and not split between large PCs and transmission 4 Note that the balance sheet data for power plants for which not individual balance sheet data has been provided are included here eg balance sheet data for list of plants given in existing power plant s column will appear in transmission.


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Financial Statements (Consolidated Entities) Profit & Loss Single Buyer Core business EVN Consolidated

Main Income Sales of bulk power to PCs Power Company Core business + non core business

Other income None Power Company Core business + non core business

Power purchases Power purchases from Other JVs, IPPs and imports

Single Buyer Core business

O&M O & M costs of Transmission + 3 HPPs O&M costs of Power Companies, Main EVN PP, Single Buyer

Core business + non core business

Selling costs % of total income Power Companies + Single Buyer Core business + non core business

Admin costs Transmission + 3 HPPs Power Companies + Single Buyer Core business + non core business

Fuel costs N/a Main EVN PP Core business

Hydro tax Single Buyer + Main EVN PP Core business

Depreciation Transmission + 3 HPPs Power Companies + Main EVN PP + Single Buyer



Transmission + 3 HPPs Power Companies + Main EVN PP + Single Buyer


Interest Transmission + 3 HPPs Power Companies + Main EVN PP + Single Buyer


Profit from JVs N/a N/a Total cost of Other JV *EVN’s share of Investment in Other JV * EVN’s expected return


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Profit & Loss Single Buyer Core business EVN Consolidated

Corporate tax % of profit % of profit % of profit

Dividends N/a Power Companies + Main EVN PP Power Companies + Main EVN PP

Balance sheet Single Buyer Core business EVN Consolidated

Cash Calculated from cash flow


% of sales


None None

Inventories Transmission + 3 HPPs Power companies + Main EVN PP + Single Buyer

Core Business + Non Core Business


Transmission + 3 HPPs Power companies + Main EVN PP + Single Buyer


Fixed assets Transmission + 3 HPPs Power companies + Main EVN PP + Single Buyer


CIP Transmission + 3 HPPs Power companies + Main EVN PP + Single Buyer









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None None

Short term Loans Transmission + 3 HPPs Power companies + Main EVN PP + Single Buyer





LT Loans Transmission + 3 HPPs Power companies + Main EVN PP + Single Buyer


Other LT Liabilities



EVN Share capital



Other share capital



Retained profits From P&L From P&L From P&L

Other reserves Transmission + 3 HPPs Power companies + Main EVN PP + Single Buyer


Revaluation reserve




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Transmission + Hoa Binh + Tri An + Yaly balance sheet data

EVN Consolidated accounts – balance sheet data for EVN Telecom, Thu Duc Manufacturing Co, Equipment manufacturing Co, PECC1, PECC2, PECC3, PECC4

EVN 2004 Consolidated accounts

Song Bung 4 Hydropower Project, TA No. 4625-VIE Second Interim Report Volume I: Main Report

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U:\Documents and Settings\MMJ\My Documents\SEID\PRADEEP\FINAL DEC 2006-NO TRACKS\Main Report\Data Input Business Model.doc 04/09/2007

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Annex 3

DATA INPUT FOR EVN’S BUSINESS MODEL


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Data Requirements in Work sheet “BASE DATA”

Worksheet Parameters Item Description Comments Financing CAPEX - 500 kV, 220 kV, 110 kV transmission, LV distribution network, LV rural electrification program, HPP, TPP, EVN Telecom, other Non-core entities(Thu Duc, Equipment Manufacturing Co, Consulting ) % of total expenditure % of total CAPEX for a particular

investment payable in USD Remaining % of CAPEX is assumed to be in local currency

Financing Source of money to fund CAPEX • % by foreign (USD) loans • % by local (VND) loans • % by equity injections into

EVN

Remaining % of CAPEX Is assumed to be financed from EVN internal sources. Capital injections into EVN by GoV only appear in EVN consolidated statement. Elsewhere they are included in EVN’s contribution

Interest rate Interest rate for local and foreign loans

Capitalise IDC? = Yes – capitalise IDC. = No - Do not capitalise IDC (ie assume IDC is included in P&L)

For HPP and TPP, IDC is capitalised over the whole construction period of the plant For HV and LV lines, IDC is capitalised over the Construction Period for those lines

Construction Period Period over which IDC on HV and LV lines is capitalised.

Only applies to CAPEX on HV and LV lines and CAPEX in non-core entities. Construction period for new power plants is calculated from CAPEX data.

Depreciation – HV transmission (500 kV, 220 kV, 110 kV), LV distribution (includes rural electrification), HPP, TPP, EVN Telecom, Non-core Depreciation Depreciation period in years for

different categories of fixed asset Depreciation is calculated as a % of gross fixed assets at start of year for each category of asset.

O & M costs – HV transmission (500 kV, 220 kV, 110 kV), LV distribution (includes rural electrification), HPP, TPP O & M costs O & M cost (expressed as a % of

asset value) O & M cost is calculated as a % of adjusted fixed assets for each category of asset.

Financial information Real change in VND/USD Exchange rate

Real change in USD/VND rate over and above changes due to inflation


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Item Description Comments VND Inflation Annual inflation rate of VND prices Only directly used to inflate VND component of CAPEX and to

calculate exchange rate. At present it is also used to index other user defined data (Hydro tax, end user tariffs, bulk supply tariff)

USD Inflation Annual inflation rate of USD prices Only directly used to inflate USD component of CAPEX and calculate future exchange rates.

Exchange rate Actual exchange rate in 2005 and 2006

Used to seed exchange rate calculation. Assumes all USD costs are in 2005 USD terms

Tariffs End user tariffs Expected average end user tariff

in each year for each main consumer category (excluding VAT)

At present it is index linked to VND inflation, but this can be removed by entering specific values

Other parameters Hydro tax Hydro tax payable on output from

HPPS (2006 value in VND/kWh) At present it is index linked to VND inflation, but this can be removed by entering specific values

Losses % losses for each large PC in each year

Losses expressed as a % of total supply to each PC (ie if total supply is 100 units, and losses are 5 units, then losses are 5/100 =5%, (and NOT 5/95=5.26%).

Stocks Amount of stocks of materials etc held by each entity

Expressed as a % of total asset value. Used to calculate inventory line in balance sheet

Delay in non EVN customers paying

Average period (in months) for non-EVN customers to pay

Used to calculate receivables for Power Companies and non-core entities

Delay in paying fuel Average delay in EVN power stations paying for fuel

Used to calculate payables for power plants.

Delay in paying other costs Average delay in paying for all other cash operating costs (O&M, Hydro tax)

Used to calculate payables for all entities.

Delay in paying for bulk power Delay in inter entity payments within EVN

Delay in inter EVN payments (primarily bulk power, but also payments from core to non-core entities)

Tax rate Profits tax rate All profits are taxed at this rate. Rate of return Expected rate of return on

investments Used to calculate selling price of electricity for each power plant, to give this return on gross asset value, and the bulk supply tariff for PCs, assuming this return on assets.


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Item Description Comments Power market costs Cost of operating power market

(as a % of total power market sales)

Cost to single buyer entity

EVN Telecom annual sales/cost increase

Annual increase in sales and operating costs of EVN Telecom

Used to calculate EVN Telecom’s income and costs

Non Core annual sales/cost increase

Annual increase in sales and operating costs of non-core entities

Used to calculate income and costs of non-core entities

% of sales from inside EVN % of sales for each non-core entity from other EVN entities

Used to calculate consolidated income and costs by eliminating inter company payments between core and non-core entities.

Use specified plant specific self consumption data?

Determines whether to apply average self consumption data to all generation sources, or use plant specific ones

Yes = use plant specific ones (self consumption data should be entered for all sources in worksheet “power station data”). The calculated self consumption is then used in energy balance (see worksheet “actual demand”) No = Use average self consumption data specified in energy balance (note output from imports and other non EVN source will be reduced)

Worksheet PC Data Item Description Comments 2005 sales data for each PC Sales in GWh by major customer

group This data is the starting point for sales forecasts

Worksheet - DISCOM Equitisation This contains the data on planned equitisation of each PC.

For each of the 58 PCs that is planned to be equitised enter (if known)

• Planned equitisation data

• % to be equitised

• Simplified balance sheet information (AS AT 31/12/2005) (Note a value for all items must be entered ie do not leave any cell blank; instead enter 0.0).


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• Planned capital expenditure data in each future year (Split by LV distribution network and LV rural electrification)

If the data of planned equitisation is unknown, enter a date after 2012

If balance sheet data is unknown or unavailable leave all balance sheet items blank

The model calculate averages 2004 balance sheet data for any PC where actual 2004 balance sheet data for that PC is not available or specified as follows:

The starting point is the adjusted balance sheet for PC1, PC2 and PC3; Actual balance sheets adjusted for removal of 110 KV assets, which are assumed to be transferred to Transmission – see 110 kV adjust work sheet

Subtract the known balance sheet information from the relevant parent PC balance sheet.

Allocate the remaining balance sheet items for PC1, PC2 and PC3 equally (not on any pro rata basis but just by dividing the remainder by the number of PCs for which there is no balance sheet information) among the remaining PCs that formed PC1, PC2 and PC3 respectively

Capital expenditure

A similar procedure is used to estimate the future CAPEX of each PC based on the total CAPEX for PC1, PC2 and PC3

Notes.

(1) Only enter 31/12/04 balance sheet data for each PC here. If later balance sheet data for a particular PC becomes available, then you need to enter this in the relevant work sheet in the work book “power Companies”

(2) Rows 6 to 69 store actual balance sheet data and CAPEX. Rows 101 to 158 is where the data that is transferred to the model is calculated. Check balance sheets balance by looking down column AE for red cells (any red cells in rows 101-158 are almost certainly the result of leaving one or more balance sheet item blank instead of entering 0.0)

(3) There are some small errors in the balance sheet data provided by EVN for some equitised PCs and small adjustments have been made to some data to get it to balance

Worksheet Bulk Supply Tariffs Item Description Comments Bulk supply tariff f Price (in VND/kWh) that each PC

purchases its bulk electricity from single buyer

At present it is index linked to VND inflation, but this can be removed by entering specific values.


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Worksheet CAPEX Item Description Comments HV Lines Expected total capital expenditure

(in M USD) on 500 kV, 220 kV and 110 kV

CAPEX estimates should exclude IDC and be in 2005 USD terms. All 110 kV CAPEX is assigned to HV transmission.

LV Lines Expected total capital expenditure (in M USD) on LV distribution network and LV rural electrification

CAPEX estimates should exclude IDC and be in 2005 USD terms. This data is not required if specific estimates are available for individual PCs

Large PCs and PC1, PC2 and PC3

Either enter % of total LV distribution CAPEX attributable to each PC, or specific CAPEX for each large PC , PC1, PC2 and PC3

CAPEX estimates should exclude IDC and be in 2005 USD terms. CAPEX data for equitised PCs is entered in worksheet Discom equitisation

Other entities Expected total CAPEX for each non-core entity

CAPEX estimates should exclude IDC and be in 2005 USD terms.

Worksheet Sensitivities Item Description Comments Sensitivity Select appropriate sensitivity 1- Base case

2- 10% reduction in end user demand 3- 1 year delay in completing new power plants due to come on

stream after 2008 (note that phasing of capital expenditure on these delayed power plants is the same as the base case, as is phasing of expenditure on HV and LV lines)

4- Output from HPPS reduced in years 200x, 200y, 200z by 20%

Note: Scenario 2, 3 and 4 are currently not available due absence of appropriate generation schedule

Worksheet 110 kV Adjust This worksheet adjusts the 2004 balance sheets for PC1, PC2 and PC3 by removing 110 kV assets and transferring them to transmission


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Item Description Comments 110 kV assets Gross value of 110 kV assets on

2005 balance sheet (in bn VND) At present estimated from length of line (km) and number of transformers (data obtained from EVN annual report) and estimated unit cost of new assets).

PC1, PC2, PC3 Balance sheets (2004)

Simplified balance sheet data for PC1, PC2 and PC3 as at 31/12/04

110 kV adjust Enter changes to balance sheet required to remove 110 kV Asset

In the absence of actual data, the following is assumed Adjustment to Gross value : as calculated in 110 kV assets Adjustment to depreciation: pro rata to balance sheet value It is assumed these 110 kV assets were financed by LT loans and equity, which are reduced pro rata.

Transmission balance sheet (2004)

Simplified balance sheet for transmission as at 31/12/2004

Adjustments to PC1, PC2 and PC3 balance sheets added to transmission balance sheet Note: existing 110 kV assets for Large PCs are not added to transmission, but new 110 kV assets in these regions are assigned to transmission

Worksheet Generation Scenarios This worksheet contains the generation schedule for each scenario Item Description Comments Total generated volume Planed gross output (GWh) from

each power plant, JV, IPP and imports in each year for each scenario

Data to be provided by IoE for scenarios 2, 3 and 4 Gross output (before self consumption and own use) Do not change order of power plants

Worksheet Power Station Equitisation Item Description Comments Equitisation date Year in which the power station is

planned to be equitised Include JVs where EVN is the majority shareholder here with an equitisation date of 2005.

% % of equity to be equitised


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Worksheet Power Station Data Item Description Comments Location Region where power plant is

located For information only not required

Type of enterprise Identify type of enterprise EVN 1 – only use for Hoa Binh, Tri An and Yaly. (ie plants that are never to be equitised and consolidated with transmission in single buyer entity EVN 2 - include all other EVN plants including JVs where EVN will be the major shareholder JVs – EVN JV plants where EVN will be a minority shareholder IPPs - Other power plants in which EVN has no financial interest Imports – imports for neighbouring countries Each Power Plant must be categorised Only select one type for each plant If a power plant has been wrongly categorised, then please contact either Pham Ngoc Thang or Bill Pemberton before making any changes here

Type of plant Enter 1 in appropriate column Only select one type for each plant If an EVN power plant has been wrongly categorised, then please contact either Pham Ngoc Thang or Bill Pemberton before making any changes here

Fuel burn Fuel consumption to generate 1 GWh of electricity

Must be consistent with type of plant (eg if type of plant is gas, then enter gas burn; DONOT also enter the fuel burn for reserve fuel) Only enter data for EVN plants Different sources of coal and gas can have different prices

Self consumption data % of gross output required for self consumption

Make sure “Use specified plant specific self consumption data?” switch on parameter worksheet is set to yes if data is entered. Self consumption data (including zero if necessary) should either be entered for all sources, or non entered and average self consumption used instead. Using average self consumption data specified in energy balance applies to all sources (including imports and other non-EVN sources)

Bulk electricity selling price Price (USD/kWh) obtained by selling electricity to singe buyer

Determines income of each power plant 2005 USD prices


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Item Description Comments Capital expenditure Planned capital expenditure in

each year for each source Exclude IDC In 2005 USD terms Data only required for EVN power plants

Worksheet Fuel Costs Item Description Comments Fuel costs Expected price of each type of fuel

in future years. Expressed in 2005 USD terms Fuel categories correspond to those in work sheet “power station data” Note: Gas price is price per 000 m3.

Worksheet Joint Ventures Enter data here for JVs where EVN is the minority shareholder. Item Description Comments Name Name of JV EVN’s % contribution % of total capital supplied by EVN Expected return EVN’s expected annual return on

its investment

Start production The year the JV is expected to start production

Determines when EVN starts receiving income from the JV

Total cost Total cost of JV in each year Include all pre 2004 capital expenditure in 2004 column

Worksheet Base Regional Demand Base regional demand data forecasts used to calculate future demand for each PC.

Worksheet Actual Demand Calculates actual demand for each customer category in each year for each PC, taking into account available generation.

Worksheet Exist Foreign Loans Details of all existing foreign loans converted to USD (as at 01/01/05). Data obtained from former ICM module, and each loan allocated to one or more modelled entities. Data included outstanding loan, future loan repayments, future interest payments and IDC


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Worksheet Exist VND Loans Details of all existing VND loans (as at 01/01/05). VND. Data obtained from former ICM module, and each loan allocated to one or more modelled entities. Data included outstanding loan, future loan repayments, future interest payments and IDC

Worksheet 2004 Accounts Breakdown of EVN’s 2004 financial statements

Worksheet EVN Telecom Financial statements for EVN telecom entity

Worksheet Thu Duc Financial statements for Thu Duc Manufacturing Co entity

Worksheet Equip Man Co Financial statements for Equipment Manufacturing Co entity

Worksheet Consulting Financial statements for Consulting entity.

Worksheet Transmission Financial statements for Transmission entity.

Worksheet Power Companies Summary financial statements for all 64 Power Companies combined.

Worksheet Main EVN PP Summary financial statements for all EVN owned Power Plants except the 3 HPPs combined.

Worksheet 3 HPPS Summary financial statements for Hoa Binh, Tri An and Yaly combined


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Worksheet Single Buyer Financial statements for the Single Buyer Entity

Worksheet Core Business Summary financial statements for the Core Business entity

Worksheet Total Non-core Summary financial statements for EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co and Consulting (PECC1, PECC2, PECC3, PECC4 combined) combined.

Worksheet EVN Consolidated Summary financial statements for the whole of EVN.

Worksheet Summary Summary of key operating parameters of EVN Consolidated

Song Bung 4 Hydropower Project, TA No. 4625-VIE Second Interim Report Volume I: Main Report

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Page I-12


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Annex 3

DATA INPUT FOR EVN’S BUSINESS MODEL


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Data Requirements in Work sheet “BASE DATA”

Worksheet Parameters Item Description Comments Financing CAPEX - 500 kV, 220 kV, 110 kV transmission, LV distribution network, LV rural electrification program, HPP, TPP, EVN Telecom, other Non-core entities(Thu Duc, Equipment Manufacturing Co, Consulting ) % of total expenditure % of total CAPEX for a particular



EVN




For HPP and TPP, IDC is capitalised over the whole construction period of the plant For HV and LV lines, IDC is capitalised over the Construction Period for those lines


Only applies to CAPEX on HV and LV lines and CAPEX in non-core entities. Construction period for new power plants is calculated from CAPEX data.

Depreciation – HV transmission (500 kV, 220 kV, 110 kV), LV distribution (includes rural electrification), HPP, TPP, EVN Telecom, Non-core Depreciation Depreciation period in years for


O & M costs – HV transmission (500 kV, 220 kV, 110 kV), LV distribution (includes rural electrification), HPP, TPP O & M costs O & M cost (expressed as a % of


Financial information Real change in VND/USD Exchange rate



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Item Description Comments VND Inflation Annual inflation rate of VND prices Only directly used to inflate VND component of CAPEX and to

calculate exchange rate. At present it is also used to index other user defined data (Hydro tax, end user tariffs, bulk supply tariff)









Losses % losses for each large PC in each year

Losses expressed as a % of total supply to each PC (ie if total supply is 100 units, and losses are 5 units, then losses are 5/100 =5%, (and NOT 5/95=5.26%).






Delay in paying fuel Average delay in EVN power stations paying for fuel

Used to calculate payables for power plants.





Tax rate Profits tax rate All profits are taxed at this rate. Rate of return Expected rate of return on

investments Used to calculate selling price of electricity for each power plant, to give this return on gross asset value, and the bulk supply tariff for PCs, assuming this return on assets.


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Item Description Comments Power market costs Cost of operating power market

(as a % of total power market sales)












Yes = use plant specific ones (self consumption data should be entered for all sources in worksheet “power station data”). The calculated self consumption is then used in energy balance (see worksheet “actual demand”) No = Use average self consumption data specified in energy balance (note output from imports and other non EVN source will be reduced)

Worksheet PC Data Item Description Comments 2005 sales data for each PC Sales in GWh by major customer

group This data is the starting point for sales forecasts

Worksheet - DISCOM Equitisation This contains the data on planned equitisation of each PC.

For each of the 58 PCs that is planned to be equitised enter (if known)

• Planned equitisation data

• % to be equitised

• Simplified balance sheet information (AS AT 31/12/2005) (Note a value for all items must be entered ie do not leave any cell blank; instead enter 0.0).


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• Planned capital expenditure data in each future year (Split by LV distribution network and LV rural electrification)

If the data of planned equitisation is unknown, enter a date after 2012

If balance sheet data is unknown or unavailable leave all balance sheet items blank

The model calculate averages 2004 balance sheet data for any PC where actual 2004 balance sheet data for that PC is not available or specified as follows:

The starting point is the adjusted balance sheet for PC1, PC2 and PC3; Actual balance sheets adjusted for removal of 110 KV assets, which are assumed to be transferred to Transmission – see 110 kV adjust work sheet

Subtract the known balance sheet information from the relevant parent PC balance sheet.

Allocate the remaining balance sheet items for PC1, PC2 and PC3 equally (not on any pro rata basis but just by dividing the remainder by the number of PCs for which there is no balance sheet information) among the remaining PCs that formed PC1, PC2 and PC3 respectively

Capital expenditure

A similar procedure is used to estimate the future CAPEX of each PC based on the total CAPEX for PC1, PC2 and PC3

Notes.

(1) Only enter 31/12/04 balance sheet data for each PC here. If later balance sheet data for a particular PC becomes available, then you need to enter this in the relevant work sheet in the work book “power Companies”

(2) Rows 6 to 69 store actual balance sheet data and CAPEX. Rows 101 to 158 is where the data that is transferred to the model is calculated. Check balance sheets balance by looking down column AE for red cells (any red cells in rows 101-158 are almost certainly the result of leaving one or more balance sheet item blank instead of entering 0.0)

(3) There are some small errors in the balance sheet data provided by EVN for some equitised PCs and small adjustments have been made to some data to get it to balance

Worksheet Bulk Supply Tariffs Item Description Comments Bulk supply tariff f Price (in VND/kWh) that each PC




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Worksheet CAPEX Item Description Comments HV Lines Expected total capital expenditure


CAPEX estimates should exclude IDC and be in 2005 USD terms. All 110 kV CAPEX is assigned to HV transmission.

LV Lines Expected total capital expenditure (in M USD) on LV distribution network and LV rural electrification

CAPEX estimates should exclude IDC and be in 2005 USD terms. This data is not required if specific estimates are available for individual PCs

Large PCs and PC1, PC2 and PC3

Either enter % of total LV distribution CAPEX attributable to each PC, or specific CAPEX for each large PC , PC1, PC2 and PC3

CAPEX estimates should exclude IDC and be in 2005 USD terms. CAPEX data for equitised PCs is entered in worksheet Discom equitisation

Other entities Expected total CAPEX for each non-core entity

CAPEX estimates should exclude IDC and be in 2005 USD terms.

Worksheet Sensitivities Item Description Comments Sensitivity Select appropriate sensitivity 1- Base case

2- 10% reduction in end user demand 3- 1 year delay in completing new power plants due to come on

stream after 2008 (note that phasing of capital expenditure on these delayed power plants is the same as the base case, as is phasing of expenditure on HV and LV lines)

4- Output from HPPS reduced in years 200x, 200y, 200z by 20%

Note: Scenario 2, 3 and 4 are currently not available due absence of appropriate generation schedule

Worksheet 110 kV Adjust This worksheet adjusts the 2004 balance sheets for PC1, PC2 and PC3 by removing 110 kV assets and transferring them to transmission


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Item Description Comments 110 kV assets Gross value of 110 kV assets on

2005 balance sheet (in bn VND) At present estimated from length of line (km) and number of transformers (data obtained from EVN annual report) and estimated unit cost of new assets).

PC1, PC2, PC3 Balance sheets (2004)

Simplified balance sheet data for PC1, PC2 and PC3 as at 31/12/04

110 kV adjust Enter changes to balance sheet required to remove 110 kV Asset

In the absence of actual data, the following is assumed Adjustment to Gross value : as calculated in 110 kV assets Adjustment to depreciation: pro rata to balance sheet value It is assumed these 110 kV assets were financed by LT loans and equity, which are reduced pro rata.

Transmission balance sheet (2004)

Simplified balance sheet for transmission as at 31/12/2004

Adjustments to PC1, PC2 and PC3 balance sheets added to transmission balance sheet Note: existing 110 kV assets for Large PCs are not added to transmission, but new 110 kV assets in these regions are assigned to transmission

Worksheet Generation Scenarios This worksheet contains the generation schedule for each scenario Item Description Comments Total generated volume Planed gross output (GWh) from

each power plant, JV, IPP and imports in each year for each scenario

Data to be provided by IoE for scenarios 2, 3 and 4 Gross output (before self consumption and own use) Do not change order of power plants

Worksheet Power Station Equitisation Item Description Comments Equitisation date Year in which the power station is

planned to be equitised Include JVs where EVN is the majority shareholder here with an equitisation date of 2005.

% % of equity to be equitised


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Worksheet Power Station Data Item Description Comments Location Region where power plant is

located For information only not required

Type of enterprise Identify type of enterprise EVN 1 – only use for Hoa Binh, Tri An and Yaly. (ie plants that are never to be equitised and consolidated with transmission in single buyer entity EVN 2 - include all other EVN plants including JVs where EVN will be the major shareholder JVs – EVN JV plants where EVN will be a minority shareholder IPPs - Other power plants in which EVN has no financial interest Imports – imports for neighbouring countries Each Power Plant must be categorised Only select one type for each plant If a power plant has been wrongly categorised, then please contact either Pham Ngoc Thang or Bill Pemberton before making any changes here

Type of plant Enter 1 in appropriate column Only select one type for each plant If an EVN power plant has been wrongly categorised, then please contact either Pham Ngoc Thang or Bill Pemberton before making any changes here

Fuel burn Fuel consumption to generate 1 GWh of electricity

Must be consistent with type of plant (eg if type of plant is gas, then enter gas burn; DONOT also enter the fuel burn for reserve fuel) Only enter data for EVN plants Different sources of coal and gas can have different prices

Self consumption data % of gross output required for self consumption



Determines income of each power plant 2005 USD prices


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Item Description Comments Capital expenditure Planned capital expenditure in

each year for each source Exclude IDC In 2005 USD terms Data only required for EVN power plants

Worksheet Fuel Costs Item Description Comments Fuel costs Expected price of each type of fuel

in future years. Expressed in 2005 USD terms Fuel categories correspond to those in work sheet “power station data” Note: Gas price is price per 000 m3.

Worksheet Joint Ventures Enter data here for JVs where EVN is the minority shareholder. Item Description Comments Name Name of JV EVN’s % contribution % of total capital supplied by EVN Expected return EVN’s expected annual return on

its investment




Worksheet Base Regional Demand Base regional demand data forecasts used to calculate future demand for each PC.

Worksheet Actual Demand Calculates actual demand for each customer category in each year for each PC, taking into account available generation.

Worksheet Exist Foreign Loans Details of all existing foreign loans converted to USD (as at 01/01/05). Data obtained from former ICM module, and each loan allocated to one or more modelled entities. Data included outstanding loan, future loan repayments, future interest payments and IDC


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Worksheet Exist VND Loans Details of all existing VND loans (as at 01/01/05). VND. Data obtained from former ICM module, and each loan allocated to one or more modelled entities. Data included outstanding loan, future loan repayments, future interest payments and IDC

Worksheet 2004 Accounts Breakdown of EVN’s 2004 financial statements

Worksheet EVN Telecom Financial statements for EVN telecom entity

Worksheet Thu Duc Financial statements for Thu Duc Manufacturing Co entity

Worksheet Equip Man Co Financial statements for Equipment Manufacturing Co entity

Worksheet Consulting Financial statements for Consulting entity.

Worksheet Transmission Financial statements for Transmission entity.

Worksheet Power Companies Summary financial statements for all 64 Power Companies combined.

Worksheet Main EVN PP Summary financial statements for all EVN owned Power Plants except the 3 HPPs combined.

Worksheet 3 HPPS Summary financial statements for Hoa Binh, Tri An and Yaly combined


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Worksheet Single Buyer Financial statements for the Single Buyer Entity

Worksheet Core Business Summary financial statements for the Core Business entity

Worksheet Total Non-core Summary financial statements for EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co and Consulting (PECC1, PECC2, PECC3, PECC4 combined) combined.

Worksheet EVN Consolidated Summary financial statements for the whole of EVN.

Worksheet Summary Summary of key operating parameters of EVN Consolidated

Annex 4

Business Model of EVN

User Guide

July 2006

Asian Development Bank Electricity of Vietnam

Song Bung 4 Hydropower Project, TA No. 4625-VIE

SWECO IPA Energy Consulting

Song Bung 4 Hydropower Project, TA No. 4625-VIE Business Model – User Manual

SWECO InternationalIPA Energy Consulting

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1 Overview

The main driver for the model is the demand forecast defining how much electricity different categories of consumer require, and the associated capital expenditure and generation schedule to meet this demand. The information given in the draft Master Plan VI is planned to be used since this gives the latest demand forecasts and associated investment plan and generation schedule. The links between demand, capital expenditure program and generation schedule are complex and these will not be modelled within the existing business plan. Instead the demand forecasts, capital expenditure plan and generation schedule will be assumed fixed. In order to perform sensitivity analysis on these key variables, various different scenarios will be included (e.g. 10% reduction in demand, 1 year delay in capital expenditure program). From this information an energy balance can be obtained and this will be used to determine the expected revenues and cost of generating, transmitting and distributing this electricity.

The main modules in the model are as follows:

• Distribution Companies. PC Dong Noi, PC Hoa Duong, PC HCMC, PC Hanoi, PC Hai Phong, PC Ninh Binh, PC1, PC2, PC3, and PC Khank Hoa are modelled separately. Unless otherwise stated, PC3 refers to the original PC3 but excluding PC Khank Hoa.

• Power Stations. Each existing and planned EVN power station, including JVs where EVN has a majority shareholding (referred to as “EVN JV Power Stations”, to distinguish them from other JV where EVN is a minority shareholder), is modelled separately. It is assumed that each Power Station sells its electricity to the Single Buyer entity.

• Single Buyer entity. This entity serves two purposes in the proposed model. First, it acts as single buyer of electricity by buying electricity from all EVN power stations (including EVN JV PP), Other JVs, IPPs, and imports, and then selling bulk electricity to each Power Company. Second, it operates the HV transmission network, and the Base PP (eg Hoa Binh, Tri An and Yaly) that are planned to stay in total EVN ownership1. The costs of the Single Buyer are the cost of buying electricity from other Power Stations, the cost of operating the HV transmission network, and the operating costs of Base PP.

In addition there are simple modules for the non-core businesses: Telecom, the Electrical and Mechanical Manufacturing Companies, and the Consulting Companies.

Figure 1 illustrates the main cash flows between the various modules

1 There is a implicit assumption that only HPPs can be Base PPs.



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Figure 1: Summary of Main Cash Flows between Entities

Equitisation Dividends Proceeds Dividends

Non Core Businesses Operating Costs

egWages,

Materials,Services,Finance

costs.

EVN Single10 Buyer of

End Power Electricity EVNUsers Companies (Including Equitised

HV Transmission and Coaland Base PP) EVN JV Gas

Power OilStations

IPPs +Imports

Other JVs

Customers

Loans, loan repayments

The main cash flows are for the core business. End users pay the Power Company for the electricity supplied and used. The Power Company in turn pays its own operating costs (e.g. wages, materials, interest on money it has borrowed). It also pays the Single Buyer for the supply of bulk electricity. The Single Buyer then pays all the Power Stations for the electricity they have generated at the appropriate tariff. The EVN Power Stations use this money to pay for the fuel (coal, etc) and their own operating costs.

Also shown are the expected flows from the core activities to the non-core businesses, which will also have their own customers for their services and products, and their own operating costs. Some of their income will come from the core business entities in EVN.

The cash flows of loans to finance the capital expenditure program of each entity, and the interest and loan repayments are also shown

Equitisation proceeds from the sale of shares in equitised Power Companies and Power Stations, and Non-EVN contributions to EVN JVs flow into EVN (represented here by the Single Buyer) These Entities will also pay dividends to their shareholders. EVN will also receive a proportion of the profits from Other JVs it has invested in.

It is important to realize the limitations of such a model. EVN is a large and complex organization, with many separate entities, each of which is a significant business in its own right. The model is by necessity an approximation of EVN’s actual operations.



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The model requires a lot of data initially to seed the model, some of which is readily available, or only available with considerable effort. Where relevant data is not readily available, sensible estimates have been used until more accurate data become available.



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2 Key Inputs

The key inputs to the model are:

• End–user demand, capital expenditure plan, generation schedule (from Master Plan VI).

• Financing of capital expenditure (split of expenditure by foreign and local currency, % of financing by loans, interest rate, repayment period).

• Planned equitisations (entity, timing, expected % to be equitised).

• Future end-user tariffs by major category.

• EVN Joint Ventures Power Stations (timing, amount of EVN contribution).

• Future fuel costs, cost of power purchases.

• Other operating costs by entity.

• Information of Other JVs (total cost, EVN’s share, expected return)

Further details of the inputs are given in the Annex.



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3 Main Outputs

The main outputs are:

• Financial statements and performance indicators for each entity.

• Consolidated financial statements and performance indicators for Core Business.

• Consolidated financial statements and performance indicators for EVN as a whole.

• Sensitivity results.

• Internal transfer prices.



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4 Outline

The model is build up from a number of small models of individual entities as follows:

Power Companies - PC Dong Noi, PC Hoa Duong, PC HCMC, PC Hanoi, PC Hai Phong, PC Ninh Binh, PC1, PC2, PC3, PC Khank Hoa.

EVN Power Stations – each of the existing and planned EVN power stations is modelled separately. These include those that are never to be equitised (eg Hoa Binh, Tri An, Yaly, collectively referred to as Base PP), new or existing Power Stations that might be equitised, and JVs where EVN will be the major shareholder (referred to as EVN JV Power Stations).

Non-core Activities. – EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co and Consulting (PECC1, PECC2, PECC3, PECC4 combined) are each modelled separately.

Transmission Entity – Combination of the existing four power transmission entities.

Each of the above entities is initially modelled as a stand alone separate entity, in which EVN initially holds all of the shares. This is not meant to represent the actual legal structure of each entity, but rather it is a convenient and realistic way of modelling each entity in a similar way (developing a separate model for each of the above individual entities would be impossible). These entities are then successively aggregated as shown in diagram below and at each aggregation inter-entity transfers are eliminated. All profit attributed to EVN as a shareholder of the modelled entity is assumed to remain as retained profit.

EVN JV Power Stations, where EVN is the majority shareholder are modelled as if they are an EVN entity that is to be equitised in 2005, with the proportion to be equitised being equal to the non-EVN shareholding2. Other JVs, where EVN is the minority shareholder, are not specifically modelled, but EVN’s shareholding and share of its profits are incorporated in the consolidated results. In the remaining part of this documentation, unless otherwise clarified, Other JV refers to power stations in which EVN is the minority shareholder.

Each entity is modelled on its own worksheet, and these are then aggregated as follows:

Power Companies – sum of results of all 10 PCs (no consolidation).

Main EVN PP– sum of results of all existing and new EVN Power Stations (except Base PP) plus EVN JVs (no consolidation).

Base PP – sum of results of Base PP (currently only Hoa Binh, Tri An and Yaly) (no consolidation).

Non-core Business – aggregate of EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co and Consulting (PECC1, PECC2, PECC3, PECC4 combined) (no consolidation).

Note that Transmission still remains a separate entity at this stage.

Single Buyer – consolidation of results from Transmission, Base PPs and the inclusion of power purchases from Other JVs, IPPs and imports.

Core Business – consolidation of results from Single Buyer, Power Companies and Main EVN PP.

2 From a modelling point of view this is fine for JVs where EVN will hold the majority of shares, since these assets will appear on EVN’s consolidated balance sheet and the partners shares will be a minority interest. In the case of JVs where EVN is the minority shareholder, a different approach is required since here the assets should NOT appear on EVN’s balance sheet, but EVN’s share of the profit from these JVs will appear in the P&L as share of profit from other sources.



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EVN Consolidated – consolidation of Core Business and Non-core Business. It is at this stage that the equitisation proceeds, GoV capital injections, EVN’s contribution to, and its share of profit from, Other JVs are included.

The outputs from a number of EVN Power Plants can be combined to form one Power Station for modelling purposes (eg Power Plants Uong Bong 1 & 2 are combined to form one Power Station Uong Bong). In such cases, the fuel costs and expected sales revenue are calculated on a plant by plant basis and then aggregated, thus allowing different fuel burns, and different selling from each Power Plant to be modelled if necessary. However any capital expenditure for each power plant is aggregated before modelling the financing of this capital expenditure3.

The following diagram illustrates the relationship between the entities and their aggregation and consolidation.

Existing EVN PP

New EVN PP

EVN JVs

Yaly

Tri An

Hoa Binh

???

Transmission

10 Power

Companies

EVN Telecomm

Thu Duc Co

Equip Man Co

4 PECCS

EVN Consolidated

Total Non-core

Power companies

Single Buyer

Base PP Core Business

Main EVN PP

3 There is a potential problem here if the phasing of the capital expenditure for two or more Power Plants is different because interest payments will be capitalised over the construction period of the whole Power Station, rather than over the period of the construction of each of the respective Power Plants. To avoid this it is necessary to model each Power Plant as a separate Power Station. This is only a problem if there is capital expenditure at two or more Power Plants that belong to one Power Station. It is possible to overwrite the calculated date when capital expenditure is to stop being capitalised for each Power Station



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5 Energy Balance

The starting point for estimating future demand is energy balances prepared by IoE. Unfortunately these do not go into the necessary detail and so some extrapolation is necessary

Three sets of data are used:

(1) Estimates of regional (North, Central and South) sales by main category, losses, self consumption and total generation for 2005, 2010 and 2015.

(2) Actual sales in each of the 10 PCs in 2005.

(3) Annual gross production in each year 2006-2012 given in the generation schedule.

It is assumed that these are all internally consistent and that there is no unsatisfied demand; in particular the expected generation in years for which there are no sales forecasts is just sufficient to cover demand in those years, once losses etc have been taken into account.

Estimate sales (and losses) (by category and by region) in intermediate years by assuming constant growth.

Apply respective regional annual growth rates for each customer category to the actual 2005 sales for each customer category in each PC.

Estimate distribution losses for each PC (based on specified distribution loss for each PC).

Add distribution losses to total sales to give total requirement for each PC.

Add transmission losses to distribution requirement (based on loss % given in IoE energy balance).

Add self consumption (either global figure given in IoE balance or calculated from plant specific self consumption data).

This gives the gross generation requirements.

Pro rata all data (sales, losses, self consumption) to match output in generation schedule.



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6 Capital Expenditure

The model divides EVN’s existing and future assets into different categories to reflect the different characteristics (from financial modelling point of view) of these assets:-

• HV transmission.

• LV distribution.

• Thermal power plants (TPP).

• Hydro power plants (HPP).

• EVN Telecom.

• Other Non-core entities.

In some cases these are further split as follows:

• HV transmission - 500 kV, 220 kV and 110 kV.

• LV distribution - LV distribution networks and LV rural electrification.

• Other Non-core entities – investments in Thu Duc Co, Equipment Manufacturing Co, Consulting.

Capital expenditure is funded by four possible sources: USD loans, VND loans, capital injections into EVN, and EVN’s own resources. The calculation of loan repayments and interest payments are modelled in a conventional way. The difference between the capital expenditure and the total amount borrowed in loans in a particular year is assumed to be a capital injection into the relevant entity by EVN ie EVN’s own contribution plus any capital injection (ie from GoV) into EVN is assumed to be an EVN injection into the modelled entity, and appears as additional equity for that entity.

Details of the capital expenditure (including financing parameters) for each new power plant are input, where as annual totals are input for capital expenditure in HV transmission and LV distribution. The model could be developed to include details of each major or significant investment in HV transmission, and aggregate the results, and this would allow different projects to have different financing parameters. In theory a similar approach could be used for capital expenditure in LV distribution, but the large number of different schemes would make this difficult.



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7 Equitisation

The equitisation of an entity is modelled as follows:

Assume x% (which is <50%) is to be equitised in year N. Then at the end of year N, x% of the total equity in the entity (ie sum of EVN equity, retained profits, other funds, revaluation fund) is split (1-x%) to EVN, and x% to other shareholders, and the retained profits, other finds, revaluation fund set to zero.

In this (and subsequent year), y% of profits after tax are distributed as dividends to shareholders (and shown in P&L statement), and the remaining profit retained by the entity as retained profits. Dividends to non-EVN Shareholders are assumed to be paid in cash, where as the dividend to EVN is assumed to remain within EVN at the consolidation level.

After equitisation, further capital injections to finance the CAPEX program are assumed to be split between EVN and the new shareholders.

This reallocation of equity in the year of equitisation can be difficult to see in the model because other adjustments are made at the same time, so the following illustrates what occurs.

Bal

ance

at e

nd o

f Ye

ar N

-1

Re

allo

catio

n of

eq

uity

due

to

equi

tisat

ion

Cap

ital i

njec

tions

(To

finan

ce C

APEX

)

Allo

catio

n of

reta

ined

pr

ofits

Bal

ance

at e

nd o

f ye

ar N

EquityEVN Equity bn VND 500.0 480.0 +60.0 540.0Other shareholders bn VND 0.0 320.0 +40.0 360.0Total share capital bn VND 500.0 800.0 +100.0 0.0 900.0Retained profits bn VND 100.0 0.0 50.0 50.0Other funds bn VND 100.0 0.0 0.0Revaluation reserve bn VND 100.0 0.0 0.0Total equity bn VND 800.0 800.0 100.0 50.0 950.0

Adjustments

The first column shows the equity part of the balance sheet at the end of year N-1.

The second column shows the result of equitising 40% of the entity in year N (EVN retains 60% of total equity, new shareholders obtain 40%).

The third column shows new capital injections required under the financing assumptions to finance CAPEX in year N. Total injection of 100 bn VND is required in this example.

The fourth column shows the allocation of retained profit (the dividend payments have already been deducted from the profit in the P&L statement)

The fifth column shows the resulting equity part of the balance sheet at the end of Year N.

The proceeds from equitisation are incorporated in the EVN consolidated financial statements, not in the entity’s financial statement.



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8 Rates of exchange and inflation

The model works primarily in VND, but some costs are expressed in USD and it is necessary to convert these into appropriate VND. There are 3 factors at work

USD inflation – the change prices expressed in USD due to USD inflation

VND inflation - the change in prices expressed in VND due to VND inflation

VND/USD exchange rate – this can either mirror changes in USD and VND inflation or there might be a real change in the exchange rate (ie a change that can not be accounted for purely in terms of changes in USD and VND inflation rates. At present it is assumed there is no real change in exchange rates

Exchange rate in year i (RoEi ) = RoEi-1 * (1+real change in exchange rate in year i)*(1+USD inflation in year i)/(1+VND inflation in year i). This is used to convert USD costs to VND in year i


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9 Financial Statements (Individual entities)

The following tables summarise the way the P&L and balance sheets for each type of entity are complied. Items highlighted in bold italic font are parameters than can be changed (see later) Profit & Loss Power Companies Existing Power

Stations New power Stations Transmission Non Core

Main Income Tariff * sales Selling price to Single buyer * net output

Selling price to Single buyer * net output

Assumed to equal total costs

Annual increase in sales

Other income % of main income Zero Zero Zero 2004 actual % of main income

O&M 2004 actual % of Gross asset value

2004 actual % of Gross asset value

HPP - 0.67% of gross asset value TPP – 2.5% of Gross asset value

1.5% of gross asset value

EVN Telecom - 20% annual increase Other – 8% annual increase

Selling costs 2004 actual % of total sales


Admin costs 2004 actual % of total sales


Power purchase Bulk supply tariff * total requirement

N/a N/a Transmission losses * average cost of bulk electricity

N/a

Fuel costs N/a HPP – n/a TPP – gross output * fuel burn (units/GWH) * unit fuel price

N/a N/a

Hydro tax N/a HPP – Gross output * hydropower tax TPP – n/a

N/a N/a


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Profit & Loss Power Companies Existing Power Stations

New power Stations Transmission Non Core

Depreciation % of gross asset value


Increase/decrease in closing value of USD loans (both new and existing) at year end

Interest Calculated on average of opening and closing balances of for new loans+ actual values for existing loans

Corporate tax % of gross profit

Dividends For equitised entities, profit after tax * % of profit distributed as dividends * % Equitised, otherwise zero

N/a N/a

Balance sheet Power Companies Existing Power Stations

New Power Stations Transmission Non Core

Cash Calculated from cash flow statement


Total sales * delay in non-EVN customers paying

N/a N/a N/a Total sales from non-EVN sources* delay in non-EVN customers paying


N/a

Total sales * delay in paying for bulk power Total income * delay in paying for bulk power

Total sales from EVN sources * delay in paying for bulk power4

Inventories % of gross asset value



4 Note these do not appear as payables within EVN on other entities balance sheets.


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Fixed assets Gross asset value – accumulated depreciation

CIP New CAPEX + any IDC is recorded under CIP for duration of construction period, then transferred to Fixed Assets











HPP - (O&M + hydro tax) * delay in paying other costs TPP – (O&M * delay in paying other costs) + (fuel cost * delay ion paying fuel costs)

O&M * delay in paying other costs



Power purchase costs * delay in paying for bulk power

N/a Power purchase costs * delay in paying for bulk power

N/a

Short term Loans 2004 value (ie no change)


For year N, calculate repayments for Year N+1

LT Loans Total loans (new existing , USD, VND) - Current portion of LT loans

Other Lt Liabilities



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EVN Share capital

EVN’s assumed share capital in entity, plus any EVN capital injections for CAPEX minus any shares sold under equitisation process

Other share capital

Equitised shares plus any proportion of capital injection from new shareholders to finance CAPEX

Retained profits Profit from P&L

Other reserves 2004 value (ie no change)

Revaluation reserve



For PC Dong Noi, PC Hoa Duong, PC HCMC, PC Hanoi, PC Hai Phong, PC Ninh Binh, PC1, and PC2, the appropriate balance sheet data for 2004. For PC Khank Hoa, the balance sheet data prepared for equitisation process, For PC3, the PC3 Balance sheet minus Balance sheet data for PC Khank Hoa.

2004 balance sheets. Payables to EVN is adjusted to match known loans. 2004 Balance sheet data for some small Power Stations (3 diesel plants, Can Tho, Dray Hling, Na Loi, Nam Mu, Ry Ninh, Srok Phu Mieng, Suoi Sap, Suoi Vang, Thu Duc) is not yet available and so these are included in Transmission’s balance sheet.

Zero Residual of 2004 consolidated balance sheet is assigned to Transmission. That is balance sheet items that can not be allocated either to a Power company, an existing Power Station , EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co PECC1, PECC2, PECC3, or PECC4 is included in Transmission’s balance sheet5.

As per appropriate 2004 balance sheets

5 Note that the balance sheet data for Power Plants for which not individual balance sheet data has been provided are included here eg balance sheet data for list of


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10 Financial Statements (Consolidated entities)


Main Income Sales of bulk power to PCs Power Company Core business + non core business

Other income None Power Company Core business + non core business

Power purchases Power purchases from Other JVs, IPPs and imports

Single Buyer Core business

O&M O & M costs of Transmission + Base PPs O&M costs of Power Companies, Main EVN PP, Single Buyer


Selling costs % of total income Power Companies + Single Buyer Core business + non core business

Admin costs Transmission + Base PP Power Companies + Single Buyer Core business + non core business

Fuel costs N/a Main EVN PP Core business

Hydro tax Single Buyer + Main EVN PP Core business

Depreciation Transmission + Base PP Power Companies + Main EVN PP + Single Buyer



Transmission + Base PP Power Companies + Main EVN PP + Single Buyer


Interest Transmission + Base PP Power Companies + Main EVN PP + Single Buyer


plants given in existing Power Station column will appear in Transmission’s balance sheet.


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Profit from JVs N/a N/a Total cost of Other JV *EVN’s share of Investment in Other JV * EVN’s expected return

Corporate tax % of profit % of profit % of profit

Dividends N/a Power Companies + Main EVN PP Power Companies + Main EVN PP


Cash Calculated from cash flow


n/a Power Companies + Main EVN PP + Single Buyer




None

Inventories Transmission + Base PP Power Companies + Main EVN PP + Single Buyer





Fixed assets Transmission + Base PP Power Companies + Main EVN PP + Single Buyer


CIP Transmission + Base PP Power Companies + Main EVN PP + Single Buyer



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None None

Short term Loans Transmission + Base PP Power Companies + Main EVN PP + Single Buyer





LT Loans Transmission + Base PP Power Companies + Main EVN PP + Single Buyer


Other LT Liabilities



Minority Interest N/a Power Companies + Main EVN PP Core Business + Non Core Business

EVN Share capital

Transmission + Base PP 2004 share capital for Core business + any subsequent GoV injections to finance CAPEX


Retained profits From P&L From P&L From P&L


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Other reserves Transmission + Base PP Power Companies + Main EVN PP + Single Buyer


Revaluation reserve




Transmission + Base PP balance sheet data

EVN Consolidated accounts – balance sheet data for EVN Telecom, Thu Duc Manufacturing Co, Equipment manufacturing Co, PECC1, PECC2, PECC3, PECC4

EVN 2004 Consolidated accounts



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Annex Data Input for Business Model

Data Requirements in Worksheet “BASE DATA”


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Worksheet “Parameters” Item Description Comments Financing CAPEX – Specify financing parameters for 500 kV, 220 kV, 110 kV transmission, LV distribution network, LV rural electrification program, HPP, TPP, EVN Telecom, other Non-core entities (Thu Duc, Equipment Manufacturing Co, Consulting). Project specific financing parameters can be set for each new EVN Power Plant if necessary in Worksheet “Power Stations” Financing parameters for 110 KV lines apply to both 110 kV CAPEX by Transmission entity and by Power Companies. % of total expenditure % of total CAPEX for a particular



EVN




For HPP and TPP, IDC is capitalised over the whole construction period of the Power Plant. For HV and LV lines, IDC is capitalised over the Construction Period for those lines


Only applies to CAPEX on HV and LV lines and CAPEX in non-core entities. Construction period for a new Power Plant is calculated from CAPEX data.

Depreciation – HV transmission (500 kV, 220 kV, 110 kV) , LV distribution (includes rural electrification), HPP, TPP, EVN Telecom, Non-core Depreciation Depreciation period in years for


O & M costs – HV transmission (500 kV, 220 kV, 110 kV) , LV distribution(includes rural electrification), HPP, TPP O & M costs O & M cost (expressed as a % of



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Item Description Comments Financial information Real change in VND/USD Exchange rate


VND Inflation Annual inflation rate of VND prices Only directly used to inflate VND component of CAPEX and to calculate exchange rate. At present it is also used to index other user defined data (Hydro tax, end user tariffs, bulk supply tariff)














Delay in paying fuel Average delay in EVN Power Stations paying for fuel

Used to calculate payables for Power Stations.





Tax rate Profits tax rate All profits are taxed at this rate.


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Item Description Comments Rate of return Expected rate of return on

investments Used to calculate selling price of electricity for each Power Station, to give this return on gross asset value, and the bulk supply tariff for PCs, assuming this return on assets.

Dividend % of profit after tax distributed to shareholders

Power market costs Cost of operating power market (as a % of total power market sales)












Yes = use plant specific ones (self consumption data should be entered for all sources in worksheet “Power Station data”). The calculated self consumption is then used in energy balance (see worksheet “Actual Demand”) No = Use average self consumption data specified in energy balance (note output from imports and other non EVN source will be reduced)


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Worksheet “Bulk Supply Tariffs”

Item Description Comments Bulk supply tariff f Price (in VND/kWh) that each PC




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Worksheet “CAPEX” Item Description Comments Transmission Expected total capital expenditure


Capital expenditure estimates should exclude IDC and be in 2005 USD terms.

Power Companies Expected total capital expenditure (in M USD) on 110 kV, LV distribution network and LV rural electrification by Power company Alternatively, enter total capital expenditure on 110 kV, LV distribution network and LV rural electrification for all Vietnam, and % for each Power company

Capital expenditure estimates should exclude IDC and be in 2005 USD terms. The total data is not required if specific estimates are available for individual PCs.

Other entities Expected total capital expenditure for each non-core entity

Capital expenditure estimates should exclude IDC and be in 2005 USD terms.


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Worksheet “Sensitivities” Item Description Comments Sensitivity Select appropriate sensitivity 1- Base case

2- 10% reduction in end user demand 3- 1 year delay in completing new Power Plants due to come on

stream after 2008 (note that phasing of capital expenditure on these delayed Power Plants is the same as the base case, as is phasing of expenditure on HV and LV lines)

4- Output from HPPS reduced in years 200x, 200y, 200z by 20% Note: Scenario 2, 3 and 4 are currently not available due absence of appropriate generation schedule


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Worksheet “Generation scenarios” This worksheet contains the generation schedule for each scenario Item Description Comments Power Plant name Name of Power Plant or source of

electricity DONOT DELETE AN EXISTING ROW OR INSERT NEW ROWS HERE; INSTEAD ADD THE NEW POWER PLANT AT THE END OF THE EXISTING LIST. An existing Power Plant name can be amended or overwritten if necessary but remember to change the information in worksheet “Power Plant Data” as well.

Total generated volume Planned gross output (GWh) from each Power Plant or source in each year for each scenario

Data to be provided by IoE for scenarios 2, 3 and 4 Gross output (before self consumption and own use) Do not change order of Power Plants or sources.


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Worksheet “Power Plant Data” Item Description Comments Location Region where Power Plant is

located For information only.

Power Station Name of “parent” Power Station” Two or more Power Plants can be grouped into one Power Station for modelling purposes. Select relevant Power Station from list, (a new Power Station name can be added in Worksheet “Power Station data”) Each Power Plant classified as Base PP, Equitised PP or EVN JV MUST be allocated to a Power Station. A Power Station can consist of only one Power Plant.


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Item Description Comments Type of enterprise Identify type of enterprise

Base – only use for Power Plants that are never to be equitised and consolidated with Transmission in Single Buyer entity. Equitised - include all other EVN Power Plants except EVN JVs EVN JVs – EVN JVs where EVN will be majority shareholder Other JVs – Power Stations where EVN will be a minority shareholder IPPs - Other Power Station in which EVN has no financial interest Imports – imports for neighbouring countries

Each Power Plant must be categorised. Only select one type for each Power Plant. Only select one type for each Power Plant. If the type of Power Plant is changed from Base PP, Equitised or EVN JV to Other JV, IPP or Import, then the relevant worksheet in workbook “Power Stations” should be deleted. If the type of Power Plant is changed from Other JV, IPP or Import to either Base PP, Equitised or EVN JV then it is necessary to add a new worksheet in workbook “Power Stations” (see workbook “Power Stations”) If the type of Power Plant is changed Base PP to Equitised, them move the relevant worksheet from the “base” section to “equitised section” in Workbook “Power Stations” Add the relevant equitisation data (DONOT INSERT A NEW ROW JUST ENTER THE ACTUAL DATA) in worksheet “Power Station Data” in workbook “Base Data”. (see workbook “Power Stations)” If the type of Power Plant is changed Equitised to Base to, then move the relevant worksheet from the “equitised section” to “base” section in Workbook “Power Stations” Delete the relevant equitisation data (DONOT DELETE THE COMPLETE ROW JUST DELETE THE ACTUAL DATA).in worksheet “Power Station Data” in workbook “Base Data”. (see workbook “Power Stations”)

Type of plant Enter 1 in appropriate column Enter the Power Station name and Power Station reference number (this is the number in the purple box in worksheet “Power Station Data” in workbook “Base Data” in column A next to the name Check that the worksheet is picking up the correct generation and capital expenditure data for the new Power Station (rows 12 and 15). Note that each sheet in Workbook “Power Stations” refers to a Power Station, and not a Power Plant.


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Item Description Comments Fuel burn Fuel consumption to generate

1 GWh of electricity Must be consistent with type of Power Plant (eg if type of plant is gas, then enter gas burn; DONOT also enter the fuel burn for reserve fuel) It is only necessary to enter data for EVN Power Plants Different sources of coal and gas can have different prices

self consumption data % of gross output required for self consumption



Determines income of each Power Plant 2005 USD prices

Capital expenditure Planned capital expenditure in each year for each source

Exclude IDC In 2005 USD terms Data only required for EVN Power Plants

Only Power Plants of type Base PP, Equitised or EVN JV should appear in the workbook “Power Stations”.


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Worksheet “Power Station Data” Item Description Comments Power Station name Enter name of Power Station Only required for Power Stations operating Power Plants of type Base

PP, Equitised or EVN JV Equitisation date Year in which the Power Station is

planned to be equitised, or for EVN JVs enter first year of construction

% % of equity to be equitised , or for EVN JVs % of share held by other shareholders


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Worksheet “Fuel costs” Item Description Comments Fuel costs Expected price of each type of fuel

in future years. Expressed in 2005 USD terms Fuel categories correspond to those in worksheet “Power Station Data” Note: Gas price is price per 000 m3.


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Worksheet “Joint Ventures” Enter data here for JVs where EVN is the minority shareholder. Item Description Comments Name Name of JV EVN’s % contribution % of total capital supplied by EVN Expected return EVN’s expected annual return on

its investment






Page A4-35

Worksheet “Base Regional Demand” Base regional demand data forecasts used to calculate future demand for each PC.

Worksheet “Actual Demand” Calculates actual demand for each customer category in each year for each PC, taking into account available generation.

Worksheet “Exist Foreign Loans” Details of all existing foreign loans converted to USD (as at 01/01/05). Data obtained from former ICM module, and each loan allocated to one or more modelled entities. Data included outstanding loan, future loan repayments, future interest payments and IDC

Worksheet “Exist VND Loans” Details of all existing VND loans (as at 01/01/05). VND. Data obtained from former ICM module, and each loan allocated to one or more modelled entities. Data included outstanding loan, future loan repayments, future interest payments and IDC

Worksheet “2004 accounts” Breakdown of EVN’s 2004 financial statements. Used to determine 2004 balance sheet for Transmission entity. It is possible to adjust Transmission‘s balance sheet. If necessary.

Worksheet “2005 accounts” Breakdown of EVN’s 2005 financial statements. Used to determine 2005 balance sheet for Transmission entity. It is possible to adjust Transmission balance sheet. [Only used once actual 2005 balance sheet data for all Power Companies and Power Stations has been entered].

Worksheet “EVN Telecom” Financial statements for EVN telecom entity.

Worksheet “Thu Duc” Financial statements for Thu Duc Manufacturing Co entity.

Worksheet “Equip Man Co” Financial statements for Equipment Manufacturing Co entity.

Worksheet “Consulting” Financial statements for Consulting entity.

Worksheet “Transmission” Financial statements for Transmission entity.

Worksheet “Power Companies” Summary financial statements for all 10 Power Companies combined.

Worksheet “Main EVN PP” Summary financial statements for all EVN owned Power Stations except Base PP.



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Worksheet “Base PP” Summary financial statements for Base PPs.

Worksheet “Single Buyer” Financial statements for the Single Buyer Entity.

Worksheet “Core Business” Summary financial statements for the Core Business entity.

Worksheet “Total Non-core” Summary financial statements for EVN Telecom, Thu Duc Manufacturing Co, Equipment Manufacturing Co and Consulting (PECC1, PECC2, PECC3, PECC4 combined) combined.

Worksheet “EVN Consolidated” Summary financial statements for the whole of EVN.

Worksheet “Summary” Summary of key operating parameters of EVN Consolidated.



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WORKBOOK “POWER STATIONS” This workbook contains a separate worksheet for each EVN Power Station.

For existing EVN Power Station, enter historic profit and loss, balance sheet and cash flow data for each year.

Points to note:

(1) LT Loans. Often the balance sheet data on LT loans and information on loans in workbook “base data” do not agree. If the problem can not be reconciled, then assume the information in loans file is correct and make an adjustment in the balance sheet (eg in other Liabilities)

(2) The Base PP part of the workbook is between worksheets “Start-base PP” and “End-base PP”

(3) The Equitised PP part of the workbook is between worksheets “Start-eq PP” and “End-eq PP”

(4) To add a new EVN Power Station, insert a new worksheet in the appropriate part of the workbook – Base PP or Equitised PP depending on type of Power Station. Go worksheet “Blank HPP” or “Blank TPP” depending on whether the new Power Station is hydro or thermal. Copy the all the contents (press ,<ctrl>A, followed by <ctrl>C, then go to new worksheet and press <ctrl>V) of the appropriate blank worksheet into the new worksheet. Enter the number of the Power Station (as shown in column A of worksheet “Power Station Data” in workbook “Base Data”.) in cell F3. Enter the date that the capitalisation of interest is to stop in cell F5.



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WORKBOOK “POWER COMPANIES” This workbook contains a separate worksheet for each power company.

Enter profit and loss, balance sheet and cash flow data for each year.

Enter planned equitisation date plus % of PC to be equitised.

Points to note:

(1) LT Loans. Often the balance sheet data on LT loans and information on loans in workbook “base data” do not agree. If the problem can not be reconciled, then assume the information in loans file is correct and make an adjustment in the balance sheet (eg in other Liabilities)



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Adding subsequent year’s data Power Stations and Power Companies 2005 data (and subsequent years data) profit and loss, balance sheet and cash flow data can be added in the appropriate cells for each Power Station and Power Company. It is necessary to enter actual financial data in all the cells in the 2005 column to ensure future balance sheets balance. Alternatively all the financial data in 2005 column (except P&L, balance sheet and cash flow) can be set to zero, but it will then be necessary to seed the opening balances for new loans (both foreign and local), CIP, gross fixed assets and gross depreciation with the appropriate 2005 values.

Workbook “Base data” Telecom, Thu Duc, Equipment manufacturing company, and Consulting companies. These can be updated in the same way as for Power Stations and Power Companies (as described above.)

Transmission.

Enter the consolidated balance sheet for EVN into worksheet “2005 accounts”. This worksheet will then calculate the resulting balance sheet for Transmission by subtracting the balance sheet data of all the other parts of EVN. The resulting balance sheet data can then be adjusted if necessary. It will then be necessary to link” this data with the “actual” balance sheet data in worksheet “Transmission” in workbook “Base Data”. This is done in a same way as the 2004 balance sheet data in worksheet “Transmission” is linked to the calculated 2004 Transmission balance sheet data calculated in worksheet “2004 accounts”.

Sales and Demand Worksheets “Base Regional Data” and "Actual demand” already contain actual 2005 demand. If 2006 (or subsequent years) actual demand data is to be used to calculate annual growth, then the formulae in worksheet “Base Regional Data” will need changing. At present the growth rate over 5 year periods (2005-2010, and 2010-2015) is calculated, since 2005, 2010, 2015 are the only years for which either actual data or firm forecasts are available.

To change the formula once 2006 actual demand data has been entered in column D in Worksheets “Base Regional Data”, change the formulae in cell E5 in Worksheets “Base Regional Data” from

=+D5*(($H5/$C5)^(1/5) to =+D5*(($H5/$D5)^(1/4)

Copy this formula into each cell in the following ranges: E5:G9, E12:G16, E19:G23.


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Annex 5

FINANCIAL MANAGEMENT ASSESSMENT QUESTIONNAIRE


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Topic Response Remarks

1. Implementing Agency EVN

1.1 What is the entity’s legal status / registration? State Owned Enterprise

1.2 Has the entity implemented an externally financed project in the past (if so, please provide details)?

Yes

1.3 What are the statutory reporting requirements for the entity?

Monthly, quarterly, annual reports to GoV

1.4 Is the governing body for the project independent?

1.5 Is the organizational structure appropriate for the needs of the project?

Yes

2. Funds Flow Arrangements

2.1 Describe (proposed) project funds flow arrangements, including a chart and explanation of the flow of funds from ADB, government and other financiers.

See figure 6.4

2.2 Are the (proposed) arrangements to transfer the proceeds of the loan (from the government / Finance Ministry) to the entity satisfactory?

N/a

2.3 What have been the major problems in the past in receipt of funds by the entity?

None

2.4 In which bank will the Imprest Account be opened?

Not decided yet

2.5 Does the (proposed) project implementing unit (PIU) have experience in the management of disbursements from ADB?

EVN has experience of administering ADB loans

2.7 Does the entity have/need a capacity to manage foreign exchange risks?

No

2.8 How are the counterpart funds accessed? Through dedicated bank account

2.9 How are payments made from the counterpart funds?

Transferred from EVN

2.10 If part of the project is implemented by communities or NGOs, does the PIU have the necessary reporting and monitoring features built into its systems to track the use of project proceeds by such agencies?

No NGO planned to be involved


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2.11 Are the beneficiaries required to contribute to project costs? If beneficiaries have an option to contribute in kind (in the form of labor), are proper guidelines formulated to record and value the labor contribution?

No

3. Staffing

3.1 What is the (proposed) organizational structure of the accounting department? Attach an organization chart.

See text

3.2 Identify the (proposed) accounts staff, including job title, responsibilities, educational background and professional experience. Attach job descriptions and CVs of key accounting staff.

See text

3.3 Is the project finance and accounting function staffed adequately?

Yes

3.4 Is the finance and accounts staff adequately qualified and experienced?

Yes

3.5 Is the project accounts and finance staff trained in ADB procedures?

No (but see text)

3.6 What is the duration of the contract with the finance and accounts staff?

No limit

3.7 Indicate key positions not contracted yet, and the estimated date of appointment.

None

3.10 Does the project have written position descriptions that clearly define duties, responsibilities, lines of supervision, and limits of authority for all of the officers, managers, and staff?

Yes

3.11 At what frequency are personnel transferred? No specific time frequency

3.12 What is training policy for the finance and accounting staff?

No specific training policy or program.

4. Accounting Policies and Procedures

4.1 Does the entity have an accounting system that allows for the proper recording of project financial transactions, including the allocation of expenditures in accordance with the respective components, disbursement categories, and sources of funds? Will the project use the entity accounting system?

Yes – part of EVN’s computerised finance system


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4.2 Are controls in place concerning the preparation and approval of transactions, ensuring that all transactions are correctly made and adequately explained?

Yes

4.3 Is the chart of accounts adequate to properly account for and report on project activities and disbursement categories?

Yes

4.4 Are cost allocations to the various funding sources made accurately and in accordance with established agreements?

Yes

4.5 Are the General Ledger and subsidiary ledgers reconciled and in balance?

Yes

4.6 Are all accounting and supporting documents retained on a permanent basis in a defined system that allows authorized users easy access?

Yes

Segregation of Duties

4.7 Are the following functional responsibilities performed by different units or persons: (i) authorization to execute a transaction; (ii) recording of the transaction; and (iii) custody of assets involved in the transaction?

Yes

4.8 Are the functions of ordering, receiving, accounting for, and paying for goods and services appropriately segregated?

Yes

4.9 Are bank reconciliations prepared by someone other than those who make or approve payments?

Yes

Budgeting System

4.10 Do budgets include physical and financial targets?

Yes

4.11 Are budgets prepared for all significant activities in sufficient detail to provide a meaningful tool with which to monitor subsequent performance?

Yes

4.12 Are actual expenditures compared to the budget with reasonable frequency, and explanations required for significant variations from the budget?

Yes

4.13 Are approvals for variations from the budget required in advance or after the fact?

Usually in advance


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4.14 Who is responsible for preparation and approval of budgets?

Director of HPPMB3, approved by EVN

4.15 Are procedures in place to plan project activities, collect information from the units in charge of the different components, and prepare the budgets?

Yes

4.16 Are the project plans and budgets of project activities realistic, based on valid assumptions, and developed by knowledgeable individuals?

Yes

Payments

4.17 Do invoice-processing procedures provide for: (i) Copies of purchase orders and receiving reports to be obtained directly from issuing departments? (ii) Comparison of invoice quantities, prices and terms, with those indicated on the purchase order and with records of goods actually received? (iii) Comparison of invoice quantities with those indicated on the receiving reports? (iv) Checking the accuracy of calculations?

Yes

4.18 Are all invoices stamped PAID, dated, reviewed and approved, and clearly marked for account code assignment?

Not stamped “PAID”, approvals recorded separately.

4.19 Do controls exist for the preparation of the payroll and are changes to the payroll properly authorized?

Yes, approved by Director

Policies And Procedures

4.20 What is the basis of accounting (e.g., cash, accrual)?

Accrual

4.21 What accounting standards are followed? VAS

4.22 Does the project have an adequate policies and procedures manual to guide activities and ensure staff accountability?

No project specific manuals at present; follow GoV guidelines. Will prepare manuals

4.23 Is the accounting policy and procedure manual updated for the project activities?

Yes

4.24 Do procedures exist to ensure that only authorized persons can alter or establish a new accounting principle, policy or procedure to be used by the entity?

Yes


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4.25 Are there written policies and procedures covering all routine financial management and related administrative activities?

Yes

4.26 Do policies and procedures clearly define conflict of interest and related party transactions (real and apparent) and provide safeguards to protect the organization from them?

Covered by Vietnamese laws

4.27 Are manuals distributed to appropriate personnel?

Yes

Cash and Bank

4.28 Indicate names and positions of authorized signatories in the bank accounts.

Director, deputy director, Head of Finance

4.29 Does the organization maintain an adequate, up-to-date cashbook, recording receipts and payments?

N/a

4.30 Do controls exist for the collection, timely deposit and recording of receipts at each collection location?

N/a

4.31 Are bank and cash reconciled on a monthly basis?

Yes

4.32 Are all unusual items on the bank reconciliation reviewed and approved by a responsible official?

Yes

4.33 Are all receipts deposited on a timely basis? N/a

Safeguard over Assets

4.34 Is there a system of adequate safeguards to protect assets from fraud, waste and abuse?

No specific measures. Covered by general laws

4.35 Are subsidiary records of fixed assets and stocks kept up to date and reconciled with control accounts?

Yes

4.36 Are there periodic physical inventories of fixed assets and stocks?

Annually

4.37 Are assets sufficiently covered by insurance policies?

Yes (during constriction)


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Other Offices and Implementing Entities

4.38 Are there any other regional offices or executing entities participating in implementation?

No

4.39 Has the project established controls and procedures for flow of funds, financial information, accountability, and audits in relation to the other offices or entities?

N/a

4.40 Does information among the different offices/implementing agencies flow in an accurate and timely fashion?

N/a

4.41 Are periodic reconciliations performed among the different offices/implementing agencies?

N/a

Other

4.42 Has the project advised employees, beneficiaries and other recipients to whom to report if they suspect fraud, waste or misuse of project resources or property?

Follow Vietnamese law

5. Internal Audit

5.1 Is there an internal audit department in the entity?

EVN has Internal Audit function

5.2 What are the qualifications and experience of audit department staff?

Unknown

5.3 To whom does the internal auditor report? EVN Management Board

5.4 Will the internal audit department include the project in its work program?

Yes

5.5 Are actions taken on the internal audit findings?

Unknown – no internal audits of HPPMB3 carried out recently

6. External Audit

6.1 Is the entity financial statement audited regularly by an independent auditor? Who is the auditor?

Yes (VACO)

6.2 Are there any delays in audit of the entity? When are the audit reports issued?

No

6.3 Is the audit of the entity conducted according to the International Standards on Auditing?

Yes


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6.4 Were there any major accountability issues brought out in the audit report of the past three years?

No

6.5 Will the entity auditor audit the project accounts or will another auditor be appointed to audit the project financial statements?

Put out to tender

6.6 Are there any recommendations made by the auditors in prior audit reports or management letters that have not yet been implemented?

No

6.7 Is the project subject to any kind of audit from an independent governmental entity (e.g., the supreme audit institution) in addition to the external audit?

Ministry of Finance can carry out audits to check with compliance of MoF/GoV instructions

6.8 Has the project prepared acceptable terms of reference for an annual project audit?

Unknown

7. Reporting and Monitoring

7.1 Are financial statements prepared for the entity? In accordance with which accounting standards?

Yes, VAS

7.2 Are financial statements prepared for the implementing unit?

Yes

7.3 What is the frequency of preparation of financial statements? Are the reports prepared in a timely fashion so as to useful to management for decision making?

Quarterly, annually

7.4 Does the reporting system need to be adapted to report on the project components?

No

7.5 Does the reporting system have the capacity to link the financial information with the project's physical progress? If separate systems are used to gather and compile physical data, what controls are in place to reduce the risk that the physical data may not synchronize with the financial data?

Not really

7.6 Does the project have established financial management reporting responsibilities that specify what reports are to be prepared, what they are to contain, and how they are to be used?

Yes

7.7 Are financial management reports used by management?

Yes


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7.8 Do the financial reports compare actual expenditures with budgeted and programmed allocations?

Yes

7.9 Are financial reports prepared directly by the automated accounting system or are they prepared by spreadsheets or some other means?

Yes

8. Information Systems

8.1 Is the financial management system computerized?

Yes

8.2 Can the system produce the necessary project financial reports?

Yes

8.3 Is the staff adequately trained to maintain the system?

Yes

8.4 Does the management organization and processing system safeguard the confidentiality, integrity and availability of the data?

Yes


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Annex 6

EXAMPLES OF JOB DESCRIPTIONS IN FINANCE DEPARTMENT OF HPPMB3


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Code: MC. P5.01

Version: 01 ATD3 Job Description of Financial Department

Issuing date:......

1. Position Manager 2. Department Financial Department 3. Report to Director of HPPMB 3 4. Authorized person Deputy Manager 5. Required qualification

• Qualification: Bachelor (finance and accounting) • Training: Grade A in English and computing skill, refresh course on state governance

for officer • Experience:

- Minimum 5 years working in accounting and finance sector - Experience in accounting of capital construction, preparing accounting report

and other accounting related activities - Acquirement of state's general policies, sector policies, acquirement of basic

knowledge in finance and accounting, standards, understanding of law codes and legal documents, experience in arrangement of finance and accounting works.

- Good command of computing skills and relevant softwares • Other necessary skills:

- Good coordination with other departments to complete financial finalization and payment of hydroelectricity subprojects

6. Right and responsibility: • Advise the Director of HPPMB 3 on accounting and financial issues of the entire

HPPMB 3, specifically as following: - Financial management of capital construction and payment and financial

finalization according to construction progress during the preparation and construction of hydroelectricity projects.

- Supervision and follow up the application for fund allocation and loan for timely payment to contractors of work items under the projects managed by the HPPMB3

• Acting on behalf of the Director of HPPMB 3 to manage financial and accounting work of the entire HPPMB 3 according to related principles and the state's ordinance on statistic accounting.

• Preparing quarterly financial statement, annual statement and inventory report according to accounting standards and time schedule.

• Detailing schedule of work progress of the Department by months and years. • Advising the Director on management of fund for capital construction according to the

state regulations. • Suggesting changes or maintaining solutions to promote effective management of

fund for capital construction. • Reporting to the Director of wrong actions.


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Code: MC. P5.02


Issuing date:......

1. Position Deputy Manager 2. Department Financial Department 3. Report to Manager 4. Authorized person 5. Required qualification

• Qualification: Bachelor (finance and accounting) • Training: Grade B in English and computing skill • Experience:

- Minimum 3 years working in accounting and finance sector - Experience in accounting of capital construction, preparing accounting report

and other accounting related activities - Experience in payment for completed volume of capital construction, prepare

report of fund finalization for capital construction and accounting report, experience in bid evaluation

- Acquirement of state's general policies, sector policies, acquirement of basic knowledge in finance and accounting, standards, acquirement of law codes and legal documents, experience in arrangement of finance and accounting works.

- Good computing skills and relevant softwares • Other necessary skills: • Good coordination with other departments to complete financial finalization and

payment of hydroelectricity subprojects

6. Right and responsibility: • Coordinating with officers to prepare and interpret report of fund finalization for

hydroelectricity projects managed by the HPPMB3. • Advising the manager on payment and finalization of fund, prepare report of fund

finalization • Preparing quarterly and annually financial statement and inventory report according

to accounting standards and time schedule. • Detail schedule of work progress of officers by months and years • Undertaking and manage activities of the department when manager is absent • Dealing with other works as delegated by Directors of the HPPMB3 and manager.


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Code: MC. P5.01


Issuing date:......

1. Position Officer 2. Department Financial Department 3. Report to Manager 4. Authorized person Accounting and financial officer of the same or higher

position 5. Required qualification

• Qualification: Bachelor (finance and accounting) • Training: Grade A in English and office computing certificate • Experience:

- Minimum 1 year working in accounting and finance sector - Preparing accounting report - Experience in accounting of investment and capital construction, preparing

accounting report and other accounting related activities - Undertaking payment and fund finalization for work items of hydroelectricity

project - Acquirement of fund finalization of items of the completed projects - Acquirement of the state policies and regimes and legal documents applied - Good computing skills and relevant softwares

• Other necessary skills:

6. Right and responsibility: • Being accounting and financial officer in supervising payment and finalization of fund

for construction of work items of hydroelectricity projects; assisting managers within the scope of assigned duties.

• Undertaking payment and finalization of capital construction of work item: proceed, monitor, follow up and supervise implementation of legal procedures according to regulation on capital construction.

• Preparing documents related to his/her assigned duties. • Undertaking accounting of capital construction investments within his/her assigned

duties according to accounting regime applied for EVN. • Preparing quarterly and annually financial statement following accounting standards

and time schedule. • Detail scheduling his/her work progress by months and years. • Having the right to reject payment procedure implementation for inadequate

application and against ineligible invoices. • Reporting to manager, director of HPPMB 3 of signs of violation.


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Code: MC. P5.02


Issuing date:......

1. Position Cashier 2. Department Financial Department 3. Report to Manager 4. Authorized person Accounting and financial officer of the same or higher

position 5. Required qualification

• Qualification: High school graduate • Experience:

- Minimum 1 year working as cashier - Undertaking payment and spending according to invoices approved by the

accountant, managers or directors of the HPPMB3 and payment of salary to other staffs and officers.

• Other necessary skills:

6. Right and responsibility: - Working as the cashier to proceed cash withdrawal from bank using cheque

(signed and sealed), check the value of the cheque and the amount received from bank and ensure safety of money transport from bank to the HPPMB3.

- Undertaking payment and spending according to invoices approved by the accountant, managers or directors of the HPPMB3

- Collecting or spending according to exact amount on invoices; all invoices are clearly recorded into cashier's book.

- Daily making updates into cashier's book and check it at the end of working day to ensure safety of safe.

- Making the balance of payment and spending at the end of month between cashier's book and accounting book.


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Annex 7

LIST OF DOCUMENTS PREPARED FOR ISO 9001


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Project Management Board 1 Quality policy.

2 Quality objectives.

3 Quality handbook.

4 Document control procedures.

5 Procedures of meetings by leaders for quality considerations.

6 Quality evaluation procedure.

7 Procedures of action taking for remedies and preventions.

Personnel Department. 8 Work description sheet P2.

9 Work description sheet P3.





14 Car Management Procedures.

15 HR Management Procedures.

16 Procedures for setting salaries.

17 Information management procedures.

18 Asset management procedures.

Planning Department 19 Procedures for establishing and managing capital construction investment plans

for each project.

20 Procedures of establishing, reviewing and approval of project unit rates.

21 Procedures of establishing and approval of bidding plans.

22 Bidding procedures.

23 Procedures of contractor assignment.

24 Procedures of management and payment of equipment and materials for each project.

25 Procedures of management of office equipment.

26 Schedule supervision Procedure.

27 Instructions for establishment of general schedule and follow up.

28 Instructions for management of contracts, treatment of delays and penalties.

Technical and Project Department 29 Procedure for review of ToR, survey and design and cost estimates.

30 Procedure for review and approval of technical design.

31 Procedure for review and approval of additional quantities and costs


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32 Procedure for review and approval of adjusted investment cost and cost estimate.

33 Procedure for control of non-conforming works.

34 Procedure for review and approval of feasibility studies.

35 Instructions for review of feasibility studies.

36 Procedure for review and approval of detail design and cost estimates.

37 Procedure for acceptance of civil works.

38 Procedure for acceptance of completed erection works.

39 Procedure for final acceptance of completed works.

40 Supervision procedures.

41 Instructions for recognition, delivery and management of documents.

42 Instructions for solving non-conforming technicalities in the works.

43 Instructions for handing over of bench marks.

44 Instructions for supervision of warranty.

45 Instructions for ensuring hygiene during project implementation.

46 Procedure of initiative /improvement.

Environment and Resettlement Department 47 Compensation procedures.

48 Instructions for procedures of applying for land for the project area.

49 Loss Survey instructions.

50 Instructions for establishment of compensation plan

51 Instructions for establishment and approval of criteria for compensation and resettlement.

52 Instructions for establishment and approval of resettlement plans.

53 Instructions for survey design and approval of resettlement sites.

54 Instructions for clearance organising.

55 Procedures for establishment, approval and execution of environment plan.

Finance and Accounting Department 56 Procedures for payment of the investment cost of the complete project.

57 Procedures for payment of works quantities for each period (instalments)

58 Procedures for payment of complete components.

59 Procedures for inventories and disposal of assets.

60 Procedures for programming the administrative cost.

61 Instructions for payment of administrative cost.

Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report Energy Production

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U:\Documents and Settings\MMJ\My Documents\SEID\PRADEEP\FINAL DEC 2006-NO TRACKS\Main Report\SB4 Energy.doc 04/09/2007

Table 1 Monthly Energy Production at Song Bung 4 Hydropower Project

Unit: GWh Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Mean1978 42,0 27,1 29,8 28,8 29,8 28,8 41,1 32,3 91,6 67,2 96,6 87,2 602,21979 44,4 30,3 29,8 28,8 44,4 95,8 40,3 47,4 41,1 59,6 67,2 33,7 562,91980 29,8 27,1 29,8 25,7 20,4 28,8 29,8 62,3 99,8 108,5 106,9 98,5 667,21981 77,7 49,9 39,7 40,6 49,1 65,8 46,6 36,9 40,6 90,0 110,3 107,7 754,71982 72,8 50,7 40,6 55,9 38,8 42,8 30,3 29,8 61,2 51,4 60,0 29,8 563,91983 27,1 27,1 29,8 16,9 14,0 23,1 29,8 29,8 28,8 28,6 91,5 67,6 414,01984 43,8 29,9 29,8 28,8 29,8 31,5 29,8 29,8 28,8 66,8 88,6 60,7 498,01985 32,6 27,1 29,8 28,8 29,8 28,8 29,8 29,8 28,8 60,2 91,8 77,3 494,41986 40,6 28,2 29,8 28,8 29,8 28,8 29,8 29,8 28,8 55,1 39,6 56,4 425,31987 29,8 27,1 29,8 28,8 24,1 28,8 26,9 25,4 26,1 32,6 92,8 39,1 411,31988 45,4 27,1 29,8 28,8 29,8 28,8 29,8 12,5 8,1 63,4 67,3 38,5 409,31989 38,6 27,1 29,8 28,8 29,8 28,8 29,8 29,8 28,8 29,8 16,7 0,0 317,71990 0,0 27,1 12,9 12,7 16,3 10,7 14,1 16,2 12,5 70,8 97,1 66,2 356,71991 50,1 34,6 30,6 28,8 29,8 28,8 29,8 29,8 28,8 45,4 51,8 57,2 445,41992 30,3 27,1 29,8 28,8 29,8 28,8 29,8 29,8 28,8 76,2 85,7 61,3 486,01993 38,5 27,2 29,8 28,8 29,8 33,3 34,6 29,8 45,9 82,6 59,5 87,1 526,81994 36,7 27,9 29,8 28,8 29,8 28,8 29,8 29,8 34,0 62,3 67,7 63,5 468,71995 30,8 27,1 29,8 28,8 29,8 28,8 29,8 29,8 28,8 78,7 104,3 88,3 534,71996 49,0 36,6 29,9 28,8 29,8 28,8 29,8 29,8 50,2 101,4 108,9 101,9 624,71997 71,8 47,4 37,3 35,4 44,4 30,7 29,8 29,8 46,4 69,5 58,7 43,5 544,51998 29,8 27,1 29,8 28,8 29,8 25,5 29,8 29,8 28,8 66,4 90,0 92,6 508,11999 81,5 55,4 44,8 48,5 87,7 67,4 36,1 40,1 40,3 73,6 108,7 106,5 790,72000 83,9 57,4 45,1 58,5 78,3 52,2 47,1 61,0 53,7 93,1 99,2 102,9 832,32001 69,1 41,9 48,6 31,0 39,7 34,5 29,8 69,0 39,4 65,4 71,3 76,5 616,22002 39,7 27,2 29,8 28,8 29,8 28,8 29,8 29,8 76,0 90,1 95,7 59,9 565,42003 33,7 27,1 29,8 28,8 29,8 28,8 29,8 29,8 57,4 84,4 77,8 66,8 523,92004 43,2 28,4 29,8 28,8 29,8 30,3 35,9 71,9 66,8 63,5 66,8 60,6 555,9

Mean 44,9 33,3 32,0 31,2 34,6 35,1 31,8 35,2 42,6 68,0 80,5 67,8 537,1Min 0,0 27,1 12,9 12,7 14,0 10,7 14,1 12,5 8,1 28,6 16,7 0,0 Max 83,9 57,4 48,6 58,5 87,7 95,8 47,1 71,9 99,8 108,5 110,3 107,7

Table 21

SONG BUNG 4 HYDROPOWER PROJECT

TENTATIVE COST ESTIMATE

Full Supply Level: 222.5 mMinimum Operating Level: 195 mInstalled Capacity: 156 MW

No. STRUCTURE AND PAY ITEM UNIT QUANTITY UNIT RATE COSTUSD MUSD

A PREPARATORY WORKSA1 Permanent Access Roads

New Road km 13.6 FS 7.20Relocation of Highway 14D FS 9.30Direct Cost Permanent Access Roads 16.50

A2 Site PreparationsLevelling of Sites FS 0.35Electrical and Mechanical Works FS 2.57Communications FS 0.33Temporary Houses for EVN FS 1.85Direct Cost Site Preparations 5.10Contingencies for Preparatory Works % of A1-A2 10 2.16

A TOTAL COST PREPARATORY WORKS 23.76

B CIVIL WORKSB1 Preliminary Works

Service Roads FS 1.49Auxiliary Works FS 2.29Clearing and Stripping m2 3,923 0.1 0.00Excavation Soil m3 34,978 1.3 0.04Excavation Rock m3 26,972 5.0 0.13Mass Concrete m3 419 38 0.02Structural Concrete, Open-air, M=250, pump m3 10,826 62 0.67Structural Concrete, Open-air, M = 200, head cover m3 2,815 62 0.17Formwork m2 33,587 3.3 0.11Tunnel Excavation, Access Tunnel m3 11,681 30.0 0.35Filter m3 1,050 10 0.01Rockbolts Ton 1.22 979 0.00Shotcrete m2 9,295 10.6 0.10Earthfill m3 56,690 1.4 0.08Rockfill Embankment m3 79,380 3.0 0.24Surface Grouting m 2,070 63 0.13Steel Ribs Ton 19.24 950 0.02Steel Reinforcement, Surface Ton 616 627 0.39Ankerbolts m 225 12.5 0.00Steelnet m2 4,004 15 0.06Miscellaneous % of B1 10 0.63Direct Cost Preliminary Works 6.94

B2 DamClearing and Stripping m2 127,183 0.1 0.02Excavation Soil m3 1,089,691 1.3 1.41Excavation Rock m3 71,586 5.4 0.39Surface Grouting m 16,307 63 1.03Backfill Rock m3 10,131 3.0 0.03RCC m3 301,060 36 10.74Mass Concrete m3 1,959 38 0.07Structural Concrete, M = 250, open-air m3 85,325 57 4.87Formwork m2 1,567 4.7 0.01Steel Reinforcement, Open-air Ton 4,693 627 2.94Miscellaneous % of B2 5 1.08Direct Cost Dam 22.58

Table 22

No. STRUCTURE AND PAY ITEM UNIT QUANTITY UNIT RATE COSTUSD MUSD

B3 SpillwayClearing and Stripping m2 14,763 0.1 0.00Excavation Soil m3 45,670 1.3 0.06Excavation Rock m3 30,267 5.4 0.16Backfill Rock m3 2,735 3.0 0.01Surface Grouting m 13,057 63 0.82Mass Concrete m3 1,168 38 0.04RCC m3 301,128 36 10.73Structural Concrete,M=300, open-air m3 42,094 67 2.82Structural Concrete, M =250, open-air m3 61,842 57 3.52Formwork m2 279,324 4.7 1.31Steel Reinforcement, Open-air Ton 5,292 627 3.32Miscellaneous % of B3 5 1.14Direct Cost Spillway 23.95

B4 WaterwaysClearing and Stripping m2 17,200 0.1 0.00Excavation Soil m3 427,465 1.6 0.68Excavation Rock m3 254,389 5.2 1.33Structural Concrete, Surface, M= 200 m3 22,612 59 1.33Steel Reinforcement, Surface Ton 1,107 627 0.69Formwork m2 59,470 4.2 0.25Underground Grouting m 12,526 49 0.61Tunnel Excavation, Headrace m3 207,973 30.0 6.24Tunnel Excavation, Penstock m3 9,726 40.0 0.39Tunnel Lining m3 85,239 86 7.33Shaft Excavation Surge Tank m3 10,876 54 0.59Raise Boring Penstock and Surge Tank m 100 2,000 0.20Rockbolts Ton 119 979 0.12Shotcrete, cm=10 m2 35,075 14.4 0.51Shaft Lining m3 4,678 88 0.41Steel Reinforcement, Underground Ton 3,211 850 2.73Steel Ribs Ton 270.40 950 0.26Ankerbolts m 17,892 12.5 0.22Steelnet m2 35,075 15.4 0.54Miscellaneous % of B4 10 2.44Direct Cost Waterways 26.88

B5 Power StationClearing and Stripping m2 19,291 0.1 0.00Excavation Soil m3 67,477 1.3 0.09Excavation Rock m3 130,797 5.0 0.65Mass Concrete m3 1,180 38 0.04Structural Concrete, Surface, M= 200, pump m3 550 61 0.03Steel Reinforcement, Surface Ton 2,343 627 1.47Backfill Earth m3 22,435 1.5 0.03Structural Concrete, Surface, M=250 m3 35,714 57 2.04Formwork m2 96,319 3.3 0.32Operation Building FS 0.49Other Works FS 0.03Miscellaneous % of B5 15 0.78Direct Cost Power Station 5.98

B6 Switchyard Clearing and Stripping m2 33,788 0.1 0.00Excavation Soil m3 140,114 1.3 0.18Excavation Rock m3 53,128 5.2 0.28Backfill Earth m3 71,897 1.5 0.11Structural Concrete, M= 200 m3 132 61 0.01Formwork m2 368 3.3 0.00Mass concrete m3 26 38 0.00Steel Reinforcement, Open air Ton 10 627 0.01Miscellaneous % of B6 5 0.03Direct Cost Switchyard 0.62

Contingencies for Civil Works % of B1-B6 10 8.69B TOTAL COST CIVIL WORKS 95.63

A+B TOTAL COST PREPATATORY WORKS AND CIVIL WORKS 119.39

Table 23

No. ITEM UNIT QUANTITY COSTMUSD

C ELECTRICAL AND MECHANICAL WORKSC1 Hydromechanical Equipment FS 7.36C2 Power Station Epuipment FS 32.68

Direct Costs Electrical and Mechanical Works 40.04

Contingencies for Electrical and Mechanical Works % of C1-C2 5 2.00C TOTAL COST ELECTRICAL AND MECHANICAL WORKS 42.04

D TRANSMISSION (NOT INCLUDED)Transmission Lines,220 kV, Double Circuit, AC 300 km FS 5.61Substation FS 1.20Direct Cost Transmission 6.81

Contingencies for Transmission % of D 7 0.48D TOTAL COST TRANSMISSION 7.29

C+D TOTAL COST ELECTROMECHANICAL WORKS AND TRANSMISSION 49.33


E ENVIRONMENTAL AND SOCIAL COSTSE1 Environmental Management Costs

Direct Costs Environmental Management Costs, Including Contingencies LS EIA 0.62

E2 Resettlement and Social Mitigation CostsDirect Costs Social Mitigation Costs, Including Contingencies LS REMDP 19.83

E TOTAL ENVIRONMENTAL AND SOCIAL COSTS 20.45


F ENGINEERING AND ADMINISTRATION INCL. CONTINGENCIES FS 12.52


G IMPLEMENTATION SUPPORT INCLUDING CONTINGENCIESG1 Implementation Supvervision Comsultant LS 4.95G2 Independent Monitoring Services LS 0.15

G TOTAL IMPLEMENTATION SUPPORT 5.10


H TOTAL COST A+B+C+D+E+F+G - 206.79

D:\FINAL DEC 2006-NO TRACKS\Main Report\Demand Forcast.doc

Power Demand Forecast-Master Plan VI Table 3 Whole Country Page 1

2005 2010 2015 2020 2025 Years Works GWh % GWh % GWh % GWh % GWh %

Low Scenario Agriculture, Forestry, Aquaculture 658 1.44 1168 1.27 1443 0.98 1716 0.79 2065 0.67 Industry and Construction 20909 45.77 44055 47.91 73391 49.96 111653 51.59 163798 53.09 Trade, Hotel and Restaurant 2022 4.43 5636 6.13 9292 6.33 14511 6.70 22410 7.26 Public & Management 20173 44.16 36042 39.20 53838 36.65 73751 34.08 98129 31.81 Others 1920 4.20 5047 5.49 8935 6.08 14802 6.84 22109 7.17 Commercial Electricity 45682 100 91948 100 146898 100 216433 100 308511 100 Transmission & Distribution Loss 12.0 10.8 9.6 8.5 7.5 Self use 2.7 3.0 3.6 4.0 4.2 Generation 53567 106669 169238 247352 349390 Max Capacity (MW) 9512 18513 28671 40922 57804 Per capita (kWh/cap.) 549 1048 1579 2189 2997

Base Scenario Agriculture, Forestry, Aquaculture 658 1.44 1229 1.27 1624 0.98 2061 0.80 2611 0.68 Industry and Construction 20909 45.77 46325 47.70 81559 49.44 131066 50.95 199296 52.29 Trade, Hotel and Restaurant 2022 4.43 6168 6.35 10528 6.38 17319 6.73 27550 7.23 Public & Management 20173 44.16 38042 39.17 59777 36.24 85629 33.28 119109 31.25 Others 1920 4.20 5347 5.51 11472 6.95 21185 8.24 32595 8.55 Commercial Electricity 45682 100 97111 100 164961 100 257260 100 381160 100 Transmission & Distribution Loss 12.0 10.8 9.6 8.5 7.5 Self use 2.7 3.0 3.6 4.0 4.2 Generation 53567 112658 190047 294012 431664 Max Capacity (MW) 9512 19553 32196 48642 71416 Per capita (kWh/cap.) 549 1106 1774 2629 3703


Power Demand Forecast-Master Plan VI Table 3 Whole Country Page 2


High Scenario Agriculture, Forestry, Aquaculture 658 1.44 1272 1.26 1672 0.97 2109 0.79 2658 0.67 Industry and Construction 20909 45.77 48201 47.65 84958 49.29 135398 50.60 204149 51.76 Trade, Hotel and Restaurant 2022 4.43 6354 6.28 10828 6.28 17719 6.62 28750 7.29 Public & Management 20173 44.16 39656 39.21 62412 36.21 88692 33.15 123089 31.21 Others 1920 4.20 5665 5.60 12485 7.24 23643 8.84 35741 9.06 Commercial Electricity 45682 100 101148 100 172354 100 267561 100 394388 100 Transmission & Distribution Loss 12.0 10.8 9.6 8.5 7.5 Self use 2.7 3.0 3.6 4.0 4.2 Generation 53567 117341 198565 305784 446645 Max Capacity (MW) 9512 20365 33639 50590 73894 Per capita (kWh/cap.) 549 1152 1853 2734 3872


Power Demand Forecast-Master Plan VI Table 3 Central Region Page 3

2005 2010 2015 2020 2025 Years Works

GWh % GWh % GWh % GWh % GWh %

Low Scenario Agriculture, Forestry, Aquaculture 84.9 1.85 166.2 1.80 218.6 1.48 279.4 1.23 360.1 1.04 Industry and Construction 1722.6 37.60 3718.4 40.24 6427.2 43.67 10619.8 46.74 17171.4 49.52 Trade, Hotel and Restaurant 175.0 3.82 492.5 5.33 827.5 5.62 1414.1 6.22 2202.0 6.35 Public & Management 2391.4 52.20 4318.6 46.73 6340.7 43.08 8871.9 39.05 12358.6 35.64 Others 207.0 4.52 545.0 5.90 904.3 6.14 1536.8 6.76 2584.7 7.45 Commercial Electricity 4580.9 100 9240.7 100 14718.3 100 22722.0 100 34676.8 100 Capacity (MW) 986 1938 3005 4495 6798

Base Scenario Agriculture, Forestry, Aquaculture 84.9 1.85 175.9 1.78 254.7 1.48 347.0 1.23 470.5 1.05 Industry and Construction 1722.6 37.60 3988.4 40.37 7398.6 42.91 12890.0 45.70 21736.8 48.51 Trade, Hotel and Restaurant 175.0 3.82 549.4 5.56 1004.7 5.83 1785.6 6.33 2900.1 6.47 Public & Management 2391.4 52.20 4579.4 46.36 7306.8 42.38 10768.6 38.18 15507.1 34.61 Others 207.0 4.52 585.7 5.93 1277.0 7.41 2413.0 8.56 4196.3 9.36 Commercial Electricity 4580.9 100 9878.6 100 17241.7 100 28204.3 100 44810.7 100 Capacity (MW) 986 2063 3502 5551 8741

High Scenario Agriculture, Forestry, Aquaculture 84.9 1.85 182.0 1.77 262.1 1.45 355.0 1.21 479.1 1.03 Industry and Construction 1722.6 37.60 4149.9 40.32 7707.0 42.76 13316.1 45.37 22266.1 48.00 Trade, Hotel and Restaurant 175.0 3.82 565.8 5.50 1023.2 5.68 1805.1 6.15 3020.7 6.51 Public & Management 2391.4 52.20 4773.6 46.38 7617.2 42.27 11130.1 37.92 16001.5 34.50 Others 207.0 4.52 620.6 6.03 1412.2 7.84 2742.0 9.34 4618.1 9.96 Commercial Electricity 4580.9 100 10291.9 100 18021.8 100 29348.3 100 46385.4 100 Capacity (MW) 986 2149 3661 5776 9048


Power Demand Forecast-Master Plan VI Table 3 Northern Region Page 4






Power Demand Forecast-Master Plan VI Table 3 Southern Region Page 5





Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report Existing Generating Capacity

SWECO International

D:\FINAL DEC 2006-NO TRACKS\Main Report\Existing Plants.doc 04/09/2007

Page 1

Table 4

Existing Generating Capacity Existing Thermal Power Plants

Region Plant Type Location Installed Capacity MW

Year of Commissioning

Northern Pha Lai 1 Coal Hai Duong 4x110=440 1985

Pha Lai 2 Coal Hai Duong 2x300=600 2001

Ninh Binh Coal Ninh Binh 4x25=100 1974

Uong Bi Coal Quang Ninh 55+50=105 1970

Na Duong Coal Lang Son 2x55=110 2004

Total 1,355

Southern Thu Duc Diesel HCM City 33+2x66=165 1966-1972

Thu Duc Gas HCM City 23.4+15+2x37.5=113.4 1988-1992

Ba Ria C/C Vung Tau 2x23.4+6x37.5+58.1+59.1=389 1992-2002

Can Tho Oil Can Tho 1x33=33 1975

Can Tho Gas Can Tho 2x38.5+2x39.1=155.2 1996-1999

Phu My 1 C/C Vung Tau 3x248+370=1,114 2002

Phu My 2-1 C/C Vung Tau 2x140+2x144+170+168=906 2002

Phu My 2.2 C/C Vung Tau 3x240=720 2002

Phu My 3 C/C Vung Tau 3x240=720 2004

Phu My 4 C/C Vung Tau 3x150=450 2004

Hiep Phuoc Oil HCM City 3x125=375 IPP

Vedan Oil HCM City 1x72=72 IPP

AMATA Oil 1x13=13 IPP

Formosa Coal 3x50=150 IPP

Total 5,376

Various Diesel Various 245

TOTAL 6,976

Song Bung 4 Hydropower Project, TA No. 4625-VIE Final Report Existing Generating Capacity

SWECO International

D:\FINAL DEC 2006-NO TRACKS\Main Report\Existing Plants.doc 04/09/2007

Page 2

Existing Hydropower Plants

Region Plant River Active Storage Mm3

Installed Capacity, MW

Year of Commissioning

Northern Thac Ba Chay 1,560 3x36=108 1970-1973 Hoa Binh Da 5,650 8x240=1,920 1989-1994 Total 2,028 Central Vinh Son Con 120 2x33=66 1994 Song Hinh Hinh 323 2x35=70 2000 Yali Se San 779 4x180=720 2001 Total 856 Southern Da Nhim Da Nhim 155 4x40=160 1963-1964 Tri An Dong Nai 2,547 4x100=400 1988-1989 Thac Mo Be 1,226 2x75=150 1985 Ham Thuan La Nga 523 2x150=300 2001 Da Mi La Nga 12 2x87.5=175 2001 Can Don Be 80 2x39=78 2004 Total 1,263 Small Hydro Various Various 51 TOTAL 4,198

Page 1

Table 5 Power Projects Considered in Master Plan VI and Scheduled Commissioning Hydropower Projects No Plant Name Capacity

MW Plan V Year

Plan VI Year

Current Status

1 Nam Mu 11 2006 Com. 2 Na Loi 9 2006 Com. 3 Suoi Sap 16 2006 Com. North Total 2006 36 4 Se San 3 260 2006 2006 Under construction 5 Se San 3A 100 2006 2006 Under construction Central Total 2006 360 6 Srokphumieng 54 2006 2006 Under construction South Total 2006 54 7 Nam Dong 22 2007 Planned 8 Minh Luong 22 2007 Planned 9 Huong son 1 18 2007 North Total 2007 62

10 Quang Tri 70 2007 2007 Under construction 11 Hchan Hmun 27 2007 Planned 12 PleiKrong 110 2007 2007/2008 Under construction 13 Ea Rong Rau 28 2007 Planned Central Total 2007 235

14 Dai Ninh 300 2007 2007 Under construction 15 Bac Binh 34 2008 2007 Under construction South Total 2007 334

16 Tuyen Quang 342 2008 2008 Under construction 17 Ban Ve 320 2009 2008 Under construction 18 Na Le 90 2009 2008 Start const. 05/06 19 Thai An 44 2008 Planned 20 Van Chan 35 2008 Planned 21 Ngoi Bo 35 2008 Planned 22 Coc San 40 2008 Planned 23 Seo Chung Ho 22 2008 Planned 24 Ngoi Phat 76 2008 Planned North Total 2008 1004

25 Song Ba Ha 250 2008 2008 Under construction 26 A Vuong 210 2008 2008 Under construction 27 Buon Kuop 280 2008 2008 Under construction 28 Buon Tua Srah 85 2008 2008 Under construction 29 Binh Dien 44 2008 2008 Start const. 05/06 30 Ea Krong Hnang 64 2008 2008 Start const. 05/06 31 Co Bi 48 2008 FS 32 Da Dang 16 2008 Planned 33 Central Small Hydro 1 55 2008 Planned Central Total 2008 1052

34 Dong Nai 3 180 2008 2008 Under construction South Total 2008 180

35 Ban Coc 30 2009 Start const. 06

Page 2

North Total 2009 30 36 Se San 4 360 2010 2009 Under construction 37 Sre Pok 3 220 2009 2009 Start const. 05/06 38 An Khe Ka nak 173 2009 2009 Start const. 05/06 39 Dak Tik 72 2009 2009 Start const. 05/06 40 La Ngau 38 2009 Planned 41 Central Small Hydro 2 84 2009 Planned Central Total 2009 947

42 Thac Mo (extend) 75 2009 2009 Start const. 05/06 South Total 2009 75

43 Cua Dat 97 2010 2010 Under construction 44 Ban Chat 200 2010 2010 Start const. 05/06 45 Song Hieu 53 2010 2010 Planned 46 Chu Linh 30 2010 Planned 47 Nhac Han 45 2010 Planned 48 Nam Chien 192 2010 2010 Start const. 05/06 North Total 2010 617

49 Dam Bri 72 2009 2010 Under construction 50 Song Tranh 2 160 2010 2010 Start const. 05/06 51 Dak Rinh 100 2010 2010 Start const. 05/06 52 Song Con 2 70 2010 2010 Start const. 05/06 Central Total 2010 402

53 Dong Nai 4 340 2010 2010 Under construction South total 2010 340

54 Son La 2400 2010/2012 2011/2013 Start const. 05/06 55 Huoi Quang 560 2011 PFS/FS North Total 2011 2960

56 Song Bung 2 128 2011 PFS/FS 57 Song Bung 4 165 2011 PFS/FS 58 Central Small Hydro 3 100 2011 Planned Central Total 2011 393

59 Serepok 4 28 2012 Planned 60 Thuong Kon Tum 220 2012 FS Central Total 2012 248

61 Dong Nai 2 80 2012 PFS/FS 62 Dong Nai 5 140 2012 PFS/FS 63 Duc Xuyen 52 2012 PFS/FS South Total 2012 272

64 Dak Mi 4 196 2013 PFS/FS 65 Dak Mi 1 210 2013 PFS/FS Central Total 2013 406

66 Lai Chau 1200 2014 PFS/FS 67 Hoi Xuan 75 2014 Planned North Total 2014 1275

68 Song Bung 5 85 2014 Planned Central Total 2014 85

69 Hua Na 180 2015 PFS/FS 70 Khe Bo 68 2015 Planned 71 Ta Thang 47 2015 Planned 72 North Small Hydro 100 2015 Planned North Total 2015 395

73 Nho que 2&3 230 2016 Planned North total 2016 230

Page 3

74 Bac Me 170 2017 Planned 75 Trung Son 310 2017 Planned 76 Ban Uon 3 80 2017 Planned North total 2017 560

77 Ban Uon 280 PFS/FS-out 78 Bao Lac 75 Out 79 Nam Na 300 Out Total out 655 Country total up to

2025 12552

Page 4

Coal-fired Power Projects

No

Plant Name Capacity MW

Plan V

Plan VI

Current Status

North 1 Uong Bi extended1 300 2005 2006 Finishing 2 Cao Ngan 100 2005 2006 Finishing North total-2006 400 3 Hai Phong I#1 300 2006 2008 Start

construction 4 Son §ong 200 2008 Start

construction North total-2008 500 5 Uong Bi extended2 300 2009 2009 FS/Gov.1195-

2009 6 Ninh Binh extended 300 2009 2009 FS 7 Hai Phong I#2 300 2007 2009 FS 8 Cam Pha I 300 2009 9 Quang Ninh 1 300 2007 2009 FS/Gov.1195-

2009 10 Quang Ninh 2 300 2008 2009 Gov.1195-2009 11 Quang Ninh 3 300 2011 2009 Gov.1195-2009 12 Quang Ninh 4 300 2012 2009 Gov.1195-2009 13 Mao Khe 1 200 2009 North total-2009 2600 Central

14 Nong Son 30 2009 FS Central total-2009 30 North

15 Hai Phong II #1 300 2010 Gov.1195-2009 16 Hai Phong II #2 300 2010 Gov.1195-2009 17 Cam Pha II 300 2010 FS/Gov.1195-

2009 18 Mong Duong #1 500 2013 2010 FS/Gov.1195-

2010 North total-2010 1400

19 Mao Khe 2 200 2011 20 Nghi Son #1 300 2009 2011 FS 21 Mong Duong #2 500 2014 2011 22 Vung Ang I #1 600 2017 2011 Gov.1195-2010 North total-2011 1600

23 Nghi Son #2 300 2010 2012 North total-2012 300 South

24 Soc Trang 1 600 2015 25 Soc Trang 2 600 2015 South total -2015 1200 North

26 Mong Duong II #1 500 2016 Gov.1195-2010 North total-2015 500

Page 5

27 Mong Duong II #2 500 2017 Gov.1195-2010 28 Vung Ang I #2 600 2017 Gov.1195-2010 North total-2017 1100 South

29 Tra Vinh 1 600 2017 30 Tra Vinh 2 600 2017 31 Tra Vinh 3 600 2017 32 Tra Vinh 4 600 2017 33 Soc Trang 3 600 2017 South total - 2017 30000 North

34 Nghi Son II #1 600 2018 35 Nghi Son II #2 600 2018 North total-2018 1200 South

36 Soc Trang 4 600 2018 37 Soc Trang 5 600 2018 38 Tien Giang 1 600 2018 South total 1800 North

39 Vung Ang II #1 600 2019 40 Vung Ang II #2 600 2018 2019 North total-2019 1200 Central

41 Central 1 600 2019 Central total-2019 600 South

42 Tien Giang 2 600 2019 43 Tien Giang 3 600 2019 South total-2019 1200 North

44 Nghi Son III #1 600 2020 45 Nghi Son III #2 600 2020 46 Vung Ang III #1 600 2020 47 Vung Ang III #2 600 2020 North total-2020 2400

48 New domestic #1 600 2021 49 New domestic #2 600 2021 North total-2021 1200

50 New domestic #3 600 2022 51 New domestic #4 600 2022 52 Import coal #1 1000 2022 North total-2022 2200 Central

53 Central 2 600 2022 Centre total 2022 600

54 Import coal #2 1000 2023 North total-2023 1000

Page 6

South 55 South 1000 #1 (Binh Thuan) 1000 2023 56 South 1000 #2 (Binh Thuan) 1000 2023 South total 2023 2000

57 Import coal #3 1000 2024 58 Import coal #4 1000 2024 North total-2024 1000 Central

59 Central 3 600 2024 Central total 600 South

60 South 1000 #3 (Binh Thuan) 1000 2024 South central 2024 1000 North

61 Import coal #5 1000 2025 62 Import coal #6 1000 2025 North total-2025 2000 Central

63 Central 4 600 2025 Central total 600 South

64 South 1000 #4 1000 2025 South total 1000 Country total-up to 2025 33,230

Page 7

Gas and Oil-fired Power Projects

No

Plant Name Capacity MW

Plan V Plan VI Current Status

South 1 Phu My extended 100 2006 FS/Gov. 1195-2006 South total-2006 100 2 Phu My fertilizer 20 2007 3 GT-GE 1,2,3,4 428 2007 4 Ca Mau 1 720 2005/2006 2007 South total-2007 1368 5 Nhon Trach I CC 450MW 450 2008 FS/Gov. 1195-2008 6 O Mon III 660 2011/2012 2008 Gov.1195-07/08 7 Ca Mau 2 720 2008 South total-2008 1830 8 O Mon I #1 300 2005 2009 FS South total-2009 300 9 O Mon I #2 300 2006 2010 10 O Mon II (1,2,3) 720 2009/2010 2010 PFS/Gov.1195-

2009 South total-2010 1020

11 Nhon Trach II #1 CC 330 2007 2012 12 Nhon Trach II #2 CC 330 2008 2012 13 O Mon IV 720 2012 South total-2012 1380

14 Binh Thuan I CC 720 2013 15 Nhon Trach III CC 720 2009 2013 South total-2013 1440

16 Binh Thuan II CC 720 2014 South total-2014 720

17 O Mon V (New CC#3) 720 2015 18 Nhon Trach IV CC 720 2010 2015 South total-2015 1440

19 Cai Lay I CC 720 2016 20 Cai Lay II CC 720 2016 South total-2016 1440 Central

21 Central new 720 2020 Central total 2020 720

22 New 6 CC 720 6x720,2013/2020

2020

South total-2020 720 23 New 7 CC 720 2021 South total-2021 720 Country total-up to 2025 11,358 Added from 2006 to

2025

Page 8

Candidates for Power Import No Plant Name Capacity

MW Plan V Plan VI Current

Status North 1 Import from China-110kV-

220kV 450 2007 Gov. 1195-

2007 2 L1. Nam Mo 95 2008 2011 3 Import from China 1 250 2019 2015 4 Import from China 2 250 2019 2016 5 Import from China 3 250 2019 2016 6 Import from China 4 250 2019 2016 7 Import from Lao (Nam Theun) 382 2011/2015 2017 8 Import from China 5 250 2019 2017 9 Import from China 6 250 2019 2017 10 Import from China 7 250 2019 2018 11 Import from China 8 250 2019 2018 North total up to 20025 2927 Central 12 L4. Xekaman 3 248 2011/2015 2010 13 L6. Sekong 4 464 2011/2015 2013 14 Xe Kaman 1 396 2011/2015 2016 15 L3. Nam Kong 1 229 2011/2015 2016 16 L7. Sekong 5 388 2011/2015 2016 17 Import from Cambodia (Ha

Sesan 3) 375 2016

Central total up to 2025 2100 South 18 Import from Cambodia (Hạ

Srepok2) 222 2019 2016

19 Import from Cambodia (Hạ Se San2)

207 2019 2016

South total up to 2025 429 Country total up to 2025 5456

Page 9

Some Key Parameters of Thermal Power Projects Considered in Master Plan VI

Gas Coal Oil Nuclear

Technology (Fuel) CC Gas

turbin Gas Domestic

Coal Domestic

Coal Import Coal

DO FO PWR

Region South South South North South South Unit (MBTU) (MBTU) (MBTU) (Tone) (Tone) (Tone) (Tone) (Tone) (Mkcal) Capacity MW 700 250 300 300 300 500 250 300 1000 Specific Investment cost (including IDC)

$/kW 600 400 900 1120 1120 1000 400 800 1740

Efficiency % 48 34 38 39.5 39.5 40.0 34 38 37 Fuel Consumption Kcal/kW

h 1792 2529 2263 2177 2177 2150 2529 2263 2324

Life time Year 25 20 25 30 30 30 20 20 40 Self use % 2.5 2.5 5.0 7.0 7.0 7.0 2.5 5.0 5.0 Fixed O&M cost $/kW.ye

ar 21.6 15.4 18.0 33.6 33.6 30.0 15.4 19.5 66.2

Variable O&M cost $/MWh 0.90 4.40 0.86 0.15 0.15 0.15 4.40 1.48 0.14 Discount rate % 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 (CFR) % 11.0 11.7 11.0 10.6 10.6 10.6 11.7 11.7 10.2 HLV Kcal/kg 8500 8500 8500 5500 5500 6500 10000 9900 Fuel price in the basis year* $/unit 3.5 3.5 3.5 21.0 28.0 45.0 391.0 220.0 1.8 Price increasing rate %/year 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 1.5 Levelized generation cost VS. load factor

USc/kWh

30 6.80 6.89 8.45 7.24 7.6 7.35 14.19 10.45 10.28 40 5.85 6.28 7.28 5.68 6.0 5.96 13.58 9.31 7.83 50 5.28 5.92 6.58 4.74 5.07 5.12 13.21 8.63 6.36 60 4.90 5.68 6.11 4.12 4.45 4.57 12.97 8.17 5.39 70 4.63 5.50 5.77 3.68 4.00 4.17 12.80 7.85 4.69 80 4.42 5.37 5.52 3.34 3.67 3.87 12.67 7.61 4.16 90 4.27 5.27 5.33 3.08 3.41 3.64 12.57 7.42 3.76


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D:\FINAL DEC 2006-NO TRACKS\Main Report\Profit and Loss.doc 04/09/2007

Table 6 Forecast Profit and Loss Statement (in USD) for Song Bung 4 - 2008-2047 IAS Profit & Loss Account 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2027 2037 2047Revenue

Sales of Electricity M USD 0,00 0,00 0,00 0,00 0,00 11,92 23,84 23,84 23,84 23,84 23,84 23,84 23,84 23,84Cost of Sales

O & M M USD 0,00 0,00 0,00 0,00 0,00 1,20 1,20 1,20 1,20 1,20 1,20 1,20 1,20 1,20Monitoring costs M USD 0,00 0,00 0,00 0,00 0,00 0,01 0,01 0,01 0,01 0,01 0,00 0,00 0,00 0,00Depreciation M USD 0,00 0,00 0,00 0,00 0,00 9,87 9,87 9,87 9,87 9,87 9,87 9,87 0,00 0,00Foreign exchange losses/(gains) M USD 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00Hydro power tax M USD 0,00 0,00 0,00 0,00 0,00 0,24 0,47 0,47 0,47 0,47 0,47 0,47 0,47 0,47

Total Cost of Sales M USD 0,00 0,00 0,00 0,00 0,00 11,32 11,56 11,56 11,56 11,56 11,54 11,54 1,67 1,67

Operating Profit M USD 0,00 0,00 0,00 0,00 0,00 0,60 12,29 12,29 12,29 12,29 12,30 12,30 22,17 22,17Finance Cost M USD 0,00 0,00 0,00 0,00 0,00 13,52 13,05 12,40 11,75 11,10 10,44 4,75 0,00 0,00

Profit Before Tax M USD 0,00 0,00 0,00 0,00 0,00 -12,92 -0,77 -0,12 0,53 1,19 1,85 7,55 22,17 22,17Profits tax M USD 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,15 0,33 0,52 2,11 6,21 6,21

Net Profit M USD 0,00 0,00 0,00 0,00 0,00 -12,92 -0,77 -0,12 0,38 0,85 1,33 5,44 15,96 15,96Dividend M USD 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,38 0,85 1,33 5,44 15,96 15,96

Retained profit M USD 0,00 0,00 0,00 0,00 0,00 -12,92 -0,77 -0,12 0,00 0,00 0,00 0,00 0,00 0,00


SWECO International


Table 7: Forecast Balance Sheets (in USD) for Song Bung 4 - 2008-2047 IAS Balance Sheet 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2027 2037 2047Assets

Current AssetsCash M USD 0,00 0,00 0,10 0,44 0,21 -7,25 -9,59 -9,45 -9,42 -9,40 -9,38 2,79 20,91 20,91Account Receivables M USD 0,00 0,00 0,00 0,00 0,00 0,99 1,99 1,99 1,99 1,99 1,99 1,99 1,99 1,99Inventories M USD 0,00 0,00 0,00 0,00 0,00 0,00 0,84 0,84 0,84 0,84 0,84 0,84 0,84 0,84

Total Current Assets M USD 0,00 0,00 0,10 0,44 0,21 -6,26 -6,77 -6,62 -6,60 -6,57 -6,55 5,62 23,74 23,74Non-Current Assets

Net Fixed Assets M USD 0,00 0,00 0,00 0,00 0,00 236,89 227,02 217,15 207,28 197,41 187,54 88,84 0,00 0,00Construction in Progress M USD 0,00 20,49 66,65 126,87 246,76 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00

Total Non-Current Assets M USD 0,00 20,49 66,65 126,87 246,76 236,89 227,02 217,15 207,28 197,41 187,54 88,84 0,00 0,00

Total Assets M USD 0,00 20,49 66,75 127,31 246,97 230,63 220,26 210,53 200,69 190,84 180,99 94,45 23,74 23,74

Liabilities & EquityCurrent Liabilities

Trade & Other Payables M USD 0,00 0,00 0,00 0,00 0,00 0,10 0,10 0,10 0,10 0,10 0,10 0,10 0,10 0,10Short-Term Loans M USDCurrent Portion of Long-Term B M USD 0,00 0,00 0,00 0,00 9,85 9,85 9,85 9,85 9,85 9,85 9,85 7,86 0,00 0,00

Total Current Liabilities M USD 0,00 0,00 0,00 0,00 9,85 9,95 9,95 9,95 9,95 9,95 9,95 7,96 0,10 0,10Long-Term Borrowings M USD 0,00 7,77 45,46 100,27 200,70 196,47 186,71 176,95 167,10 157,25 147,41 62,86 0,00 0,00

Total Liabilities M USD 0,00 7,77 45,46 100,27 210,55 206,41 196,66 186,90 177,05 167,20 157,35 70,82 0,10 0,10Equity

EVN Contribution M USD 0,00 12,72 21,29 27,05 36,42 37,14 37,29 37,44 37,44 37,44 37,44 37,44 37,44 37,44Retained profit M USD 0,00 0,00 0,00 0,00 0,00 -12,92 -13,69 -13,81 -13,81 -13,81 -13,81 -13,81 -13,81 -13,81

Total Equity M USD 0,00 12,72 21,29 27,05 36,42 24,22 23,60 23,64 23,64 23,64 23,64 23,64 23,64 23,64

Total Liabilities & Equity M USD 0,00 20,49 66,75 127,31 246,97 230,63 220,26 210,53 200,69 190,84 180,99 94,45 23,74 23,74


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Table 8: Forecast Cash Flow Statements (in USD) for Song Bung 4- 2008-2047 IAS Cash Flow 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2027 2037 2047Cash Flows from Operating Activities

Profit After Tax M USD 0,00 0,00 0,00 0,00 0,00 -12,92 -0,77 -0,12 0,00 0,00 0,00 0,00 0,00 0,00Adjustment for:

Depreciation & Amortization M USD 0,00 0,00 0,00 0,00 0,00 9,87 9,87 9,87 9,87 9,87 9,87 9,87 0,00 0,00Interest Expense M USD 0,00 0,00 0,00 0,00 0,00 13,52 13,05 12,40 11,75 11,10 10,44 4,75 0,00 0,00Foreign Exchange Loss M USD 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00

Subtotal M USD 0,00 0,00 0,00 0,00 0,00 10,47 22,16 22,16 21,62 20,97 20,31 14,62 0,00 0,00Change in Working Capital M USD 0,00 0,00 0,00 0,00 0,00 -0,89 -1,83 0,00 0,00 0,00 0,00 0,00 0,00 0,00

Net Cash Flows from Operating Activitie M USD 0,00 0,00 0,00 0,00 0,00 9,58 20,32 22,16 21,62 20,97 20,31 14,62 0,00 0,00

Cash Flows from Investing ActivitiesAcquisition of Fixed Assets and Cons M USD 0,00 -19,99 -44,00 -54,82 -109,72 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00

Net Cash Flows from Investing Activities M USD 0,00 -19,99 -44,00 -54,82 -109,72 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00

Cash Flows from Financing ActivitiesCash Proceeds from Long-Term Borr M USD 0,00 7,77 37,70 54,80 110,28 5,61 0,09 0,09 0,00 0,00 0,00 0,00 0,00 0,00Repayment of Loans M USD 0,00 0,00 0,00 0,00 0,00 -9,85 -9,85 -9,85 -9,85 -9,85 -9,85 -7,86 0,00 0,00Interest Expense M USD 0,00 -0,30 -1,83 -4,82 -10,13 -13,52 -13,05 -12,40 -11,75 -11,10 -10,44 -4,75 0,00 0,00Commitment fee M USD 0,00 -0,19 -0,34 -0,58 -0,04 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00 0,00Capital Injected (EVN) M USD 0,00 12,72 8,57 5,75 9,38 0,72 0,15 0,15

Net Cash Flows from Financing Activitie M USD 0,00 19,99 44,10 55,16 109,49 -17,04 -22,66 -22,01 -21,60 -20,95 -20,29 -12,61 0,00 0,00

Net Increase in Cash M USD 0,00 0,00 0,10 0,34 -0,23 -7,46 -2,34 0,15 0,02 0,02 0,02 2,01 0,00 0,00Cash at Beginning of Year M USD 0,00 0,00 0,00 0,10 0,44 0,21 -7,25 -9,59 -9,45 -9,42 -9,40 0,78 20,91 20,91Cash at End of Year M USD 0,00 0,00 0,10 0,44 0,21 -7,25 -9,59 -9,45 -9,42 -9,40 -9,38 2,79 20,91 20,91


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Table 9 Forecast Profit and Loss Statement (in VND) for Song Bung 4 - 2008-2047

IAS Profit & Loss Account 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2027 2037 2047Revenue

Sales of Electricity bn VND 0,0 0,0 0,0 0,0 0,0 195,9 391,9 391,9 391,9 391,9 391,9 391,9 391,9 391,9Cost of Sales

O & M bn VND 0,0 0,0 0,0 0,0 0,0 19,7 19,7 19,7 19,7 19,7 19,7 19,7 19,7 19,7Monitoring costs bn VND 0,0 0,0 0,0 0,0 0,0 0,2 0,2 0,2 0,2 0,2 0,0 0,0 0,0 0,0Depreciation bn VND 0,0 0,0 0,0 0,0 0,0 162,2 162,2 162,2 162,2 162,2 162,2 162,2 0,0 0,0Foreign exchange losses/(gains) bn VND 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 0,0Hydro power tax bn VND 0,0 0,0 0,0 0,0 0,0 3,9 7,8 7,8 7,8 7,8 7,8 7,8 7,8 7,8

Total Cost of Sales bn VND 0,0 0,0 0,0 0,0 0,0 186,0 189,9 189,9 189,9 189,9 189,8 189,8 27,5 27,5

Operating Profit bn VND 0,0 0,0 0,0 0,0 0,0 9,9 201,9 201,9 201,9 201,9 202,1 202,1 364,3 364,3Finance Cost bn VND 0,0 0,0 0,0 0,0 0,0 222,3 214,5 203,9 193,2 182,4 171,7 78,0 0,0 0,0

Profit Before Tax bn VND 0,0 0,0 0,0 0,0 0,0 -212,4 -12,6 -2,0 8,7 19,5 30,5 124,1 364,3 364,3Profits tax bn VND 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 2,4 5,5 8,5 34,7 102,0 102,0

Net Profit bn VND 0,0 0,0 0,0 0,0 0,0 -212,4 -12,6 -2,0 6,3 14,0 21,9 89,3 262,3 262,3Dividend bn VND 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 6,3 14,0 21,9 89,3 262,3 262,3

Retained profit bn VND 0,0 0,0 0,0 0,0 0,0 -212,4 -12,6 -2,0 0,0 0,0 0,0 0,0 0,0 0,0


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Table 10: Forecast Balance Sheets (in VND) for Song Bung 4 - 2008-2047

IAS Balance Sheet 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2027 2037 2047Assets

Current AssetsCash bn VND 0,0 0,0 1,7 7,2 3,4 -119,2 -157,7 -155,3 -154,9 -154,5 -154,1 45,9 343,7 343,7Account Receivables bn VND 0,0 0,0 0,0 0,0 0,0 16,3 32,7 32,7 32,7 32,7 32,7 32,7 32,7 32,7Inventories bn VND 0,0 0,0 0,0 0,0 0,0 0,0 13,8 13,8 13,8 13,8 13,8 13,8 13,8 13,8

Total Current Assets bn VND 0,0 0,0 1,7 7,2 3,4 -102,9 -111,2 -108,8 -108,4 -108,0 -107,7 92,4 390,1 390,1Non-Current Assets

Net Fixed Assets bn VND 0,0 0,0 0,0 0,0 0,0 3893,7 3731,5 3569,2 3407,0 3244,8 3082,5 1460,1 0,0 0,0Construction in Progress bn VND 0,0 336,7 1095,5 2085,4 4056,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0

Total Non-Current Assets bn VND 0,0 336,7 1095,5 2085,4 4056,0 3893,7 3731,5 3569,2 3407,0 3244,8 3082,5 1460,1 0,0 0,0

Total Assets bn VND 0,0 336,7 1097,2 2092,6 4059,4 3790,8 3620,3 3460,4 3298,6 3136,7 2974,9 1552,5 390,1 390,1

Liabilities & EquityCurrent Liabilities

Trade & Other Payables bn VND 0,0 0,0 0,0 0,0 0,0 1,6 1,6 1,6 1,6 1,6 1,6 1,6 1,6 1,6Short-Term Loans bn VNDCurrent Portion of Long-Term Borrobn VND 0,0 0,0 0,0 0,0 161,9 161,9 161,9 161,9 161,9 161,9 161,9 129,2 0,0 0,0

Total Current Liabilities bn VND 0,0 0,0 0,0 0,0 161,9 163,5 163,5 163,5 163,5 163,5 163,5 130,8 1,6 1,6Long-Term Borrowings bn VND 0,0 127,7 747,3 1648,0 3298,9 3229,2 3068,8 2908,5 2746,6 2584,7 2422,9 1033,2 0,0 0,0

Total Liabilities bn VND 0,0 127,7 747,3 1648,0 3460,7 3392,8 3232,3 3072,0 2910,1 2748,2 2586,4 1164,0 1,6 1,6Equity

EVN Contribution bn VND 0,0 209,0 350,0 444,5 598,7 610,5 612,9 615,5 615,5 615,5 615,5 615,5 615,5 615,5Retained profit bn VND 0,0 0,0 0,0 0,0 0,0 -212,4 -225,0 -227,0 -227,0 -227,0 -227,0 -227,0 -227,0 -227,0

Total Equity bn VND 0,0 209,0 350,0 444,5 598,7 398,1 387,9 388,5 388,5 388,5 388,5 388,5 388,5 388,5

Total Liabilities & Equity bn VND 0,0 336,7 1097,2 2092,6 4059,4 3790,8 3620,3 3460,4 3298,6 3136,7 2974,9 1552,5 390,1 390,1


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Table 11: Forecast Cash Flow Statements (in VND) for Song Bung 4- 2008-2047 IAS Cash Flow 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2027 2037 2047Cash Flows from Operating Activities

Profit After Tax bn VND 0,0 0,0 0,0 0,0 0,0 -212,4 -12,6 -2,0 0,0 0,0 0,0 0,0 0,0 0,0Adjustment for:

Depreciation & Amortization bn VND 0,0 0,0 0,0 0,0 0,0 162,2 162,2 162,2 162,2 162,2 162,2 162,2 0,0 0,0Interest Expense bn VND 0,0 0,0 0,0 0,0 0,0 222,3 214,5 203,9 193,2 182,4 171,7 78,0 0,0 0,0Foreign Exchange Loss bn VND 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

Subtotal bn VND 0,0 0,0 0,0 0,0 0,0 172,1 364,2 364,2 355,4 344,7 333,9 240,3 0,0 0,0Change in Working Capital bn VND 0,0 0,0 0,0 0,0 0,0 -14,7 -30,1 0,0 0,0 0,0 0,0 0,0 0,0 0,0

Net Cash Flows from Operating Activities bn VND 0,0 0,0 0,0 0,0 0,0 157,4 334,0 364,2 355,4 344,7 333,9 240,3 0,0 0,0

Cash Flows from Investing ActivitiesAcquisition of Fixed Assets and Construc bn VND 0,0 -328,6 -723,2 -901,0 -1803,5 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0

Net Cash Flows from Investing Activities bn VND 0,0 -328,6 -723,2 -901,0 -1803,5 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0

Cash Flows from Financing ActivitiesCash Proceeds from Long-Term Borrowin bn VND 0,0 127,7 619,6 900,8 1812,7 92,3 1,5 1,5 0,0 0,0 0,0 0,0 0,0 0,0Repayment of Loans bn VND 0,0 0,0 0,0 0,0 0,0 -161,9 -161,9 -161,9 -161,9 -161,9 -161,9 -129,2 0,0 0,0Interest Expense bn VND 0,0 -4,9 -30,1 -79,3 -166,5 -222,3 -214,5 -203,9 -193,2 -182,4 -171,7 -78,0 0,0 0,0Commitment fee bn VND 0,0 -3,2 -5,6 -9,5 -0,7 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0Capital Injected (EVN) bn VND 0,0 209,0 140,9 94,6 154,1 11,8 2,5 2,5 0,0 0,0 0,0 0,0 0,0 0,0

Net Cash Flows from Financing Activities bn VND 0,0 328,6 724,8 906,6 1799,7 -280,1 -372,5 -361,8 -355,0 -344,3 -333,5 -207,2 0,0 0,0

Net Increase in Cash bn VND 0,0 0,0 1,7 5,5 -3,8 -122,6 -38,4 2,4 0,4 0,4 0,4 33,1 0,0 0,0Cash at Beginning of Year bn VND 0,0 0,0 0,0 1,7 7,2 3,4 -119,2 -157,7 -155,3 -154,9 -154,5 12,8 343,7 343,7Cash at End of Year bn VND 0,0 0,0 1,7 7,2 3,4 -119,2 -157,7 -155,3 -154,9 -154,5 -154,1 45,9 343,7 343,7Cash at End of Year (USD check) M USD 0,00 0,00 0,10 0,44 0,21 -7,25 -9,59 -9,45 -9,42 -9,40 -9,38 2,79 20,91 20,91

Figure 1

A Vuo ng

So ng Tr a nh

Buo nKuo p

D.Na i4

SeSa n3

Hydr o po w er pl a nt s in Viet na m

Ba nCha t

Da Na ng

Ha No i

HCM c it y

Ho a Binh

Ya l y

Tha c Ba

Tr iAn

Da iNinhHa mThua n

ThKo nTum

SeSa n3A

Ba n La

D.Na i3

Da Mi

Da Nhim

Sr epo k 3

TuyenQua ng

Tha c Mo

Pl eiKr o ng

AnKhe

So ng Ba Ha

East Sea

China

La o s

Ca mbo dia

Tha iLa nd

Leg end:

Ea st Sea

Exist ing

Pl a nned

So ng Hinh

VinhSo n

Figure 2Song Bung 4 Hydropower Project

Tentative Construction Scedule

2008 2009 2010 2011 2012Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Preparatory Works

Commencement of Main Works

Dam and Spillway

Diversion Culvert

Foundation Excavation

Cofferdam

RCC Dam to El. 170 m

Dry Season Delays

RCC Dam to El. 198.5 m

Wet Season Delay

RCC Dam to El. 227.5 m

Spillway Concrete

Spillway Gates

Closure Diversion

Excavation of Plunge Pool

Intake

Excavation

Concrete Structure

Gates

Waterway

Adit Tunnels

Headrace Tunnel

Surge Shaft above El. 222.5 m

Surge Shaft below El. 222.5 m

Penstock

Penstock Lining

Tunnel Lining

Power Station

Excavation

Concrete Structure

Equipment

Transmission Line

Reservoir Filling and Commisioning

Reservoir Filling

First Unit

Second Unit

Construction Schedule.xls09/04/2007

Figure 3Song Bung 4 Hydropower Project

Tentative Implementation Scedule

2007 2008 2009 2010 2011 2012A S O N D J F M A M J J A S O N D J F M A M J J A S O N D Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

General ActivitiesPPTAApproval of Feasibility StudyLoan ProcessingBoard Approval of LoanLoan Effective

Technical Design and Bidding DocumentsPreparationApproval by EVN and ADB

Recruitment of Implementation Supervision ConsultantTORGeneral Procurement NoticeEOI by ConsultantsShortlisting of ConsultantsBidding, Evaluation, Negotiations, and ApprovalSigning of Contract

Procurement of Civil WorksPreparation and Approval of Prequalification DocumentsGeneral Procurement NoticeSpecific Procurement NoticePrequalificationBidding, Evaluation, Negotiations and ApprovalSigning of Contracts

Procurement of Electromechanical WorksGeneral Procurement NoticeSpecific Procurement NoticeBidding, Evaluation, Negotiations and ApprovalSigning of Contracts

ConstructionPreparatory WorksCommencement of Main WorksDam and SpillwayIntakeWaterwayPower StationPower Station EquipmentTransmission LineRelocation of Highway 14D

Relocation of Inundated VillagesPreparationsAccess Roads to Resettlement Sites

DesignAward of Contracts

Construction of Roads to Pa Rum A and Pa Rum BConstruction of Road to Pa Pang

Preparation of Resettlement SitesConsultations and Design

Award of ContractsConstruction

Implementation of ResettlementPayment of Compensation

Relocation to New SitesProvision of Subsidies

Downstream ProgramLivelihood Program for Pa Dau 2 Village

Dai Son RoadLivelihood Program for Dai Son Commune

Project Lands-Consultations, DMS, REMDP, CompensationConstruction Area

Relocation of Highway 14DTransmission Line

Reservoir Filling and CommisioningReservoir Filling Commisioning of First UnitCommisioning of Second Unit

2006

Implementation Schedule.xls09/04/2007

Figure 4

EVN ADB Directorate CommitteeQuang Nam Province

Project Director

Compensation, Support and Project Manager Resettlement Council

Nam Giang District

IndependentMonitoring

Finance and Accounting Project Materials & Equipment Environment & Resettlement Implementation Team Department Department Department Department

ImplementationSupervisionConsultant

Note:ADB-financed

Consultant

ORGANIZATION CHART FOR PROJECT MANAGEMENT OFSONG BUNG 4 HYDROPOWER PROJECT