Power System Development Plan
for Lao PDR
FINAL REPORT
Volume A : Main Report
August 2004
*
POWER SYSTEM DEVELOPMENT PLAN FOR LAO PDR
Prepared for Lao People’s Democratic Republic Ministry of Industry & Handicrafts Department of Electricity World Bank
FINAL REPORT
VOLUME A: MAIN REPORT
Prepared by Maunsell Limited* in association with Lahmeyer GmbH 47 George Street, Newmarket PO Box 4241, Auckland New Zealand
August 2004
* formerly known as Meritec Limited
POWER SECTOR DEVELOPMENT PLAN FOR LAO PDR (August 2004)
LIST OF DOCUMENTS
VOLUME A : MAIN REPORT
Volume B : Annexes
Volume C : Project Catalogue
TABLE OF CONTENTS
1.0 EXECUTIVE SUMMARY...... 1
1.1 Background ...... 1
1.2 Demand Forecast...... 1 1.2.1 Domestic Market ...... 1 1.2.2 Export Market...... 3
1.3 Project Evaluation ...... 4 1.3.1 Evaluation Methodology...... 4 1.3.2 Environmental Evaluation of Shortlisted Projects ...... 4 1.3.3 Ranking of Projects ...... 5
1.4 Lao Power System Development ...... 7 1.4.1 Methodology...... 7 1.4.2 Grid Interconnection Strategy ...... 8 1.4.3 Northern Region...... 9 1.4.4 Central Region ...... 9 1.4.5 Southern Region ...... 11 1.4.6 Transmission and Distribution...... 13 1.4.7 Off-Grid Electrification ...... 13 1.4.8 Domestic Power System Investment Program...... 13
1.5 Export Market Development...... 14 1.5.1 Export Scenarios...... 14 1.5.2 GOL Revenues from Export Development...... 14
1.6 Nam Theun 2 Issues ...... 16 1.6.1 Scope of Studies ...... 16 1.6.2 Alternative Reservoir Full Supply Levels...... 16 1.6.3 Comparison of Price for Domestic Power Off-take from Nam Theun 2 ...... 17 1.6.4 Comparison of Government Receipts ...... 17 1.6.5 Absorption of Domestic Off-take ...... 18
2.0 BACKGROUND...... 19
2.1 Objectives of PSDP...... 19
2.2 Structure of the Draft Final Report ...... 20
2.3 The Consultant ...... 20
2.4 Acknowledgements ...... 20
3.0 OVERVIEW OF LAO POWER SECTOR ...... 21
3.1 Setting ...... 21 3.1.1 Development of the Power Sector ...... 21 3.1.2 Planning and Financing Lao Power Projects ...... 22 3.1.3 Future Trends...... 24
3.2 Power Sector in Lao PDR ...... 25 3.2.1 Status of Power System...... 25 3.2.2 Electricity Trade with Neighboring Countries ...... 29 3.2.3 EdL System Development...... 30
3.3 Review of Past Studies ...... 31 3.3.1 Summary of Key Studies...... 31 3.3.2 Reconciliation of Study Differences ...... 33
3.4 Overview of PSDP Planning Methodology ...... 35
4.0 LAO POWER MARKET...... 36
4.1 Load Analysis ...... 36 4.1.1 Analysis of System Load Data ...... 36 4.1.2 Load Profiles ...... 38 4.1.3 Load Duration Curves ...... 40
4.2 Demand Forecast for Lao PDR ...... 42 4.2.1 Basis of Forecast ...... 42 4.2.2 Assumptions...... 42 4.2.3 PSDP Base Case Scenario Assumptions ...... 46 4.2.4 Comparison of PSDP and EdL Forecasts...... 46
5.0 EXPORT POWER MARKET ...... 49
5.1 Regional Market ...... 49 5.1.1 Regional Cooperation ...... 49 5.1.2 Energy Distribution within GMS Region ...... 49 5.1.3 Electricity Trading among GMS Countries ...... 51 5.1.4 Regional Electricity Demand ...... 52
5.2 Thailand...... 53 5.2.1 Sector Development and Reform...... 53 5.2.2 Energy Resources for Generation...... 54 5.2.3 Demand for Electricity in Thailand ...... 55 5.2.4 Load Profiles ...... 56 5.2.5 Distribution of Power Demand and Generation...... 59 5.2.6 Sources of Future Generation...... 60 5.2.7 Candidate Power Plants...... 62 5.2.8 Opportunities for Power Exports to Thailand from Lao PDR...... 63
5.3 Vietnam ...... 64 5.3.1 Energy Resources...... 64 5.3.2 Power and Energy Demand ...... 65 5.3.3 Load Profiles ...... 69 5.3.4 Cooperation with Neighboring Countries ...... 70 5.3.5 Opportunities for Power Exports to Vietnam from Lao PDR ...... 71
5.4 Cambodia ...... 72 5.4.1 Overview of Sector...... 72 5.4.2 Energy Resources...... 73 5.4.3 Demand for Electricity ...... 73 5.4.4 Generation and Transmission Development...... 74 5.4.5 Scope for Imports and Exports...... 79
5.5 Yunnan Province, Peoples Republic of China...... 79 5.5.1 Energy Resources...... 79 5.5.2 Scope for Imports and Exports...... 80
5.6 Myanmar ...... 80 5.6.1 Energy Resources...... 80 5.6.2 Scope for Imports and Exports...... 81
5.7 Export Prospects for Lao Hydropower ...... 82
5.8 Import and Export Prices...... 82 5.8.1 Current Import and Export Tariffs...... 82 5.8.2 Pricing Principles...... 84 5.8.3 Marginal Costs in Thailand...... 84 5.8.4 Prices for Exports to Thailand ...... 88 5.8.5 Prices for Imports from Thailand ...... 90 5.8.6 Prices for Power Trade with Vietnam...... 91 5.8.7 Power Trade with Other Countries...... 92
6.0 CANDIDATE POWER PROJECTS...... 94
6.1 Status of Projects ...... 94 6.1.1 Previous Project Assessments...... 94 6.1.2 EdL Generation Expansion Plan ...... 96 6.1.3 Concession Commitments ...... 97 6.1.4 PSDP Candidate Projects ...... 98
6.2 Hydrology ...... 100
6.3 Project Evaluation Methodology...... 102 6.3.1 Evaluation Overview ...... 102 6.3.2 Evaluation Process ...... 103 6.3.3 Project Evaluation Software ...... 104 6.3.4 Project Cost Estimation...... 107
6.4 Project Screening ...... 108 6.4.1 Screening Process ...... 108 6.4.2 Screening Results ...... 109
6.5 Evaluation of Hydropower Projects ...... 111 6.5.1 Overview of Evaluation Methodology...... 111 6.5.2 Performance of Hydropower Projects ...... 112
6.6 Evaluation of Thermal Projects...... 113 6.6.1 Evaluation Methodology...... 113 6.6.2 Performance of Thermal Projects ...... 113 6.6.3 Comparison with Gas-fired Plant ...... 119
6.7 Project Interactions...... 121 6.7.1 Types of Interaction...... 121 6.7.2 Nam Ngum Basin Projects ...... 123 6.7.3 Nam Theun Basin Projects ...... 123 6.7.4 Xe Kaman Basin Projects ...... 124 6.7.5 Xeset Basin Projects ...... 124 6.7.6 Nam Ngum 1 Extension Project ...... 128 6.7.7 Theun Hinboun Expansion Project...... 129
6.8 Environmental and Social Impacts ...... 130 6.8.1 Preamble...... 130 6.8.2 The SESAMEE MODEL...... 133 6.8.3 Soft and Hard Impacts ...... 136 6.8.4 Calculation of Economic Costs and Benefits of Impacts...... 138 6.8.5 SESAMEE and EVALS Outputs Combined ...... 142
6.9 Standardized Ranking of Projects ...... 145 6.9.1 Basis of Ranking ...... 145 6.9.2 Ranking of Shortlisted Projects ...... 145
7.0 DOMESTIC POWER SYSTEM EXPANSION ...... 147
7.1 Planning Overview ...... 147 7.1.1 System Planning Objectives ...... 147 7.1.2 Features of the Lao Power System...... 149 7.1.3 Planning Issues...... 150 7.1.4 Selection of New Generation Projects ...... 152 7.1.5 Role of IPP Projects in Generation Expansion...... 152
7.2 Planning Principles, Parameters and Constraints ...... 155 7.2.1 Economic Evaluation Methodology ...... 155 7.2.2 Assumptions and Constraints ...... 155 7.2.3 Planning Horizon...... 157 7.2.4 Power Plant Data ...... 157 7.2.5 International Interconnections ...... 157 7.2.6 Import and Export Tariffs...... 158
7.3 SEXSI Power System Planning Model...... 159
7.4 Power System Expansion Scenarios ...... 160 7.4.1 Grid Interconnection Analysis ...... 160 7.4.2 System Development – Northern Supply Area ...... 162 7.4.3 System Development – Central Grid...... 163 7.4.4 Development Scenarios - Southern Grid ...... 168 7.4.5 Sensitivity of Expansion Plans to Demand...... 177 7.4.6 Preparation of Domestic Generation Projects...... 177
7.5 National Transmission Development...... 179 7.5.1 Transmission Objectives ...... 179 7.5.2 Transmission Planning...... 179 7.5.3 Grid Interconnection...... 180 7.5.4 Extension of the EdL Grids ...... 182 7.5.5 Impact of IPP Schemes on National Grid Development ...... 182
7.6 MV and Distribution Planning ...... 183 7.6.1 Distribution Objectives ...... 183 7.6.2 Marginal Costs of Grid Based Distribution ...... 184
7.7 Off-Grid Development ...... 185 7.7.1 Off-Grid Targets ...... 185 7.7.2 Off-Grid Renewable Energy Electrification Pilot Project ...... 186 7.7.3 Off-Grid Technologies ...... 186
7.8 Domestic Power System Investments...... 188 7.8.1 Overview ...... 188 7.8.2 Capital Investment Schedule ...... 188 7.8.3 Average Incremental Costs for System...... 192
8.0 EXPORT POWER DEVELOPMENT...... 196
8.1 Objectives of Power Exports ...... 196
8.2 Export Candidate Projects...... 196 8.2.1 Status of Lao Export Program...... 196 8.2.2 Separation of Domestic and Export Programs...... 197 8.2.3 Development of Export Development Scenarios ...... 198
8.3 Transmission Development for Export ...... 202 8.3.1 Background ...... 202 8.3.2 Lao National Electricity Transmission Grid ...... 203 8.3.3 Regional Grid Development ...... 206 8.3.4 Transmission Development within Thailand and Vietnam ...... 209
9.0 FINANCIAL EVALUATION OF POWER PROJECTS ...... 211
9.1 Objectives of Financial Evaluations...... 211
9.2 Financial Evaluation Methodology...... 211 9.2.1 Financial Modeling ...... 211 9.2.2 Financial Modeling Parameters...... 213 9.2.3 Financial Effects of Environmental and Social Impacts ...... 213
9.3 Financial Modeling of Projects for Domestic Supply ...... 217 9.3.1 Required Tariffs for Bankability ...... 217 9.3.2 Role of Development Agencies in Financing of Projects ...... 220
9.4 Financial Modeling of Projects for Export Markets ...... 221 9.4.1 Marketing of Project Output ...... 221 9.4.2 GOL Net Revenue Benefits...... 222
10.0 NAM THEUN 2 ISSUES ...... 224
10.1 Scope of Nam Theun 2 Issues...... 224
10.2 Comparison of Full Supply Levels ...... 224 10.2.1 Effect of FSL on Economic Performance ...... 224 10.2.2 Run-of-River Case ...... 225 10.2.3 Ban Signo Case ...... 226
10.3 Comparison of Benefits from Nam Theun 2 ...... 227 10.3.1 Scope of Benefits Review ...... 227 10.3.2 Least Cost Domestic Supply ...... 227 10.3.3 GOL Revenues from Nam Theun 2 Export Sales ...... 228
10.4 Absorption of Domestic Off-take...... 230
1.0 EXECUTIVE SUMMARY
1.1 Background
In Lao PDR, the power sector serves two vital national priorities:
(i) It promotes economic and social advancement by providing a reliable and affordable domestic power supply.
(ii) It earns foreign exchange from electricity exports.
Strategic planning of the sector under the Power System Development Plan (PSDP) considers system development for best furthering both domestic and export objectives. Power planning in Lao PDR has in the past been largely intuitive but as the national and regional power systems expand and integrate, the optimal direction of development is becoming more difficult to determine. A rational development plan is needed to guide sector expansion and several planning and strategy studies have been prepared in response to this need. However, they are to some extent fragmentary and contradictory. The Power System Development Plan builds on this previous work to outline a development path for the period from 2005 to 2020.
On a domestic level, the Lao power system is still in an early stage of development. Currently only 41% of households in Lao PDR are electrified but the Government of Lao PDR (GOL) has committed itself to increasing this to 90% by 2020.
On an international level, power markets in the Greater Mekong Sub-region are changing. Bilateral power trading is already established and Lao PDR has been a key participant in this development. The trend towards closer regional cooperation continues and this is opening up wider opportunities. Regional grid integration and market structures are planned, though their scope and timing remain open.
1.2 Demand Forecast
1.2.1 Domestic Market
The reference point in formulating a development plan for the Lao power system is the forecast of demand established by the Government’s target of electrifying 90% of household by 2020. This target will be achieved by:
(i) Off-grid development – a program of off-grid electrification targets 150,000 household installations by 2020.
(ii) Grid extension program to increase on-grid household electrification to meet the balance of households required to achieve the GOL’s target.
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The PSDP base case demand forecast for grid-supplied electricity (excluding exports) is based on the current EdL forecast, as published in the Power Development Plan (PDP) 2002-12, System Planning Office, Development Division, EdL, July 2003. The following adaptations to the EdL forecast were made:
(i) 2002 load data from EdL substations was collected and analyzed, and dimensionless load duration curves were developed. Based on the load analysis, the anchor pont of the forecast, the 2002 energy demand data, was adjusted to reflect measured data.
(ii) Information from the load analysis on the average weekly load profile and seasonal distribution of peak loads was generated. Diversity effects were taken into account as the separate grids are interconnected.
(iii) GOL’s intermediate 2005 household electrification target was revised downward by 45% to smooth out a period of abrupt growth implied by this target.
(iv) Off-grid household electrification was taken into account in determining the on-grid electrification program needed to achieve GOL’s 2020 target.
(v) Additional industrial point loads have been allowed for in the Central 2.1 grid (Khamouanne Province).
The PSDP aggregate demand forecast for the country is compared with the EdL forecast in Table 1.1.
Table 1.1: Comparison of EdL and PSDP Forecast
Item Unit 2002 2005 2010 2015 2020 1/ EdL PDP Demand Forecast:
Energy Consumption GWh 968.8 1,839.3 2,775.9 3,716.8 4,834.2 Av. annual Growth Rate % 24% 9% 6% 5% Peak Load MW 204.7 367.7 542.8 727.9 948.8 Av. annual Growth Rate % 22% 8% 6% 5% Load Factor % 55.3% 55.6% 60.0% 60.0% 60.0% PSDP Demand Forecast: Energy Consumption GWh 937.0 1,731.3 2,695.0 3,559.8 4,664.2 Av. annual Growth Rate % 23% 9% 6% 6% Peak Load MW 197.8 338.8 486.4 642.9 836.4 Av. annual Growth Rate % 20% 7% 6% 5% Load Factor % 54% 58% 63% 63% 64%
1/ Source of EdL froecast: Summary of Electricity Demand Forecast (High Case), EdL PDP Plan, EdL Power Development Plan PDP 2002-12, July 2003
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1.2.2 Export Market
The Greater Mekong Subregion (GMS), comprising Lao PDR, Thailand, Vietnam, Cambodia, Myanmar and Yunnan Province of the People’s Republic of China, is endowed with substantial energy reserves, but they are unevenly distributed between member countries. Due to its energy surplus and geographical location at the hub of the GMS region, Lao PDR is strategically positioned to play a significant role in promoting regional power trade.
The primary markets for Lao PDR are Thailand and Vietnam. These markets are large compared with the potential supply from Lao PDR and trade is therefore constrained by price rather than demand. Opportunities are also influenced by other factors including:
• Relative costs of hydropower and thermal generation;
• Progress in establishing regional 500 kV transmission interconnections;
• Timing and nature of power market reforms within GMS countries;
• Availability of, and competition for, capital;
• Progress of large hydropower developments in neighboring countries.
The expected price range for power trade with Thailand, based on avoided costs within the Thai system is summarized in Table 1.2.
Table 1.2: Summary of Price Range for Lao Power Trade with Thailand
Exports Imports
Contract - Firm Primary Energy Low 0.036 0.046 High 0.051 0.061
Contract - Firm Secondary Energy Low 0.022 0.032 High 0.027 0.037
Contract - Non-firm Energy Low 0.015 0.025 High 0.020 0.030
Notes: 10% discount rate $ 0.005 per kWh wheeling rate.
Discount Rate Sensitivity 6% 8% 10% 12% 14% EXPORTS - Firm Primary Energy Low 0.033 0.035 0.036 0.038 0.040 High 0.045 0.048 0.051 0.054 0.057 ----- IMPORTS - Firm Primary Energy Low 0.043 0.045 0.046 0.048 0.050 High 0.055 0.058 0.061 0.064 0.067
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Prices for future power trade with Vietnam and other GMS countries cannot be meaningfully specified until transmission linkages are firmly planned. Nevertheless, the basic principles governing price determination in the Thai market would also apply to other markets; i.e. Lao PDR will be able to trade power at a price up to the marginal cost of generation (capacity and energy), as adjusted for the cost of wheeling.
Under current economic conditions five or six hydropower sites have the qualities needed for profitably serving either the Vietnamese or Thai markets. With growing demand in the region, increasing global energy prices and rising concern about greenhouse gasses, it is reasonable to expect an improvement in market conditions opening the way for other projects.
1.3 Project Evaluation
1.3.1 Evaluation Methodology
The TOR named 28 hydropower and two thermal projects for evaluation. The number of projects swelled to 33 after several new hydropower sites were added and one was dropped after it was found to be non-viable.
Projects were evaluated on a standalone basis and also, as appropriate, in a basin context or in conjunctive operation with other projects. Desktop techniques were employed. No fieldwork was involved; evaluations used existing data. As appropriate, evaluations were based on a common set of assumptions to facilitate project comparisons on a consistent basis.
The projects were evaluated in a two-stage process:
(i) Screening: Projects were evaluated initially on a technical and economic level using the Lahmeyer hydro project dimensioning and evaluation software, “EVALS”. Projects were compared on the basis of their weighted average generation costs (calculated assuming a value for secondary energy at only half the rate for primary). Those with values over a prescribed threshold were discarded unless by virtue of their system fit they were likely to perform a useful function in the domestic system. Nineteen hydropower sites were shortlisted.
(ii) Evaluation and Ranking: Shortlisted projects were studied in more detail. Economic evaluations were preformed using EVALS. The project cash flows were adjusted to incorporate the monetary values of their positive and negative social and environmental effects. The value of weighted average generation cost, adjusted for social and environmental impacts, was used to rank projects.
1.3.2 Environmental Evaluation of Shortlisted Projects
For shortlisted projects, social and environmental effects were internalized into the evaluation and ranking process by reducing all impacts to monetary valuations. This was done using a new spreadsheet model, SESAMEE, to
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process the many parameters involved in valuing project impacts. The model’s algorithms use market values and other input data to calculate positive and negative cash flows associated with each impact event.
Two sets of cash flows were calculated using alternative market valuations as follows:
• international (“global”) values; and • Lao (“local”) values.
Each of the SESAMEE cash flows were separately combined with the project’s economic cash flows to give aggregate cash flows corresponding to global and local market valuations. The project rankings in Table 1.3 are based on cash flows derived from global market values.
The SESAMEE approach introduces into the project evaluations large positive and negative cash flows hitherto neglected or externalized in traditional project evaluation methodologies. The influence of the SESAMEE cash flows on the ranking of projects, though, is minor except in one or two cases where projects are associated with significant environmental issues.
The SESAMEE model is new and only limited verification has been possible within the PSDP timeframe. Calibration tests against existing impact studies were reassuring.
1.3.3 Ranking of Projects
Shortlisted projects are ranked according to their relative economic performance as measured by their weighted generation costs calculated using EVALS and SESAMEE. Project rankings are presented in Table 1.3.
Projects were also analyzed on a financial basis to determine the financial tariff needed to satisfy investors and lenders. Hurdle rates were assumed as follows:
• nominal, after-tax return on equity of 17% • minimum debt service coverage ratio of about 1.3.
A standard set of assumptions was made regarding loan conditions and concession terms to ensure comparability. The results are formatted into a supply curve (Figure 1.1).
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Table 1.3: Economic Ranking of Shortlisted Projects
Rank Project Project Type Installed Annual Adjusted Capacity Energy Weighted Output Gen’tn Cost 1/
(MW) (GWh p.a.) (¢/kWh) 1 Nam Theun 2 Storage / transfer 1074 5922 1.6 2 Theun Hinboun Expansion Storage / transfer 105 686+ 2.4 3 Thakho R-of-R / Mekong 30 214 2.6 4 Nam Mo Storage 125 603 2.7 5 Xe Kaman 3 Storage 250 1369 2.8 6 Xe Kaman 1 (u/s reg.) Storage 470 2086 3.1 7 Nam Ngum 2 (u/s reg.) 2/ Storage 460 1901 3.2 7a Nam Ngum 2B 2/ Storage 140 196 8.7 8 Xe Kong 5 Storage 400 1795 3.2 9 Nam Sane 3 Storage 60 283 3.3 10 Nam Ngiep 1 (+ reg dam) Storage 330 1537 3.8 11 Xe Kong 4 (u/s reg.) Storage 490 2257 3.8 12 Nam Ngum 3B 2/ Storage 530 2167 4.1 12a Nam Ngum 3 2/ Storage 690 2859 3.9 13 Houay Lamphan Gnai Storage 60 250 4.0 14 Nam Pot Storage 25 99 4.6 15 Nam Ngum 5 Storage 75 317 5.4 16 Nam Bak 2B (u/s reg.) Storage / transfer 85 389 5.6 17 Nam Long Storage 12 63 6.2 18 Nam Sim Storage 10 47 7.1 19 Xe Katam Run-of-river 13 60 8.1
1/ The ranking parameter “Weighted Generation Cost” is explained in Section 6.3.3. “Adjusted” Weighted Generation Cost refers to the adjustment for environmental and social effects (positive and negative) calculated using SESAMEE. 2/ Alternative developments on the Nam Ngum 2 and Nam Ngum 3 sites are considered.
If a project is to be promoted for IPP export development, the supply curve indicates whether it is bankable at the avoided cost prevailing at the time in the target market. If a project is to be promoted for IPP domestic supply, the supply curve indicates the wholesale tariff EdL would need to pay for bankability.
The economic ranking in Table 1.3 and the financial supply curve in Figure 1.1 are indicative and should not color judgments about specific projects. The PSDP evaluations are based on standard assumptions reflecting present conditions and do not factor in changes that may occur over the planning period. They also take no account of the potential for developers to boost the attractiveness of a project by the way they package it.
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Figure 1.1: Financial Supply Curve of Projects (nominal ROE of 17%)
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1.4 Lao Power System Development
1.4.1 Methodology
Power system expansion planning was undertaken to determine for each of EdL’s grids:
• The optimal timing of interconnection; and
• The least-cost expansion scenarios that satisfy projected demand and meet system reliability criteria.
System expansion scenarios were formulated and then analyzed using Lahmeyer’s SEXSI system planning software. SEXSI is a simulation program designed for predominantly hydro systems and takes seasonality and annual variability of flows into account in optimizing expansion scenarios.
Generation in the evaluated scenarios were drawn from alternative sources as follows:
(i) Construction of domestic generation projects: With the growing size and interconnection of the main grids, the economic option now is to develop fewer, but larger, projects to exploit economies of scale.
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However, with a number of the more attractive sites now the subject of IPP mandates, the curious situation is arising where Lao PDR is putting the interests of its neighbors ahead of its own.
(ii) Purchases from IPP export projects:. Reliance on power purchases from IPPs up to the limit of the specified domestic entitlement is cost- effective and has the additional benefit of minimizing EdL’s capital requirements over the next five to ten years. However, this strategy involves uncertainty in, and lack of control over, the commissioning dates of new IPP capacity. Contingency planning involves the use of imports to buy time to implement a prepared fall-back scenario.
(iii) Purchases from Thailand: Interconnection of the EdL and EGAT systems confers significant power system planning advantages:
- Surplus energy that would otherwise be wasted through spilling can be sold to EGAT;
- Deficits in system demand can be covered by imports until they grow to equal the next capacity increment. In this way, new capacity is fully employed upon entering service, allowing the full economic benefit of new investments to be enjoyed from the outset.
- The timing of new capacity increments in hydro-based systems is often determined by system security concerns during dry years. Interconnection with the predominantly thermal Thai system allows EdL to cover dry year deficits with imports and thereby defer investments in new capacity.
- Slippages in the commissioning dates of IPP capacity selling partially or wholly to EdL can be covered for a period by increasing imports.
1.4.2 Grid Interconnection Strategy
The present EdL system consists of a number of separate grids. The principal grids are Central C1, Central C2.1, Central C2.2, and Southern. A strategy for interconnecting these grids was investigated using the SEXSI software and the following sequence and timing of interconnections was found to be optimal:
• Interconnection of C1 and C2.1 grids: The construction of a line from Pakxan to Thakhek should proceed as soon as possible.
• Interconnection of C2.1 and C2.2 grids: The construction of a line from Thakhek to Pakbo (Savannakhet) should proceed as soon as possible.
• Interconnection of C2.2 and Southern grids: An optimal interconnection date of 2017 was determined, but the optimization curve is flat and an earlier date could be justified. For the time being, a decision should be
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deferred and the situation monitored. Interconnection should not occur before 2010.
In pure economic and financial terms, the construction of new transmission infrastructure to interconnect the three central grids through Lao territory may be more costly than the alternative of wheeling through the EGAT system. However, there are system security issues that may justify this additional outlay.
1.4.3 Northern Region
The major centers in the northern provinces of Oudomxai and Luangnamtha, and Phongsaly are currently being interconnected to the Central Grid under the Power Transmission and Distribution Project (PTD2). The loads from these centers are included in the system generation planning as part of the Central Grid.
Several generation projects in the Northern Region were evaluated but none performed well. However, a small project of less than 50 MW, such as Viengphouka or Nam Long, may nevertheless be justified for its ancillary benefits including:
• Voltage support to the long 115 kV interconnection to the Central Grid; • Security of supply through reduced vulnerability to transmission outages; • Lower transmission losses through proximity of load and generation; • Diversification of generation (hydrological diversity, plant mix, etc.).
1.4.4 Central Region
Under the optimal grid interconnection strategy the Central grid, comprising the C1, C2.1 and C2.2 grids, will be interconnected as soon as possible.
Industrial, mining and agricultural development in the Central Region is rapidly increasing the load in the Central Grid. There are a number of project sites that could be developed to meet this load but the least-cost expansion scenario (the “Preferred Scenario”) draws on GOL’s domestic off-take entitlements from two IPP projects, the Nam Theun 2 (75 MW) and Theun Hinboun Expansion (105 MW) projects (refer Figure 1.2).
Under the Preferred Scenario, demand growth in the Central Grid to 2020 would be met in the following way:
• Imports from EGAT would increase over the period to 2008. Imports, as a percentage of total energy, would peak in 2007 at about 30%.
• In 2008, the new unit at Theun Hinboun (Unit 3, 105 MW) would come on-line and EdL would purchase its output from the Theun Hinboun Power Company.
• From 2010, EdL would purchase its off-take entitlement of 300 GWh (75 MW) from the Nam Theun 2 Power Company;
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• By the time the Nam Theun 2 and Theun Hinboun Expansion domestic entitlements have been absorbed, peak load in the Central Grid would have grown to more than 400 MW. This opens the way for the introduction of larger and more cost-effective projects. Nam Ngiep 1 (213 MW), with a commissioning date of 2014, is the next least-cost augmentation. The Nam Ngiep 1 project could be developed as a public sector or private sector project or as a PPP.
The Preferred Scenario is heavily dependent on IPP off-take and a Fall-Back Scenario is developed to provide an expansion plan less susceptible to the uncertainties of IPP development. Smaller projects such as Nam Ngum 5, Nam Bak 2B or Nam Pot substitute for the Theun Hinboun Expansion off-take (refer Figure 1.3). The Fall-Back Scenario is about 5% higher more expensive than the Preferred Scenario.
Figure 1.2: Central Grid System Expansion 2005 – 2020 Preferred Scenario
Energy Demand (TWh) 5 Reference Scenario
4 Export of Dump Energy
Energy Demand 3
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Figure 1.3: Central Grid System Expansion 2005 – 2020 Fall-Back Scenario
Energy Demand (TWh) 5 Case: without Theun Hinboun Extension
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1.4.5 Southern Region
Expansion planning in the Southern Grid assumes that interconnection with the Central Grid is still many years away. Existing generation plant in the Southern Grid is run-of-river and rapidly growing dry season load is met largely through imports from Thailand. Additional power is needed immediately to cover dry season demand in particular.
The Preferred Scenario for the Southern Grid defines the least-cost plan for meeting rising demand to 2020 (refer Figure 1.4):
• A second 115 kV link with Thailand would be constructed immediately and imports from EGAT increased until the Houay Lamphan Gnai project can be brought on-line in 2010. Imports as a percentage of total energy demand would peak in 2009 at about 55%.
• The Houay Lamphan Gnai hydropower would be commissioned by 2010 with an installed capacity of at least 60 MW and a storage sufficient to provide seasonal regulation. The addition of Houay Lamphan Gnai to the system would reduce imports to 12%.
• No additional generating plant would be needed for the remainder of the planning horizon. After commissioning Houay Lamphan Gnai, imports would gradually rise from about 12% to around 36% in 2020.
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The Houay Lamphan Gnai site has not been investigated beyond inventory level and an immediate study is needed to confirm the project’s viability.
Planning for the Southern Grid is made more difficult by uncertainty in the status and viability of some projects. In addition to a Preferred Scenario, other least- cost scenarios are prepared and these would prevail in certain circumstances:
• Xeset 2 Scenario: Preparations for the Xeset 2 project are well advanced but conditions have not yet been satisfied to a point where the project can be regarded as committed. In the event these conditions are met, Xeset 2 would become a “given”.
• Thakho Scenario: The Thakho hydropower project, with its low generation cost and firm capacity in the dry season, is the best source of generation for the Southern Grid. However, it is located in an environmentally sensitive area and a study is needed to demonstrate that the project is benign and bankable.
• Xe Kaman 3 Scenario: Provision is being made in the concession conditions for the Xe Kaman 3 IPP hydropower project for a significant domestic allocation. The quantity and price of the domestic off-take is not yet known but it could be an attractive source of generation, especially if finance for capital works is scarce.
Figure 1.4: Southern Grid System Expansion 2005 – 2020 Preferred Scenario
Energy Demand (GWh) 700 Reference Scenario
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1.4.6 Transmission and Distribution
GOL’s electrification target of 90% of households by the year 2020 provides the overarching objective of grid development, but the factor that will most decide the rate at which the distribution system expands is the availability of funds. Multilateral and bilateral loans are in place for several major transmission and distribution projects but much of the program remains unfunded.
Most of the urban and provincial centers have already been, or soon will be, electrified and grid investments are becoming increasingly marginal. Planned extensions of the EdL grid over the period to 2020 will absorb most of the remaining load centers of any significance into the grid. The additional load captured by these extensions has been included in the PSDP demand forecast.
1.4.7 Off-Grid Electrification
A component in GOL’s strategy for meeting its 2020 electrification target of 90% and its intermediate targets is its off-grid household electrification program employing conventional off-grid technologies includes solar photovoltaic and village hydro/diesel mini grids. The off-grid program targets 150,000 household installations by 2020, about 50,000 of which will be overtaken by the expansion of the grid during that period.
Off-grid development is promoted by GOL and a number of development agencies as a means of bringing affordable electricity to remote communities for whom there is little prospect of grid electrification in the coming years. Energy Service Companies (ESCOs) have been established for the installation and servicing of off-grid units according to commercial principles. Due to the entrepreneurial nature of the program, the numbers of installations may vary widely from those targeted.
1.4.8 Domestic Power System Investment Program
Least cost development of the Lao power system as proposed in the PSDP involves a sequence of generation, transmission, distribution and off-grid investments to meet GOL’s electrification objectives and to satisfy resulting demand and system reliability criteria.
The sequence of capital investments required under the PSDP domestic system expansion plan involves annual outlays on generation, transmission, distribution and off-grid development of the order of US$50 million. Due to the hiatus in generation development in recent years and the rapid growth implied in ambitious intermediate electrification targets, annual investment peaks at over US$100 million around 2010.
The incremental cost of EdL system development under the PSDP Preferred Scenarios, including generation, transmission and distribution, is calculated to be about 8.4 ¢/kWh.
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1.5 Export Market Development
1.5.1 Export Scenarios
There is no systematic basis for optimizing the sequence and timing of export projects in the way of domestic power system scenarios. In the Thai and Vietnamese markets, Lao PDR is a price taker and the formulation of export development scenarios essentially comes down to judgments about the quality of project sites and the ability of developers to package their projects to meet hurdle rates of return and debt service at the specified avoided cost tariff. Effective planning of export projects is further frustrated by a lack of control over financing and implementation processes.
A Base Export Scenario is nominated in Table 1.4. As a sensitivity measure, an Optimistic Export Scenario is also proposed. Commercial operation dates were fixed according to a developer’s nominated date only where such dates are realistic. Projects were otherwise spaced to avoid institutional overload by keeping the number concurrently under development to a manageable level.
1.5.2 GOL Revenues from Export Development
The Base Export Scenario forms the basis of estimates of GOL’s cash flow receipts from export projects to 2020 (refer Table 1.5).
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Table 1.4: Export Generation Development Scenarios
Base Export Scenario Optimistic Export Scenario 2006 2007 2008 Theun Hinboun Expansion 3/ Nam Mo (Vietnam) 2/ Theun Hinboun Expansion 3/ 2009 Nam Mo (Vietnam) 2/ 2010 Nam Theun 2 (Thailand) 1/ Nam Theun 2 (Thailand) 1/ Xe Kaman 3 (Vietnam) 4/ 2011 Xe Kaman 3 (Vietnam) 4/ 2012 2013 Xe Kaman 1 (Vietnam or Thailand) 2014 Xe Kaman 1 (Vietnam or Thailand) 2015 Xe Kong 5 (Vietnam) 2016 2017 Xe Kong 5 (Vietnam) Nam Ngum 3B (Thailand) 2018 2019 Nam Ngum 2B (Thailand) 2020 Nam Ngum 3B (Thailand)
NOTES: 1/ Scheduled for 2010 in the EGAT PDP 2/ Scheduled for 2008 in the EVN PDP 3/ Assume one unit for domestic supply. Output from any additional units plus Incremental output from existing turbines for export. 4/ Scheduled for 2010 in the EVN PDP
Table 1.5: GOL IPP Revenues from Base Export Scenario
Year Royalties Taxes Dividends Total ($ mill) ($ mill) ($ mill) Receipts ($ mill) 2008 0.0 0.0 0.0 0.0 2009 1.4 0.0 -1.8 -0.4 2010 10.5 0.0 -12.5 -1.9 2011 15.0 0.0 -2.6 12.4 2012 15.5 0.0 7.5 23.1 2013 15.7 0.0 11.8 27.5 2014 20.8 0.9 7.7 29.4 2015 21.6 7.4 12.7 41.7 2016 21.8 9.8 18.3 49.9 2017 26.2 10.4 20.0 56.5 2018 26.9 10.5 28.6 66.1 2019 27.1 13.9 38.0 78.9 2020 34.2 14.5 29.8 78.4
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1.6 Nam Theun 2 Issues
1.6.1 Scope of Studies
The TOR defines specific tasks in relation to the Nam Theun 2 Hydroelectric Project; they are to:
• Evaluate alternative reservoir Full Supply Levels (FSLs)
• Compare Nam Theun 2 with alternative power projects and determine whether Nam Theun 2 is more beneficial for GOL than other projects in terms of the cost of domestic off-take and tax, royalty and dividend receipts.
• Determine how long it will take for the domestic off-take allocation from Nam Theun 2 of 300 GWh per annum to be fully absorbed by the Lao power system.
1.6.2 Alternative Reservoir Full Supply Levels
The performance of Nam Theun 2 was simulated for a range of FSLs and Table 1.6 describes the effect on economic performance using annual energy production and weighted average cost of generation as indicators, expressed as a percentage of the NTPC reference case (FSL = 538 masl).
Table 1.6: Nam Theun 2 – Comparison of FSLs
Reservoir Installed Energy Relative Relative Capacity Generation 2/ Project Generation FSL Area Volume Cost 1/ 2 Cost (m asl) (km ) (mcm) (MW) (GWh pa) (%) (%) 538 450 3680 1074 5898 (100%) 100 100 535 354 2466 1070 5218 (88%) 98 118 532 291 1498 1060 4674 (79%) 96 136 530 218 984 1050 4544 (77%) 94 150 528 164 602 1040 4357 (74%) 92 225
NOTES: 1/ Based on weighted average generation cost. 2/ Energy outputs are adjusted for reduced generation at Theun Hinboun
Deterioration of economic performance below RL 532 is severe and this sets an effective floor. More detailed comparisons of the NTPC reference case with two layouts were made:
1. Run-of-river case (FSL = 532 masl) 2. Ban Signo case with the dam moved upstream (FSL = 538 masl)
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The run-of-river layout involves a significantly smaller reservoir and this would reduce the social and ecological impacts. Although significant, they are associated with a 36% increase in the cost of generation and this would render the project unviable.
The Ban Signo variant has the same FSL as the NTPC reference case but impacts are reduced by moving the dam to a site about 10 km upstream. The principal social benefit of moving the dam upstream is a 9% reduction in the number of people resettled. From an environmental perspective, the principal gain is a 30% reduction in reservoir area, but the area saved is largely degraded. The economic penalty for the Ban Signo arrangement is an increase in the cost of generation of roughly 20%. This, too, could undermine the viability of the project under current market conditions.
1.6.3 Comparison of Price for Domestic Power Off-take from Nam Theun 2
Domestic power from an export IPP project such as Nam Theun 2 is priced against the opportunity cost of that power to the project company. In general terms, the revenue foregone by the project company with each unit of output sold to EdL rather than the foreign off-taker is equal to the export tariff adjusted for transmission loss differentials, wheeling and any differences in the level of supply commitment. The export tariff is determined, in turn, by negotiation based on avoided cost within the foreign off-taker’s system. Therefore, the value of the tariff is not a function of a project’s characteristics – these determine whether or not a project will proceed – but of the characteristics of the EGAT or EVN system and the skills of the negotiating teams.
1.6.4 Comparison of Government Receipts
GOL receipts generated over the lifetime of a project were compared for the projects making up the export scenarios defined in Table 1.4. An export project’s revenue earning potential for GOL comes in the form of taxes, royalties and dividends and this will depend on a number of factors including average annual generation, tariff, GOL equity share and concession terms (taxes and royalties). Cash flow projections of frontline IPP candidate projects confirm the greater earning capacity of Nam Theun 2 (refer Table 1.7).
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Table 1.7: GOL Net Receipts – Common Construction Start (2003)
Project Base Royalties Taxes Dividends Total GOL GOL 2/ Cost Receipts receipts as 1/ 3/ % of Base NPV @ 10% NPV @ 10% NPV @ 10% NPV @ 10% Cost ($ mill) ($ mill) ($ mill) ($ mill) ($ mill) Xe Kaman 3 278 33.3 23.4 72.7 129.4 47% Nam Theun 2 617 101.3 60.8 113.3 275.5 45% Nam Mo 116 10.8 6.8 16.6 34.2 29% Xe Kaman 1 420 36.5 22.4 45.1 103.9 25% Xe Kong 5 400 33.3 20.4 45.6 99.4 25% Nam Ngum 3B 773 51.1 28.9 44.7 124.7 16% Nam Ngum 2B 180 10.3 1.9 -10.4 1.8 1% 1/ Base cost including SESAMEE environmental and social impacts (positive and negative) 2/ All projects other than Nam Theun 2 modeled according to common set of assumptions as described in Section 9.2. All projects modeled on a 2003 construction start date. 3/ GOL receipts are based on project costs and energy production figures calculated using EVALS. For Nam Theun 2, the official GOL estimate of receipts is based on a more conservative estimate of primary energy production (i.e. 4,406 GWh, versus the EVALS figure of 4,883 GWh).
1.6.5 Absorption of Domestic Off-take
Nam Theun 2 is located strategically in the C2.1 supply area and will contribute 300 GWh pa to the grid which, by the time of commissioning, will be interconnected to the C1 and C2.2 grids. Demand growth within the central area of Lao PDR is very rapid and will remain so for several years. This growth is being met by imports at present. Under the optimal power system expansion scenario studied by the Consultant a deficit roughly equal to the maximum domestic off-take from Nam Theun 2 (300 GWh) would open up in the period between the commissioning of the previous project (Theun Hinboun Expansion) and the Nam Theun 2 Commercial Operation Date (COD). Thus, Nam Theun 2’s domestic allocation would be absorbed, if not immediately, then within a short time.
Antecedent supply and demand conditions are fundamental to this outcome, with the timing of prior capacity increments largely determining the result. Under present pricing for power trades between EGAT and EdL, the least-cost strategy is to allow a system deficit to build in the years prior to augmenting generation so that the full output of the increment is absorbed from the outset. The alternative is to add capacity before the system goes into deficit but the surplus that exists while demand absorbs the increment can only be sold to EGAT as non-firm energy attracting a low price.
It therefore follows as a general rule for all capacity increments, and for Nam Theun 2 in particular, that the increment will be fully absorbed upon or soon after commissioning if generation expansion follows least-cost planning principles.
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2.0 BACKGROUND
2.1 Objectives of PSDP
Originally conceived as a study to reconcile differences between previous studies and to examine specific sectoral issues, the TOR for the Power System Development Plan (PSDP) evolved towards a master plan format that included comprehensive investment planning covering generation (national and export), transmission (national and regional), distribution and off-grid development for the period 2005 to 2020.
The key objectives of the PSDP are to:
(i) Prepare or update evaluations of proposed generation developments against a common set of assumptions, rank them and provide a catalogue of projects that will best serve the needs of the sector;
(ii) Evaluate power system expansion scenarios and determine an optimal development plan to guide effective investment in domestic generation, transmission and distribution;
(iii) Analyze the power markets of Lao PDR’s neighbors and prepare realistic export development scenarios based on the competitiveness of Lao power projects in these markets;
(iv) Aggregate project investment cash flows to provide an investment plan for the period up to 2020;
(v) In relation to Nam Theun 2:
• examine the trade-off between benefits and environmental impacts of different reservoir Full Supply Levels;
• assess whether the project is the most effective choice in terms of providing least-cost domestic power and maximizing GOL receipts from exports; and
• estimate how long it will take for Lao PDR to absorb its annual domestic allocation of 300 GWh.
The PSDP is one of several coordinated studies that address a number of interrelated issues facing the power sector. Other studies will examine financing and solicitation strategies, but the PSDP, by focusing on the above points, will provide an optimal and affordable investment plan to guide future state and private investments and provide a reference for assessing sector performance.
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2.2 Structure of the Draft Final Report
This Draft Final Report is arranged into the following sections:
Section 1: Executive Summary Section 2: Background Section 3: Overview of Lao Power Sector Section 4: Lao Power Market Section 5: Export Power Market Section 6: Candidate Power Projects Section 7: Domestic Power System Expansion Section 8: Export Power Development Section 9: Financial Evaluation of Power Projects Section 10: Nam Theun 2 Issues
2.3 The Consultant
Meritec Limited of New Zealand (now Maunsell Limited) in association with Lahmeyer International of Germany was awarded the contract to provide PSDP consulting services on 12th August 2003. The grouping also includes Dr. M. Watson of Resource Management and Research (RMR), R. Vernstrom of Robert Vernstrom Associates and R. MacGeorge of Ridgway Consulting to provide environmental, economic and financial expertise respectively.
2.4 Acknowledgements
In the course of preparing this report the Consultant consulted and received assistance from a large number of individuals. The Consultant would like to thank all for their assistance. A particular debt is owed to the personnel of the staff of the Department of Electricity and the World Bank team who assisted us in an administrative and technical capacity. We would like to extend particular thanks to Houmphone Bulyaphol, Director of Department of Energy, and his staff including Chanto Milattanapheng, Chansavang Bounyong, Khamso Kouphokham and the counterpart team.
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3.0 OVERVIEW OF LAO POWER SECTOR
3.1 Setting
3.1.1 Development of the Power Sector
In Lao PDR, the power sector serves two vital national priorities:
(i) It provides a reliable and affordable power supply to Lao society and industry. Inexpensive electricity promotes competitiveness in Lao commerce and brings social benefits to urban and rural communities.
(ii) It earns foreign exchange from electricity exports. The country possesses abundant energy resources, principally hydropower but also coal, and the exploitation of these resources through electricity exports is at the heart of GOL’s strategy for earning the revenues needed to fund the country’s development.
Strategic planning of the sector will consider both objectives.
Currently about 41% of households in Lao PDR are electrified and GOL has committed itself to increasing this to 90% by 2020. One of the primary objectives of the PSDP is to determine the development requirements of the Lao power system to meet this objective.
In the early years of power sector development in Lao PDR, power systems evolved separately around the main centers of population. Investments tended to be small and decisions were intuitive. Power projects were planned on an individual project basis without the need for a coordinated plan to ensure optimality across the country. Projects were publicly financed through bilateral and multilateral development agencies and the orderly procedures of these agencies governed project selection and procurement processes.
With the growth of demand and expansion of power systems, intuitive ad hoc decision-making is becoming less reliable. Investments are typically larger and the consequences of sub-optimal decisions are now greater. Also, over the last decade power sector planning is being complicated by the changing way in which projects are financed and implemented.
A rational development plan is needed to guide development to the maximum advantage of the country, and to forecast the capital investment and revenue implications of this development. Several planning and strategy studies have been prepared in recent years but they have been fragmentary and contradictory. The PSDP draws on this previous work, updates and reconciles conflicts, and outlines a development path for the period from 2005 to 2020.
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3.1.2 Planning and Financing Lao Power Projects
Planning and financing of projects are interdependent. In Lao PDR, a clear distinction has been drawn in the past between EdL-owned, publicly planned and financed power projects for domestic supply and privately owned, project financed export-oriented projects. Reasons for this distinction include:
• Physical infrastructure: Transmission networks have evolved within national boundaries and have not had the trans-national links to support free transfer between surplus and deficit areas with the region. The proposed development of an ASEAN/GMS grid will facilitate energy trading by providing the means and reducing the cost of moving energy to a willing buyer. It will also act as a catalyst in establishing an institutional framework to manage trades;
• Size of project: In the past, the ideal capacity increment was less than 100 MW for the Lao system but greater than 100 MW for EGAT and EVN. As demand increases and EdL’s grids combine, optimal capacity increments will become larger;
• Financing of Projects: The reduction in the availability of ODA for domestic generation projects and the improvement in EdL’s financial position is encouraging private investors and lenders to consider national supply as well as export markets.
The principal features of each category is outlined:
(i) EdL-owned projects for domestic supply:
EdL-owned projects have been financed in the past by multilateral agencies (e.g. World Bank, ADB) and bilateral agencies (e.g. JBIC, NORAD) on concessional terms. They have been planned and implemented in accordance with the agencies’ procedures resulting in an orderly project selection process based on least-cost principles.
In the early days of sector development, demand for electricity was low and the capital needs were manageable. Demand growth, though, has been rapid and the availability of concessional funds and grants is not keeping pace with the increasing capital requirements of the sector. Also, a shift in policy of development agencies towards social and governance objectives has seen an abrupt decline in support for power generation investments. Transmission, distribution and off-grid projects continue to receive direct concessional lending.
The financing vacuum left by the withdrawal of the development agencies has been filled for the moment by non-traditional sources of finance, notably the China Exim Bank. Finance from these sources appears to be abundant and the financing model is effective in accessing loans, but it is new and the associated procurement practices are weak.
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(ii) Privately financed projects for export markets:
GOL signed MOUs with the governments of Thailand and Vietnam for the export of about 3000 MW over the period up to 2010. The private sector responded vigorously to the opportunities these agreements offered and about 24 project MOUs were signed with private developers between 1991 and 1997 based on the BOT model.1
Promotion of IPP projects in Lao PDR begins with an unsolicited proposal from a sponsor and, from this, an MOU is drawn up and a concession ultimately negotiated. Concessions are awarded in the absence of competition after the sponsor has completed technical and environmental studies of the proposed project.
The Lao IPP program met with initial success and two hydropower projects, Theun Hinboun and Houay Ho, were implemented. The Asian Economic Crisis and problems among key international power sector investors exposed many weaknesses in private financing models in use throughout the region. This has seen a downturn in private sector interest and no IPP projects in Lao PDR have been financed since the Theun Hinboun loans were closed about a decade ago.
The recent signing of the Nam Theun 2 PPA and advances in the development phases of the Nam Mo, Xe Kaman 3, and Theun Hinboun Expansion projects signal a recovery, but fundamental problems in the planning and procurement of private power projects remain.
The development of the PSDP is an important step towards establishing rational sector planning but there is a parallel need for compatible financing and procurement models to complement the plan by facilitating the implementation of power sector projects, whether EdL or private, in accordance with the PSDP. Aspects that need strengthening include the following:
• Selection of projects, being based on unsolicited proposals, tends to be ad hoc and sub-optimal;
• Selection of developers does not effectively discriminate between opportunistic adventurers and reputable, experienced sponsors. This has been a contributing factor in the difficulties developers have encountered in securing lender commitment;
• PPAs are negotiated project-by-project. EGAT and EVN have the advantage in such negotiations because they are not as dependent on a single project as the developer and their commitment is therefore weaker. Compromises by developers on tariff reduce tax and royalty entitlements;
1 All but two of the MOUs were for hydropower projects – the exceptions being a lignite-fired plant (Hongsa) and a transmission project (Southern Laos Transmission Project).
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• Transparency in concession negotiations is lacking and leaves GOL vulnerable to unreasonable risks and harsh commercial terms. GOL is particularly vulnerable to unfair determination of a project’s capital cost;
• The development and financing of projects are attended by great uncertainty.
• Engineering and environmental standards are not clearly specified and enforced.
3.1.3 Future Trends
The power industry globally and regionally has undergone great changes over the last decade. Cooperation between ASEAN/GMS countries is increasing, 500 kV international grid interconnections are planned, and in the longer term competitive markets may emerge. While the trend towards regional integration is now well established, the pace at which it will happen and the timing and scope of specific initiatives is still open.
The PSDP is therefore prepared against an uncertain and changing backdrop and, if it is to be effective and relevant, it must be in harmony with the direction of sector development in the GMS/ASEAN region. Much of the uncertainty in power sector investment planning concerns the following:
• Extent of private sector involvement and the private power procurement models used to mobilize participation;
• Pace of integration of the GMS/ASEAN power systems and, in particular, the timing of transmission interconnections;
• On-going development of the legal, institutional and regulatory environment in Lao PDR;
• Strengthening of the institutional capacity in Lao PDR and improvements in the commercial position of EdL;
• Setting of wholesale and retail tariffs in Lao PDR and neighboring countries.
A number of trends are evident in the power sector of Lao PDR, although it is too early to say where they are leading. The opening of the sector to new financing models is fundamentally changing the way in which projects are planned and implemented.
An increasing convergence between domestic and export projects is likely. New models will evolve to better capture the benefits of system integration but it is not yet clear what form they will take. Possibilities include:
• Establishment of a regulator to set domestic retail tariffs and negotiate wholesale export tariffs. This would mean tariffs could be pre-set before
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bidding power generation concessions and bidding would therefore be on some other criterion, perhaps the highest royalty payments;
• Creation of a centralized Lao power purchasing agency or cooperative that could competitively bid power concessions within Lao PDR and could sell the off-take from some or all Lao projects to domestic and/or foreign power purchasers. The agency (perhaps the regulator) could negotiate cross border trades from a position of greater strength because of the amount of MW it brings to the market;
• Development of models tailored to the demands of the capital markets with risks shared between IPPs, GOL, EdL and MLAs according to market tolerance – e.g. capping of unforeseen conditions exposure, sharing of hydrological risk (e.g. through a capacity charge for availability), etc.
• In the longer term, establishment of a competitive power market within the region and the emergence of merchant plants.
The PSDP covers the period to 2020 and there is a need to regard the Lao power system in a regional context in preparing development plans and to look beyond the present distinction between domestic and export markets.
3.2 Power Sector in Lao PDR
3.2.1 Status of Power System
The status of Lao power sector development is summarized in Table 3.1 and Figure 3.1. It is divided into four principal unconnected supply areas, and a number of smaller supply areas. In addition, off-grid village and household systems provide electricity to remote and isolated communities. Thus, electrification is provided through the following six supply areas:
• Northern Supply Area (EdL) • Central C1 Supply Area (EdL) • Central C2 Supply Area (EdL) • Southern Supply Area (EdL) • Isolated Supplies (EdL/Provinces) • Off-grid electrification (Provinces/Private)
(i) Northern Supply Area
No HV grid has yet been established in the northern part of Lao PDR. Two of the main towns, Pongsaly and Luang Nam Tha, now have MV connections to the Chinese grid, but the tariff is high. A more permanent solution will be provided by a 115 kV transmission extension of the C1 grid from Luang Prabang to the three north-eastern provinces of Oudomxai, Pongsaly and Luang Nam Tha. This line is being financed by ADB under the second phase of its Power Transmission and Distribution Project (PTD2) and will be completed by 2007.
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Table 3.1: EdL Generation Plant
Plant Province Grid Capacity Average First Year Units Total Energy of Operation (MW) (MW) (GWh/a) HYDROPOWER Nam Ngum Vientiane C1 2 x 15 30.0 1021 1971 (incl. Nam Song) 2 x 40 80.0 1978 1 x 40 40.0 1984 Nam Dong Luang Prabang C1 3 x 0.336 1.0 3.0 1970 Nam Leuk Vientiane C1 60 60 249 2000 Nam Phao Bolikhamxay C1 3 x 0.5 1.5 1995 Selabam Champassak South 3 x 0.668 2.0 30 1969 Xeset 1 Saravane South 1 x 3 3.0 180 1994 2 x 3 6.0 1991 3 x 13 39.0 1991
Hydro Sub-total 263 263 1473
DIESEL PLANT Region: C1 Operation 3hrs/day Sokpaluang Vientiane 8.00 - 1971 Sanakham Vientiane 0.24 - 1993 Luangprabandg Luang Prabang 1.64 - 1991-92 Phongsaly Phongsaly 0.30 0.33 1994 Luangnamtha Luangnamtha 0.32 0.35 1992 Xiangkhuang Xiang Khuang 0.48 0.53 1995 Xayabury Xayabury 0.78 1.53 1994 Oudomxay Oudomxay 0.25 0.27 1978 Bokeo Bokeo 0.48 0.53 1992
Region: C2 Savannakhet Savannakhet 1.00 - 1971
Region: Southern Pakse Champassak 0.28 - 1970/85 Saravane Saravane 0.40 - 1985 Attapeu Attapeu 0.24 0.26 1993
Diesel Sub-total 14.11 2.8
Source: Ministry of Industry and Handicraft
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Figure 3.1: Existing EdL System (Hydro generation and 115 kV Transmission)
No Power Plant Installed 100 102 104 106 Capacity ( MW ) Government Projects: CHINA 1 Nam Ngum 150 2 Nam Dong 1 3 Nam Phao 1.6 22 4 Selabam 5 Phongsaly 5 Nam Ko 1.5 5 Xeset 45 6 Nam Leuk 60 NORTHERN SUPPLY AREA Total Government 264 MYANMAR Nam Ko Luangnamtha 1.5 MW IPP Projects: Oudomxay 8 Theun Hinboun 210 9 Houay Ho 150
M.Tonpeung Huaphan Total IPP 360 Bokeo 20 TOTAL EXISTING 624 Chiang Rai Luangprabang Nam Dong 1.0 MW Xiengkhuang VIETNAM CENTRAL C1 GRID Xayabury
Nam Ngum 1 Nam Song 150 MW Diversion Paksane
Nam Leuk Laksao 60 MW Nam Phao 18 M.Salakham Theun Hinboun 1.5 MW 18 VIENTIANE Bung Kan 210 MW
M.Botene Nongkhai Thakhek Loei Oudon II 115 kV Nakhonphanom M.Sepone THAILAND
CENTRAL C2 GRID
115 kV Savannakhet 16 Mukdahan Kengkok 16 Saravane
Xexet 45 MW Selabam SOUTHERN GRID Legend 5 MW Sekong
Pakse Houay Ho Hydropower plant 150 MW 115 kV substation Attapeu 115 kV line Sirindhorn Dam Int. MV connection
14 14
CAMBODIA
Source : Ministry of Industry and Handicraft,Vientiane Lao PDR 102 104 106
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Sam Neua (Houphan Province) and Houayxai (Bokeo Province) are supplied as isolated supplies (refer (iv) below). Sam Neua will be connected to the C1 grid at Xieng Khouang through the construction of a 115 kV line under the third stage of the ADB’s Power Transmission and Distribution Project (PTD3).
(ii) Central C1 Supply Area
Historically, the load in Lao PDR occurs predominantly in the Central C1 Grid which comprises a 115 kV transmission system connecting Vientiane, Luang Prabang, Vangvieng, Pakxan, Xieng Khouang and Sayaburi. 115 kV interconnections link the C1 and EGAT grids at Phontong (Nam Ngum 1), Thanaleng (Vientiane) and Pakxan.
Hydropower generation for the C1 Grid is provided by Nam Ngum 1 (150 MW, with Nam Song and Nam Leuk diversions to augment energy), Nam Leuk (60 MW) and Nam Dong (1 MW). In addition, there is limited diesel capacity including 8.2 MW at Sokpaluang (Vientiane) and 1.6 MW at Luang Prabang. The Nam Mang 3 hydropower project will contribute a further 35 MW when it is completed in 2005.
(ii) Central C2 Supply Area
The Central C2 area includes two separate networks, eminating from Thakek (C2.1) and Savannakhet (C2.2), each supplied by 115 kV interconnections with the EGAT grid. Under successive World Bank projects, i.e. the Provincial Grid Integration (PGI) and Southern Provinces Rural Electrification (SPRE 1) projects, these networks are radiating out, electrifying villages and towns in rural areas of Khammouane, and Savannakhet provinces. SPRE 1 includes about 52 km of 115 kV transmission line.
Under the current PPA between EdL and EGAT, EdL imports from Thailand at a premium on its export price, effectively a transmission charge for wheeling energy from the Nam Ngum/Nam Leuk plants through the EGAT system to the C2 grids.
(iii) Southern Supply Area
The Southern Grid services areas of Champassak and Saravane. The grid is supplied principally from three sources: from Xeset 1 (45 MW) and Selabam (5 MW) (both run-of-river), and from imports from EGAT. Xeset 1 is connected to Pakse and Ubon Ratchathani (Thailand) by a 115 kV line and to Saravane by a 22 kV line.
The town of Attapeu (Attapeu Province) has an isolated supply with generation provided by the Houay Ho IPP project.
As with the Central Supply Area, the PGI and SPRE 1 projects have extended the Southern Grid further into rural areas of Saravane and Champassak and this work will continue under the new SPRE 2 loan.
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(iv) Isolated EdL Supplies
EdL is also responsible for the reticulation of electricity in a number of areas isolated from the main supply grids. Some centers import supplies across international borders through MV feeders.
Sam Neua and Vieng Xai (Houphan Province) are supplied by 35 MV feeders from Vietnam and Houay Xai (Bokeo Province) is supplied at 22 kV from Thailand.
Other towns receiving isolated cross border supplies include Xe Pon (Savannakhet) from Vietnam grid and Mouang Kenthao (Sayabury) from Thailand. More cross border connections are planned. Wholesale import prices for these supplies vary; Thai imports are at the PEA price for a large industrial customer while imports from EVN are charged at 6 ¢/kWh. Retail sales in areas supplied from cross border connections are largely to domestic customers and the EdL domestic tariff is currently below wholesale purchase prices.
Isolated hydropower and diesel generators electrify other centres, e.g. Mouang Xai from Nam Ko hydropower plant (1.5 MW) and Laksao from Nam Phao hydropower plant. The township of Attapu is supplied from the Houay Ho IPP project. Sometimes EdL is responsible for providing isolated supplies (e.g. Laksao, Attapeu) but in the majority of cases it is the relevant provincial, district or village authority.
(v) Off-Grid Supplies
Much of the country lies beyond the economic reach of the EdL’s grids and off-grid development provides the only prospect of electrification for many isolated rural communities. The Rural Electrification Department of DOE is responsible for a program of off-grid electrification at a village and household level using micro- and pico-hydro, diesel and solar technologies. Subsidy funding is mobilized from GOL and donor sources and there are plans to establish a Rural Electrification Fund to coordinate and channel contributions. A system of licensing enterprises to provide off-grid services is being introduced.
Approximately 5,000 household installations have been completed or are planned under this program. This is expected to grow to 150,000 by 2020.
3.2.2 Electricity Trade with Neighboring Countries
Electricity trading between Lao PDR and its neighbors is carried out at several levels:
(i) Committed exports are made under project-specific PPAs that set out strict conditions (including penalties) governing delivery of capacity and
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energy. At present, PPAs have been signed only with EGAT (Theun Hinboun, Houay Ho and Nam Theun 2), although negotiations are in progress with Vietnam in respect of two other proposals, the Nam Mo and Xe Kaman 3 projects.
(ii) Under a blanket PPA between EdL and EGAT, EdL can freely export surplus energy without committing to the quantity or timing of either. Electricity exports from Lao PDR began in 1971 with the commissioning of Nam Ngum 1. In the period since, the trade has provided a significant source of foreign exchange but it is tapering off as local demand absorbs surplus energy and periodic tariff negotiations erode price.
(iii) As outlined in the previous section, there is opportunistic power trading with Lao PDR’s neighbors for least-cost supply to border areas. EdL’s PPA with EGAT allows EdL to import capacity and energy at the PEA large customer tariff and several important border towns have been supplied in this way. Similar arrangements are in place allowing localized MV imports from China and Vietnam to supply towns near those borders.
While electricity trading has been an important feature of the sector’s development to date, its role in future sector development is potentially profound. Given the country’s location between populous and growing neighbors, the Lao power system is likely to take on an increasingly regional dimension.
3.2.3 EdL System Development
Expansion of the EdL grid has been rapid and this has brought electricity to many rural towns and villages.
In the past, EdL relied primarily on multilateral and bilateral finance for transmission and distribution projects with the ADB playing a central role in the north and the World Bank in the south. Despite re-focusing their resources in recent years, the World Bank and ADB continue to support grid extension projects. Bilateral funds from Japan and India also contribute to the development. Grid expansion as well as economic development is fuelling the high rates of growth in domestic demand.
Generation expansion has not kept pace with demand growth. The funding gap left by the withdrawal of MLAs from generation is being partially filled by loans from the China Exim Bank.
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3.3 Review of Past Studies
3.3.1 Summary of Key Studies
The PSDP draws on the extensive work of others in its formulation. A large number of studies and documents related to the Lao power sector have been prepared over the last decade and this body of work provides a useful foundation on which to base the integrated planning of the Lao power sector. Many previous studies are narrow and project-specific in nature and add only to our understanding of a particular site or basin. Collectively, though, these project studies extend our knowledge of the county’s commercially exploitable energy resource base and provide useful data for evaluating and ranking projects. The objectivity of some of project studies can be questioned and the information is used with care. (There is evidence in some cases of commercial interests of project sponsors influencing content and conclusions.)
Other studies take a broader planning perspective and explore optimal development directions and sequences. The PSDP overlaps and duplicates much of this material.
Studies of particular relevance to the PSDP are listed in Table 3.2). Wherever this work is current, correct and relevant, it is adopted without duplication.
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Table 3.2: Key References: Power Sector Planning Studies and Projects
Study Year Funding Focus
Strategy Studies:
Power System Planning in the MIH 1997 ADB Domestic hydropower (< 50MW) Hydropower Development Plan for Lao PDR 1998 EU Evaluation of projects > 50 MW Nam Theun 2: Study of Alternatives 1998 WB Export hydropower projects Hydropower Development Strategy Study 1999 WB Rank domestic & export projects Power System Strategy Study 2002 ADB Domestic and export projects EdL PDP – PDP2002-12, July 2003 (draft) 2003 EdL Power system expansion.
Basin Development Studies/Projects: Masterplan Study on Hydroelectric Power Coordinated hydropower 1995 JICA Development in the Sekong Basin development in Xe Kong Water Management Plan for the Nam Theun Coordinated water management in 1997 ADB / Nam Hinboun, Lao PDR Nam Theun Se Kong, Se San and Nam Theun River 1999 ADB Hydropower dev. in 3 river basins Basins Hydropower Study Nam Ngum River Basin Development Sector Integrated water resources 2003+ ADB Project management of Nam Ngum
Transmission Planning Studies: Establishment of Lao National Grid Company 1997 ADB Technical legal and commercial. Lao National Grid Study (Lahmeyer) 1997 GOL Development of national 500kV grid Nam Ngum 500kV Transmission Project, 1998 ADB Technical planning of Nam Ngum 3 Part A: Feasibility Study transmission line Masterplan of Transmission Lines and 2002 JICA Domestic grid development Substation Systems Indicative Masterplan on Power 2001/2 ADB GMS grid development Interconnections in GMS Countries
GMS Power Demand: Thailand: General Information EGAT Power April EGAT Plan for expansion of generation Development Plan, (draft April 2003) 2003 and transmission in Thailand General Information: EGAT Power April EGAT Plan for expansion of generation Development Plan (draft – April 2003) 2003 and transmission in Thailand North Eastern Thailand: Power Development 2003 EGAT Plan for generation and trans- Plan (PDP 2003) mission expansion in NE Thailand Thailand: Power Development Plan – 2003 EGAT Plan for expansion of generation (presentation Manila 16-17 June 2003) and transmission in Thailand Vietnam: PDP and Power Interconnection June EVN Generation and transmission among Vietnam, Lao PDR and Thailand 2003 expansion Plan and interconnection (presentation Manila 16-17 June 2003) with Lao PDR and Thailand Myanmar: Developments in the Power Sector Dec Min of Elec Plan for expansion of generation 2001 Power and transmission in Myanmar Power Generation Country Report 2003 Min of Elec Long term plan for expansion of (Myanmar) Power generation in Myanmar.
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3.3.2 Reconciliation of Study Differences
Inconsistencies exist between studies and an objective of the PSDP is to reconcile them. The inconsistencies derive from differences in:
• methodology • level of detail and effort • study objectives • parameter values, constraints and other assumptions.
In most cases disparities can be traced to differences in assumptions and parameters. Agreement on appropriate values was reached at the Inception Workshop. This was held a few weeks after mobilization of the Consultant and it provided a formal forum for debating many of the divergent issues. The principal participants in the power sector, representing diverse and sometimes conflicting interests, were represented at the workshop and their views were influential in deciding assumptions and constraints to be employed in the formulation of the PSDP.
The two most recent and relevant studies to the PSDP are the Hydropower Development Strategy Study (HDSS) and the Power Sector Strategy Study (PSSS).2 The more prominent disparities in the conclusions of the HDSS and PSSS are listed in Table 3.3. They are attributable in large part to the financing assumptions on which each is based. For the most part these are reconciled by adopting values agreed with stakeholders in the Inception Workshop and as otherwise advised by the Consultant’s infrastructure financing specialist (refer Annex 4.1).
In the PSDP, investment recommendations are made on the basis of project rankings and system expansion plans determined using economic methodologies and a discount rate of 10%. Financing terms (and the availability of concessional financing) are not considered in the investment recommendations; the financing of investments is treated as a separate matter and is discussed in Section 9.
2 Hydropower Development Strategy Study, Worley – Lahmeyer, World Bank (2000); and Power Sector Strategy Study, Electrowatt – PA Consulting, ADB TA 3374-LAO (2002).
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Table 3.3: HDSS and PSSS – Comparison of Conclusions
HDSS (2000) PSSS (2002)
Export In the current tariff regime, few projects are In the current tariff regime, there are enough Projects likely to meet the objectives of power attractive projects to meet hurdle rates of purchasers, sponsors, lenders and GOL. return at avoided cost tariffs to ensure GOL’s export commitments of around 4,000 MW are met.
Concession = 25 years from COD. Concession = 30 years from COD.
Multilateral Partial Risk Guarantee (PRG) Assumes PRG support more widely support for IPP projects is rationed. Also, available PRG available only to projects providing demonstrable benefits to GOL. Under the current tariff regime, there are few projects technically capable of this.
Assumptions regarding commercial loan Less stringent assumptions regarding loan terms and fees, and project development terms and fees, and project development costs are more stringent than PSSS. costs.
IDA or ADB’s ADF highly concessional Concessional finance available for GOL finance cannot be relied on for GOL equity. equity. Theun Hinboun model adopted.
Assumed limits to the number of project GOL’s institutional capacity and access to concurrently under development based on finance on reasonable terms do not limited capacity of EdL and GOL to borrow constrain IPP development. money and to negotiate, monitor and implement projects.
Domestic Financed with concessional IDA or ADF Financed with concessional IDA or ADF Supply finance, domestic hydropower projects finance, domestic hydropower projects provide least cost source of generation. provide the least cost source of generation. However, concessional lending for Concessional lending will be available for all generation is becoming scarce. Without projects and on this basis, the least cost concessional loans, least cost supply is: supply is: Northern: Either interconnection with main Northern: Interconnection grid or domestic hydro (e.g. Nam Beng); C1 and C2 Grids: Interconnection of grids C1 and C2 Grids: Interconnect main grid with development of Nam Ngum 5 and Nam with Central grids; 75 MW off-take from Nam Mang 3 Theun 2; if NT2 doesn’t proceed, import from Thailand. Southern Grid: Domestic hydropower (Houay Lamphan Gnai). Southern Grid: Domestic hydropower (Xe Katam) or import from Thailand.
Power system expansion planning takes Comparison of development scenarios is stochasticity of hydropower plant into based on annual average values for demand account and supply, masking system reliability problems due to annual and seasonal hydrological fluctuations.
Relied on domestic off-take only from NT2 Domestic off-take allocations form an because of the greater certainty of this integral part of domestic generation project but otherwise regarded such sources expansion planning. opportunistically because of development uncertainties.
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3.4 Overview of PSDP Planning Methodology
The following steps were used to identify the power system investments that meet forecast demand in Lao PDR and maintain minimum system security standards at least-cost:
1. Evaluate EdL’s demand forecast and adjust as appropriate. The demand forecast derives from EdL’s electrification plan scoped to achieve GOL’s electrification target of 90% electrification by 2020.
2. Prepare a supply curve of attractive projects. Projects will be chosen not only for their suitability in supplying EdL’s grids at least-cost, but also for their competitiveness in selling electricity into Lao PDR’s target export markets.
3. Prepare an optimal generation and transmission development plan for the power sector. Transmission system development will link new power stations, interconnect grids and reinforce and extend the system to achieve the objectives of the electrification plan.
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4.0 LAO POWER MARKET
4.1 Load Analysis
4.1.1 Analysis of System Load Data
Load data from EdL substations was collected analyzed and, after some adjustments, used as a basis for the development of dimensionless load duration curves needed by Lahmeyer’s generation planning model, SEXSI. The load analysis was carried out for the calendar year 2002 and used data from EdL’s existing grids but not from its isolated load centers.
Hourly substation load data was keyed into data files and converted to the Lahmeyer time series database. Hourly values of power sent out were processed for most of the main 22 kV substations covering more than 90% of the total power demand. This figure was brought to 100% by proportioning the predicted year 2002 values of all substations given in Tables 5.5.1 and 5.5.2 of the report, Study on Master Plan of Transmission Line and Substation System in Lao PDR (the “JICA Report”) 3 against those from the substations for which data was available.
The data contained several inconsistencies and the following procedure was used to identify and rectify readings that appeared erroneous:
• All readings with a rise or fall exceeding 70% compared with the previous hour were marked and checked, and those showing subsequent rebound of the same magnitude were specially marked as being highly suspicious. The time series were then inspected for the occasions marked and adjustments made where plausible. Program HCHEK was used to automatically suggest more reasonable values based on readings for the same hour in the previous and following week.
• All days that showed a total drop in generation of 30% compared with the previous week were also inspected (program HCHEC), and adjustments made as described above.
The losses for the 115 kV system were taken as 4% at peak load and quadratically less for periods of lighter loads; i.e. the corresponding energy loss during any hour at half of peak load would be calculated as 4% x 0.5 2 = 1.0%.
The results of the load analysis are given in Table 4.1 and a summary of peak load and energy requirements is provided in Table 4.2. The values in Table 4.1 are for stations connected to the grid by the beginning of 2002. A small percentage of national electricity demand occurs in small EdL grids, provincial isolated systems and through off-grid generation in remote locations. The estimation of peak load takes load diversity into account using the diversity
3 Study on Master Plan of Transmission Line and Substation System in Lao PDR, Final Report, Nippon Koei, JICA, September 2002
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found in the 2002 load data. The estimated peak for an interconnected system is therefore less than the aggregate of peak loads of the component systems.
Table 4.1: Load Analysis Summary – Comparison with EdL PDP 2003 PSDP Load Analysis Isolated Grids Code Peak Energy Load Factor Diversity Facor (MW) (GWh/a) (%) (%) Central 1 C1 128 677 61 Central 2.1 C21 18 75 48 Central 2.2 C22 22 83 44 South S 22 80 41 Sum CS 189 914 55
Aggregate Values Central 1 + Central 2.1 C121 141 752 61 97 Central 1 + Central 2.1 + 2.2 C 158 835 60 94 Central + South S 179 915 58 94
Comparison with EdL PDP 2003 Isolated Grids Code Peak Energy Difference in Peak Difference in Energy (MW) (GWh/a) (MW) (GWh/a) Central 1 C1 141 682 10% 1% Central 2 C21+C22 32 154 -18% -2% South S 24 104 8% 30% Sum CS 197 939 4% 3%
Aggregate Values Central 1 + Central 2.1 + 2.2 C 173 835 10% 0% Central + South S 197 939 10% 3%
Table 4.2: Peak Load and Energy Requirements
Grid Code Peak Load (MW) Energy Annual System Requirement Load Factor (GWh) (%) Central 1 + Central 2.1 C121 158 835 60 Central 1 + Central 2.1 and 2.2 C12 141 752 61 Central 1 + Central 2 + South CS 179 915 58 Central 2.2 C22 22 84 44 South S 22 80 41
It can be seen from Table 4.2 that EdL estimates of peak demand (MW) for combined systems (assuming interconnection) appears to be about 10% higher than the values derived from the load analysis. This is largely because load diversity was not considered by EdL. EdL’s estimate of overall energy requirement (GWh) is also higher, by about 3%.
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4.1.2 Load Profiles
Information on the average weekly load profile and seasonal distribution of peak loads for each of the grids were also generated (example of Grids C1/C2.1 provided as Figures 4.1 and 4.2).
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Figure 4.1: 2002 Average Weekly Load Profile – Central 1 and 2.1
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Figure 4.2: 2002 Annual Peak Load Profile – Central 1 and 2.1
A number of features of the load profiles in Lao PDR are evident:
• Three distinct peaks occur within the daily load curve – in the morning, afternoon and evening. The prominent evening peak extends from 6:00pm to 9:00pm and defines the system’s installed capacity requirements – the morning and afternoon peaks are only 80% of the evening peak.
• The EGAT system peak is in the afternoon and the lack of coincidence with the Lao peak may provide opportunities for mutual gain in power trading arrangements. The morning and afternoon peaks are attenuated on Saturdays and Sundays and the evening peak is about 10% less than the weekday peaks.
• The shape of the daily load curve does not vary between seasons but the capacity does. Loads during the cooler months of December and January are about 80% of the equivalent loads dung the hottest months.
• The system load factor 4 is relatively constant over the year (refer Figure 4.2)
4.1.3 Load Duration Curves
The load analysis of hourly loads produced dimensionless load duration curves (LDC) for each month of 2002 for use in the SEXSI power system expansion modeling. The SEXSI model employs the dimensionless curves to provide load duration patterns for future years by scaling them up to the predicted peak power and generation requirements of a given year. As an example, monthly load duration curves for C1/C2.1 are provided as Figure 4.3). The uniformity in their shape emphasizes the lack of variation in load patterns between months.
4 System load factor is defined as the ratio of energy (continuous power) to peak demand.
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The 2002 annual load duration, formed by aggregating the monthly figures for individual substations, is provided as Figure 4.4).
Figure 4.3: 2002 Monthly Dimensionless Load Duration Curves – Central 1 and 2.1
Figure 4.4: 2002 Annual Dimensionless Load Duration Curves – Central 1 and 2.1
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4.2 Demand Forecast for Lao PDR
4.2.1 Basis of Forecast
The reference point for the preparation of the demand forecast is the Government’s goal to increase the national electrification ratio from the current level of 41% to 90% by 2020. This goal will be achieved by:
(i) Off-grid development – a successful but embryonic program of off-grid electrification employing state, donor and private resources is in place in Lao PDR. Villages chosen for off-grid electrification are currently beyond the reach of the EdL grids and are expected to remain so for the next 10 years (the time assumed for amortization of off-grid loans).
(ii) Grid extension programs involving sub-transmission and distribution development. These programs will be scoped to achieve the 90% target after taking into account the contribution of off-grid household electrification.
The basis of the demand forecast is the growth in demand in EdL’s grids due to increasing demand of existing custiomers plus load associated with new connections.
To the extent practicable, the PSDP demand forecast is based on the EdL forecast which was reviewed and adapted for the purpose. EdL’s current forecast is described in EdL’s recently updated Power Development Plan (the “EdL PDP”).5 EdL based its forecast on the methodology adopted in the JICA Report.
The methodologies used in the JICA Report and EdL PDP have been reviewed and a summary of the reviews is contained in Annex 8.
4.2.2 Assumptions
The key assumptions used in deriving the EdL demand forecast are described in Annex 8. These have been modified for the PSDP in the following areas.
(i) Forecast of Electrification Ratio
The planned household and village electrification ratios are a key input into the EdL and JICA demand forecast models. Accordingly the planned electrification ratios have been reviewed and the EdL targets modified as noted in Table 4.3 with the objective of electricity being introduced into of 90% of households by 2020 either through grid connections or off-grid supplies. The EdL electrification rates have been modified for PSDP forecasting purposes as indicated in Table 4.3. The modified EdL rates represent achievable interim targets.
5 Power Development Plan PDP 2002-12 (Updated Schedule of Committed Projects), System Planning Office, Development Division, Electricité du Laos, July 2003.
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Table 4.3: Electrification Targets
Forecast Scenario 2003 2005 2010 2015 2020 PDP Low (%) 36 39 48 58 70 PDP Medium (%) 39 50 60 69 80 PDP High (%) 42 60 70 79 90 Modified PDP (%) 38 45 70 79 90 Pre-Grid (%) 0 0 5 7 12 Grid Conversion (%) 0 0 2 5 10 Off-Grid (%) 0 0 5 7 10 Modified EdL (%) 38 45 65 72 80 Total Households (№) 915,868 960,449 1,071,383 1,183,863 1,295,799 Pre-Grid Households (№) 310 1,325 50,000 86,603 150,000
The assumptions and sources of data behind the PSDP electrification targets in Table 4.3 are outlined:
a) EdL PDP low, medium and high scenario - the source of this data is the EdL Power Development Plan for the period 2002-2012, July 2003. Although it is not explicitly stated, EdL’s power development plan has been predicated on the high growth forecast scenario. This is the scenario that achieves GOL’s intermediate and long-term electrification targets.
b) Modifications to EdL PDP – The EdL PDP’s 2010, 2015 and 2020 targets may be achievable if funds for the necessary capital works are available. The 2005 PDP target, though, is ambitious from two perspectives; firstly, availability of funds for capital works and, secondly, capacity constraints within the Lao power transmission and distribution system. Consequently, the 2005 target was reviewed downwards from the EdL PDP high and medium case values. A 2005 household electrification target of 45% was adopted by interpolating between the EdL PDP’s 2003 and 2010 PDP household electrification targets.
c) Pre-Grid – The EdL PDP does not take into account off-grid technologies (pre-grid) for electrifying households. There is currently a successful off-grid program in Lao PDR and the pre-grid household electrification targets have been deducted from the overall household electrification targets for the PSDP forecast. Targets of 50,000 households by 2010 and 150,000 households by 2020 were established for the pre-grid program in consultation with the off-grid unit of DOE and the World Bank. Though the contribution of the off-grid program to GOL’s household electrification targets is significant, the effect on forecast demand for capacity and energy is slight.
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d) Grid Conversion - In combination with pre-grid targets, a rate at which off-grid villages convert to grid supplies was also estimated. This target takes into the account pre-grid households that change to grid-connected services as the grid extends further into rural areas. The grid conversion target was established in consultation with the off-grid unit of DOE.
e) Off-Grid – The off-grid scenario represents the households that will use off-grid technologies for the foreseeable future and is calculated by deducting the grid conversion target from the pre-grid target.
f) Modified EdL – The modified EdL scenario is calculated by deducting the off-grid households from the modified EdL PDP scenario. This is the demand forecast scenario that the PSDP study will use as a Base Case going forward.
The household electrification rates from which the EdL PDP and modified EdL demand forecast scenarios are derived are shown in Figure 4.5. The modified EdL demand forecast scenario, together with the underlying assumptions, were discussed with the World Bank.
Figure 4.5: Household Electrification Rates
(ii) Non-Residential Demand Growth
Non-residential demand growth is based in part on GDP growth targets. Should actual GDP growth be less than the GOL’s targets, there will be lower than planned demand growth. The GDP growth targets assumed are the same for all scenarios and are based on the Socio-Economic Strategy of the GOL, repeated in Table 4.4.
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Table 4.4: GDP Growth Targets
2000 to 2005 2006 to 2010 2011 to 2020 GDP Total 6.5 6.0 5.0 GDP Industry Sector 8.5 8.0 6.5 GDP Service Sector 7.0 6.5 5.5
The above GDP growth figures have been adopted; however, demand forecast should be reviewed in subsequent years and adjusted to reflect any changes in actual and forecast GDP figures.
(iii) Household Electrification Rate
Household electrification rates (number of electrified houses divided by the total number of houses in each village) are not specifically taken into account in the demand forecast. The implication of a low household electrification rate is that the grid must extend further to electrify the target number of households and this increases the cost per electrified household in newly electrified villages.
Though household electrification rates may be low initially, household electrification rates are expected to increase rapidly to close to 100% within within 5 years of the grid arriving at a village. We therefore have not taken the household electrification rate into account in the demand forecast.
(iv) Coincidence
The following coincidence factors were allowed for when interconnecting EdL’s grids:
• Central 1 + C 2.1 Grid 0.97 • Central 1 + C2.1 + C2.2 Grid 0.94 • Central 1 + C2.1 + C2.2 + S Grid 0.94
v) Industry Load in Central 2.1 Grid
There is evidence of increasing economic activity in Lao PDR and the GMS region. A number of developments within the Central C2 supply area, in particular, is seeing a significant increase in demand. The improvement of the north-south and east-west (Thailand-Vietnam) road system will contribute to the general development of the area but, more significantly in the short term, a number of industrial point loads are being added in the Central 2.1 area including the following:
• Cement factory 20 MW 2005 • Quarry 5 MW 2008 • Gypsum & lead mine 5 MW 2006 • Copper/Gold Mine 40 MW 2005
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• Nam Theun 2 construction 4-8 MW 2006-2010 • Irrigation 10 MW 2003 - 2020
vi) Actual Energy Demand Data
The 2002 value of demand was determined using load data obtained from EdL substations and processed using Lahmeyer’s HCHEC and HDURM programs. The value so derived did not correspond to the EdL figure for the same year and the EdL forecast was therefore adjusted for PSDP purposes by anchoring the EdL growth forecasts to this known 2002 starting value.
4.2.3 PSDP Base Case Scenario Assumptions
In summary, the PSDP base case demand forecast for grid-supplied electricity (domestic consumption) is formulated on the EdL PDP forecast with the following adjustments:
(i) The household electrification target (inclusive of off-grid households) for 2005 is reviewed downward to 45%;
(ii) Pre-grid and off-grid households are taken into account in the projections of total households electrified;
(iii) Coincidence has been allowed for when interconnecting isolated grids;
(iv) Additional industrial load has been allowed for in the Central 2.1 grid (Khamouanne Province);
(v) The forecast has been adjusted to reflect actual 2002 energy demand data.
4.2.4 Comparison of PSDP and EdL Forecasts
The aggregate EdL demand forecast is summarized in Table 4.5. The PSDP demand forecast, determined by making the adjustments to the EdL forecast described in the preceding section, is summarized in Table 4.6. The apparent anomaly between years 2002 and 2005 is caused by the copper/gold mine electro winning process in Central 2.1. This will be a load of about 40 MW with a load factor of 0.8. The electro winning plant is presently under construction, as is the 115 kV transmission line to feed the plant, with a planned commissioning date of December 2004.
A graphical comparison of recent demand forecasts is provided in Figure 4.6.
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Table 4.5: Aggregate EdL Forecast
Item Unit 2002 2005 2010 2015 2020 Energy Consumption GWh 968.8 1,839.3 2,775.9 3,716.8 4,834.2 Av. annual Growth Rate % 24% 9% 6% 5% Peak Load MW 204.7 367.7 542.8 727.9 948.8 Av. annual Growth Rate % 22% 8% 6% 5% Load Factor % 55.3% 55.6% 60.0% 60.0% 60.0%
(Source: Summary of Electricity Demand Forecast (High Case), EdL PDP Plan, EdL Power Development Plan PDP 2002-12, July 2003)
Table 4.6: PSDP Demand Forecast
Item Unit 2002 2005 2010 2015 2020 Energy Consumption GWh 937.0 1,731.3 2,695.0 3,559.8 4,664.2 Av. annual Growth Rate % 23% 9% 6% 6% Peak Load MW 197.8 338.8 486.4 642.9 836.4 Av. annual Growth Rate % 20% 7% 6% 5% Load Factor % 54% 58% 63% 63% 64%
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Figure 4.6: Comparison of Recent Demand Forecasts
1200
PSDP Demand Forecast (June 2004) 1000 EdL PDP 2002-2012 (High Scenario, July 2003) JICA Study, (High Scenario, Sept 2002) JICA Study, (Low Scenario, Sept 2002) 800 PSSS Study (High Scenario, March 2001) PSSS Study (Base Scenario,March 2001) HDSS Study (Base Scenario, Jan 600 2000)
400 MAXIMUM DEMAND (MW)
200
0 2000 2002 2005 2010 2015 2020 YEAR
6000
PSDP Demand Forecast (June 5000 2004) EdL PDP 2002-2012 (High Scenario, July 2003) JICA Study, (High Scenario, Sept 2002) JICA Study, (Low Scenario, Sept 4000 2002) PSSS Study (High Scenario, March 2001) PSSS Study (Base Scenario,March 2001) 3000 HDSS Study (Base Scenario, Jan 2000) DEMAND (GWh) 2000
1000
0 2000 2002 2005 2010 2015 2020 YEAR
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5.0 EXPORT POWER MARKET
5.1 Regional Market
5.1.1 Regional Cooperation
Lao PDR belongs to two regional power cooperation groupings. The first is ASEAN comprising Lao PDR, Thailand, Vietnam, Cambodia, Myanmar, Malaysia, Singapore, Brunei, Philippines and Indonesia and a number of initiatives are being pursued under the auspices of ASEAN including grid interconnection between member countries.
The other grouping, the Greater Mekong Subregion (GMS), comprises Lao PDR, Thailand, Vietnam, Cambodia, Myanmar and Yunnan Province of the People’s Republic of China. The GMS region better defines the regional extent of Lao’s market as China, a country of potential importance, is represented (Yunnan Province) and those ASEAN countries of peripheral relevance are not.
5.1.2 Energy Distribution within GMS Region
The GMS is endowed with substantial energy reserves, but they are unevenly distributed between the member countries. Lao PDR, Myanmar, Yunnan and Vietnam have the energy resources to be self-sufficient but Thailand is energy deficient and will increasingly rely on imports in spite of considerable oil, gas and lignite reserves. Cambodia is also dependent on imported energy. Within each county there is also a lack of balance in the mix of energy sources.
Hydropower resources in Lao PDR, Myanmar, Yunnan and to some extent Vietnam are abundant and exceed those countries’ own demand. Good quality coal deposits occur in Yunnan and Vietnam. Lignite deposits in Thailand are unlikely to be exploited further due to a combination of economic and environmental reasons unless cost-efficient emission control technologies are advanced. There are substantial recoverable reserves of natural gas, mainly from offshore fields in Myanmar, Thailand and Vietnam. Oil production in the GMS is limited.
Indicative electricity trading potential between GMS countries is illustrated in Figures 5.1 and 5.2. Existing contracts and MOUs indicate that Thailand intends to meet its energy deficit by importing hydropower from Lao PDR, Yunnan, Myanmar and possibly Cambodia, natural gas from Myanmar, and coal, oil and more gas from countries outside the GMS. Vietnam will probably become an importer of electricity as well, mainly to cover supply shortfalls expected in the southern part of the country.
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Figure 5.1: Import and Export Potential of Regional Energy Resources
Cambodia Lao PDR Myanmar Thailand Vietnam Yunnan
Hydropower Import ?
Coal Import
Import ? Gas
Import Oil
Export Potential Import Needs
Figure 5.2: Energy Trading in the Greater Mekong Sub-Region
The following energy trade agreements currently exist among GMS countries:
• The Petroleum Authority of Thailand (PTT) signed contracts in 1996 and 1997 for natural gas supplies from two major offshore fields in the Gulf of Martaban, Myanmar, the Yadana field and Yetagun field. Pipelines from these fields transport the gas to the newly completed
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Ratchaburi CCGT plant. Recent discoveries of more gas in the Gulf of Martaban open the way for gas imports from Myanmar to rise from the planned 725 MMcfd to about 1000 MMcfd (sufficient for a 4,000 to 5,000 MW combined cycle power station). This would then fully utilize the capacity of the pipeline to Ratchabun.
• Inter-governmental MOUs between Thailand and Lao PDR provide for the supply of 3,000 MW of power by Lao PDR by the year 2010.
• An inter-governmental MOU, signed in July 1997 between Thailand and Myanmar, firstly for the purchase by Thailand of 1,500 MW by 2010 and, secondly, for the sale of 100 to 150 MW in the shorter term to alleviate power shortages in Myanmar.
• An agreement for the importation of 3,000 MW from Yunnan Province, China by 2017 including 1,500 MW of power from the Jinghong hydroelectric project. The HV transmission line from Jinghong will be routed through northern Lao PDR.
• An inter-governmental MOU signed in 1999 between Thailand and Cambodia agreement for power exchanges between the two countries, involving initially exports from Thailand of 15 to 20 MW to border areas in Cambodia, and later to allow the output of a hydropower project in Cambodia to sell into the Thai market.
• An inter-governmental MOU signed between Lao PDR and Vietnam in 1995 for Lao PDR to supply 1,500 to 2,000 MW of hydropower to Vietnam by 2010.
• Recently, GOL signed an agreement with the Government of the Kingdom of Cambodia on power sector cooperation for least-cost supply of electricity to areas along the common border.
5.1.3 Electricity Trading among GMS Countries
Of the various forms of energy, electricity is particularly suited to efficient exchange among trading partners once the transmission infrastructure and institutional framework are in place. The economic, environmental and sectoral benefits of electricity trading include the following:6
• Improved efficiency in the allocation of resources through project ranking and optimal plant mix being determined on a regional rather than national basis;
• Income from power sales for the exporting country from projects that might not otherwise be built for domestic purposes. This income can be applied to the development of the country;
6 Benefits of regional power trade are identified, discussed and quantified in the report “Power Trade Strategy for the Greater Mekong Sub-Region”, Crousillat, E., World Bank, September 1998
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• Reduced reserve margins, time-of-day benefits, improved reliability and network stability with less overall power plant capacity;
• Better economies-of-scale and reduced operating costs, leading to lower overall tariffs;
• Reduced consumption of fossil fuels and reduced air emissions, due to better exploitation of the region’s hydropower potential;
• Greater regional self-reliance and reduced exposure to sudden price hikes in international fossil fuel markets;
• Economic benefits through import substitution associated with greater regional exploitation of indigenous energy resources;
• Promotion of a ‘regional’ power market and private sector involvement.
Due to its geographical location of at the hub of the GMS region and its hydropower potential, Lao PDR is strategically positioned to play a significant role in realizing the benefits outlined above.
To date, international power trade within the GMS region has been facilitated through several different models. At one level, umbrella government-to- government agreements provide a framework for project-specific PPAs to be negotiated between private sponsors and power purchasers (e.g. Nam Theun 2), while on another, direct exchanges between utilities take place on relatively flexible and opportunistic terms (EGAT agreements with EdL and Tenaga).
Prerequisites to an efficient trading environment include adequate transmission infrastructure and an institutional framework that encourages trade on the basis of economic efficiency. A 500 kV regional grid is planned but its development will take time (refer Section 8.3). Also, the institutional arrangements in most member countries have evolved to meet the needs of a more insular time when power sectors developed independently and investments were largely public financed. Cross border exchanges of electricity have been introduced under these arrangements on a case-by-case and project-by-project basis but a new framework is needed to facilitate free and efficient trade, unburdened by the large transaction costs and biases of the present system.
5.1.4 Regional Electricity Demand
Figure 5.3 provides a brief snapshot of regional demand for electrical power and energy over the period up to 2010. The following sections contain more recent and detailed forecasts for each GMS country and an analysis of trading opportunities for Lao PDR.
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Figure 5.3: Regional Electricity Demand
5.2 Thailand
5.2.1 Sector Development and Reform
Energy has been considered a key production factor of the Thai economy, which depends on external sources for about 60% of its commercial energy needs. The total installed generation capacity has increased from 2,400 MW in 1975 to over 23,000 MW in 2002.7 A breakdown of installed capacity by generation technology is shown in Figure 5.4. The transmission system now interconnects almost all parts of the country and almost 100% of villages and 80% of rural households in the Kingdom are now electrified.
7 Information on Thai demand and power development is drawn from the document EGAT Power Development Plan, General Information, Generation System Development Planning Department, System Planning Division, EGAT, April 2003 (subject to approval from Ministry of Energy), and supplemented from recent public domain publications, conference presentations and official documents posted on the EGAT and NEPO web sites.
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Figure 5.4: Generation in Thailand 2002
The electricity sector, while retaining its primary function of providing reliable and inexpensive electricity, has had its role re-defined in recent years. Restructuring and reform processes were introduced over the last decade to encourage private sector participation and promote efficiency. The direction of the sector changed again with the incoming Government reversing initiatives such as the proposed power pool and promoting a partial listing of EGAT on the Stock Exchange of Thailand.
5.2.2 Energy Resources for Generation
The indigenous and imported primary energy sources used for the generation of electricity in Thailand are outlined in Table 5.1:
The main fuels for future use in power generation in Thailand are:
• Imported natural gas, because it is environmentally friendly and, when burnt in combined cycle gas turbine units, it provides the most efficient and economic form of thermally generated energy.
• Imported coal, because of its low price and worldwide availability. Thailand is committed to importing only low sulfur coal to limit environmental effects.
• Imported heavy fuel oil, as a back-up fuel for gas, especially for steam power plants.
• Domestic lignite, as the main indigenous resource, largely restricted to the Mae Moh area.
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Table 5.1: Energy Resources for Generation in Thailand
Fuel Reserves, Imports Potential Use for Power Generation, and Assessment of Environmental Impact
Lignite Domestic, substantial Restricted potential due to environmental reserves opposition. Mae Moh deposits have high sulfur content. High environmental and social impact. Coal Imported Major medium to long term option. Currently medium to high environmental impact but technological improvements may reduce emission problems. Gas Limited domestic reserves Will become major source; marginal cost that will in time become equivalent to import price. Imports are supply exhausted. Major imports constrained. Clean burning compared with oil or from nearby countries are coal, but CO2 emission are considerable. Low to planned medium impact. Oil Limited domestic reserves, Role of oil to be reduced, but still an important imports from overseas option due to plentiful supply situation. Medium to suppliers high impact. Orimulsion Imported from Venezuela Asphalt-like oil substance. Proposed by one private developer as fuel for steam plant. Medium to high impact. Uranium Imported Long term option, public acceptance is a problem. Hydro Substantial local potential, Further development restricted due to only 25% developed. environmental difficulties, pumped storage may be Remaining sites attractive. Degree of impact depends on many predominantly in national factors: location, storage size and mitigation parks or on Mekong River measures. Solar Substantial potential No utility size plant in sight. Photo-voltaics used in market niches. Low impact. Wind Limited potential due to low Major development unlikely in spite of ever and irregular wind speeds decreasing windmill prices. Low impact. Geothermal No proven potential. Thailand No plans for utility scale development. Low to has small demonstration unit medium impact, depending on mitigation measures. Waste Possible source of fuel Co-generation in waste incinerators will make a modest contribution. Medium to high impact, depending on mitigation measures
5.2.3 Demand for Electricity in Thailand
Thailand’s economy has been characterized by rapid expansion over recent years, particularly during the period 1987-1991, when significant structural shifts occurred. On average, GDP grew at 11% per annum during this period, spurred by rapid industrialization in the country. GDP growth rates since 1991 remained high, averaging 8% per annum. The demand in the industrial sector in particular has been growing rapidly, averaging 16% up to 1991 and approximately 11% between 1991 and 1995. By 1995, manufactured goods accounted for 81% of all exports, increasing from a level of 30% in 1980. The
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services and commercial sectors were not far behind, averaging 8% and 9% respectively.
Electricity has played an important role in fueling growth. From 1985 to 1997, electricity consumption grew at 12% per annum. Since 1985, the annual per capita electricity consumption nationwide increased from 400 to 1,400 kWh, and that of the Bangkok area increased from 1,500 to 5,000 kWh. This rapid growth was brought about by a high rate of urbanization, an aggressive electrification program, and a rapid expansion into service and manufacturing industries.
The Asian Economic Crisis brought this period of unparalleled growth to a close in mid 1997. Demand growth in 1998 was negative, and remaind slow in subsequent years. The Thai economy has now recovered and the EGAT Power Development Plan (April 2003) is based on GDP growth as follows:
Year GDP Growth (%) 2002 3.5 2003 4.0 2004 5.0 2005 5.0 2006 5.5
The load forecast issued in August 2002 by the Thailand Load Forecasting Subcommittee (TLFS)8 is summarized in Table 5.2. The forecasting methodology used is an "end use" approach to residential demand combined with a forecast of demographic trends, trends in housing mix, trends in appliance characteristics and changing customer preferences. Business loads are derived from an econometric equation relating business sales to business components of GDP for small customers and are based on a floor space approach to new construction and a net growth for existing buildings for large customers. Industrial loads are forecast from applications for new service and by taking into account information on new industrial developments, particularly in industrial estates. Thailand has an active demand side management (DSM) program that is factored into the forecast.
Table 5.2 presents the growth in demand for power and energy over a 25- year period from 1991 to 2016, the period from 2002 being the TLFS forecast.
5.2.4 Load Profiles
Daily and seasonal variations in peak load are illustrated for the years 1997 to 2002 in Figures 5.5 and 5.6. The peak in the Thai daily load curve occurs between 2:00pm and 3:00pm, while the Lao peak occurs in the evening between 6:00pm and 9:00pm. This might create time-of-day power trading possibilities.
8 The Thailand Load Forecasting Subcommittee includes representatives of NEPO, EGAT, MEA and PEA.
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Table 5.2: Generation Load – Historical and Forecast
Peak Energy Load Fiscal year MW Increase GWh Increase Factor MW % GWh % % Actual 1991 8,045.0 951.3 13.41 49,225.0 6036.2 13.98 69.8 1992 8,876.9 831.9 10.34 56,006.4 6781.4 13.78 72.0 1993 9,730.0 853.1 9.61 62,179.7 6173.3 11.02 73.0 1994 10,708.8 978.8 10.06 69,651.1 7471.4 12.02 74.2 1995 12,267.9 1,559.1 14.56 78,880.4 9229.2 13.25 73.4 1996 13,310.9 1,043.0 8.50 85,924.1 7043.8 8.93 73.7 1997 14,506.3 1,195.4 8.99 92,724.7 6800.5 7.91 73.0 1998 14,179.9 -326.4 -2.25 92,134.4 -590.2 -0.64 74.2 1999 13,712.4 -467.5 -3.30 90,414.0 -1720.5 -1.87 75.3 2000 14,918.3 1,205.9 8.79 96,780.7 6366.7 7.04 74.1 2001 16,126.4 1,208.1 8.10 103,165.2 6384.5 6.60 73.0 2002 16,681.1 554.7 3.44 108,389.2 5224.0 5.06 74.2 Average growth 1993-2002 - 780.42 6.51 - 5238.3 6.83 - Forecast 2003 17843.0 1,161.9 6.97 114,754.0 6,364.8 5.87 73.4 2004 19029.0 1,186.0 6.65 122,024.0 7,270.0 6.34 73.2 2005 20295.0 1,266.0 6.65 130,232.0 8,208.0 6.73 73.3 2006 21648.0 1,353.0 6.67 139,000.0 9,769.0 6.73 73.3 2007 23020.0 1,372.0 6.34 147,835.0 8,835.0 6.36 73.3 2008 24450.0 1,430.0 6.21 157,064.0 9,229.0 6.24 73.3 2009 26143.0 1,693.0 6.92 168,004.0 10,940.0 6.97 73.4 2010 27711.0 1,569.0 6.00 178,079.0 10,075.0 6.00 73.4 2011 29321.0 1,610.0 5.81 188,446.0 10,367.0 5.82 73.4 2012 31014.0 1,693.0 5.77 199,378.0 10,932.0 5.80 73.4 2013 32842.0 1,828.0 5.89 211,146.0 11,768.0 5.90 73.4 2014 34743.0 1,901.0 5.79 223,437.0 12,291.0 5.82 73.4 2015 36754.0 2,011.0 5.79 236,364.0 12,927.0 5.79 73.4 2016 38851.0 2,097.0 5.71 249,878.0 13,514.0 5.72 73.4 Average growth 1992-1996 - 1,053.2 10.60 - 7,339.8 11.79 - 1997-2001 - 563.1 3.91 - 3,448.2 3.73 - 2002-2006 - 1,104.3 6.07 - 7,167.0 6.14 - 2007-2011 - 1,534.6 6.26 - 9,889.2 6.28 - 2012-2016 - 1,906.0 5.79 - 12,286.4 5.81 -
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Figure 5.5: Monthly Peak Generation (1997 – 2002)
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Figure 5.6: EGAT Daily Load Curves on Peak Days
5.2.5 Distribution of Power Demand and Generation
The distribution of power demand and generating capacity across Thailand is shown in Figure 5.7. Apart from metropolitan Bangkok, the North-Eastern Region is the only part of Thailand with a deficit in generating capacity. Exports from the Nam Ngum, Nam Theun and Xe Kong are strategically located to meet this deficit.
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Figure 5.7: Distribution of Power Demand and Generation (2002)
5.2.6 Sources of Future Generation
The EGAT PDP (2003) sets out a “Recommended Plan” and an “Alternative Plan” for augmenting generation in the Thai power system over the period from 2003 to 2016 (refer Table 5.3). The table describes the planned changes in the mix of energy sources for generation over the planning horizon.
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Table 5.3: Thai Generation by Fuel Type (%)
RECOMMENDED PLAN ALTERNATIVE PLAN Fuel Type 2003 2006 2011 2016 2003 2006 2011 2016 Hydro 8.5 6.0 6.3 5.1 8.5 6.0 6.3 17.6 - EGAT 6.3 4.1 2.3 2.2 6.3 4.1 2.3 2.0 - Lao PDR 2.2 1.9 4.0 2.9 2.2 1.9 4.0 3.0 - Salawin ------12.6 Natural Gas 71.0 72.8 70.5 47.3 71.0 72.8 70.5 49.3 - EGAT 28.3 27.9 28.6 18.7 28.3 27.9 28.6 19.7 - EGCO 9.6 9.3 6.6 4.4 9.6 9.3 6.6 4.3 - RATCH 16.4 15.7 11.8 7.9 16.4 15.7 11.8 7.9 - IPP(Phase1) 8.7 12.3 18.0 12.2 8.7 12.3 18.0 13.3 - SPP 8.0 7.6 5.5 4.1 8.0 7.6 5.5 4.1 Heavy Oil 2.5 5.2 0.8 0.6 2.5 5.2 0.8 0.5 Diesel 0.0 0.4 0.1 0.0 0.0 0.4 0.1 0.0 Lignite 15.1 12.7 9.1 6.9 15.1 12.7 9.1 6.5 Imported Coal 2.1 1.9 6.5 4.9 2.1 1.9 6.5 4.9 Renewable 0.6 0.9 0.6 0.5 0.6 0.9 0.6 0.5 TNB 0.2 0.1 0.2 0.1 0.2 0.1 0.2 0.1 New Capacity 0.0 0.0 5.9 34.6 0.0 0.0 5.9 20.6 TOTAL 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
The emerging importance of IPPs in the EGAT system is highlighted in Figure 5.8 showing purchased power from Thai IPPs and international sources rising from 42% of total generation in 2003 to 61% in 2016.
Figure 5.8: Purchased Power in the Thai System
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Particular points to note from Tables 5.2 and 5.3 are:
• Thailand remains heavily reliant on gas for the remainder of the decade (over 70%). At the planned rates of extraction, Thailand’s indigenous gas resources will be exhausted within about 20 years. However, recent discoveries of more gas in the Gulf of Martaban gives cause to believe that gas imports from Myanmar will rise. Thailand is also planning long-term imports of liquefied natural gas (LNG) from the State of Oman. In summary, Thailand would therefore appear to have contracts in place to cover its gas demand until 2006, with options to increase gas imports as the need arises.
• The contribution from Thai hydropower declines from 6.3% in 2003 to 2.2% in 2016. Purchases from Lao PDR compensate to some extent and maintain the hydro share of the plant mix;
• The use of polluting forms of generation such as lignite, diesel and fuel oil declines steadily from a total of 18.3% in 2006 to 7.5% in 2016;
• Planned purchases from Lao PDR increase in 2010 with the commissioning of Nam Theun 2 but no other Lao projects are specifically named in the PDP;
• Projects to provide 34.6% of generation in 2016 are not named (“New Capacity”) and this may indicate significant market opportunities.
• The Alternative Plan differs from the Recommended Plan only in the progressive introduction of units of the Salawin hydropower project from 2013 onwards. The competition to Lao export prospects posed by a major development on the Salawin River is clear – the project will contribute 12.6% of total generation needs in 2016 and will boost the hydro share of the market from 6.3% in 2011 to 17.6% in 2016.
5.2.7 Candidate Power Plants
The choice of power plants to be built to cover future electricity needs in Thailand is governed by a number of considerations:
• Apart from lignite, Thailand will have to import most of its fuels for power generation. For reasons of security of supply it is necessary to diversify supply sources and fuel types.
• The system demand will grow by about 1,200 MW in 2003. Thus, the largest commercially available unit sizes can be selected. These units have higher efficiencies and economies of scale and can produce power more cheaply than smaller size units.
• Strong environmental opposition makes it difficult to build hydropower, nuclear and lignite-fired steam plant in Thailand, and therefore most additions will be gas, oil or coal-fired power plants or international purchases.
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The most suitable power plant types for Thailand are:
• coal-fired steam power plant, fired using imported coal, for base load operation.
• gas-fired combined cycle units for base and mid load operation;
• dual-fired steam power plant for base and mid load operation (primary fuel is gas, but with oil as back-up fuel);
• gas turbines and pumped storage plant to cover peak load and provide reserve;
• lignite-fired steam power plant for base load operation (with good desulfurization and dust filters).
5.2.8 Opportunities for Power Exports to Thailand from Lao PDR
The analysis of the Thai market establishes a number of complementary features between the Thai and Lao systems:
• Hydropower from Lao PDR provides political and fuel diversity to balance Thailand’s reliance on gas imported from Myanmar.
• The location of Lao projects along Thailand’s north-eastern and eastern border balances the concentration of generating capacity in the Central and Northern Regions.
• Differences in system characteristics between the two systems offer possibilities for mutually beneficial time-of-day exchanges.
Although the latest Thai generation expansion plan specifically names only one Lao project (Nam Theun 2), there are a number of unspecified capacity increments in the plan that leave open the possibility of further potential for export. Projected load growth is rapid – at the time Nam Theun 2 is commissioned in 2010, the project’s output will be absorbed within about 8 months – and it is principally a question of price. If Lao projects will can supply the market at or below avoided cost, they will probably attract interest.
The lowest cost generation technology for new plant in Thailand is combined cycle gas turbine. For a 15% discount rate and a plant factor around 60%,9 the average generation costs are in the order of 4 to 5 US¢/kWh, depending on whether external costs are to be included or not. The next lowest cost generation technology is coal-fired steam plant. Coal would probably be imported from Indonesia or Australia. The generation cost for a major coal plant is in the order of 5 to 6 US¢/kWh for base load plant and 6 to 7 US¢/kWh for the mid-load range. Coal plant has considerable
9 A plant factor of about 60% is assumed based on an estimate of opportunity cost in the current market calculated by optimising generation expansion with and without Lao imports. Plant factor of combined cycle plant in the Thai system is at least 80% and therefore the Lao hydro plant largely displaces plant operating at higher plant factors and allow Thailand to reduce generation from some of its less efficient CCGT plant.
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environmental impacts and the future of this form of generation will depend on advances in flue gas treatment technologies.
The main competitor for Lao power exports to Thailand in the medium term is gas-fired combined cycle plant. In the long-term future, if cheap gas is not available in sufficient quantities, the economics could switch to favor coal-fired generation, but adequate reserves of fuel over the next 15 years is expected and has been assumed.
Developers of projects in Lao PDR also face competition from other countries in supplying the Thai market. In view of long-term supply security and environmental constraints, Thailand is building electricity trading relationships with its neighbors and has entered into international agreements to provide the framework for such imports. Hydropower development on the Salawin River in Myanmar and Lancang River in China could play a role in the last half of next decade.
Opportunistic exports of non-firm energy to Thailand have been made since 1971 and it is understood that these will continue for the foreseeable future under a PPA between EGAT and EdL that is reviewed periodically. These exports only offset the variable operating cost of the marginal plant in the system and the pricing is discussed in Section 5.8.
5.3 Vietnam
5.3.1 Energy Resources
Vietnam has abundant indigenous energy resources. An overview is provided in Table 5.4.
Table 5.4: Primary Energy Resources of Vietnam
Resource Reserves Estimated Potential Rate of Exploitation Coal Found mainly in northern part of Large quantities suitable for power Vietnam. generation. Export is a possibility, Reserves: Anthracite 2,250 mt, brown but domestic supply has priority. coal 30,000 mt Crude Oil Proven and probable reserves of 200 Remains an option. mt, but actual reserves probably much higher. Exploration on-going. Gas Proven and probable reserves not Associated gas from oil production known, but reserves could be used for power generation. Gas substantial, in the order of 50 Gm3, from offshore fields will be used for equivalent to 1.8 tcf. Exploration on- new combined cycle plant. going. Possibly considerable export potential.
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Resource Reserves Estimated Potential Rate of Exploitation Hydropower Hydropower potential is in central and Vietnam has an exploitable northern Vietnam. hydropower potential of some 15,000 MW (of which 2,000 MW on the Mekong). However much of the potential is in small plant, which may not be able to compete. Uranium Uranium reserves available. Sufficient for large nuclear power plant. Geothermal unknown Biomass unknown Bagasse and other biomass (waste) generation being promoted. Wind Mean wind velocity less than 1 m/s, in Costs in areas of less than 4 m/s mountain areas likely to be somewhat likely to be in upper end of range higher. US$ 0.05-0.25 per kWh, hence limited potential. Solar Annual solar radiation received in Photovoltaic modules already used Vietnam about 1800 kWh/m2, possibly for small-scale (e.g. 100 W) remote less in mountain areas. Corresponds applications to conditions in southern Europe (e.g. Current costs of large-scale solar Italy, Spain) thermal (up to 10¢/kWh) or photovoltaic power (around 50¢/kWh) make plants infeasible
5.3.2 Power and Energy Demand
During 1980 to 1995 electricity sales increased much faster than real GDP. The relationship over the period shows an average elasticity of electricity sales to GDP of 1.7, meaning that electricity sales increased 70% faster than GDP. During the period 1990 to 1995 electricity consumption grew by 12.6% per year. The Asian Economic Crisis did not have the impact it did in Thailand and other Asian countries and a high rate of growth has been sustained to the present day (refer Figure 5.9).10
10 Information on Vietnamese demand and power development is drawn from recent publications and presentations as follows: • Power Development Program and Interconnection between Vietnam and Regional Counties, 9th Meeting of the Experts Group on Power Interconnection and Trade, Guangzhau, PRC, 18th November 2003; • Vietnam Power Development Program and Power Interconnection among Viet Nam, Lao PDR and Thailand, Consultation Meeting on PPTA for GMS Power Interconnection Project, Phase 1, Manila, Philippines, 16th-17th June 2003.
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Figure 5.9: Power Generation and Consumption to 2002
Electricity consumption increased significantly in across the country. Vietnam’s power sector has a regional character due to the country’s long, narrow shape and the geographic distribution of energy resources for power generation. For purposes of forecasting future demand, the energy sector is different in each of the three main regions – North, Central and South (refer Figure 5.10). In absolute terms the greatest increase has been in the south, although power consumption in Hanoi and Ho Chi Minh City is much higher than elsewhere. The central region is less economically advanced than the north or the south and per capita consumption there is therefore lower.
The highest growth rate was in agriculture (from a small base), at 21.1% a year. Growth in residential demand was second highest, at 14.7% a year. Industrial demand growth was slower until 1990, but has accelerated since to about 10% a year. The share of residential sales in total sales has increased in recent years.
Demand growth is expected to increase over the PSDP planning horizon. The base and high growth scenarios for generation requirements to 2020 are given in Figure 5.11.
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Figure 5.10: Demand by Regions
Figure 5.11: Generation Requirements to 2020
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In the north, the system is dominated by hydropower, but there are also significant reserves of coal. The fast growing south has hydro capacity as well but is relying increasingly on gas-fired generation using gas from the offshore gas fields of Bach Ho and Nam Con Son. A large gas-fired power generation complex at Phu My is being developed. The central region has the smallest population and limited installed capacity in hydro and diesel-fired generation. In the medium term, hydropower generation is being developed in the Se San basin with much of it earmarked for supply to the south. Part of Vietnam’s future electricity demand will thus be met by hydropower, but the main system additions will be:
• coal-fired power plants for northern Vietnam, burning domestic coal;
• gas-fired combined cycle plants for southern Vietnam, exploiting domestic off-shore gas resources, and from 2010 onward coal-fired power plants, burning imported coal.
It is not clear whether gas supplies will be sufficient to fuel additional generating capacity in the south. New discoveries are expected, provided investment in exploration continues. From 2010, though, the development of coal-fired power stations burning imported coal will increase (refer Figure 5.12 and 5.13). This suggests that the economic advantage of Lao hydropower would improve as coal-fired power plants have higher generation costs and environmental impacts than gas-fired combined cycle plants.
It can be seen from Figure 5.13 that imports play only a minor role in meeting Vietnamese generation needs but they do increase in the second decade of this century, increasing from 2% to nearly 9% of total requirements.
Figure 5.12: Capacity of Power Plants by Primary Fuel Type
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Figure 5.13 Source of Generation – 2010 and 2020
5.3.3 Load Profiles
Daily and seasonal variations in peak load are illustrated for the years 1996 to 2001 in Figures 5.14 and 5.15. The peak in the Vietnamese daily load curve occurs between 6:00pm and 7:00pm, roughly the same as the Lao peak. Thus, the potential for time-of-day power trading may be limited. Monthly variation in generation by plant type is shown in Figure 5.16.
Figure 5.14: Daily Load Curve – Peak Days 1996 - 2001
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Figure 5.15: Daily Load Curve – by season (1996 – 2001)
Figure 5.16: Monthly Generation by Plant Type - 2001
A comparison of Figures 5.6 and 5.15 highlight complementary features in the annual load curves of EGAT and EVN with the system peaks occurring in March and July respectively.
5.3.4 Cooperation with Neighboring Countries
The policy of the Government of Vietnam is to cooperate with its neighbors as a means of achieving a least-cost and reliable power supply for the country.
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As a member country of the ASEAN and GMS groupings, Vietnam is involved in regional cooperation in the construction of transmission lines and the promotion of power trade. Regional power agreements to which it is a signatory are:
• Inter-governmental agreement for cooperation with Lao PDR for the purchase of approximately 1,500 to 2,000 MW;
• Cooperation with Cambodia in the construction of a 220 kV transmission line from Vietnam to Phnom Penh and supply of power;
• Regional cooperation and grid interconnection among ASEAN countries;
• Transmission interconnection with China according to the following target dates: - current interconnections at MV - 110 kV before 2010 - 220 kV and 500 kV after 2010
5.3.5 Opportunities for Power Exports to Vietnam from Lao PDR
Prospects for the discovery of more natural gas within Vietnam’s territory are good. The question remains whether the new discoveries will be sufficient to cover the fuel needs associated with meeting the rising demand for electricity in southern Vietnam. This question cannot be answered with certainty as it is tied to the allied issue of whether the large amounts of capital required for the expansion of Vietnam’s power sector and gas resources will be mobilized.
The information contained in the EVN power development plan indicates an increasing reliance on coal-fired generation (refer Figure 8.11). If imported hydropower from Lao PDR is competing with coal-fired power plant, it will be an attractive option. However, if the primary generation alternative in Vietnam is gas-fired combined cycle, a tariff based on avoided cost would probably not be high enough to support any but the better Lao hydropower projects. As in Thailand, Lao hydropower is marginal in competition with combined cycle plant in the current market.
To date, no projects have been implemented for export to Vietnam and no sponsors have signed a PPA with EVN. However, negotiations between EVN and the sponsors of the Nam Mo and Xe Kaman 3 projects are well advanced. There is also Vietnamese interest in other hydropower prospects in the Xe Kong basin. Among them, the Xe Kaman 1 and Xe Kong 5 projects also perform well in the PSDP evaluations.11
Vietnam is, and will remain for the time being, short of foreign currency and will seek to fund its generation development in Dong to the maximum extent possible. The Xe Kaman 3 project is an interesting development in this
11 The extension of the hydrological series to 2002 benefits projects in the Xe Kong basin. The additional years of record result in an upwards revision in estimates of long term mean flows.
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respect. The project’s large civil component and the involvement of Song Da and EVN in its development will reduce US dollar denominated costs and will achieve levels of local financing that would not be possible under a traditional project finance arrangement.
5.4 Cambodia
5.4.1 Overview of Sector
The power market in Cambodia is small but growing rapidly. Grid electrification of households stands at only 15%; consumption is 45 kWh per capita. 12
The power system is fragmented, comprising three isolated load centers of Phnom Penh, Siem Reap and Sihanoukville. Generation in these grids is supplied from diesel sets owned by Electricité du Camboge (EdC) and IPPs (refer Figure 5.17).
Figure 5.17: Generation in EDC Grids – 1997 to 2000
12 Information on Cambodian power demand and power development is drawn from the recent publications and sources: • Current Structure of Cambodia Power Sector, presentation to 9th Meeting of the Experts Group on Power Interconnection and Trade, Guangzhau, PRC, 18th November 2003; • The ASEAN Centre for Energy website (ASEANenergy.org).
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Other small isolated provincial loads are supplied on a commercial basis but the costs of generation are high. Retail tariffs vary from 9 ¢/kWh to 25 ¢/kWh in the grids but are as high as 80 ¢/kWh in rural off-grid areas. An objective of power sector development is to replace these small off-grid sources with lower cost grid supply, particularly in areas of growing industrial and commercial loads.
5.4.2 Energy Resources
The primary energy source in Cambodia is still firewood. Table 5.5 gives an overview of the energy resources of Cambodia.
5.4.3 Demand for Electricity
Projections of total power and energy demand for Cambodia is shown in Figure 5.18. Given the disaggregated nature of Cambodian demand and the embryonic status of the national grid, export opportunities for Lao PDR will be confined to areas close to the common border between the countries, i.e. Rattanakiri and Stung Treng (refer Tables 5.6 and 5.7). Demand in these areas is small, although perhaps understated due to suppressed demand, and could be accommodated by MV feeders from Lao PDR once the transmission line from Pakse to the border area is completed in 2005.
Table 5.5: Primary Energy Resources of Cambodia
Resource Reserves Potential for Use in Power Generation Oil No known reserves. Exploration on- All oil for diesel stations is imported. going. Gas No known reserves. Exploration on- None going. Coal No known reserves, but some 7 mt of Possibly in long-term, unit size required by hard coal in the Boeung Talat present power system too small for Kampong Thom and Stung Treng commercially viable coal-fired powerplant, provinces and unknown quantities of and coal quantities and quality must first be lignite in Kampot and Koh Kong proven. provinces may be available.
Uranium No known uranium reserves. No potential Solar Annual solar radiation received in Photovoltaic modules used for small-scale Cambodia about 1800 kWh/m2, remote applications. Current costs of large- possibly less in mountain areas. scale solar thermal (up to US$ 0.10 per Corresponds to conditions in kWh) or photovoltaic power (≈ US$ 0.50 southern Europe (Italy, Spain) per kWh) make plants infeasible Wind Mean wind velocity less than 1 m/s, Costs in areas of less than 4 m/s likely to in mountain areas likely to be be in upper end of range US$ 0.05-0.25 somewhat higher. per kWh, hence limited potential Geothermal unknown Biomass Unknown
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Resource Reserves Potential for Use in Power Generation Hydropower Theoretical hydropower potential of The potential in Cambodia is quite large: about 15,000 MW. 6,500 MW on the Mekong mainstream, 2,000 MW in tributaries and other rivers. However much of the potential is rather low head with unfavorable generation costs. Only limited potential for power export, but important for domestic use.
Figure 5.18: Electricity Demand Forecast – Cambodia
5.4.4 Generation and Transmission Development
Phnom Penh is the largest load center, accounting for about 60% of all load in the country. Present generation in Phnom Penh is almost exclusively dependent on imported oil that is transported on barges via the Mekong River through Vietnam. Sites for new power stations around Phnom Penh are limited and there are also limits to the barge traffic on the Mekong due to river depth and bridge clearances.
Cambodia also has a relatively large hydropower potential, most of which is on the Mekong mainstream. The development generation costs per kWh are high and the environmental issues associated with the mainstream projects add to the unsuitability of developing this potential for export.
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Cambodia has power cooperation agreements with Vietnam, Thailand and Lao PDR. These provide a framework for cooperation on power trade, technical assistance and access to third parties. Developments include:
• A 220 kV transmission line from Chau Doc in Vietnam to Phnom Penh will be completed in 2007 under ADB finance and will be;
• EDC and Electricity Generating Public Holding Co (ECGO) are developing an HV interconnection of Banteay Meanchey, Siem Reap and Battambang with Thailand, scheduled for completion in 2012;
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Table 5.6: Cambodia: Demand Forecast – Base Case Peak Load (GWh) Period: 2000 - 2020
No. Area 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2015 2020 1 Banteay Meanchey 12.89 13.44 13.64 17.04 19.18 22.57 26.37 30.92 35.70 41.10 47.49 88.95 146.98 2 Battambang 30.07 31.21 31.55 36.78 39.60 44.56 50.09 56.51 62.63 70.70 80.21 134.97 219.47 3 Kampong Cham 7.00 8.00 10.00 12.00 15.00 19.00 23.00 26.00 35.00 44.00 55.00 129.11 207.93 4 Kampong Chahnang 6.10 6.60 7.33 7.81 8.31 9.11 9.47 10.05 10.97 11.59 12.58 17.07 22.95 5 Kampong Speu 4.00 7.00 13.00 35.00 39.00 43.00 52.00 57.00 64.00 74.00 84.00 138.57 213.20 6 Kampong Thom 9.14 10.16 11.06 12.13 13.25 14.16 15.12 16.42 17.48 18.86 20.32 28.93 39.06 7 Kampot 4.00 5.00 7.00 11.00 15.00 23.00 34.00 49.00 87.00 95.00 104.00 148.23 207.90 8 Kandal 28.00 22.00 26.00 53.00 68.00 81.00 95.00 110.00 127.00 148.00 170.00 299.51 504.69 9 Koh Kong 5.52 6.00 6.49 6.99 7.53 8.33 8.77 9.42 10.09 10.77 11.51 15.83 22.66 10 Kratie 11.24 12.69 14.26 15.87 17.59 19.48 20.73 22.48 24.32 26.33 28.42 41.35 56.28 11 Mondul Kiri 0.71 0.79 1.05 1.16 1.25 1.36 1.45 1.56 1.67 1.78 1.89 2.97 3.98 12 Phnom Penh 355.00 382.00 417.00 632.00 725.00 810.00 901.00 1007.00 1124.00 1237.00 1367.00 1951.49 2737.07 13 Preah Vihear 1.88 2.22 2.44 2.64 2.82 3.02 3.19 3.40 3.93 4.17 4.42 6.29 9.38 14 Prey veng 12.40 13.33 14.45 15.37 16.32 17.52 18.22 19.57 20.76 22.23 23.74 31.95 42.28 15 Pursat 8.89 9.88 10.96 12.06 13.24 14.50 15.38 16.60 17.89 19.26 20.72 29.64 40.16 16 Rattanakiri 3.62 3.78 4.18 4.30 4.44 4.63 4.75 5.31 5.55 5.78 6.04 8.50 11.22 17 Siem Reap 39.20 43.65 47.53 53.63 58.07 65.31 72.43 80.17 87.69 96.19 105.04 156.04 208.99 18 Sihanoukville 36.00 41.00 50.00 60.00 78.00 101.00 133.00 181.00 201.00 233.00 265.00 459.52 774.32 19 Stung Treng 1.44 1.60 1.74 1.89 2.04 2.44 2.60 2.79 3.01 3.22 3.43 4.78 7.83 20 Svay Rieng 6.28 6.90 7.30 7.68 8.08 8.49 8.77 9.22 10.06 10.57 11.09 14.66 19.47 21 Takeo 3.00 5.00 6.00 9.00 13.00 17.00 26.00 36.00 61.00 70.00 80.00 139.76 225.08 TOTAL 586.38 632.25 702.98 1007.35 1164.72 1329.48 1521.34 1750.42 2010.75 2243.55 2501.9 3848.12 5720.9
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Table 5.7: Cambodia: Demand Forecast – Base Case Peak Load (MW) Period: 2000 - 2020
No. Area 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
1 Banteay Meanchey 2.57 2.68 2.73 3.52 4.01 4.78 5.63 6.66 7.73 8.94 10.36 12.03 13.56 15.29 17.25 19.38 21.78 23.88 26.18 28.69 31.45 2 Battambang 5.72 5.95 6.02 7.12 7.74 8.79 9.96 11.31 12.56 14.23 16.20 18.46 20.26 22.34 24.52 27.01 29.95 32.91 36.15 39.72 43.64 3 Kampong Cham 2.00 2.00 3.00 3.00 4.00 5.00 6.00 8.00 9.00 12.00 14.00 22.00 24.00 26.10 28.32 30.73 33.36 36.21 39.32 42.70 46.37 4 Kampong Chahnang 1.63 1.89 2.24 2.54 2.83 3.15 3.38 3.67 4.02 4.31 4.67 4.97 5.35 5.65 6.05 6.31 6.68 7.08 7.50 7.94 8.41 5 Kampong Speu 1.00 1.00 3.00 8.00 9.00 10.00 11.00 13.00 14.00 16.00 18.00 20.00 23.00 24.86 27.14 29.63 32.34 35.31 38.55 42.08 45.94 6 Kampong Thom 2.41 2.86 3.42 3.94 4.65 4.92 5.35 5.89 6.37 6.91 7.45 8.01 8.59 9.18 9.77 10.39 11.03 11.61 12.22 12.87 13.55 7 Kampot 1.00 1.00 2.00 3.00 4.00 6.00 9.00 12.00 22.00 24.00 26.00 28.00 30.00 32.01 34.11 36.35 38.74 41.28 43.99 46.88 49.96 8 Kandal 6.00 4.00 5.00 9.00 12.00 14.00 16.00 18.00 20.00 23.00 26.00 30.00 35.00 38.85 43.12 47.87 53.13 58.98 65.46 72.67 80.66 9 Koh Kong 0.91 1.03 1.17 1.29 1.42 1.58 1.70 1.85 2.01 2.18 2.34 2.52 2.71 2.90 3.10 3.31 3.64 3.89 4.17 4.46 4.77 10 Kratie 3.16 3.79 4.44 5.04 5.66 6.31 6.77 7.39 8.02 8.69 9.36 10.07 10.84 11.62 12.45 13.32 14.27 15.13 16.03 17.00 18.02 11 Mondul Kiri 0.21 0.25 0,31 0.36 0.41 0.46 0.50 0.54 0.59 0.64 0.68 0.73 0.77 0.92 0.97 1.02 1.08 1.15 1.22 1.30 1.38 12 Phnom Penh 64.00 67.00 73.00 127.00 145.00 161.00 179.00 202.00 228.00 253.00 281.00 307.00 330.00 353.10 377.82 404.26 432.56 462.84 495.24 529.91 567.00 13 Preah Vihear 0.51 0.61 0.74 0.85 0.95 1.06 1.14 1.25 1.41 1.52 1.63 1.73 1.84 2.04 2.15 2.27 2.39 2.53 2.69 2.85 3.02 14 Prey veng 3.04 3.66 4.36 4.79 5.55 6.13 6.58 7.21 7.79 8.42 9.04 9.56 10.25 10.83 11.48 12.14 12.69 13.39 14.13 14.92 15.75 15 Pursat 2.28 2.75 3.24 3.70 4.16 4.63 4.99 5.46 5.94 6.43 6.95 7.48 8.04 8.61 9.22 9.85 10.52 11.10 11.71 12.35 13.03 16 Rattanakiri 1.06 1.15 1.28 1.39 1.50 1.60 1.68 1.84 1.94 2.05 2.16 2.26 2.45 2.57 2.68 2.91 3.04 3.18 3.34 3.50 3.68 17 Siem Reap 8.38 9.36 10.20 11.59 12.58 14.19 15.76 17.48 19.12 21.00 23.07 25.36 27.54 29.89 32.04 33.94 35.93 38.03 40.24 42.58 45.06 18 Sihanoukville 5.00 6.00 7.00 10.00 14.00 19.00 26.00 37.00 42.00 48.00 54.00 60.00 68.00 74.84 82.79 91.59 101.33 112.10 124.01 137.20 151.78 19 Stung Treng 0.45 0.55 0.66 0.76 0.85 0.99 1.08 1.19 1.30 1.41 1.52 1.64 1.77 1.89 2.02 2.15 2.41 2.59 2.77 2.96 3.17 20 Svay Rieng 1.61 1.90 2.23 2.51 2.79 3.04 3.25 3.51 3.85 4.11 4.38 4.64 4.91 5.27 5.55 5.82 6.11 6.47 6.85 7.26 7.69 21 Takeo 1.00 1.00 2.00 3.00 4.00 6.00 9.00 15.00 17.00 19.00 22.00 25.00 29.00 31.90 35.09 38.60 42.46 46.70 51.38 56.51 62.16
TOTAL 113.94 120.43 137.73 212.4 247.1 282.63 323.77 380.25 434.65 485.84 540.81 601.46 657.88 710.66 767.64 828.85 895.44 966.36 1043.15 1126.35 1216.49
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• Finance agreements have been signed for the construction of a 115 kV extension of the Lao Southern grid to the border. Completion is expected in 2005.
Priority Cambodian power projects for the period to the end of the decade include the following:
• Construction of the Southern and Western Grid of Cambodia; • Connection of Southern Grid with Vietnam, and Western Grid with Thailand; • Rehabilitation of Kirirom hydro power station and transmission line (115 kV) from Kirirom to Phnom Penh; • Construction of base load thermal power plant in Sihanoukville; • Construction of peak generation in Phnom Penh (IPP); • Construction of the Kamchay and Battambang hydro power stations.
Proposed power development in Cambodia to 2024 is summarized in Table 5.8.
Table 5.8: Power System Expansion Plan
Year Generation Transmission Source MW Location 2004 HFO 10 Siam Reap 2005 32 Phnom Penh * Trade Thailand-Banteay Meanchey-Battambang 2006 HFO 10 Phnom Penh * 30 Phnom Penh * 2007 Trade Takeo-Vietnam (import) 2008 Increase import capacity from Vietnam 2010 CCGT 60 Sihanoukville Sihanoukville 2011 CCGT 30 Sihanoukville Hydro 127 Kamchay Kamchay -Kampot 2012 Hydro 73 Battambang Battambang 1&2 - Battambang 2013 Hydro 110 Stung Atay Stung Atay - Pursat 2014 CCGT 90 Sihanoukville 2015 Hydro 125 Stung R Chrom Stung Russei Chrom interconnection 2016 Link Southern & Northern grid to Western 2017 CCGT 90 Sihanoukville 2018 Hydro 467 Sambo Sambo interconnection 2019 Import 500kV interconnections w/- Lao & Vietnam 2020 2021 CCGT 90 Sihanoukville Hydro 202 Srepok II Srepok II interconnection 2022 Hydro 222 Se San II Se San II interconnection 2023 Hydro 375 Se San III Se San III interconnection 2024 500kV interconnect of Thailand & Vietnam * IPP projects
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5.4.5 Scope for Imports and Exports
Electricity generation in Cambodia is currently based mainly on diesel plants and high cost off-grid technologies. The country’s hydropower is still to be developed but generation costs of most sites are unfavorable compared to alternative sites in southern Lao PDR. Avoided costs in Cambodia are high and, potentially at least, there is a market for Lao hydro, albeit a rather small one. Significant power trading opportunities will emerge only when a 230 kV or 500 kV connection is built to link the Lao Southern Grid with the major Cambodian loads centers of Phnom Penh, Sihanoukville and Siam Reap. Currently, this is not planned until 2019. Until, the only accessible market will be the small and dispersed loads in those border provinces within economic reach of the future EdL 115 kV substation in the Khone Falls area. The loads in these border provinces are small and dispersed.
A high voltage interconnection between Lao PDR and Phnom Penh is not planned until 2019.
5.5 Yunnan Province, Peoples Republic of China
5.5.1 Energy Resources
Yunnan Province of the People’s Republic of China is rich in energy resources, including abundant hydropower potential. Table 5.9 provides an overview of the energy resources of Yunnan Province.
Table 5.9: Primary Energy Resources of Yunnan
Resource Reserves Potential for Use in Power Generation Oil and Gas Reserves are unknown No major oil- or gas-fired stations planned.
Coal Substantial reserves (4000 Large potential, theoretically enough to fuel 125,000 mt of anthracite, 9000 mt of MW of coal-fired capacity over 30 years. lignite and 1500 mt of coking coal) Uranium unknown Solar unknown Wind unknown Geothermal unknown Biomass unknown Hydropower Theoretical hydropower The exploitable hydro potential in Yunnan is in the potential of about order of 90,000 MW (40,000 MW on the Yangtze, 150,000 MW 22,000 MW on the Lancang (upper Mekong), 14,000 MW on the Salawin, and 13,000 MW elsewhere). It is planned to develop 8 major projects on the Lancang – 2 are built and 2 are under construction – with a total installed capacity of about 20,000 MW.
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5.5.2 Scope for Imports and Exports
The current power demand in Yunnan is about 3,000 MW, but is expected to grow to about 7,000 MW by the year 2010. The coal and hydropower potential in Yunnan far exceeds domestic requirements. Other parts of China have deficits in energy resources and some areas are experiencing power shortages and therefore power from Yunnan can be expected to supply the neighboring provinces of China. Because of its location, Yunnan is well positioned to export electricity to GMS countries, the main target market being Thailand.
Within the planning horizon of the PSDP, Yunnan could therefore be a competitor of Lao PDR in marketing electricity to the GMS region, but the extent to which it would be free to pursue an export strategy would depend on the balance of demand and supply within the Chinese system. The Jinghong Hydropower Project is to supply 1,500 MW of its output to Thailand. Other major developments are also planned for the Lancang River, although at this stage there are no agreements regarding the marketing of their output beyond the borders of China.
As a matter of speculation, it is possible that the growing economy in China and the rapid growth in the power demand this is causing, could result in China becoming a regional importer in the latter part of the planning horizon; however, for the period to 2010 Yunnan is not likely to need electricity from Lao PDR.
The northern towns of Pongsaly and Luang Nam Tha have MV connections to the Yunnan grid and currently import their supplies from Yunnan. Supply from the Lao grid through a 115 kV extension to the Luang Prabang line will commence in 2007 and displace these imports.
5.6 Myanmar
5.6.1 Energy Resources
Myanmar has abundant energy resources and is likely to become a net exporter of energy in the next decade. 13 Table 5.10 gives an overview of the energy resources of Myanmar.
13 Information on demand and power development in Myanmar is drawn from recent publications and presentations as follows: • Power Sector Country Report (Myanmar), presentation to 9th Meeting of the Experts Group on Power Interconnection and Trade, Guangzhau, PRC, 18th November 2003; • Developments in the Power Sector, Myanmar, Ministry of Electric Power, Government of the Union of Myanmar, December 2001.
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5.6.2 Scope for Imports and Exports
The current power demand of Myanmar is about 900 MW, and is expected to grow annually by about 8.5% to about 2100 MW by the year 2010. The hydropower potential therefore greatly exceeds domestic requirements and in the medium to long-term future, Myanmar is likely to become a net exporter of electricity with Thailand as its main market. In the short term, though, Myanmar may import some power from Thailand.
Myanmar is particularly well positioned to provide low cost energy to Thailand and is a potential competitor of Lao PDR. Sites for large hydropower projects on rivers such as the Salawin close to the Thai border are capable of undercutting the cost of producing electricity from all but the best Lao sites.
Table 5.10: Primary Energy Resources of Myanmar
Resource Reserves Potential for Use in Power Generation Oil Long history of exploitation. Remaining Reserves inadequate for large scale proven and probable reserves 32 mt power generation, but some oil is used to drive diesel generators and old small thermal plant Gas Onshore gas limited, sufficient to drive Used by two existing 100 MW GT in 200 MW gas turbines. Offshore Yadana Yangon. Used for export to Thailand gas field, potential 10 tcf or 300 Gm3. and domestic purposes. Potential use Offshore Yetanun gas field, potential for power generation and/or export. 1.2 tcf or 35 Gm3 . Total gas reserve 3 Myanmar is net exporter of gas, which about 160 Gm . is piped to Thailand. Coal Total reserves about 200-230 million tons, A 100 to 200 MW coal-fired power most of it sub-bitumous. Not a major station could be built in Kalewa in source. Northern Myanmar, but further exploration of reserves is necessary. Uranium No known uranium reserves in Myanmar No potential Solar Annual solar radiation received in Photovoltaic modules already used for Myanmar about 1800 kWh/m2, possibly small-scale (e.g. 100 W) remote less in mountain areas. Corresponds to applications. Current costs of large- conditions in southern Europe (Italy, scale solar thermal (up to US$ 0.10 per Spain). kWh) or photovoltaic power (around US$ 0.50 per kWh) make plants infeasible. Wind Mean wind velocity less than 1 m/s, in Costs in areas of less than 4 m/s likely mountain areas likely to be somewhat to be in upper end of range US$ 0.05- higher. 0.25 per kWh, hence limited potential Geothermal unknown Biomass (waste) unknown Hydropower Theoretical hydropower potential of The exploitable potential in Myanmar is 100,000 MW (excluding mainstream very large. In the order of 37,000 MW Mekong). has already been identified, but much of it is far from Thailand. The potential of rivers near the Thai border is about 6,500 MW.
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5.7 Export Prospects for Lao Hydropower
The primary markets for Lao hydropower are Thailand and Vietnam. These markets are large compared with the potential supply from Lao PDR and participation is therefore constrained by price rather than demand. In the current market, there are several projects in Lao PDR that could compete and, depending on changes in avoided costs over the next decade, a number of others could become financially feasible.
Competition is emerging from large hyropower projects being planned in Myanmar and China. Projects such as Jinghong (Yunnan Province, PRC) and Salawin / Ta Sang (Myanmar) have the potential to displace Lao projects from the Thai market. EGAT’s “Alternative Power Development Plan” illustrates the threat. Purchases by EGAT from the Salawin Project from 2013 and Jinghong from 2017 would leave less room for Lao participation (refer Table 5.3). However, the likelihood of this competition materializing needs to be understood. The Chinese domestic market could absorb much or all of the output from Yunnan; the financing hurdles of the Salawin projects are formidable.
In conclusion, export prospects for Lao hydropower over the forecast period depend on many factors outside Lao control - international energy prices, introduction of emissions trading, discovery of gas reserves, and economic and political developments within the region, to mention a few. Under current economic conditions five or six hydropower sites are known to have the qualities for profitable implementation for either the Vietnamese or Thai markets. With growing demand in the region, increasing global energy prices and rising concern about greenhouse gasses, it is reasonable to expect improvement in market conditions.
5.8 Import and Export Prices
5.8.1 Current Import and Export Tariffs
Power trading between Lao PDR and its neighbors occurs at several levels. In describing the current tariff regime for international exchanges, it is necessary to distinguish between those involving EdL and those involving IPPs:
(i) EdL Exports and Imports
Trade involving EdL can be divided between medium voltage cross border transfers to supply border towns and villages, and high voltage exchanges with Thailand to supply EdL’s grids and earn foreign exchange from surplus generation. The current tariffs are set out in Table 5.11.
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Table 5.11: International EdL Tariffs - 2002
Export Tariffs (at 115 kV) Price
Nam Ngum, Xeset Peak (18:00 to 21:30) 2.77 ¢/kWh & Nam Leuk Off-peak (21:30 to 18:00) 2.59 ¢/kWh Import Tariffs
1. 115 kV Vientiane / Xeset: Peak (18:00 to 21:30) 3.20 ¢/kWh Off-peak (21:30 to 18:00) 3.02 ¢/kWh 2. 22 kV Savannakhet / Khammouane: Peak (18:00 to 21:30) 6.00 ¢/kWh Off-peak (21:30 to 18:00) 3.50 ¢/kWh
Bokeo / Kenthao / Saiyaburi Peak (18:00 to 21:30) Mon - Fri 8.00 ¢/kWh Off-peak (21:30 to 18:00) Mon - Fri 3.25 ¢/kWh Off-peak (0:00 to 24:00) Sunday 3.25 ¢/kWh 3. 35 kV Huaphan, Sepone & Flat Rate 6.00 ¢/kWh Savannakhet Source: EdL Annual Report 2002
(ii) IPP Exports
The first IPP power generation projects in Lao PDR, Theun Hinboun and Houay Ho, secured their tariff agreements in the mid-nineties. Much has changed since this time; local Asian currencies have realigned and the costs of power generation have changed. Thus, the experience of these projects is of no particular relevance as a guide to the value of tariffs for future projects in Thailand.
The most recently concluded PPA was for Nam Theun 2. Its tariff provides an indication of likely EGAT tariffs in the current market, although some project-specific features such as transmission need to be considered. The Nam Theun 2 tariff price for primary energy is about 4.7 ¢/kWh levelized.
No PPAs have been signed with Vietnam but the developers of two projects, Nam Mo and Xe Kaman 3, are discussing tariff with EVN. The Xe Kaman project is still in its early stages of development with a feasibility study only just completed. The Nam Mo project is more advanced but no commitments have been made.
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5.8.2 Pricing Principles
The Lao PDR is a “price-taker” with respect to power trade. Neighboring countries have alternative sources of supply, and would be unwilling to sell power for less, or buy power for more, than their alternative cost of supply.
The relevant “cost of supply” for neighboring countries is the marginal cost, the cost of meeting an increment of load at different times of the day/year and at different voltage levels. If the load must be supplied over an extended period (i.e., years), its value is given by the system long run marginal cost (LRMC), which includes the incremental cost of both capacity and energy required to serve the load without interruption. If no long-term commitment is required, however, its value is given by the system short run marginal cost (SRMC), which includes only the cost of fuel and variable O&M required for generating units operating at the margin during different hours of the day and seasons of the year.
For international power trade, the LRMC, adjusted for the cost of wheeling, is the best proxy for the value of a firm power purchase or sale, and SRMC, similarly adjusted, is the best proxy for the value of a non-firm transaction. Specifically, the relevant marginal cost must be adjusted downward in the case of exports, since the buying country will expect to pay no more than its own marginal cost at the point where additional load is required. Likewise, marginal cost must be adjusted upward for imports, since the selling country will expect to receive its full marginal cost at the point of generation plus any cost for transmission to the buyer.
The value of power imports to, and exports from, Lao PDR cannot be estimated precisely. At best we can only approximate the marginal cost of neighboring countries based on publicly available sources of information. Further, actual tariffs for international power trade are typically developed through bilateral negotiations, and influenced by site-specific factors such as quality and location of supply, availability of surplus capacity and energy for export, financial requirements of private developers, and regional political considerations. None of these factors can be quantified for the current analysis.
Nevertheless, estimates of the marginal cost of production, coupled with known tariff terms of existing power transactions, can provide useful guidance as to the price range under which different types of power trade will take place.
5.8.3 Marginal Costs in Thailand
Two recent studies have presented estimates of the marginal cost of power in Thailand: (i) a national tariff study prepared by PricewaterhouseCoopers (PwC),14 and (ii) a study of electricity industry reform prepared by Arthur
14 Thailand tariff study, PricewaterhouseCoopers, 2001. (Study documents published on the National Energy Policy Office website.)
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Andersen (Andersen).15 We will compare the results of these studies with our own approximations to develop an estimate of Thai marginal costs.
LRMC calculations typically have two components: (i) the marginal cost of capacity (generation and network), and (ii) the marginal cost of energy. For power trade purposes, we need not consider the complexity of network capacity costs,16 but only the cost of cross-border wheeling. Each of these costs is estimated in the following discussion.
• Marginal cost of generation capacity. PwC adopts the widely accepted “peaker method” for calculating the marginal cost of generation capacity. This method presumes that a peaking gas turbine is the least cost means of meeting an incremental increase in demand, and therefore the value of marginal generation capacity. The study estimates this value to be $36/kW per year in 1999, equivalent to about $3.38/kW/month in 2003 prices.
Table 5.12 reports our own estimate of the current installed value of a peaking GT in Thailand, $3.98/kW/month. The difference between the two calculations is likely due to variation in investment/economic assumptions and to changes in the value of the Thai Baht since the time of the PwC study. Although supporting documentation was not published with the PwC results, the report notes that the PwC estimate reflects short-term surpluses in capacity, delaying the need for capacity additions. We have not assumed such delays since we are projecting marginal costs for the future years in which surpluses in the Thai power system are expected to have been fully absorbed.
Table 5.12: Marginal Generation Capacity Cost
Marginal Plant - PROXY Gas Turbine Combined Cycle Capital Cost ($/kW) 300.0 500.0 Year Required 2003 2003 Life (years) 20 20 Reserve Margin (%) 15% 15% Station Use (% of gross generation) 3.0% 3.0% Discount Rate (%) 10% 10% Fixed O&M (% of capital cost) 2.0% 2.0% Marginal Cost ($/ckW/yr) 1/ 47.78 79.63 Marginal Cost ($/ckW-month) - busbar 3.98 6.64 Marginal Cost ($/kWh) 2/ 0.014 0.024
1/ ckW denotes coincident kW. 2/ capacity cost allocated to 13 peak weekday hours adopted by EGAT for TOU tariffs (Monday-Friday, 9:00-22:00).
15 Thailand Power Pool and Electricity Industry Reform Study, Arthur Andersen, 2000. (The study consortium also included National Economic Research Associates; Barker, Dunn & Rossi; Cameron McKenna, and Presko Shandwick.) 16 Network capacity costs include transmission, substation, and distribution investments for serving customers over a range of voltage levels throughout the country.
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We wish to express results of our pricing analysis in US dollars per kWh, and therefore need to restate generation capacity costs on a per-unit basis. We have allocated the costs to peak hours as defined by Thailand’s National Energy Policy Office (NEPO) in current TOU tariffs. Specifically, peak hours are assumed to be 13 hours per weekday (Monday through Friday, 9:00 to 22:00), or about 282 hours per month. Based on the peaker method, the resulting marginal cost of generation capacity is $0.014 per kWh.
An alternative method for estimating the marginal cost of generation capacity – the “proxy unit method” – is based on the premise that marginal capacity costs should be based on the generating unit which is most frequently considered for system expansion, especially if gas turbines do nor form a major part of the system. In the case of Thailand, gas-fired combined cycle units are the most common unit proposed for expansion. (Table 5.12 includes an estimate of the cost of combined cycle generation capacity.) The proxy unit method dictates that the capital cost of a combined cycle plant should be used for purposes of estimating marginal generation capacity cost.17 Applying the proxy unit method results in an estimate of marginal generation capacity cost of $0.024 per kWh, as shown in the table.
• Marginal cost of energy. Independent estimates of the marginal cost of energy in Thailand have been prepared as part of the aforementioned studies (refer Table 5.13). The PwC study estimates the average cost of marginal energy to be $0.024 per kWh, approximately $0.027 in prices of 2003. The Andersen study estimated SRMC at 0.99 Baht/kWh, equivalent to $0.024/kWh at 2003 prices.18
Table 5.14 presents our own approximation of operating costs for the range of units that might be expected to provide marginal energy for the Thai power system. The assumptions in the table are not based on actual data; moreover, we do not have details on the current and planned operating regime, i.e., which unit groups are operating at the margin during different hours. The approximations suggest, however, that the marginal cost of energy is on the order of $0.03 per kWh, slightly more or less depending on the share of time that different unit groups operate at the margin. Table 5.14 shows two scenarios for purposes of illustration. When higher cost GTs and oil-fired steam provide a significant share of marginal energy, the average marginal energy cost is $0.032 per kWh; when the role for these units is reduced, average marginal energy cost falls to $0.027 per kWh.
17 In fact, the method suggests that the cost of the proxy unit in excess of the cost of a gas turbine should be assigned to the marginal energy cost; however, since we are expressing all costs – capacity and energy – in $/kWh, this subtlety is irrelevant for our current calculations. 18 The Andersen study calculations were presented only in Thai Baht. The slightly lower value derived might be a result of distortions in the Baht/US$ exchange rate at the time of the study.
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Table 5.13: Marginal Energy Cost Estimates from Other Sources
All Hours Peak Off-Peak PriceWaterhouse Coopers 1/ Marginal Cost ($/kWh) - 1999 0.024 Inflation Adjustment to 2003 3/ 1.13 Marginal Cost ($/kWh) – 2003 4/ 0.027 Arthur Andersen 2/ SRMC (Bht/kWh) – 2004 0.99 1.07 0.92 Current foreign exchange rate 40.0 Inflation Adjustment to 2003 3/ 0.97 Marginal Cost ($/kWh) – 2003 4/ 0.024 0.026 0.022
1/ From Thailand national tariff study, PriceWaterhouse Coopers, 2001. (Study documents published on the National Energy Policy Office website) 2/ Thailand Power Pool and Electricity Industry Reform Study, Arthur Andersen, 2000 3/ Assuming 3% average annual inflation rate 4/ Estimated marginal cost of energy in 2003 based on original estimate.
Table 5.14: Energy Costs of Marginal Plant Groups
Marginal Plant – PROXY GT Oil Older New CC Steam CC Heat Rate (Btu/kWh) 11,000 10,000 9,000 7,000 Fuel Used Diesel Fuel Oil Nat. Gas Nat. Gas Economic Fuel Cost (US$/MM Btu) 1/ 5.60 3.17 2.75 2.75 Heat Content (MM Btu/unit) 1.00 1.00 1.00 1.00 Variable O&M (% of fuel cost) 3.0% 3.5% 3.0% 2.0% Station Use (% of gross generation) 3.0% 3.0% 3.0% 3.0%
Fuel Cost ($/kWh) 0.0616 0.0317 0.0248 0.0193 Variable O&M ($/kWh) 0.0018 0.0011 0.0007 0.0004 Station Losses ($/kWh) 0.0020 0.0010 0.0008 0.0006
Marginal Energy Cost ($/kWh) - busbar 0.0655 0.0339 0.0263 0.0202
Scenario 1: - % of group at margin 5% 45% 50% 0% - avg. marginal energy cost ($/kWh) 0.032 Scenario 2: - % of group at margin 0% 30% 50% 20% - avg. marginal energy cost ($/kWh) 0.027
1/ Fuel price assumptions based on historical relationships: - Diesel: $25 crude / 5.8 MM Btu per barrel x 1.3 (empirical relationship) - Fuel Oil: $25 crude / 6.3 MM Btu per barrel x 0.8 (empirical relationship) - Natural Gas: estimated from recent international institution forecasts.
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• Wheeling charges. In recent years, we have had occasion to review a number of confidential power purchase agreements involving an adjustment for wheeling, either for power deliveries within Thailand or for cross-border exchange. Most of these agreements have been associated with IPP projects in which actual investment costs were subject to debate, and each side tended to advocate costs favoring its cause. Interestingly, however, all of these arguments have fallen within the relatively narrow range of $0.003 to $0.006 per kWh transmitted. As a practical matter, therefore, we have assumed a wheeling charge of $0.005 per kWh for cross-border transactions.
The validity of this assumption is confirmed by the fact that Thailand has in recent years charged Electricité du Laos (EdL) a wheeling rate of 0.19 Baht/kWh – approximately $0.0048/kWh at the current exchange rate – for energy transmitted to Lao border locations via the Thai grid.
We should note that the foregoing marginal cost estimates do not take explicit account of additional factors that could impact power trade transaction prices.
• Network Losses. Wheeling charges estimated above do not explicitly consider losses within the Thai power network. The PwC study estimates average losses for transmission from generation to the 115 kV network of approximately 5 percent during off-peak periods, and about 7.5 per cent during peak periods. If a transaction involves deliveries from transmission voltages through lower voltages, transaction tariffs might be expected to be proportionately higher than the above-reported estimates.
• Efficiency Improvements. Evidence suggests rapid improvement in the cost and efficiency of thermal supply options. For example, some analysts project GT capacity cost estimates of $250 (or even $200) per kW, and technology experts are projecting combined-cycle operating efficiency increases of more than 20 percent over the next decade.19 Marginal cost calculations reported above do not incorporate these longer-term adjustments in thermal capital and operating costs; our estimates might therefore be taken as high-range values for marginal energy and capacity.
5.8.4 Prices for Exports to Thailand
In the following paragraphs we combine the foregoing marginal cost estimates to derive an expected export price range. We then summarize available information on known cross-border transactions for purposes of comparison.
Firm contract primary energy exports (i.e., committed exports of both capacity and energy during daytime peak hours) can be expected to negotiate a contract price of from $0.036 to $0.051 per kWh. The low value of this range is based on the “peaker method” valuation of generation capacity ($0.014), plus the lower scenario for marginal energy ($0.027), minus the assumed cost of wheeling
19 See, for example, forecasts by the US Department of Energy in its Annual Energy Outlook series.
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($0.005); the high value is based on the “proxy unit method” valuation of generation capacity ($0.024) plus the higher scenario for marginal energy ($0.032), minus the assumed cost of wheeling ($0.005).
Firm contract secondary energy exports (i.e., committed energy exports during off-peak nighttime hours) can be expected to negotiate a contract price of from $0.022 to $0.027 per kWh, i.e., the full value of marginal energy adjusted for the cost of wheeling.
Non-firm, non-committed energy exported without obligation (i.e., only when surplus energy is available) can be expected to negotiate less favorable prices ($0.015 to $0.020 per kWh).
Data from existing and pending contracts broadly support the conclusions presented above. Table 5.15 presents the recently renegotiated tariff for Lao power sales to Thailand. Under the contract, there is no minimum or maximum delivery required, and no penalty for non-delivery.
Table 5.15: Lao PDR Tariff for Sales to Thailand
Energy Charge US$ Equivalent
Peak Off-Peak (Baht/kWh) (Baht/kWh) (US$/kWh) 1.22 1.14 0.030
NOTES: 1/ Peak period 18:00 – 21:30 weekdays; off-peak all other hours 2/ Lao imports charged these rates plus 0.19 Baht/kWh wheeling charge. 3/ Rates quoted in Baht, paid in US$; 50% at 38 Baht/$, 50% at market rate. 4/ Exchange rate conversion assumptions: - 50% peak energy share - 40.0 Baht/US$ market exchange rate
The agreed tariff for power sales under the planned Nam Theun 2 IPP project (995 MW to EGAT) has three components: (i) firm primary energy sales during 16 daytime peak hours, (ii) firm secondary energy sales during 8 nighttime off- peak hours, and (iii) non-firm sales during nighttime hours at the option of the buyer. The tariffs have been adjusted to reflect the costs of wheeling. The levelized value of the tariffs negotiated under the 25-year agreement are estimated to be:20
• $0.046 – firm, primary energy • $0.022 – firm, secondary energy • $0.014 – non-firm, secondary energy
20 Levelized assuming a current exchange rate of 40 Baht/US$, and a discount rate of 12 percent. Note that agreed tariff values are at current prices; annual payments change over time, but there is no inflator in the tariff.
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5.8.5 Prices for Imports from Thailand
Firm contract primary energy imports (i.e., committed exports of both capacity and energy during daytime peak hours) can be expected to require a contract price of from $0.046 to $0.061 per kWh. The low value of this range is based on the “peaker method” valuation of generation capacity ($0.014), plus the lower scenario for marginal energy ($0.027), plus the assumed cost of wheeling ($0.005); the high value is based on the “proxy unit method” valuation of generation capacity ($0.024) plus the higher scenario for marginal energy ($0.032), plus the assumed cost of wheeling ($0.005).
Firm contract secondary energy exports (i.e., committed energy exports during off-peak nighttime hours) can be expected to negotiate a contract price of from $0.032 to $0.037 per kWh, i.e., the full value of marginal energy adjusted for the cost of wheeling.
Non-firm, non-committed energy exported without obligation (i.e., only when surplus energy is available) can be expected to negotiate somewhat lower prices ($0.025 to $0.030).
The terms for current power purchases from Thailand’s Provincial Electricity Authority (PEA) confirm the range of these prices. PEA sells to Lao border towns under its standard Medium and Large General Service Tariff for time-of- use sales. This tariff is summarized in Table 5.16. Note that these tariffs are somewhat higher than our marginal cost estimates since these PEA rates are for sales at lower voltages, and reflect losses within the Thai power grid. Lao border loads are subject to the identical tariffs they would be charged if they were large industrial customers within Thailand.
Table 5.16: PEA Tariff for Sales to Lao Border Towns
Voltage Level Demand Energy Charge US$ Charge Equivalent
Peak Off-Peak (kV) (Baht/kW-peak) (Baht/kWh) (Baht/kWh) (US$/kWh)
> 69 74.14 2.6136 1.1726 0.062 11 - 13 132.93 2.6950 1.1914 0.068
NOTES: 1/ TOU rates for PEA General Service customers (demand 30 MW or more) 2/ Reported rates exclude Baht 228.17 monthly invoice service charge. 3/ Peak period 09:00 – 22:00 weekdays; off-peak all other hours. 4/ Rates quoted in Baht, paid in US$; 50% at 38 Baht/$, 50% at market rate. 5/ Exchange rate conversion assumptions: - 0.45 load factor - 70% peak energy share - 40 Baht/US$ market exchange rate
Finally, Table 5.17 presents a summary of the expected price range for power trade with Thailand, including a test of the sensitivity of firm contract results to changes in the discount rate.
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Table 5.17: Summary of Price Range for Power Trade with Thailand
Exports Imports
Contract - Firm Primary Energy Low 0.036 0.046 High 0.051 0.061
Contract - Firm Secondary Energy Low 0.022 0.032 High 0.027 0.037
Contract - Non-firm Energy Low 0.015 0.025 High 0.020 0.030
Notes: 10% discount rate $ 0.005 per kWh wheeling rate.
Discount Rate Sensitivity 6% 8% 10% 12% 14% EXPORTS - Firm Primary Energy Low 0.033 0.035 0.036 0.038 0.040 High 0.045 0.048 0.051 0.054 0.057 ----- IMPORTS - Firm Primary Energy Low 0.043 0.045 0.046 0.048 0.050 High 0.055 0.058 0.061 0.064 0.067
5.8.6 Prices for Power Trade with Vietnam
Vietnam, too, has alternative sources of supply. Marginal costs are dominated by domestic coal-fired and hydro generation in the north, and by gas-fired generation in the south. While EVN does not publish an official estimate of the marginal cost of supply, the World Bank prepared an estimate as part of a recent study of Vietnam’s energy sector.21 That study estimated the average marginal cost for generation (capacity and energy) to be approximately $0.042 per kWh for the period 1999-2010, and approximately $0.036 per kWh for the period 1999-2015.22 The estimates range from $0.041 to $0.050 at 2003 prices.
These marginal cost estimates do not take account of variation by time of day; peak hour variation will be more significant in Vietnam than in Thailand, since Vietnam’s peak is a narrow evening peak as in Lao PDR as opposed to the broad daytime peak of the Thai power system.
Further, the reported marginal costs do not incorporate the cost of wheeling. While we do not have an estimate of this cost, it can be expected to be at least as high – and probably higher – than the $0.005 per kWh estimated for Thailand. Sites for power development in either country are quite distant from major cross-border load centers, and necessary transmission investment would provide no ancillary benefits that might share the cost burden.
21 Fueling Vietnam's Development: New Challenges for the Energy Sector, World Bank Report No. 19037-VN (in two volumes), December 1998. 22 Sensitivities varied by ±3 percent depending assumptions regarding gas contract terms and CCGT installed costs.
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At present, Vietnam is concerned about meeting rapidly expanding domestic load, and does not appear to have any short or medium-term plans to export power on any scale.23 Lao PDR has signed a memorandum of understanding (MOU) with Vietnam for export of 2000 MW by 2010, but required generation and transmission capacity are not yet firmly committed. No pricing has been agreed for this power trade, although Vietnam has stated that imports must be priced below domestic avoided cost, and exports at greater than domestic avoided cost.
Current power trade with Lao PDR is limited to opportunistic border trade, in which Lao towns neighboring Vietnam and isolated from any domestic system are served from across the border. This trade takes place at a standard tariff of $0.060 per kWh.
5.8.7 Power Trade with Other Countries
Six countries within the Greater Mekong Sub-region (GMS) – Cambodia, Lao PDR, Myanmar, Thailand, Vietnam and Yunnan Province of China – are actively investigating regional power integration. The GMS Expert Group on Power Interconnection and Trade, under sponsorship of the World Bank and Asian Development Bank, has met regularly for several years to consider problems and potentials associated with increased power trade. As part of this effort, conceptual plans for cross-border transmission networks have been developed. One example of such a linkage – connecting Phnom Penh with the Vietnamese grid – is committed. Another concrete proposal is the extension of the Thai-Lao transmission linkage (planned as part of the Nam Theun 2 hydropower project) to the Vietnamese North-South 500 kV line; of course, this project will only be viable in association with NT2 development.
To date, however, there has been no firm agreement on prices for power trade within the GMS. For the examples cited above, we would expect that the Vietnam-Cambodia link would sell power at (or above) Vietnam’s marginal cost, especially since this value is considerably below the current marginal cost for power generation in Cambodia; to the best of our knowledge, the transaction cost for potential future trade between Thailand and Vietnam has not been formally assessed.
23 Transmission infrastructure to facilitate exports to Cambodia is being developed and it is understood that a project in the north for export to China is planned.
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Prices for future power trade between Lao PDR and other countries within the region cannot be meaningfully specified until transmission linkages are firmly planned. Nevertheless, the basic methodology set forth for Thailand in this section will be applicable to all future power trade: Lao PDR will be able to trade power at a price up to the marginal cost of generation (capacity and energy) adjusted for the cost of wheeling.
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6.0 CANDIDATE POWER PROJECTS
6.1 Status of Projects
6.1.1 Previous Project Assessments
Over 100 sites throughout Lao PDR have been evaluated for their suitability for medium or large-scale power generation. All but a handful of them are hydropower. Project studies have been carried out by GOL with ODA assistance and by private parties pursuing IPP development ambitions. These studies tend to fall into one of two categories:
• Project-specific studies carried out with the objective of determining the feasibility of a particular project, usually measured by its financial or economic rate of return;
• Project ranking studies involving the evaluation and comparison of a number of projects, usually carried out as part of a generation expansion planning exercise.
Project comparisons based on project-specific studies can be misleading. Project proponents use widely varying assumptions, methodologies and standards in evaluating their sites; also they tend to prepare and evaluate project layouts that best serve their own ends and, consequently, these layouts may not be optimal or even reliable. In a number of cases, alternative configurations for the same site exist.
A more reliable indication of the relative performance and quality of project sites is provided by project ranking studies. The principal ranking studies to have been undertaken of Lao projects are:
• Nam Theun 2: Study of Alternatives (NT2SOA) • Power System Planning in the MIH (PSP) • Hydropower Development Strategy Study (HDSS) • Power System Strategy Study (PSSS) • Se Kong, Se San and Nam Theun River Basins Study (Basins study) • Hydropower Development Plan for Lao PDR (HDP)
A comparison of project rankings from previous studies is provided in Table 6.1. The Basins and HDP studies are not included in this comparison because, in the case of the Basins study, only two of the country’s river basins were considered, and in the case of the HDP, most of the frontline projects were excluded from its TOR.
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Table 6.1: Project Rankings - Comparison of Studies
NT2SOA 1/ PSP 2/ HDSS 3/ PSSS 4/
DOMESTIC PROJECTS: 1 n/a Nam Bak 2B Nam Mang 3 N. Ngum 5 (C) 2 n/a Nam Ngum 4A H. Lamphan Gnai Xeset 2 / HH (C) 3 n/a Nam Sane 3B Nam Bak 2B Nam Mang 3 (D) 4 n/a Nam Sane 2 Thakho H.Lamphan Gnai (D) 5 n/a Nam Chian 1A Xeset 3 Thakho (D) 6 n/a Xe Pon Xeset 2 Nam Beng (D) 7 n/a Nam Khan 3 Nam Sim Viengphouka (D) 8 n/a Nam Ngum 4B Nam Beng Xeset 3 / HH (E) 9 n/a Thakho (Phapheng) Nam Pot 1 Nam Ngum 4A (E) 10 n/a Nam Sane 3A Nam Sane 2 Nam Ngum 4B (E) 11 Nam Mang 3 Xe Katam (E) 12 Nam Suang 1 Nam Bak 2B (E) 13 Nam Pot Nam Long (E)
EXPORT PROJECTS: 1 Theun Hinboun n/a Nan Theun 2 Nam Theun 2 (A) 2 Nam Theun 2 n/a Nam Mo XePian-XeN’noy (A) 3 Houay Ho n/a Nam Ngum 3 Nam Mo (A) 4 Nam Ngum 2 n/a Xe Katam Xe Kaman 1 (B) 5 Nam Ngum 3 n/a XePian-XeNamnoy Xe Kaman 3 (B) 6 Nam Ngiep 1 n/a Nam Ngum 2 Nam Kong 1 (B) 7 XePian-XeNamnoy n/a Nam Ngiep 1 Nam Ngum 2A (B) 8 Xe Kaman 1 n/a Nam Theun 3 Nam Ngum 3A (B) 9 Hongsa Lignite n/a Xe Kaman 1 Nam Theun 1F (B) 10 Nam Theun 1 n/a Xe Kaman 3 Hongsa Lignite (E) 11 Xe Katam Xe Kong 4 (E) 12 Nam Mo Xe Kong 5 (E) 13 Nam Ngum 5 Nam Theun 3 (E)
1/ NT2SOA considered only export projects. Projects ranked according to common methodology using a multi-objective system based on hierarchical weighting of various disciplines 2/ PSP evaluated projects for supplying the EdL grids and primarily focused on medium sized projects of 50 MW or less. Projects ranked on average cost of energy. 3/ HDSS considered medium and large projects and ranked them separately for export and domestic service. Projects evaluated by a common methodology using a multi-objective system based on hierarchical weighting of various disciplines. 4/ PSSS considered medium and large projects and evaluated them separately for export and domestic service. Projects were evaluated by a common methodology using multi-objective system based on hierarchical weighting of generation cost and social/environmental considerations. Projects were classified into one of the following five categories: “A” Export projects with some certainty of proceeding; “B” Export projects with reasonable prospects of proceeding subject to additional studies or further action by GoL and/or developer; “C” Domestic or domestic/export projects with some certainty of proceeding; “D” Domestic or domestic/export projects with reasonable prospects of proceeding subject to additional studies; “E” Projects with uncertain prospects due to lack of studies, and/or uncompetitive generating cost, and/or unacceptable social-environmental impact.
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6.1.2 EdL Generation Expansion Plan
Generation expansion for the Lao system may be achieved by:
• constructing new power plants • rehabilitating and upgrading existing plants • increasing imports from neighboring countries, particularly Thailand
The EdL PDP sets out EdL’s proposed generation expansion strategy. Already in Lao PDR peak demand is overtaking installed capacity and there will soon be an energy deficit. The thrust of EdL’s generation planning is to restore an adequate reserve margin and reduce dependence on imports. This strategy is underpinned by a concern that:
(i) electricity imports are not backed by contractual guarantees of supply and may not enjoy priority over the exporter’s domestic customers in the event of power shortages or crises;
(ii) pricing of power imports is agreed on a two to three year basis but generation planning is long term, leaving EdL unable to respond quickly to changes in pricing and retailing policies of foreign sellers.
The EdL generation expansion plan therefore plans to expand capacity faster than the growth in peak load until an adequate reserve margin exists and, from that point, to keep abreast of demand growth. The EdL generation expansion plan emphasizes greenfield hydropower development, reflecting the economics of indigenous energy reserves and the limited potential for rehabilitating and upgrading existing plants in Lao PDR.
The growth in peak demand is determined in part by the rate of electrification of the country. The PDP responds directly to GOL’s electrification target of 90% by 2020. The 2005 target of 45% would involve rapid expansion of the power system over the next couple of years that is unlikely to happen given the limited time and resources available to EdL. The resulting program of power station construction and rehabilitation is ambitious (refer Tables 6.2 and 6.3). Domestic off-take from export IPP projects is considered only in respect of the Nam Theun 2 project and the current allocation from Theun Hinboun.
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Table 6.2: EdL - Proposed Generation Projects, 2004 - 2020
Comm. Project Installed Finance Status Year Capacity (MW) 2005 Nam Mang 3 35 Exim China Under construction 2006 Xeset 2 76 Exim China Financing arranged 2007 Nam Lik 100 tba Feasibility study 2008 Xepon 75 tba Inventory study 2009 Nam Theun 2 IPP 75 NTPC Concession and PPA executed “ Viengphouka 60 tba Inventory study 2010 H.Lamphan Gnai 60 tba Inventory study 2012 Nam Ngum 5 100 tba Prefeasibility study 2013 Thakho 36 tba Inventory study 2014 Xeset 3 20 tba Feasibility study 2015 Nam Ngum 4A 54 tba Inventory study 2016 Nam Kong 3 35 tba Inventory study 2017 Nam Pot 23 tba Inventory study 2018 Nam Bak 2B 116 tba Inventory study 2019 Nam Ngum 4B 54 tba Inventory study 2020 Xe Xou 60 tba Inventory study tba – to be advised Source: EdL PDP 2001-12, System Planning Office, July 2003
Table 6.3: EdL – Proposed Plant Rehabilitation and Upgrade Projects
Comm. Project Finance Year 2004 Nam Ngum 1, Units 1 + 2 JICA Xeset 1, Units 4 + 5 EdL Selabam, Units 1, 2 + 3 AFD
2005 Nam Ngum 1, Unit 5 EdL Selabam, Unit 4 EdL
2007 Nam Ngum 1, Units 3+4 EdL Xeset 1, Units 1, 2 + 3 EdL
Source: EdL PDP 2001-12, System Planning Office, July 2003
6.1.3 Concession Commitments
Whether projects are publicly or privately financed is a financing decision, to be made independently of the investment decision relating to the choice of projects and the timing of their implementation. The decision to award concessions to private developers to finance and construct generation projects should be tied to an economic rationale that determines the most beneficial project and optimal moment for its implementation.
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Private developers have been awarded sole mandates to develop generation projects at a number of sites in the country. The legal nature of these mandates varies, as does the vigor with which developers are exercising them. The current status of IPP proposals and mandates is summarized in Table 6.4.
It is recognized that many of these projects will not be successfully implemented by their present sponsors (if, in fact, they are ever realized) and those that are built may be years late and take a different form to the layouts currently proposed. This uncertainty is a characteristic of many IPP models and is quite incompatible with orderly least-cost generation expansion.
Already the private sector plays a pivotal role in developing export projects and, if EdL credit risk can be reduced or countered, its role in meeting domestic demand will grow, whether through domestic off-take from primarily export projects or from dedicated domestic developments. However, the involvement of the private sector on a significant scale introduces problems for power planners in managing the uncertainty of IPP CODs and a means of countering this risk must be found for the private sector’s role in domestic generation development to be dependable and constructive. The issue is considered in some detail in Section 7.
6.1.4 PSDP Candidate Projects
For the PSDP, all projects were evaluated and ranked using a standardized methodology. Optimal power system investments were identified using project evaluations and power system investment sequences based on economic principles.
The budget for the PSDP did not extend to a comprehensive assessment of the full Lao project inventory. Based on previous studies and on current priorities, 30 projects were listed in the TOR for evaluation and ranking. The projects listed in the TOR for evaluation are:
• Nam Theun 2 • Nam Ngum 5 • Nam Theun 3 • Xeset 2 • Nam Ngum 3E • Xeset 3 • Nam Ngum 2L • Xe Katam • Xe Pian - Xe Namnoy • Houay Lamphan Gnai • Xe Kaman 1 • Project on the Xe Bang Fai • Xe Kaman 3 • Papheng (Thakho) • Nam Mo • Xepon 3 • Nam Theun1F • Nam Fa • Xe Kong 5 • Nam Beng • Xe Kong 4 • Nam Xane • Nam Kong 1 • Tad Samphamit • Nam Ngiep 1 • Nam Ngieu • Don Sahong • Nam Ngum 1 (add new capacity) • Hongsa Lignite • Viengphouka coal plant
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Table 6.4: Status of IPP Mandates in Lao PDR
Item Project Capacity Original Project Sponsor Type of Signing Date Current Project Sponsor Status (MW) Agreement 1 Theun Hinboun 210 THPC CA 13-Oct-94 THPC Operating phase 2 Houay Ho 150 Daewoo CA 23-Sep-93 Tractabel Operating phase 3 Hongsa Lignite 720 Thai Lao Lignite CA 22-Jun-94 Thai Lao Lignite Initialed PPA lapsed 4 Nam Ngum 3 440 GMS Power PDA 15-Nov-97 GMS Power MOU superseded by PDA 5 Nam Ngum 2 615 Shlapak CA 17-Mar-98 Shlapak MOU superseded by CA 6 Nam Mo 105 Mahawong PDA 18-Nov-99 Mahawong/Harza MOU superseded by PDA 7 Nam Theun 2 1074 NTEC CA 16-Nov-98 NTEC EGAT PPA negotiated 8 Xe Kaman 3 250 Viet-Lao PDR MOU 25-Jul-03 Viet-Lao PDR Feasibility study submitted 9 Xe Kong 5 250 Sondel S.P.A MOU 10-Apr-00 - Inactive (MOU expired) 10 Xe Katam 100 Hydro Power MOU 15-Oct-94 Kansai Electric MOU transferred 11 Nam Tha 1 265 SPB MOU 07-Oct-95 - Inactive 12 Xe Pian-Xe Namnoy 390 Dong Ah CA 17-Aug-94 K & L MOU re-assigned 13 Xe Kaman 1 468 ALP Mgt / ANSCAN CA 15-Nov-97 ALP Mgt / ANSCAN In process of cancellation 14 Nam Theun 3 237 Heard Energy PDA 01-Aug-94 THPC Concession transferring to THPC 15 Nam Theun 1 540 SUSCO MOU 25-Mar-94 Gamura (Malaysia) MOU reassigned 16 Nam Ou 8 600 Pacific Rim Energy MOU 11-Nov-94 - Inactive 17 Don Sahong 30 EP (Malaysia) MOU 23-Aug-01 EP (Malaysia) MOU extended for 6 months 18 Nam Ngum 5 90 Melkyma MOU 10-Sep-96 Sinohydro Corporation MOU reassigned 19 Nam Lik 100 Hainan SIT MOU 16-Feb-94 CWE Corportation MOU reassigned 20 Xe Kong 4 528 Modular MOU 21-Jan-94 - Intention to cancel notified 21 Nam Pha 70 Statecorp Holding P/L MOU 29-Aug-02 Statecorp Holding P/L Survey for feasibility study 22 Nam Bak (Cha) 2B 120 Nisho Iwai MOU 1997 Engineering Con. Survey planned 23 Nam Beng 25-50 International Blaster MOU 16-Dec-02 International Blaster Survey for feasibility study 24 Nam Ngieu 20 Hongkham Contruction MOU 29-Nov-02 Hongkham Contruction Survey for feasibility study 25 Nam Sim A 9.3 Energy Development MOU 15-Feb-03 Energy Development Feasibility study in progress 26 Nam Ngiep 1 440 Nippon Koei MOU 09-May-03 Nippon Koei Active 27 Thakho / Phapeng 30 CERIECO MOU 30-Nov-01 CERIECO Active 28 Houay Lamphan Gnai 100 - - 2004 - Application to JICA for FS 29 Se Pone 3 70 - - 2004 CIMC Application pending
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With the exceptions of the Hongsa and Viengphouka coal plants, all projects on the TOR list are hydropower projects.
The list should not be seen as a final and inflexible statement of prospective projects. It was based on current data and current market conditions and as the information base expands and markets developed, omitted projects may be added while others on the list discarded. Between the finalization of the PSDP TOR and the mobilization of the Consultant, other projects have come to prominence for one reason or another. In response, GOL asked that a further four projects be added to the list, these being:
• Nam Bak 2B (Nam Cha) • Nam Long • Nam Sim / Houay Bokay • Theun Hinboun Expansion (of which Nam Theun 3 is a part)
One project, the Xe Bang Fai development, was dropped after an initial evaluation. A desk study of power and irrigation options in the reach of the Xe Bang Fai between the Mekong and the Nam Theun 2 Downstream Channel was undertaken and a visit to prospective sites was made. This work failed to identify a project of sufficient promise to justify further effort. Notwithstanding the greatly increased and less seasonal post-Nam Theun 2 flows in the Xe Bang Fai, the hydropower potential within this reach suffered technically and environmentally from the flatness of the Xe Bang Fai floodplain. An irrigation scheme involving the transfer of water from the Nam Noy, a tributary of the Xe Bang Fai, to the Savannakhet plains was also identified.
6.2 Hydrology
At best, the streamflow series employed on previous planning studies extended from 1966 to 1995. The hydrology of the sites of all PSDP candidate projects was recently updated to include data for the years 1995 to 2002. This work was carried out under a separate contract under World Bank financing.24 The principal outcome of this work was the updating and generation of monthly flow series for all candidate project sites using data from 1966 to 2002. Monthly flow series for 39 project sites were generated, including the sites of 6 existing projects. The results were delivered progressively over a three-week period up to mid-October 2003.
Lack of time and reliable flood data prevented an updating of the design flood estimates at the project sites. From the perspective of the PSDP, the flood estimates were less important than long-term streamflow estimates. Any inaccuracy in flood estimates might have a minor affect on dam height and a more significant effect on spillway design. These elements account for a relatively small percentage of total project cost. In contrast, inaccuracies in long-term streamflow estimates would have a direct and proportionate effect
24 Dr. P. Ko, Updating Hydrology for PSDP Studies, World Bank, 31 October 2003
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on project revenues. Therefore, the overall effect of errors in flood flow estimates on the evaluation of candidate projects is much less.25
Isohyets, derived by Lahmeyer26 from rainfall estimates for the period 1966 to 1995 were used for the transposition of generated monthly flow series to ungauged sites. The isohyets were not updated due to limitations in time and lack of rainfall data for areas of Vietnam, Myanmar and southern China adjacent to Lao PDR not covered by the Mekong River Commission (MRC). Digitally generated monthly isohyets for the Year 2002 from the MRC, provided some insights into the uncommonly high run-off ratios for the upper catchment of Nam Theun and Xe Bang Fai basins. The mean annual precipitation of these two catchments could have been underestimated in the isohyets.
HEC-4 software was used for preparing streamflow estimates. Models using various groupings of interrelated flow gauges were prepared and 19 base series were selected for the transposition of extended flow series to ungauged sites. Extended flow series were generated at 38 locations - 32 for candidate project sites and 6 for sites of existing projects. The flow series were provided progressively as they were completed so that preliminary runs of EVALS could be performed. This was followed by checks of consistency by comparing flow duration curves with corresponding runoff ratios. The consistency checks and preliminary runs of EVALS exposed a number of data inconsistencies attributable to the poor quality of the recorded data and short record lengths. Affected series were regenerated.
The scope of work did not include field inspections of gauging and rating sites. Streamflow gauging points are too few to provide accurate hydrological inputs for detailed project design at many of the candidate sites. Gauges are mostly located in the lower catchments and there are none in the northern and north-western basins. Some of the stream gauging records are totally unreliable, probably due to poor design of the gauging stations, lack of maintenance and unreliable recording. Rainfall data is also a problem. High spatial variability is a characteristic of rainfall patterns in Lao PDR because of localized thunderstorms and variations in topographic relief, and the rain gauge network cannot provide reasonable representations of such patterns. Recording gauges are not used and therefore short duration intensities are not recorded. Inconsistencies encountered in the hydrological data are often attributable to problems with the hydrometric monitoring network.
Pro-rating by catchment area from measured sites has been used to generate streamflow estimates to overcome the paucity of data. Low flow values at several sites, mainly located in the north-western part of Lao where no gauging records were available, could have been over-estimated. Without any real data within the region, manipulation of generated series is needed to compensate but this would require detailed analysis for which there was no time. From an analysis of the small amount of available data it would appear that dry season flows in a number of the smaller catchments is overestimated. The hydropower output most affected by this would be firm energy. Dry
25 The estimate of flood flows will affect capital costs of dam and spillway structures while long-term streamflow estimate will affect production estimates. The outcomes of project evaluations are more sensitive to the latter. 26 Lahmeyer, Hydropower Development Plan for the Lao PDR, EU, 1998
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season generation is likely to be overstated. The PSDP project evaluations most at risk from possible small catchment effects would be:
• Houay Lamphan Gnai • Nam Sim • Nam Bak 2B – run-of-river option • Nam Ngieu • Nam Long
Two recommendations are made:
(i) The hydrology of small catchments in Lao PDR should be studied. If the streamflow estimation techniques used in the recent hydrology update are found to be inappropriate for small-catchments, the generation estimates of these projects, in particular dry season generation, should be reviewed and the project evaluations updated as required.
(ii) As an essential feature of any study into the feasibility of any of those projects listed above would be to establish a stream gauge at the dam site and to record flows for a minimum period of a full year.
6.3 Project Evaluation Methodology
6.3.1 Evaluation Overview
Most of the candidate projects have been evaluated before, either by GOL/EdL with assistance from development agencies, or by developers with a commercial interest in the site. The objectives of the evaluations undertaken under the PSDP are:
• to use a standardized approach to determining optimal technical layouts and dimensions to allow comparisons between projects on an even basis;
• to express in monetary values a project’s social and environmental impacts to remove subjectivity and overlap associated with multi- objective methodologies.
All candidate projects are evaluated and ranked using for the most part common methodologies and assumptions based on economic principles. Whether a project is likely to be publicly or privately financed is not reflected in the evaluation approach.
Projects were optimized, evaluated and selected on a free and unencumbered basis unless they were “committed”. The point at which the status of a project becomes “committed” is a matter for conjecture. As indicated in Table 6.4, a number of project sites are the subject of legally binding concession agreements but many are now inactive and it would be inappropriate for this to be held as the criterion of commitment. Strictly
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speaking, a project is not committed until loans are closed but for the purposes of the PSDP, a PPA and concession are taken as evidence of commitment. The signing of a concession does not necessarily fix the configuration of a project but the signing of a PPA constrains a project to the contracted conditions it specifies. Only Nam Theun 2 has a concession and PPA and in practical terms, the project has progressed to the point where to vary its contracted conditions would be to undermine the practical usefulness of system planning proposals. Section 10 of the report has been set aside to consider particular Nam Theun 2 optimization and evaluation issues, but the remainder of the PSDP work has been based on the project configuration defined in the Nam Theun 2 concession agreement and PPA.
Projects were evaluated using desktop techniques and existing data. Software was employed to facilitate rapid optimization, dimensioning and evaluation so that the candidate projects and their many variants can be assessed.
A catalogue of generation projects has been assembled from the outputs of the evaluations (refer Volume C), and project rankings were prepared according to economic criteria using methodologies described in the following sections.
Historically, projects have been designated as either export or domestic but, as projects supplying the national market increase in size and as private financing is introduced into domestic project development, so the convergence between the two categories increases. PSDP generation expansion programs were formulated assuming projects are available for either or both the domestic or export markets depending on their optimal role.
Projects are evaluated on a standalone basis and also, as appropriate, in a basin context or in conjunctive operation with other projects.
6.3.2 Evaluation Process
Projects are assessed so that so that they can be judged both in absolute terms and relative to each other. Evaluations are therefore conducted where possible using a common set of assumptions so that project performance measures are comparable notwithstanding the diversity in their technical, environmental, social, economic and financial characteristics.
Projects have been investigated to different degrees and the quality of the work varies greatly between them. The information used in the evaluations is therefore not of the same standard and to restore comparability of the evaluations the contingencies used in the EVALS costings have been chosen to reflect the reliability of input data.
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A two-stage procedure has been adopted as follows:
(i) Project Screening
A total of thirty hydropower and two thermal projects were evaluated with the objective of screening out less attractive projects. The early elimination of such projects allows more intensive focus on a shortlist of projects. The shortlist includes those projects that are more likely to be selected as least-cost generation increments in the domestic generation expansion plan, or as competitive candidates for supplying Lao PDR’s export markets.
(ii) Detailed Desktop Evaluation
Shortlisted projects were assessed more closely, though still at a desktop level. The scope of the evaluations was expanded primarily in the following respects:
• Conjunctive operation and project interdependencies were examined in more detail (refer Section 6.7);
• Social and environmental effects were analyzed in greater detail, with impacts expressed as monetary amounts to provide cash flows on an annual basis for internalizing in the economic (EVALS) and financial evaluations (refer Section 6.8);
• Financial performance was modeled to produce cash flow projections and financial performance measures to test bankability a number of bankability, revenue generation and tariff issues (refer Section 9).
6.3.3 Project Evaluation Software
Two of the candidate projects, Hongsa Lignite and Viengphouka, are coal- fired thermal plants; the remainder are hydropower projects. For thermal projects, the Lahmeyer software package “SCOPE” was used for calculating specific generation costs. The software and evaluation process is described in Section 6.6.
Project screening and ranking of hydropower projects were performed using project evaluation software, the primary tool being Lahmeyer’s “EVALS” package. Only through extensive use of this package was it possible to facilitate rapid, objective and comparable evaluations of all candidates.
The capability, functions, inputs and outputs of EVALS are depicted in Figure 6.1 and described below (refer also Annex 5). EVALS facilitates computerized evaluation of hydro projects by performing the following tasks:
• dimensioning of project elements, e.g. dam, powerhouse and spillway • inter-element optimization and co-ordination • reservoir operation and filling simulation • reservoir sedimentation analysis
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• cost estimation and bill of quantities • calculation of specific generation costs • probabilistic cash flow analysis
The program mimics the input of a multi-disciplinary team of specialists by translating field and economic data into project design and performance information. Once the project data has been assessed and entered into the database, EVALS rapidly produces results that would take months to produce manually.
Figure 6.1: Basic Structure of the EVALS Model
Field Data Unit Cost Data Project Definition Control Param's Hydrology, Geology, Labour, Materials, Fuel, Projects, Alternatives, I/O Control, Discount Rate, Topography, Hydraulics Construction Equipment Construction Elements Value Power / Energy, etc.
Dimensioning, Project dimensions Inter-Element Bill of quantities Optimization Equipment characteristics
Cost Estimate Detailed cost estimate Specific generation costs Reservoir Operation Data Base Planned : Project Evaluation Process Economic and Financial Analysis Drawings Risk Assessment Text Blocks for Report Results
Developed over the past 20 years, EVALS capabilities and accuracy have been proven on many hundreds of projects worldwide. The accuracy of the results obtained with EVALS depends on the quality of field data but experience has shown the software to reliably achieve results within 5% to 10% of the results obtained manually by study teams.
Principles for the development of EVALS have been the following:
• The program user ‘builds’ the project by selecting principal project elements from a library of standard designs. These are automatically adapted to the local topography, geology, hydrology, and other field data. A choice can be made from 12 different dam designs, 24 power- house types, 4 different kinds of spillway, etc.
• All project definition parameters are simple and do not require any calculation. Input data are largely physical parameters, e.g. elevations, horizontal lengths, widths, rock classes, permeability indices, distances to and voltages of nearest grid points.
• The program, within limits specified by the user, automatically carries out inter-element optimization.
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• Current country-specific cost information is entered and stored in an integrated database to be processed by the UCOST module into unit rates and plant and equipment costs (refer below).
• Element-specific percentages are added to cover the costs of non- measured items and contingencies.
• The program is intelligent and suggests cost saving design changes.
• Special cost and benefit items can be used to account for non- standard and external cost elements, such as resettlement costs, environmental mitigation costs, special excavation, landscaping, and developer’s risk premiums.
• EVALS can test the financial robustness of the project by rotating the initial year of streamflow sequences and examining the effect on reservoir filling and operation. This information is used for the probabilistic cashflow analysis to quantify the hydrological risks associated with the scheme.
The EVALS cost database was updated to reflect the 2003 cost structure in Lao PDR and world markets for the equipment, materials, labor and services required for medium and large hydropower projects.
A hydrological data period of 1966 - 2002 was uniformly adopted for all projects (refer Section 6.2).
In the EVALS analyses, a standard real annual discount rate of 10% was used to represent the opportunity cost of capital. In addition EVALS automatically generated information for discount rates of 5% and 15%. A discount rate of 5% would reflect the social preference rate, a rate of 10% would be equivalent to the economic discount rate for a country such as Lao PDR, while a rate of 15% would be indicative of a target rate of return of a private developer.
Software modules were used with EVALS for specific tasks as follows:
• “UCOST” processes country-specific cost information, builds up unit rates for civil works and stores them in an integrated cost database (refer Figure 6.2).
• “EVSYS” can be used to investigate the coordinated operation of two or more projects as an integrated unit. EVSYS quantifies the effectiveness of coordinated operation of a group of projects by comparing combined benefits and costs of different combinations of projects and operating strategies.
Project cash flows do not include development costs but transmission costs are included and IDC is internalized in the discounting procedure.
EVALS outputs describe a project’s capital cost, recurrent costs, disburement schedule, energy production data, and economic performance data. Energy production figures include several measures that indicate the capacity value
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of the output. Two of the key economic performance measures are average energy cost and weighted average cost of generation.
Figure 6.2: UCOST Build-up of Unit Costs for Civil Works
Weighted average cost of generation, in particular, is a useful single indicator of the economic value of a project to a power system and it was adopted as the primary screening and ranking parameter. Weighted energy is the sum of the energy production exceeded during 95% of all simulated months (primary energy) plus the product of the balance of production and a weighting factor between 0 and 1 (secondary energy). The value of the weighting factor depends on the power system. It is assumed that primary energy offsets new capacity and energy in the system, whereas secondary energy offsets energy only. Thus the weighting factor is equivalent to the ratio of the marginal variable energy cost to the total fixed plus variable energy cost, in this case in the order of 0.5. The calculation of weighted average cost of energy therefore credits secondary energy with only half the value of primary. In this way capacity and energy contributions are accounted for in a single value.
6.3.4 Project Cost Estimation
Project cost estimation is carried out by the EVALS/UCOST software in the case of hydropower plant and by SCOPE in the case of coal-fired thermal plant.
Hydropower projects, being predominantly civil in character, are more sensitive to local costs of construction plant, fuel, material, labor, etc. These costs are updated and entered into a cost database that is used by EVALS/UCOST to develop unit rates and combine them with calculated quantities to provide construction cost estimates.
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Costs of plant and equipment, on the other hand, are based on cost algorithms that apply plant and equipment costs derived from international tender prices to the particular specifications of the project. This would include hydraulic steelwork and electro-mechanical equipment.
All costs used by EVALS are economic costs for Lao PDR, i.e. costs that would be incurred in Lao PDR excluding taxes, royalties, duties, and refer to mid 2003 price levels. Cost estimates include the costs of transmission interconnections and also account for Interest During Construction through the present value discounting process.
6.4 Project Screening
6.4.1 Screening Process
The objective of performing an initial economic screening of candidate projects was to eliminate those that were unlikely to perform in either a domestic generation expansion or export role, thereby allowing closer attention to be paid to the more promising projects.
Screening was a three-step process as follows:
(i) A uniform analysis of the technical and economic attributes of candidate projects was conducted using EVALS to estimate and compare their performance. Inputs to EVALS for each candidate were to similar standards of scope and accuracy and included hydrology, cost data, topography, etc. Only some social and environmental impacts were internalized at the screening stage, these generally being those for which costs were readily available from previous planning studies. (For the evaluation and ranking of shortlisted projects, wider social and environmental impacts were accounted for through the application of the SESAMEE model – refer Section 6.8).
(ii) Projects that would be competitive in export markets (or might become so with favorable changes in these markets) were accepted onto the project shortlist. The principal criterion for selection on this basis was the weighted average cost of generation (¢/kWh). This pivotal concept is explained in Section 6.3.3. A value of 5.0 ¢/kWh was adopted to represent the upper bound of viability, this being equivalent to a higher wholesale financial tariff. Projects with weighted average generation costs greater than this would probably not succeed in the Thai or Vietnamese markets in the foreseeable future (assuming international standards of implementation).
(iii) A project with an economic weighted average cost of generation greater than 5.0 ¢/kWh might still be attractive if by virtue of its location, size and generating characteristics it might form part of a least-cost system expansion scenario for the Lao domestic market. These projects were also retained on the shortlist for further evaluation.
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6.4.2 Screening Results
The screening process reduces the number of candidate sites from 32 to the shortlist of 19 projects presented in Table 6.5. The screening values of weighted average cost of generation (with only limited environmental impacts internalized) are included.
Table 6.5: Project Shortlist based on Screening Results
Shortlisted Projects Screening Value of Weighted Average Cost of Generation 1 Nam Theun 2 1.4 ¢/kWh 2 Theun Hinboun Exp / Nam Theun 3 (3 options) 1.5 – 4.0 ¢/kWh 3 Nam Mo 2.5 ¢/kWh 4 Xe Kaman 3 2.6 ¢/kWh 5 Xe Kaman 1 2.8 ¢/kWh 6 Nam Sane 3 2.8 ¢/kWh 7 Nam Ngum 2 (and 2B) 3.0 ¢/kWh 8 Xe Kong 5 3.1 ¢/kWh 9 Nam Pot 3.4 ¢/kWh 10 Nam Ngum 3 (and 3B) 4.0 ¢/kWh 11 Nam Ngiep 1 4.0 ¢/kWh 12 Xe Kong 4 4.1 ¢/kWh 13 Nam Sim 4.7 ¢/kWh 14 Houay Lamphan Gnai 4.8 ¢/kWh 15 Nam Long 4.9 ¢/kWh 16 Nam Ngum 5 5.0 ¢/kWh 17 Nam Bak 2B 5.2 ¢/kWh 18 Thakho 1/ 5.2 ¢/kWh 19 Xe Katam 7.1 ¢/kWh 1/ Thakho generates anti-cyclically (strong dry season generation) and its weighted generation cost equivalent in the Lao system is about 2.6 ¢/kWh.
These projects are judged to be those able to best serve GOL’s export and domestic power generation objectives over the next ten to fifteen years, taking into account foreseeable developments in that period. In number, size, location and configuration, they are sufficient to satisfy the domestic and export objectives of GOL/EdL.
For reasons of balanced domestic system development it was intended that the shortlisted projects should have a reasonable geographic spread. Figure 6.3 gives the location of the projects and shows under-representation in Oudomxay, Phongsaly and Huaphan provinces.
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Figure 6.3: Location of Shortlisted Projects
No: Name
1 Theun-Hinboun Extension 2 Nam Theun 2 3 Xe Kaman 3 PHONSALY 4 Xe Kaman 1 5Xe Kong 4 29 6Xe Kong 5 LUANG NAMTHA 7Xe Katam 32 8 Xe Pian/Xe Namnoy BOKEO OUDOMXAY 9 Nam Kong 1 28 10 Nam Ngum 2 24 11 Nam Ngum 3 26 LUANG PRABANG 12 Nam Theun 1 31 13 Xeset 2 14 Xeset 3 16 XIENGKHUANG 15 Nam Ngiep 1 11 23 16 Nam Ngum 5 18 10 27 17 15 33 30 12 PAKXAN 1 VIENTIANE 2
THAKHEK
No: Name
17 Nam Mo SAVANNAKHET 25 18 Nam Pot 19 Houay Lamphan Gnai 20 Thakho 21 Tad Samphamit SARAVANE 22 Don Sahong 6 23 Nam Ngieu 5 SEKONG 24 Nam Fa 13 25 Xepon 3 PAKSE 14 15 3 26 Nam Beng 7 4 27 Nam Sane 3 8 ATTAPEU 28 Nam Sim 9 29 Nam Long 30 Nam Bak 2B 31 Hongsa Lignite 20 32 Viengphouka 22 21 33 Nam Ngum 1 Extension
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6.5 Evaluation of Hydropower Projects
6.5.1 Overview of Evaluation Methodology
All but two of the candidate projects and all of the shortlisted projects are hydropower developments. Optimal project configurations of hydropower projects were developed using EVALS, which evaluated alternative layouts, dam heights and Installed Capacity Factors (ICFs) 27 according to assumptions about the project and its circumstances. EVALS dimensioned project elements, simulated and optimized reservoir operation, estimated costs of construction and operation, and calculated key outputs including capital cost, annual firm and non-firm energy, and cost of energy production. Social and environmental impacts were evaluated in monetary terms and included in the analysis.
Developing optimal project configurations for evaluation and ranking was not straightforward. The optimal configuration of a hydropower project depends on its role within a system and its interactions with other projects. The TOR requires a methodology that accommodates system expansion scenarios and project interactions as follows:
• domestic generation expansion sequences, alternatively with and without domestic off-take allocations from IPP export projects;
• domestic generation sequences assuming a project is alternatively constrained and unconstrained by the power system it supplies;
• operation of a project, alternatively on a standalone basis or in conjunction with other projects;
• operation of a project, alternatively with and without hydraulic and environmental interactions with other projects (diversion, upstream regulation, water quality, etc.).
The permutations created by these requirements are unmanageably numerous and a practical approach was devised to satisfy the intent of the TOR. This entailed the evaluation of alternative project configurations, designed to represent their optimal roles serving, firstly, the export market and, secondly, the domestic market.
(i) Export Market
All projects were optimized and evaluated with an ICF of 1.75. This is equivalent to a plant factor of about 57% and was adopted for the following reasons:
27 Installed Capacity Factor is the ratio of the hydraulic capacity of a power conduits and turbines to the long term mean flow of the river.
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• It is a reasonable representation of normal plant factors for hydropower projects in the region and provides a sensible basis for comparing and ranking project sites;
• It is equivalent to the 16 hours a day, 6 days a week operating mode presently required by EGAT for IPP projects supplying the Thai grid.
Although a number of projects are clearly unsuited to an export role, all projects were evaluated at an ICF of 1.75 (unless they were run-of- river, e.g. Thakho). This established a common basis from which project comparisons could be made for screening and ranking purposes.
(ii) Domestic Market
Those projects that are included in any least-cost domestic power system expansion scenarios were also optimized and evaluated at the ICFs corresponding to their optimal ICF for the system and for the relevant scenario. The EVALS outputs computed on this basis provided inputs for the power system expansion analyses (refer Section 7).
The optimal ICFs for a project’s system role varied widely in some cases from the layouts computed based on an ICF of 1.75.
6.5.2 Performance of Hydropower Projects
The results of the hydropower screening evaluations are broadly summarized in Table 6.6. Table 6.6 groups projects according to whether or not they were shortlisted by the screening process and the results are not strictly comparable between categories. Evaluations of shortlisted projects were more detailed and internalized a wider spectrum of project impacts.
Project alternatives and project interactions were studied and the results are included in Table 6.6.
Some notable projects were screened out and their omissions are briefly discussed below:
• Xe Pian-Xe Namnoy was a frontline IPP project in the nineties when some preliminary construction works were commenced. This ceased with the onset of the Crisis. The project economics were not helped by EGAT’s decision to receive power through Mukdahan. The screening value of weighted average cost of generation of 5.60 ¢/kWh puts it behind other candidate projects but with favorable changes in market conditions, the completion of the regional 500 kV collector substation, and a competitive capital cost, it could still be viable.
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• Nam Theun 1 was screened because the weighted average cost of generation of 5.68 ¢/kWh is above the cut-off value. The development of the Theun Hinboun Expansion proposals will further increase this figure by diverting more water from the Nam Theun basin upstream of the project.
• The Xeset 2 and 3 projects are discussed in Section 6.7.5.
• The Hongsa and Viengphouka thermal projects are discussed in Section 6.6.
6.6 Evaluation of Thermal Projects
6.6.1 Evaluation Methodology
Two thermal projects are included among the candidate projects listed in the TOR - the Hongsa Lignite and the Viengphouka projects.
An economic evaluation of Hongsa and Viengphouka was conducted using the Lahmeyer “SCOPE” software. Parameters describing the quality of local coal and cost of extraction were entered into SCOPE, which draws on its database of standard industry costs to compute capital and recurrent cost disbursements, plant availability, heat rate and heat rate degradation, net energy production and emissions.
The evaluations assume that both projects include emission control equipment such as precipitators and Flue Gas Desulferizing (FGD) units, as required to meet international air emission standards and incorporate associated capital and recurrent costs into the evaluation.
The SCOPE outputs provided inputs to a spreadsheet calculation of economic values of average and weighted average tariff.
6.6.2 Performance of Thermal Projects
The assumed values of inputs and calculated performance characteristics of the thermal projects are presented in Table 6.7. Evaluation results are listed with competing hydropower projects in Table 6.6, although the results are not strictly comparable and the evaluation methodologies were different.
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Table 6.6: Estimated Cost of Generation of Candidate Projects
Project MW Average Weighted Av Comments Gen Cost Gen Cost
Projects promoted to Project Shortlist at screening stage. Generation costs are based A. SHORTLISTED PROJECTS on broad internalizing of social and environmental effects (SESAMEE). 1 Nam Theun 2 1074 1.39 1.51 PPA configuration Nam Theun 2 681 1.17 1.52 original installed capacity 2 Theun Hinboun Expansion Costs based on incremental energy, i.e. energy over and above that already generated by the existing facility. NT2 is assumed - if no NT2, incremental generation costs are less.) THB 315 105 1.51 2.92 add 1 additional unit at Theun Hinboun (THB) THB 420 210 3.91 7.73 add 2 additional units at THB THB 210+NT3 dam 0 1.26 1.30 add Nam Theun 3 (NT3) dam (no PS) THB 315+NT3 dam 105 1.22 1.26 add NT3 dam + 1 unit at THB THB 420+NT3 dam 210 1.28 1.31 add NT3 dam + 2 units at THB THB 210+NT3 PS 195 1.54 1.61 add NT3 PS (195 MW) THB 315+NT3 PS 300 1.49 1.58 add NT3 PS (195 MW) + 1 unit at THB THB 420+NT3 PS 405 1.45 1.56 add NT3 PS (195 MW) + 2 units at THB 3 Nam Mo 125 2.54 2.57 4 Xe Kaman 3 250 2.57 2.69 5 Xe Kaman 1 470 2.79 2.85 Xe Kaman 1 470 2.79 2.87 w/- upstream regulation from Xe Kaman 3 Xe Kaman 1 470 2.79 2.80 conjunctive operation with Xe Kaman 3 6 Nam Sane 3 60 2.77 2.82 7 Nam Ngum 2 460 2.87 3.07 Nam Ngum 2 460 2.78 2.96 w/- upstream regulation from Nam Ngum 3 Nam Ngum 2 460 2.81 3.03 w/- upstream regulation from Nam Ngum 5 Nam Ngum 2 460 2.76 3.12 w/- upstream regulation from NN3 & NN5 Nam Ngum 2B 195 3.08 5.26 w/- smaller dam to reduce impacts
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Project MW Average Weighted Av Comments Gen Cost Gen Cost Nam Ngum 2B 195 3.21 5.22 w/- smaller dam plus upstream regulation from Nam Ngum 3 Nam Ngum 2B 195 3.58 6.14 w/- smaller dam plus upstream regulation from Nam Ngum 5 Nam Ngum 2B 195 3.28 4.23 w/- smaller dam plus upstream regulation from Nam Ngum 3 & Nam Ngum 5 8 Se Kong 5 410 2.88 3.15 9 H. Lamphan Gnai 55 3.48 3.49 10 Nam Pot 20 3.51 3.53 11 Nam Ngum 3 530 3.67 4.07 Nam Ngum 3 530 3.61 3.89 w/- upstream regulation from Nam Ngum 5 Nam Ngum 3B 690 3.60 3.98 w/- PS shifted downstream Nam Ngum 3B 690 3.51 3.85 w/- downstream PS & Nam Ngum 5 regulation 12 Nam Ngiep 1 330 3.59 4.06 Nam Ngiep re-reg pond 40 4.13 4.75 additional 40 MW at re-regulating dam 13 Se Kong 4 490 3.80 4.16 Se Kong 4 490 3.70 3.85 w/- upstream regulation from Se Kong 5 Se Kong 4 490 3.71 3.82 conjunctive operation with Se Kong 5 14 Nam Sim 15 3.08 4.80 15 Nam Long 1 20 4.53 4.90 16 Nam Ngum 5 75 5.01 5.21 17 Thakho 60 2.63 5.26 Mainstream project. Flexibility in choice of capacity. Constrained by environmental issues. Anti-cyclical generation with equivalent weighted generation cost of about 2.6 ¢/kWh. 18 Nam Bak 2 85 5.36 5.54 Storage project configuration (FSL 1030) 19 Xe Katam 20 4.10 7.09 Minimum release of 10 m3/s for falls
B. SCREENED CANDIDATES Projects eliminated at screening stage. Generation costs are based on limited inclusion of social and environmental effects.
20 Nam Kong 1 150 4.12 5.17 21 Xe Pon 3 65 5.07 5.18
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Project MW Average Weighted Av Comments Gen Cost Gen Cost 22 X.Pian-X.Namnoy 235 5.65 5.60 23 Viengphouka Coal 50 4.03 4.85 Base load thermal plant (refer discussion in Section 6.6) 24 Nam Theun 1F 400 4.90 7.50 w/- THB (210 MW) & Nam Theun 2 (1074 MW) Nam Theun 1 600 3.23 5.68 w/- Theun Hinboun (315 MW) upstream Nam Theun 1 600 5.37 8.15 w/- Theun Hinboun (315 MW), NT3 storage & Nam Theun 2 (1074 MW) 25 Hongsa Lignite 300 4.39 5.27 Base load thermal plant (refer discussion in Section 6.6) 26 Nam Ngeui 30 3.76 6.19 27 Don Sahong 55 3.24 6.52 Mainstream project 28 Nam Beng 35 6.01 6.56 29 Tad Somphamit 55 3.83 7.66 30 Xeset 3 Without Houay Ho. Refer Table 4.8 for analysis of conjunctive operation. XS3+XS2+XS1+HH 16 5.4 8.3 Including incremental XS1 + XS2 benefits. Output is predominately wet season 31 Xeset 2 Without Houay Ho. Refer Table 4.8 for analysis of conjunctive operation. XS2 + XS1 76 5.8 8.5 including incremental XS1 benefits excluding Houay Tapong diversion XS2+XS1+TP 76 5.6 8.5 including incremental XS1 benefits with Houay Tapong diversion (2m3/s riparian release) 32 Nam Fa (Nam Pha) 70 10.60 10.89 33 Nam Ngum 1 Ext. 40 4.70 n/a Incremental output is mostly off-peak, worth about 2 ¢/kWh. Project is therefore discarded.
C. EXCLUDED PROJECTS Projects excluded from screening and ranking for reasons given below
34 Lower Xe Bang Fai n/a n/a No project identified due to flat terrain and lack of suitable dam site
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Table 6.7: Parameters and Performance of Thermal Projects
Hongsa Viengphouka Market Export Domestic Installed Capacity (MW) 1,400 50 Fuel Cost ($/tonne) 16 22 Fuel Heating Value (HHV) (MJ / tonne) 9.1 19.1 Fuel Consumption (mill tones p.a.) 11.00 0.306 Gross Heat Rate (LHV) (kJ / kWh) 9,500 15,000 Plant Factor (%) 82% 85% Gross energy production (GWh p.a.) 9,980 372 Station Own Use (%) 7.4% 7.4% Specific Investment Cost ($ / kW) 950 804
Average cost of energy (¢/kWh) 4.39 4.03 Weighted average cost of energy (¢/kWh) 5.27 4.83
(i) Hongsa Lignite Project
The proposed Hongsa plant is a greenfield mine-mouth steam coal development located on a lignite deposit in northern Lao PDR. Power developments at the Hongsa deposit have been variously scoped with installed capacities ranging between 300 and 1400 MW.
A concession to develop the field was given to Thai-Lao Lignite in the nineties and a PPA with EGAT was initialed in 1996 for the delivery of about 720 MW of base load power at a levelized tariff of 5.7 ¢/kWh. With the onset of the Asian Economic Crisis, the developer was unable to obtain finance and the tariff agreement lapsed. With the drop in the avoided cost in the EGAT system (Nam Theun 2 primary energy was more recently negotiated at a levelized value of around 4.7 ¢/kWh), the project has been unable to obtain a bankable tariff. The market has recently moved in a more favorable direction. The price of oil has risen with the instability in the Middle East and also EGAT is believed to be considering separate classification of thermal and hydropower projects for tariff negotiations to promote an optimal plant mix in the Thai system. These developments could improve Hongsa’s prospects.
The lignite at Hongsa is of poor quality and economies of scale are needed to reduce generation costs. An economic development at Hongsa would be too large for domestic supply alone and the project is therefore conceived as an export project. It was modeled under the PSDP as a 1400 MW development. The investment costs used in the modeling for the expanded development took account of the cheaper cost per kW of large identical units, lower transmission costs per unit, and more efficient use of station common facilities such as access roads, ash disposal, water supply, offices and workshops, firefighting infrastructure, mine development costs, etc.
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The economic weighted average cost of generation was calculated at 5.27 ¢/kWh. This suggests that the financial tariff needed for viability is still higher than EGAT’s avoided cost of base load generation and that a shift in the economics of power generation would therefore be needed for it to be attractive to EGAT.
(ii) Viengphouka Project
Like Hongsa, the proposed 50 MW Viengphouka plant is also conceived as a mine-mouth steam coal development. Although the power block would be new, it is understood that a small-scale mining operation is already in progress at the site
At 50 MW, the Viengphouka proposal is small for a coal plant and lacks the economies of scale important for such plants. However, the properties of the coal it would burn are superior to those of the Hongsa deposit. If Viengphouka were to be constructed to international standards, it would be uneconomic and Chinese prices were used to improve the viability of the project.28
The economic weighted average cost of generation was estimated to be 4.83 ¢/kWh, based on a plant factor in excess of 80%. This result is not directly comparable with the calculated weighted average costs of generation for competing hydropower plants as reported in Table 6.6. The Viengpoukha plant was evaluated as a domestic project operating within the EdL grid as a public project. A thermal project operating within a hydropower system will be lower in the dispatch order and will achieve low levels of utilization during wetter than average years to minimize spill from EdL’s reservoirs. This increases the cost of energy from the plant over its lifetime. Power from the project would therefore be more expensive compared with hydropower alternatives and for this reason the project was not shortlisted.
Despite its absence from the shortlist, the economics of the project are reasonable, its location is favorable for supplying the northern provinces and the alternatives there are few. A significant source of generation in the north of the country could reduce transmission losses, provide voltage support, improve supply security, and stabilize the long 115 kV transmission line. Viengphouka would also add diversity to EdL’s plant mix that could prove useful in drought years, although it is probable that drought relief would achieved more cheaply through imports from the predominantly thermal EGAT system.29 Detailed system studies are needed to determine whether Viengpoukha’s system advantages would compensate for its higher generation cost.
28 Chinese prices obtained were approximately 60% of international western cost levels. Plant availability for the cheaper units would probably be lower and O&M higher, but these were assumed at international levels. 29 EdL currently relies on imports from EGAT for back-up during dry years. While this has been cost-effective to date, peak demand in Lao PDR is growing rapidly and there may come a time when EGAT is unwilling or unable to provide back-up generation during times of drought when the contribution from its own hydropower projects (and hydropower imports) may be curtailed.
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6.6.3 Comparison with Gas-fired Plant
The generation costs of Hongsa and Viengphouks were compared with equivalent gas-fired generation using a gas price of US$ 2.9 per GJ based on the current price in Thailand. For the purposes of the comparison, three fuel prices were tested for Hongsa, being 10, 15 and 20 US$ per tonne (equivalent to 0.83, 1.25 and 1.66 US$/GJ).
Assumed characteristics of the reference plant are listed in Table 6.8. Graphs comparing their costs of generation with Hongsa and Viengphouka for a range of plant factors is provided in Figures 6.4 and 6.5.
Table 6.8: Characteristics of Gas-Fired Reference Plant
Power Plant Unit Combined Gas Turbine Cycle Installed Capacity MW 620 215 Specific Cost US$/kW 560 300 Construction Period Years 3 2 Heat Rate (@ 80% plf) kJ/kWh 7500 13700 Availability (%) 80 ** 86
The comparisons indicate that Hongsa may be feasible at the lower lignite price. However, to the Hongsa price should be added a further 0.5 USc/kWh for wheeling in the Thai system. Combined cycle and gas turbine plant by comparison can be built much closer to demand centers.
If emission charges are considered, Hongsa is not feasible compared with gas-fired generation.
The Viengphouka plant, despite assuming Chinese procurement prices, cannot compete directly with any form of gas-fired generation, especially if emission charges are considered. However, in a system context it could become feasible.
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Figure 6.4: Generation Costs – Thermal Plant without Emission Costs Generation Cost for Thermal Plant Viengphouka and Hongsa vs Gas-Fired Generation
Specific Generation Cost (USc/kWh) 10% discount rate 6
Viengphouka Hong Sa - Lignite 5 1.66 US$/GJ 1.25 US$/GJ 0.83 US$/GJ
4 Gas Turbine
3
Gas-Fired Combined Cycle 2 40 50 60 70 80 90 100 Degree of Utilization (%) Lahmeyer - Maunsell
Figure 6.5: Generation Costs – Thermal Plant with Emission Costs Generation Cost for Thermal Plant Viengphouka and Hongsa vs Gas-Fired Generation
Specific Generation Cost (USc/kWh) 10% discount rate 6 Viengphouka
5
Gas Turbine
4 Hong Sa - Lignite 1.66 US$/GJ Emission Penalties 1.25 US$/GJ 0.83 US$/GJ 3 CO2 5 US$/ton SO2 300 US$/ton NOx 100 US$/ton Dust 100 US$/ton Gas-Fired Combined Cycle 2 40 50 60 70 80 90 100 Degree of Utilization (%) Lahmeyer - Maunsell
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6.7 Project Interactions
6.7.1 Types of Interaction
Project interactions can take different forms. They can involve:
(i) Conjunctive Operation
Within the Lao system there are opportunities to increase the benefits of individual power projects by operating them in combination with others. Unless the cooperating projects are under the same ownership and operating structure, the mobilization of conjunctive synergies will involve contractual issues and third party risks that could dilute or stifle potential benefits. Conjunctive operation of projects is investigated only in the technical sense under the PSDP and the contractual issues have been set aside. However, where existing contracts are in place, as on the case of the Xeset projects, the sensitivity of the conjunctive arrangements to benefit sharing has been investigated.
The potential gains from actively coordinating the operation of two or more projects were investigated using the EVSYS software module. EVSYS optimizes and quantifies the effectiveness of coordinated operation of a group of projects by comparing incremental benefits and costs of different project combinations and operating strategies.
Within the present Lao system projects having greater potential for conjunctive synergy tend to be clustered within the same basins or geographical proximity. With further extension and strengthening of the 115 kV transmission systems and development of the 500 kV system, the potential for inter-basin cooperation will increase but this was not investigated. Tandem operation was investigated for existing and planned storage projects with existing and planned run-of-river plants with complementary characteristics. The results of simulations are summarized in Table 6.6 and specific cases are explored in more detail later in this section.
(ii) Hydraulic Interactions
The relationship of one project to another within intra and inter basin cascades may involve hydraulic interactions through the alteration of natural river flows by one project to the benefit or detriment of others (e.g. upstream regulation, diversion of flows into or from a basin).
Hydraulic interdependencies between projects were investigated. There are a number of projects located primarily in the Nam Ngum, Nam Theun and Xe Kong basins that derive additional generation from river regulation by an upstream project, or projects within the same basin. Such interactions between candidate projects were explored using EVALS and the results are reported in Table 6.6.
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There are also instances where an inter-basin project affects the output of other projects, either by reducing the flows available to projects downstream of its dam, or by increasing the flows available to projects downstream of its tailrace. The three areas where such inter- basin proposals have been proposed are (i) the Nam Theun basin where Theun Hinboun and Nam Theun 2 divert water from the Nam Theun; (ii) the Nam Sane and Nam Ngiep basins where projects diverting from one basin to another have been identified in the past; and (iii) the Nam Bak where Nam Bak 2B would divert water to the Nam Xan.
(iii) Environmental Interactions
Environmental interactions between projects can affect economic performance. Adverse environmental effects of one project can affect the operation and maintenance of another, directly or indirectly. For instance, the construction of the Nam Ngum 2 reservoir would buffer the impacts of poor water quality from Nam Ngum 3 releases, allowing wider discretion in the way the project is operated.
Environmental interactions were taken into account by identifying the principal effects and quantifying them using the SESAMEE model. The environmental cash flows are incorporated into the economic evaluations of projects and in some cases have resulted in an adjustment in a project’s ranking.
(iv) Project Extensions
Project extensions involve interactions between an existing project and proposed expansions of that project. An extension project may involve augmentation of a project’s installed capacity, generation flows, storage, upstream regulation, etc. in a way that increases or otherwise modifies its generation characteristics.
All but two of the projects listed in the TOR are greenfield developments, the exceptions being Nam Ngum 1 Extension and Theun Hinboun Expansion (Nam Theun 3). Greenfield hydropower projects are proving difficult to finance either publicly or privately, but plant refurbishment and extension projects continue to enjoy considerable support from lenders because the project has an existing cash flow, incremental capital requirements are more manageable, environmental impacts are usually small, and risks are better understood.
Interactions between projects of potential significance in the development of the domestic or export power development programs are explored in more detail in the following sections.
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6.7.2 Nam Ngum Basin Projects
The Nam Ngum projects include Nam Ngum 2, Nam Ngum 3 and Nam Ngum 5. Simulations show that the regulation provided to Nam Ngum 2 and Nam Ngum 3 by projects upstream has little effect on their weighted costs of generation, mainly because of the sufficiency of their own reservoirs, but also because the small regulation benefit is negated in part or whole by additional evaporation losses from the upstream reservoirs.
Something of a stalemate prevails in the Nam Ngum basin with both Nam Ngum 2 and Nam Ngum 3 having difficulty obtaining finance. In the case of Nam Ngum 2, challenging environmental and social problems present an obstacle, while for Nam Ngum 3 it is the marginal economics of the project. A solution identified by Electrowatt-Ekono (Power Sector Strategy Study, 2002) involves the following:
• lower the Nam Ngum 2 Full Supply Level to about 285 masl to reduce resettlement and other impacts (Nam Ngum 2B); and
• move the Nam Ngum 3 powerhouse downstream to take advantage of the smaller Nam Ngum 2B reservoir and the steep gradient of the river to capture additional head (Nam Ngum 3B). This boosts the project’s financial performance.
The Nam Ngum 2B configuration, with its smaller reservoir, would be dependent on the Nam Ngum 3 for much of its seasonal regulation. Without Nam Ngum 3, Nam Ngum 2 B would not be viable in the present market and, consequently, Nam Ngum 3 should be developed first.
The Electrowatt proposal would open the way for one or both of the Nam Ngum projects to move forward. It would also assist the Nam Ngiep Project. Export projects in the Nam Ngum and Nam Ngiep basins are to interconnect through the proposed 500 kV transmission line to Ban Na Bong and the financing of this line depends on the sufficiency of projected wheeling revenues. As long as there is deadlock in the Nam Ngum basin, finance for the 500 kV line will be difficult to obtain.
Environmental interactions also need to be considered in the planning of the Nam Ngum projects. In the absence of Nam Ngum 2, quality water impacts of Nam Ngum 3 on the Nam Ngum 1 reservoir must be mitigated. If Nam Ngum 2 is built, the mitigation problem is shifted to the lower project. Another consideration is the effect on the Nam Ngum 1 fisheries of building both Nam Ngum 2 and Nam Bak 2B.
6.7.3 Nam Theun Basin Projects
Project interactions within the Nam Theun basin were investigated and the results are summarized in Table 6.6.
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Various expansion scenarios for Theun Hinboun were modeled with and without Nam Theun 2, and with and without a regulating storage on the Nam Gnouang (Nam Theun 3). These simulations indicate several attractive alternatives.
The diversion of water by Nam Theun 2 to the Xe Bang Fai potentially detracts from the performance of the Theun Hinboun and Nam Theun 1 projects. Similarly, increased diversion to the Hinboun by an expanded Theun Hinboun (including a storage on the Nam Gnouang) reduces generation flows at Nam Theun 1 and further detracts from its economic performance. A more detailed description of the Theun Hinboun Expansion project is provided in Section 6.7.7.
6.7.4 Xe Kaman Basin Projects
Two projects in the Xe Kaman basin, i.e. Xe Kaman 1 and Xe Kaman 3, were investigated and the results are presented in Table 6.6. Both perform well but the downstream Xe Kaman 1 derives little additional benefit from interaction with its upstream counterpart. Again, this is primarily because of the full regulation provided by Xe Kaman 1’s large reservoir.
A Vietnamese consortium including Song Da Construction Company and EVN is developing Xe Kaman 3. The newly completed feasibility study confirms the project’s viability and the project is listed in EVN’s PDP with a 2010 COD.
Xe Kaman 3 could also play an important role in supplying EdL. The Southern Grid may not connect to the Central Grid for some years and the Xe Kaman 3 project offers EdL a cost-effective source of generation for the grid without capital commitment. The PPA conditions and domestic off-take entitlements from the project have not yet been determined and an off-take of up to 20% of the annual output (perhaps less during the first years of operation) has been assumed in power system expansion scenarios investigated in Section 7. A tariff of 2.5 ¢/kWh for wet season energy and 5.0 ¢/kWh in the dry season is quoted in the feasibility study. The price would normally average out at about 3.25 ¢/kWh over the year, but as the wet season generation requirements in the Southern Grid are less acute, off-take from Xe Kaman 3 in the dry season could be higher. A price of 4.0 ¢/kWh has therefore been assumed for the purpose of system expansion modeling.
6.7.5 Xeset Basin Projects
The existing Southern Grid power plants, Xeset 1 (45 MW) and Selabam (5 MW) are both run-of-river with strongly seasonal generation patterns. The proposed Xeset 2 and 3 projects, operating with Xeset 1 as an optimized basin development, would merely increase wet season surpluses while doing little to address the dry season deficits. A source of dry season generation is a priority in the south.
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Early operation of the Houay Ho project suggests that its reservoir is oversized for the its hydrology.30 This surplus capacity could be used to regulate and firm the output of other projects with little overall effect on Houay Ho’s production.
Conjunctive operation of Houay Ho with the Xeset projects has been proposed and simulations were carried out to test this arrangement. Xeset 1, as an existing project, provides a means of capturing the unused regulation benefit of the Houay Ho reservoir without any new capital outlay and it was therefore given priority in the modeling sequence. The results show that conjunctive operation of Xeset 1 and Houay Ho is attractive, with the Xeset 1 output being almost entirely firmed (refer Figure 6.6). When Xeset 2 is added to the Houay Ho / Xeset 1 combination, the incremental gains over the standalone operation of these projects were smaller, though significant, indicating some reserve capacity remained in the Houay Ho reservoir after firming Xeset 1 (refer Figure 6.7). However, there would be no firming of Xeset 3, should that project be added later. In summary, the simulations confirm the technical advantages of operating the Xeset projects conjunctively with Houay Ho.
The simulations conducted under the PSDP also explored the question of allocation of conjuctive operation benefits among the parties and its effect on the viability of Xeset 2 from an EdL perspective. The results of the simulations are presented in Table 6.9 and they show that the Xeset 2 would reduce to a marginal proposition for EdL if about 20% of the energy processed through conjunctive operation were traded away for the access rights to the Houay Ho reservoir.
Three parties would be involved in this arrangement: EdL as owner of Xeset, HHPC (and it lenders) as owner of Houay Ho, and EGAT as the power purchaser and dispatcher of Houay Ho. At the time of writing, the situation is:
• The parties have agreed in principle to cooperate and that negotiations on the contractual details have commenced. It is understood that the discussions will involve not only access to the Houay Ho reservoir, but also the right to inject Xeset 2 output into the Houay Ho transmission line and sell it to EGAT under an amended Houay Ho PPA.
• Financing and construction agreements for the Xeset 2 project have been executed but do not come into force until satisfaction of conditions precedent related to finalization of agreement between EdL, EGAT and HHPC.
30 There is a divergence in views on the contention that the Houay Ho reservoir is oversized. Due diligence studies conducted during the recent sale and refinancing of the project are said to support the argument but it is disputed in the PSSS (Electrowatt, 2002). One of the issues that would need to be resolved in the conjunctive operation arrangements between EdL, EGAT and HHPC is responsibility for hydrological risk in the Houay Ho basin.
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Figure 6.6: EVSYS Conjunctive Operation of Houay Ho and Xeset 1
Figure 6.7: Conjunctive Operation of Houay Ho with Xeset 1 and Xeset 2
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Table 6.9: Xeset Projects – with and without Conjuntive Operation with Houay Ho Incremental Generation Cost Combination PV Installed Energy Primary Weighted Total Benefit 50% Benefit Sharing 20% Benefit Sharing Incr. Cost Capacity Generation Energy Energy Average Weighted Average Weighted Average Weighted (mUS$) (MW) (GWh/a) (GWh/a) (GWh/a) (c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh) HH alone 0 150 490 490 490 XS1 alone 0 45 154 25 89.5 Existing 0 195 644 616 630
Without Tandem Operation with Houay Ho:
XS1 0 45 154 25 89.5 XS1+XS2 118 115 360 100 230 5.78 8.47 XS!+XS2TP 126 115 379 99 239 5.65 8.50 XS1+XS2TP+X3 157 130 448 113 280.5 5.38 8.29
With Tandem Operation with Houay Ho:
HH alone 0 150 490 490 490
XS1 0 45 155 137 146 XS1+XS2 118 115 358 347 352.5 5.83 4.52 11.66 9.05 7.29 5.65 XS!+XS2TP 126 115 377 383 380 5.70 4.37 11.39 8.75 7.12 5.47 XS1+XS2TP+X3 157 130 426 370 398 5.82 5.13 11.64 10.26 7.27 6.41
KEY: HH = Houay Ho; XS1 = Xeset 1; XS2 = Xeset 2; X3 = Xeset 3; TP = Houay Tapong
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The Xeset 2 project therefore poses a dilemma for the PSDP Consultant in its planning of the Southern Grid:
1. The project has considerable momentum behind it, including financing commitments, but must satisfy key conditions before the project and loan agreements come into force and the project becomes “committed” in a contractual sense;
2. The viability of the project depends on the outcome of EdL’s discussions with EGAT and HHPC and, in particular, on the positions of the parties with respect to the allocation of the benefits of conjunctive operation.31
3. EdL is apparently negotiating with EGAT on the basis of exporting the majority of the plant’s output to Thailand. It is therefore unclear at this stage what role the project would play in meeting the generation needs of the Southern Grid.
As a contractual right to the Houay Ho reservoir has not yet been established for Xeset 2, only intra-basin interactions were taken into account in the uniform PSDP project screening and ranking exercise. On this basis its performance did not justify a shortlisting. However, given the reasonable possibility that agreements with EGAT and HHPC are concluded and the project proceeds as an integral part of the Houay Ho operation, it has been treated as a special case and has been studied separately, both in a basin context as reported in this Section and in a system context (refer Section 7.4).
6.7.6 Nam Ngum 1 Extension Project
With the completion in the nineties of the diversion of two rivers into the Nam Ngum reservoir, i.e. Nam Song and Nam Leuk, the long term mean generation flows at Nam Ngum 1 have increased. A study of options to augment the installed capacity of the power station was carried out about 10 years ago but concluded that the economics of adding a new unit were marginal.32 This suggested that the reservoir was optimally sized for the new inflows and existing installed capacity.
The modeling undertaken under the PSDP does not challenge this conclusion. A system expansion scenario with a 40 MW augmentation at Nam Ngum 1 was simulated assuming interconnection of the Central Grid. The scenario was not the least-cost development path because IPP off-take from the Nam Theun 2 and Theun Hinboun Expansion projects provides sufficient power for the system and results in the Nam Ngum output being exported. Exports to EGAT are priced as non-firm energy, well under the specific weighted cost of generation. This situation prevails for a period of about 5 years by which time demand in the grid has grown enough to
31 If EGAT is already using the Houay Ho reservoir for firming its own generation (e.g. Pak Mun, Xeset 1 imports), it may seek consideration for yielding the right to EdL. 32 Lahmeyer/Worley “Nam Ngum 1 Hydropower Station Extension, Feasibility and Engineering Study”, main Report, World Bank, 1995.
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accommodate Nam Ngiep 1, a project preferred to Nam Ngum Extension because of its lower weighted generation cost.
Were the Theun Hinboun Expansion not to proceed, the capacity benefit of Nam Ngum Extension would be of greater value to the system and under such circumstances it might form part of a least-cost scenario. This and other possible outcomes and project alternatives were not modeled. A more detailed appraisal of the project may be justified for a couple of reasons: firstly, an extension of the existing Nam Ngum power station would have a shorter construction time than an equivalent greenfield project (provided plant procurement could be fast-tracked); secondly, the project has characteristics that would make it attractive to multilateral and bilateral agencies and may be more readily financeable under concessional terms.
The construction of upstream developments would not help the viability of an expansion of capacity at Nam Ngum 1. The Nam Ngum 1 reservoir already provides full seasonal regulation and any additional regulation benefit would be negated by evaporation losses from the upstream storages.
The evaluation of Nam Ngum 1 extension options also indicates that reservoir operation is sub-optimal for power generation, although it is understood that this is because the reservoir also serves a flood mitigation function. The PSDP simulations did not consider any multipurpose uses of Nam Ngum reservoir and are therefore of limited use to EdL who faces conflicting pressures in determining its reservoir operation policies and practices. The new Nam Ngum Watershed Management Study (ADB) provides an opportunity to reconcile these contradictory pressures.
6.7.7 Theun Hinboun Expansion Project
A range of options for increasing generation at Theun Hinboun were examined, each involving some or all of the following:
• Addition of a 3rd turbine (105 MW) at Theun Hinboun power station;
• Addition of 3rd and 4th units (2 x 105 MW) at Theun Hinboun power station with duplication of waterways;
• Construction of a regulating dam (Nam Theun 3) on the Nam Gnouang without generation;
• Construction of a regulating dam (Nam Theun 3) on the Nam Gnouang with a 195 MW power station.
Eight combinations were evaluated, each being optimized for the corresponding total installed capacity. The results are presented in Table 6.10.
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Table 6.10: Theun Hinboun Expansion – Evaluation of Options
Incremental Works Additional Average Weighted Capacity Generation Generation Cost Cost (MW) (¢/kWh) (¢/kWh) 1 1 additional unit at THB PS 105 1.51 2.92 2 2 additional units at THB PS 210 3.91 7.73 3 NT3 dam with no PS 0 1.26 1.30 4 NT3 dam + 1 unit at THB PS 105 1.22 1.26 5 NT3 dam + 2 units at THB PS 210 1.28 1.31 6 NT3 dam & PS (195 MW) 195 1.54 1.61 7 NT3 dam & PS + 1 unit at THB 300 1.49 1.58 8 NT3 dam & PS + 2 units at THB 405 1.45 1.56
All options were attractive but Options 4 and 3 (in that order) produced the lowest weighted average cost of generation. The options with generation at the Nam Gnouang dam ranked lower.
The options with upstream regulation from the Nam Gnouang storage perform better relative to the other options once the closure of the Nam Theun 2 dam reduces dry season flows in the Nam Theun at Theun Hinboun. The storage on the Nam Gnouang would be operated to regulate the water throughout the year in such a way that the full output of Theun Hinboun could be achieved during the daily 16-hour primary energy window.
It is assumed in the domestic system expansion analyses that a unit of Theun Hinboun would be available for supplying the Central Grid (refer Section 7.4). Thus, if the expansion involves only one unit, it would be dedicated to domestic supply but any additional units, whether they be at the Theun Hinboun power station or at the Nam Gnouang regulating storage, would be available for export.
6.8 Environmental and Social Impacts
6.8.1 Preamble
Historically, the costs of mitigating the environmental and social consequences of power generation projects are generally a relatively minor part of most projects’ overall cost. This is true also of hydropower projects but such issues stir political opposition and engender lender reservations that have the potential to derail projects.
The management of environmental and social mitigations is a much debated and closely scrutinized aspect of project development. Costs associated with impacts in Lao PDR have generally been found to lie between 0.5% and 12%
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for forecasts and 3% to 6% for projects actually built. In some instances, though, environmental and social consequences can significantly affect project performance and rankings.
Estimation of environmental and social costs can involve costly and time- consuming issues and open-ended processes. Environmental impact assessment methods generally involve quantifying in dollar terms those costs such as resettlement that lend themselves to traditional cost estimation methods, and accounting for other impacts by more subjective techniques such as multi-objective analysis. This can introduce distortions because the quantitative and qualitative elements of the assessment may not be aligned. Only a monetary valuation of all impacts could ensure that the different effects are given due and proportionate recognition. However many impacts have been considered to be too theoretical or unrealistic to value by standard cost estimation methods.
Economists and environmentalists have been long aware that some projects, apparently sound by conventional economics, were failing to attract investors because of their social and environmental dimensions. The need to develop a common “language” in which both parties could be involved in productive discourse, rather than mutual puzzlement, has stimulated a number of promising attempts at valuing the invaluable33.
33 Economic Valuation of the Environment: a Challenge for the 21st Century. Roger I. C. Hansell in Environmental Monograph No.15, “Workshop on Emerging Environmental Issues in Ontario”,May 1999, Institute for Environmental Studies, University of Toronto ISBN 0-7727-4413-0 A Guide to Benefit-Cost Analysis, Edward M. Gramlich, Waveland Press, 1997 ISBN 0881339881 Environmental and Natural Resource Economics, Sixth Edition, Tom Tietenberg, Pearson Addison Wesley; 6th edition, 2002, ISBN: 020177027X Environmental Economics, Charles D. Kolstad, Oxford University Press; 1999 ISBN: 0195119541 Human Well-Being and the Environment: Partha Dasgupta. Oxford Press; 2002, ISBN: 0199247889 Nature and the Marketplace: Capturing the Value of the Ecosystem, Geoffrey Heal, Island Press; 2000, ISBN: 155963796X Resource Economics, Jon M. Conrad, Cambridge University Press; October 28, 1999, ISBN: 0521649749 Using Surveys to Value Public Goods: The Contingent Valuation Method, Robert Cameron Mitchell, Richard T. Carson Resources for the Future, 1989, ISBN: 0915707322 Valuing Environmental and Natural Resources: The Econometrics of Non-Market Valuation (New Horizons in Environmental Economics), Timothy C.Y Haab, Kenneth E. McConnell, Valuing Environmental Preferences: Theory and Practice of the Contingent Valuation Method in the Us, Eu, and Developing Countries, Ian J. Bateman, Kenneth G. Willis, Kenneth J. Arrow, Ken G. Willis (Editors), Oxford University Press, January 2002, ISBN: 0199248915 Contingency Calculations for Environmental Impacts with Unknown Monetary Values. David Dole Economic Analysis and Operations Support Division of the Economics and Research Department, Asian Development Bank 2002 Environment and Economics in Project Preparation: Ten Asian Cases. Abeygunawardena, P., B. Lohani, D. Bromley, and R. C. Barba, Asian Development Bank, Manila, 1999. Economic Valuation of Environmental Impacts: A Workbook, Office of the Environment and Social Development, Asian Development Bank. 1996 and Appendix 24 of Economic Analysis of Projects, Asian Development Bank. 2003 The Application of Economic Techniques in Environmental Impact Assessment , David E James, (Editor), Environment & Management , Australia, 1994, ISBN 0-7923-2721-7 A Review of the Valuation of Environmental Costs and Benefits in World Bank Projects, Patricia Silva Stefano Pagio, Environmental Economics Series Paper No. 94, The World Bank Environment Department December 2003 Valuing the Environment in Developing Countries: Case Studies, David Pearce, Corin Pearce, Charles Palmer (Editors), Edward Elgar Pub; 2002, ISBN: 1840641487
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Previous project ranking studies for Lao PDR incorporated environmental and social impacts through multi-criteria evaluation methodologies using impact categories and weightings based on the views of stakeholders. To avoid the distortions inherent in these methods and to adhere more strictly to economic principles, the PSDP TOR specifies that the consultants should attempt a monetary valuation of environmental impacts, leading to the inclusion of these monetary values in the project economic models.
The Consultants chose to use a selected convenient or applicable valuation technique, drawn from contingency (willingness to pay), utility, hedonics, productivity, benefits transfer or alternative opportunity analyses for each individual impact consequence of an impact event. The disaggregation of the analyses to an extreme micro-economic level facilitated this valuation process. Disparity of scales and focus seem to have played a large role in inhibiting the application of monetary values to social and environmental impacts. Costs and complexity have been more significant than any fundamental properties of the impacts in leading to the position taken by some analysts that environmental impacts cannot be valued.
The solution of the valuation technique problem led to another difficulty that is central to the question of development. This is the problem of alternative standards and markets, another topic exciting significant debate34. Which standards or market places should be used to establish the costs or benefits of environmental impacts experienced in Lao PDR as a result of projects seeking international finance? It was decided to produce two sets of cash flows. One, termed the Global set, is based on what could be described broadly as the standards and market values at present set by the developed states as part of the target towards which the development process is intended to move undeveloped states35. The other, termed the Local set, is based on the current standards and market values of Lao PDR, which are the conditions which cause the country to be classified as undeveloped.
34 Can Openers and Comparative Advantage: Alternative Theories of Free Trade and Globalization, Frank Ackerman Global Development and Environment Institute Tufts University, Medford, 2001 Comparing alternative regulation policies: an environmental law and economics approach Mariachiara Alberton, Resources and Environmental Economics, Political Economy of the Environment, European Summer School, 2003 Society, State and Market: A Guide to Competing Theories of Development, John Martinussen, Zed Books. 1997, ISBN: 185649442X The Rise & Fall of Development Theory, Colin Leys, Indiana University Press, 1996, ISBN: 025321016X Poverty and Development: Into the 21st Century, Tim Allen and Alan Thomas (Editors), Oxford University Press; Revised edition, 2000 ISBN: 0198776268 Guide to Practical Project Appraisal: Social Benefit Cost Analysis in Developing Countries, John R. Hansen, UN Pub, 1991 ISBN: 9211061075 Cost-Benefit Analysis and Project Appraisal in Developing Countries, C. H. Kirkpatrick and John Weiss (Editors), Edward Elgar Pub, 1996) ISBN: 1858983460 Green Development: Environment and Sustainability in the South, W. M. Adams, Routledge; 2nd edition, 2001, ISBN: 0415147662 Liberation Ecologies: Environment, Development, Social Movements, Richard Peet and Michael Watts (Editors), Routledge; 1996, ISBN: 0415133629
35 This is the source of a Development Investment Paradox. To succeed in attracting substantial investment for development a country needs to be perceived by the investor to behave as though it were already developed.
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To summarize:
1. The Consultants have examined social and environmental impacts in sufficient detail to simplify the process of assigning monetary values to them.
2. Two sets of standards and market values, Local and Global, have been used to establish the magnitudes of these values.
6.8.2 The SESAMEE MODEL
A model has been developed using Microsoft Excel® to manage the production of cost and benefit cash flows from the disaggregated impact consequences. Called the Social and Environmental Screening and Analysis Model for Economic Evaluations model (SESAMEE), its main features and its application are:
(i) Each energy project passing through the preliminary economic screenings has been treated identically36.
(ii) The analysis of each energy project’s costs and benefits is based on information
• at an identical level of disaggregation • with the same level of accuracy37 • with similar levels of precision38 • brought up to date to the same moment (year) • judged to be comprehensive in scope39
(iii) The following rules and procedures have been followed:
• All negative consequences of a project are either effectively mitigated to meet the appropriate regulatory standards, or borne as a loss by GOL if not mitigated;
• The costs of mitigations or losses are treated as a project cost regardless of which stakeholder40 bears the cost;
36 Equal treatment has been made easier in that all the energy projects which seem to be economic are hydropower projects. A specific version of SESAMEE could be created for thermal projects, or indeed any large infrastructure project. The costs of such an exercise have been avoided in this case. 37 As far as possible errors have been restricted to symmetric ones, but biases are of course inevitable in such coarse data. All projects will be affected by the same biases, and these will tend to work through to the cash flows proportionally according to the size of the Project. 38 Most energy projects examined have not yet been studied at Feasibility level. Nam Ngum 3 is one exception, and this project was used to make the initial templates, and to verify algorithms. The differences between projects resulting from differing precision of their source data will not affect the rankings, as no account of risks has been taken in the rankings. SESAMEE forecasts of costs and benefits will be less uncertain for Nam Ngum 3, and more uncertain for Houay Lamphan Gnai, Nam Mo, Nam Ngum 5, Nam Pot, Nam Sim, Nam Long, Nam Bak Thakho, Xe Kaman 3, Sekong 4, Sekong 5 and Nam Sane 3, than for the other Projects. 39 This judgement has to be tested. The possibility that an individual project has impacts leading to costs or benefits outside the scope of the model remains. Some assurance that this is unlikely, or certainly unlikely to have large effects, is offered from the fact that the range of possible impact consequences has been drawn from the aggregate of those identified in existing studies.
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• Positive impacts are regarded as project benefits. Investments required to realize the benefit have been deducted so that benefits are valued net.
• For each impact consequence, and for each distinct global or local set of cash flows, the costs and benefits are calculated using the same screening procedures, the same market values, the same databases of mitigation unit rates and using the same algorithms. Thus, although the confidence interval around individual estimates may be wide in some cases, they can be considered equivalent in firmness to the estimate of costs for all other projects because the same calculation methodology is applied uniformly to all candidate projects in the ranking exercise.
• In cases of negative impact consequences, the costs of mitigations (by more than one mechanisms, if appropriate) are compared with the costs of sustaining the damage to choose the least cost that should be applied to the consequence41.
• Mitigations which apply to groups of negative impact consequences, particularly engineering mitigations such as bottom outlets, variable level intakes, reservoir destratifiers, thermocline distortion devices, re-regulating ponds and so on, are compared with each other where they have overlapping mitigation effects, and with the costs of “no mitigation”, in a sub-model in which impact consequence costs have been aggregated by effects.42
• Many of the so-called “cumulative” impacts are the result of hydraulic interactions between projects. These are managed automatically by SESAMEE through the changes in hydrologic parameters which determine impact event types and magnitudes.
• Other cumulative impacts, such as competition between projects for the same resettlement land or the destruction by one project of areas needed by another for substitute habitat protection, are more appropriately managed by an integrated regional planning process in which the needs and opportunities of all types of projects in a river basin are considered.43
40 A stakeholder is any person or community affected by the Project. Wildlife populations, habitats and landscapes have been assigned notional stakeholders who represent their interests in the model. 41 At present this choice is based on simple aggregate cost. In more advanced versions net present values could be compared. 42 In later versions of the model it is intended to integrate these engineering mitigations into the full model, to enable net present value comparisons of costs and benefits. Readers should be reminded however that SESAMEE is a screening model only, and decisions about mitigation strategies should be made from Feasibility and Design studies. 43 No such process yet exists. It would be logical to integrate the essentially economic PSDP into national and regional planning using information about other resources, development potentials and political realities. This is the appropriate stage to make an evaluation of the non-hydraulic cumulative impacts.
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(iv) It has been built and applied following these steps:
a) Best contemporary desk sources were used to assemble information about:
• the areas affected by different project impacts;
• numbers of affected people;
• natural resource, landscape, habitat and biodiversity quality of affected areas;
• severity and duration of impact events;
• known and estimated unit-costs for mitigation works;
• estimated values for unavoidable damage to, or loss or impairment of, livelihoods, life qualities, health and well- being, resources, landscapes, habitats, heritage sites or assets stemming from project negative consequences based on both global and local market values, utilities and standards.
• estimated costs for mitigations which cost-effectively prevent or limit damage to, or loss or impairment of, livelihoods, life qualities, health and well-being, resources landscapes, habitats, heritage sites, etc. using substitution, replacement, translocation or protection principles and global or local markets as appropriate;
• estimated values of any social or environmental benefits based on local market and utility systems (net of investments to realize the benefits);
• estimated cost of preparing EIAs, Social Action Plans and Environmental Management Plans and of administering the environmental regulatory and monitoring processes.
b) For each impact consequence, and for separate global and local standards and market conditions, unit costs and values were combined with appropriate magnitude and duration data for each project, to estimate the net cost or benefit of:
• Mitigations of all negative social and environmental consequences to current global or local standards
• Losses and unavoidable benefits at current global or local market prices
• Benefits made possible by additional investments shown as net benefits.
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c) For each impact consequence, and for separate global and local standards and market conditions, the least net cost or greatest net benefit was estimated to become the roject cost or benefit of that impact consequence.
d) For each impact consequence, and for separate global and local standards and market conditions, mitigation costs, losses or net benefits were distributed over the project’s 50 year lifetime according to how they are expected to be incurred, to the separate global and local sets of cash flows.
e) The distributed costs and benefits were accumulated for each project over all Impact Sectors to provide two sets of 50 year project cash flows – the Global cash flows for global standards and market conditions, and the Local cash flows for local standards and market conditions.
f) In the economic evaluation, the net costs were treated as project cash flows in the same way as other project costs.
The SESAMEE Model provides a pragmatic and robust way to compare environmental and social impacts of selected hydropower projects. Furthermore because the model has been based on real impact events, real impact consequence chains, and actually experienced mitigation methods and costs, it provides useful insights into the absolute magnitudes and spatial and temporal distributions of economic costs of social and environmental impacts of hydropower projects in Lao PDR.
6.8.3 Soft and Hard Impacts
It was earlier foreseen that a particular difficulty in valuation would be for losses that cannot be mitigated, have no utility for affected stakeholders, or have very low or no local contemporary commercial market-place value. These were termed “Soft Impacts”. They generally involve effects on landscape appearance, habitats, wild animal and plant populations, river integrity and so on. They were contrasted with “Hard Impacts” which are those with quantifiable mitigation processes or markets for the resources concerned. “Hard impacts” include most social impacts as well as other impacts affecting resources with established local utility or local commercial values.
This difficulty has turned out to be less serious than expected because:
(i) There were no impacts that could not be valued by the techniques available. More appropriate definitions of soft and hard impacts would be these:
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• Soft Impacts are those where there is a large discrepancy between local market values, or the standards determining impact costs, and global market values or standards.44
• Hard Impacts are those where the local and global market values and standards are identical or at least very similar.
(ii) Although Lao hydropower projects have many Soft Impacts, they generally delivered only small contributions to the overall costs45.
It is appreciated that there will be some challenges to the low values attributed to most environmental impacts based on local conditions, and to the relatively much higher values attributed to social impact costs. The explanation lies in the following in the specific conditions encountered in Lao PDR, which are in the consultants’ experience typical of many undeveloped regions worldwide, namely:
(i) Many negative environmental consequences cannot be mitigated because of the limited capacity of official environmental agencies to execute appropriate mitigations46. In these circumstances the negative consequence becomes classed as “unavoidable damage”, and is assigned the value of the loss.
(ii) Local values for habitats, biodiversity, landscape and heritage sites reflect:
• limited environmental awareness among affected stakeholders, most of whom still depend on hunter-gatherer activities to augment subsistence food supplies;
• the failure of urban populations to yet adopt middle-class concerns for wildlife, the environment, and heritage matters;
• a market for wild products based entirely on their immediate utility as food or as folk/magical medicines;
44 The concept is well explained by an example. Individual rare mammals such as the Giant Muntjack or the Saola have international values as zoo specimens of tens of thousands of dollars. The money which could be raised in the USA or western Europe to protect the last known population of either species would reach millions of dollars. In the local market the animal might be worth $5 per kg to a hunter selling meat, or it could be a crucial element in the diet of a rural farmer/hunter-gatherer making the difference between moderate health and poor health. 45 Undeveloped regions by definition have standards and market values widely different from, and generally lower than, those in developed regions. The degradation of natural resources, which arises from prolonged impover- ishment and subsistence hunter-gathering, has resulted in soft impact costs making generally minor contributions to global social and environmental impact costs. This result is at odds with the concept of Projects in a developing country damaging the pristine environments that sustain both the inhabitants and a rich floral and faunal biodiversity. Only three Projects, Thakho, Nam Theun 2 and Nam Ngiep, have global costs more than twice local costs. These global costs reflect the unique conservation status of the Irrawaddy dolphin population downstream of the Khong Falls, the less degraded state of the Nakai Plateau and the proximity of the Project to the ranges of important endemic species, and the relatively less degraded state of the Nam Ngiep valley, respectively. 46 Examples of mitigation options for “soft impacts” include protection of substitute habitat areas, preventing habitat and landscape damage and resource exploitation (particularly hunting and logging) in protected areas, capture and relocation to protected areas of endemics threatened by project-induced impact events, establishment of wetlands using surplus diversion discharges, etc. There are no institutions in the country with the mandate or the experience to carry out these activities.
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• the slow growth of specialized eco-tourism in Lao which would have the capacity to demonstrate the revenue earning potential of sound conservation of landscapes, habitats and wildlife.
(iii) Social impacts by definition affect stakeholders who do have representation. Moreover social development programs, regarded by both GOL and donors alike as essential precursors for economic and social development, take a dominant position at present in national aspirations and investments.
(iv) Environmental impacts on the other hand affect resources, habitats, landscapes and populations of animals and plants which have at present virtually no stewardship representatives in either national or project stakeholder discourse. Protection of environmental resources is at present hardly possible except in a few small areas.47
6.8.4 Calculation of Economic Costs and Benefits of Impacts
The monetary valuation of the social and environmental impacts of shortlisted projects is performed using a spreadsheet-based model developed by RMR Consultants. The Social and Environmental Screening and Analysis Model for Economic Evaluation model (“SESAMEE”) reduces project impacts to cash flows, providing estimates of dollar costs and benefits for each year of the project’s construction and operation.
Large amounts of data are required to quantify the effects of hydropower projects at an appropriate level of detail. To quantify impact events, the SESAMEE model incorporates up to 2,175 project-specific parameters and 364 constants applicable over all or several Projects. These are listed in Annex 7.
The data is applied to six modules, which have been separated on the basis of the functional distinctions of their main impact events. The modules are:
• Planning, Studies and Regulation • Construction Sites • Transmission Line • Access Roads • Reservoir and Catchment • Downstream Rivers, comprising donor river, recipient river and affected river(s) depending on the Project’s water arrangements.
As with other models, the results produced by SESAMEE are sensitive to the quality of input data. The data requirements are extensive and collection of the required inputs is time consuming. Existing data quality is low and access is complicated and in some cases costly. Data validation and screening
47 Conservation of natural resources and protection of biodiversity cannot be expected to occur until the bulk of the population no longer subsists on these resources; that is to say, economic development has to precede environmental protection (the Karshenas Principle).
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requires skilled manpower. SESAMEE is not yet a tool which could be supported outside a research setting. Trends in digitization and GIS, leading to the availability of reasonably accurate and internet-accessible national and regional datasets will ultimately allow SESAMEE type models to be applied speedily to planning investments in any large infrastructure projects in most parts of the world. At the present time however consultants still have to collect and analyse or interpret large amounts of analogue texts and graphics to establish reasonably accurate estimates of the input parameters.
Quantifying impact costs and benefits in dollar terms allows them to be internalized in a project’s economic evaluation. Many social and environmental impacts treated in previous studies as externalities will, through SESAMEE, be brought into the analysis. Depending on the particular characteristics of a project, some of the costs and benefits internalized in this way could be significant, for instance:
• timber logged from transmission and road easements (net of associated ecological and social losses);
• population health improvements from the introduction of health clinics at project sites;
• water quality impacts on fishing among downstream communities.
Such issues have been considered in previous studies only in subjective terms through multi-criteria perceptions of consultants and stakeholders. The introduction of new and in some cases large values into the economic cash flows gives new insights into the qualities of projects in both relative and absolute terms. The perspectives opened by this extensive (in terms of time periods, scope and geography) internalization provide planners and politicians, as well as economists and financial analysts, with a much more real picture of the effects of a large investment over a long period The most appropriate ways to take advantage of this picture will cover more than fixed discount NPV calculations of core infrastructure elements.
Quantification of the SESAMEE social costs and benefits assumes inter- national standards of design, construction and operation are applied. If lower standards are used, the negative impact costs will be higher (e.g. risk of dam- break and reservoir rim instability, safety issues, risks of construction accidents, introduction of HIV into rural areas, unrehabilitated landscape and habitat impairment, excessive stream sedimentation and pollution, etc.) and the benefits will be lower (e.g. less effective health services provided to affected stakeholders, all-weather access roads which need more maintenance and thus induce lower economic responses, rural electrification which reaches less people or is unreliable, etc.).
The SESAMEE costs have assumed high standards of administration and governance in executing mitigations, compensation, regulation and enforcement of developer compliance. The SESAMEE benefits in particular rely on high quality governance. A glance at the annual cash flows in later project years will provide some idea of the mobilization of economic activities
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which is expected to occur. These positive economic impacts will require a major expansion and improvement of local and national administrative and support services, and the maintenance of high standards of transparency and accountability in governance. Economic growth rates used in SESAMEE, for example, depend on
• all stakeholders and the surrounding host populations having secure land titles before a project starts construction;
• all stakeholders regarding enterprise as being much less risky than they do now;
• Government support of stakeholder economic initiatives through institutions and regulations which facilitate fair trade and enterprise equitably.
The loss and benefit cash flows of a project’s impacts are sensitive to population, a time-dependent variable. SESAMEE therefore has built-in population growth and movement functions to take into account demographic and migration-induced population changes.
Calibration is a critical part of the development of a model such as SESAMEE but this phase has been restricted by a lack of equivalent and reliable data. Existing EIAs are largely unsuitable for the purpose as they lack sufficient detail and address many impacts in quantitative terms. RMR’s detailed mitigation studies for the Nam Ngum 3 project are more closely attuned to the SESAMEE approach and have therefore been used to test the model. The results are reassuring. RMR’s work on the Nam Leuk, Theun Hinboun, Nam Song and Nam Mang 3 mitigations also provides recent in-country data to test specific parts of the model.
The concepts and logic used to value and distribute costs and benefits over a project’s service life are written into SESAMEE’s algorithms. By way of illustration, an example is provided in Annex 7. These algorithms are based wherever possible on established relationships between impact events and their consequences and on known market values. However, in many cases the processes and interactions that SESAMEE seeks to replicate are inexact and incompletely understood, and the algorithms modeling these relationships therefore are more empirical and reflect to some degree the Consultant’s professional judgments and experience. Given the nature of the task and the size of the model, a period of peer review and practical application to problems is needed to improve the model’s accuracy and reliability. Again, due to the limited time available, the testing and review processes in the model’s development have been necessarily brief.
Three sets of cash flows have been prepared for each project; two of these, the Local and Global valuations of impacts, are described in Section 6.8.3. These are economic in nature, taking a country perspective and including all identified project impacts. The third cash flow describes the extent to which the environmental and social impacts impact the financial position of the project owner and its calculation is described in Section 9.2.3. Calculated
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NPVs of cash flows for environmental and social impacts of all shortlisted projects are summarized in Table 6.11.
Table 6.11: Environmental and Social Economic Costs
Project MW Annual NPV of Social and Generation Cost Energy Env. Costs Component 1/ Global Local Global Local (GWh) ($ mill) ($ mill) (¢/kWh) (¢/kWh) Houay Lamphan Gnai 60 250 15.959 13.409 0.64 0.54 Nam Theun 2 (1074 MW) 1074 5922 89.463 39.031 0.15 0.07 Nam Theun 2 (681 MW) 681 5701 89.977 39.868 0.16 0.07 Nam Mo 125 603 17.413 16.500 0.29 0.28 Nam Ngiep 1 (+ reg dam) 368 1537 31.865 7.689 0.21 0.05 2/ Nam Sane 3 60 283 23.915 17.806 0.85 0.63 Nam Ngum 2 (u/s reg.) 460 1901 91.046 80.790 0.48 0.43 Nam Ngum 2B (u/s reg.) 140 602 83.624 82.458 1.40 1.38 Nam Ngum 3 530 2167 18.383 13.168 0.09 0.06 Nam Ngum 3B 690 2859 19.989 14.759 0.07 0.05 Nam Ngum 5 75 317 11.718 14.010 0.37 0.45 Nam Bak 2B 85 389 10.360 6.661 0.27 0.17 Nam Long 12 63 5.208 3.570 0.83 0.57 Nam Sim 10 47 15.870 10.025 3.41 2.15 Nam Pot 20 93 15.366 10.637 1.67 1.15 Thakho 60 403 270.506 40.066 6.77 1.00 3/ Theun Hinboun Expansion 105 686+ 59.688 57.687 0.66 0.64 Xe Kaman 1 (u/s reg.) 470 2086 116.913 71.274 0.57 0.34 Xe Kaman 3 250 1369 10.124 8.127 0.07 0.06 Xe Kong 4 (u/s reg.) 490 2257 34.709 0.543 0.16 0.00 Xe Kong 5 400 1795 32.913 19.574 0.18 0.11 Xe Katam 13 60 6.355 4.592 1.07 0.77 1/ Calculated as ratio of NPV of social and environmental costs and NPV of generation, both taken over 50 years 2/ There is uncertainty in the estimates of populations in the Nam Sane 3 reservoir area, perhaps attributable to confusion in the designations of Nam Sane 2 and Nam Sane 3. 3/ In addition to the incremental energy reported in this table, a proportion of the output from the existing units is promoted from secondary to primary energy.
The role of the SESAMEE model in the PSDP Study is to quantify impacts in the same values as other costs. It’s use as a design tool was also demonstrated during the course of the study by using it to optimize mitigation measures and structures. For instance, the effectiveness of regulating dams, variable level intakes, destratification systems and the like could be refined by testing the response in the values of downstream impacts to changes in the sizing of the structures.
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6.8.5 SESAMEE and EVALS Outputs Combined
The SESAMEE valuations of social and environmental impacts are combined with the EVALS technical evaluations to provide an overall measure of a project’s worth. The NPVs of the SESAMEE cash flows given in Table 6.11 are combined with EVALS technical performance measures through the use of a multiplier to indicate the relative economic performance of shortlisted projects (refer Table 6.12). Two sets of project economic rankings were prepared:
(i) One set, called the Global project economic ranking, is based on global standards and market values.
(ii) The other set, called the Local project economic ranking, is based on local standards and market values.
Projects are ranked according to their relative economic performance. Each project’s overall economic attractiveness was quantified for comparison purposes by combining its technical and socio-environmental attributes. EVALS performance measures were calculated for each project, based on project optimizations at a common ICF of 1.75. Two measures, average and weighted generation costs, were chosen to represent the performance of projects for ranking purposes with weighted generation cost being the key value.
These purely “technical” values of average and weighted generation costs were then combined with the monetary valuations of social and environmental impacts determined using SESAMEE. The SESAMEE model produced two sets of social and environmental costs – Local and Global – and therefore the combined EVALS and SESAMEE measures included both a Local and a Global value of average and weighted generation costs for each project (refer Table 6.12).
Table 6.12 sets out the SESAMEE adjustments for both “Global” and “Local” impacts. The adjustments were made by applying a multiplier to the EVALS values of Average Generation Cost and Weighted Generation Cost to calculate corresponding values based on both the Global and Local SESAMEE valuations of impacts. The multiplier is a ratio of a project’s technical and environmental costs, where:
• The “technical” cost is the capital cost of a project calculated by EVALS without inclusion of any environmental and social costs;
• The “environmental” cost is the NPV of the Global or Local SESAMEE cash flows.
The multiplier is therefore calculated as follows:
• Global Multiplier: The sum of the technical cost and the Global environmental cost divided by the technical cost;
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• Local Multiplier: The sum of technical cost and Local environmental cost divided by the technical cost.
A comparison of the Global and Local valuations of weighted generation cost in Table 6.12 shows the sensitivity of the project rankings to global and local valuations of impacts. It might be argued that rankings based on the Local valuations shows the order of projects in conditions of no investment restraints, whereas the Global ranking shows the order of projects if multilateral guarantees or loans are needed.
Table 6.12 shows that out of 33 projects examined, application of the SESAMEE based Global costs set based on Average Generation Costs has resulted in revisions in the ranking by 3 or more places for seventeen projects, and by 5 or more places for thirteen projects. Application of the local costs set delivers an identical result, with the same scenarios changing rank position by the same or slightly different amounts. If the rank based on Weighted Generation Costs is examined, SESAMEE Global costs will shift nine projects by 3 or more places, and seven by 5 or more. SESAMEE local costs move eight projects by 3 or more places and three projects by 5 or more.
These ranking shifts reflect particular issues with each project. A prominent example is Thakho where the Global valuation of possible impacts on the Khone Falls are high because of the international regard for the aesthetic and biodiversity attributes of the area. Nam Sim is an example of a small project with reasonable technical characteristics being marked down because the impacts, though not large in absolute terms, are large compared with the project’s small output.
Somewhat unexpectedly, there is not much difference between the outcomes for the two sets of costs in changing the ranking of projects. However, it is clear from Table 6.12 that generation costs are generally increased more from the application of the Global costs set than the Local set. The non-weighted project average increase in Average Generation Costs is 32% and 21% respectively for the Global and Local cost set respectively. Weighted Generation costs are increased by 43% and 23% respectively. The difference between the two sets in terms of project economics is sufficient to significantly affect project viability.
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Table 6.12: Specific Generation Costs for Shortlisted Projects, with and without Environmental Costs
Tech Costs Env Costs Multiplier Average Generation Cost Weighted Generation Cost Project Plant Installed Energy % Name ICF Factor Capacity Generation 2ndary (EVALS) +Global +Local +Global +Local EVALS +Global +Local EVALS +Global +Local xQmean (%) (MW) (GWh) (%) (m$) (m$) (m$) (c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh) (c/kWh)
Xe Kaman 3 1.75 52 301 1369 11 349 10.1 8.1 1.03 1.02 2.57 2.64 2.63 2.69 2.77 2.75 Xe Kaman 1 1.75 50 472 2087 6 556 116.9 71.3 1.21 1.13 2.69 3.25 3.03 2.75 3.32 3.10 XK3 u/s reg 1.75 51 472 2086 7 556 116.9 71.3 1.21 1.13 2.69 3.25 3.03 2.76 3.35 3.12 XK3 conj 1.75 50 472 2085 2 556 116.9 71.3 1.21 1.13 2.69 3.25 3.03 2.69 3.26 3.04 Xe Katam 1.00 55 13 61 81 25 6.4 4.6 1.26 1.18 4.09 5.14 4.85 6.86 8.61 8.13 Se Kong 5 1.75 50 407 1795 18 504 32.9 19.6 1.07 1.04 2.83 3.01 2.94 3.10 3.30 3.22 Se Kong 4 1.75 51 491 2192 19 814 34.7 0.5 1.04 1.00 3.74 3.90 3.75 4.11 4.28 4.11 XK5 u/s reg 1.75 53 485 2257 9 812 34.7 0.5 1.04 1.00 3.63 3.79 3.63 3.77 3.94 3.78 XK5 conj 1.75 53 485 2238 7 812 34.7 0.5 1.04 1.00 3.66 3.82 3.66 3.77 3.93 3.77 Nam Theun 2 680 0.86 95 683 5701 45 644 89.5 39.0 1.14 1.06 1.14 1.30 1.21 1.47 1.67 1.56 1074 1.35 63 1072 5922 18 796 90.0 39.9 1.11 1.05 1.36 1.51 1.42 1.49 1.65 1.56 Nam Ngiep 1 main 1.75 47 328 1362 24 450 31.9 7.7 1.07 1.02 3.33 3.56 3.38 3.76 4.03 3.82 re-reg 1.75 50 40 175 27 72 (inc in NNGIEP1) (inc in NNGIEP1) (inc in NNGIEP1) (inc in NNGIEP1) Nam Ngum 5 1.75 50 73 317 10 150 11.7 14.0 1.08 1.09 4.77 5.14 5.21 4.95 5.33 5.41 Nam Ngum 3 1.75 47 528 2167 22 785 18.4 13.2 1.02 1.02 3.65 3.74 3.71 4.05 4.15 4.12 NN5 u/s reg 1.75 48 527 2203 17 785 18.4 13.2 1.02 1.02 3.59 3.68 3.65 3.88 3.97 3.94 Nam Ngum 3B 1.75 47 689 2859 21 1017 20.0 14.8 1.02 1.01 3.59 3.66 3.64 3.97 4.05 4.03 NN3 u/s reg 1.75 49 689 2931 20 1017 20.0 14.8 1.02 1.01 3.50 3.57 3.55 3.84 3.91 3.89 Nam Ngum 2 1.75 47 458 1868 19 480 91.0 80.8 1.19 1.17 2.59 3.08 3.03 2.82 3.35 3.29 NN3 u/s reg 1.75 48 456 1901 14 479 91.0 80.8 1.19 1.17 2.54 3.03 2.97 2.71 3.23 3.17 NN5 u/s reg 1.75 47 458 1880 17 479 91.0 80.8 1.19 1.17 2.57 3.06 3.01 2.78 3.31 3.25 NN3+NN5 u/s reg 1.75 48 456 1910 23 479 91.0 80.8 1.19 1.17 2.53 3.01 2.96 2.86 3.40 3.34 Nam Ngum 2B 1.75 44 197 757 83 231 83.6 82.4 1.36 1.36 3.08 4.19 4.18 5.26 7.16 7.14 NN5 u/s reg 1.75 45 139 552 83 196 83.6 82.4 1.43 1.42 3.58 5.11 5.09 6.14 8.76 8.72 NN3+NN5 u/s reg 1.75 50 138 602 45 196 83.6 82.4 1.43 1.42 3.29 4.69 4.67 4.23 6.03 6.00 Nam Mo 1.75 55 125 603 2 146 17.4 16.5 1.12 1.11 2.45 2.74 2.72 2.47 2.77 2.75 Thakho 0.03 76 60 403 100 103 270.5 40.1 3.62 1.39 2.59 9.37 3.59 2.59 18.74 7.19 H. Lamphan Gnai 1.75 51 56 249 4 85 16.0 13.4 1.19 1.16 3.44 4.08 3.98 3.46 4.10 4.00 Nam Sim 1.00 66 8 47 63 13 15.9 10.0 2.23 1.78 2.76 6.15 4.90 4.03 8.98 7.15 Nam Pot 1.75 53 20 93 3 31 15.6 10.6 1.50 1.34 3.41 5.11 4.57 3.42 5.13 4.59 Nam Sane 3 1.75 54 61 286 6 74 23.9 17.8 1.32 1.24 2.60 3.44 3.23 2.65 3.51 3.29 Nam Long 1.00 61 12 63 21 32 5.2 3.6 1.16 1.11 5.02 5.84 5.58 5.60 6.52 6.23 Nam Bak 2B 1.75 52 85 389 9 161 10.4 6.7 1.06 1.04 5.20 5.53 5.42 5.40 5.75 5.62 Theun Hinboun Ext n/a n/a 105 686+ - 194 59.7 57.7 1.31 1.30 2.60 3.40 3.37 1.88 2.46 2.44
NOTES: 1 Costs are expressed as Present Values. 2 For NPV calculations, discount rate of 10% is used and Year '0' is year of commissioning 3 Specific Generation Cost are Levelized Cost over lifetime 4 Weighted Generation Costs consider 100% primary plus 50% of Secondary Generation 5 Primary Generation level can be generated during at least 95% of time 6 Theun Hinboun Extension performance underestimated. Incremental primary energy exceeds overall incremenal energy (greater dry season generation).
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6.9 Standardized Ranking of Projects
6.9.1 Basis of Ranking
Generally speaking, a project is optimized for the site it will occupy and for the function it will perform in the system it is to supply.48 Under previous Lao power planning studies, projects were allocated either to the domestic or export markets and optimized and ranked accordingly. For the PSDP rankings, though, a project’s target market and functions are not specified. All projects are ranked against a common set of reference conditions and are available to supply either the domestic or export markets, or both.
Ranking is therefore based on a common ICF to ensure even comparisons. The value chosen is 1.75, roughly equivalent to a plant factor of about 57%, because it is a reasonable representation of normal plant factors for hydropower projects in the region and it corresponds roughly to the current EGAT PPA requirements.
6.9.2 Ranking of Shortlisted Projects
Projects are ranked according to their relative economic performance as indicated by the values of their weighted average generation cost as adjusted for their social and environmental impacts valued according to global standards and markets. The rankings are set out in Table 6.13.
Table 6.13 also gives the development status of each project, although it needs to be borne in mind that the sincerity with which developers are fulfilling their mandates is weak in a number of cases.
A succinct report on each of the shortlisted projects is contained in the Project Catalogue (Volume C), giving key technical and economic data.
48 System context will influence project optimization. Parameters such ICF, active reservoir volume and re-regulation arrangements will depend on the role of the project and these could affect calculated performance measures used to rank projects (e.g. annual energy, firm energy, cost of generation, etc.).
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Table 6.13: Ranking and Characteristics of Shortlisted Projects Rank Project Project Type Installed Annual Energy Adj. Weighted Development Status Present Contractual Capacity Output Gent’n Cost 1/ Status (MW) (GWh p.a.) (¢/kWh) 1 Nam Theun 2 Storage / transfer 1074 5922 1.6 FS, EIA CA, PPA, 2 Theun Hinboun Expansion 2/ Storage / transfer 105 686+ 2.4 Operation CA, PPA, FC 3 Thakho 3/ R-of-R / Mekong 30 214 2.6 IS MOU 4 Nam Mo Storage 125 603 2.7 FS, EIA CA 5 Xe Kaman 3 Storage 250 1369 2.8 FS MOU 6 Xe Kaman 1 (u/s reg.) Storage 470 2086 3.1 FS CA 7 Nam Ngum 2 (u/s reg.) Storage 460 1901 3.2 FS CA 7a Nam Ngum 2B Storage 140 196 8.7 IS CA 8 Xe Kong 5 Storage 400 1795 3.2 IS MOU 9 Nam Sane 3 Storage 60 283 3.3 IS - 10 Nam Ngiep 1 (+ reg dam) Storage 330 1537 3.8 FS, EIA MOU 11 Xe Kong 4 (u/s reg.) Storage 490 2257 3.8 IS - 12 Nam Ngum 3 Storage 530 2167 4.1 FS, EIA CA 12a Nam Ngum 3B Storage 690 2859 3.9 IS CA 13 Houay Lamphan Gnai Storage 60 250 4.0 IS - 14 Nam Pot Storage 25 99 4.6 IS - 15 Nam Ngum 5 Storage 75 317 5.4 PFS MOU 16 Nam Bak 2B (u/s reg.) Storage / transfer 85 389 5.6 IS MOU 17 Nam Long Storage 12 63 6.2 IS - 18 Nam Sim Storage 10 47 7.1 IS - 19 Xe Katam Run-of-river 13 60 8.1 PFS -
MOU Memorandum of Understanding FC Financing Commitment FS Feasibility Study CA Concession Agreement IS Inventory level study EIA Environmental Impact Assessment PPA Power Purchase Agreement PFS Pre-feasibility Study 1/ Economic weighted average cost of generation calculated using EVALS, adjusted for environmental costs determined by SESAMEE. 2/ In addition to annual incremental energy, the project also promotes a portion of the output from the existing project from secondary to primary energy 3/ Thakho generates anti-cyclically, with output greater in wet season. Weighted average cost of generation is adjusted accordingly.
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7.0 DOMESTIC POWER SYSTEM EXPANSION
7.1 Planning Overview
7.1.1 System Planning Objectives
Domestic peak demand is about 250 MW and is expected to grow to about 900 MW by the year 2020. A number of generation expansion scenarios to meet this demand were evaluated using the Lahmeyer system expansion simulation model, SEXSI. The program is explained in Section 7.3.
Electrification objectives for both grid or off-grid development derive from the household and village electrification targets set by GOL. The Socio Economic Development Strategy published in March 2001 sets out the numbers of households and villages to be electrified in the pursuit of GOL’s target which foresees 90% of all households in the country being supplied on a continuous basis from the national grid or at least from regional grids, municipal grids, or independent electricity sources.
Table 7.1 gives the village and household electrification targets to comply with the 90% target in 2020. The interim targets in 2010 were estimated from MIH/EDL’s electrification program.
Table 7.1: Household and Village Electrification Ratio Targets
Year Villages Households 1999 19% 34% 2010 43% 55% 2020 80% 90%
Where the electrification objectives are less defined are in the technologies to be employed in meeting the 2020 electrification target. Assumptions made in this study involve:
• The adoption of off-grid development targets (refer Section 4.2.2) and meeting the balance of demand implied in the 2020 GOL target by grid development;
• Adoption of EdL’s transmission development plans to 2013 on which the EdL and JICA power and energy demand forecasts are based. New transmission is indicated as dashed green lines in Figure 7.1);
• Adoption of EdL’s indicative grid extension proposals for the period from 2013 to 2020, as indicated in dashed red lines in Figure 7.1.
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Figure 7.1: EdL 115 kV Power System Development to 2020
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The basic objective of the system expansion planning exercise is the formulation of a least-cost plan for meeting forecasted demand at a specified level of reliability. The principal decisions involved in proposing an optimal system development plan are:
• Expansion and reinforcement of the transmission system;
• Timing of interconnections between the grids if, in fact, they are warranted within the planning horizon;
• Source of generation, whether it be imports, domestic off-take from IPP projects or new EdL capacity;
• In respect of new capacity, the timing, type, size and location of future power plant;
• Optimal mode of operation of the system as a standalone system or as an integrated part of the Thai system.
The economics underlying the determination of a least-cost investment strategy will vary with time. Generation technology, global energy prices, international carbon trading agreements and other factors may change. This is not accounted for in the PSDP and regular updating will be needed to maintain the relevance of the plan over time.
7.1.2 Features of the Lao Power System
Although the Lao power sector is small, it is complex. Characteristics complicating the formulation of an optimal power system expansion plan include the following:
(i) Indigenous energy sources are plentiful but they are predominantly hydropower. A number of factors must be taken into account in hydro-based systems, among them:
• Hydrological variability (seasonal and annual) and its effect on meeting capacity and energy requirements in normal years and on security of supply issues during drought years;
• Hydraulic and electrical interactions between projects: hydraulic interactions may include regulation benefits, diversion of flows, backwater effects, etc. while electrical interactions may include tandem operation of storage and run-of-river projects, sharing of transmission infrastructure, etc.;
• Environmental and social impacts of each project, and cumulative and sequential effects of multiple projects;
• Financing characteristics of hydropower projects including their large capital requirements, high completion risks, long planning and construction periods, low ECA coverage and variable revenues streams.
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(ii) The Lao system consiste of a number of separate grids that will expand and interconnect over the course of the planning horizon;
(iii) The Lao grids are interconnected with Thailand and will become interconnected with other GMS countries over the planning period. International power trading is an important feature of the Lao power sector for several reasons:
• Exports are an important contributor to foreign exchange earnings of Lao PDR;
• Interconnections with Thailand, Vietnam and China provide least-cost supplies to border towns.
• Imports from Thailand backstop the Lao power system with dry season generation in the south and reserve margin in the north.
(iv) EdL is reliant on external sources of capital for generation and transmission development and the private sector is seen as an important partner in developing future generation. The primary focus of IPP developments to date has been the export market and the allocation of a portion of a project’s output for the national grids has been regarded to date as a secondary benefit. Placing increasing reliance on IPPs to meet future generation needs will introduce planning problems related of the poor record of IPPs in achieving scheduled operation dates.
(v) Another variable in the planning of the Lao sector is the reform process itself. Under GOL’s power sector policy, the project implementation framework should improve and stronger institutions should emerge. As a result, development risks should become more manageable. This, together with the closer integration of ASEAN/GMS power systems, will open the way to financing and development options not presently available to state or private investors.
7.1.3 Planning Issues
EdL can procure generation for its grids by either: (i) developing new domestic generation projects, (ii) purchasing electricity from IPP projects, or (iii) importing energy from neighboring countries. Past policy and practice of GOL has been to develop power generation projects, not just to meet domestic demand but well in advance of it so that export revenues could be earned from the sale of surplus power to EGAT. These earnings have been an important contributor to the Lao economy for nearly 30 years, although the contribution has declined in recent years for several reasons:
• Domestic generation development has not kept abreast with growing demand;
• Prices paid by EGAT for surplus EdL energy have fallen progressively over the last decade, roughly reflecting recent trends in avoided costs in the Thai system;
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• The ¢/kWh cost of generation from new projects in Lao PDR has been increasing due, firstly, to the withdrawal of multilateral funding from generation development and, secondly, to a decline in the quality of available sites at the margin.49
The economic justification for this policy is re-assessed as part of the PSDP economic planning process that evaluates system expansion options on a least-cost supply basis, taking into account broad economic criteria including:
• Cost of electricity: The cost of capacity and energy, infrastructure development and other project attributes associated with the delivery of new power to the load are considered.
• Power Trade: Exchanges of electricity between the EdL and EGAT system are valued according to their commitment (firm / non-firm);
• Environmental and social impacts and benefits: Positive and negative impacts of each option are valued through the incorporation of the SESAMEE cash flows.
• Economic benefits: To some extent the comparison of expansion options considers wider economic costs and benefits through the SESAMEE valuations of social and environmental impacts;
Some factors of relevance to project selection and financing decisions are considered only in part or not at all in the PSDP system expansion planning:
• Risk: Risks borne by GOL when it finances and constructs new domestic projects (e.g. construction risks) are not routinely analyzed and compared for different project and scenario alternatives. Some risks are implicitly built into capital costs through contingency allowances and the like and many social and environmental risks are built into the SESAMEE cash flows. Prominent risks such as IPP implementation uncertainty are discussed and risk management strategies proposed.
• Financing: The financing requirements, and likely availability and terms of finance may be a factor in project selection where a particular type of project or form of generation can attract finance more readily and under better terms than another.
• Self-sufficiency: GOL may wish to limit reliance on other parties for an essential service such as electricity, be they private companies or neighboring power utilities. The level of reliance is not an express constraint in the PSDP studies but the degree of reliance on imports and IPP purchases has been tracked and has been minimized consistent with least cost and system reliability criteria.
49 Logically, better sites enjoy priority in expansion sequencing and predictably the Xeset 1, Nam Leuk and Nam Mang 3 sites fall short of Nam Ngum 1 in technical quality. However, with national grid integration and growing peak demand, larger projects can be developed for domestic supply and this widens the choice and opens the way for improved economies of scale which might reverse the rising specific generation cost from EdL’s new projects.
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7.1.4 Selection of New Generation Projects
In the absence of systematic domestic generation expansion plans (the first appearing only in 1997 50), EdL has tended to sequence its projects according to pragmatic considerations such as access to finance and availability of feasibility studies. Pressure of time and a lack of evaluated sites have resulted in an arbitrary selection of those projects that can be implemented quickly without inordinate delays associated with the preparation of feasibility studies and approval of finance.
The PSDP provides a rational least-cost sequence of projects but this is but one element in a procurement process that should include the following steps:
(i) Project Identification: An optimal sequence of investments is identified.
(ii) Project Development: A systematic pipeline of projects is prepared to feasibility / EIA level with a couple of priority projects each in the Central and Southern grids and another perhaps in the Northern Supply Area.
(iii) Project Implementation: Financing and procurement strategies for individual projects are decided closer to their time of implementation and are chosen according to the type of project and most beneficial source of finance. Traditional procurement using ICB is favored for public sector financing but other procurement practices may be favored under BOT implementation models are adopted.
7.1.5 Role of IPP Projects in Generation Expansion
GOL policy mandates that part of the output of IPP export projects should be available for supplying the domestic grid if needed. IPP off-take is attractive for a couple of reasons. IPP projects are larger and therefore, all things equal, the cost of production will be lower compared with the marginal domestic plant. Also, it is a source of generation that involves little capital expenditure, an attraction in a difficult debt market given the high levels of GOL and EdL indebtedness. The principal problem with IPP off-take is development uncertainty; i.e. GOL/EdL cannot predict which IPP projects will proceed and when this will occur. This is unhelpful when orderly planning is the goal. Care in choosing which projects and developers to rely on will reduce IPP implementation uncertainty, but not eliminate it.
Four IPP proposals are making steady progress towards implementation - Nam Mo, Theun Hinboun Expansion, Nam Theun 2, and Xe Kaman 3. All have sound economics, interested power purchasers and credible financing and procurement plans. Many of the power system expansion scenarios tested by the SEXSI program included domestic off-take from these projects and was found to be an attractive source of generation. The roles of each frontline IPP candidate in supplying domestic demand are outlined below:
50 Power System Planning in the Ministry of Industry and Handicraft, Knight Piesold, ADB, 1997
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• Nam Mo is only 125 MW and its remote location and small local off-take entitlement prevent it from playing a strategic role in the expansion of the Central Grid. It could, however, make a useful contribution in electrifying part of Xieng Khoung province and providing voltage support to the north-eastern extension of the grid. The PSDP assumes that demand growth in this part of Lao PDR would be covered by Nam Mo.
• Theun Hinboun Expansion will provide competitively priced power at a pivotal location. The existing Theun Hinboun facility has been operating commercially since 1998 and contributes up to 4% of its generation to the Central 2.1 Grid. The scope of the extension to Theun Hinboun is not yet decided and the SEXSI scenarios are therefore based on Option (iii) as described in Section 6.7; i.e. augmenting the plant’s existing two 105 MW units with a third, plus the construction of an upstream regulation on the Nam Gnouang (Nam Theun 3) with no generation at the new dam. The new works are expected to enter commercial operation in 2008.
The project, being an extension of the existing plant, is to be developed by THPC, a company 60% owned by GOL with a strong cash flow and a history of responsible and profitable management. It is therefore perhaps unique among Lao projects in being able to access finance on the strength of an EdL PPA. The SEXSI system expansion scenarios including this project have therefore assumed that the new unit would be dedicated to supplying EdL. Due to the seasonal regulation provided by the Nam Gnouang dam, there would also be incremental dry season energy from the existing turbines, and this would be available for export to EGAT under the existing PPA. Additional units might also be added, in which case it is assumed these, too, would be for export.
It is also assumed in the SEXSI evaluations that the pricing of EdL’s purchases from THPC would be based on the price of 4.59 ¢/kWh currently paid by EGAT, as adjusted to reflect transmission differences to the point of sale.
• Nam Theun 2 is also located centrally and offers a valuable source of low cost generation. NTPC is committed through a signed PPA to supply EdL with 75 MW and an average of 300 GWh per annum through two dedicated Pelton units. The output will not be 100% firm and it was assumed in the SEXSI simulations that year-to-year and month-to-month fluctuations would be proportional to the deliveries to EGAT grid. The tariff for domestic supply is set out in the EdL PPA and levelizes to a value of around 4.0 ¢/kWh. The Nam Theun 2 COD is 2010.
• Xe Kaman 3 is a 250 MW project being developed by a Vietnamese consortium. The site is located near the Vietnamese border in southern Lao PDR but has attractive economics and could make a cost-effective contribution to the development of the EdL system in the south. For the purposes of the SEXSI simulations, a domestic off-take of 20% is assumed (i.e. 50 MW, 220 GWh/a).
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The project’s main transmission line will be built to the east to interconnect with the EVN system, and therefore the construction of a dedicated 115 kV line would be necessary to interconnect the project with the Southern Grid.
In summary, the assumptions made with respect to the role of IPPs in meeting the generation requirements of the Lao power system expansion are described in Table 7.2.
Table 7.2: Assumed IPP Contributions in System Expansion Simulations
IPP Project MW GWh Assumed Grid COD Price domestic domestic (c/kWh) Nam Theun 2 75 300 4.0 Central 2010 Theun Hinboun 105 686 4.1 Central 2008 Xe Kaman 3 50 220 4.0 Southern 2008
The PSDP expansion analyses underline the considerable benefits of utilizing the domestic off-take allocations of IPP export projects and contingency planning to cover associated IPP development risk is an integral feature of the planning of the domestic system. Wherever IPP off-take is assumed in generation planning, it is backed by a specific contingency plan, the elements of such plans being:
(i) Identification of a fall-back project (or projects) with the location and generation characteristics that would allow it to substitute for the chosen IPP off-take. If a Preferred Scenario includes IPP off-take, the PSDP identifies a “Fall-Back” Scenario that assumes no IPP off-take.51
(ii) Specification of the substitution procedure. The procedure would involve defining trigger dates according to IPP milestones and the actions that would be initiated by the failure of the IPP project to achieve the milestones. The PPA between EdL and the IPPs for the planned off-take would contain clauses that would permit EdL to break off cleanly from its commitment without penalty if defined milestones are missed.
(iii) Development of the fall-back project(s) to the point where a substitution could be made at short notice. This would involve as a minimum taking the project through prefeasibility, feasibility and EIA processes, but it would be more convincing if it also included permitting, preparing tender documents, and arranging or underwriting a stand-by financing plan.
Domestic IPPs (selling wholly or primarily to EdL) do not feature explicitly in system expansion analyses. The SEXSI approach is economic and financing issues involved in developing domestic projects, such as the choice between public sector or private sector, are not relevant to the determination of an optimal investment plan. Financing issues are discussed in Section 9.
51 The exception is Nam Theun 2 off-take for the Central Grid. Both the EDL and EGAT PPAs are signed and Lenders’ due diligence is well advanced,and it is considered unlikely (though possible) that Nam Theun 2 will fail. To leave it out of the Central Grid Fall-Back Scenario would therefore detract from the practical usefulness of that scenario.
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Also not considered in the expansion analyses is any contribution from small projects under 10 MW. Small Power Producer (SPP) programs in other countries have been successful in attracting regional developers to develop small grid-connected power projects. SPP programs encourage developers by promoting projects small enough to be balance sheet financed in regional currencies. The time and uncertainty involved in negotiating agreements is eliminated by the use of a standard PPA and published tariff. An SPP program may be introduced in Lao PDR. Its role would be to attract capital to the sector, encourage regional developers, promote renewable energy projects and strengthen the grid through diversification of generation. It is too early to say whether such a program would make a significant contribution to EdL’s generation needs.
7.2 Planning Principles, Parameters and Constraints
7.2.1 Economic Evaluation Methodology
Power sector investments and their timing are formulated and justified on economic grounds and must meet the following criteria:
• investments must have adequate economic rates of return; and
• investments must represent, or be part of, the least-cost solution to an identified system need.
Economic assessment of alternative system expansion scenarios using SEXSI identifies the sequence of investments that maximize the benefit of scarce capital. All investments are evaluated according to common assumptions and using the same opportunity cost of capital (as represented by a 10% discount rate). The output from the PSDP system expansion studies is a least-cost investment sequence that meets system demand and reliability criteria.
Investment decisions are separate and distinct from financing decisions, which come later as part of a project’s implementation. No account is taken in the system expansion studies of the ownership, capital structure and debt financing arrangements of individual projects. These issues are addressed in Section 9.
7.2.2 Assumptions and Constraints
For the Lao system, the options and combinations that could be considered in formulating alternative generation expansion and grid interconnection scenarios are almost endless. An essential starting point in planning the system is to define reasonable boundaries to the scope of the planning exercise. A common set of assumptions and constraints were made in setting these boundaries and these are listed in Table 7.3. Standardizing assumptions as much as possible assures an even comparison between candidate investments.
All costs and benefits are expressed in constant 2003 US$. SEXSI runs have tested alternative expansion scenarios with and without the costs of emissions, and with local and global environmental and social costs.
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Table 7.3: Parameters for Power System Expansion Analysis
Parameter Adopted Value Remarks GENERAL PARAMETERS Economic Discount Rate 10% p.a. 8% and 12% for sensitivity studies Planning Period 2005-2020 Base year for costs and discounting 2003 Hydrological data series 1966 - 2002 Planning year Jan - Dec ELECTRIFICATION DEVELOPMENT Grid extension: to 2012 Based on EdL PDP PDP2002-12, July 2003 (draft) 2012 - 2020 Based on 90% GOL target of 90% electrification by 2020 after electrification target allowing for off-grid contribution. (based on EdL/JICA forecasts, where applicable). PROJECT EVALUATION Project evaluation and ranking Economic Power system expansion Economic Project supply curve (domestic projects) Financial Tariff to meet ROE of 17% and DSCR of 1.3 Cash flow benefits (export projects) Financial Taxes, royalties and dividend benefits POWER SYSTEM EXPANSION ANALYSIS Cost of Diesel Oil (Rural Areas) US$ 0.3/liter Lifetime of Diesel Plant 20 years Availability of Diesel Plant 0.80 Project life of Hydro 50 years Use 50 yrs for all projects. Hydrology 1966 - 2002 Streamflow series at project sites updated for PSDP under WB funding. Loss of Load Probability 24 hours p.a. 72 hours for sensitivity Value of unserved energy US$0.20/kWh Normally 5 to 10 times the tariff depending on level of development. Value will rise over the planning horizon as Lao PDR develops.52 Power Import Prices: Capacity: LRMC Thailand + Firm capacity & energy - based on avoided cost wheeling in Thailand Energy: SRMC Thailand Export Prices – Firmly Contracted LRMC Thailand - Firm capacity & energy – with sensitivity testing wheeling using export tariffs: (i) as negotiated for Nam Theun 2 Export Prices – non-firm Energy SRMC Thailand – (ii) existing EdL/EGAT PPA wheeling Forced outage rate of Thai 1% interconnections Average interval between major IPP Not greater than Apply target to reflect institutional capacity schemes (>200 MW) one project every 2 constraints and limits in international financial years on average market acceptance of Lao risk.
52 In the system studies, Loss of Load Probability rather than unserved energy proved to be the dominant factor.
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7.2.3 Planning Horizon
In accordance with the TOR, a planning period of 2005 to 2020 is adopted to provide a long-term perspective to overall system planning. Events and changes over the planning horizon are difficult to foresee and it is important that the PSDP is routinely and regularly updated.
Over the duration of the planning period, the ways in which projects are awarded and power is marketed will affect project preferences and optimization objectives. It cannot be assumed that the power systems within the GMS region will retain the same characteristics over the next 15 years, and the optimal configuration of projects operating individually or in combination with others may vary over the planning horizon.
Where private capital is to play a role, a planning horizon of 15 years is necessary because of typical project lead times and IPP payback periods.
7.2.4 Power Plant Data
The characteristics of hydropower plants are summarized in Section 6 and described in Volume C, Project Catalogue.
New diesel plant was assumed to cost US$ 440 per kW installed for unit sizes of 0.5 MW and 1.0 MW. The efficiency was assumed to be about 40%. The efficiency of small existing stations was taken as 28%. Other types of thermal power plant, specifically coal-fired stations, are less attractive than hydropower equivalents and, for the time being at least, not included in the expansion scenarios (although a PSS/E power system analysis might demonstrate a case for a source of generation in the Northern Region such as the Viengphouka project).
The price of diesel oil was taken as US$ 250 per tonne in Vientiane, and US$ 300 per tonne elsewhere. These prices do not include taxation and duties.
7.2.5 International Interconnections
Open trade in electricity between Lao PDR and Thailand has been assumed in the SEXSI expansion analyses. Access to each other’s markets and the price of imports and exports is subject to continuing agreement between EGAT, EdL and the governments of Lao PDR and Thailand. It has also been assumed that the existing interconnections to Thailand can be used for exports and imports alike, restricted only by the capacity of the connection. A PSS/E analysis should also check whether this is the case, or whether reinforcements of the Thai network are needed.
Existing system interconnections with Thailand and Vietnam are listed in Table 7.4. The interconnections with the EGAT grid are an important feature in planning the optimal development of the Lao system. As its system is small compared with EGAT’s, EdL can within reason import or export at its convenience as a large customer without disturbing the orderly planning of the Thai system. The strategic benefits offered by this facility do not involve sustained dependence on imports. They include the following:
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• Following the addition of new capacity to the system, surplus energy that would otherwise be wasted through spilling can be sold to EGAT until domestic demand catches up with the augmented system capacity. This trade attracts only a non-firm energy tariff and simulations confirm the intuitive position that it is better from economic and financial standpoints to delay capacity increments and meet the growing deficit with imports from Thailand until the time is reached when the new increments would be more fully employed upon entering commercial service. This allows the full economic benefit of new investments to be enjoyed from the outset.
• The timing of new capacity increments in hydro-based systems is often determined by loss of load criteria during dry years. Interconnection with the predominantly thermal Thai system allows EdL to import during dry years and thereby defer investments in new capacity.
• EdL off-take entitlements from IPP export projects offer a cost-effective source of domestic generation but the uncertainty associated with IPP commissioning dates would normally limit their usefulness. Interconnection with Thailand allows for the contingency of increasing imports for a year or two to meet deficits caused by IPP slippages.
Table 7.4: Existing Interconnections with Thailand and Vietnam
No From To Voltage № of Present Conductor Capacity Size (Lao PDR) Circuits (MVA) (mm2) Des. Op. Design Inst. 1 Theun Hinboun Nakhon Phanom (EGAT) 230 230 2 2 644 2 Houay Ho Ubon Ratcha’ni (EGAT) 230 230 2 2 644 3 Phonetong S/S Udon 1 & 2 (EGAT) 115 115 2 2 70x2=140 240 4 Thanaleng S/S Nong Khai (EGAT) 115 115 1 1 95 5 Pakxan S/S Bounkan (EGAT) 115 115 2 1 70 240 7 Thakek S/S Nakhon Phanom (EGAT) 115 22 2 2 169 6 Pakbo S/S Mukdahan 2 (EGAT) 115 115 2 1 70 240 7 Bang Yo S/S Sirindikhorn P/S (EGAT) 115 115 1 1 70 240 8 Xam Neua S/S Pahang (EVN) 35 35 1 1 4 150 9 Houay Xai Xieng Khong (PEA) 22 22 1 1 4 150 10 Kenthao Thali (PEA) 22 22 1 1 4 150 11 Bolikhamsay Vietnam (EVN) 22 22 1 1 4 150 12 Xepone Vietnam (EVN) 22 22 1 1 4 150
7.2.6 Import and Export Tariffs
Movements in the real value of future tariffs for EdL’s trade with Thailand cannot be predicted with accuracy. Stable prices were assumed based on relevant avoided costs in the Thai system as described in Section 5.8 and summarized in Table 5.17. The SEXSI analyses were performed for a range assumed tariffs as follows:
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• Imports from Thailand: 4.6 ¢/kWh and 6.1 ¢/kWh • Surplus (non-firm) exports to Thailand: 2.0 ¢/kWh and 3.0 ¢/kWh
With respect to these assumed prices, it should be noted that:
1. Assumed export tariffs are based on currently traded firm and non-firm energy prices only to the extent that such prices reflect avoided cost conditions in the Thai system. Power prices received from EGAT by Lao IPPs are higher than those received by EdL because IPP energy deliveries are guaranteed during certain hours of the day and certain days of the week, while the electricity exported by EdL is non-firm, being neither guaranteed, nor restricted to particular times. It therefore has no capacity value to EGAT.
2. Prices reflect current conditions, and changes in energy prices (gas, coal, etc.) and other external factors (e.g. carbon credits) would alter the situation.
7.3 SEXSI Power System Planning Model
The least-cost generation expansion and grid interconnection planning was conducted using the SEXSI program. SEXSI employs economic methodologies in determining the sequence and timing of system expansion investments that optimally allocates the sector’s finite resources.
SEXSI, standing for System EXpansion SImulation, is a propriety program of Lahmeyer International and is particularly suited for the analysis of power systems with a large share of hydropower. SEXSI is a simulation model. It analyzes generation expansion sequences by simulating generation projects to meet demand in order of increasing marginal cost over time. An overview of the operation of the SEXSI model is illustrated in Figure 7.2.
Figure 7.2: Computer Model for Generation System Expansion Analysis
DATA BASE demand forecast supply options fuel prices system topology economic parameters reliability targets
MAINTENANCE SCHEDULING SYSTEM OPERATION OPTIMIZATION
PROBABILISTIC PRODUCTION COSTING optimal dispatch, fuel use, LOLP, EENS, operation costs, emissions, deficits/surplus SEXSI Power Systems NEXT CALENDAR MONTH Analysis NEXT HYDROLOGICAL YEAR
NEXT DEMAND YEAR
PROBABILISTIC CASHFLOW ANALYSIS RISK QUANTIFICATION STATISTICAL ANALYSIS
INTERFACE TO FINANCIAL MODEL
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SEXSI is an ideal tool for evaluating expansion scenarios in a hydro-based system such as EdL’s. It analyzes the domestic power system in detail using a monthly time step and taking the full stochasticity of the monsoonal river flows into account. The streamflow records of power stations are entered and simulations can be conducted either for an average hydrological year or for each available hydrological year.
Net Present values and long-run average incremental generation costs of the chosen scenarios are calculated for the applicable discount rates. The minimization of Net Present Values of all future investment and operation costs is usually the key mathematical criterion in selecting the preferred system expansion scenario, but additional criteria can also be specified according to the planning objectives and characteristics of the system to arrive at a balanced decision.
The model main features are:
• full consideration of stochasticity of the hydrology • optimizes system operation and maintenance schedule • probabilistic production costing • probabilistic cashflow analysis • risk quantification • keeps track of fuel use, emissions, power and energy production of individual plants, system reliability • allows detailed comparison of competing power system expansion plans
The program considers the hydrological stochasticity of generation as follows:
• For each demand year (i.e. 2005, 2006..…2020) as many power system simulations are carried out as there are years in the hydrological data series (i.e. 1966…...2002).
• The fifteen-year demand period (2005 to 2020) can thus overlap with all fifteen year periods in the hydrological period (1966 to1981, 1967 to 1982, 1968 to 1983, etc), and within each of the hydrological sequences the end-of-year lake levels are used as starting level for the next year.
• Assuming that the hydrological history may repeat itself, altogether 30 hydrological sequences are analyzed, resulting in 30 corresponding present values for system expansion and operation.
A more detailed description of the software and its optimization methodology is provided in Annex 6.
7.4 Power System Expansion Scenarios
7.4.1 Grid Interconnection Analysis
Optimal timings of major grid interconnections were determined by preparing a number of expansion scenarios for the separate systems and evaluating them using
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SEXSI. Each of the four main grids that presently make up much of the EdL system were analyzed separately for the period up to the optimal timing of interconnection, after which it was considered as part of the main grid. The grids were combined according to a range of assumed interconnection dates and the combination yielding the lowest NPV determined the optimal interconnection date. The process involved converging on a solution by progressive refinement of expansion scenarios and assumed interconnection dates.
Implicit in this approach is consideration of demand growth in the separate grids, location and cost of new generation projects, location and capacity of interconnections with EGAT, and the cost of transmission links.
The sequence adopted in evaluating interconnection options was:
(i) Interconnection of C1 and C2.1 grids: The interconnection of the C1 and C2.1 grids, i.e. a 115 kV link between Pakxan and Thakhek, is assumed to take place as soon as possible. The need for this line has been demonstrated in several recent studies including the Hydropower Development Strategy Study (World Bank, 2000), the Masterplan of Transmission Lines and Substation Systems (JICA, 2002) and Power Sector Strategy Study (ADB, 2002).
(ii) Interconnection of C1/C2.1 and C2.2 grids: Intuitively, the interconnection of the C1/C2.1 and C2.2 grids, involving the construction of a 115 kV line from Thakhek to Pakbo (Savannakhet), will precede interconnection of the Southern Grid. Wheeling through Thailand could be less expensive but a link within Lao territory is included because of greater certainty in access and pricing. A power flow analysis of this interconnestion is needed to confirm its technical viability.
A cost of US$20 million was assumed for the line. The SEXSI simulations show that the optimal timing of this interconnection for all parameter settings is 2005 and therefore it should proceed as soon as possible (refer Table 7.5).
Table 7.5: Interconnection of C2.1 and C2.2 Grids
Import Export Best Year of Interconnection C121 and C2 Tariff Tariff Technical Technical + Technical + (USc/kWh) (USc/kWh) Cost only Local Global Environmental Environmental 4.6 2.0 2005 2005 2005 6.1 2.0 2005 2005 2010
4.6 3.0 2007 2010 2010 6.1 3.0 2007 2007 2010 Decision: As soon as possible
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(iii) Interconnection of Central and Southern Grids: Finally the combined Central grid (C1/C2.1/C2.2) is interconnected with the Southern grid. This will involve the construction of a 115 kV line from Pakbo to Pakse which, together with some southern network reinforcement, is priced at a total of US$20 million. As with the interconnection between C1 and C2, wheeling through Thailand could again be less expensive but a link within Lao territory would provide security in access and pricing.
The SEXSI simulations under most parameter assumptions show that interconnection of the Southern Grid should not occur before 2017 (refer Table 7.6).
Table 7.6: Interconnection of C2 and Southern Grids
Import Export Best Year of Interconnection C and S Tariff Tariff Technical Technical + Technical + (USc/kWh) (USc/kWh) Cost only Local Global Environmental Environmental 4.6 2.0 > 2020 > 2020 > 2020 6.1 2.0 2015 2010 2010
4.6 3.0 > 2020 > 2020 > 2020 6.1 3.0 2015 2010 2010 Decision: No interconnection for the time being, Keep monitoring situation. Interconnect around 2010 at the earliest
Details of the SEXSI scenarios and the results of the interconnection simulations are provided in Annex 6.
The Central and Southern grids will both continue to be extended under on-going programs of 115 kV transmission development (refer Section 7.5).
7.4.2 System Development – Northern Supply Area
The major centers in the northern provinces of Oudomxai and Luangnamtha (both 2006), and Phongsaly (2009) will be connected to the Central Grid under the Power Transmission and Distribution Project (ADB PTD2). Later, Sam Neua (2015) will be connected under PTD3. The loads from these centers are included in the system generation planning as part of the Central Grid.
Several generation projects in the Northern Supply Area were evaluated but none performed well. However, a small to medium project of 10 - 50 MW such as Nam Long or Viengphouka may nevertheless be justified on the basis of ancillary benefits such as:
• voltage support to the long 115 kV interconnection to the Central Grid;
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• security of supply through reduced vulnerability to transmission outages;
• lower transmission losses through proximity of load and generation.
It is recommended that a prefeasibility study of a project in the Northern Supply Area such as Nam Long is is undertaken.
7.4.3 System Development – Central Grid
The demand forecast for the Central Grid is shown in Figure 7.3. Industrial, mining and agricultural development is causing the load in the Central Grid to increase rapidly. Least-cost scenarios for meeting this demand at involve a Preferred Scenario relying on IPP off-take from the Theun Hinboun Expansion and Nam Teun 2 projects, and a second “Fall-Back Scenario” providing a least-cost alternative in which IPP development risk is reduced.
Figure 7.3: Forecast Demand in Central Grid
(i) Central Grid – Preferred Scenario
There are a number of project sites that could be developed to meet the Central Grid load but the expansion scenario with the lowest NPV obtained its generation from competitively priced domestic IPP electricity allocations. Off-
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take from Theun Hinboun Expansion (105 MW) and Nam Theun 2 (75 MW) projects are assumed to be available in 2008 and 2010 respectively. Imports from Thailand provide the cheapest means of meeting load growth till then (and, in fact, given the lead times for new projects, there is no alternative to imports for the period up to 2008).
By the time the Nam Theun 2 and Theun Hinboun off-take entitlements have been fully absorbed, the Central Grid would have grown to more than 400 MW through interconnection and load growth, allowing the possibility of larger capacity increments and larger unit sizes. Under these conditions, the most attractive augmentation strategy is the development of Nam Ngiep 1 as a domestic project in time for commercial operation in 2014. 53 Nam Ngiep 1 is nominated as an export IPP project. Its generation characteristics and location make it an ideal project for supplying the Central Grid and with bilateral and multilateral support it could be developed instead as a domestic IPP
To summarize, under the Preferred Scenario rising demand in the Central Grid to 2020 will be met by (refer Figure 7.4):
• increasing imports from EGAT over the period up to 2008, the assumed date for commissioning the Theun Hinboun Expansion project. Imports, as a percentage of total energy, would peak at 30% in 2007;
• from 2008 onwards, purchase of all output from the new Theun Hinboun unit (Unit 3, 105 MW) from the Theun Hinboun Power Company;
• from 2010 onwards, purchase of EdL’s domestic off-take entitlement of 300 GWh (75 MW) from the Nam Theun 2 Power Company;
• commissioning the Nam Ngiep 1 project (213 MW) by 2014 either as an EdL development or a private domestic project.
Figure 7.4 illustrates the variations in the levels of imports and the fluctuations in the Loss of Load Probability (LOLP) under the Preferred Scenario. It is a robust scenario, being relatively insensitive to delays or cancellations in the three selected generation projects. The least-cost reaction to delays or cancellations would be to step up cross-border imports from Thailand through existing transmission facilities. At higher cost, smaller domestic projects such as Nam Ngum 5, Nam Bak 2B or Nam Pot could be substituted to fill the gap – this possibility is analyzed under the Fall-Back Scenario.
The Preferred Scenario is least-cost because it exploits the economies of scale of larger plant. It also minimizes EdL’s capital commitments over the next five years, and reduces the construction risks and institutional problems associated with project-managing multiple concurrent projects.
53 The timing of Nam Ngiep 1 is not governed by system reliability. It could be deferred until 2019 without compromising LOLP criteria. It is advanced to 2014 for least cost reasons.
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(ii) Central Grid – Fall-Back Scenario
As outlined in Section 7.1.5, a Fall-Back Scenario is also prepared involving IPP off-take from only Nam Theun 2, a project with an acceptably low IPP development risk. In the Central Grid, this corresponds to the substitution of three medium sized projects, Nam Ngum 5, Nam Bak 2B and Nam Pot, for the Theun Hinboun Expansion off-take excluding the off-take from the Theun Hinboun Expansion project (refer Figure 7.5).
The NPV of the Fall-Back scenario is 5% higher than the Preferred Scenario (US$ 607 million compared with US$ 572 million) but has the additional disadvantage of committing EdL to significant capital expenditure in the period from 2005 to 2010.
Under the Fall-Back Scenario, the least-cost strategy for meeting rising demand in the Central Grid to 2020 involves:
• increasing imports from EGAT over the period up to 2010. Imports, as a percentage of total energy, would peak at about 38% in 2010; • commission Nam Ngiep 1 (213 MW) by 2010; • from 2010 onwards, purchase EdL’s domestic off-take entitlement of 300 GWh (75 MW) from the Nam Theun 2 Power Company; • commission Nam Ngum 5 (45 MW) by 2012; • commission Nam Bak 2B (50 MW) by 2015; • commission Nam Pot (12 MW) by 2018.
The sequence of domestic projects is optimized to maintain imports at acceptable levels from 2010 and to meet system LOLP reliability targets.
As part of the Fall-Back strategy, it is recommended that project studies are prepared for the projects included in the scenario. A prefeasibility study for Nam Ngum 5 already exists and it is understood that a developer with a new mandate for the site is updating this. Another developer holds an MOU for the Nam Bak 2B project and plans to undertake feasibility level studies of the project as part of its obligations under that mandate.54 Another promising candidate, the Nam Sane 3 project, should also be investigated to prefeasibility level at least.55
SEXSI outputs for the Central Grid expansion analysis are provided in Annex 6. They provide details of the NPV differences between the Preferred Scenario, the Fall-Back Scenario and other tested scenarios.
54 The developer of the Nam Bak 2B project is understood to be evaluating it as a trans-basin run-of-river project. The SEXSI system expansion analyses identify an optimal system role for the project as a storage project offering a dry season capacity benefit. 55 In a technical sense, Nam Sane 3 is a good site but the project was not included in the system expansion scenarios because of information about the extent of resettlement involved. Accounts from other sources now suggest this to be overstated.
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Figure 7.4: Central Grid System Expansion 2005 - 2020 Preferred Scenario
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Figure 7.5: Central Grid System Expansion 2005 - 2020 Fall-Back Scenario
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7.4.4 Development Scenarios - Southern Grid
Expansion planning in the Southern Grid assumes that interconnection with the Central Grid is still many years away (refer Section 7.4.1). Existing plant in the Southern Grid is run-of-river and dry season generation requirements are obtained largely through imports. Demand in southern Lao PDR is rising rapidly and additional power is needed immediately to cover dry season demand in particular. In the short term, therefore, a second 115 kV interconnection with Thailand is proposed so that system reliability targets can be maintained until another source of domestic generation can be developed. The addition of this line is common to all reasonable scenarios investigated for the Southern Grid.
The scenario for meeting demand in the Southern Grid at least-cost does not involve IPP off-take and, therefore, a “Fall-Back Scenario” free of IPP development risk is not needed. However, the situation in the Southern Grid is complicated by other issues that require additional least-cost scenarios that explore certain eventualities.
(i) Southern Grid – Preferred Scenario
The least-cost path strategy for meeting demand in the Southern Grid assumes that Houay Lamphan Gnai is developed as soon as possible. The NPV of the Preferred Scenario is US$ 95 million.
Under the Preferred Scenario, rising demand in the Southern Grid to 2020 is therefore met by the following additions (refer Figure 7.6):
• A second 115 kV link with Thailand is constructed immediately and imports from EGAT are increased until Houay Lamphan Gnai can be brought on-line. Based on a COD for Houay Lamphan Gnai of 2010, imports, as a percentage of total energy, would peak at about 55% in 2009.
• Houay Lamphan Gnai is built and commissioned by 2010. It is configured as a 60 MW storage project with good dry season generation characteristics.
• No additional generating plant would be needed for the remainfder of the planning horizon with the system installed capacity and EGAT interconnections being sufficient to meet demand and maintain system reliability targets. After commissioning Houay Lamphan Gnai in 2010, imports would gradually rise from about 12% to around 36% in 2020.
The Houay Lamphan Gnai site has not been investigated beyond inventory level. A field team that included a geologist has visited the site but its catchment is ungauged. A prefeasibility level study should be undertaken as soon as possible to confirm the project’s promise.
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Figure 7.6: Southern Grid System Expansion 2005 – 2020 Preferred Scenario
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(ii) Southern Grid – “Thakho” Scenario
From a technical and financial standpoint, the preferred least-cost expansion plan would involve a run-of-river development of about 60 MW on an arm of the Mekong at Kone Falls. Generation costs of Thakho are low and generation during the dry season is greatest during the dry season when it is most needed by the system. (High tailwater levels reduce wet season output.) In this sense the generation characteristics neatly complement the existing Selabam and Xeset 1 run-of-river plants.
The Thakho generation expansion scenario is depicted in Figure 7.7. It is similar to the Preferred Scenario and involves a second 115 kV interconnection with Thailand being built to meet demand growth until Thakho can be built. Imports rise to about 55% before Thakho is commissioned in 2010.
A small capacity increment is needed later in the planning period to maintain system security and Xe Katam has been inserted for this purpose. The Xe Katam development evaluated in the PSDP did not perform well under release assumptions designed to protect the Xe Katam falls, but it is understood that the developer currently holding the mandate for the site is proposing an alternative layout that would improve its performance.
The NPV of the Thakho Scenario (US$ 83 million) is 13% lower than that of the Preferred Scenario. Once Thakho enters commercial service, imports would remain below 10% of the total generation requirement for the remainder of the planning period.
However, Thakho could be the focus of international opposition because of the sensitivity of its location in the Seephandom reach of the Mekong and the potential threat it poses to the aesthetic and ecological attributes of the area. Expected impacts of the project could also extend into Cambodia and this might further complicate its implementation. Though the proposed development is discreet, widespread organized opposition is possible and the potential harm to GOL’s broader objectives could be out of proportion to the benefits of the project (as measured by the US$ 12 million differential between the NPVs of the Thakho and Preferred scenarios).
For these reasons, the Thakho Scenario is not the “Preferred Scenario” but it should not be discarded unless and until the project’s likely impacts have been closely studied and shown to justify such a decision.
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Figure 7.7: Southern Grid System Expansion 2005 – 2020 Thakho Scenario
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(iii) Southern Grid – “Xe Kaman 3” Scenario
The Xe Kaman 3 project, being a 250 MW development on a good site, can offer a competitive cost of generation. The project is being developed as an IPP by a primarily Vietnamese joint venture and if it were to be commissioned on or before 2010, part of its output could be used to supply the Southern Grid. A scenario based on an assumed off-take allocation of 20% of its output (50 MW) was simulated using SEXSI (refer Figure 7.8). It is understood that the governments of Vietnam and Lao PDR are discussing a tariff of around 4 ¢/kWh and this value was used in the generation expansion simulations.
A 115 kV transmission interconnection with a future Attapeu substation is assumed and was priced in the simulations at US$ 4 million.56
The present value of this scenario is about US$ 113 million, or about 19% higher than the Preferred Scenario.
An advantage of the Xe Kaman 3 Scenario is that it avoids significant capital expenditure over the next 5 or 6 years. A weakness of the Xe Kaman 3 Scenario, though, is IPP development risk. If the scenario is adopted, a fall- back project (or projects) would need to be groomed as a contingency measure so that a substitution can be made at short notice should the Xe Kaman 3 project not proceed.
(iv) Southern Grid – “Xeset” Scenarios
The technical attributes of the Xeset 2 and Xeset 3 projects are examined in Section 6.7.5. Their performances were evaluated within the context of an optimized Xe Set basin and in a conjunctive operation arrangement with the Houay Ho IPP project.
56 The Xe Kaman 3 interconnection could be built as a 230 kV line to provide a more robust link between the Vietnamese, Lao and Thai systems. The power system problems of such an idea could be considerable and were not investigated as part of the PSDP.
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Figure 7.8: Southern Grid System Expansion 2005 – 2020 Xe Kamam 3 Scenario
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Least-cost expansion simulations were undertaken that assumed the Xeset 2 and 3 projects are commissioned in 2008, as planned by EdL. The simulations explored the cases of with and without Houay Ho and least-cost scenarios were developed for each (refer Figures 7.9 and 7.10). Under the “Xeset 2 & 3” Scenarios, the least-cost strategy for meeting rising demand in the Southern Grid to 2020 involves the following:
• A second 115 kV link with Thailand is constructed immediately and imports from EGAT are increased until Xeset 2 and 3 are commissioned in 2008.
• Xeset 2 (76 MW) and Xeset 3 (16 MW) enter commercial service in 2008. In practice, Xeset 3 would be developed sequentially rather than concurrently and would therefore be commissioned, say, 18 months after Xeset 2. However, Xeset 3 is a small project and a simplifying assumption is made that they are both completed together. A marginal improvement in the scenario NPVs could be expected by more accurately modeling the Xeset 3 capital cash flows.
• The least-cost path would involve no further generation projects if conjunctive operation with Houay Ho is allowed. Without Houay Ho to firm the output from the Xeset projects, high LOLP values in the last years of the planning period would justify a third generation project late in the planning period.
Figures 7.9 and 7.10 illustrate the beneficial effect of Houay Ho on an expansion strategy based on the Xeset projects. Imports of firm energy are less and the dumping of non-firm energy in the Thai market is reduced.
Without Houay Ho regulation, the NPV of the least-cost scenario is US$ 152 million, 60% higher than that of the Preferred Scenario based on Houay Lamphan Gnai. By 2015, import dependency under the Xeset Scenario is 44% of total energy requirements compared with 25% for the Preferred Scenario.
Conjunctive operation with Houay Ho improves the situation. Assuming that that Houay Ho and EGAT together receive 20% of the unregulated energy from Xeset 2 and 3 as consideration for the firming of the output, the NPV of the scenario reduces to US$ 143 million, still 50% higher than that of the Preferred Scenario.
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Figure 7.9: Southern Grid System Expansion 2005 – 2020 Xeset Scenario without Houay Ho
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Figure 7.10: Southern Grid System Expansion 2005 – 2020 Xeset Scenario with Houay Ho
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If Houay Lamphan Gnai is added as a third project to the Xeset Scenario, the NPV improves marginally to US$ 142 million, and the 2020 energy dependency reduces from 37% to 10%.
Of the projects nominated as candidates for supplying the Southern Grid, Xe Kaman 3 and Xeset 2 have already been studied to feasibility level. Two key projects that have not been studied in any detail, though, are Houay Lamphan Gnai and Thakho, and arrangements should be made to redress this gap as soon as possible.
7.4.5 Sensitivity of Expansion Plans to Demand
Conclusions drawn from system expansion studies about the sequence and timing of generation investments were tested for sensitivity to demand. It was found generally that the projects and their CODs were insensitive to lower than expected demand. Those investments that may be sensitive occur late in the planning period and would be re-evaluated several times before implementation as part of a normal periodic planning updates.
7.4.6 Preparation of Domestic Generation Projects
Generation projects identified in the SEXSI system expansion analysis as part of the Preferred Scenarios for supplying the the Central and Southern grids are listed in Table 7.7. These and other shortlisted projects have been evaluated at an ICF that is optimal in the context of the least-cost power system expansion scenario in the grid it supplies.
Table 7.7: Domestic Generation Projects in Expansion Scenarios
Project COD Grid Inst. Capacity (MW)
Preferred Scenarios: Theun Hinboun Expansion Off-take 2008 Central 105 Nam Theun 2 Off-take 2010 Central 75 Houay Lamphan Gnai 2010 Southern 60 Nam Ngiep 1 (inc reg dam) 2013 Central 213
Other Scenarios: Nam Ngum 5 2012 Central 45 Nam Bak 2B 2015 Central 50 Nam Pot 2018 Central 12 Xeset 2 and 3 2008 Southern 76 Thakho 2010 Southern 16
Much of the work described in the preceding paragraphs is based on project evaluations that are still at inventory level. To this extent the proposed scenarios need confirmation and before moving to the financing and implementation phases of the projects, it is important that they are evaluated in more detail to eliminate as many
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of the hydrological, geological, environmental and other technical and economic uncertainties as possible. As a matter of priority, prefeasibility level and, as appropriate, feasibility level studies should be carried out for projects forming part of the Preferred Scenarios and the alternative scenarios described above. Some projects have already been studied to feasibility or prefeasibility levels (refer Table 6.13), but those sites needing urgent appraisal include the following:
• Houay Lamphan Gnai: As an immediate priority, a stream gauge should be established at the proposed dam site and a prefeasibility study undertaken. This should flow straight into a full feasibility study and EIA if the prefeasibility study supports the conclusions of several inventory level studies.
• Nam Ngum 5: It is understood that a Chinese developer has been awarded the mandate to develop Nam Ngum 5 and is in the process of undertaking a study to extend the work already performed during the time Melkyma held the mandate.
• Nam Bak 2B: A developer recently signed an MOU with GOL for the development of the Nam Bak 2B project and has issued an inventory level appraisal document. The study proposed a run-of-river layout with an attractive average generation cost but the design did not perform well in a system context because of its fit poor dry season production. A storage was added to the PSDP configuration. This increased the capital cost but improved its performance in system expansion scenarios. There are a number of untested possibilities that could further improve its performance. An increase in the installed capacity at Nam Ngum 1 would create conjunctive operation opportunities that could be exploited by a Nam Bak 2B run-of-river arrangement. A feasibility study with a wide TOR is needed.
• Nam Pot: A prefeasibility study and, if warranted, a feasibility study of Nam Pot should be conducted to determine the merit of the Nam Pot project.
• Nam Sane 3: The point of immediate interest with the Nam Sane 3 project is resettlement. The projected economic performance of the project is promising but reports of large numbers living in the reservoir area discourage interest. Estimates of resettlement vary widely and it needs to be established definitively whether it is manageable.
• Thakho: The Thakho project is similar in the sense that it is attractive from an economic viewpoint but has particular environmental questions that need to be answered before it can be included as a candidate. In the case of Thakho, the problem is not specific but relates to a general sensitivity of the project location. The environmental importance of the Seephandom reach of the Mekong is recognized internationally. More particular concerns include the effects of construction blasting on a pod of freshwater dolphins that feed at the base of the Khone Falls. A study is needed to allay such concerns.
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7.5 National Transmission Development
7.5.1 Transmission Objectives
The objectives of national transmission development are to achieve the following at least-cost:
• extend the reach of the grid in pursuit of GOL’s electification objectives; • connect sources of generation within Lao PDR to the grid; • achieve and maintain power system reliability targets; • interconnect Lao grids with neighboring countries to facilitate least-cost supply and power trade objectives.
Strategic transmission planning generally responds to the following factors:
• electrification targets • generation technologies for electrification • social and environmental considerations • size and rate of demand growth within the separate grids; • technical considerations (voltage drop, cost of losses, capacity) • quality and reliability of supply considerations • large single point loads of an industrial or commercial nature • location of new generation projects; • proximity of unserved Lao load to substations in neighboring countries; • relative cost of electricity in the grids to be interconnected;
In pursuit of the broader power system development objectives (refer Section 7.1) EdL, JICA and others have prepared optimal transmission plans for interconnecting EdL’s separate grids, linking generation projects and generally reinforcing and extending the system.
The grid interconnection strategy has been independently modeled as part of the PSDP. EdL’s plans for extending its transmission grids were reviewed. Planned transmission developments are listed in EdL’s PDP and reproduced in Table 7.8. The additional load captured by these extensions to the 115 kV system have been included in the PSDP demand forecast.
7.5.2 Transmission Planning
One of the issues facing power planners of the Lao power system is the increasingly marginal nature of investments in EdL’s transmission and distribution developments. High-density loads such as urban and provincial centers and high demand agricultural areas along the major river valleys have already been, or soon will be, electrified. As the grid extends out of the valleys and into the mountains beyond, loads will be smaller and more dispersed and the topography more difficult. Where villages and households are located more than about 100 km from an existing or planned substation, technical constraints of voltage drop, excessive losses and capacity are factors that must be considered and may involve additional HV transmission infrastructure to reach them.
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Thus, the costs of transmission line and substation development for new areas will be higher and spread over fewer households, resulting in lower economic returns from the marginal investment dollar. In acknowledgement of these diminishing returns, transmission development for electrirfication of remote areas should be prioritized as follows:
1. As a first priority, target areas for electrification should be within 100 kilometers of transmission lines that are either:
• existing or under construction;
• planned 115 kV extensions that have the backing of a funding agency; or
• planned new 115 kV lines that are to be built for other purposes such as interconnecting new generation projects (e.g. Nam Theun 2), or as feeder lines to large industrial or commercial projects (e.g. Xepon mine);
2. Extend the EdL grid to population centers according to economic criteria based on the cost of new lines and the potential benefits of electrification;
3. Wherever cost-effective means are available, adopt alternative distributed off- grid generation technologies for areas beyond the economic reach of the grid.
Electrification of the more remote geographic regions could be deferred to a time when the grid has moved closer or new and more advanced off-grid technologies are available to provide electrification at reasonable cost.
7.5.3 Grid Interconnection
Interconnection of the separate EdL grids was simulated using the SEXSI software to determine optimal interconnection dates as part of the processs of identifying least- cost generation expansion scenarios. The work is described in Section 7.4.1. The key conclusions are:
• Interconnection of the C1, C2.1 and C2.2 grids should proceed as soon as possible;
• Interconnection of the Southern Grid and the enlarged Central Grid is not economically justified until 2017.
Technical interconnection issues not studied in detail under the PSDP include:
• The voltage and capacity of transmission interconnections (115 kV, 230 kV, size of conductor, number of circuits);
• The voltage at which the interconnections should be energized, both initially and ultimately.
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Table 7.8: Planned EdL 115 kV Transmission Development
From To km kV Cond- № of uctor Circuits
Under Construction: Thalat Non Hai 100 115 240 1 Xieng Nguen Xayabury 76 115 240 1 Nam Leuk Phonsavan 164 115 240 1 Pakbo Kengkok 52 115 240 1
Planned: Nam Mang 3 Thanaleng 51 115 240 2 Khoksaad Naxaythong 18 115 240 1 Mahaxay Sepone mine 150 115 240 1 Thakhek Nam Theun 2 68 115 240 2 Ban Jiangxai (Pakse) Ban Hat (Thakho) 123 115 240 2 Xeset 1 & 2 Paksong 39 115 240 2 Pakxan Thakhek 180 115 400 4 Thakhek Pakbo 93 115 240 2 Nam Ngum 1 Thalat 5 115 240 1 Hin Heup Vang Vieng 46 115 240 1 Luang Prabang Oudomxai 173 115 240 2 Oudomxai Luangnamtha 79 115 240 1 Namo Boun Neua 96 115 240 1 Ban Hat (Thakho) Cambodian border 30 115 240 1 Ban Na Attapeu 123 115 240 2 Nam Lik Ban Don 6 115 240 2 Ban Don Thalat (add a cct) 48 115 240 1 Xepon P/S Saravan 98 115 240 1 Xepon town Xepon P/S 78 115 240 2 Xepon town Xepon mine 36 115 240 1 Xepon town Kengkok 140 115 240 2 Xayabury Paklay / Nonhai 223 115 240 1 Viengphouka Luangnamtha 56 115 240 2 Viengphouka Houayxai 95 115 240 1 Xeset 1 Saravan 32 115 240 1 Pakbo Kengkok (add a cct) 50 115 240 1 Hongsa Xayaburi 64 115 240 1 Nam Leuk Pakxan (add a cct) 85 115 240 1 Ban Jiangxai (Pakse) Xeset 1 76 115 240 2 H. Lamphan Gnai Sekong / Saravan 76 115 240 2 Kengkok Ban Jiangxai (Pakse) 180 115 240 2 Phoukhoun Phonsavan 100 115 240 1 Phonsavan Sam Neua 152 115 240 1 Nam Ngum 5 Phoukhoun 26 115 240 2 Vangvieng Phoukhoun 72 115 240 2 Phoukhoun Luang Prabang 75 115 240 2 Thalat Vangvieng 64 115 240 1 Source: EdL Power Development Plan 2002-12, July 2003
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The EdL PDP and the JICA study looked more closely at these aspects. During the preparation of the PDP, detailed load flow studies were carried out by the EdL System Planning Department using PSS/E computer software. This department has developed considerable skill in power systems modeling, and updates the load flow model for the interconnected Lao and Thai systems on a regular basis. The outputs of the load flow studies were reviewed.
EdL plans to interconnect the networks using double circuit 115 kV transmission lines in preference to a 230 kV solution. Due to the long distances involved, extensive capacitive voltage support will be required to maximize power transfer between the grids. To ensure that the 115 kV option is optimal, the following should be carried out:
• Power system stability studies to test the stability of the proposed design (EdL do not have the system stability module of PSS/E);
• System modeling of a 230 kV grid interconnection, including financial and economic modeling, to test the viability of this alternative and compare it with a 115 kV interconnection.
7.5.4 Extension of the EdL Grids
Planned extensions to the EdL grid are outlined in Table 7.8 and depicted in Figure 7.1. This effectively provides a blueprint for absorbing most of the remaining load centers of any significance into the grid.
Under the ADB PTD2 and PTD3 loans, provincial centers in the northern provinces of Oudomxai, Luangnamtha, Phongsaly and Hua Phan will be connected to the Central 115 kV grid by 2007, 2007, 2009 and 2015 respectively. Other interconnections are contingent on related developments and available finance. The interconnection of Houayxai, for instance, is tied to the construction of the Viengphouka thermal plant.
In the Southern Grid, the construction of a 115 kV line from Pakse to Thakho is proceeding under finance from the Export-Import Bank of China, and a tee-off from this line, to be developed with Indian finance, will link Attapeu to the Southern Grid.
The EdL PDP also outlines the costing and proposed funding arrangements for the pipeline of 115 kV transmission projects to 2007 (refer Table 7.9).
7.5.5 Impact of IPP Schemes on National Grid Development
Foreseeable IPP development could have some influence on the pace and direction of domestic transmission development, although the effects are likely to be localized. Domestic grid expansion and reinforcement in the central part of Lao PDR will emerge from the development of the Nam Theun 2, Theun Hinboun Expansion and Sepone mine developments, and from the interconnection of the C1, C2.1 and C2.2 grids.
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Table 7.9: EdL Planned 115 kV Transmission Development, 2004 - 2007
Project Financing Agency Comm Year 1 Nam Mang 3 – Khoksaad – Thanaleng – Naxaythong CWE, China Exim 2005 2 Ban Jiangxai (Pakse) – Ban Na – Ban Hat (Thakho) CERIECO, China Exim 2005 3 Mahaxay – Xepon Mine EdL / EGAT 2005 4 Nam Theun 2 – Thakhek NTPC 2005 5 Xeset 1 – Xeset 2 – Paksong NORICO, China Exim 2006 6 Pakxan – Thakek not identified 2006 7 Thakek – Pakbo (Savannakhet) not identified 2006 8 Nam Ngum 1 – Thalat (2nd circuit) ADB, NDF 2006 9 Thalat – Hin Heup – Vang Vieng (2nd circuit) ADB, NDF, GOL 2006 10 Luang Prabang – Oudomxai – Luang Nam Tha ADB, NDF and GOL 2007 11 Ban Hat – Cambodian border India Exim 2007 12 Ban Na to Attapeu India Exim 2007 13 Nam Mo – Boun Neua ADB, NDF 2007 Source: EdL Power Development Plan 2002-12, July 2003
The absorption of domestic off-take from the Xe Kaman 3 project would require the construction of a 115 kV line of almost 100 km in length to interconnect the project with the Southern Grid. With the completion of the Ban Na to Attapeu transmission line, the Xe Kaman 3 project could play a useful role in supporting and extending this connection. The route is sparsely populated but a road from Pakse to Vietnam is planned and this could increase the potential electrification benefits of the line.
Were IPP prospects on the Xe Kong and Nam Ngum rivers to proceed, opportunities for extending and strengthening the EdL grid would open up in these areas. Provision for domestic off-take are routinely included in IPP concession negotiations. Even small amounts of generation would increase voltage stability in weak networks by generating Vars during times of high load and absorbing Vars at low load.
The influence of IPP projects on GMS grid development is explored in Section 8.3.
7.6 MV and Distribution Planning
7.6.1 Distribution Objectives
The objectives of distribution development are integral with transmission objectives in expanding access to electricity at least cost. Distribution investment decisions must consider the following:
• electrification targets • marginal costs of grid based distribution system expansion • alternative technologies for electrification • social and environmental considerations • size and rate of demand growth • technical considerations (voltage drop, cost of losses, capacity)
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• quality of supply considerations • large single point loads of an industrial or commercial nature • location of new 220/115/22 kV substations; • proximity of unserved Lao load to distribution grids in neighboring countries; • relative cost of electricity in the grids to be interconnected;
These factors are largely covered in this report in the context of transmission and generation planning.
GOL’s electrification target of 90% of households by the year 2020 provides the overarching objective but the factor that will most decide the rate at which the distribution system expands is the availability of funds. Funding for distribution expansion in Southern Lao PDR, for example, will shortly be in place for the next 90,000 households, but beyond this there is a funding gap.
7.6.2 Marginal Costs of Grid Based Distribution
During the identification of the SPRE II project (2003) in the Central 1, Central 2 and Southern Region, the marginal costs of grid-based distribution extension was established for the 90,000 households targeted by that program. The calculation covered the 22 kV component, the 400/230 volt component and house wiring and the marginal cost values are provided in Table 7.10. The costs identified in the Central 1, Central 2 and Southern Regions are indicative of costs that could also be expected in the Northern Supply Area.
Table 7.10: Average Distribution Costs
Description Cost per house
Cost per household for 22 kV, 400/230 V, service US$ 450 – US$ 550 drop, electricity meter and house wiring Cost per household for service drop, electricity US$ 50 – US$ 100 meter and house wiring
The costs given in Table 7.10 result in a cost of 2.9 to 3.3 ¢/kWh for distribution based on the following assumptions:
• Cost per household for 22 kV, 400/230V, service drop, electricity meter and house wiring is within the range US$450 to US$550
• 10% discount rate, 2% operations and maintenance costs
• Project life of 2004 - 2025
• Energy consumption for customer categories as follows:
- Urban customers, and rural customers with main road access: 84 kWh per month in 2004, growing to 157 kWh per month in 2025
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- Rural customers without road access: 9 kWh per month in 2004, growing to 17 kWh per month in 2025
Options exist for further reducing the costs of distribution to rural customers and should be evaluated. These include:
• The use of single wire earth return (SWER) technology, whereby one conductor is used instead of two for single-phase medium voltage reticulation. This technology can reduce the cost of single phase MV distribution from US$ 4,200 per km for conventional two wire systems to US$ 3,100 per km for SWER systems;
• Installation of so-called “ready boards”, or combined prewired fuse boards and meter boards, to reduce the cost of house wiring;
• Effective procurement methods based on competitive and transparent processes, and bulk purchasing to further drive down the cost of materials and equipment.
7.7 Off-Grid Development
7.7.1 Off-Grid Targets
A component in GOL’s strategy for meeting its 2020 electrification target of 90% and its intermediate targets is its off-grid household electrification program employing conventional off-grid technologies includes solar, micro hydro and diesel mini grids.
Off-grid development is promoted by GOL and a number of development agencies as a means of bringing affordable electricity to remote communities for whom there is little prospect of grid electrification in the coming years. A successful but embryonic program of off-grid electrification employing state, donor and private resources is underway in Lao PDR. The Off-Grid Renewable Energy Electrification Pilot Project is a sub-component of the Southern Provinces Rural Electrification I Project and it is to provide the platform for expanding the off-grid program to achieve 150,000 “pre-grid” household installations by 2020.
Off-grid targets are specified in Table 7.11. The off-grid (or “pre-grid”) targets were fixed by examining the total electrification target in terms or rural households and then preparing an off-grid target as a subset of this. The term “pre-grid” is used to include within the definintion those installations that may in time be overtaken by the expansion of the grid. The pre-grid electrification numbers given in Table 7.11 are based on targets developed in consultaion with DOE. Due to the entrepreneurial nature of the program, the numbers of installations may vary widely from those indicated.
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Table 7.11: Off-Grid Electrification Targets
Forecast Scenario 2003 2005 2010 2015 2020 Pre-grid 0% 0% 5% 7% 12% Grid Conversion 0% 0% 2% 5% 10% Off-Grid 0% 0% 5% 7% 10% Pre-grid Households 310 1,325 50,000 86,603 150,000
7.7.2 Off-Grid Renewable Energy Electrification Pilot Project
Implementation of the Off-Grid Renewable Energy Electrification Pilot Project began in 1999 as a sub-component of the SPRE I project and the program’s scheduled completion date is June 2004. It is funded by a GEF grant of US$ 744,000 and an IDA credit of US$ 900,000 (subsequently increased by US$ 370,000 released from contingency funds). Its aims are to establish the capacity for the sustainable implementation of off-grid systems through the involvement of the private sector, with an emphasis on cost recovery from operations and the use of low-cost technologies.
The sub-component was designed as a pilot project, to develop an off-grid delivery system and test it in 46 villages. Initially an off-grid team within EdL managed the project. Ten pilot installations were undertaken and the experience gained from them was applied in developing low-cost and robust technologies and delivery mechanisms using village entrepreneurs.
The need to take policy and regulatory decisions as part of the development of the system, as well as the need for on-going support visits to villages, led to the transfer of responsibility for the off-grid program to the Department of Electricity (DOE) within MIH. An Off-Grid Promotion and Support Office (OPS) was established under DOE to investigate various models for establishing Energy Service Companies (ESCOs). Initial attempts to implement national ESCOs failed due to the reluctance of private companies and NGOs to adopt this role. OPS then adopted a model involving the appointment of new provincial ESCOs, contracted to OPS and supporting a network of Village Electrification Managers (VEMs). The ESCOs and VEMs are required to follow a participatory planning process designed by OPS and to install and service systems, as well as collect payments for remittance to OPS. Performance based payments to the ESCOs and VEMs are linked to their performance in planning, installation, payment collection and reporting.
The program is currently active in only seven provinces, namely Champassak, Luang Namtha, Luang Prabang, Sayaboury, Oudomxai, Xieng Khouang and Vientiane.
The institutional model is described in Figure 7.11.
7.7.3 Off-Grid Technologies
OPS promotes various off-grid technologies and selects the most appropriate according to the circumstances of each particular site. One non-renewable and two renewable energy technologies are being supported as follows:
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• Micro diesel gensets / micro distribution grids. • Individual solar home systems of 20, 30, 40 and 50 Wp capacities. • Micro hydro / micro distribution grids.
Of these, the vast majority of installations to date are solar home systems.,
A summary of households for which electrification has been implemented, planned and projected under the program to July 2004 is provided in Table 7.12.
Figure 7.11: Off-Grid Institutional Arrangement MIH Rural Equipment IDA Electrification suppliers Model IDA C redit Procurement [1] Provincial Department of Off-Grid Promotion and Industry and Handicrafts Support Office (OPS) (PDIH) Planning / Installation / Post-Installation / ESC O Operational Rebates
Energy Services VEAC Operational Company (ESCO) Support Payments Installation / Post-Installation / VEM Operational Support Payments C ustomer Installation Fees / Village Electricity Village Electricity Hire Purchase Payments [2] Advisory C ommittee Manager (VEM) (VEAC ) C ustomer Installation Notes Fees / Hire Purchase [1] ESC Os are expected to assume responsibility for Payments procurement as their capacity develops
[2] In practice, VEMs generally pay hire purchase Key payments to ESC Os, retaining a portion to cover Customers payment flows payments due to the VEM, and ESC Os onpay hire purchase payments to OPS, similarly retaining a contract portion to cover payments due to the ESC O
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Table 7.12: Off-Grid Electrification Program to July 2004
Province ESCO / Type Electrified Planned Total Electrified Rep (Up to Feb-04) (Mar-04 to Jul-04) (to Jul-04) Establ’d Villages H’holds Villages H’holds Villages H’holds Champassak Sep-02 SHS 18 1,060 1 189 19 1,249 Luangnamtha Apr-02 SHS 30 743 2 158 32 901 Luang Prabang None1 VH 1 58 0 0 1 58 Oudomxai Apr-02 SHS 18 612 26 550 44 1,162 Sayabouri2 Aug-03 SHS 0 0 9 500 9 500 Vientiane Apr-02 SHS 22 830 13 403 35 1,233 Xieng Khouang Mar-03 GS 1 94 0 0 1 94 Unallocated SHS 188 Total 90 3,397 51 1800 141 5,385
1 Established as a pilot project under EdL VEM is contracted directly to MIH. 2 Two ESCO contracts, covering separate districts, have been awarded.
7.8 Domestic Power System Investments
7.8.1 Overview
Least cost development of the Lao power system as proposed in this Section 7 involves a sequence of generation, transmission, distribution and off-grid investments. The development sequence is formulated from the SEXSI analyses to satisfy projected demand and meet other electrification objectives.
The EdL PDP sets out a capital investment program having the same objectives but it differs from the PSDP development sequence in a number of respects:
• differences in demand forecast;
• different generation project selection criteria, with the PSDP based on minimum discounted weighted cost of generation and system fit;
• system planning methodology, with the PSDP optimizing for seasonal and annual hydrological variability rather than average annual hydrology;
• selection of expansion scenarios, with the PSDP sequences determined by minimizing NPV of capital and recurrent expenditures.
7.8.2 Capital Investment Schedule
The sequence of capital investments required under the PSDP domestic system expansion plan is outlined under four headings, viz. generation expansion, grid interconnections, grid expansion, and off-grid program. The capital investment schedule is presented in Table 7.13. All costs are in 2003 values.
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The schedule summarizes the capital investments for domestic system development. It does not take account of capital requirements associated with the country’s export program or possible obligations arising under regional grid itegration projects. The principal demand for capital in this regard could come from GOL’s policy of acquiring equity in IPP projects developed within its borders and this has not been included in the investment schedule for the following reasons:
• The IPP program is uncertain in the number and timing of projects.
• GOL equity in IPP projects is mandated under the Electricity Law but the extent of participation is not specified, leaving open the possibility of a token or modest shareholding. A flexible case-by-case approach has been adopted with a 60% holding for Theun Hinboun contrasting with the token holding currently considered for the Xe Kaman 3 project.
• In the past, EdL has been the agency nominated by GOL to hold its shares in IPP projects. This has created a close linkage between EdL’s finacial position the success of GOL’s IPP program. A debate on the long-term wisdom of this approach is in progress and it may see a future separation of EdL from the IPP program.
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Table 7.13: Domestic Power Sector Capital Investment Schedule (US$ million in 2003 values)
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(i) Generation Expansion
Generation for the EdL grids is souced from EdL’s own generators, from imports and from power purchases from IPPs. Only the development of EdL- owned power stations has direct capital implications for EdL, although some transmission development and system reinforcement may be involved in accepting increased levels of imports or purchases from new IPPs.
Generation investment programs are described in Table 7.13 for both the preferred generation expansion scenarios (least cost) and second preference scenarios (fall-back). The program assumes the following:
• The capital costs of new generation projects are included. These have been extracted from the SEXSI outputs and represent the capital costs of the projects as optimized for the relevant expansion scenario. The costs effectively include physical contingencies, IDC and dedicated transmission development associated with the new projects;
• The investment program assumes that all generation projects in the expansion scenarios other than the three export IPPs (Nam Theun 2, Theun Hinboun Expansion and Xe Kaman 3) will be developed by EdL. In practice, these projects could be developed as domestic IPPs selling primarily or exclusively to EdL. To the extent that this occurs, the capital burden on EdL would be reduced.
• With the exception of a contribution of US$ 4 million in the case of the Xe Kaman 3 IPP project, transmission development associated with purchases from IPPs is not included. This is assumed to be the responsibility of the IPPs and will be recovered through the wholesale tariff paid by EdL.
(ii) Grid Interconnections
The grid interconnection category of investments cover, firstly, transmission development to connect the separate EdL grids and, secondly, new transmission links with the Thai system forming part of the system expansion scenarios identified through the SEXSI analyses.
The grid interconnection investments included in Table 7.13 are those assumed in the SEXSI simulations and include allowances for ancillary system reinforcement. It is assumed that the capital required for the identified grid interconnections would be the responsibility of EdL and has been included in the EdL system total capital requirements.
(iii) Grid Expansion
The expansion of the EdL grid is based on the development plan outlined in the EdL PDP, which lists the transmission lines, distribution networks and substations to be developed over the period to 2020. The scope of grid
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expansion proposed by EdL has been adjusted for PSDP purposes to take account of the follwing:
• Transmission investments associated with the interconnection of the Central grids (C1 with C2.1 and C2.2) and with the interconnection of the Southern Grid with the combined Central Grid have been excluded and treated separately (refer (ii) above) to enable then to be optimized as part of the SEXSI system expansion simulations;
• Transmission investments associated with dedicated lines for new power stations are included as part of the capital reqirements of the relevant generation project. They do not form part of the grid expansion capital requirements listed in Table 7.13.
The capital requirements for grid expansion have been calculated using bid prices for recent transmission and distribution works in Lao PDR and other global prices, as appropriate. The calculations are provided in Annex 9.
(iii) Off-Grid Program
The off-grid program is administered by MIH and will not be financed by EdL in any way. For this reason, off-grid investment requirements are isolated in Table 7.13 from EdL’s system development requirements.
Off-grid investments are an order smaller than the grid development investments. Annual investment increases gradually over the planning period as the program is scaled up from the present pilot phase.
A capital cost of US$ 200 per electrified household has been assumed in preparing the esimate of off-grid capital requirements. This is based on the current cost of a household solar unit, which is expected to form the primary off-grid technology in Lao PDR. The unit cost of each solar unit should decline over time as the technology improves and as economies of scale are harnessed with the scaling up of the program. Countering this, though, is an expected increase in the field component of each installation as households at the margin become increasingly sparse and remote.
A conspicuous feature of the investment profiles in Table 7.13 is the lower capital requirements of the Preferred Scenario. The Preferred Scenario is not only least- cost but, because it relies more on IPP off-take in meeting demand in the Central Grid, it also involves significantly less capital. Capital intensity could be reduced further if off-take from the Xe Kaman 3 IPP were substituted for the Houay Lamphan Gnai project in the Southern Grid, but this would increase overall NPV of the development scenario.
7.8.3 Average Incremental Costs for System
A parameter that provides a broad measure of the cost of producing, transmitting and distributing electricity is the system average incremental cost. This figure represents the cost of energy and capacity at the margin, and provides a measure of the tariff required to provide for future expansion of the system.
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The average incremental cost of the EdL system under the Preferred Scenario was determined by considering separately the incremental costs of, firstly, the generation and grid interconnection costs, and, secondly, the transmission and distribution costs.
(i) Generation and Grid Interconnections
As part of the system simulations performed using the SEXSI program, the overall incremental investment and recurrent operating costs of each evaluated scenario were computed to determine the system average incremental cost per kWh. The calculated figure covers those works simulated and optimized under SEXSI, i.e. generation expansion (including dedicated transmission lines) and transmission works associated with the interconnection of EdL’s grids.
Under the Preferred Scenario, the system average incremental costs per kWh for the interconnected Central systems (C1/C2.1/C2.2 grids) and the Southern Grid are given in Table 7.14. A weighted average incremental cost of the Preferred Scenario for the two systems, calculated on the basis of average demand in each system over the planning period, gives a system average incremental cost for generation of 5.3 ¢/kWh.
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Table 7.14: Average Incremental Cost – Generation and Grid Interconnections
System Average Scenario Description Expansion Incremental Scenario Cost Central Grid: Preferred Scenario 4.99 ¢/kWh IPP off-take: Nam Theun 2, Theun Hinboun Expansion EdL Projects: Nam Ngiep 1 Grid devpt: C1 & C2 interconnections Fall-Back Scenario 5.29 ¢/kWh IPP off-take: Nam Theun 2, EdL Projects: Nam Ngiep 1, Nam Ngum 5, Nam Bak 2B, Nam Pot Grid devpt: C1 & C2 interconnections
Southern Grid: Preferred Scenario 7.00 ¢/kWh EdL Projects: Houay Lamphan Gnai Grid devpt: 2nd 115kV link with Thailand “Xe Kaman 3” 8.39 ¢/kWh IPP off-take: Xe Kaman 3 off-take (IPP) Scenario Grid devpt: 2nd 115kV link with Thailand
All Grids: Central Grid + Southern Grid Preferred Scenario 5.3 ¢/kWh Weighted average of Central and Southern 2nd Pref. Scenarios 5.7 ¢/kWh Weighted average of Central and Southern
NOTES: 1/ refer SEXSI Spreadsheets – Annex 6 2/ includes transmission interconnections and dedicated transmission lines for generation projects 3/ Calculated over the period from 2004-2020
(ii) Transmission and Distribution
Incremental costs of transmission and distribution in the EdL system were calculated and are reported in Table 7.15. They comprise:
• Transmission (excluding grid interconnection lines and dedicated lines associated with new power stations) • Substations & Switching Stations • Distribution (including house wiring)
House wiring costs generally include the meter, house wiring, two to three lights and two power points. The cost of house wiring varies between US$ 50 and 100 and is a financial cost on the household and not on EdL.
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Different distribution costs (including house wiring costs) were assumed as follows:
Assumption 1: Distribution Costs = $US 450 per customer Assumption 2: Distribution Costs = $US 500 per customer Assumption 3: Distribution Costs = $US 550 per customer
Table 7.15: Average Incremental Cost – Transmission and Distribution
Incremental Cost of Energy (US¢/kWh) Assumed Distribution Costs 1 2 3 Transmission 0.679 0.679 0.679 Substations & Switching Stations 0.142 0.142 0.142 Distribution 2.054 2.282 2.511 Total Average Incremental Costs 2.875 3.103 3.332
NOTES: 1/ Refer calculation spreadsheets – Annex 9. 2/ Excludes transmission interconnections and dedicated transmission for power stations 3/ Calculated over the period from 2004-2020 4/ Distribution costs includes house wiring costs.
Substation and transmission line costs reflect the rate at which EdL’s extends its grid, but as Table 7.15 indicates, the major element of the transmission and distribution component of average incremental cost is the cost of distribution expansion.
Combining the costs for generation and transmission and distribution yields a total average incremental cost of the system as follows:
• Preferred Scenario = 5.3 ¢/kWh + 3.1¢/kWh = 8.4 ¢/kWh • 2nd preference scenarios = 5.7 ¢/kWh + 3.1¢/kWh = 8.8 ¢/kWh
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8.0 EXPORT POWER DEVELOPMENT
8.1 Objectives of Power Exports
The development of projects for export must be planned and managed within a framework established by a clear definition of objectives. The economic benefits of electricity produced by export projects are largely enjoyed beyond the borders of Lao PDR and therefore the justification for export power generation is found in the economic benefits of the GOL revenue receipts rather than the electricity outputs. Export projects should therefore proceed only if the expected net benefits from the project are clearly greater than those from any alternative use of the site. Thus, in determining the potential macroeconomic benefits of export projects, one should consider the following and compare them with the opportunity cost associated with alternative economic uses of the project area:
• the economic value of the direct revenue benefits of the project, which depend in turn on electricity prices, capital costs, tax rates, royalty charges, GOL dividend receipts and GOL debt service payments;
• the value of any electricity off-take for the domestic grids, calculated as the difference between the tariff paid by EdL to a project company and the incremental cost of generation within the Lao system;
• the value of infrastructure and regional development associated with the project;
• the net value of positive and negative social and environmental impacts not mitigated or compensated by the project company;
8.2 Export Candidate Projects
8.2.1 Status of Lao Export Program
Until the nineties, power sector development in Lao PDR focused primarily on serving domestic demand, though the development and operation of Nam Ngum 1 power station in 1971 represented an early and significant departure from this focus. That station was developed in three stages, maintaining an installed capacity well in excess of that needed for domestic load growth in the Vientiane grid. The surplus was sold to EGAT and provided the country with much needed foreign exchange. In 1991, the commissioning of Xeset 1 boosted wet season exports.
These revenues, expressed as a percentage of export earnings, peaked in 1992 at 47%. In recent years export earnings from EdL stations have fallen as rising demand diverts an increasing proportion of output into local grids and export power prices decline in sympathy with the lower avoided costs in the EGAT system.
The success of Nam Ngum 1 focused attention of the potential role of power exports as a means of earning foreign currency for funding the country’s economic and social
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development. In the early nineties, with electricity demand in the region rising rapidly, an ambitious expansion in export sales from Lao PDR was planned. The large amounts of capital required were sought from the private sector through an IPP program. The program specifically targeted the power markets of Thailand and Vietnam with whom GOL had inter-governmental power trading agreements.
In the period from 1993 to 1996, agreements were signed with more than twenty developers, but activity all but ceased with the onset of the Asian Economic Crisis. The Crisis not only reduced demand in Lao PDR’s export markets, but it also increased the wariness and conservatism of international financiers. At the same time, efficiency improvements in gas generation plant have reduced the cost of generation in the EGAT and EVN systems and depressed the tariffs offered to developers. The situation is now improving, and the prospects are reasonable for any credible developer with a quality site. Several projects have these attributes.
With the growing liquidity in the banking sectors of some Asian countries, notably China, but also India, Korea, Taiwan, Thailand and Malaysia, new and more flexible financing models are being introduced. Preferential loans obtained from the China Exim Bank through Chinese contractors are already financing domestic generation and transmission projects with security packages that would not interest traditional lenders. If mobilized within a more rigorous commercial and procurement framework, finance through these regional banks could provide an effective alternative to international commercial banks and mulatilateral agencies.
Two export projects have been completed. Theun Hinboun entered commercial service in April 1998 and Houay Ho in September 1999. Both projects supply Thailand. Also Nam Theun 2 has signed a PPA with EGAT and the sponsors of Nam Mo and Xe Kaman 3 are in formal negotiations with EVN for a PPA to supply Vietnam. At the time of writing, no other project has current power purchase or financing commitments. The status of power generation mandates in Lao PDR is summarized in Table 6.4.
8.2.2 Separation of Domestic and Export Programs
In the past, projects developed by EdL for domestic supply have been quite separate and distinct from those promoted under the IPP export program both physically and in their objectives.
The programs were physically demarcated mainly on the basis of project size. Projects larger than 100 MW were generally considered to be unsuitable for domestic development because GOL did not have access to sufficient capital to develop them, and also the capacity increments were too large for the system.57 At the same time, projects smaller than 100 MW are considered unsuitable for export development for the following reasons:
57 EdL can sell surplus output to EGAT as non-firm energy as it did profitably in the case of Nam Ngum 1. In recent years, however, the price paid by EGAT for non-firm energy has declined in line with decreasing generation costs in the Thai system. This has eroded the economic advantage of maintaining a large surplus capacity in the Lao system.
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(i) Financing: Investors can finance small projects (say, US$ 30 million or less) on their balance sheets, but are unwilling to risk corporate financing of larger projects. Project financing provides the means of shifting larger projects off the balance sheet but the work required of lenders to structure the deals is relatively insensitive to the size of project and a point is reached where projects become too small to warrant the effort. The cut-off point is considered to be generally in the range of US$ 100 million to US$150 million, i.e. roughly equivalent to a 100 MW project.
(ii) Power Purchase: As long as international power purchases continue to be structured on an individual project basis, projects under 100 MW do not justify the time and resources the power purchaser would need to expend in negotiating a PPA, completing the transmission interconnections and administering the on-going commercial arrangements. With greater system integration and institutional change, regional power market models may emerge that standardize and simplify matters and this would open the way for smaller projects. This may not necessarily involve power pools and merchant plants; the Thai SPP program may provide a model.
While the grids in Lao PDR were separate and small, the distinction between the export and domestic markets was necessary and practical. However, the situation is changing:
• Load growth and grid interconnection will see the peak load in the Central Grid rise rapidly and this will admit the possibility of larger capacity increments and bigger projects for domestic supply.
• With time, the financial position of EdL will improve and eventually the point will be reached where international capital markets will accept EdL credit risk. Larger projects will then be suitable for both export and domestic supply.
• The emergence of regionally-based markets will better direct investment and output to best effect, opening up new opportunities for Lao-based generators to supply export and domestic markets on a more flexible basis.
8.2.3 Development of Export Development Scenarios
In Section 6, power generation projects were shortlisted, optimized and evaluated according to systematic economic principles. In Section 7, domestic generation expansion sequences were systematically optimized to meet forecast demand, again on economic principles reflecting the optimal allocation of scarce resources. A foreign power purchaser, though, is not concerned with allocative efficiency in Lao PDR in deciding where it should obtain its power. Lao PDR is a price taker in its main export markets and export projects will only proceed if they can be financed at a tariff reflecting the purchaser’s avoided cost. Export development scenarios are formulated on this basis rather than being planned in any system optimization sense.
An export project will therefore proceed or falter according to its capacity to achieve hurdle rates of return and debt service at the purchaser’s avoided cost tariff. The ability of a project to compete in an export market therefore comes down to its
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financial performance rather than any broader economic attributes (although the latter should determine whether GOL chooses to support the project).
The value of avoided cost tariff to be used in evaluating the competitiveness of projects is not straightforward. It depends on a number of factors including:
• choice of market (e.g. Vietnam, Thailand, Cambodia); • daily, monthly and seasonal generation characteristics; • ancillary system benefits; • commercial conditions; • project location with respect to the purchaser’s load and transmission infrastructure.
In practice, the negotiation process adds another variable. A reasonable estimate of avoided cost can track within a range reflecting the subjective nature of the calculation. The work described in Section 5.8 suggests a value roughly within a 4.5 to 5.5 ¢/kWh band. An imbalance in bargaining strength would see agreement settle on a value towards the extremes of that range. The experience of the last decade confirms, too, that avoided cost values within a system can fluctuate significantly over time and that a tariff figure thought to be reasonable today may tomorrow be considered too high or low.
Thus, the development of export scenarios involves an assessment of the financial performance of projects under ill-defined export tariff conditions Accordingly, the following procedure was adopted in devising realistic export generation scenarios:
1. All candidates were optimized and evaluated using the EVALS software using, wherever applicable, an Installed Capacity Factor of 1.75, roughly equivalent to the current EGAT operating requirement of 16 hours per day, six days per week. The results of these optimizations are presented in Table 6.6.
2. Using the methodology described in Section 9.3.1, projects were analyzed using cash flow modeling to determine the financial tariff a project would need for it to be bankable (i.e. the tariff to achieve a nominal rate of return on equity of 17% and minimum debt service coverage ratio of around 1.3). The projects were then arranged into a supply curve according to their calculated financial tariffs (refer Figure 9.2) indicating for any chosen avoided cost tariff which projects are likely to succeed and which ones may need some assistance.
3. In further refining the pool of eligible projects, all projects with an optimized installed capacity less than 100 MW were discarded as being too small for the reasons outlined in Section 8.2.2.
4. The remaining projects were then subjectively arranged into a development sequence according to:
• Current status, based on a project’s progress towards financial close as indicated by the status of power purchase negotiations, level of lender commitment, likelihood of multilateral backing, track record of the developer, etc.;
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• Future prospects, as indicated by a project’s economic and financial characteristics, and likely interest of off-takers and lenders.
5. The commercial operation dates were then allocated to projects as follows:
• Where a developer’s nominated commercial operation date is realistic and achievable, it is adopted;
• Otherwise, projects are spread over the planning period according to an achievable program, allowing roughly two or three year intervals between projects. This spacing is arbitrarily chosen but acknowledges:
- limitations in GOL’s institutional capacity to develop multiple, concurrent projects;
- possible concerns in capital markets to overexposure to Lao risk.
• Acknowledging the uncertainties involved in IPP implementation, two export scenarios, are put forward in Table 8.1 – a Base Export Scenario based on the Consultant’s judgment of a reasonable progression of projects, and an Optimistic Export Scenario, based more closely on the stated intentions of developers.
Demand in Lao PDR’s key export markets of Thailand and Vietnam does not significantly constrain export sales and the two scenarios in Table 8.1 are not linked to base and high forecasts of EGAT and EVN. The differences between the two relate more to a diverse range of factors that underly the uncertainty in project CODs. These include:
• Poor track record of IPPs generally in being bringing private projects to fruition according to a stated schedule;
• Changes in the relative costs of hydropower and thermal generation affecting the competitiveness of Lao projects from one year to the next;
• Rate of progress in establishing 500 kV regional transmission inter- connections, particularly those linking Lao PDR to Thailand and Vietnam;58
• Timing and nature of power market reforms within GMS countries, affecting access to markets and the market risk to be borne by generators;
• Developments in global financial markets and in the competition for capital from other sectors and other countries;
• Developments in the implementation of large competing hydropower proposals in neighboring countries.
58 The development of the 500 kV grid would enhance the viability of a number of Lao export prospects, particularly those in southern Lao PDR. The grid is also a necessary precursor for the development of a regional power market.
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The export scenarios would involve the commissioning of about seven projects over the 12-year period from 2008 to 2020. This may seem ambitious when compared with the track record of only two projects to 2007, but it is achievable with expected improvements in the region’s power and capital markets.
Table 8.1: Export Generation Development Scenarios
Base Export Scenario Optimistic Export Scenario
2005 2006 2007 2008 Theun Hinboun Expansion 3/ Nam Mo (Vietnam) 2/ Theun Hinboun Expansion 3/ 2009 Nam Mo (Vietnam) 2/ 2010 Nam Theun 2 (Thailand) 1/ Nam Theun 2 (Thailand) 1/ Xe Kaman 3 (Vietnam) 4/ 2011 Xe Kaman 3 (Vietnam) 4/ 2012 2013 Xe Kaman 1 (Vietnam or Thailand) 2014 Xe Kaman 1 (Vietnam or Thailand) 2015 Xe Kong 5 (Vietnam) 2016 2017 Xe Kong 5 (Vietnam) Nam Ngum 3B (Thailand) 2018 2019 Nam Ngum 2B (Thailand) 2020 Nam Ngum 3B (Thailand)
NOTES: 1/ Scheduled for 2010 in the EGAT PDP 2/ Scheduled for 2008 in the EVN PDP 3/ PSDP recommends one unit is dedicated to domestic supply. Modeling is based on a single unit expansion but two or more units is also attractive and favoured by THPC. 4/ Scheduled for 2010 in the EVN PDP
Several projects are being actively and successfully promoted in the present market and they make up the projects commissioned in the first ten years of the Base Export Scenario. Of these, only Nam Theun 2 has a PPA and none has lender commitment at this stage. Nam Theun 2, because of its long construction period, is not scheduled for completion until 2010. There are, however, two projects that could foreseeably be completed in advance of Nam Theun 2. If the sponsors of Nam Mo (105 MW) were to finalize their negotiations with EVN and lenders by the end of 2004, they could feasibly achieve commercial operation in 2008, but 2009 is more achievable. THPC could bring on additional capacity at the Theun Hinboun site earlier than this, depending on how the project is phased.
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The Xe Kaman 3 project has the backing of a credible consortium (refer Section 6.7.4) and preliminary studies indicate that the economics of site are attractive. A feasibility study has been prepared and the future of the project will become clearer as discussions between the developer, GOL and EVN advance.
Ideally, projects should be evenly spaced in time with a gap of two or three years between each. This would put less strain on GOL’s limited institutional capacities and provide continuity in resourcing over the planning period. The time intervals between projects are something over which GOL has little control in practice. In the PSDP’s proposed domestic and export scenarios, project spacing is not even; peak congestion occurs in the period from 2008 to 2011 when as many as six projects could be concurrently under construction, viz. Nam Theun 2 (export), Nam Mo (export), Xe Kaman 3 (export), Theun Hinboun Expansion (domestic/export), Houay Lamphan Gnai (domestic) and Nam Ngiep 1 (domestic). This may be neither realistic nor desirable.
8.3 Transmission Development for Export
8.3.1 Background
In the mid-nineties, the execution of bilateral inter-governmental power trading agreements between GMS countries heralded an expansion in international power exchanges within the region. Given the significant complementarities between the power systems of the region, interest in the concept of system integration has grown. Member governments have been cooperating in planning the interconnection of their grids and in exploring regional power market possibilities. With the admission of Lao PDR, Vietnam, Cambodia and Myanmar to the ASEAN grouping in the late nineties, the issue of regional grid interconnection has also been taken up by ASEAN.
The governments of the ASEAN/GMS countries see considerable political, economic and environmental merit in an integrated regional 500 kV system. Backed by the World Bank and ADB, studies have been undertaken that confirm the benefits of international cooperation and plans for integrating the ASEAN/GMS power grids are proceeding. Potential benefits of integration include:
• Improved system reliability through international back-up;
• Reduced capital and operating costs of transmission through grid optimization on a regional rather than national level;
• Reduction in environmental damage associated with right-of-ways for dedicated lines;
• Reduced capital and operating costs in generation associated with reduced reserve margins, optimal plant mix, time-of-day trading and conjunctive operation of projects;
• Reduced greenhouse emissions through coordination of hydro and thermal generation across the region
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For Lao PDR, the concept holds considerable promise. A regional grid would provide the infrastructure to receive power from individual export projects and deliver it to nominated power purchasers in neighboring countries. The length of dedicated transmission lines would be reduced, boosting the economics of projects, particularly those in the Se Kong basin.
The large capital requirements for building the 500 kV system interconnections are an obstacle. The implementation strategy is based to some degree on coordinating transmission interconnections with the transmission infrastructure of large export projects. This is being facilitated through the activities of the GMS Subregional Electric Power Forum (EPF) and the ASEAN Center for Energy. The EPF was created in 1994, and within this structure the Experts Group on Power Interconnection and Trade (EGP) specifically promotes integration of national grids. The EPF endorsed the need for a Regional Indicative Master Plan on Power Interconnection and a strategy is being formulated for infrastructure development and institutional reform to promote effective power trading within the sub-region.
8.3.2 Lao National Electricity Transmission Grid
Proposed international 230 kV and 500 kV transmission development to 2020 within Lao PDR is shown in Figure 8.2.
A number of international MV and HV transmission links already exist in Lao PDR (refer Table 7.4). MV feeders from Thailand, China and Vietnam supply border areas that are outside the present reach of EdL’s grids. All existing international HV transmission links connect to the EGAT grid.
GOL understands the long-term technical, commercial, environmental and political benefits of regional grid integration and are committed to the concept of a 500 kV grid. It actively promotes the development of a regional grid and participates in the ASEAN and GMS forums. It has commissioned studies by Fichtner, Lahmeyer and Stikeman-Elliott to examine technical and institutional development of a 500 kV grid within Lao PDR to form part of the ASEAN/GMS grid - the National Electricity Transmission Grid (NETG). 59 The creation of an institutional and legal framework for the Lao National Grid Company to manage NETG was also studied.
The NETG gained legal status with the promulgation of the Electricity Law, Article 29 of which provides for the establishment of the NETG to link generators within Lao PDR and interconnect with the HV systems of other countries. Under the legislation, all generators are obliged to transmit through the NETG wherever it is economically accessible. Article 29 implies that the NETG must be Government- owned but it could be facilitated through private sector concessions for individual lines under BTL arrangements to comply with the legal ownership requirements.
59 Fichtner, Nam Ngum 500kV Transmission Project, Part A: Feasibility Study, ADB TA 2926-LAO, Draft Final Report, November 1998; Lahmeyer International, 500kV Lao PDR Grid, Conceptual Design Study, Ministry of Industry and Handicrafts, March 1997; Stikeman-Elliott, Hydro-Quebec, Study for Establishing Lao National Grid Company, Final Report, ADB TA No. 2728-LAO, 1997.
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Financing of NETG lines is a proving a challenge. The conceptual plans for NETG were prepared prior to the onset of the Crisis and relied on concurrent development of generation projects and cooperation of their developers to provide sufficient power flows and wheeling revenues to attract investor and lender support. Although IPP generation proposals are still being promoted in reasonable numbers, there is now less conviction that IPPs will actually achieve their declared CODs. This creates uncertainty in wheeling revenues from proposed transmission investments and makes it difficult for the private sector to take an active role in financing lines. Governments, multilateral agencies and key bilateral agencies are now taking a more prominent role. With rising demand and shrinking reserve margins in the region, many observers predict a more active period of IPP development and this would assist the financing process.
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Figure 8.2: 230 kV and 500 kV Grid Development within Lao PDR to 2020
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The 500 / 230 kV NTEG is seen as separate and distinct from the EdL 115 kV grid, with NTEG facilitating regional power flows and the EdL grid reticulating power to EdL’s customers. There are no technical barriers to prevent the NTEG serving domestic as well as regional purposes and it is recommended that transmission studies in the future explore the idea of a dual role.
8.3.3 Regional Grid Development
Power trade among GMS countries has made significant advances in the last decade or so. In 1990 the only significant international power exchange involved the export of surplus power from the Nam Ngum 1 project to Thailand. Today, the numbers of projects and interconnections have increased but, more significantly, major power trade agreements are now in place committing Lao PDR, Thailand, Vietnam, Myanmar, Cambodia, China, Malaysia and Singapore to exchanges of electricity with one or more of their neighbors. A regional grid is emerging to facilitate this trade.
Prior to the onset of the Crisis, rapid load growth in GMS countries added urgency to the development of an HV/EHV grid to interconnect countries in the region to exploit complementarities in their resource bases, plant mix and load patterns. The Crisis lowered load projections and eased the situation.
The ADB, in promoting optimal utilization and development of the region’s energy, is developing strategies for financing the construction of transmission lines, mobilizing private capital and developing an institutional capacity to manage integrated power operations. Under its Regional Power Interconnection and Power Trade Arrangements initiative it has prepared a Regional Indicative Master Plan for Power Interconnection setting out a program of grid interconnection projects. A parallel study, the ASEAN Interconnection Master Plan Study (ASEAN Power Grid) will also be prepared and there is a need to coordinate this with the ADB study to ensure consistency in their recommendations.
The Regional Indicative Master Plan for Power Interconnection has been completed and in it the following projects are identified:
(i) 230 kV Interconnection between Vietnam and Cambodia
A 230 kV double circuit transmission line will interconnect Phnom Penh and Chau Doc (Vietnam) to displace diesel generation in Phnom Penh and supply new loads in Southern Cambodia. A feasibility study has been completed and the line will be implemented by 2004
(ii) 500 kV Line - Roi Et (Thailand) to Nam Theun 2 (Lao PDR)
The project comprises: (a) a 500-kV double circuit line from Roi Et (Thailand) to Savannakhet on the Lao border to be developed by EGAT and paid for through the Nam Theun 2 wholesale tariff; and (b) a 500 kV double circuit line from Savannakhet to the Nam Theun 2 switchyard to be developed and financed by the Nam Theun 2 developer. The line was planned as a dedicated project interconnection but is also considered under the Regional Indicative Master Plan for Power Interconnection as a link in the first interconnection between Vietnam and Thailand (refer (iii) below). The
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transmission line will be completed by 2009 according to the Nam Theun 2 construction schedule.
(iii) 500 kV Interconnection between Lao PDR and Central Vietnam
A feasibility study is commissioned that is identifying potential routes for a 500 kV double circuit transmission interconnection between the Lao and Thai systems. A likely option is the 130 km route from Ha Tinh (Vietnam) to the Nam Theun 2 switchyard. By linking with the Nam Theun 2 line to Roi Et, a 500 kV interconnection between the Vietnamese, Lao and Thai systems would be established.
The feasibility study is scheduled for completion in 2004 and, if feasible, the transmission line would be completed by 2009 to coordinate with the construction schedule for the Nam Theun 2 – Roi Et line.
The project is included in ADB loan pipeline for the GMS and the proposed financing plan includes ADB soft loans to GOL and GVN. Co-financing from other bilateral or private sector sources may be enlisted. In agreeing cost sharing, there is need to determine the benefits of interconnection and how they will accrue. This will require agreement on cooperation in system operation.
(iv) 115 kV Line interconnecting Thailand and Western Cambodia
A 115 kV single circuit interconnection between Thailand and Cambodia is planned to supply isolated load centers in western Cambodia to displace generation from small diesel units. A feasibility study has been conducted and the project will be completed in 2004.
(v) 230 kV Line - Nam Mo Hydro Project (Lao PDR) to Ban Mai (Vietnam)
A 230 kV single circuit line will be built to transfer power from Nam Mo hydropower in Lao PDR to northern Vietnam. The transmission line could include a possible extension. The line will be financed by the private consortium of the Nam Mo project. An implementation date of 2007 will depend on the outcome of commercial discussions between the consortium and EVN.
(vi) 500 kV Line - Udon Thani (Thailand) and Ban Na Bon (Lao PDR)
A 500 kV interconnection between Udon Thani (Thailand) and a collector substation at Ban Na Bon near Vientiane in Lao PDR is proposed for transmitting power from export hydropower projects in the Nam Ngum and other watersheds in the Central-1 area of Lao PDR. Reinforcements of the EGAT system will be needed in support of the project. The timing of the transmission line will depend on progress with IPP hydropower proposals in the Central-1 area, namely Nam Ngum 2 and 3 and Nam Ngiep 1.
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(vii) 500 kV Line - Savannakhet to Ban Sok (Lao PDR) to Pleiku (Vietnam)
A 500 kV single circuit transmission line is planned to interconnect the Roi Et to Savannakhet line with the EVN system through Pleiku in the central highlands of Vietnam. The transmission line would include a 500 kV collector substation at Ban Sok in the Bolovans area of southern Lao PDR to receive output from IPP hydropower projects in the Se Kong basin and transmit it to loads in Vietnam and Thailand. Benefits will derive from wheeling revenues from IPPs and savings from system optimizations. A feasibility study is proposed sometime after 2006 and implementation will depend on progress with IPP hydropower developments in southern Lao PDR.
(viii) 500 kV Interconnection – Ta Sang Hydro Project to Thailand
A 500 kV transmission interconnection is planned for transferring power from the proposed Ta Sang hydropower project to Thailand. The transmission component would involve: (a) two 500-kV double circuit lines connecting the Ta Sang project to Mae Moh, and (b) a 500-kV single circuit line connecting Mae Moh to Tha Tako. A prefeasibility study has been completed and a full feasibility study is planned. The lines will be financed under the commercial arrangements put in place by the private developer of the Ta Sang project. Timing will depend on the progress of the developer’s negotiations with the Government of Myanmar, EGAT and the project lenders. Delivery of the first tranche of power from the project is unlikely to be scheduled earlier than 2013. To proceed, a power trading agreement between the governments of Myanmar and Thailand needs to be put in place. Development of the Salawin River basin is subject to some uncertainty because of political unrest in the area, and expected social and environmental impacts of the project.
(ix) 500 kV Direct Current Line – Jinghong Hydro (China) to Thailand:
A 500 kV interconnection between the Jinghong Hydropower Project on the Lancang River in Yunnan Province to Bangkok is planned. The transmission interconnection involves:
• 500 kV high voltage direct current (HVDC) line and converter stations to transfer power from the Jinghong hydropower project to Bangkok;
• 500 kV high voltage alternating current (HVAC) lines within Yunnan, PRC; and
• Under consideration is a converter station within Lao territory to serve as a collection point for Lao IPP projects in the northern river basins such as the Nam Ou, Nam Tha
The private developer of the Jinghong project will finance the transmission lines. Implementation is tied to the program of the hydropower component and depends on progress in the negotiation of project agreements. Jinghong is scheduled to supply EGAT from 2017 but it is understood that this date has been brought forward. A feasibility and EIA is planned.
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(x) 230 kV Double Circuit Line - Malutang (Yunnan) to Vietnam
A 270 km 230 kV double circuit transmission line will be built to connect the 460 MW Malutang Hydropower Project (Yunnan) to Soc Son in Vietnam to transfer the power station output to the Hanoi area. A feasibility study for the hydropower project was carried out in 1995 but a feasibility study of the transmission line is needed. Financing arrangements are to be discussed between the Provincial Government of Yunnan, PRC and the Government of Vietnam. The Malutang project is scheduled to enter commercial service in 2019, although this date is dependent on progress in finalizing commercial arrangements for the project.
The ASEAN Interconnection Master Plan Study (ASEAN Power Grid) will eventually cover the interconnection of all ten ASEAN countries but its first focus will be six transmission projects for linking GMS countries as follows:
(i) Thailand and Vietnam (ii) Lao PDR and Vietnam (iii) Thailand and Myanmar (iv) Vietnam and Cambodia (v) Lao PDR and Cambodia (vi) Thailand and Cambodia
Of particular interest is the timing of the proposed HV interconnection between Lao PDR and Cambodia to link hydropower projects in southern Lao PDR to Phnom Penh and other loads centers in Cambodia. This interconnection is not listed in the Regional Indicative Master Plan for Power Interconnection but is scheduled for 2019 in the Cambodian power development plan. Without this line, Lao projects do not have access to Cambodian load centers of any significance.
8.3.4 Transmission Development within Thailand and Vietnam
Planned 500 kV transmission interconnections with Thailand and Vietnam are shown in Figure 8.2. The NETG plans are scoped to coordinate with grid development plans in Thailand and Vietnam and with IPP generation projects within Lao PDR, notably Nam Theun 2.
In Thailand, three 500 kV double circuit transmission interconnections between NETG and the EGAT system were defined, the proposed locations being:
• Hongsa power station switchyard to Mae Moh 3 • Ban Na Bon (near Vientiane) to Udon Thani 3 • Savannakhet to Roi Et 2
All export projects with reasonable prospects, save Hongsa, would interconnect through Ban Na Bon or Savannakhet if exporting to Thailand and EGAT would reinforce its system accordingly. There is a deficit of power in the north-east of Thailand and the EGAT system there is in need of strengthening. Lao exports provide an attractive means of addressing both issues.
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In Vietnam, the geographical shape of the country and the limited power transfer capacity of the 1,500 km long 500 kV single circuit north-south transmission spine means that generation and load must be balanced separately within the north, central or southern parts of the country. The 500 kV line is being reinforced in stages but there will be a continuing need to plan these areas independently of each other to some degree. Load growth is greatest in the south.
Interconnections between Lao PDR and the EVN system currently under discussion are: • Nam Mo hydro project in Lao PDR to Ban Mai (Vietnam) (230 kV) • Nam Theun 2 to Ha Tinh (500 kV) • Xe Kaman 3 hydro project to Vietnam (230 kV) • Ban Sok to Pleiku (500 kV)
The proximity of the Se Kong basin to the central part of Vietnam makes it an attractive source of generation and a 500 kV connection is proposed witha collector station to be established at Ban Sok in the Bolavens area. Xe Kaman 3 will be the first project from this basin to be developed but it will interconnect directly to the EVN spine. Subsequent projects will feed into the NETG through the Ban Sok station.
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9.0 FINANCIAL EVALUATION OF POWER PROJECTS
9.1 Objectives of Financial Evaluations
The financing of power projects in Asia and elsewhere has been undergoing a transition over the last decade as the participation of the private sector increases. Historically, there has been a clear distinction in Lao PDR between EdL-owned, publicly financed power projects for domestic supply and privately owned, project financed export-oriented projects. As this blurs, the financial attributes of projects have assumed greater importance for domestic as well as export investments.
As transmission infrastructure improves and the institutional and regulatory framework develops at both the domestic and regional levels, power markets will become more conducive to private investment and a continuing trend towards private sector involvement can be expected into the future. Transmission and distribution projects is continuing to attract support from multilateral and bilateral agencies but a significant involvement by private investors is needed to bring new generation capacity on-line in the amounts required. Commercial factors in competing for this capital will be investor returns and lender security.
Financial analysis of generation projects indentified under the PSDP was undertaken to examine the viability of projects from a financial point of view. Specific objectives of this work were:
(i) Projects for Domestic Supply:
• to determine the tariff that projects would need to meet hurdle rates of return on equity and debt service were they to be developed by IPPs;
• to provide an indication of the sensitivity of domestic IPPs to borrowing terms and conditions.
(ii) Projects for Export Markets:
• to test whether a project is likely to meet hurdle rates of return on equity and debt service coverage at the current likely EGAT tariff;
• to estimate GOL/EdL’s tax, royalty and net dividend receipts generated by these projects.
9.2 Financial Evaluation Methodology
9.2.1 Financial Modeling
Financial analysis using cash flow modeling is a tool for evaluating the financial performance of projects and refining their financing plans. Financial cash flow
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modeling of projects for the PSDP was carried out from the perspective of the project company 60 rather than from the broader country perspective of the economic evaluations. Thus, the cash flow inputs to the model include only the monetary costs spent and benefits received by the project company and exclude many of the losses and benefits affecting other stakeholders.
Unless otherwise stated, financial evaluations assume that projects are financed on commercial terms without concessional lending. Evaluations of projects using EVALS software allows competing sites to be compared on the basis of their contribution at an economic level. This permits a decision to be made about the sequence and timing of investments. The financial analyses assess whether a project has the financial characteristics to generate the cash flows necessary to achieve a level of financial performance satisfactory to investors and lenders.
The HPO Financial Model, with some adaptation, was employed in the evaluations (refer Figure 9.1). The HPO Model is a spreadsheet-based model that replicates the flow of money between participating parties to an IPP hydropower project in Lao PDR, namely the sponsor, power purchaser, lenders and GOL. Annex 4.1 provides a description of the model and a list of assumptions and parameters used in the modeling.
Figure 9.1: HPO Financial Model : Schematic Diagram
GENERAL REVENUE PROFIT
INDEPENDENT Equity Loan POWER PROJECT
CAPITAL STRUCTURE DEVELOPER GOL's GOVERNMENT Equity LENDER OF LAO PDR Loan Finance (Debt)
OPERATING FINANCE Interest Principal Operating Cost Loan Interest PROJECT BANKS Loan Principal Multilateral, ECA's Commercial Banks, Royalties Supplier Credits Taxes
Dividends EGAT Project Income EVN Payment for Electricity
60 The PSDP modelling also included GOL cash flows associated with the borrowing and repayment of loans for GOL equity contributions.
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Performance measures are calculated to indicate the attractiveness and financeability of projects. The model provides projections (in nominal terms) of cash flow benefits, and calculates EBIT, net profit, debt service ratios, etc. Project rate of return and return on equity are calculated in nominal, after-tax terms.
The model takes the perspective of GOL as well as the project company by including the raising and servicing of loans for GOL’s equity and reporting GOL benefits from taxes, royalties and dividends.
9.2.2 Financial Modeling Parameters
Standardized inputs for many of the project parameters are used to benchmark the sites so that comparisons of financial performance of projects are meaningful. Standardized parameters include, as applicable, tariff, fees, concession period, tax and royalty regime, financing terms and GOL equity.
Financial modeling of projects is standardized on project configurations based on an ICF of 1.75 except where circumstances require a different configuration (e.g. run-of- river projects). A number of the sites are covered by concession agreements defining project configurations and concession conditions different to those assumed but, for the most part, the concessions were awarded many years ago and there is reasonable doubt about the ability of the sponsors to implement their projects.
Domestic off-take sales from projects built primarily for export attract a price equivalent to the opportunity cost of those sales to the owner; i.e. the export price as adjusted for differences in transmission losses and level of supply/off-take commitment. Thus, domestic off-take is not separately accounted for in calculating financial cash flows, as the cash flow effect is the same regardless of the purchaser.
The principal parameters and assumptions used in the standardized modeling are set out in Table 9.1 and described in more detail in Annex 4.1.
9.2.3 Financial Effects of Environmental and Social Impacts
The SESAMEE model generated monetary benefits and costs for all identified project impacts and these were internalized in the economic evaluations. Financial analysis has a project company perspective and therefore only those environmental and social impacts and mitigations with financial implications for the project company are considered in the financial modeling. Losses and benefits borne by other stakeholders (or by nobody) are excluded. Examples of impacts included in the the financial anlaysis include:
• costs associated with capital works with an environmental purpose (e.g. re- regulation dam, variable level intake);
• payments made by the project owner for social mitigations during construction (e.g. resettlement, compensation for lost production systems);
• recurring mitigation costs paid by the project owner during project operation (e.g. watershed management payments, support for social infrastructure, on- going compensations, etc).
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Financial cash flows associated with environmental and social impacts are calculated by extraction from the SESAMEE Local Market Model. The SESAMEE line items included in the project financial modeling are listed in Table 9.2. Due to the structure of the SESAMEE costs, some double counting of mitigations occurs with environmental mitigations that form a normal part of construction contracts and are priced into the capital cost estimates.
The SESAMEE cash flows are in constant dollars for economic evaluation and these are escalated to current values before applying them in financial evaluations.
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Table 9.1: Standardized Parameters for Financial Modeling
Parameter Value used in Modeling
General: Operating concession 25 years COD According to Base Export Scenario, or 2003 as appropriate Money values Nominal Discount rate 10% (tariff levelizing) Tariff: Export price: primary energy = 4.4 ¢/kWh in 2003 values 1/ Secondary energy = 2.5 ¢/kWh in 2003 values 1/ Domestic off-take price: Opportunity cost of foregone export sales Tariff profile From 2003 to COD – Escalate at 1.5% From COD onwards – Flat Costs: Development costs 1.5% of base EPC cost EPC costs Escalation: 2% pa from 2003 to COD O&M costs Escalation: 2% pa from 2003 Financing Terms: Equity Debt / Equity ratio = 70 / 30 GOL equity share = 25% Average loan terms Tenor: 10 years Interest rate: 8% Loan fees: 3.5% Grace period: none assumed 2/ GOL equity loan 3/ Tenor: 12 years Interest rate: 6 % Concession Terms: Taxes Years 1 to 5 0% of net profit – tax holiday Years 6 to 12 5% of net profit Years 13 to 25 15% of net profit Royalties Years 1 to 15 5% of sales revenue Years 16 to 25 10% of sales revenue 1/ Tariff value is escalated to the project’s COD date in the Base Export Scenario. A flat tariff is assumed. Tariff profiling may be needed accoding to a project’s debt service capacity. 2/ No grace period is assumed. This would be negotiated on a project-by-project basis according to need and would depend on a project’s early debt service capacity. 3/ Terms of loan taken out by GOL to obtain its contribution towards the equity of the project
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Table 9.2: Impacts with Financial Implications – SESAMEE Line Items
Environmental and Social Impacts Downstreams Impacts: Infrastructure / Developments Loss during filling Severely affected persons on Main River during filling Infrastructure / Developments Loss during operation Resettled affected persons on main river during operation Severely affected persons on main river during operation Transmission Line Impacts: Infrastructure / Developments Loss Resettled affected persons Severely affected persons Transmission line camp management costs (sanitation effluents, epidemics) Civil works management (erosion, drainage changes, fires) Access Road Impacts: Infrastructure/Developments Loss Resettled affected persons Access road line camp management costs (sanitation effluents, epidemics) Civil works management (erosion, drainage changes, fires) Reservoir Impacts: Infrastructure / Developments Loss Resettled affected persons Severely affected persons Drowning and loss of property during filling (wildlife, humans, domestic animals) Biomass clearance (water quality mitigation) Catchment Management Variable level intakes Destratification system Thermocline distortion devices Bottom Outlet Floating Debris and Macrophyte Management Construction Impacts: Infrastructure/Developments Loss Resettled AP's Severely AP's Labour Camp Management Costs (sanitation effluents, epidemics) Civil Works Add Management (erosion, drainage changes, fires)
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9.3 Financial Modeling of Projects for Domestic Supply
9.3.1 Required Tariffs for Bankability
Domestic generation projects could be financed either privately or publicly. Proposals from private developers are being received for domestic projects (e.g. Nam Bak 2B, Nam Pha). It is still too early to know whether medium and large IPP projects selling wholly or primarily to EdL would interest lenders; to be bankable, projects would need to meet hurdle rates of return and debt service, and to obtain cover for country and credit risks. Small grid-connected projects less than, say, 10 to 20 MW could be financed off the balance sheet and built cheaply by regional developers and they might provide a means of accessing private capital to begin with and could help “warm” the market for larger limited recourse financings.
Financial modeling of shortlisted projects has been carried out to determine the wholesale tariff each project would require to achieve these hurdle rates under normal commercial terms.
The modeling employed the following sequential steps:
1. Generation characteristics and base costs for each project were extracted from the EVALS outputs and entered into the HPO financial model.
2. Financing assumptions as described in Section 9.2 and Annex 4.1 provided other model inputs.
3. The model was used reiteratively to determine the financial tariff a project would require for it to achieve a rate of return on equity of 17% (nominal, after- tax). The results of this modeling are set out in Table 9.3 and Annex 4.4. Corresponding minimum Debt Service Coverage Ratios (DSCR) are also listed to indicate whether the projects could meet loan commitments in all years of operation at the stated tariff. If the projects were to be financed on a limited recourse basis, the financing plans of those projects with a minimum DSCR less than 1.3 would have to be structured to overcome early cash flow difficulties.
4. The projects and their calculated financial tariffs were then arranged into a supply curve (refer Figure 9.2) to indicate for any given tariff those projects best suited to private financing.
Of the projects modeled, eleven would be attractive candidates for private financing at a tariff of 8 ¢/kWh, but this reduces to only seven if the offered tariff were 6 ¢/kWh. The cash flow simulations assume limited recourse financing on standardized commercial terms. For those projects above the tariff cut-off, individual structuring of a project’s implementation and financing plans could improve its financial standing and help it overcome rate of return and debt service hurdles.
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Table 9.3: Supply Curve of Candidate Lao Projects (Financial Tariff) Project MW Primary ROE Minimum Energy Tariff nominal DSCR (c/kWh) (%) Theun Hinboun Expansion 105 4.3 17.3 1.2 Nam Mo 125 4.6 16.9 1.3 Xe Kaman 3 300 4.8 17.2 1.3 Thakho 60 5.5 17.2 1.3 Xe Kong 5 410 5.5 17.0 1.3 Nam Sane 3 60 5.7 17.1 1.2 Xe Kaman 1 470 5.7 16.9 1.2 Houay Lamphan Gnai 410 6.5 17.1 1.3 Nam Ngiep 1 + rereg dam 368 6.8 17.0 1.3 Nam Ngum 3B 690 7.2 16.8 1.3 Nam Pot 20 7.6 17.0 1.3 Nam Ngum 5 75 9.3 17.1 1.3 Nam Sim 10 9.9 17.1 1.0 Nam Bak 2B 85 10.3 17.1 1.3 Nam Long 12 10.7 17.2 1.2 Xe Katam 13 11.9 17.1 1.3 Nan Ngum 2B 195 12.1 16.9 1.3
1/ Secondary tariff is 56.3% of the primary tariff in all cases.
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Figure 9.2: Project Supply Curve (based on nominal ROE of 17%)
13 12 11 )
h 10 W k
/ 9 c
( 8 f f i
r 7
Ta 6 l a
i 5 c
n 4
na 3 Fi 2 1 0 3 1 g g m ai 3B re ta ng 5 ne 3 e k 2B Gn a r o a
man man n a a m Lon Thakho Nam Mo Nam Pot Nam Sim 1 + m B Xe K
Na Xe K Extension Xe K Xe K Nam Sa Na Nam Ngum 5 Nan Ngum 2B Nam Ngum y Lampha a n Hinboun Nam Ngiep Hou Theu
Such structuring could take a number of forms, for instance:
• Each financing could be individually arranged to overcome particular weaknesses. For instance, early debt service performance could be boosted by tariff profiling, loan grace periods and tax holidays; tax breaks could be offered to elevate investors’ returns; etc.
• Public private partnership (PPP) models could be used to share costs between the public and private sectors. PPP models are many and varied, for instance: - Some ancilary works such as infrastructure (e.g. roads and communications) could be undertaken publicly. - Where a project has multipurpose potential, civil works such as dams could be provided by by the public sector to reduce the risk profile and lower the capital cost. - The Theun Hinboun project, with 60% public ownership, provides a successful PPP model for hydropower development. This project was too difficult for either the public or private sector to develop alone but acting together, a bankable plan was devised.
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• Backing from multilateral and bilateral agencies could be enlisted to share costs, manage risks, contribute finance and assist in other ways to promote projects to instors and lenders. The role of development agencies in promoting domesticprojects is discussed in more detail in the next section.
• Hydropower projects, being renewable generators, may receive a revenue boost through some form of carbon credit.
The problem of financing the development of the Lao power system, and particularly Lao generation projects, is being considered under a separate study, the Power Sector Financing Strategy Study, currently being undertaken under World Bank funding.
9.3.2 Role of Development Agencies in Financing of Projects
Multilateral agencies and some of the larger bilateral agencies are in a position to play a key role in financing generation projects for domestic supply either through direct lending or by encouraging private lenders and investors to commit capital. Examples of such support include:
• providing concessional funding to EdL for constructing new plants;
• assisting with the further development of the legal, regulatory and institutional framework to better facilitate IPP strategies;
• providing funding for consultants to assist EdL in the preparation of projects for solicitation to the private sector (e.g. undertake project studies, obtain permits, prequalify developers, prepare Requests for Proposals, and evaluate and negotiate proposals).
• contributing to the development of bankable security packages by: - providing political risk cover (expropriation, currency convertibility, war, civil disturbance) in the form of a partial risk guarantee, and facilitating extended political risk cover (breach of contract) through cofinancing arrangements with bilateral agencies; - facilitating refinancing of completed projects (perhaps underwriting refinancing before construction commencement) to free up finance for other projects; - by assiting in the development of the local capital market (e.g. through establishment of an IPP development fund drawing on GOL’s IPP dividends and applying them to new projects).
The challenge for multilateral agencies is therefore in the formulation of policies and development of products that tailor their assistance to remedy specific market weaknesses. Their support should specifically target those risks that that market is unable to absorb and lenders will not tolerate.
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Over the last decade, EdL has had considerable difficulty obtaining finance for domestic generation projects. Of immediate interest, therefore, is the role of multilateral agencies in lending to such projects. International commercial lenders have been unable to bridge the funding gap – they are too risk averse and their money too expensive and conditional. Multilateral agencies and regional development funds, with their greater tolerance of country and credit risks, can make an important contribution to a project’s financing plan.
The benefits of multilateral agency participation were explored by modeling a project under several different financing plans. Using the Houay Lamphan Gnai project as an example, cash flow projections were prepared using the HPO financial model assuming loan conditions that typify:
• Commercial terms • IBRD terms • GOL on-lending terms to EdL • China Exim Bank
Other terms and conditions remained the same as those described in Section 9.2. The tariff needed to achieve a 17% (nominal) return on equity was determined reiteratively for each of the above financing plans and the results are summarized in Table 9.4 and Annex 4.5. They provide an indication of the sensitivity of a bankable tariff to a softening of the financing terms and conditions.
Table 9.4: Houay Lamphan Gnai: Required Tariff under Different Loan Terms
Commercial IBRD terms GOL on- China Exim Terms lending Bank 1/ terms Average interest rate (% pa) 8% 7% 6% 2% Loan term 10 years 20 years 20 years 15 years Grace period (from COD) - 5 years 4 years 5 years
Calculated ROE (% nominal) 17.1% 17.1% 17.0% 17.0% Calculated minimum DSCR 1.3 1.6 1.7 1.8
Primary Tariff (¢/kWh) 6.50 5.30 5.06 4.24
1/ In the China Exim Bank case, no allowance is made for the possibility of higher maintenance costs or shorter service life often associated with Chinese equipment.
9.4 Financial Modeling of Projects for Export Markets
9.4.1 Marketing of Project Output
The bankability of a project for export supply is linked to a number of factors, among them the creditworthiness of the power purchaser and the reputation and substance of the investors. Of crucial importance is the intrinsic quality of the site.
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The viability of those projects forming the Base Export Scenario was tested by cash flow modeling at the assumed export primary tariff of 4.4 ¢/kWh (2003 values) and using other assumptions as listed in Table 9.1). The modeling was in nominal terms with the project cash flows calculated according to the project’s COD as stated in Table 8.1. The results of the modeling are presented in Table 9.5 and indicate whether a project is likely to meet hurdle rates of return on equity and debt service coverage under the assumed tariff and financing conditions.
The performance figures listed in Table 9.5 should only be taken as a guide. The cash flow simulations from which the Table 9.5 results derive assume financing on standardized assumptions and commercial terms. As outlined at the end of Section 9.3.1, the potential exists for improving the financial viability of projects by individually structuring their implementation models and financing plans. 61
Table 9.5: Base Export Scenario - Project Financial Performance
Project COD Concession Period Service Life Minimum 3/ (25 years) (50 years) DSCR Project Equity Project Equity 4/ IRR IRR IRR IRR Nam Mo 2009 15.8% 20.0% 16.2% 20.3% 1.44 Nam Theun 2 2010 16.8% 20.3% 17.0% 20.5% 1.33 Xe Kaman 3 2011 15.1% 18.7% 15.5% 19.0% 1.38 Xe Kaman 1 2014 12.7% 14.5% 13.3% 15.2% 1.09 Xe Kong 5 2017 12.7% 14.4% 13.3% 15.1% 1.14 Nam Ngum 3B 2020 9.3% 9.2% 10.3% 10.8% 0.88
1/ Modeling is in nominal values. 2/ Theun Hinboun Expansion project is assumed to involve the addition of a single unit dedicated to the domestic market. 3/ COD is taken from the Base Export Scenario. Projects implemented later in the planning period are slightly disadvantaged due to assumptions that costs escalate at 2% while the levelized tariff escalates at 1.5% to COD. 4/ Minimum DSCR values are low in some cases. Modeling assumptions are common to all projects and in practice the each project would be individually structured to boost DSCR values to acceptable levels.
9.4.2 GOL Net Revenue Benefits
The Lao IPP export program is promoted by GOL to earn revenues for pursuing its development objectives. Projects proposed for export development under the Base
61 This important point should also be borne in mind in considering the prospects of some major IPP projects that were excluded from the project shortlist and the Base Export Scenario (e.g. Xe Pian-Xe Namnoy, Nam Ngum 2, and Hongsa). With market improvement and careful packaging, such projects could be viable and should not be discounted.
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Export Scenario are listed in Table 8.1, i.e. Nam Mo, Nam Theun 2, Xe Kaman 3, Xe Kaman 1, Xe Kong 5 and Nam Ngum 3B. 62
The GOL net revenue stream (taxes and royalties) and EdL net revenue stream (dividends less debt service payments) were derived from the modeling of export projects to determine their financial performance (refer Section 9.4.1). The project costs and energy production figures calculated using EVALS have been consistently applied for all projects in estimating the GOL receipts. These may differ in some cases from official estimates. For instance, the official GOL estimate of Nam Theun 2 receipts is based on a more conservative estimate of primary energy production (i.e. 4,406 GWh, versus 4,883 GWh as calculated using EVALS).
The cash flow projections assume project CODs as specified in the Base Export Scenario. Individual project cash flows are escalated accordingly and aggregate cash flows therefore replicate the GOL receipts in nominal terms for each year of the modeling period. The estimated annual and aggregate cash flows for each project are presented in Annex 4.3 and are summarized in Table 9.6.
Table 9.6: GOL IPP Revenues - Net Receipts from Base Export Scenario
Year Royalties Taxes Dividends Total ($ mill) ($ mill) ($ mill) Receipts ($ mill) 2008 0.0 0.0 0.0 0.0 2009 1.4 0.0 -1.8 -0.4 2010 10.5 0.0 -12.5 -1.9 2011 15.0 0.0 -2.6 12.4 2012 15.5 0.0 7.5 23.1 2013 15.7 0.0 11.8 27.5 2014 20.8 0.9 7.7 29.4 2015 21.6 7.4 12.7 41.7 2016 21.8 9.8 18.3 49.9 2017 26.2 10.4 20.0 56.5 2018 26.9 10.5 28.6 66.1 2019 27.1 13.9 38.0 78.9 2020 34.2 14.5 29.8 78.4
62 The Theun Hinboun Expansion project is assumed to comprise a single new unit dedicated to supplying EdL but it could be configured with additional units for export service. These have not been taken into account in the calculation of GOL receipts.
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10.0 NAM THEUN 2 ISSUES
10.1 Scope of Nam Theun 2 Issues
The Nam Theun 2 PPA and concession agreement have been executed and these documents contractually commit GOL, EGAT and NTPC to the key parameters of the present project layout and design. The Nam Theun 2 issues explored under the PSDP are based on the NTPC concept design, with some comparisons being made to the earlier 681 MW project configuration.
The TOR defines specific tasks in relation to the Nam Theun 2 Hydroelectric Project; they are to:
(i) Evaluate alternative reservoir Full Supply Levels (FSLs)
(ii) Compare Nam Theun 2 with alternative power projects and determine:
• whether the power EdL receives from Nam Theun 2 as domestic off- take will be at lower cost than the power from alternative projects; and
• whether the revenues paid by NTPC to GOL and EdL as taxes, royalties and dividends will be greater than corresponding revenues from alternative projects.
(iii) Determine how long it will take for the domestic off-take allocation from Nam Theun 2 of 300 GWh per annum to be fully absorbed by the Lao power system.
10.2 Comparison of Full Supply Levels
10.2.1 Effect of FSL on Economic Performance
The economic performance of the Nam Theun 2 project was simulated across a range of FSLs and the trade-off between economic and environmental attributes was examined.
The NTPC concept design configuration (FSL = 538 masl) is the reference case and the effect of reducing the size of the reservoir was simulated using EVALS. The relationship between economic performance and FSL is reported in Table 10.1 in terms of annual energy production and generation cost as a percentage of the NTPC reference case.
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Table 10.1: Nam Theun 2 – Comparison of FSLs
Reservoir Installed Energy Relative Relative Capacity Generation Project Cost Generation FSL Area Volume (MW) (GWh pa) (%) Cost (%) 1/ (m asl) (km2) (mcm) 538 450 3680 1074 5,898 (100%) 100 100 535 354 2466 1070 5,218 (88%) 98 118 532 291 1498 1060 4,674 (79%) 96 136 530 218 984 1050 4,544 (77%) 94 150 528 164 602 1040 4,357 (74%) 92 225
NOTES: 1/ Based on weighted average generation cost. 2/ Energy outputs are adjusted for reduced generation at Theun Hinboun (210 MW)
It can be seen that the cost of generation increases sharply as FSL is lowered. The generation cost at RL 532 masl is 36% higher than the reference case and FSLs below this level were not considered further in the analysis of trade-offs between economic and environmental attributes. Three project alternatives were shortlisted for further study from some 80 variants examined initially under the Nam Theun 2 Study of Alternatives (Lahmeyer/Worley, 1998). The shortlisted project layouts are:
1. Reference case as proposed by NTPC (FSL = 538 masl) 2. Run-of-river case (FSL = 532 masl) 3. Ban Signo case with the dam moved upstream (FSL = 538 masl)
The PSDP analysis of these three cases draws on the work conducted initially under the Nam Theun 2 Study of Alternatives, and updates it to incorporate additional information now available and reflect changes to the installed capacity of the project.
10.2.2 Run-of-River Case
The run-of-river layout involves a significantly smaller reservoir (FSL of 532 masl). This would have a number of social and environmental benefits:
• The area inundated at a FSL of 532 masl would be substantially reduced, with the reservoir covering only 40 km2 or less than 10% of the NTPC case);
• The length of river inundated would be about 25% of the NTPC case;
• The regulation effect on the Nam Theun would be less and more water would spill downstream, slightly reducing biodiversity impacts in that reach;
• Flood levels in the Nam Theun would be higher than the natural condition due to the diversion weir and communities living adjacent to the river would still be affected. About 1000 people would need to be resettled, compared with 6,000 for the NTPC case;
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• Fisheries yields from the smaller reservoir would be less than those expected from the NTPC reservoir but downstream fisheries might benefit slightly from the increased spill in the downstream reach;
• Project impacts on terrestrial biodiversity would be reduced due to the smaller area of inundation;
• Two thirds of the Nakai wetlands would be preserved;
• With less water diverted through the turbines, effects in the Xe Bang Fai would be reduced slightly.
Although the social and environmental advantages of the smaller reservoir are significant, they are associated with a 36% increase in the cost of generation. Such a change would fundamentally affect the viability of the project under current market conditions. It is difficult to see how the project with a reservoir FSL of RL 532 masl could simultaneously meet the EGAT avoided cost tariff ceiling and investors’ minimum rate of return criteria.
10.2.3 Ban Signo Case
The Ban Signo variant has the same FSL as the NTPC reference case but moving the dam to a site about 10 km upstream reduces impacts. Two variants of the Ban Signo case were investigated – one with the same installed capacity as the NTPC proposal and one with the same ICF (equivalent to an installed capacity of 945 MW).
The principal social benefit of moving the dam upstream to Ban Signo is a reduction of 413 (or 9%) in the number of people resettled.63 From an environmental perspective, the reservoir area would reduce by 137 km2 (30%). Of this area, about 100 km2 is degraded by logging but 20 km2 of pristine forest would be saved, i.e. about 2% of this forest type in the NBCA and about 10% of that found at low elevations. With a smaller reservoir, the Ban Signo dam would also be associated with a marginal increase in downstream flows and the aquatic ecology might benefit from this. The corollary is that fisheries in the smaller reservoir would be reduced marginally. There are no wetlands in the reach between the NTPC dam site and Ban Signo and therefore the move will not alleviate wetlands impacts.
A comparison of the economic benefits of the NTPC and Ban Signo cases is presented in Table 10.2. It indicates that the trade-off for the social and environmental gains would be a 20% higher cost of generation, an increase that could undermine the viability of the project under current market conditions. Further concessions in taxes and royalties could be made to help early cash flow and debt service but this would cut into GOL’s revenue stream and bring into question the whole basis for pursuing the project.
63 Provided WCD standards are adhered to, people resettled should be better off than before and it could be argued that the reduction in resettlement is also a reduction in non-monetary project benefits.
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Table 10.2: Nam Theun 2 - Comparison of NTPC and Ban Signo Cases
Alternative Installed Annual Basic Generation Costs Capacity Energy Cost (MW) (GWh) (mUS$) Average Weighted (¢/kWh) (¢/kWh) NTPC dam site 1074 5860 644 1.43 1.51
Ban Signo dam site - 945 4975 645 1.67 1.76 same ICF (-12%) (-15%) (0%) (+17%) (+17%)
Ban Signo dam site - 1074 5142 696 1.75 1.83 same capacity (MW) (0%) (-12%) (+8%) (+22%) (+21%)
Again, the Ban Signo case is associated with social and environmental gains but they are not as extensive as would appear on first inspection. The downside is an increase in the cost of generation of about 20% and such an increase would be difficult to reconcile with EGAT’s avoided cost tariff ceiling and investors’ minimum rate of return criteria.
10.3 Comparison of Benefits from Nam Theun 2
10.3.1 Scope of Benefits Review
The PSDP TOR seeks confirmation that: (i) the power EdL receives from Nam Theun 2 as domestic off-take will cost less than the power from alternative projects; and (ii) the revenues paid by NTPC to GOL and EdL as taxes, royalties and dividends will be greater than corresponding revenues from alternative projects. These issues were investigated using project simulations as necessary and the conclusions are reported in the following sections.
10.3.2 Least Cost Domestic Supply
In relation to the matter of the price of domestic off-take from Nam Theun 2, the price paid by EdL for power from an export IPP project such as Nam Theun 2 is tied to the opportunity cost of that power to the project company, i.e. the revenue foregone by the project company for each unit of output sold to EdL rather than the foreign off- taker. In general terms, the revenue foregone will be equal to the export tariff as adjusted to take account of transmission loss differentials and wheeling costs. The export tariff is determined, in turn, by negotiation based on avoided cost within the foreign off-taker’s system at the time the tariff was negotiated (refer Section 5.8).
This general proposition assumes that the quality of the traded energy is the same for the domestic and foreign purchasers and, more particularly, that the terms governing the contractual commitment to supply are the same, i.e. firm / non-firm, liquidated damages, etc. In the specific case of Nam Theun 2, the level of supply commitment is different in detail and this is reflected in differences in the value and structure of the EGAT and EdL tariffs.
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The domestic off-take tariffs from other candidate export projects are not yet fixed and therefore firm comparisons with Nam Theun 2 cannot be made. However, one can speculate that the same tariff setting imperatives will apply and that, regardless of the project, the wholesale tariff paid by EdL will reflect the avoided cost in the foreign purchaser’s system, be it EGAT or EVN. Thus, comparisons between the domestic off-take tariffs of Nam Theun 2 and other projects are not particularly relevant. The characteristics of a project determine whether it will proceed, not the value of the tariff it receives. The value of tariff depends more on the characteristics of the buyer’s system and the skills of the negotiating teams.
To determine whether Nam Theun 2 will provide least-cost domestic power, it then remains to be seen whether domestic off-take is cheaper than power generated by projects built exclusively for supply to EdL. This will depend on the characteristics of the competing domestic project and its financing terms. Table 10.3 presents a comparison between the Nam Theun 2 tariff and the calculated costs of production from shortlisted domestic projects. The Nam Theun 2 and Theun Hinboun off-take tariffs are based on the rates specified in their respective PPAs. For the other projects, the lowest tariff that would achieve a return on equity of 17% (nominal) is used (refer Table 9.3). The tariffs in Table 9.3 and the Nam Theun 2 and Theun Hinboun PPA rates are not comparable as the Table 9.3 rates quote only the primary energy tariff and do not account for the portion of output paid at the lower secondary energy rate (modelled at 56% of the primary energy tariff). To give greater meaning to the Table 10.3 comparison, the non-PPA tariffs are presented as weighted combined tariffs, calculated according to the proportion of primary and secondary energy produced by a project in an average year.
The comparison of tariffs confirm the intuitive position that Nam Theun 2 domestic off- take is competitive when compared with Lao-based generation, whether it is sourced as domestic allocations from primarily export projects or as output from domestic projects developed under commercial terms. However, domestic projects developed with concessional finance might well produce cheaper output if projects are carefully selected, and proper procurement standards apply.
10.3.3 GOL Revenues from Nam Theun 2 Export Sales
The TOR asks whether the GOL receipts over the lifetime of the project will be greater than those generated by other projects. GOL receipts from IPP projects come in the form of taxes, royalties and dividends. Dividends deriving from GOL’s equity in the project are paid to the agency nominated by GOL to hold the shares – EdL in the case of Theun Hinboun and Houay Ho.
The strength of the GOL revenue stream depends on a number of factors including average annual generation, tariff, GOL equity share and concession terms (taxes and royalties). The earnings potential of Nam Theun 2 has been demonstrated by a number of consultants including Louis Berger, Credit Agricole Indosuez and Lahmeyer/Worley. The Lahmeyer/Worley studies 64 used financial modeling of Nam Theun 2 and competing candidates based on actual and assumed tariffs and concession terms to quantify and compare the respective GOL revenue streams.
64 Nam Theun 2 Study of Alternatives (Lahmeyer/Worley, 1998) and Hydropower Development Strategy Study (Worley/Lahmeyer, 2000)
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Table 10.3: Nam Theun 2 EdL Tariff - Comparison with Domestic Generation
Project MW Financial Comments Weighted Tariff 1/ (¢/kWh) Nam Theun 2 75 3.91 Tariff in EdL PPA, levelized in 2003 dollars Theun Hinboun Exp. 105 4.59 Current EdL off-take tariff from THB Thakho 60 5.50 Mainstream Mekong, counter-seasonal 2/ Nam Sane 3 60 5.56 Large resettlement problem Nam Ngiep 1 368 6.07 Includes generation from reg. dam H. Lamphan Gnai 56 6.41 Nam Sim 10 7.17 Large proportion of secondary energy Nam Pot 20 7.49 Xe Katam 13 7.65 Run-of-river – mainly secondary energy Nam Ngum 5 75 8.89 Nam Long 12 9.74 Nam Bak 2B 85 9.92 Modeled as a storage project
1/ Unless otherwise specified in the “Comments” column, the quoted tariff is the weighted combined tariff for primary and secondary energy tariff calculated in financial terms to equate to the levelized tariff specified in the Nam Theun 2 EdL PPA. The primary and secondary tariffs were those required to achieve a 17% nominal return on equity and minimum debt service coverage of around 1.3. 2/ Thakho is run-of-river and produces predominantly secondary energy but it is counter-seasonal, producing most of its energy in the dry season and its output is therefore valued at primary energy rates. Also, although attractive in a financial sense, the potential economic impacts are difficult to assess and it is penalized heavily in an economic / SESAMEE evaluation.
In the time since these studies were done, many of the frontline candidates have been overtaken by events. Some have not progressed since the onset of the Asian Economic Crisis seven years ago. Nam Theun 2, Nam Mo and Xe Kaman 3, though, have formal standing in the power development plans of EGAT or EVN and it is understood that the prospects for Theun Hinboun Expansion are bright. The status of the developer groups, tariff agreements and concession terms of other projects are in doubt and the revenue comparisons are therefore based on a standardized set of assumptions rather than on lapsed or neglected agreements (refer Annex 4.3).
The comparison of benefits of Nam Theun 2 with other candidates has been approached from both economic and financial perspectives:
(i) Economic Comparison
Using EVALS and SESAMEE, an economic study of all shortlisted projects, including Nam Theun 2, was carried out. The economic benefits of projects, as represented by the average and weighted cost of generation, are compared in Tables 6.12 and 6.13 and these establish Nam Theun 2 as the most beneficial candidate by a comfortable margin.
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(ii) Financial Comparison
The financial performances of shortlisted export alternatives were simulated and cash flow projections prepared as described in Section 9. Standard assumptions were used for all projects other than Nam Theun 2, for which the contractually binding tariff and concession conditions were used. A comparison of tax, royalty and dividend streams of the various projects produces a similar finding to the economic evaluation, with the benefits from Nam Theun 2 exceeding those of other candidates (refer Table 10.4). It is evident from the financial analyses that superior characteristics of the Nam Theun 2 site allow more favorable tax and royalty conditions to be negotiated without impairing the project’s ability to clear return-on-equity and debt service hurdles. Thus, the benefits from Nam Theun 2 should be greater not only because of the project’s larger energy production, but also because GOL is likely to receive more on a per GWh basis.
Table 10.4: GOL Net Receipts (nominal) – Common Construction Start (2003)
Project 2/ Base Royalties Taxes Dividends Total GOL GOL Cost 1/ Receipts 3/ Receipts
NPV @ 10% NPV @ 10% NPV @ 10% ($ mill) NPV @ 10% (% Base Cost) ($ mill) ($ mill) ($ mill) ($ mill) Xe Kaman 3 278 33.3 23.4 72.7 129.4 47% Nam Theun 2 617 101.3 60.8 113.3 275.5 45% Nam Mo 116 10.8 6.8 16.6 34.2 29% Xe Kaman 1 420 36.5 22.4 45.1 103.9 25% Xe Kong 5 400 33.3 20.4 45.6 99.4 25% Nam Ngum 3B 773 51.1 28.9 44.7 124.7 16% Nam Ngum 2B 180 10.3 1.9 -10.4 1.8 1% 1/ Base cost including SESAMEE environmental and social impacts (positive and negative) 2/ All projects other than Nam Theun 2 modeled according to common set of assumptions as described in Section 9.2. All projects, including Nam Theun 2, modeled on a common COD. 3/ GOL receipts have been estimated using project costs and energy production figures calculated using EVALS. In the case of Nam Theun 2, the official GOL estimate of Nam Theun 2 receipts is based on a more conservative estimate of primary energy production (i.e. 4,406 GWh, versus 4,883 GWh as calculated using EVALS).
10.4 Absorption of Domestic Off-take
Nam Theun 2 is located strategically in the C2.1 supply area and will contribute 300 GWh p.a. to the grid which, by the time of commissioning, will be interconnected to the C1 and C2.2 grids. Demand growth within the central area of Lao PDR is very rapid and will remain so for a few years. Increasing economic activity is boosting demand generally but this is being further boosted by significant new point loads related to the Sepone mine, Nam Theun 2 construction, a cement factory, expanding irrigation and other industrial loads. This growth is currently being met by imports. The optimal power system expansion scenario identified by the SEXSI simulations would restore a balance by interconnecting the C1, C2.1 and C2.2 grids (2005) and by taking output from Theun Hinboun Expansion (from 2008) and Nam Theun 2 (from
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2010). The SEXSI power system simulations demonstrate that the commissioning of Theun Hinboun Expansion (105 MW) in 2008 would reduce imports to less than 10%. Demand growth from 2008 would see imports rise again but in 2010 the Nam Theun 2 domestic off-take would restore the situation by absorbing the demand growth for the two years between the CODs of the two projects. It therefore follows that the domestic allocation of Nam Theun 2 will be absorbed, if not immediately, then within a short time.
Antecedent supply and demand conditions are fundamental to this outcome, with the timing of prior capacity increments and transmission interconnections largely determining the result. If capacity is added to the system before it goes into deficit, surplus power can be sold to Thailand while domestic demand catches up with the augmented system capacity. Such trade would, however, attract only a non-firm energy tariff. The more attractive option from economic and financial perspectives involves a strategy in which a deficit, balanced by imports from Thailand, is allowed to develop in advance of new capacity. In this way, new plant will be employed more fully upon entering commercial service, allowing the economic benefits of investments to be maximized from the outset.
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