March 2012 Prepared for: The Ministry of Economy, Trade and ...

STUDY ON PRIVATE-INITIATIVE INFRASTRUCTURE PROJECTS

IN DEVELOPING COUNTRIES IN FY2011

STUDY ON THE COAL GASIFICATION AND POWER

GENERATION PROJECT IN MAE MOH, THE KINGDOM OF

THAILAND

FINAL REPORT

March 2012

Prepared for:

The Ministry of Economy, Trade and Industry

Prepared by: The Institute of Energy Economics, Japan

Mitsubishi Corporation Chiyoda Corporation

Reproduction Prohibited

Preface

This report summarizes the results of the "Study on Private-Initiative Infrastructure Projects in

Developing Countries" in FY 2011, entrusted to the Institute of Energy Economics, Japan, Mitsubishi

Corporation, and Chiyoda Corporation by the Ministry of Economy, Trade and Industry.

This study entitled "Study on the Coal Gasification and Power Generation Project in Mae Moh, the

Kingdom of Thailand" was carried out in order to assess the feasibility of the project to introduce

Integrated Coal Gasification Combined Cycle (IGCC) plants at a cost of between 110 and 125 billion

yen. The project aims to make effective use of lignite produced in the Mae Moh Coal Mine, to improve

the power source structure heavily relying on gas-fired power generation (to diversify energy sources),

to solve problems inherent in Thailand, such as the opposition movement against the construction of

coal-fired power plants caused by the past air pollution problem (to further improve environmental

measures), and to take climate change measures.

We sincerely hope this report will contribute to the implementation of the aforementioned project and

provide practical information to parties concerned in Japan.

March 2012

The Institute of Energy Economics, Japan

Mitsubishi Corporation

Chiyoda Corporation

Project Site Map

Project Site

Bangkok

Chiang Mai

N

(Source) “Global Internet Partner Utopia Co.,Ltd.” website

Abbreviations

AGR Acid Gas Removal Units

ASU Air Separation Units

B/C Benefit/Cost

BOI Thai Board of Investment

CCS Carbon dioxide Capture and Storage

CCT Clean Coal Technology

CDM Clean Development Mechanism

COD Chemical Oxygen Demand

COP17 17th Conference of the Parties

CaO Calcium Oxide

ECA Energy Conversion Agreement

EGAT Electricity Generating Authority of Thailand

EHIA Environmental and Health Impact Assessment

EIA Environmental Impact Assessment

EIRR Equity Internal Rate of Return

EPC Engineering, Procurement, Construction

EPRI Electric Power Research Institute

FEED Front End Engineering Design

FIRR Financial Internal Rate of Return

FS Feasibility Study

GDP Gross Domestic Product

GTCC Gas Turbine Combined Cycle

HHV Higher Heating Value

HPS High Pressure Steam

HR Heat Rate

HRSG Heat Recovery Steam Generator

IGCC Integrated Coal Gasification Combined Cycle

IMF International Monetary Fund

IPP Independent Power Producer

ISO International Organization for Standardization

JBIC Japan Bank for International Cooperation

JBR Jet Bubbling Reactor

JETRO Japan External Trade Organization

JICA Japan International Cooperation Agency

LHV Lower Heating Value

LPG Liquefied Petroleum Gas

LTGC Low Temperature Gas Cooling Unit

MDEA Methyldiethanolamine

MHI Mitsubishi Heavy Industry, Ltd.

MPS Middle Pressure Steam

NEDO New Energy and Industrial Technology Development Organization

NEPC National Energy Policy Council

NETL National Energy Technology Laboratory

NGCC Natural Gas Combined Cycle

NPV Net Present Value

O&M Operation & Maintenance

ODA Official Development Assistance

PDP 2010 Summary of Thailand Power Development Plan 2010-2030

PPP Public Private Partnership

RWE Rheinisch-Westfalisches Elektrizitatswerk

SC Supercritical

SCGP Shell Coal Gasification Process

SGC Syngas Cooler

SPP Small Power Producer

SRU Sulfur Recovery Unit

SS Suspended Solid

UNFCCC United Nations Framework Convention on Climate Change

USC Ultra Supercritical

VSPP Very Small Power Producer

WACC Weighted Average Cost of Capital

WTA German abbreviation standing for fluidized-bed drying with internal waste heat utilization

toe ton of oil equivalent

Contents

Executive Summary .......................................................................................................................... 1

(1) Background, necessity, etc. of the project.......................................................................................2

(2) Basic policy concerning the determination of project contents.......................................................2

(3) Outline of the project ......................................................................................................................3

(4) Implementation schedule ................................................................................................................4

(5) Feasibility concerning operation.....................................................................................................6

(6) Technical advantages of Japanese companies.................................................................................6

(7) Concrete schedule for the project completion and risks that may prevent the completion .............6

(8) Map showing the project site in the country surveyed....................................................................8

Chapter 1 Overview of the country and sector to be invested ................................................... 9

(1) The economic and fiscal conditions of the country to be invested................................................10

a) Political conditions.........................................................................................................................10

b) Economic conditions .....................................................................................................................12

c) Social conditions............................................................................................................................14

d) National fiscal conditions ..............................................................................................................15

(2) Overview of the target sector of the project ..................................................................................17

a) Energy supply and demand ............................................................................................................17

b) Electric power supply and demand ................................................................................................20

(3) Situation of the Target Region ......................................................................................................22

Chapter 2 Study Methodology ................................................................................................. 25

(1) Study Details.................................................................................................................................26

a) Background and Objectives ...........................................................................................................26

b) Study Details..................................................................................................................................27

(2) Study Methodology and Framework.............................................................................................28

a) Study Methodology........................................................................................................................28

b) Study Framework...........................................................................................................................28

(3) Study Schedule .............................................................................................................................30

a) Domestic Study..............................................................................................................................31

b) Field Study.....................................................................................................................................31

Chapter 3 Consideration of Details of Project and Technical Aspect ...................................... 35

(1) Background and Needs of the Project...........................................................................................36

a) Scope of the project .......................................................................................................................36

b) Analysis of the current situation, future prediction, and problems anticipated when this

project is not implemented............................................................................................................39

c) Effects and impacts when this project is implemented...................................................................45

d) Comparison with other options......................................................................................................46

(2) Considerations Required for Deciding the Details of the Project .................................................48

a) Demand prediction.........................................................................................................................48

b) Understanding and analysis of the problems required for considering and deciding the

details of the project......................................................................................................................50

c) Consideration of the technical methods .........................................................................................57

(3) Overview of the Project ................................................................................................................67

a) Basic policy for deciding the details of the project ........................................................................67

b) Conceptual design and specifications of the applicable facilities ..................................................67

c) Details of the proposed project (oxygen-blown gasification) ........................................................71

d) Details of the proposed project (air-blown gasification)................................................................95

e) Current Situation of Coal Mines and Coal Procurement Plan......................................................105

Chapter 4 Evaluation of Environmental and Social Impacts ................................................. 119

(1) Analysis of Current Situation in Environmental and Social Aspects ..........................................120

a) Analysis of the current situation...................................................................................................120

b) Future prediction (When the project is not implemented) ...........................................................125

(2) Environment Improvement Effects Consequent upon Project Implementation ..........................125

(3) Effects on Environmental and Social Aspects Consequent upon Project Implementation..........129

a) Results of examining the environmental and social consideration items .....................................129

b) Comparison with other options having less environmental and social impacts ...........................142

c) Discussions, etc. with the implementing agency..........................................................................143

(4) Overview of Related Laws and Regulations for Environmental and Social Considerations

in Host Country...........................................................................................................................144

a) Overview of the related laws and regulations for the environmental and social

considerations concerning project implementation.....................................................................144

b) Details of EIA (Environmental Impact Assessment) of the host country required for

project implementation ...............................................................................................................144

(5) Matters to Be Accomplished by Host Country (Implementing Agency and Other

Authorities Concerned) for Realization of Project......................................................................145

Chapter 5 Financial and Economic Evaluation ...................................................................... 147

(1) Project Cost Integration ..............................................................................................................148

a) Plant construction cost .................................................................................................................148

b) Required operators.......................................................................................................................148

c) Maintenance/service cost .............................................................................................................148

(2) Outline of Results of Preparatory Financial and Economic Analyses.........................................149

a) Results of financial analysis.........................................................................................................149

b) Results of economic analysis .......................................................................................................160

c) Feasibility of bilateral credit ........................................................................................................166

d) Syngas production option ............................................................................................................167

Chapter 6 Planned Project Schedule ...................................................................................... 171

(1) Project overall operation .............................................................................................................172

a) Detailed FS: 10-12 months ..........................................................................................................172

b) FEED (Front End Engineering Design): 12-15 months ...............................................................172

c) EPC (Engineering, Procurement, Construction): 33-36 months ..................................................173

Chapter 7 Implementing Organization .................................................................................. 175

(1) Implementing Organization ........................................................................................................176

Chapter 8 Technical Advantages of Japanese Company ........................................................ 179

(1) Assumed participation forms of Japanese corporations (investment, equipment supply,

facility operation management etc.)............................................................................................180

(2) Advantages of Japanese corporations upon implementing this project (technical and

economic aspects) .......................................................................................................................181

a) Technical advantages ...................................................................................................................181

b) Economic advantages ..................................................................................................................181

(3) Measures necessary to promote contract winning by the Japanese corporations ........................182

Chapter 9 Financial Outlook .................................................................................................. 183

(1) Review for financial sources and a financial procurement plan..................................................184

(2) Feasibility of financial procurement ...........................................................................................184

(3) Cash flow analysis ......................................................................................................................184

Chapter 10 Action Plan and Issues .......................................................................................... 189

(1) Efforts being made toward the project implementation ..............................................................190

(2) Efforts being made by counterpart government agencies and implementing bodies toward

the project implementation .........................................................................................................191

(3) Presence or absence of the counterpart’s legislative and financial constraints, etc. ....................191

(4) Necessity of additional detail analysis ........................................................................................192

List of Figures

Figure S-1 FIRR calculation result ............................................................................................................ 3

Figure S-2 Overall schedule of the project ................................................................................................ 5

Figure S-3 Project Site Map....................................................................................................................... 8

Figure 1-1 Changes in real GDP growth rate of Thailand........................................................................ 13

Figure 1-2 GDP per capita by region in Thailand (2007-08 average)...................................................... 15

Figure 1-3 Changes in the balance between revenues and expenditures in Thailand............................... 16

Figure 1-4 Changes in primary energy supply......................................................................................... 18

Figure 1-5 Domestic production and exports and imports (2009) ........................................................... 18

Figure 1-6 Changes in final energy consumption .................................................................................... 19

Figure 1-7 Outlook of primary energy supply ......................................................................................... 19

Figure 1-8 Changes in generated electricity by fuel type......................................................................... 20

Figure 1-9 Changes in electric power demand by use ............................................................................. 20

Figure 1-10 Power demand and peak demand forecast (as of February 2010) ........................................ 21

Figure 1-11 Power Development Plan (2010-2030) ................................................................................ 22

Figure 1-12 Site Location ........................................................................................................................ 23

Figure 2-1 Study Framework ................................................................................................................... 28

Figure 2-2 Study Framework ................................................................................................................... 30

Figure 3-1 EGAT Power Source Composition in 2010............................................................................ 36

Figure 3-2 Kingdom of Thailand ............................................................................................................. 37

Figure 3-3 Mae Moh District, Lampang .................................................................................................. 38

Figure 3-4 Mae Moh Coal Mine and Power Plant ................................................................................... 38

Figure 3-5 Load Factor ............................................................................................................................ 43

Figure 3-6 Tendency of Plant efficiency (Total fuel: HHV) .................................................................... 44

Figure 3-7 Monthly Peak Output (MW) .................................................................................................. 48

Figure 3-8 Typical Daily Output (Max & Min) ....................................................................................... 49

Figure 3-9 Candidate Sites for New IGCC Power Plant.......................................................................... 51

Figure 3-10 Candidate Site for New IGCC Power Plant (Next to Unit 13) ............................................. 52

Figure 3-11 Candidate Site for New IGCC Power Plant (Outside Power Plant Area) ............................. 52

Figure 3-12 Candidate Site for New IGCC Power Plant (Backside, Option) .......................................... 53

Figure 3-13 Mechang Reservoir .............................................................................................................. 54

Figure 3-14 Regulating Pond................................................................................................................... 54

Figure 3-15 Electric Power System of Thailand ...................................................................................... 56

Figure 3-16 Anticipated Improvement of Steam Turbine Efficiency by Introducing the SC and USC

Coal-Fired Power Plants to the Mae Moh Thermal Power Plant ......................................... 59

Figure 3-17 Boiler Design Examples Depending on Type of Coal Used for Coal-Fired Power Plant

(660 MW) ............................................................................................................................ 61

Figure 3-18 Temperature and Precipitation in Vicinity of Mae Moh District .......................................... 69

Figure 3-19 Facility Configuration Diagram of Coal-Fired IGCC Plant ................................................. 71

Figure 3-20 Construction Record and Prediction of Gasification Plants by Licenser.............................. 74

Figure 3-21 Effects of GT-ASU Air Integration on Efficiency ................................................................ 77

Figure 3-22 Simple Flow of Coal Drying and Coarse Crushing Facility................................................. 78

Figure 3-23 Simple Shell Gasification Process Flow .............................................................................. 79

Figure 3-24 Simple Acid Gas Removal Process Flow ............................................................................. 81

Figure 3-25 Integration between Combined Cycle Unit and Other Facilities.......................................... 84

Figure 3-26 Simple Air Separation Unit Process Flow............................................................................ 86

Figure 3-27 Waste Water Treatment Unit Block Flow............................................................................. 87

Figure 3-28 Block Flow Chart ................................................................................................................. 89

Figure 3-29 Plant Layout Drawing .......................................................................................................... 91

Figure 3-30 Improvement of Electricity Cost .......................................................................................... 94

Figure 3-31 Process Flow of Air-blown IGCC ........................................................................................ 96

Figure 3-32 Operating Principle for the MHI Air-Blown Two-Stage Entrained-Bed Gasifier................. 97

Figure 3-33 Typical Gasification Plant Process Flow Diagram ............................................................... 99

Figure 3-34 Typical Plant Layout .......................................................................................................... 104

Figure 3-35 Typical Plant Construction Schedule.................................................................................. 105

Figure 3-36 Coal Resource Distribution in Thailand ............................................................................. 106

Figure 3-37 Geological Column of Mae Moh Coal Mine...................................................................... 107

Figure 3-38 Coal Bed with Drastic Split Seams .................................................................................... 108

Figure 3-39 Main Cross-Sectional Charts.............................................................................................. 108

Figure 3-40 Lower Part Structure of Layer Q........................................................................................ 109

Figure 3-41 Coal Production Performance and Strip Ratio at Mae Moh Coal Mine ............................. 109

Figure 3-42 Final Geometry of Mining Area ......................................................................................... 110

Figure 3-43 Panoramic View of Pit.........................................................................................................111

Figure 3-44 Mining Equipment ............................................................................................................. 112

Figure 3-45 Panoramic View of Coal Stockpile..................................................................................... 113

Figure 3-46 Coal Consumption Plan (1) ................................................................................................ 116




Figure 4-1 General comparison among environmental performance (Oxygen Content in Exhaust

Gas: 7% for PC Boiler, 15% for IGCC)............................................................................... 126

Figure 4-2 General comparison among environmental performance (Oxygen Content in Exhaust

Gas: 7% for PC Boiler, 7% for IGCC)................................................................................. 127

Figure 4-3 Project Approval Process ..................................................................................................... 145

Figure 5-1 FIRR calculation results (oxygen-blown IGCC).................................................................. 152

Figure 5-2 Results of the FIRR sensitivity analysis on the construction cost (oxygen-blown IGCC) ... 153

Figure 5-3 NPV (oxygen-blown IGCC)................................................................................................. 153

Figure 5-4 FIRR calculation results (air-blown IGCC).......................................................................... 158

Figure 5-5 Results of the FIRR sensitivity analysis on the construction cost (air-blown IGCC)........... 158

Figure 5-6 NPV (air-blown IGCC) ........................................................................................................ 158

Figure 5-7 Recovery of increment of initial investment by difference of fuel and O & M cost

(IGCC at Mae Moh vs USC by imported coal).................................................................... 161

Figure 5-8 Sensitivity analysis with construction cost of USC by imported coal .................................. 163

Figure 5-9 Sensitivity analysis with the imported coal price ................................................................. 163


(IGCC at Mae Moh vs GTCC by imported LNG) ............................................................. 164

Figure 5-11 Sensitivity analysis with construction cost of GTCC by imported LNG............................ 166

Figure 5-12 Sensitivity analysis with LNG price................................................................................... 166

Figure 5-13 Transition of consumption by LPG application in Thailand (1990 to 2010) ...................... 168

Figure 5-14 Transition of import and export volume in Thailand.......................................................... 169

Figure 5-15 Transition of LPG price in Thailand................................................................................... 170

Figure 6-1 Project overall schedule ....................................................................................................... 172

Figure 7-1 EGAT Power Source Composition in 2010.......................................................................... 177

Figure 8-1 Assumed project structure .................................................................................................... 180

List of Tables

Table 1-1 Key Cabinet Ministers of Thailand (As of August 2011)......................................................... 11

Table 1-2 Major economic policies of the new administration of Thailand............................................. 17

Table 1-3 Power Generation Facilities of Mae Moh Power Plant............................................................ 24

Table 2-1 Members of Study Team.......................................................................................................... 29

Table 2-2 Counterpart .............................................................................................................................. 30

Table 2-3 First Field Study ...................................................................................................................... 32

Table 2-4 Second Field Study .................................................................................................................. 33

Table 2-5 Third Field Study (Scheduled)................................................................................................. 34

Table 3-1 Scope of Investigation for Construction Work in This Project ................................................ 39

Table 3-2 Specifications of Existing Power Generation Facilities ........................................................... 40

Table 3-3 Operation Records of Existing Power Generation Facilities (2006 to 2010) ........................... 42

Table 3-4 Latest Performance Test (Typical Coal: HHV) ........................................................................ 44

Table 3-5 Anticipated Improvement of Boiler Efficiency by Introducing the SC and USC

Coal-Fired Power Plants to the Mae Moh Thermal Power Plant ............................................. 58

Table 3-6 Anticipated Improvement of Plant Heat Efficiency ................................................................. 60

Table 3-7 Comparison of Proposed and Alternative Technologies .......................................................... 65

Table 3-8 USC Coal-Fired Power Plants (Japan)..................................................................................... 66

Table 3-9 SC/USC Coal-Fired Power Plants (Overseas) ......................................................................... 66

Table 3-10 Design Conditions (For Performance Calculation in This Survey)........................................ 68

Table 3-11 Temperature and Humidity in Vicinity of Mae Moh District (1981 to 2010) ........................ 68

Table 3-12 Precipitation in Vicinity of Mae Moh District (1981 to 2010)............................................... 68

Table 3-13 Atmospheric Pressure in Vicinity of Mae Moh District (1981 to 2010) ................................ 69

Table 3-14 Design Load of Foundation of Existing Mae Moh Thermal Power Plant.............................. 70

Table 3-15 Coal Properties....................................................................................................................... 70

Table 3-16 Coal Ash Properties ............................................................................................................... 71

Table 3-17 Oxygen-Blown Gasification Processes in Operation ............................................................. 73

Table 3-18 Estimated Construction Cost of Power Generation Facilities ................................................ 93

Table 3-19 Comparison of Plant Cost and Electricity Unit Price of Power Generation Facilities ........... 93

Table 3-20 Major Equipment Specification ............................................................................................. 95

Table 3-21 Power Generation Performance of Air-blown IGCC ........................................................... 102

Table 3-22 Process Performance of Air-blown IGCC............................................................................ 102

Table 3-23 Auxiliary Power Consumption of Air-blown IGCC............................................................. 102

Table 3-24 Flue Gas Condition of Air-blown IGCC (@Stack Outlet) ................................................... 103

Table 3-25 Effluent Condition of Air-blown IGCC ............................................................................... 103

Table 3-26 Utility Consumption of Air-blown IGCC ............................................................................ 104

Table 3-27 Quality of Raw Coal at Mae Moh Coal Mine .......................................................................111

Table 3-28 Combinations of Equipments Used for Mining ....................................................................111

Table 3-29 Assignments of Mining Work .............................................................................................. 113

Table 3-30 Facilities and Coal Consumption at Mae Moh Power Plant ................................................ 114

Table 3-31 Coal Consumption Plan by EGAT ....................................................................................... 115

Table 4-1 Atmospheric Emission Standards at Mae Moh Thermal Power Plant.................................... 120

Table 4-2 Atmospheric Emission Standards for New Thermal Power Plants in Thailand ..................... 121

Table 4-3 Effluent Standards for Industrial Plants and Industrial Estates, and Power Plant

Management Values in Thailand............................................................................................ 122

Table 4-4 Noise Standards in Thailand .................................................................................................. 123

Table 4-5 Standards for Mining and Quarrying Vibrations in Thailand................................................. 124

Table 4-6 Coal Ash Discharge Amount at Mae Moh Thermal Power Plant........................................... 124

Table 4-7 Check Lists for Environmental Matters on Thermal Power Plant Projects (from the JICA

web site)................................................................................................................................. 132

Table 4-8 Check Lists for Environmental Matters on Thermal Power Plant Projects (from the JBIC

web site, excluding same questions of JICA guidline) .......................................................... 142

Table 5-1 Project cost procurement conditions ...................................................................................... 151

Table 5-2 Financing plan and opportunity costs .................................................................................... 151

Table 5-3 WACC resulting if low-interest financing is utilized such as JICA overseas financing......... 152

Table 5-4 FIRR account (oxygen-blown IGCC).................................................................................... 154

Table 5-5 Project cost procurement conditions ...................................................................................... 156

Table 5-6 Financing plan and opportunity costs .................................................................................... 157

Table 5-7 FIRR account (air-blown IGCC) ........................................................................................... 159

Table 5-8 EIRR account (IGCC at Mae Moh vs USC with imported coal) ........................................... 162

Table 5-9 EIRR account (IGCC at Mae Moh vs GTCC with imported LNG)....................................... 165

Table 5-10 EIRR Transition of LPG import price in Thailand (2008 to 2010) ...................................... 170

Table 7-1 EGAT Financial Overview..................................................................................................... 177

Table 9-1 Cash flow analysis (oxygen-blown IGCC) ............................................................................ 186

Table 9-2 Cash flow analysis (air-blown IGCC).................................................................................... 187

Executive Summary

- 2 -

(1) Background, necessity, etc. of the project

Under the authority of the Ministry of Energy of Thailand, the Thai government and Electricity

Generating Authority of Thailand (EGAT) announced Summary of Thailand Power Development Plan

2010-2030 (PDP 2010) in April 2010 based on the following issues in order to promote the best mix of

power supply composition.

1) More than 70% of the whole Thailand's power generation composition depends on natural

gas-fired power generation, which is an unstable situation. Therefore, there is an urgent need to

diversify energy including the use of coal-fired power generation from the viewpoint of energy

security.

2) Under the projection that the domestic natural gas will peak out around 2015, Thailand is

working to introduce LNG. However, the challenge is to utilize lignite which are the valuable

domestic resources produced in Mae Moh coal mine.

3) Promotion of cooperation in international efforts towards the reduction of greenhouse gas

emissions

4) It is difficult to build coal-fired power plants due to people's feeling of aversion towards them.

In the “PDP 2010,” the installed capacity for coal-fired power generation is expected to increase from

3,897 MW in 2010 to 10,827 MW in 2030. The plan aims to promote measures against climate change

and diversification of energy through power resources development on the basis of Clean Coal

Technology. In “PDP 2010,” positive consideration is given for the introduction of Clean Coal

Technology (CCT) power generation. This includes the “scrap and built” of existing decrepit Mae Moh

Subcritical Lignite-Fired Power Plant using CCT.

Under these circumstances, it is considered most appropriate to introduce Integrated coal Gasification

Combined Cycle (IGCC) power plants that enable highly-efficient power generation, save Mae Moh

lignite resources and have good environmental performances.

The Thai government and EGAT have announced a policy to delay the nuclear power generation plan

after the nuclear accident occurred in Fukushima, Japan. They are currently revising “PDP 2010” and

considering the inclusion of IGCC in the PDP as one of CCT.

(2) Basic policy concerning the determination of project contents

This survey inspects matters concerning the introduction of Integrated Coal Gasification Combined Cycle

(IGCC) based on the effective utilization of coals (lignite) in Mae Moh coal mine owned by EGAT to

consider whether the project is feasible in terms of technology and economy. The aim of this survey is to

make the project effective as measures against climate change and realize diversification of energy and

effective utilization of domestic resources.

- 3 -

(3) Outline of the project

This project plans to build an IGCC power plant (1 on 1 type) with a total installed capacity of 500 MW

level in existing Mae Moh Thermal Power Plant in Mae Moh district, Lampang Province, located 500 km

north of Bangkok and approximately 90 km southeast of Chiang Mai.

a) Total project cost

110 billion to 125 billion yen (Exchange rate: 78.13 yen/US$)

b) Outline of results of the preliminary analysis for finance and economy

In this project, two types of IGCC are considered: oxygen-blown and air-blown IGCC. As the selling

price of electricity cannot be determined, prices range between 0.05 US$/kWh and 0.12 US$/kWh.

Evaluation of FIRR was conducted by comparing the prices with an opportunity cost of capital (weight

average capital cost: WACC). As a result, if the selling price of electricity is 0.070 US$/kWh using

oxygen-blown IGCC when the project receives a low-interest loan (assumed as 2.5% here) such as JICA

overseas loan, etc. (WACC 4.5%), it would surpass WACC. If the price is 0.067 US$/kWh using

air-blown IGCC, it would surpass WACC. If the project gets a loan (6.5% interest is assumed) from a

city bank (WACC 7.7%), prices less than 0.089 US$/kWh would not exceed WACC for oxygen-blown

IGCC and prices less than 0.085 US$/kWh would not exceed WACC for air-blown IGCC.

Therefore, it is considered that this project needs to use a low-interest loan such as JICA overseas loan,

etc.

Figure S-1 FIRR calculation result

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

14.0

0.05 0.06 0.07 0.08 0.09 0.10 0.11 0.12

Electricity selling price（US$/kWh）

FIR

R（%）

Air Blown

Oxygen Blown

WACC: 7 .7%(Interest:6 .5%)

WACC: 4 .5%(Interest:2 .5%)

(Source) Prepared by study team

NPV (Net Present Value) and B/C (Benefit/Cost) when the selling price of electricity is set as 0.08

US$/kWh are as follows.

- 4 -

Oxygen-blown IGCC Air-blown IGCC NPV 277 million US$ 428 million US$ B/C 1.26 1.32

An alternative project (here this refers to ultra supercritical (USC) power plant that uses imported coals as

fuel and GTCC that use imported LNG as fuel) with the same power generation (net) as that of the

relevant project was selected for EIRR. The costs of the relevant project were set as expenditures and the

costs of the alternative project as benefits to derive the equivalent reduction rate of both costs. Then,

EGAT evaluated the economic efficiency of the project by comparing the equivalent reduction rate with

the discount rate (interest + 4 - 5%) used to review the power resources development. The following

results were derived from the comparison with oxygen-blown IGCC (with lower FIRR), which showed

that the IGCC economically surpasses the alternative project.

EIRR of the relevant project compared to USC: 10.0%

EIRR of the relevant project compared to GTCC: 19.3%

c) Reviewing the environmental and social aspects

The Mae Moh Thermal Power Plant already has desulfurization equipment that has been installed on

every unit additionally in order to improve the environmental performance. It was sequentially installed

during the 1995 to 2000 period so as to address the concern about environmental problems that grew

around the power generation station. This has significantly improved the measures for atmospheric

emission matters and the properties of discharged water up to the present. The environmental standard has

been revised as necessary so that the management conditions have been established in response to

enhancement of environmental consciousness.

Although the Mae Moh Thermal Power Plant has been improving its environmental performance, its

facilities are becoming old-fashioned. They meet the current environmental standard, but from the view of

predicted future, the facility investment utilizing the clean coal technology is required for continually

environmental improvement.

Implementation of this project will bring much effect in environment improvement. More effect in

environment improvement will be expected for the air quality, the water quality, Waste (coal ash), or the

like.

We have already obtained some proper information about EHIA upon completion of this investigation.

Because the current members of consultation with EGAT will be wholly stakeholders of this project, they

should subsequently cooperate with the EGAT Investigation Team.

(4) Implementation schedule

Overall schedule of the project is shown in the diagram below.

- 5 -

Figure S-2 Overall schedule of the project

(Source) Prepared by Study Team

Requirements that are essential to implement a project, such as the scope of future works based on the

result of the project, are taken into account in this schedule. Assumed action categories in each Mile Stone

are listed below.

a) Detailed FS: 10 to 12 months

It is necessary to implement detailed FS in the following categories to optimize plants and identify the

feasibility (marketability) of the project. Materials that are necessary for environmental assessment are

also developed in this phase.

Optimization of flow scheme

Location survey

Determination of assumed coal property and implementation of dryness and liquidity test as

needed

Request for operation to each licenser and signing nondisclosure agreements as needed

Considering whether existing facilities can be diverted

Developing materials for environmental assessment

Calculation of total fund

Economic evaluation

b) FEED (Front End Engineering Design): 12 to 15 months

The basic plan of the plant is formulated and an EPC inquiry sheet is created in this phase. Main actions in

this phase are as follows:

Determination of facility design specification

Preparation of an EPC inquiry specification sheet (preparation of a Basic Design Package)

Inquiry/deciding EPC contractors

- 6 -

c) EPC (Engineering，Procurement，Construction): 33 to 36 months

Basic/detailed design of the plant, procurement of materials, site construction and test operations are

carried out in this phase.

Some of the purchased equipments (facilities) require 24 months to manufacture. Therefore, after adding

design period, procurement period, construction period and test operation period based on the

implementation of FEED, the total length of period will be 33 to 36 months from basic design (review of

EPC contractors) to the start of plant operation.

(5) Feasibility concerning operation

As stated in (3) b) "Outline of results of the preliminary analysis for finance and economy," the project has

a feasibility if it receives a low-interest loan such as JICA overseas loans, etc.

(6) Technical advantages of Japanese companies

IGCC plants that were reported to have been operated so far in the world are the four projects that started

operation in Western countries in the 1990s. Nakoso (Iwama machi, Iwaki City, Fukushima Prefecture)

Plant in Japan is the only plant that started operation in this century. As of November 11, 2011, the plant

had recorded 2,238 hours of continuous operation. In a long-term durability operation test, the number of

operation hours reached 5,000/y which was the initial target. The know-how that has been accumulated in

Nakoso IGCC Plant, which has demonstrated high performance and reliability, is considered to become a

great source of competitive power when Japan expands sales of IGCC plants.

Japanese makers (Mitsubishi Heavy Industries and Hitachi) and engineering company (Chiyoda

Corporation), which boast high reliability and technical capabilities in the world, have been developing

concrete IGCC project cases and therefore have advantages in terms of technology. The future issue is the

development of competitive IGCC plants that can be operated on a commercial basis.

Mae Moh coals are characterized by having a high CaO content in ash in the level that is difficult to

process in a fine powder-fired boiler. However, it was confirmed that IGCC is suitable for coals with a

low ash melting point and Mae Moh coals that have a high content of CaO in ash can be used for IGCC.

(7) Concrete schedule for the project completion and risks that may prevent the completion

a) Utilization of the Public-Private Partnership (PPP) scheme

A great amount of fund is necessary in order to start the operation of IGCC plant, from the stage of

detailed project feasibility investigation to detailed design and construction. The initial costs for this

project are very high compared to those of other power generation projects. Therefore, it has fallen into

the vicious cycle: feasibility of the project decreases significantly due to the payment of interest, etc. and it

is unable to make a final decision to invest in the project → unable to accumulate know-how on a

commercial basis → no progress in the development of competitive IGCC plants.

- 7 -

In order to improve the economic efficiency of the project and for the operating bodies of IGCC projects

to make a final decision to invest in a project, financial support to alleviate a heavy burden of initial

investment costs of the operating bodies is necessary under the Public-Private Partnership (PPP) scheme,

from the stage of detailed project feasibility investigation to detailed design and construction.

On the other hand, operating bodies need to request contractors of IGCC plant construction (Japanese

makers, engineering companies, etc.) to present competitive construction costs, while IGCC plant makers

should try to reduce costs continuously.

b) Utilization of the low-interest loan system

As stated in (3) b) "Outline of results of the preliminary analysis for finance and economy," it is difficult to

carry out the project with the interest of a city bank and the project needs to prepare to receive a

low-interest loan such as JICA overseas loans, etc.

c) Necessity of shortening the period of approval process

In Thailand, approval of EGAT and the government is required for the establishment of a power plant, and

it is necessary to estimate the time for the procedure.

d) Necessity of shortening the period of environmental impact assessment

Before the implementation of the project, a party who applies for the implementation of the project should

carry out investigation and analysis on matters concerning the establishment of a thermal power plant in

the pollution prevention section prescribed in NEQA19921, summarize the results as EHIA and gain

approval of a supervisory authority. Although a normal monitoring period is one year, according to the

hearing in EGAT, it is assumed that it takes two years for a whole set of procedures including monitoring,

analysis, review, discussions with stakeholders and approval of relevant ministries and agencies. EGAT

has already started the development of EHIA and procedure to replace the power plants No.4 to 7, which

may shorten the time.

1 The Pollution Control Department of the Ministry of Natural Resources and Environmental holds jurisdiction over the legal basis of the current procedures, and the name of the act is “Enhancement and Conservation of National Environmental Quality Act B.E. 2535 (abbreviated as NEQA1992)” (Chapter 4, (4) Overview of Related Laws and Regulations for Environmental and Social Considerations in Host Country).

- 8 -

(8) Map showing the project site in the country surveyed

Figure S-3 Project Site Map

Project Site

Bangkok

Chiang Mai

N

(Source) Prepared by Study Team based on Website of the Global Internet Partner Utopia Co., Ltd.

Chapter 1 Overview of the country and sector to be invested

- 10 -

(1) The economic and fiscal conditions of the country to be invested

This Section summarizes the political, economic and social conditions in Thailand, a country to be

invested, and the recent fiscal condition of the Thai government.

a) Political conditions

1) Political system of Thailand

Thailand had been a kingdom under absolute monarchy, a form of government in which several dynasties

govern the country, since the establishment of the Sukhothai dynasty in the 13th century. In the 20th

century, however, the monarchy aroused strong opposition. Khana Ratsadon formed around commoners

by birth achieved the Constitutional Revolution in June 1932, transforming the political system of

Thailand to constitutional monarchy. Since then and up to the present, the framework of a constitutional

monarchy has been maintained. Although the Kingdom of Thailand is a commander of the Royal Thai

Army and is supposed to make a transcendental political decision in times of emergency, it has limited

influence over usual management of politics. The current dynasty is the Chakri Dynasty, taking hold of

the sovereignty in 1782, and the current King of Thailand is Bhumibol Adulyadej, who enthroned in June

1946. The King, who has reigned for over 55 years, places great importance on a harmonious relationship

with people, as evidenced by his active involvement in rural developments in Thailand, and is considered

to enjoy great prestige among Thai people.

It is the Cabinet of Thailand that has a central administrative function, especially the prime minister, the

chairman of the cabinet, has strong influence. The prime minister is appointed from members of the lower

house, deliberated and approved in the lower house, and finally approved by the king. Its term is limited to

eight consecutive years. The current prime minister is Yingluck Shinawatra, taking office in August 2011.

Yingluck is a sister of the 31th Prime Minister Thaksin Shinawatra and Thailand's first female prime

minister. She is the second prime minister who is a member of Thaksin's family, following Somchai

Wongsawat, who served as prime minister from September 2008 to December 2008.

Abhisit Vejjajiva, who is a predecessor of Yingluck, became the leader of the Democrat Party in 2005 and

served as prime minister for two years and nine months from December 2008 to August 2011.

Thailand adopts the bicameral system with the Senate, the upper house, and the House of Representatives,

the lower house. In the politics of Thailand, the lower house (the House of Representatives) has

overwhelming importance because the upper house (the Senate) has as few as 150 members and has no

right to propose legislation, half of the members are not directly elected by the nation but selected by a

Senate Selection Committee, and the prime minister must be elected from members of the lower house. In

the general election in July 2011, the ruling party, Pheu Thai won a majority with 266 of the 500 seats and

the main opposition party, Democrats 159, Bhumjai 34, Chartthaipattana 19, Chart Pattana Puea Pandin 7,

Palung Chon 7, and others 9.

- 11 -

Table 1-1 Key Cabinet Ministers of Thailand (As of August 2011)

Title Name Career

Prime Minister Yingluck Shinawatra Former president of SC Asset Corporation and Advance Info Service (AIS)

Deputy Prime Minister

Yongyuth Wichaidit Chairman of the Pheu Thai Party


Chalerm Yoobamrung Police Captain, Former Minister of Interior, Former Minister of Justice


Kowit Watana Police General, Former Deputy Prime Minister and Minister of Interior, Former Police Commissioner General


Kittirat na Ranong President of Shinawatra University, Former managing director of the Stock Exchange of Thailand (SET)


Chumpol Silpa-archa Minister of Tourism and Sports, Former President of the Senate

Minister of Finance Thirachai Phuvanatnaranubala

Secretary-General of the Securities and Exchange Commission of Thailand

Minister of Defense Yuthasak Sasiprapha Deputy Commander-in-Chief of the Royal Thai Army

Minister of Foreign Affairs

Surapong Towichukchaikul

Deputy Chairman of the Pheu Thai Party

Minister of Commerce

Kittirat na Ranong President of Shinawatra University, Former managing director of the Stock Exchange of Thailand (SET)

Minister of Justice Preecha Rengsomboonsuk

Former Minister of Industry, Former Police Commissioner General

Minister of Industry Wannarat Charnnukul Former Minister of Energy, Former Advisor of Deputy Prime Minister, Former Advisor of Minister of Labor

Minister of Energy Pichai Naripthaphan Former Deputy Minister of Finance, Former owner of a jewelry company

(Source) The website of Japan External Trade Organization (JETRO)

2) Recent political conditions in Thailand

In the mid-2000s, political conditions in Thailand began to destabilize, which was caused by a conflict

between approval and disapproval of the policies of Thaksin who became prime minister in 2001. The

conflict over policies between pro-Thaksin group and anti-Thaksin group is deep-routed, and has yet to be

completely resolved. Since the demonstration in March 2010, the national reform committee, fact-finding

committee and other committees are established and efforts are underway to achieve national

reconciliation between both groups. It is also expected the fact that Pheu Thai won a majority of seats in

the general election in July 2011 will contribute to the stabilization of national politics in the future.

3) Political conditions after the floods

The flood problem due to a swell in the Chao Phraya River, which has become serious since around

September 2011, has caused popular dissatisfaction with the Yingluck administration, which failed to

implement effective solutions to the problem. Immediately after its inauguration, the Yingluck

administration is faced with a major political issue. Under these circumstances, the Yingluck

- 12 -

administration conferred with the former Prime Minister Abhisit Vejjajiva, the leader of the opposition

party, Democrats, who competed with Yingluck for political power in the general election in July, and

started to implement assistance measures. In October 2011, Thailand Board of Investment (BOI)

announced that it would permit the immediate transfer of the machinery and raw materials in factories and

other places without prior BOI approval. In the same month, the government announced that it decided to

establish three special committees to facilitate restoration and showed its willingness to accelerate efforts

toward an early settlement of this problem.

In the meantime, while the flood problem is moving toward resolution with its peak in November 2011, it

has been discussed who should be held responsible for the escalation of the problem. Especially Theera

Wongsamut, Minister of Agriculture and Cooperatives, is increasingly accused of since the Royal

Irrigation Department is thought to be largely responsible for this problem. In addition to this problem,

opposition parties strongly opposed that the current administration has paved the way for Thaksin's return,

because in December 2011, the Ministry of Foreign Affairs issued Thailand's passport to the former prime

minister, living in Dubai in the United Arab Emirates (UAE). There is a possibility that Thailand will

continue to be in political turmoil.

b) Economic conditions

1) General economic conditions in Thailand

Thailand has generally maintained high economic growth rate over the past 30 years, despite the

economic crisis in the late 1990s (Figure 1-1). Thailand, whose industrial structure originally relied on

agriculture, started to achieve high growth rate due to growing industrialization in the 1980s2. One reason

behind this was that many Japanese companies found their way into Thailand since they are forced to

move production overseas due to the appreciation of the yen against the dollar after the Plaza Accord. Thai

government took a policy to strongly attract such investments and increase imports to achieve high

economic growth rate. Owing to this policy taken by Thai government, Thailand could achieve economic

growth rate of above 5%/y from the 1980s to the mid-1990s.

In the 1990s, Thai economy continued to grow steadily partly due to increasing foreign investment associated with financial deregulation in Thailand, but it gradually began to show signs of a bubble because of excessive capital investment and booming real estate prices. Under these circumstances, there has been a movement to instead withdraw investment from Thailand since around 1995, and the downward pressure has increased on Thai baht, which was under a fixed exchange rate system at the time. In response, in July 1997, Thai government switched to a managed floating exchange rate system. As a result, the exchange rate of the baht against the US dollar in 1996 was about 25 baht to the dollar and plunged to 50 baht in the beginning of 1998. Because of this plunge of the baht, most financial institutions in Thailand were placed in a predicament, which accepted deposits denominated in foreign currencies and provided long term loans to domestic companies, and liquidity shortage occurred in the financial market in Thailand. Consequently, Thai economy had to suffer a negative growth in 1997 and 1998.

2 Note that agriculture is still the biggest industry, employing 40% of the labor force. (From the website of the Ministry of the Foreign Affairs)

- 13 -

Figure 1-1 Changes in real GDP growth rate of Thailand

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

2014

(Note) Values for 2009 and 2010 are estimates. Values for 2011 and after are projections by the International Monetary Fund (IMF).

(Source) International Monetary Fund (IMF), “World Economic Outlook Database” After that, Thai government received emergency assistance from the international community, including the IMF, and pursued economic reconstruction such as the disposal of nonperforming loans. Owing to this, Thai economy began to recover again in 2000. The Thaksin administration, which took office in 2001, shifted from its traditional economic management with the emphasis on exports to one aiming to expand domestic consumption along with exports, and provided support to rural areas and small and medium-sized enterprises. Thanks to expansion of domestic demand along with exports, Thai economy has again achieved economic growth rate as high as 5% until 2007.

When the Lehman Shock occurred in 2008, the global economic downturn hit hard Thailand's exports, which had been supporting the country's economy, leading to a fall in the income level. Thailand's economic growth slowed to 2.5% in 2008 and -2.3% in 2009. In response, Thai government implemented stimulus measures through increasing public spending, including reduction of the policy interest rate by the Bank of Thailand and reduction of the price of electricity to the poor. As external demand recovers, Thai economy is turning up again. Thai government projects the growth rate at 7.9% in 2010 and 3.5-4.5% in 20113, and the IMF projects the growth rate at 7.8% in 2010 and 4.0% in 2011.

Foreign investment in Thailand has increased steadily. Foreign direct investment in Thailand in 2009

decreased by 224 (26.7%) to 614 in terms of number of projects and by 59.5% to 142,077.4 million baht

in terms of monetary value from the previous year (on approval basis, projects with foreign capital of at

least 10%) partly due to the Lehman Shock. However, projects submitted (the number of projects

submitted is a leading indicator of investments) in 2009 increased by 17.9% to 350,755.4 million baht in

terms of monetary value from the previous year, despite a slight decrease to 788 in terms of number of

projects4. Thailand is thought to remain attractive as an investment destination because of the advantage of

the concentration of a wide range of industries and its potentiality as a market of finished products, though

there is an investment risk associated with uncertain political conditions and anti-government

demonstrations. 3 The website of the Ministry of the Foreign Affairs (http://www.mofa.go.jp/mofaj/area/thailand/data.html&sa=U&ei=LnxITvf9Oo_JrQetyKHUAw&ved=0CBMQqwMoADAA&usg=AFQjCNFUIKmR-Wzy6NLl6pURUjACPc7csQ) Access date: August 15, 2011 4 "JETRO Global Trade and Investment Report: Thailand" from the website of JETRO (http://www.jetro.go.jp/world/gtir/2010/pdf/2010-th.pdf) Access date: August 15, 2011

- 14 -

2) Outlook of Thai economy after the floods

The IMF initially projected that Thai economy would maintain high growth rate of around 5% until 2015.

This is because the IMF expected the country would achieve steady economic growth with domestic

production recovering to the level before the Lehman Shock, backed by brisk exports.

However, as a consequence of the flood problem in the fall of 2011, the projection of Thai economy was

revised drastically downward. This is because, due to the floods, domestic production and exports have

declined overall, consumption has slowed down by the confusion in people's life, and tourism, one of the

main industries of Thailand, has been suffering. Under the present circumstances, Thai government

revised its estimates for the GDP growth rate for 2011 significantly downward from 3.5-4.0%, which was

estimated before the floods.

Though the floods could hinder economic recovery for the time being, as for the second half of 2012,

there is a possibility that Thai economy can recover steady economic growth rate of above 3%, if

restoration plans of the government and the consumption stimulus measures as promised in the election

campaign of the Yingluck administration work well.

c) Social conditions

In Thailand, there has been a tendency of social conditions to destabilize along with the political turmoil

described above since around 2008. The unstable condition has been continued. For example, in

November 2008, the pro-Thaksin People's Alliance for Democracy (PAD) objected to Somchai, who took

office as the prime minister, and forced the Bangkok International Airport to shut down. Also, in April

2009, pro-Thaksin group raised a riot in Bangkok and Pattaya, tourist site, and in April 2010, pro-Thaksin

group took over the urban area in Bangkok where commerce facilities are concentrated5.

Behind the destabilization of social conditions is the fact that the income gap between people is expanding

amid continued economic growth. The driving force behind Thailand's economic growth is an increase of

exports. Because of this, except for Bangkok, job opportunities with relatively high wages mostly exist in

the coastal region in the eastern Thailand, where production bases of manufacturers such as car

manufacturers are concentrated. On the other hand, in most other regions, there is still a traditional

industrial structure such as agriculture. There is a wide gap in economic growth rate between the eastern

region and other regions (Figure 1-2), and as a result, the regional income gap tends to expand. Residents

in the eastern region enjoy affluent lives with increasing income, whereas residents in other regions are

left behind in the improvement of living standards. The expansion of regional economic gap is one of

major factors that heighten political tensions in the country.

Yingluck, who took office as the prime minister in August 2011, indicates a willingness to address to solve

the problem of the income gap. In an interview with the Wall Street Journal in July before taking office,

Yingluck presented policy proposals to improve the living standards of the poor such as an increase of the

minimum wage to 300 baht (about 800 yen) /d uniformly and a tax reduction on the price of gasoline and

light oil, and unveiled her idea of maintaining Thailand's economic growth by stimulating domestic

consumption through these measures after taking office as the prime minister. It is expected that, through

5 “JETRO Global Trade and Investment Report: Thailand” from the website of JETRO (http://www.jetro.go.jp/world/gtir/2010/pdf/2010-th.pdf) Access date: August 15, 2011

- 15 -

these measures, tensions between people from different regions and walks of life will be eased, and

actually, a fierce anti-government movement, as happened before, has not arisen at the time of writing (as

of February 2012).

Figure 1-2 GDP per capita by region in Thailand (2007-08 average)

(Source) IMF (Original source: CEIC Data Co. Ltd.)

Other factors of social unrest include that Muslims in Southern Thailand have deepened the confrontation

with the central government in pursuit of separation from Thailand from the 1970s to the 1980s, and the

Islamic movement escalated into an insurgency in 2004, but there were no remarkable developments at

the time of writing (as of February 2012). As for the flood problem due to a swell in the Chao Phraya

River, although a possible outbreak of infectious diseases due to the deterioration of sanitary conditions is

worried about, the destabilization of social conditions is not seen.

d) National fiscal conditions

As for the fiscal balance of Thailand, expenditures have exceeded revenues since the 2000s except a

certain period of time. Although the budget deficit greatly expanded in the fiscal year (FY) 2008 (from

October 2007 to September 2008) and 2009, when the impact of the Lehman Shock was significant, the

government nearly restored fiscal equilibrium in FY 20106. However, in FY 2011, from January to July

2011, the budget deficit reached 11% of the total expenditures, and there are signs of deteriorating fiscal

balance again (Figure 1-3).

6 In Thailand, it is stipulated by the law that government borrowing is reduced to not more than 20% of the total expenditures.

- 16 -

Figure 1-3 Changes in the balance between revenues and expenditures in Thailand

6%

-2%

-7%

-2%

-22%-22%

-2%

-11%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

-500

-400

-300

-200

-100

0

100

200

2003

/200

4

2004

/200

5

2005

/200

6

2006

/200

7

2007

/200

8

2008

/200

9

2009

/201

0

2010

/201

1

Unit: Billion baht

Revenues - Expenditures

Budget def icit to expenditures ratio

(Note) FY 2010/2011 is data from January 2010 to July 2011. (Source) Information posted on the website of the Bank of Thailand (Key Economic Indicators)

The Pheu Thai administration of Yingluck, who took office in August 2011, is to implement economic

policies heavily relying on increasing public spending, and the policies bring concerns of deteriorating

fiscal balance again. In the election campaign, Yingluck made many campaign promises which involve

public spending such as an increase of the minimum wage, reduction of the corporate tax rate, a rice price

guarantee, and the restoration of the 30-Baht Health Care Scheme. Also, in her policy speech made on

August 23, 2011, after taking office as the prime minister, from the perspective that the existing economic

structure heavily relying on exports has a high risk, she indicated a willingness to put domestic-demand

expansion policies at the center of economic policies, and above all, she is expected to aggressively make

government spending. Actually, measures to increase real national income through a reduction of

domestic prices of petroleum products have already been implemented. Information has been reported

that, since the government exempted petroleum products distributors from contributions to the "State Oil

Fund", which had been required thus far, domestic prices of petroleum products have declined by 10-20%

as of the end of August7. Other than the reduction of fuel prices, the administration is to gradually

implement the measures as promised in the election campaign. In September, as a result of requiring

consumables manufacturers to revise retail prices, the administration succeeded in reduction of prices for

five items such as cement and wheat. Also in September, a tax reduction policy was implemented for

first-time car buyers and home buyers, the excise tax on small-size passenger cars with piston

displacement of 1,000cc or less is to be refunded up to a ceiling of 100,000 baht (about 270,000 yen)8.

7 Nikkei Newspaper (September 24, 2011) Note that the decline of domestic prices is thought to have been significantly contributed by the decline of international crude oil prices in early August. 8 Nikkei Newspaper (September 24, 2011)

- 17 -

Table 1-2 Major economic policies of the new administration of Thailand

Description of the policies Implementation status

Reduction of the price of gasoline and light oil Implemented on August 27

Tax reduction for first-time car buyers Implemented on September 16

Tax reduction for first-time home buyers Implemented on September 22

Purchase of rice at higher prices by the government To be implemented on October 7

Reduction of the corporate tax rate (from 30% to 23%) To be implemented on January 1, 2012

Increase of the statutory minimum wage to 300 baht/d uniformly throughout the nation from the current range of between 159 and 221 baht according to provinces

To be implemented on January 1, 2012 (an increase of about 40 percent)

(Source) Nikkei Newspaper (September 24, 2011)

These measures, although temporary for a year, will place a large burden on Thailand's public finances.

However, the Yingluck administration showed prospects that, by introducing these measures, the

economic growth will be achieved owing to improved corporate performance and increased consumption,

leading to an increase in tax revenues. In the first government budget for the administration, approved in a

cabinet meeting in September 2011, revenues are expected to be 1.9 trillion baht, up 4,2% from the budget

of the previous year, based on economic expansion. Public spending is assumed to increase further partly

because large-scaled infrastructure improvement projects including railway construction are planned in or

after 2012. Moreover, in December 2011, the government decided in an extraordinary cabinet meeting to

spend additional 20 billion baht as an emergency budget for recovery from the floods and support for

disaster victims, and the additional budget will make the fiscal conditions of Thailand even severer. There

is great interest in the Yingluck administration's ability to manage economic policies, or whether the

administration can boost the domestic economy through ongoing domestic-demand expansion measures

and improve fiscal balance.

(2) Overview of the target sector of the project

This Section summarizes the current situation and outlook of energy and electric power in Thailand..

a) Energy supply and demand

The primary energy supply was 83 Mtoe (million ton oil equivalent) in Thailand in 2009, and has

increased by an average of 4%/y in the decade from 1999 to 2009. By energy source, oil comes first with

49 percent, followed by natural gas with 32 percent and coal with 18 percent. Nowadays, the growth rate

of coal and natural gas is high, and the share of oil tends to shrink (Figure 1-4).

- 18 -

Figure 1-4 Changes in primary energy supply

0

10

20

30

40

50

60

70

80

90

100

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Coal Oil Natural gas Hydropower and others

Mtoe

(Source) IEA, Energy Balances of non-OECD Countries

Coal demand is divided between power generation use and industrial use. Against a backdrop of strong

electric power demand and the growth of cement production, the demand for both power generation use

and industrial use has sharply increased with the growth rate in the past decade are 6 percent and 8%/y,

respectively. The coal demand for power generation use has increased because imported coal-fired power

plants started operation in 2006 and 2007.

The domestic production of energy was 42 Mtoe in 2009. Of the domestic production, natural gas comes

first with 46 percent, oil with 39 percent, and coal with 13%. Of the imports, oil comes first with 70

percent, coal with 17%, and natural gas with 12%. The overall energy self-sufficiency rate was 50 percent

as of 2009 (Figure 1-5).

Figure 1-5 Domestic production and exports and imports (2009)

OilNatural

gasCoal

OthersTotal

Import

Export

Domestic production

16.2

5.2

19.2

0.6

41.2

13.6

0.00.1

13.8

42.8

10.67.5

0.2

61.1

0

10

20

30

40

50

60

70

(Mtoe)


- 19 -

The final energy consumption was 76 Mtoe in 2009, and has increased by an average 4 %/y in the decade

from 1999 to 2009. By sector, in 2009, the industrial sector comes first with 32 percent, followed by the

transportation sector with 25 percent, the consumer sector with 20 percent (Figure 1-6).

Figure 1-6 Changes in final energy consumption

0

10

20

30

40

50

60

70

80

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Industrial sector Transportation sector Consumer sector Others

Mtoe


According to the outlook of the Institute of Energy Economics, Japan (IEEJ), Thailand's primary energy

supply is expected to increase by an average 3.0 %/y from 2009 to 2035, reaching 182 Mtoe in 2035.

Against a backdrop of the growth of demand for power generation use and industrial use, coal is expected

to increase the most, and increase by an average 4.1 %/y from 2009 to 2035, reaching 43 Mtoe in 2035.

As a result, the share of coal in primary energy supply is thought to increase from 18 percent in 2008 to 23

percent in 2035 (Figure 1-7).

Figure 1-7 Outlook of primary energy supply

0

50

100

150

200

250

2008 2020 2030 2035


Mtoe

(Source) The Institute of Energy Economics, Japan (IEEJ), Asia/World Energy Outlook 2011

- 20 -

b) Electric power supply and demand

Electric power demand was 148 terawatt hour (TWh) in 2009. It has increased by 5 %/y in the decade

from 1999 to 2009. As for power generation by fuel type, the growth rate of coal and natural gas in the

same period are as high as 6 percent and 5 %/y, respectively. As described above, the coal-fired power

generation has increased because imported coal-fired power plants started operation in 2006 and 2007.

For the share by fuel type as of 2009, natural gas comes first with 71 percent, followed by coal with 20

percent (Figure 1-8).

Figure 1-8 Changes in generated electricity by fuel type

0

20

40

60

80

100

120

140

160

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009


TWh


For the electric power demand by use, the growth rate of commercial use, and industrial and residential

use in the decade from 1999 to 2009 are 6%/y, 5%/y and 5%/y, respectively. In 2009, industrial use

accounts for 42 percent, commercial use 35 percent, and residential use 22 percent (Figure 1-9).

Figure 1-9 Changes in electric power demand by use

0

20

40

60

80

100

120

140

160

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Industrial use Commercial use Residential use Others

TWh


- 21 -

According to Summary of Thailand Power Development Plan 2010-2030 (PDP 2010), as of December

2009, the total contract capacity was 29,212 megawatt (MW) comprising 14,328.1 MW (49 percent) of

Electricity Generating Authority of Thailand (EGAT)'s power plants, 14,243.9 MW (49 percent) of IPPs

and SPPs9 and 640 MW (2 percent) of power purchase from Laos or Malaysia.

According to the power demand forecast in “PDP 2010,” an average growth rate of the forecasted energy

demand during 2010 - 2030 is 4%/y, and the forecasted peak demand in 2030 is 52,890 MW, 2.4 times

higher than that in 2009. Power demand is expected to increase by 4%/y from 146 TWh in 2009, reaching

348 TWh in 2030, 2.4 times higher than that in 2009 (Figure 1-10).

Figure 1-10 Power demand and peak demand forecast (as of February 2010)

0

50

100

150

200

250

300

350

400

2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

Pow

er

dem

and （

TW

h）

0

10

20

30

40

50

60

70

80

Peak d

em

and （

GW

）

Peak dmand

Power demand (left axis)

(Source) Summary of Thailand Power Development Plan 2010-2030

Based on the power demand forecast above, in “PDP 2010,” it is expected that 54,005 MW of capacity is

newly added from EGAT, IPPs, SPPs and VSPPs10, 17,671 MW of capacity is reduced due to retirement

of power plants and expiration of Power Purchase Agreement (PPA) term, and accordingly the generation

capacity in 2030 increases to 66 gigawatt (GW) from 29 GW in 2009. By fuel type, the growth rate of

natural gas and electricity (hydropower) imported from Laos, etc. are as high as 11 GW and 10 GW,

respectively. The capacity of coal-fired power generation is expected to increase by 7 GW. The capacity of

oil fired-power generation (mono-fuel combustion or multi-fuel combustion) will decrease11. Nuclear

power plants were scheduled to start operation in 2020 (Figure 1-11).

However, the possibility of the plan above is not necessarily high. As for the nuclear power generation, in

response to the Accident at Fukushima Daiichi Nuclear Power Station after Great East Japan Earthquake,

the National Energy Policy Council (NEPC) decided in April 2011 to delay the construction of nuclear

power plants scheduled in 2020 by 3 years. Additionally, the share of natural gas in generated electricity

9 Small Power Producers. They are intended to encourage power generation harnessing renewable or non-conventional resources such as hydropower, biomass and cogeneration. They sell electricity to EGAT or consumers near power plants. 10 Very Small Power Producers. They are defined as power producers with generating capacity of less than 10 MW. Like SPPs, they sell electricity to EGAT or consumers near power plants. 11 In 1999, the government decided in a cabinet meeting to replace other fuels with natural gas in the power sector. After that, the construction of oil fired power plants is basically prohibited.

- 22 -

was as high as 71 percent as of 2009, dependence on imports of natural gas is expected to increase. Since

"Thailand's Energy Policy" announced by Thailand's Ex-Prime Minister Abhisit Vejjajiva in December

2008 includes the policy that the share of natural gas should not exceed 70 percent, there are questions

about the increased dependence on natural gas from the standpoint of energy security.

Under these circumstances, EGAT is amending “PDP 2010,” which is scheduled to be issued in the spring

of 2012.

Figure 1-11 Power Development Plan (2010-2030)

0

10

20

30

40

50

60

70

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

GW

Others

Imports

Nuclear power

Renewable energy

Natural gas (including cogeneration)

Coal (including lignite)

Oil and gas combustion

Oil

Hydropower

IPPs (included in the total)

(Note) "Others" are power-generating facilities such as VSPPs. (Source) Summary of Thailand Power Development Plan 2010-2030

(3) Situation of the Target Region

Considered as a candidate site for this project is the EGAT-owned Mae Moh Coal Mine and Mae Moh

Power Plant located in Mae Moh County situated at a border with Phrae Province to the east of Lampang

Province situated in the north of Thailand. Mae Moh County is situated about 500 km north of Bangkok

and about 90 km south east of Chiang Mai.

- 23 -

Figure 1-12 Site Location

Mae Moh

Lampang

Candidate SiteMae Moh Coal Mine

& Mae Moh Power Plant

(Source) Prepared by Study Team based on Wikipedia

In addition to the Mae Moh Coal Mine and Mae Moh Power Plant located in Mae Moh County, pottery

production has been thriving as part of Lampang Province’s local industry owing to abundant

production of white pot clay. The products such as dishes, ornaments, tiles, construction materials, etc. are

produced and used both domestically and overseas. There is also the largest cement factory in the north

of Thailand. Agriculturally, Lampang Province is rich in pineapple production in addition to rice

cultivation12.

An investigation conducted in 1921 to 1923 found existence of lignite in the Mae Moh district. With

another investigation in 1950, lignite production by open-pit mining was started from 1955. Back in those

days, the produced lignite was used at various factories such as a tobacco factory. Then, the lignite-based

Mae Moh Power Plant with an installed capacity of 12.5 MW was constructed and inaugurated on Nov.

28, 1960.

Full-scale development of Mae Moh lignite deposits was started by the EGAT founded in 1969. The

EGAT conducted an exploration in order to use the lignite for power generation and confirmed at least 70

million t of minable lignite reserves at that point. After than, the EGAT permitted the Mae Moh Power

Plant to construct two plants (installed capacity of 75 MW x 2) and proceeded with expansion of the Mae

Moh Coal Mine. The Unit 1 started operation in 1978 and the Unit 2 in 1979, respectively.

The EGAT continued to explore the Mae Moh coalfield, and launched expansion of the Mae Moh Coal

Mine and Mae Moh Power Plant after grasping the final coal reserves. The maximum installed capacity of

the Mae Moh Lignite Power Plant was increased to 2,625 MW (Units 1 to 13). Currently, the Units 4 to

13 are operating (total installed capacity: 2,400 MW), and the generated electricity in 2010 was 18.0 TWh

(31% of the EGAT’s total generated electric energy) (see Figure 3-1). The Mae Moh Power Plant is linked

to Bangkok with 500 kV transmission lines and to Chiang Mai, the second largest city in Thailand, with

230 kV ones through the Mae Moh Substation, supplying electric power to the entire northern region,

middle region and north eastern region of Thailand plus Bangkok. Thus, the Mae Moh Power Plant plays

12 Wikipedia, Secondhand information

- 24 -

a significant role in electric power supply in Thailand.

Since the Mae Moh lignite has high sulphur content, the Mae Moh Power plant had a serious

environmental issue of air pollution in the early 1990s. As a remedy for the issue, the flue-gas

desulfurization equipments were installed for the Units 4 to 13 and the Units 1 to 3 were retired.

Table 1-3 Power Generation Facilities of Mae Moh Power Plant

Rated Capacity Current Output Power Plant FGD

1 75 retired 1978 -

2 75 retired 1979 -

3 75 retired 1981 -

4 150 150 1984 2000

5 150 150 1984 2000

6 150 150 1985 1999

7 150 150 1985 1999

8 300 300 1989 1997

9 300 300 1990 1997

10 300 300 1991 1998

11 300 300 1992 1998

12 300 300 1995 1995

13 300 300 1995 1995

Total 2,625 2,400

UnitCommencement date of OperationCapacity (MW)

(Source) Prepared by Study Team based on the EGAT-supplied material

Chapter 2 Study Methodology

- 26 -

(1) Study Details

a) Background and Objectives

Thailand's current power source structure heavily relies on natural gas (natural gas produced in the

country and natural gas imported via pipeline from Myanmar, and accounts for as high as above 70

percent. However, since domestically-produced natural gas is limited against increasing power demand,

LNG is being introduced13. Under these circumstances, Thai government is pursuing the best mix of

power sources. Electricity Generating Authority of Thailand (EGAT) under the Ministry of Energy issued

“Summary of Thailand Power Development Plan 2010-2030 (PDP 2010)” in April 2010, which is

currently under review.

According to “PDP 2010,” the installed capacity of coal-fired power plants is scheduled to be increased

from 3,897 MW in 2010 to 10,827 MW in 2030, the government is to promote the diversification of

energy sources by proceeding with power development based on Clean Coal Technology (CCT) and

taking climate change measures.

Thailand has Mae Moh Lignite-fired Power Plant (owned by EGAT), Map Ta Phut Imported Coal-fired

Power Plant (Independent Power Producers (IPP)), and GHECO-ONE Imported Coal-fired Power Plant

(IPP) under construction (all of them are subcritical pressure, coal-fired power facilities).

The Mae Moh Lignite-fired Power Plant started operation in 1978, and the current total installed

generating capacity is 2,400 MW. The power plant is located next to Mae Moh Coal Mine, which is

owned by EGAT and produces lignite. According to “PDP 2010,” EGAT plans to gradually shut down

power plants currently in operation in 2020s. On the other hand, EGAT plans to introduce nine units (800

MW each) of supercritical pressure (SC) or ultra-supercritical pressure (USC) coal-fired power facilities at

present although their places are not specified.

Thai government and EGAT are giving positive consideration to the introduction of CCT power

generation as described in “PDP 2010,” taking into consideration the following problems and issues.

1) Since Thailand is in a precarious position where it relies on natural gas for above 70 percent of its power sources, there is an urgent need to diversify energy sources including coal-fired power generation from the standpoint of energy security. 2) It is necessary to make an effective use of lignite, precious domestic resources, produced in the Mae Moh Coal Mine, in addition to the introduction of LNG based on an assumption that the domestic production of natural gas will peak out around 2015. 3) The promotion of cooperation to international efforts for greenhouse gas reduction. 4) The situation where the construction of coal-fired power plants is difficult because of public aversion to “coal-fired power plants”.

It is also considered that the existing and aging Mae Moh subcritical pressure, lignite-fired power plant

13 The first LNG receiving terminal started operation in 2011.

- 27 -

will be scrapped and built incorporating CCT.

Under these circumstances, in this study, we studied the coal gasification power generation project in light

of the introduction of Integrated Coal Gasification Combined Cycle (IGCC) technology and an effective

use of coal (lignite) produced in the Mae Moh Coal Mine owned by EGAT, and considered whether the

project was technologically and economically feasible or not. By implementing the project, we aim to

achieve its effectiveness as climate change measures and the diversification of energy sources.

b) Study Details

In this study, in order to investigate the above, we investigate the following matters.

1) General information about the Kingdom of Thailand 2) Technical feasibility study 3) Environmental and social considerations 4) Economic feasibility study 5) Outlook for realizing the project

In particular, since the IGCC will be introduced, which requires higher initial investment than the existing

technologies, it becomes important to consider the following matters and we took them into consideration.

In the technical feasibility study, we conduct conceptual design of coal gasification power plants. In order

to consider the advantages of introducing IGCC, we compare it with ultra supercritical pressure coal-fired

power plants and LNG-fired power plants, which are already commercialized. The Mae Moh Coal Mine,

which is located next to the Mae Moh Power Plant, is estimated to have 825 million t of lignite reserves.

We investigate its recoverable reserves, quality and mining plans to develop a stable fuel supply plan for

the future.

As part of environmental and social considerations, we study environmental and social impacts of the

introduction of IGCC on surrounding areas. It is assumed that IGCC has a better environmental

performance than supercritical pressure coal-fired power facilities, and has less environmental and social

impacts than supercritical pressure coal-fired power generation under consideration by EGAT.

In the economic feasibility study, we conduct economic and financial analyses of the project based on the

calculated project cost. In order to enhance the profitability, we also consider the benefit of credit granted

when a bilateral offset agreement is concluded.

As for the outlook for realizing the project, in addition to the results of the study above, we consider the

implementation capacity of EGAT, Thailand's implementing organization, and the advantages of Japanese

companies and financing of the project, and summarize action plans and issues toward the implementation

of the project. In considering financing of the project, the project formation through PPP and Japan

International Cooperation Agency (JICA)'s overseas investment is required, since the project involves the

introduction of IGCC and it is difficult to ensure profitability.

- 28 -

(2) Study Methodology and Framework

a) Study Methodology

We conducted a study including specification and conceptual design of IGCC plant facilities, and

economic analysis, by making the most of the knowledge which the study team has already accumulated

and receiving from the counterpart, EGAT, necessary information and data in conducting this study. In this

study, we conducted three field studies. In the first field study, we explained the project to the

organizations concerned, requested them to provide necessary information and data, and collected the

latest information and data. In the second field study, we made an interim report and collected additional

information and data. In the third field study, we reported the results of study to the counterpart and the

organizations concerned.

As for the contact with the counterpart, we had close contact with it by contacting it via Thai-MC

Company Limited, a subsidiary of Mitsubishi Corporation (a joint proposing corporation), in addition to

communication by e-mail.

b) Study Framework

The study framework, members of the study team and the counterpart are described in Figure 2-1, Table

2-1 and Table 2-2.

Figure 2-1 Study Framework

　Mian proposing cooporation:　　　　　　　　　　　　　　　Subcontractor:

　　　Joint proposing corporation:

　Mitsubishi Corporation

　The Institute of Energy Economics, Japan

　Chiyoda Corporation

　Tokyo Electric Power Services Co., Ltd.


- 29 -

Table 2-1 Members of Study Team

Koji Morita The Institute of Energy Economics, Japan

Director, Charge of Electric Power & Coal Unit

Atsuo Sagawa The Institute of Energy Economics, Japan

Coal Group, Electric Power & Coal Unit

Koichi Koizumi The Institute of Energy Economics, Japan

Coal Group, Electric Power & Coal Unit

Ayako Sugino The Institute of Energy Economics, Japan

Electric Power Group, Electric Power & CoalUnit

Tetsuo Morikawa The Institute of Energy Economics, Japan

Gas Group, Oil & Gas Unit

Makoto Akimoto The Institute of Energy Economics, Japan

Gas Group, Oil & Gas Unit

Yoshikazu Kobayashi The Institute of Energy Economics, Japan

Oil Group, Oil & Gas Unit

Reiko Takeuchi The Institute of Energy Economics, Japan

Electric Power & Coal Unit

Masaru Murata Mitsubishi Corporation

Shared Service Office

Michio Nakajima Mitsubishi Corporation

Shared Service Office

Keisuke Tanaka Mitsubishi Corporation

Power System Internatonal Unit

Takuya Inoue Mitsubishi Corporation

Power System Internatonal Unit

Kazuhiro Watanabe Thai-MC Company Limited

Machinery Dept. A

Krit Tangvisutthijit Thai-MC Company Limited

Machinery Dept. A

Lalintip Tantadprasert Thai-MC Company Limited

Machinery Dept. A

Saowarat Techamaneerat Thai-MC Company Limited

Machinery Dept. A

Ryouzo watari Chiyoda Corporation

CSR Divisio

Noboru Takei Chiyoda Corporation

Senior Group Leader, Energy & EnvironmentalProject Dept.

Kazuhito Ichihara Chiyoda Corporation

Process Engineer, Energy & EnvironmentalProject Dept.

Hideyuki Okano Tokyo Electric Power Services Co., Ltd.

Overseas Thermal Power Enginieering Dept.Mechanical Group

Takehiko Inagaki Tokyo Electric Power Services Co., Ltd.

Overseas Thermal Power Enginieering Dept.

Local survey coordination, localsurvey interpretation


Survey regarding environmental andsocial considerations


Technical aspects: IGCCspecifications, conceptual design



Thermal power generation planning

Name Company Role assigned

General affairs (electricity andenergy), feasibility projection

Economic and financial analysis(overall)

Coal procurement, bilateral carboncrediting

Effectiveness of syngas productionoptions

General affairs (electricity andenergy)

Coordination with customers,review for PPP

Project manager

General affairs (socio-economy)

Technical aspects, project cost

Technical aspects, project cost

Project cost, review for PPP

Assistance in data reduction andtable creation etc.

Local survey coordination, Generalinformation of Thailand


- 30 -

Table 2-2 Counterpart

Position

1 Mr. Paskorn Dangsmakr Project Development and Planning Division

2 Mr. Suwin Ajjimangkul Planning and Quality Development Division

3 Mr. Surapan Chuensiri Civil and Hydro Power Engineering Division

4 Mrs. Montharee Suvatanadecha Mechanical Engineering Division

5 Mrs. Sriwan Buranachokepisal Project Development and Planning Division

6 Mr. Charan Khumngeon Mae Moh Power Plant Production Division

7 Mr. Ampon Kitichotkul Mae Moh Mine Planning and Administration Division

8 Mr. Wallop Rirksutthirat Civil and Hydro Power Engineering Division

9 Mr. Sivarak Mahitthiburin Environmental Division

10 Mr. Paramaet Payattapin Energy Resources Engineering Division

11 Miss Jiraporn Sirikum System Planning Division

12 Mr. Sompan Prakthong Power Plant Development Planning Division

13 Miss Weena Singhnil Power Plant Development Planning Division

14 Mr. Piriya Tongchiew Mae Moh Power Plant Production Division

15 Miss Thanawadee Deetae System Planning Division

16 Mr. Worapoch Kamutavanich Project Development and Planning Division

17 Mr. Watchara Pinpetch Project Development and Planning Division

Name

(Source) Material provided by the EGAT

(3) Study Schedule

This study was conducted from August 6, 2011 to March 19, 2012. Since the second field study was

delayed by four weeks due to the floods in Thailand, this study was conducted a month behind the original

schedule.

Figure 2-2 Study Framework

Augast September October November December January February March

(Demestic work)(1)

(2)

Holding of an interim report meeting ☆(3) 10/21

Submission of a final report (draft) 　　　◎(4)

Holding of a final report meeting ☆3/1 Submission of a final report (draft) ◎

(1)

(2) 8/14-8/20

(3) 12/12-12/17 　　　　　　2/13-2/18

★

☆: Interim report meeting and final report meeting, ★: Field report meeting

◎：Submission of a draft final report and a final report

Preparation of a final report (draft)

2011 2012

Second field survey

Third field survey

　　　（Holing a report meeting）

Activity description

Preparation of a final report andholding a final report meeting

First field survey

Preliminary study, prearation ofquestionnaires and other works

Collection and analysis of informationand data


- 31 -

a) Domestic Study

In the preliminary study, in order to request the counterpart to provide information and data, we organized

existing information, and collected information and data necessary in deciding the specification of IGCC

plants and conceptual design, and conducting environmental and social considerations and profitability

assessment.

After the first field study, we investigated the specification of IGCC plants, conceptual design,

environmental and social considerations, economic analysis and general information.

After the second field study, based on the results of consultation with the counterpart and additional

information, we made the final decision on the specification of IGCC plants and construction costs,

conducted an economic analysis, and considered the feasibility of the project.

After the third field study, we brushed up the reports, including the results of consultation with parties

concerned in the partner country.

b) Field Study

The outline of field studies is as follows.

1) First Field Study

Term: From Sunday, August 14 to Saturday, August 20

Members:

Hirohito Morita The Institute of Energy Economics, Japan



Ryuzo Watari Chiyoda Corporation



Details:

Brief explanation of the project to EGAT Governor and Deputy Governor

Meeting with the EGAT project team (counterpart) (brief explanation of the project,

explanation of the study details, and request for data, etc.)

Site visit in Mae Moh (brief explanation of the project, explanation of the study details,

request for data, and site inspection, etc.)

Reports to the organizations concerned in Japan (brief explanation of the project, explanation

of the study details, etc.)

- 32 -

Table 2-3 First Field Study

Destination / Details Accommodation

Sunday, August 14 Travel: Tokyo => Bangkok Bangkok

Monday, August 15 EGAT project team (members in headquarters) / Meeting EGAT Governor and Deputy Governor / Brief explanation of the project JETRO / Brief explanation of the project

Bangkok

Tuesday, August 16 Embassy of Japan, NEDO, JICA / Brief explanation of the project Travel: Bangkok => Chaing Mai => Lampang

Lampang

Wednesday, August 17 EGAT project team (members in Mae Moh) / Meeting Site inspection

Lampang

Thursday, August 18 EGAT project team (members in Mae Moh) / Meeting Site inspection Travel: Mae Moh => Chaing Mai => Bangkok

Bangkok

Friday, August 19 EGAT project team (members in headquarters) / Meeting Travel: Bangkok =>

Flying overnight

Saturday, August 20 Travel: =>Tokyo

(Note) Major members in headquarters attend the meetings in Mae Moh. New Energy and Industrial Technology Development Organization (NEDO) (Source) Prepared by Study Team

2) Second Field Study

Term: From Monday, December 12 to Saturday, December 17

Members:



Kouichi Koizumi The Institute of Energy Economics, Japan

Takuya Inoue Mitsubishi Corporation




Details:

Meeting with the EGAT project team (counterpart) (interim report and information collection,

etc.)

Site visit in Mae Moh (interim report, information collection and site inspection, etc.)

Reports to the organizations concerned in Japan (progress of the study, etc.)

- 33 -

Table 2-4 Second Field Study

Destination / Details Accommodation

Monday, December 12 Travel: Tokyo => Bangkok Bangkok

Tuesday, December 13 Embassy of Japan, JETRO, JICA / Reports of progress of the study Travel: Bangkok => Chaing Mai

Chiang Mai

Wednesday, December 14 Travel: Chaing Mai => Mae Moh EGAT project team (members in Mae Moh) / Meeting, collection of information and data

Lampang

Thursday, December 15 EGAT project team (members in Mae Moh) / Meeting, collection of information and data, site inspection Travel: Mae Moh => Chaing Mai

Chiang Mai

Friday, December 16 Travel: Chaing Mai => Bangkok EGAT project team (members in headquarters) / Meeting Travel: Bangkok =>

Flying overnight

Saturday, December 17 Travel: =>Tokyo

(Note) Major members in headquarters attend the meetings in Mae Moh.. (Source) Prepared by Study Team

3) Third Field Study (Scheduled)

Term: From Monday, February 13 to Saturday, February 18

Members:






Kazuhiro Watanabe Thai-MC Company Limited


Lalintip Tantadorasert Thai-MC Company Limited

Details:

Holding of a final report meeting

Reports to the organizations concerned in Japan

Reports to the Ministry of Energy, EGAT Governor and Deputy Governor

- 34 -

Table 2-5 Third Field Study (Scheduled)

Destination / Details AccommodationMonday, February 13 Travel: Tokyo => Bangkok Bangkok

Tuesday, February 14 Ministry of Energy / Reports of results of the study Embassy of Japan, JICA / Reports of results of the study

Bangkok

Wednesday, February 15 EGAT Governor and Deputy Governor / Reports of results of the study Travel: Bangkok => Chaing Mai => Lampang

Lampang

Thursday, February 16 Travel: Lampang => Mae Moh Holding of a final report meeting (Mae Moh) Travel: Mae Moh => Chaing Mai => Bangkok

Bangkok

Friday, February 17 NEDO / Reports of results of the study Travel: Bangkok =>

Flying overnight

Saturday, February 18 Travel: =>Tokyo

(Note) Members in headquarters attend a final report meeting in Mae Moh. (Source) Prepared by Study Team

[Interviewees]

(Ministry of Energy)

Suparerk Sitahirun Director, Mineral Fuels Management Bureau

Sunti Thongvilard Senior Professional Geologist, Mineral Fuels Management Division

Tinnakorn Sunee Senior Professional Geologist, Mineral Fuels Management Division

Worasit W. Senior Professional Geologist, Mineral Fuels Management Division

(EGAT Governor and Deputy Governors and others)

Sutat Patmasiriwat Governor

Surasak Supavititpatane Deputy Governor - Generation

Pithsanu Tongveerakul Deputy Governor - Business Development

Soonchai Kumnoonsate Deputy Governor - Power Plant Development

Somboon Arayaskul formar Deputy Governor - Development

Somyos Theravongsakul Assistant Governor - Generation 2

(Organizations concerned in Japan)

Yohei Ogino Embassy of Japan in Thailand Second Secretary

Yoshito Asano JETRO Bangkok Director

Takashi Kono JETRO Bangkok Coordinator

Tomoyuki Kawabata JICA Thailand Office Senior Representative

Hajime Taniguchi JICA Thailand Office Representative

Rie Sato JICA Thailand Office Representative

Koichi Eguchi NEDO Asian Representative Office Chief Representative

Hironori Kawamura NEDO Asian Representative Office Director

Decha Chainapong NEDO Representative Office in Bangkok Director

Chapter 3 Consideration of Details of Project and Technical Aspect

- 36 -

(1) Background and Needs of the Project

Electricity Generating Authority of Thailand (to be referred to as the “EGAT”) manages all the power

plants in Thailand single-handedly and purchases electricity from other countries.

According to the Summary of Thailand Power Development Plan 2010-2030 (PDP 2010), the EGAT has

the projects to construct three 800 MW coal-fired power plants between 2021 and 2023, two 800 MW

plants in 2026, two 800 MW plants in 2028, and two 800 MW plants between 2029 and 2030. The “PDP

2010” does not specify the locations of the coal-fired power plants. Given the coal reserves in Thailand,

coal-fired power plants will depend on overseas coal, but the EGAT is also considering replacement at the

Mae Moh lignite based power plant.

Naturally, it is clear that new construction of the coal fired power plants is significantly positioned from

viewpoints of energy security, supply-demand balance and best mix of power source composition. The

EGAT is going to gradually retire the Mae Moh Thermal Power Plant in line with starting operation of the

above coal-fired power plants. Since the Mae Moh Thermal Power Plant is only one power plant using

domestic coal, the needs of replacement at Mae Moh are very high.

Figure 3-1 EGAT Power Source Composition in 2010


a) Scope of the project

This project is to construct an IGCC thermal power plant with a total installed capacity of 500 MW class

at the existing Mae Moh Thermal Power Plant located in the Mae Moh district, Lampang Province, about

90 km southeast of Chiang Mai, 500 km north of Bangkok. The following figure shows its general

location.

Total power energy: 57,630 GWh

Mae Moh (Units 4 to 7) 4,350GWh

(7.55%)

Gas turbine 276 GWh (0.48%)

Gas-fired 10,831 GWh

(18.79%)

Mae Moh (Units 8 to 13)13,663 GWh

(23.71%) Hydraulic

5,338 GWh (9.26%)

Combined cycle 23,167 GWh

(40,20%)

- 37 -

Figure 3-2 Kingdom of Thailand

Mae Moh

Bangkok

Chiang Mai

N

(Source) Prepared by Study Team based on Google Map

- 38 -

Figure 3-3 Mae Moh District, Lampang


Figure 3-4 Mae Moh Coal Mine and Power Plant

2400MW Sub-CriticalPower Plant at Mae Moh

City at Mae Moh

0 2 km


As a result of discussion with Thai counterpart, EGAT, in the first field survey, it was determined that

introduction of a 500 MW-class IGCC power plant using one gas turbine would be suitable for the current

- 39 -

facility situation.

Accordingly, this project will be considered, assuming its scope to be the 500 MW-class IGCC power

plant (one-on-one configuration).

The following table outlines the scope of construction of the IGCC power plant, or the target of this

project, at this point.

Table 3-1 Scope of Investigation for Construction Work in This Project

Target plant Mae Moh Thermal Power Plant Target unit For reducing project budget, it is necessary to make maximum reuse of the existing

common facilities. This survey assumes the new power plant to be constructed next to the existing Mae Moh Thermal Power Plant. It is not specified at this stage which unit should be replaced, because careful determination is required in view of a project completion period and the operating condition of the existing power generation facilities.

Scope of construction work

IGCC power plant construction work • Detailed design of the IGCC power plant. • Manufacturing, transportation and installation of the IGCC power plant. • Design and installation of a waste water treatment unit. • Connection to the existing reused facilities. • Test run and performance test of the IGCC power plant. • Technical consulting or owner’s engineering services.

Outside the scope

From a viewpoint of maximum reuse of the existing facilities, this survey excludes the following matters from the scope of construction work. However, they are subject to change due to identification of a project implementation site. • Demineralizer installation work. • Auxiliary steam generator installation work. • Auxiliary air and control air generator installation work. • Fire extinguishing pump/Diesel Generator installation work.


b) Analysis of the current situation, future prediction, and problems anticipated when this project

is not implemented

1) Situation of the existing facilities

At the existing Mae Moh Thermal Power Plant, the Units 1 to 3 have been already demolished, and the

Units 4 to 13 are currently running. Since the old Units 1 to 3 were located in a different area, the Units 4

to 13 currently constitute one thermal power plant.

The table on the following page outlines the Units 4 to 13 at the existing Mae Moh Thermal Power Plant.

- 40 -

Table 3-2 Specifications of Existing Power Generation Facilities

Unit4 Unit5 Unit6 Unit7 Unit8 Unit9 Unit10 Unit11 Unit12 Unit13

1 Rated Capacity (MW) 150 150 150 150 300 300 300 300 300 300

2 Current output (MW) - - - - 300 300 300 300 300 300

3 Plant Heat rate (Last Perform. Test) (kcal/ kWh)

- - - - 2,375 2,375 2,375 2,375 2,400 2,400

4 Boiler manufacturer CEMAR (CE / Marubeni)

5 Boiler Type - Coal fired, Double pressure, Reheat, Subcritical

6 Turbine manufacturer Fuji Electric

7 Main steam temperature degree-C - - - - 538 538 538 538 538 538

8 Main steam pressure (MPa) - - - - 16.1 16.1 16.1 16.1 16.1 16.1

9 Generator Manufacturer Fuji Electric

10 FGD manufacturer ABB IDECO Mitsubishi

11 Commercial operating year 1984 1984 1985 1985 Oct.16 1989

Jul.20 1990

Sep.1 1991

Jan.1 1992

May.5 1995

Nov.19 1995

12 Retirement year (planning) 2023 2024 2024 2025 2029 2030 2031 2032 2035 2035

(Source) EGAT, Summary of Thailand Power Development Plan 2010-2030, April 2010 edition

- 41 -

In order to introduce a supercritical pressure (SC) coal-fired power plant in place of the Units 4 to 7, the

EGAT has just started a procedure for an environmental and health impact study. For the moment, it is

planned to stop the Units 4 to 7 and construct the new plant next to the Unit 13.

This is because the Units 4 to 7 supplies power and include monitoring device, etc. for the common

facilities of the power plant, it is unrealistic to remove them, while continuing to run the Units 8 to 13. To

make use of the space of the Units 4 to 7, various facility replacement and renovation are required in

advance such as relocation of the common power source facilities of the power plant, switching of the

plant internal power system, relocation of common facility piping, and remodeling of the control units for

common facilities. Because it is necessary to wait for the boilers and turbines to be removed after

relocation of the common facilities in addition to occurrence of these relocation and remodeling expenses,

the construction starting date of new facilities will be delayed. The existing turbine building cannot be

reused because the facilities will be enlarged, increasing the load conditions. Namely, it is unrealistic in

terms of both cost and construction period to carry out removal and construction work in a narrow space

surrounded by the existing facilities. Since there is a spacious site available for new construction, the

EGAT is currently planning to construct next to the Unit 13. In constructing the IGCC power plant in this

project, a similar situation is assumed if the existing facilities are not greatly remodeled.

The Units 4 to 7 and 8 to 13 have different outputs and operation start times. The Units 4 to 7 have power

generation output of 150 MW each and have been operating for about 30 years since their start of

operation. In view of the past background, the desulfurization equipments have been additionally installed

for all of them, fully considering environmental performance. At the time of survey, the typical

environmental performance values were SO2 = 118 ppm, NOx = 280 ppm, and PM = 9 mg/Nm3. With

their facilities properly inspected and maintained, there is no remarkable output fall or degradation of

environmental performance, indicating a sufficient management system being in place.

However, the installed technologies are old fashioned and gross heat rate is lower than the current

technologies. Furthermore, the quality of mined coal has been changing these years, partly becoming

incompatible with the current boiler design conditions from time to time. Particularly, a ratio of CaO in the

ash content has risen, becoming one of the factors causing slagging. Since a boring survey expects a

higher ratio of CaO in the future, the Mae Moh Thermal Power Plant has been studying a CaO

distribution in a coal bed (K and Q layers), mixing the coal with high and low ratios of CaO together so as

to be available for operation, conducting various combustion tests, thus making efforts to ensure stable

combustion.

As described later, a high load factor and high facility availability have been maintained in the operational

aspect.

Accordingly, operation upkeep work at the Mae Moh Thermal Power Plant indicates the high technical

quality of each engineer. Even if the state-of-the-art power plant is introduced in this project, it can be

determined that implementation of technical guidance will allow the employees to operate it. On the other

hand, the existing boilers are becoming incompatible with the coal properties, indicating the responsive

limit of the facility capabilities. It is appropriate to considering replacement at this moment.

The table on the following page shows the latest operating condition of the Units 8 to 13 at the existing

- 42 -

Mae Moh Thermal Power Plant.

What is most distinctive is a high load factor. Over these 5 years, the average load factor of all the units is

96.3%; the highest at 98.4% and lowest at 88.3%, indicating extremely high values. This shows that the

Mae Moh Thermal Power Plant continues to generate the power in a close-to-full load state almost around

the clock. Given that actual plant operation does not allow operation at constant rated output in order to

respond to each plant’s frequency control function, voltage control function and load fluctuation, those

values are quite excellent.

Table 3-3 Operation Records of Existing Power Generation Facilities (2006 to 2010)

Unit Total Output

(MWh) Operating hours

(h) Maintenance Outage (h)

Load Factor (%)

8 2,105,041 7,169 0 97.88

9 1,890,986 6,689 1,668 94.24

10 2,045,662 7,009 1,356 97.29

11 2,503,108 8,526 0 97.86

12 2,485,105 8,515 0 97.28

2006

13 2,239,541 7,672 607 97.30

8 2,349,074 7,960 0 98.37

9 1,948,576 7,360 0 88.25

10 2,452,434 8,374 0 97.62

11 2,236,268 7,672 0 97.16

12 2,402,299 8,427 0 95.03

2007

13 2,484,510 8,518 0 97.23

8 2,120,041 7,239 1,332 97.62

9 2,483,320 8,559 0 96.72

10 2,457,900 8,394 0 97.60

11 2,440,882 8,395 0 96.92

12 2,284,446 7,939 614 95.91

2008

13 2,231,795 7,890 653 94.29

8 2,409,990 8,316 0 96.60

9 2,242,270 7,850 641 95.21

10 2,061,881 7,083 1,416 97.03

11 2,027,446 7,105 1,361 95.12

12 2,357,840 8,254 0 95.22

2009

13 2,388,224 8,316 0 95.72

8 2,148,626 7,475 636 95.81

9 2,345,234 8,060 0 96.99

10 2,465,768 8,470 0 97.04

11 2,482,390 8,527 0 97.04

12 2,111,957 7,278 1,332 96.73

2010

13 2,110,192 7,282 1,212 96.59

(Source) Prepared by Study Team based on EGAT data

- 43 -

The second most distinctive is availability. With actual operating time reaching about 7,000 to 8,000 hours,

the number of operating days is high and inoperable time due to facility troubles is little.

Accurate availability cannot be calculated because operation standby time has to be added. Even if

operation standby time is assumed to be 0 hour as the toughest case, however, the average simple

availability of all the units over 5 years is higher than 85%.

In view of its long operating time and high load factor according to the operation records of the Mae Moh

Thermal Power Plant, it is understood why it is positioned as a significant power source running at full

load as much as possible as the EGAT’s base power source. Accomplishment of the high load factor

means actual implementation of excellent maintenance and inspection which allows constant exhibition of

full-load operation. It is assumed that a gradual decrease of availability is a result of the latest quality

change of coal, but the Mae Moh Thermal Power Plant has been still accomplishing sufficiently high

values.

As a conclusion, the Mae Moh Thermal Power Plant has been acting as a significant power source

through excellent operation and maintenance, while including an indefinite risk called the quality change

of coal.

Figure 3-5 Load Factor


Table 3-4 shows gross plant efficiency η (%, on a higher heating value basis) based on the latest

performance test data of the Units 8 to 13 at the existing Mae Moh Thermal Power Plant. Figure 3-6

shows the tendency of gross plant efficiency over the latest five years.

The gross plant efficiency (η) is given in inverse number of heat rate HR(kcal/kWh) and calculated by the

following formula.

82.00%

84.00%

86.00%

88.00%

90.00%

92.00%

94.00%

96.00%

98.00%

100.00%

2006 2007 2008 2009 2010

Unit 8

Unit 9

Unit 10

Unit 11

Unit 12

Unit 13

- 44 -

η = 860/HR (%)

Fuel data is managed by higher heating values (to be referred to as“HHVs“) and its values are the HHVs

unless otherwise specified.

Table 3-4 Latest Performance Test (Typical Coal: HHV)

Unit 8-11 Unit 12-13

Plant Heat Rate (kcal/kWh) 2,375 2,400

Plant Efficiency η(Gross: %) 36.21% 35.83%


Figure 3-6 Tendency of Plant efficiency (Total fuel: HHV)

33.00%

33.50%

34.00%

34.50%

35.00%

35.50%

36.00%

36.50%

37.00%

37.50%

38.00%

38.50%

2006 2007 2008 2009 2010

Unit 8

Unit 9

Unit 10

Unit 11

Unit 12

Unit 13


Given that the existing Mae Moh Thermal Power Plant has been running for 20 to 30 years from the start

of operation and burning lignite, Table 3-2 and Figure 3-5 show that it has been fully exhibiting its design

performance. Figure 3-6 also shows that it has been appropriately managed.

In the aspect of performance as shown in Table 3-4, however, it has been becoming obsolete increasingly,

compared with the up-to-date thermal power generation technologies. The performance test data in Table

3-4 is of the Units 8 to 13 which started operation 15 to 20 years ago; the values are not very high.

When the properties of coal used at the Mae Moh Thermal Power Plant are applied to the up-to-date

thermal power generation technologies, the value is estimated to be 37.42% for the supercritical pressure

coal-fired power plant (SC), 38.35% for the ultra supercritical pressure coal-fired power plant (USC), and

about 41.5% (net: HHV) in case of the oxygen blown method for this IGCC power plant on an HHV

basis, respectively.

- 45 -

Some data in Figure 3-6 are greater than the data in Table 3-4, but this is because the data in Figure 3-6

has been calculated based on the calorific value of total fuel added with coal and all fuel oil for auxiliary

combustion at start-up time. This is because the coal and fuel oil for auxiliary combustion cannot be split

for generated electric power. Table 3-4 shows the performance values with coal only, and Figure 3-6 is

evaluated as tendency values showing the EGAT’s latest management condition.

2) Future prediction

According to the “PDP 2010,” the peak demand in Thailand is expected to increase by 1,000 MW or more

every year.

Currently generating about 31% of the EGAT’s power generation on a generated electricity basis and

being the EGAT’s only one coal-fired power plant, the Mae Moh Thermal Power Plant is an extremely

significant power source in terms of both fuel balance and electric energy.

According to the “PDP 2010,” the power source composition of the power plants will not change for the

time being and the operating condition of the Mae Moh Thermal Power Plant seems to continue as it is.

Accordingly, the Mae Moh Thermal Power Plant, a main power plant, is significantly positioned in future

electric power supply and demand in Thailand, and the replacement plan has been already reflected in the

“PDP 2010.”

Given high environmental awareness in Thailand and the EGAT’s future plans based on the

above-mentioned, it is very significant to implement the construction of the IGCC power plant at the Mae

Moh Thermal Power Plant.

3) Problems anticipated when this project is not implemented

If this project is not implemented, the Mae Moh Thermal Power Plant will age further, requiring

replacement. Preparations for replacing the Units 4 to 7 with an SC coal-fired power plant are currently

under way, but recent problems such as aging of the subsequent Units 8 to 13 and deteriorated combustion

due to the change of coal properties are anticipated.

Particularly, there is a high possibility of more frequent slagging phenomenon due to a higher CaO ratio

resulting from the change of coal properties, the current old-design power plant may have difficulty

continuing to run in the future, having an enormous influence on power supply, when the significance of

the Mae Moh Thermal Power Plant in the EGAT is taken into account.

c) Effects and impacts when this project is implemented

When this project is implemented, suppose the existing coal-fired power plant is suspended from

generating 425 MW worth of electric power, gross plant efficiency will be improved by 36.21 to 48.82%

and fuel consumption will be improved by about 35% (relative value on the ggross basis). Furthermore, a

combustion condition will become suitable for the IGCC power plant with respect to the change of coal

properties, allowing us to expect stable operation.

Also, the IGCC power plant brings about various major effects owing to its high plant efficiency. The

following list the minimum possible items.

- 46 -

When the same electric energy is generated, the resources in Thailand can be used more

effectively than before because fuel consumption can be inhibited.

Gas emissions will be reduced for an improved rate of plant efficiency.

Water consumption will be reduced, resulting in less environmental burdens, because

desulfurization is implemented in the high-pressure combustion gas condition on the

following wake side of the gasifier.

A total discharge amount of coal ashes will be reduced because of the improved plant

efficiency and a lower volume due to melting of the coal ashes.

The IGCC power plant has high operational adaptability to low-grade coal and is effective to

the future change of coal properties.

Furthermore, it is expected that introduction of the first IGCC coal-fired power plant in Thailand will

bring about incidental effects such as enhanced environmental awareness in Thailand, better coexistence

with the general public living in the vicinity, acquisition of knowledge on the cutting-edge environmental

technologies, and improved technical capabilities by this project.

d) Comparison with other options

There are the following possible alternatives to introduction of the IGCC power plant. The following

compares these alternatives. Alternative 2 is further subdivided into two because there are two possible

cases of using domestic fuel or imported fuel.

Alternative 1: Fuel shift to imported natural gas

Construction of a natural gas combined cycle (NGCC) thermal power plant based on imported

LNG; construction site undetermined

Alternative 2: Construction of an ultra supercritical pressure coal-fired thermal power plant.

2-(1): Construction of an ultra supercritical pressure coal-fired thermal power plant at the Mae

Moh Thermal Power Plant.

2-(2): Construction of an ultra supercritical pressure coal-fired thermal power plant based on

imported coal; construction site undetermined.

Alternative 1: Fuel shift to imported natural gas

“Construction of a natural gas combined cycle thermal power plant based on imported natural gas;

construction site undetermined”

This is a possible option when an overall domestic power source development plan is considered. When

the construction site is left undetermined, all the problems peculiar to the construction site such as

securement of fuel, acquisition of land, power transmission lines, industrial water (cooling water included),

and environmental problems are excluded from consideration.

Given that imported natural gas combined cycle thermal power plants have been running as main power

generation facilities in each different countries, there is no problem resulting from the plant technologies.

Accordingly, this case contributes to determination of investment priority in the EGAT and needs to be

simply compared by economic calculation with all the construction site properties eliminated.

For the economic calculation according to the imported natural gas combined cycle thermal power plant,

- 47 -

given the necessity to construct infrastructure for this case, it is realistic to include the installation costs of

an LNG terminal as minimum infrastructure.

Alternative 2: Construction of an ultra supercritical pressure coal-fired thermal power plant

“2-(1): Construction of an ultra supercritical pressure coal-fired power plant at the Mae Moh Thermal

Power Plant”

Given the facility renewal of the current subcritical pressure coal-fired power plant, introduction of an

ultra supercritical pressure (to be referred to as the “USC”) coal-fired power plant is the most general

method. The USC refers to higher-temperature, higher-pressure boiler steam conditions and have been

developed as subcritical pressure, supercritical pressure (SC) and ultra supercritical pressure (USC) at

large-scale plant manufacturers; it is the improvement result of the existing boiler technologies. That is to

say, it is mostly reasonable for the EGAT to intend to replace the Units 4 to 7 with the supercritical

pressure (SC) coal-fired power plant.

When the technical aspect is purely considered, there are merits and demerits in the USC coal-fired power

plant and the proposed technology, IGCC power plant, and it cannot be said which one is absolutely

superior. They are options to combine optimum methods in line with the construction site properties.

However, the Mae Moh Thermal Power Plant faces the problem of the change of coal quality and has to

take its conditions into full account.

Technical details are considered in Chapter 3, (2), c).

“2-(2): Construction of an ultra supercritical pressure coal-fired power plant based on imported coal;

construction site undetermined”

When the construction site is left undetermined, the problem of fuel supply as implemented in the Mae

Moh district is solved, as with the case in 1-(2).

When the above-mentioned three alternatives are compared, introduction of the IGCC thermal power

plant proposed this time is believed to be a very effective project in order to realize the most efficient

power source composition within a limited period, because various conditions such as the construction

site, water resource, power transmission lines and fuel have been already settled.

Since introduction of the USC coal-fired power plant in Alternative 2-(1) is also effective, it is specifically

compared as to the differences in the technological characteristics combined with construction site

conditions in following Chapter 3, (2), c).

Alternatives 1 and 2-(2), which have the construction site properties excluded, are compared in the

financial and economic practicabilities because they contribute to determination of investment priority in

the EGAT.

- 48 -

(2) Considerations Required for Deciding the Details of the Project

a) Demand prediction

For a future prospect of overall demand, the EGAT predicts a continuous increase of domestic electric

power demand in Thailand based on Chapter 1, (2) Overview of the project target sectors. Namely, supply

capacity improvement measures are essential, such as continuous renewal of the power generation

facilities, power output enhancement.

The following analyzes an electric power demand based on the track record values of the demand curve of

the entire EGAT in 2010.

Figure 3-7 shows the maximum monthly output in 2010. This demand curve indicates the seasonal

variations of the electric power demand of the entire EGAT.

Figure 3-8 shows the demand curve for the day having the maximum output in 2010, and that for the day

having the maximum output in the month of the lowest demand. The day having the maximum output is

May 10, 2010, and the typical day of the month having the lowest maximum monthly output is Oct. 8,

2010.

Figure 3-7 Monthly Peak Output (MW)

-

5,000.00

10,000.00

15,000.00

20,000.00

25,000.00

30,000.00

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

2010

Man

thly

Peak

(M

W)


- 49 -

Figure 3-8 Typical Daily Output (Max & Min)

0

5000

10000

15000

20000

25000

30000

0:00

1:00

2:00

3:00

4:00

5:00

6:00

7:00

8:00

9:00

10:00

11:00

12:00

13:00

14:00

15:00

16:00

17:00

18:00

19:00

20:00

21:00

22:00

23:00

Time

Dai

ly L

oad

Curv

e (M

W)

10-May-2010 8-Oct-10


According to Figure 3-7, a generation output ratio of the month having the maximum output to that

having the lowest maximum output is 87.3%, indicating that there is not so big change in electric power

consumption due to seasonal variations in Thailand.

The maximum output value for each month indicates a supply capacity which has to be minimally held in

order to carry out periodical inspection, and that which has to be maximumly held for demand. Since the

power generation facilities require periodical inspection, it is necessary to sum up the supply capacities,

taking both of these values into account. Namely, it is assumed that power source operation by the EGAT

always requires appropriate securement of a reserve capacity at periodical inspection time of the power

generation facilities, and it is presumed that the power source development plan is going to throw in the

facilities early in good time.

Figure 3-8 shows an electric power balance between the daytime and night, and seasonal differences.

According to this figure, it is clear that there is not so big change of electric power consumption due to

variations between the daytime and night.

Of the day, the minimum generation output to the maximum generation output is 71.4% on May 10 and

73.0% on Oct. 7. Obviously there is a considerable demand even during late night hours.

The above-mentioned small seasonal variations of electric power demand and small variations between

the daytime and night mean that the power generation facilities do not have a high extra supply capacity,

making it important to stably run the facilities. In other words, the expected role of the Mae Moh Thermal

Power Plant is extremely important, which accounts for about 25% of the EGAT’s entire power

generation, continuous investment in the power generation facilities is essential, and the need for renewing

the Mae Moh Thermal Power Plant is expected to be very high.

- 50 -

b) Understanding and analysis of the problems required for considering and deciding the details of

the project

This project consists of one block of the IGCC thermal power plant. Device configuration per block is

one-on-one, including one coal gasifier, one gas turbine, one heat recovery steam generator and one steam

turbine.

This project survey conducted the minimum checks and examinations as follows, imperative for planning

construction of a power plant as to a proposed construction site at the existing Mae Moh Thermal Power

Plant. As a result of considering from the viewpoints of the following five items 1) to 5), this proposed

construction site was found out to be suitable for construction of the thermal power plant from every

viewpoint.

Preparations for the replacement plan of the Units 4 to 7 are now under way as to a specific layout in the

premises, but they have just started, requiring technical cooperation in near future. Accordingly, this

survey will report the conditions such as required areas, layout, etc. so as to contribute to future adjustment

instead of deciding detailed locations.

Also, the following analyses assume the maximum reuse of the existing facilities in order to curb the

project implementation expenses.

1) Fuel supply

With an adjoining coal mine, the Mae Moh Thermal Power Plant problems peculiar to the site. Firstly,

fuel consumption must be designed in line with a fuel supply capacity from the coal mine. Since the coal

produced from the coal mine is used, the fuel quality depends on the coal bed. In other words, it is difficult

to mix the coal with high degree of freedom such as imported coal and necessary to run the power plant,

while finding an operable coal-mixing range, using the produced coal.

Consider the fuel supply capacity. Because the reuse of the existing facilities is a precondition, the output

was set to the 500 MW class so as to be compatible with the current ancillary facilities.

The IGCC power plant planned in this project consumes less fuel than the existing power generation

facilities, and its fuel consumption is estimated to be not greatly different from fuel consumption of one

300 MW unit (or two 150 MW units) at the existing Mae Moh Thermal Power Plant. Given that the

existing facilities have been smoothly run year after year, it is not specially difficult in terms of fuel supply

capacity to stop these units and use the IGCC power plant.

Consider the fuel quality. There are growing concerns about quality degradation of recently mined coal

due to an increasing component ratio of CaO in the ash content. Currently, the Mae Moh Thermal Power

Plant has been continuously running, while mixing the coal based on the CaO distribution in the surveyed

coal bed, but the existing boilers have experiences of forced outage due to slagging to remove the coal

ashes. Taking the CaO issue seriously, the EGAT has predicted future quality degradation of coal

properties based on boring data. In carrying out this project, it is necessary to consider the future prospect

of coal properties in designing.

- 51 -

2) Power plant construction site

Candidate sites are the premises of the existing power plant and a site slightly distant from the premises.

The candidate site in the premises of the existing power plant is next to the Unit 13. The other candidate

site slightly distant from the premises is where the EGAT once planned an expansion (power generation

by a circulating fluidized bed boiler) in the past. Figure 3-9 shows the candidate sites.

In the premises of the existing power plant, a power plant area is compactly laid out, but the premises are

so extensive that the construction site can be fully secured even under the condition that replacement of

the Units 4 to 7 has been drawn up. There is a blank space next to the Unit 13, and a reservoir on its

extension, which can be also fully expected as the construction site. Since this project has to consider

maximum use of the existing facilities in order to cut down on initial costs, it is most realistic to install on

the extension of the existing facilities. It is also possible to secure the construction site behind the flue of

the existing facilities as another alternative, but it is not easily accessible.

Figure 3-9 Candidate Sites for New IGCC Power Plant

(Source) Google Map, Study Team

Candidate 2

New Unit instead of Unit 4-7

Existing Unit 1-3 (Demolished)

Existing Unit 4-13

Candidate 1: Next to New Unit instead of Unit 4-7

- 52 -

The candidate site slightly distant from the premises of the existing power plant can easily take the water

because it is adjacent to the reservoir, but requires fuel facilities, common facilities and renovation of

transmission lines, installation of a switching station, and collaborative control with a transmission system.

Furthermore, it is necessary to consider an office building and various maintenance spaces, resulting in

higher costs.

As a conclusion, since both this project and the replacement plan of the Units 4 to 7 are to be implemented

by the EGAT, the use of the land in the premises of the existing power plant can be planned in a

collaborative manner, and there is no problem in securing the power plant construction site at this moment

because of availability of many candidate sites.

Figure 3-10 Candidate Site for New IGCC Power Plant (Next to Unit 13)


Figure 3-11 Candidate Site for New IGCC Power Plant (Outside Power Plant Area)


- 53 -

Figure 3-12 Candidate Site for New IGCC Power Plant (Backside, Option)


3) Securement of water sources

The biggest consumption source of water sources at the thermal power plant is cooling of exhaust steam

in a condenser. In the existing facilities, a cooling tower system has been installed to reduce water

consumption. In addition, there are demineralized water and service water; all the water sources are raw

water from the reservoir. The following figure shows Mechang Reservoir, one of main reservoirs, and a

regulating pond. In line with development of the power plant in the past, a river was backed up to create

an artificial reservoir. This raw water is partly distributed to neighboring residents as daily life water. In

order to respond to a dry season, the Mae Moh Thermal Power Plant has several reservoirs such as

Kaekham Reservoir (adjacent to the power plant candidate site 2 in Figure 3-9).

The raw water goes into the regulating pond through a canal from the reservoir and is fed by a raw water

pump. After being fed, it is purified by a clarifying, water purifier, and so on in the power plant area, and

then, distributed to each facility.

- 54 -

Figure 3-13 Mechang Reservoir


Figure 3-14 Regulating Pond


The IGCC power plant is a combination of gas turbines and steam turbines, and when it generates the

same output as a pulverized coal-fired power plant, water consumption is reduced greatly because of the

output quotient ratio of the steam turbines mainly using the industrial water. For the IGCC, the generated

output of the stem turbines is about halt to one third of the total output, and the required boiler water

volume is similarly reduced.

Furthermore, the Mae Moh Thermal Power Plant has wet desulfurization equipments installed as an

environmental measure for the coal-fired power plant, but these wet desulfurization equipments require a

considerable amount of industrial water. On the other hand, the IGCC power plant implements

desulfurization in the high-pressure combustion gas condition at the gas purification facility on the

- 55 -

following wake side of the gasifier, resulting in higher reactivity. When the output is the same, average

industrial water consumption is cut down. Because the gas purification facility has several options,

quantitative values cannot be set for the moment. Considering together with reduced consumption of plant

water, however, water consumption is greatly reduced with respect to the existing facilities, and as a result,

there will be an spare capacity in the capabilities of water treatment system, posing no special problem.

4) Power transmission plan

A connecting voltage and connecting point to the transmission lines will be planned, considering a tidal

current and transmission line capacity in the phase of making a future detailed plan.

As shown in Figure 3-15, however, the Mae Moh Substation, one of key substations, is high-capacity

facilities taking charge of key systems such as 115 kV, 230 kV and 500 kV key systems, and local supply

system. Based on the above, there still remains a need to consider in collaboration with other power

source projects, there will hardly be any problems.

Fig. 3-15 shows an overall layout of the EGAT’s electric power supply facilities such as power

transmission lines, substations, power plants. Full lines denote the existing facilities, dotted ones denote

the facilities under construction, and broken ones the facilities on the drawing board. Color-coding

indicates different voltage classes. The types of facilities are indicated by using different graphic figures.

- 56 -

Figure 3-15 Electric Power System of Thailand

(Source) EGAT, Summary of Thailand Power Development Plan 2010-2030

- 57 -

5) Environmental and social considerations

Prior to implementation of this project, the EHIA (Environmental and Health Impact Assessment) is

required. The EGAT has been preparing for proceeding with the procedure by itself for the replacement

plan of the Units 4 to 7. In view of the fact that the desulfurization equipments were additionally installed

for the existing Units 4 to 13, the EGAT is extremely aware of the environment, having no problem as to

environmental management.

Concerns about the aspect of environmental performance are the effects of air quality, water quality, noise,

vibrations and waste materials. Although the details are described in Chapter 4, it is a prerequisite to reuse

the existing power generation facilities maximumly, and there is currently no factor which may deteriorate

the environmental performance.

c) Consideration of the technical methods

The technology proposed in this project is construction of the IGCC power plant. Based on the results of

comparison in Chapter 3, (1), d), the following compares the technical aspect with the most realistic

alternative technologies among them, namely the supercritical pressure (SC) and ultra supercritical

pressure (USC) coal-fired power plants using Mae Moh coal as fuel.

1) Features of the alternative technologies, the supercritical pressure and ultra supercritical pressure

coal-fired power plants

Thermal power boilers have been largely improved on two points in a continual manner. The first point is

improvement of combustion and the second one is that of steam conditions. With the performance being

improved by accumulation of these technical developments, it has the following features.

For the first point, improvement of combustion, the technologies with excellent environmental

characteristics have been continually developed, while maintaining stability of combustion in the boiler

furnace. This depends greatly on the fuel quality. Lower exhaust gas loss and radiation from the boiler

body have more effect on boiler efficiency viewed from the aspect of combustion, but relatively

improvement of combustion has a small effect on boiler efficiency improvement of the entire plant.

Improvement of combustion greatly contributes to higher environmental performance.

For the second point, improvement of the stem conditions, the steam pressure and temperature in the

boiler tube have been continually improved. Although they do not have a big effect on boiler efficiency,

viewed from the entire boiler, they considerably help improve efficiency of the steam turbine on the

following wake side, contributing to higher plant efficiency.

Based on the subcritical pressure coal-fired power plant introduced to the Mae Moh Thermal Power Plant,

the following compares the proposed technology, the IGCC power plant and the alternative technologies,

SC and USC coal-fired power plants.

As one of performance features, Table 3-5 shows the anticipated boiler efficiency improvement due to

introduction of the SC and USC coal-fired power plants to the Mae Moh Thermal Power Plant. Adding

efficiency improvement of the steam turbine in Figure 3-16 to this, Table 3-6 shows the anticipated plant

efficiency improvement.

- 58 -

As qualitative comparison of the technical aspect, Figure 3-17 shows boiler design examples depending

on the quality of coal properties.

Based on the above considerations, the Table 3-7 summarizes the performance features, qualitative

comparison results of the technical aspect, and those of the environmental aspect.

2) Comparison of the performance aspect

Consider comparison of the performance aspect.

The following describes selection of the main steam pressure, main steam temperature and reheat steam

temperature. For the subcritical pressure boiler serving as a base case, the values of the current Mae Moh

Thermal Power Plant were used as they are.

For the supercritical pressure boiler and ultra supercritical pressure boiler, given the creep properties and

economic efficiency of the material, it is necessary to turn the performance to either the pressure or

temperature. As shown in Tables 3-8 and 3-9, the overseas plants tend to have higher maximum operating

pressure and Japanese ones tend to have higher maximum operating temperature. To enhance plant

efficiency, it is generally more effective to improve the temperature than the pressure. Accordingly,

versatile values were employed for comparison in this survey, taking into account the track records of the

Japanese and overseas plants.

Since the IGCC power plant uses the heat recovery steam generator, exclusive design values are assumed

because the furnace internal temperature is lower and it is not so effective to apply the SC or USC.

Table 3-5 shows anticipated improvement of boiler efficiency by improving the pressure and temperature,

and Figure 3-16 shows anticipated improvement of steam turbine efficiency.

The plant heat efficiency can be calculated by “Boiler efficiency x Turbine efficiency.”

Table 3-5 Anticipated Improvement of Boiler Efficiency by Introducing the SC and USC Coal-Fired

Power Plants to the Mae Moh Thermal Power Plant

Subcritical Supercritical (SC) Ultra supercritical (USC)

Boiler efficiency (%;HHV) 80.47 80.58 80.67

(Source) Prepared by Study Team based on internal data

Table 3-5 shows the calculation results of anticipated boiler efficiency. The base subcritical pressure boiler

efficiency is the value calculated by dividing with the steam turbine efficiency according to the weather

conditions of the Mae Moh Thermal Power Plant, based on the latest performance test data of the plant

efficiency of the Mae Moh Thermal Power Plant. Namely, the base boiler efficiency is a calculated value,

not a measured one, but there is no big discrepancy because the plant efficiency is a track record value.

The base value of the subcritical pressure value was corrected with a relative value, using the recent actual

performance improvement data of the SC and USC boilers to calculate the boiler efficiency. As a result, it

- 59 -

is clear that the efficiency is improved only slightly with the boiler alone. Namely, it is understood that

introduction of the SC and USC should be evaluated with comprehensive values added with the improved

turbine efficiency. On the other hand, the boiler efficiency depends more on the coal properties than the

performance of the boiler in a way.

Figure 3-16 shows the calculation results of steam turbine efficiency improvement rate. As with Table 3-5,

the base steam turbine efficiency is the value calculated by dividing the actual plant efficiency according

to the weather conditions.

The calculation results are +3.18% (relative value) for the supercritical pressure plant and +5.64%

(relative value) for the ultra supercritical pressure plant with respect to the steam turbine efficiency base

value. According to these results, the turbine efficiency increases as the temperature and pressure become

higher. Figure 3-16 indicates that the effect of temperature rise is high. Since there is the problem of

creep properties of the material, however, it is difficult to use at extremely high temperature when it is

particularly necessary to take combustion into account such as low-grade coal.

Figure 3-16 Anticipated Improvement of Steam Turbine Efficiency by Introducing the SC and USC

Coal-Fired Power Plants to the Mae Moh Thermal Power Plant

600/600

593/593

566/593

566/566

538/566

538/538

0.00

3.18

5.64

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

15.0 20.0 25.0 30.0

Rated Main Steam Pressure (MPag)

Heat

Rat

e Im

prove

ment

(%)

600/600

593/593

566/593

566/566

538/566

538/538

Mae Moh 400MW (Sub C)


Table 3-6 shows the calculation results of the plant efficiency added with the above-mentioned improved

boiler efficiency and turbine efficiency. These results indicate that the plant efficiency is bettered

accordingly by improving the maximum operating temperature and pressure.

- 60 -

Table 3-6 Anticipated Improvement of Plant Heat Efficiency

Subcritical pressure

Supercritical pressure（SC）

Ultra supercritical pressure（USC）

Abs. value 36.21 37.42 38.35 Plant efficiency (%;Gross, HHV） Rel. value Base 3.33 5.91


3) Qualitative comparison of technical aspect

Consider qualitative comparison of technical aspect.

Firstly, there is a difference in slagging properties.

In case of the pulverized coal-fired boiler, the coal ashes are mainly removed from the bottom of the boiler

furnace in the form of clinker ashes and from the rear flue of the boiler in the form of fly ashes. Once the

coal ashes melt in the boiler furnace, they adhere to the heat transfer surface of the furnace, causing

various troubles. For this reason, two basic measures are mainly considered; one is to reduce melting of

the ashes, and the other is to eliminate the adhered ashes, if any, by blowing high-temperature steam to the

heat transfer surface by a soot blower. However, it is impossible to blow the high-temperature steam to all

the heat transfer surfaces, and it is important to minimize adhesion of the ashes. Regardless of the

subcritical pressure, supercritical pressure and ultra supercritical pressure boilers, the pulverized coal-fired

boiler generally has the combustion temperature of about 1,400 deg C even in case of bituminous coal

which has the highest calorific value. Namely, this is a significant design element when using low-grade

coal with a low ash fusion point.

In case of the IGCC power plant, on the other hand, the coal ashes are melted in the furnace to be

discharged, and the melted ashes are hardened into glassy slag and released from the bottom of the gasifier.

This is because the combustion temperature in the gasifier is 1,500 deg C to 1,600 deg C, higher than the

pulverized coal-fired boiler, which is completely different from the pulverized coal-fired boiler. The

temperature in the gasifier differs depending on whether the applied gasifier is oxygen blown or air blown,

but the coal ashes discharge principle is the same.

Secondly, there is a difference in the volume of the boiler and gasifier.

Figure 3-17 exemplifies design differences depending on the type of coal for the coal-fired power plant;

(a) for bituminous coal, (b) for subbituminous coal, and (c) for lignite, with the same output design of 660

MW.

When low-grade coal is used, it is necessary to increase the volume of the boiler and install more soot

blowers as slagging preventive measures. Specifically, a distance between the burner and furnace wall is

designed longer.

When using coal with a low rank of coalification, it burns very easily, but contains more moisture, etc.,

having a low fuel calorific value. In other words, the specific gravity of combustion gas becomes higher,

and as a result, it is necessary to expand a heat transfer area to fully absorb the low calorific value as well

as heighten the boiler to enhance draft power.

- 61 -

The following illustrations (a) to (c) exemplify horizontally opposed burners. In order to simplify their

comparison, the burner arrangement direction (depth direction in the figure) is assumed to be of the same

width. Generally, the lignite-fired boiler is designed extended in the height direction as shown in (c). For

example, the width and height of its furnace are 1.2 times wider and 1.4 times higher, respectively, as

shown in (a) to (c).

Figure 3-17 Boiler Design Examples Depending on Type of Coal Used for

Coal-Fired Power Plant (660 MW)

(Source) Steam its generation and use, Edition:41, The Babcock & Willcox Company

What counts here is that the design differences among (a), (b) and (c) depend on the design requirements

on the part of the furnace, considering the combustion properties. Selection of the subcritical pressure,

supercritical pressure and ultra supercritical pressure boilers depends on the design of the boiler water feed

condition after a furnace layout has been decided. The boiler tube material and structure are reflected on

the design, adding the furnace structure and water feed conditions.

Generally, when designing the ultra supercritical pressure boiler, it is necessary to set the higher water feed

pressure and higher flow rate. On the contrary, since the tensile strength of the boiler tube has been

decided depending on the material, the pressure is designed with economic efficiency taken into account

without selecting the extremely high pressure. On the other hand, if the boiler volume increases because

of the conditions on the furnace side, so does a flow passage area, resulting in the lower mass velocity of

the boiler water. The lower mass velocity causes metal temperature rising on the surface of the boiler tube,

requiring design considerations. The large ultra supercritical pressure coal boilers have generally

employed a spiral structure having the slanted boiler tube, designing a tube internal flow rate at an

appropriate level. This is, however, effective for bituminous coal whose ash fusion temperature is high,

and not always suitable for lignite because the adhered ashes in the slanted boiler tube cannot be easily

removed. When the boiler tube is designed vertical, use of a rifled tube has been also developed, but the

manufactures are limited.

In view of the above, the ultra supercritical pressure boiler using the lignite requires the furnace to have a

high capacity based on the combustion condition, but on the other hand, it requires a high-pressure,

- 62 -

high-capacity water feed system which does not result in the lower mass velocity of the boiler feed water.

Given economic efficiency, it is awkward to say that this is the optimum boiler type. This type has few

track records and is technically possible. Given difficult handling of lignite combustion, etc., the

subcritical pressure boiler is usually chosen for low-grade coal worldwide.

On the contrary, the gasifier for the IGCC power plant consists of a standard gasifier and has less

custom-made design than the pulverized coal-fired boiler. A difference in combustion due to combustion

properties is controlled by adjusting an added amount of fluxant. When a required amount of gas increases,

it can be solved by installing multiple gasifier. Generally, the gasifier is deemed more applicable to

combustion of the low-grade coal than the pulverized coal-fired boiler.

Thirdly, there are various considerations for the facilities other than the volume issue when using the

low-grade coal. The most characteristic one of them is the need for an exclusive fuel supply facility.

Standard roller mills with bituminous coal are not available because of the coal properties. Since it

contains particularly high moisture, the exclusive fuel supply facility having the drying performance is

necessary when burning the lignite. The pulverized coal-fired boiler already has a proven track record, but

the high-performance models are marketed by limited manufacturers. In Japan, the gasifier currently

available for the IGCC power plant are only those using the bituminous coal and subbituminous coal, and

it is necessary to study construction of an exclusive fuel supply system having the drying performance.

Since it has already been manufactured for the pulverized coal-fired boiler, however, it is necessary to

study the design, but this issue can be solvable.

4) Qualitative comparison of the environmental aspect

Consider qualitatively the environmental performance based on the ultra supercritical boiler and the IGCC

power plant properties.

The environmental performance generally evaluates air quality, water quality, noise, vibrations and waste

materials as main items. Although the environmental and social aspects of the IGCC power plant are

considered in details in the next chapter, the following compares qualitatively the differences attributable

to the plant properties among the general matters in the environmental aspect of the plant performance.

a. Air quality

The air quality is evaluated based by diffusion of emission matters, types of emission matters and

emission amounts. The emission matters mainly attribute to the coal components, and the power

plant currently keeps running within the environmental criteria. Since the ground concentration

of each emission matter differs depending on the type of the selected gasifier, an emission

simulation should be conducted at detailed investigation time. Given that the IGCC power plant

generally has higher desulfurization performance than the current subcritical pressure boiler,

environmental degradation is prevented. Because the plant efficiency is improved in addition, an

exhaust gas emission amount is reduced by the difference of the plant efficiency, producing an

environment improvement effect, when the same power energy is generated. There is no sufficient

track record of the ultra supercritical pressure boiler which uses lignite equivalent to Mae Moh coal,

but when the supercritical pressure boiler is taken as an example, the typical values are assumed to

be SO2 = 100 ppm, NOx = 120 ppm, and PM = 50 mg/Nm3. On the other hand, the IGCC power

plant expects those values to be SO2 = 12 ppm, NOx = 50 ppm, and PM = 4.8 mg/Nm3 without

- 63 -

denitrification equipments; NOx will be 4.8 ppm if they are installed.

Namely, the IGCC power plant can reduce emission gas at least by the difference of the heat

efficiency with respect to the ultra supercritical pressure boiler, expecting to have great

improvement effects on evvironmental performance, although this is hypothetical.

b. Water quality

The water quality is affected by water intake and discharge. Water discharge is evaluated by

diffusion of emission matters, types of emission matters and emission amounts.

For water intake, an output ratio by the steam turbine accounts for one third to half of the output of

the IGCC power plant, and industrial water consumption is cut down by desulfurization on the

following wake side of the gasifier, thereby considerably reducing water consumption, compared

with the USC power plant of the same output. For water discharge, this project will install a waste

water treatment facility equivalent to or better than the existing one to converge drainage before

discharge it, thus preventing environmental degradation.

Namely, with lower water consumption and the waste water treatment facility equivalent to or

better than the existing one, the IGCC power plant is expected to have an environment

improvement effect on the ultra supercritical pressure boiler.

c. Noise

Main noise source facilities are a boiler draft fan and a water feed pump for the ultra supercritical

pressure boiler, and a gas turbine body, etc. for the IGCC power plant, respectively. Given that all

of them already have various proven operational track records and comply with the environmental

criteria all over the world, however, noise measures have been already established for both

proposed and alternative technologies.

d. Vibrations

As with noise, there is no vibration source peculiar to the ultra supercritical pressure boiler and

IGCC power plant, and vibration measures have already been established for both proposed and

alternative technologies.

e. Waste materials

Because of different coal ash removal techniques, the ultra supercritical pressure boiler and IGCC

power plant uses different coal ash discharge systems. There is no big difference between them

except for the coal ashes.

As with the subcritical pressure boiler, the ultra supercritical pressure boiler discharges clinker

(bottom ashes) from the bottom of the furnace and fly ashes from the rear flue of the boiler. On the

contrary, the IGCC power plant discharges glassy slag from the bottom of the gasifier. Glassy slag

is a solid substance of melted coal ashes and generally has a lower volume than when separately

removing the clinker and fly ashes; the volume is generally 30% to 50% lower in terms of relative

value, compared with the ultra supercritical pressure boiler. Solidified into a glass substance,

trace minerals are not eluted easily.

- 64 -

For recycling of the waste materials, part of fly ashes and part of gypsum discharged from the

desulfurization equipment are currently taken back as valuable substances to be continually

recycled such as using the clinker for backfill. The glassy slag is expected to be taken back as a

valuable substance as before to be used as a cement raw material, making no big difference in

terms of recycling.

5) Conclusion

Table 3-7 summarizes the above consideration results.

As a result of comparing the proposed technology, the IGCC power plant, and alternative technology, ultra

supercritical pressure boiler, it can be determined that the IGCC power plant is comprehensively more

suitable in the performance, technical and environmental aspects.

Particularly, given the current situation that the Mae Moh Thermal Power Plant has been doing different

kinds of things for its operation because of the varying coal quality resulting from a higher ratio of CaO in

the ash content, it is preferable to select the IGCC power plant suitable for the low-grade fuel.

Furthermore, the IGCC power plant is superior to the alternative technology in all the considerations of

the performance and environmental aspects, and the Japanese technologies are expected to make

significant contributions.

As shown in Table 3-7, these consideration results do not deny the pulverized coal-fired power plants

(subcritical pressure, supercritical pressure and ultra supercritical pressure boilers). Particularly, the

subcritical pressure boiler has been the standard type so far as the lignite-fired power plant and is a

possible option when emphasizing the elements except for the performance, technical and environmental

aspects. However, the lignite-fired ultra supercritical pressure boiler does not have a sufficient proven

track record, causes concerns about the occurrence of facility failures in future operation, having a slight

inherent risk.

- 65 -

Table 3-7 Comparison of Proposed and Alternative Technologies

IGCC

Subcritical pressure boiler (Base)

Ultra supercritical pressure boiler Oxygen blown method Air blown method

Main steam pressure (MPa)/ Main steam temperature (deg C)/

Reheat stem (deg C) 16.1/538/538 24.5/600/600 10.0/550/550 10.0/550/550

36.21% (Gross) 38.35% (Gross) 48.82% (Gross),

41.5% (Net) 49.06% (Gross),

43.4% (Net) Plant efficiency (HHV)

Base 5.91% improved (relative value)

34.82% improved (relative value)

35.49% improved (relative value)

Comparison of

performance aspect

Coal consumption (t/hour @ 425 MW)

337.5 318.6 250.3 240.0

Slagging properties High melting point preferred

for ash content High melting point preferred

for ash content Low melting point preferred for ash content

Boiler furnace / Gasifier design features

Base Larger capacity

Countermeasures for boiler water flow velocity required

Larger capacity With application characteristics for low-grade coal

Qualitative comparison of technical

aspect Fuel drying system

Exclusive lignite firing facility required

Exclusive lignite firing facility required

Consideration of exclusive facility required

Exhaust gas volume Base Approx. 6% reduced (relative

value) Approx. 35% reduced (relative value,)

Industrial water consumption Base Approx. 6% reduced (relative

value) Reduced, calculated by considering the details

because of difference depending on the facility type.

Noise Base No particular matter No particular matter

Vibrations Base No particular matter No particular matter

Qualitative comparison

of environment

al aspect

Waste materials Fly ashes, clinker Fly ashes, clinker Glassy slag (Lower volume, higher stability)

Overall evaluation Base Better Best


- 66 -

6) Track records of the SC/USC coal-fired power plants

The following tables list the track records of main Japanese and overseas SC/USC coal-fired power

plants.

Table 3-8 USC Coal-Fired Power Plants (Japan)

Company Unit Name Unit No.

Capacity (MW)

Steam condition (MPa/ Main steam deg C / RH steam deg C)

Start up year

Type of Coal

1 CEPCO Hekinan 3 700 24.1/ 538/ 593 1993 Bituminous

2 J Power Tachibanawa

n 1, 2 1,050 25.0/ 600/ 610 2000 Bituminous

3 CEPCO Hekinan 4, 5 1,000 24.1/ 566/ 593 2001 Bituminous

4 TEPCO Hitachinaka 1 1,000 24.5/ 600/ 600 2003 Bituminous

5 TEPCO Hirono 5 600 24.1/ 600/ 600 2004 Bituminous

6 J Power Isogo 2 600 24.5/ 600/ 620 2009 Bituminous

(Source) Preparatory Survey for Indramayu Coal-fired Power Plant Project in Indonesia, JICA

Table 3-9 SC/USC Coal-Fired Power Plants (Overseas)

Company Unit Name Unit No.

Capacity (MW)

Steam condition (MPa/ Main steam deg C / RH steam deg C)

Start up year

Type of Coal

1 Germany Schkopau

A&B 2 492 28.5/ 545/ 560 1996 Lignite

2 Germany Schw.

Pumpe A, B 2 800 26.4/ 542/ 560

1997- 1998

Lignite

3 Germany Lippendorf

R&S 2 934 26.7/ 554/ 583 1999 Lignite

4 Germany Boxberg Q 1 915 26.7/ 555/ 578 2000 Lignite

5 Germany Niederaussen 1 975 27.4/ 580/ 600 2003 Lignite

6 Canada Genesee 3 495 25.0/ 570/ 569 2005 Sub-bituminous

7 USA Walter Scott,

Jr. Energy Center

4 853 26.2/ 569/ 595 2007 Sub-bituminous

8 Germany Neurath

F&G 2 1,100 27.2/ 600/ 605 2010 Lignite

9 Canada Keep hills 3 495 25.0/ 570/ 569 2011 Sub-bituminous

10 Germany Boxberg R 1 670 - / 600/ 610 2011 Lignite

11 Indonesia Paiton III 1 815 25.8/ 542/ 568 2012 Sub-bituminous

(Source) Preparatory Survey for Indramayu Coal-fired Power Plant Project in Indonesia, JICA

- 67 -

(3) Overview of the Project

a) Basic policy for deciding the details of the project

Given the properties of the Mae Moh coal, the most suitable technology is the IGCC process as

mentioned above. There are two possible systems available for the gasification facilities which are the

main component facilities of the IGCC process; an oxygen-blown gasification system using high-purity

oxygen as an oxidant and an air-blown gasification system using the air as an oxidant. Of the coal-fired

IGCC plants currently running in the world, the oxygen-blown gasification system has been used at four

plants and the air-blown system at one plant, respectively. The Shell-process oxygen-blown plant has been

running in Buggenum, Holland since 1994 and the MHI-process air-blown plant has been running in

Nakoso, Japan since 2007. The purpose of this investigation is to consider the feasibility of the IGCC

project at the Mae Moh Power Plant in the environmental, social and economic aspects, not to compare

the gasification systems. For convenience sake, the following consideration centers around the

oxygen-blown gasification-based IGCC which has a richer construction record and longer operation

record. The air-blow gasification, a domestic technology, is considered with MHI’s cooperation.

Plant construction cost of US$1,400 million was calculated based on cost data, inquiry, and track record

data owned by Chiyoda Corporation. However, the plant construction cost will need to be considered in

more detail in subsequent investigation.

b) Conceptual design and specifications of the applicable facilities

1) Setting of the basic conditions

a. Design conditions

Table 3-10 shows the design conditions for performance calculation in this survey. The design

temperature and design relative humidity need to be carefully considered because they are greatly

related to generation output and serve as performance assurance points. In order to avoid hasty

consideration, this survey calculates the performance based on the general International

Organization for Standardization (ISO) conditions. Since the set design temperature conforms to

the lowest value of the average monthly minimum temperature, it is a reasonable value for

deciding the physical constitution of the power generator. As a matter of course, this item will be

decided in cooperation with the EGAT in detailed design, considering the past data.

Other data than the design temperature and design relative humidity are required for facility design,

but are simple meteorological data and have been reported as meteorological data as they are

because their values are not likely to change greatly.

b. Meteorological data

Tables 3-11 to 3-13 show the long-term meteorological data of the vicinity of the Mae Moh district,

the planned construction site of the thermal power plant; more specifically, 1981 to 2010 data of

the monitoring station No. 328201 in Lampang Province. The monitoring station is located on the

latitude 18.17.0 N and longitude 99.31.0 E, 48 km in the west-southwest of the Mae Moh Thermal

Power Plant.

- 68 -

Table 3-10 Design Conditions (For Performance Calculation in This Survey)

Item Design condition Remark

1 Design temperature 15 deg C ISO condition

2 Min. design temperature 15 deg C For calculation of generator

capacity 3 Atmospheric pressure 1.013 hPa ISO condition

4 Design relative humidity 60% ISO condition

5 Min./max. relative humidity 23%/95%

6 Cooling water temperature (inlet, outlet) 15 deg C /25 deg C Cooling tower system

7 Annual precipitation 1,049 mm

8 Max. daily precipitation 135.4 mm/day

9 Earthquake resistance standards Seismic Zone VI

10 Snow load 0 kg/m2

11 Calorific value 13.21 MJ/kg


Table 3-11 Temperature and Humidity in Vicinity of Mae Moh District (1981 to 2010)

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

1 Avg. temp. (deg C) 22.2 24.7 28.0 30.0 28.8 28.3 27.8 27.4 27.0 26.3 24.2 21.6

2 Avg. monthly max.

temp. (deg C) 31.6 34.4 37.2 38.3 35.5 34.0 33.3 33.0 32.8 32.3 31.3 30.2

3 Avg. monthly min.

temp. (deg C) 15.0 16.6 20.1 23.4 24.2 24.4 24.1 23.9 23.5 22.3 19.1 15.3

4 Avg. relative humidity (%)

70 62 57 60 72 76 78 81 83 82 78 75

5 Avg. monthly max.

humidity (%) 94 89 83 84 90 91 92 94 96 96 95 95

6 Avg. monthly min.

Humidity (%) 38 31 30 34 50 56 58 61 63 60 53 45

(Source) Climatological Data For Period 1981 - 2010, Index 48328, Station 328201-Lampang

Table 3-12 Precipitation in Vicinity of Mae Moh District (1981 to 2010)

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

1 Avg. precipitation

(mm) 3.2 9.4 22.8 65.9 160.4 117.5 134.6 186.3 211.6 98.3 31.6 7.8

2 Daily max.

precipitation (mm) 14.3 32.9 59.7 61.3 77.4 102.2 97.1 135.4 109.9 77.3 77.4 54.8


- 69 -

Table 3-13 Atmospheric Pressure in Vicinity of Mae Moh District (1981 to 2010)

Jan. Feb. Mar. Apr. May Jun.

Avg. atmospheric pressure hPa (Jan. to Jun.)

1,013.7 1,011.4 1,009.0 1,007.4 1,006.3 1,005.3

Jul. Aug. Sep. Oct. Nov. Dec.

Avg. atmospheric pressure hPa (Jul. to Dec.)

1,005.3 1,005.7 1,008.0 1,011.0 1,013.5 1,009.3


Figure 3-18 Temperature and Precipitation in Vicinity of Mae Moh District

0

5

10

15

20

25

30

35

40

45

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

Month

Degr

ee-C

0

50

100

150

200

250

mm

Rainfall(Ave.)

Temperature (Ave.)

Average Temperature (Monthly Max)

Average Temperature (Monthly Min)


c. Topography

The Mae Moh Thermal Power Plant is located adjacent to the Mae Moh Coal Mine. Since it has

been installed along with development of its coal mine, there are few restrictions on its property.

Namely, given only the topography, there are many candidate construction sites. One of the main

points of this study includes reduction of facility investment expenses by maximum reuse of the

existing facilities. A facility layout plan considering with this point is described later.

A prerequisite for earthquake-resistance design is Seismic Zone VI in terms of Mercalli intensity

scale, based on an internationally used national disability risk chart which was prepared by the UN

Office for the Coordination of Humanitarian Affairs. For a fundamental structure and a high-eave

building requiring earthquake-resistant performance, it must be reflected at the time of designing

the details.

The following table summarizes the survey results related to the foundation of the existing power

generation facilities as data accompanying the topography. The local power plant has detailed data

such as a pile layout drawing, etc. It is evaluated that the EGAT has sufficient technical capabilities to

- 70 -

evaluate the ground and lay out necessary foundation piles.

Table 3-14 Design Load of Foundation of Existing Mae Moh Thermal Power Plant

Pile

(35 cm in diameter) Pile

(50 cm in diameter) Pile

(90 cm in diameter)

1 Regular working load (t) 40 120 380

2 Max. working load (t) 50 150 475

3 Ultimate bearing capacity (t) 100 300 950


d. Fuel

The following describes the coal properties for the future plan of the Mae Moh Thermal Power

Plant. Mae Moh Coal Mine has been conducting a survey related to future coal mining by boring

investigation. By reflecting these survey results and adding the properties of coat to be produced in

the future to the currently used coal, the EGAT set the coal properties as follows for this survey.

They may be modified because of the future coal mining plan and coal blending plan.

Table 3-15 Coal Properties

Unit Average Max Min 1 Total Moisture (TM) %ar 32.65 35.71 28.13 2 Inherent Moisture (IM) %ad 19.71 24.75 15.47 3 Ash %ad 16.08 20.21 12.67 4 Volatile Matter (VM) %ad 34.13 38.49 17.88 5 Fixed Carbon (FC) %ad 30.08 48.33 22.52 6 Total Sulfur (TS) %ad 2.63 3.56 1.96 7 Hard Grove Grindability Index (HGI) - 57.15 75 45

Gross (ad) MJ/kg 17.53 19.25 15.90 Gross (ar) MJ/kg 14.70 15.67 13.55 Net (ar) MJ/kg 13.21 14.15 11.98

8 Calorific Value (CV)

Gross (daf) MJ/kg 27.30 28.08 26.46 Carbon %daf 73.09 85.66 64.18 Hydrogen %daf 3.37 7.03 1.79 Nitrogen %daf 2.25 3.27 0.76 Sulfur %daf 4.16 5.34 3.27

9 Ultimate Analysis

Oxygen %daf 17.13 27.31 4.59 10 Specific Gravity (SG) - 1.33 1.40 1.27

(Note) ar = as received basis, ad = air dry basis, daf = dry ash free basis (Source) EGAT

- 71 -

Table 3-16 Coal Ash Properties

Unit Average Max Min Silica %db 18.14 26.60 11.00

Alumina %db 8.78 11.94 5.46 Titania %db 0.15 0.22 0.05

Ferric Oxide %db 13.52 16.73 12.27 Calcium Oxide %db 28.07 35.15 22.03

Magnesia %db 3.53 5.40 2.50 Potassium Oxide %db 0.89 1.53 0.37 Sodium Oxide %db 1.89 3.07 1.25 Sulfur Oxide %db 23.14 30.38 10.27

1 Ash Analysis

(% wt)

Mangan Oxide %db 0.21 1.19 0.08 Initial default deg C 1253 1353 1129

Softening deg C 1285 1501 1153 Hemisphere deg C 1299 1501 1172

2 Ash Fusion Temperature

(AFT) Flow deg C 1347 1501 1195

(Note) db = dry basis (Source) EGAT

c) Details of the proposed project (oxygen-blown gasification)

1) Facility configuration

Figure 3-19 shows the facility configuration diagram of the coal-fired IGCC plant (500 MW class).

Figure 3-19 Facility Configuration Diagram of Coal-Fired IGCC Plant


- 72 -

The component facilities are detailed below.

a. Coal Gasification Unit

Coal Pretreating

Coal Feeding

Coal Gasification

Slag Removal

Dry Solid Removal

Wet Scrubbing

Primary WWT

b. Gas Clean-up Unit

COS Conversion/Raw Syngas Cooling

AGR (Acid Gas Removal)

SRU (Sulfur Recovery Unit)

c. Combined Cycle Unit

d. ASU (Air Separation Unit)

e. WWT (Waste Water Treatment)

2) Bases for selecting the main process facilities

The following describes the bases for selecting the coal pretreating unit, coal gasification unit, acid gas

removal unit, sulfur recovery unit, combined cycle unit and air separation unit which have many selective

options at each facility.

a. Coal pretreating unit

Selection process: WTA14 process

Since the water content of the Mae Moh coal is as high as 32%, its direct use for a gasifier is not

desirable, requiring a drying facility. A fluidized-bed drying process made by

Rheinisch-Westfalisches Elektrizitatswerk (RWE) was selected as the drying facility because of the

following reasons.

(1) Proven records of high-capacity coal dewatering treatment (dewatering rate 100 t/h.).

(2) An energy consumption rate is low because water vapor is made available for heating boiler

feed water.

(3) Recovered water is relative clean and made reusable by simple treatment because a drier is

operated at normal pressure and low temperature.

(4) Capable of dewater down to the specified supply value to a gasifier. The optimum

conditions, however, should be checked in the drying and fluidity tests at the time of detailed

design.

b. Coal gasification unit

Selected process: SCGP（Shell Coal Gasification Process）

14 WTA = German abbreviation standing for fluidized-bed drying with internal waste heat utilization

- 73 -

Table 3-17 shows the currently commercialized typical oxygen-blown gasification processes.

Table 3-17 Oxygen-Blown Gasification Processes in Operation

(1) (2) (3) (4)

Process licenser Shell Uhde GE ConocoPhillips

Plant Buggenum Puetollano Tampa Wabash River

Plant installed country Holland Spain United States United States

Coal supply system Dry feed Dry feed Wet feed Wet feed


If the raw coal supply systems are compared from a viewpoint of power generation efficiency, the

dry feed systems ((1), (2)) are superior to the wet feed systems15 ((3), (4)). Of the dry feed systems,

the Shell gasification process was selected because of its high availability of the running plant.

Since development of the Shell gasification process started in 1972, it has an operation track record

of 35 years or longer so far. The technological, operational and maintenance management aspects

have been continuously developed and improved by making effective use of the knowledge

obtained through the initial troubles experienced at the running plant, design faults, maintenance

and conservation problems, and their solutions.

Technological merits are as follows.

(1) A variety of gasifiable types of coals from a low to high melting point, including the lignite.

(2) High carbon conversion rate of 99% or more.

(3) High CO＋H2 concentration and low CO2 content in raw syngas because of dry supply.

(4) High gasification efficiency and low consumption of raw coal and oxygen.

(5) Easy expansion of the gasifier because of multiple opposed nozzles, allowing a wide

operating range and a long burner life.

(6) Stable quality of slag produced by high-temperature melting of ashes. Superior in

environmental conservation and available as a construction material because of almost no

leaching of components.

(7) Gasifier internally protected by a water-cooled membrane wall against high temperature

and covered with molten slag, requiring less maintenance expense .

As a reference material, it is reported in the Worldwide Gasification Database studied by U.S.

DOE (Department of Energy)/NETL (National Energy Technology Laboratory) in 2010 that the

15 Since the wet feed system supplies the coal to the gasifier in the form of slurry substance, it contains about 30% of moisture. A heating value is used to increase the moisture up to the internal temperature of the gasifier (1,500-1,600 deg C), resulting in lower efficiency. Since CO is converted into CO2 and H2 of zero heating value by aqueous gasification reaction, generation of CO2 becomes a factor of lower efficiency.

- 74 -

Shell gasification process has been most widely employed as shown in Figure 3-20 in comparison

of plant capabilities by licenser, scheduled to be constructed by 2030.

Figure 3-20 Construction Record and Prediction of Gasification Plants by Licenser

(Source) DOE/NTEL Gasification 2010 Worldwide Database

c. Acid gas removal unit

Selected process: Chemical absorption process using amine solution MDEA

(Methyldiethanolamine)

Acid gas (H2S, COS, CO2) removal processes include a chemical absorption process, physical

absorption process and physicochemical absorption process. The following describes the features

of each process.

Chemical absorption process

(1) Capable of reducing a solution circulation flow rate because of high solvent load (acid gas

absorption volume per absorbent solution unit volume) and high absorption speed.

(2) Higher energy required for regeneration than the physical absorption process.

(3) Capable of absorbing CO2 and H2S simultaneously and removing H2S selectively from a

gas containing CO2.

(4) Lower construction cost than the physical absorption process.

(5) Necessary to pay heed to corrosion of metal materials as an acid gas solution load becomes

higher.

(6) Deterioration of an absorbent solution caused by impurities in a process gas.

Physical absorption process

(1) As the partial pressure of the acid gas (CO2 + H2S) becomes higher, the solution load value

of the acid gas increases, allowing to lower an absorbent solution circulation rate. For the

- 75 -

partial pressure of the acid, 350 kPa or more is a guide for employing the physical absorption

process.

(2) Solubility of the acid gas becomes lower as the temperature increases. Lower temperature is

more advantageous for absorption. A refrigerator is required depending on the process.

(3) Lower thermal energy required for regeneration than chemical absorption.

(4) Less deterioration of the absorbent solution caused by impurities in the process gas.

(5) Complicated low-temperature process configuration, resulting in higher construction cost

than the chemical absorption process.

(6) More expensive absorbent solvent than the chemical absorption process.

To apply to the IGCC plant, the following is required as the process performance.

(1) In order to observe the regulation value of the SOx concentration in the gas turbine exhaust

gas, keep the H2S + COS concentration in the syngas within the specifications after removing

the acid gas.

(2) Absorb H2S selectively. (Since CO2 contributes to the enhanced output of the gas turbine, it

is important to recover more CO2 into the process gas.)

Placing a premium on a mild regulation value of SOx in the exhaust gas and construction cost

reduction, the chemical absorption process using the amine solution (MDEA) has been employed

in this investigation.

d. Sulfur recovery unit

Selection of various processes is conceivable as a sulfur recovery method depending on the end

product, but a gypsum production process was selected because a market has been already

established.

Selected process: CT-121 process (limestone and gypsum process)

The CT-121 process developed by Chiyoda Corporation has been employed as the gypsum

production process because it has a richer domestic and overseas construction record, high process

performance, etc. among the limestone and gypsum processes widely used for coal- and oil-fired

boiler exhaust gases. The following describes the features of the CT-121 process.

(1) High process performance by a superior gas-liquid contact system (jet bubbling system).

High desulfurization rate (99% or more).

High removal performance of harmful trace components in soot dust and gas.

The conventional spray system sprays the absorbent solution into the gas and desulfurizes by

contacting the gas with the liquid. On the contrary, the jet bubbling system jets the exhaust gas

into the absorbent solution to form a bubble layer, realizing high-efficiency gas-liquid contact.

- 76 -

(2) High reliability and simple, stable operation.

Simple mechanism by a simple control loop.

Flexible load following capability and low-load operation.

(3) Low construction cost and low maintenance/conservation cost

Small-scale slurry pump, flexible material selection and low JBR (Jet Bubbling

Reactor) tower.

(4) Low operation cost

Fewer operators, low power consumption, high limestone utilization rate and

large-particle-size gypsum crystal.

e. Combined cycle unit

Selected gas turbine (GT): M701F

A gas turbine made by MHI was selected; MHI has, as a gas turbine manufacturer, the richest

business results of the combustion devices for the low-calorie blast furnace gases which are the

by-products of the steel manufacturing plants, and has been positively addressing development

aiming at higher inlet temperature and higher efficiency of the gas turbines. It has an affluent track

record of shipping over 500 gas turbines in total. Of MHI’s models, this project selected a

high-efficiency gas turbine M701F running at the turbine inlet temperature of 1,400 deg C. Other

bases for selection are as follows.

(1) One gas turbine will do because of its high capacity, reducing the construction cost.

(2) The gas turbine, steam turbine and power generator are arranged on one axis to save a site

area.

(3) A combined cycle power generation output combined with the steam turbine is of 500 MW

class (on the gross basis), satisfying a basic design condition16.

f. Air separation unit (ASU)

GT-ASU air integration rate17: 30%

GT-ASU air integration at the IGCC plant leads to lower power consumption in the ASU,

effectively improving overall efficiency. On the other hand, operability is restricted because

variations of the power generation output leads to the ASU’s operational variations and it is

necessary to coordinate with the combined cycle side at the time of starting the unit.

As shown in Figure 3-21, full air integration (all the air supplied to the ASU is acquired from the

gas turbine compressor) is about 3 to 5% more efficient than no air integration (all the air supplied

to the ASU is acquired from the atmosphere). Although full air integration is superior in efficiency

like the Buggenum and Puertollano plants, it has been switched to partial air integration because of

the reasons such as no flexibility in operation, more time required for start-up. It is said that 25 to

16 Described in (1) Background and Necessity of Project, a) Scope of the project. 17 The air is supplied to the ASU in the three ways; (1) from the atmosphere through the air compressor installed in the ASU, (2) from the extraction air of the gas turbine compressor, and (3) from both of them. The air in (1) is not integrated, the air in (2) is fully integrated, and the air in (3) is partly integrated, indicating the ratios of the extraction air and atmosphere in terms of percentage.

- 77 -

50% partial air integration is adequate, considering efficiency and operability. This study has

employed 30% air integration, considering securement of easy operability and minimizing

variations in the unit, while placing a premium on overall efficiency.

Figure 3-21 Effects of GT-ASU Air Integration on Efficiency

(Source) Siemens:IChemE2009

3) Main facility specifications

a. Coal pretreating unit

The coal pretreating unit consists of the following facilities.

Coal drying and coarse crushing facility

Coal pulverizing facility

Basic design specifications

The coal pretreating unit has been considered based on the following basic design specifications.

Coal drying and coarse crushing facility: 100%18 x 1 unit

Moisture content in pulverized coal: 10% or less

Pulverized coal particle distribution: 90μm or less, 90%

Pulverizer: 50% x 2 units

Process description

Figure 3-22 shows RWE’s typical flow of the coal drying and coarse crushing facility.

18 The percentage values mentioned in each basic design specifications indicate the required capabilities of the facilities and devices.

- 78 -

Figure 3-22 Simple Flow of Coal Drying and Coarse Crushing Facility

(Source) RWE

The raw coal is supplied into a receiving bunker by a belt conveyor from outside the system. The

coal coarsely crushed by a hammer mill (raw lignite milling) is introduced into a fluidized-bed

drier. A steam coil is disposed at the bottom of the drier and the raw coal is dried by externally

supplied steam. The dried coarsely crushed coal is cooled by an air-contact cooler (dry lignite

cooler), and then, blended with fluxant19, and finely-powdered slag recycled from the gasification

facility and introduced into a roller mill (dry lignite milling) to be pulverized.

After removing a slight amount of dust contained in dewatered vapor by an electrostatic

precipitator, the dewatered vapor is utilized as a fluidizing medium for a fluidized-bed dryer and as

a heat supply medium for a vapor condenser.

A crushed particle size distribution and moisture content are greatly associated with the fluidity of

the coal supplied to the gasifier, and may require drying and fluidity tests in actual design.

b. Coal gasification unit

The coal gasification unit consists of the following facilities.

Coal feeding

Coal gasification

Slag removal

Dry solid removal

Wet scrubbing

Primary WWT

19 Necessity of fluxant is determined by fluidity of ashes in the gasifier and from a viewpoint of securing an enough amount of ashes to coat and protect the internal membrane wall of the gasifier. The Mae Moh coal, however, has a problem with fluidity of ash content because it has high CaO content and low Si2O3 and Al2O3 contents. Fluxant is added in order to improve the fluidity.

- 79 -


The coal gasification unit has been considered based on the following basic design specifications.

Coal feeding: 60% x 2 strings

Gasifier: 100% x 1 unit

Dry solid removal: 60% x 2 strings

Soot dust concentration in syngas: 1mg/Nm3

Process description

Figure 3-23 shows a typical Shell gasification process flow.

Figure 3-23 Simple Shell Gasification Process Flow

(Source) Shell Global Solutions

<Coal feeding>

A high-safety lock hopper system has been employed, which has a good track record of coal

pressurization and feeding. Nitrogen from the air separation unit is used as a pressurization and

feeding medium. Composed of a low-pressure pulverized coal hopper, high-pressure pulverized

coal hopper, high-pressure coal feeding hopper and gate valve, the lock hopper system is

controlled by a sequence program to automatically receives, pressurizes and feeds the coal in

series.

<Coal gasification>

The coal supplied into the gasifier is partially oxidized under the existence of oxygen and steam to

generate a raw syngas mainly composed of H2 and CO. Since a reaction in the gasifier is

performed under high temperature, a carbon conversion ratio 20 becomes 99% or more.

Hydrocarbon in the raw syngas contains only a slight methane fraction and does not generate any

other heavy fraction. The generated raw syngas is cooled by a recycled syngas circulated by a

20 Carbon conversion ratio = (Carbon content in the syngas)/(Carbon content in the coal supplied to the gasifier)

- 80 -

recycling compressor at the outlet of the gasifier, and then, thermally recovered by a syngas cooler

as high-pressure steam (HPS) and medium-pressure steam (MPS).

Since the inside of the gasifier is protected by the membrane wall composed of water tubes and the

tube surface is covered with molten slag film, there is less heat loss, resulting in high gasifier cold

gas efficiency21.

<Slag removal>

Although it depends on the ash content in the coal or an added ash amount, about 50 to 80% of the

mineral content such as silica, alumina, iron, calcium, etc. are discharged as molten slag from the

gasifier. In order to assure smooth discharge, the gasifier is operated at the temperature higher than

an ash melting point. After water-cooled in a slag water cooling tank and pulverized by a slag

crusher, the molten slag is depressurized and separated from water in a slag water sealing tank, and

fed out of the system by a slag drag conveyor and slag conveyor. The molten slag is non-leachable

(glassy substance not leaching outside) and handled as a non-dangerous object.

<Dry solid removal>

In order to lower soot dust concentration in the raw syngas at the gasification outlet, a

high-pressure high-temperature filter is installed to remove soot dust contained in the gas as fly ash.

According to the Buggenum plant’s track record, 99.9% have been removed.

The fly ash recovered by the filter is depressurized and cooled by the lock hopper system, and then,

conveyed outside the system. Since the dried fly ash has low carbon content, it is available as a raw

material for cement and ceramics.

<Wet scrubbing>

Composed of a venturi scrubber22、and first rinsing tower, this facility removes the ashes, unburnt

carbon content, and aqueous chlorine and ammonia accompanying the raw syngas. Although the

rinsing tower uses water cyclically, low pH concentration causes problems such as corrosion of

piping. To avoid this, it is necessary to inject caustic soda to keep the pH concentration almost

neutral.

<Primary waste water treatment>

The circulation water partly extracted from the first rinsing tower water circulation line of the wet

scrubbing unit and part of filtrate separated by a clarifier23 are supplied to a sour slurry stripper to

remove dissolved acid gas and ammonia. Part of the filtrate separated by the clarifier is used by the

coal gasification unit as recycled water and the remaining water is fed to the waste water treatment

unit.

Slag slurry supplied from a slag dewatering tank is condensed by the clarifier and a thickener24

and dewatered by a vacuum belt filter. Then, slag is fed out to a coal yard. 21 Gasifier cold gas efficiency = (LHV of H2 + CO in the syngas)/(LHV of the coal supplied to the gasifier) 22 Equipment designed to rinse away the impurities contained in the gas. 23 Equipment designed for solid-liquid separation from solid contained slurry by gravitational sedimentation. It is intended for obtaining the filtrate.

- 81 -

c. Gas clean-up unit

The gas clean-up unit consists of the following facilities.

COS conversion/raw syngas cooling

Acid gas removal


The gas clean-up unit has been considered based on the following basic design specifications.

H2S + COS concentration in the gas after removing the acid gas: 100 ppmv or less

CO2 recovery from the supplied raw syngas should be inhibited to increase gas turbine

output.

Process description

<COS conversion/raw syngas cooling>

The raw syngas from the wet scrubbing unit is heated by a COS converter gas/gas heat exchanger

and COS converter inlet gas preheater so that it will be in the optimum temperature range of the

COS converter. At the COS converter, carbonyl sulfide (COS) and Hydrogen cyanide (HCN) are

converted into H2S and NH3 by hydrolysis reaction. The raw syngas from the COS converter is

cooled by the COS converter gas/gas heat exchanger and a second rinsing tower inlet gas cooler.

Then, the second rinsing tower removes components such as NH3, halogen, etc. which can cause

corrosion to the downstream facilities.

<Acid gas removal>

Figure 3-24 shows a typical acid gas removal process flow.

Figure 3-24 Simple Acid Gas Removal Process Flow


The raw syngas (sour gas) from the second rinsing tower is introduced into an absorber, brought

into countercurrent contact with a lean amine solution (lean solvent), thus removing H2S. Given a

H2S recovery rate and H2S selectivity (CO2 non-selectivity), the amine solution based on MDEA

24 Equipment intended for obtaining condensed slurry.

- 82 -

(Methyl diethanol amine) is used as an absorbent.

The purified gas from the top of the absorber is warmed up by the heat exchanger, etc. in the raw

syngas cooling process, and then, fed to the combined cycle unit. An H2S-rich amine solution

(rich solvent) is heat-exchanged with a regenerator’s bottom liquid and warmed up at an absorbent

heat exchanger. Then, it is fed to the regenerator, and an acid gas containing H2S is recovered from

the top of the regenerator. The H2S removed lean solution is cooled by the absorbent heat

exchanger and an absorbent cooler, and then, recycled to the absorber.

The acid gas recovered by the regenerator is introduced into the sulfur recovery unit where its

sulfur content is recovered as gypsum.

d. Sulfur recovery unit

The sulfur recovery unit has been considered from a viewpoint of gypsum production as an

application of sulfur products.


Sulfur recovery rate: 95% or more

Process description

<Regenerated exhaust gas treatment/exhaust gas denitrification>

The acid gas from the gas clean-up unit is introduced into a regenerated exhaust gasifier and

combusted together with the vent gas from the gas clean-up unit, waste water treatment unit and

coal gasification unit lines. After cooled by a regenerated exhaust gas combustion cooler, the

combusted exhaust gas is led to an exhaust gas denitrifier where an NOx component is resolved.

The outlet temperature of the regenerated exhaust gas combustion cooler is designed not to cause

blockage or adhesion of acid ammonium sulfate, etc. in the subsequent exhaust gas denitrifier,

ensuring prevention of an exhaust gas drift and uniform spray of NH3.

<Exhaust gas cooling, SO3 mist removal>

The exhaust gas from the regenerated exhaust gasifier is partly diluted by the air, and then,

introduced into a cooler where it is humidified and cooled to the saturation temperature by makeup

water (industrial water) and a cooler circulation liquid, and SO3 is condensed and removed. The

cooler circulation liquid is partly brought into contact with an NH3 vent gas in a cooler extraction

pit, and then, fed to the absorber.

<Desulfurization and crystallization>

The exhaust gas from the cooler is introduced into the Jet Bubbling Reactor (JBR) where it is

blown out at high speed into a liquid from a sparger pipe provided with many small-diameter

outlets to form an enormous gas-liquid contact interface and a bubble layer (froth layer) having a

microscopic particle collecting function by diffusion, removing a SO2 gas, microscopic SO3 mist,

etc. efficiently and stably even under the exhaust gas condition with high SO2 and SO3

concentrations. The absorbed sulfite gas is instantaneously oxidized into almost sulfuric acid in the

bubble layer of the JBR by oxygen in the exhaust gas and the air blown in from an oxidizing air

blower, inhibiting generation of sulfite gypsum, which is a factor for contamination and lower

- 83 -

gypsum purity, by maintaining remaining sulfite at a low level. This sulfuric acid is neutralized by

limestone powder supplied by a limestone slurry pump, generating high-grade high-dewaterability

gypsum as a by-product under the condition that there is a sufficient retention time, small seed

crystals to be added to induce crystallization, and no crushing by a large circulation pump. The

generated gypsum is fed to a centrifugal separator by an absorber extraction pump.

Since the JBR operation parameter, pH and liquid submergence are automatically controlled by

feed forward signal for a cooler inlet volume, they require no operation for inlet condition changes

due to modifications of the type of coal, etc. and are always controlled at an optimum point,

conserving the energy.

After removal of accompanying airborn droplets (mist) and pressure increase by a mist eliminator,

the desulfurized exhaust gas is discharged from a chimney.

< Gypsum separation>

The gypsum slurry extracted by the absorber bleed pump is fed to a gypsum vacuum belf filter.

The gypsum dewatered by the gypsum vacuum belt filter and containing about 10wt% adhered

moisture is stored in a gypsum storage. The filtrate water is stored in a filtrate pit. Then, it is partly

fed to a limestone slurry pit by a filtratepump and the remainder is fed to the JBR.

e. Combined cycle unit


Integration with other facilities is emphasized, considering higher power generation output, higher

efficiency, enhanced energy conservation and lower construction cost.

The combined cycle unit has been considered based on the following basic design specifications.

Gas turbine: 100% x 1 unit (M701F)

Exhaust heat recovery boiler: 100% x 1 unit (reheat multi-pressure natural

circulation boiler)

Steam turbine: 100% x 1 unit (two-cylinder double flow exhaust

reheat condensing type)

Outlet NOx concentration: 10 ppmv or less at 15% O225, dry (with a denitrifier)

Figure 3-25 shows integration between the combined cycle unit and other facilities.

25 Equivalent at a specific concentration (15%), not an oxygen concentration in an actual gas, in order to correctly assess an NOx/SOx concentration.

- 84 -

Figure 3-25 Integration between Combined Cycle Unit and Other Facilities


Process description

The treated syngas with H2S removed to a predetermined concentration by the acid gas removal

unit (gas clean-up unit) is supplied to the gas turbine after temperature rise. Nitrogen is introduced

into a gas turbine combustor from the air separation unit to reduce NOx in the gas turbine outlet

gas and increase the power generation output. The gas turbine outlet gas is thermally recovered by

an HRSG (Heat Recovery Stem Generator) and discharged into the atmosphere from the stack.

The HRSG includes a high-pressure steam heater, high-pressure steam evaporator, high-pressure

boiler feed water economizer, medium-pressure steam heater, medium-pressure steam evaporator,

feed water heater (economizer) and reheat exchanger for the steam turbine to effectively recover

the heat.

A denitrification facility is additionally installed for reducing NOx. The air partly extracted from

the gas turbine’s air compressor (GT extracted air) is fed to the air separation unit. The

high-pressure and medium-pressure steam produced at the syngas cooler is fed to the steam turbine

together with the steam produced at the HRSG to generate the power. The medium-pressure steam

extracted from the steam turbine is reheated at the HRSG to increase the output. A condensate is

cooled at a condenser for cyclical use.

f. Air separation unit (ASU)


ASU-GT integration has been put into practice for higher efficiency, higher output of the gas

turbine and NOx reduction.

The air separation unit has been considered based on the following basic design specifications.

Air separation unit: 100% x 1 unit (cryogenic distillation method)

Product oxygen: Oxygen concentration 95 vol%

- 85 -

Product nitrogen: Nitrogen concentration 99.8 vol%, Oxygen

concentration 100 volppm or less

GT-ASU integration ratio: 30%

(The 30% of oxygen required for the gasifier is introduced from the gas turbine’s air

compressor.)

Nitrogen is supplied to the gas turbine maximumly in order to enhance the output.

Process description

Figure 3-26 shows a typical air separation unit process flow.

After dust and impurities are removed by an air filter, the raw air is pressurized by the air

compressor and supplied to a spray cooler. The 2-stage spray cooler cools the raw air by bringing it

into countercurrent contact with circulation cooling water (lower tower) and chiller water (upper

tower) as well as clears it of dust and water-soluble impurities, and then, introduces it into an MS

adsorber filled with a molecular sieve.

The MS adsorber has two towers which are switchably operated. While one of the towers is

adsorbing, the other one is desorbing. After moisture and carbon dioxide are adsorbed and

removed by the MS adsorber, the air is branched into two streams. The main stream is introduced

into an air separator (cold box), cooled by heat exchange with product oxygen and nitrogen at the

main heat exchanger, and introduced into the high-pressure lower tower. The other stream is

pressurized by an expansion turbine and supplied to the low-pressure upper tower through the

subsequent cooling and depressurization processes.

The expansion turbine generates the cold heat to make up for heat losses in the system. At the

lower tower, high-purity nitrogen is extracted from its top and an oxygen-rich liquid from its

bottom and fed to the upper tower, respectively. At the upper tower, high-purity nitrogen is

extracted from its top and high-purity oxygen from its bottom, respectively. After warmed up by

the main heat exchanger, they are pressurized to predetermined pressures by the compressor,

respectively, and the oxygen is fed to the coal gasification, nitrogen is used as a regenerated gas for

the MS adsorber, and the remaining gas is used as a dilution gas for the gas turbine and a coal

feeding gas.

- 86 -

Figure 3-26 Simple Air Separation Unit Process Flow

(Source) Brochure of Taiyo Nippon Sanso

g. Waste water treatment unit


The waste water treatment unit is intended to treat process waste water discharged from the coal

gasification plant to lower than effluent standard.

Process description

The primary waste water discharged from the coal gasification unit and the rinsing tower waste

water discharged from the gas clean-up unit are treated by each process described below. Figure

3-27 shows a block flow of the waste water treatment unit.

<Free cyanide removal>

The waste water from the coal gasification unit is pH-adjusted to acidity and introduced into a

hydrogen cyanide removal tank where hydrogen cyanide in the waste water is diffused and

removed by aeration. The diffused exhaust gas is combusted and resolved at a regenerated exhaust

gas treatment furnace, and the treated waste water is fed to the ammonia removal process.

<Ammonia removal>

After the free cyanide removal process, the waste water pH-adjusted to alkalinity is heated and

introduced into a stripper where ammonia in the waste water is diffused and removed. The diffused

exhaust gas is used as reducing ammonia for the denitrification device of the sulfur recovery unit.

The treated waste water is mixed with the individually treated rinsing tower waste water from the

- 87 -

gas clean-up unit and fed to the fluoride removal process.

Figure 3-27 Waste Water Treatment Unit Block Flow

To Sulfur Recovery Unit

Waste water from Gasification Unit

Waste water from Gas cleanup unit

Waste water treated

Free cyanide Removal

Ammonia Removal

Ammonia Removal

Heavy metals/ Fluoride Removal

Calcium Removal

Organics Removal

Cyano complex Removal

SS・COD Removal

To Sulfur Recovery Unit

Waste water from Gasification Unit

Waste water from Gas cleanup unit

Waste water treated

Free cyanide Removal

Ammonia Removal

Ammonia Removal

Heavy metals/ Fluoride Removal

Calcium Removal

Organics Removal

Cyano complex Removal

SS・COD Removal


<Heavy metal and fluoride removal>

After the ammonia removal process, fluoroboric acid (BF4), a persistent fluoride, and free fluorides

are removed through a two-step process by Chiyoda Ca-Al method. In the first step, the waste

water is pH-adjusted to acidity, BF4 is resolved by returning and dissolving aluminum hydroxide

sludge generated in the second step, and then, free fluorides are adsorbed and removed by

aluminum hydroxide which has been coagulated and generated by adding calcium hydroxide.

After adding calcium hydroxide, the generated sludge is fed to the filter press.

In the second step, the waste water is pH-adjusted to acidity again, added with aluminum chloride

to resolve BF4, pH-adjusted to alkalinity to generate aluminum hydroxide sludge, thus adsorbing

and removing free fluorides. The generated sludge is returned to the first step to reduce aluminum

chloride consumption. Coagulation removes heavy metals and n-hexane extracts as well as

fluorides.

<Calcium removal (softening)>

After fluoride removal, sodium carbonate is added in alkalinity to remove calcium ions as calcium

carbonate in order to prevent calcium scaling in subsequent biological treatment. The treated waste

water is fed to the biological treatment process.

<Organic removal>

After fluoride removal, the treated waste water is pH-adjusted and put through four-step treatment,

namely organic removal, nitrification, denitrification and aftertreatment using Chiyoda original

technologies, Biofiner (organic removal) and Biofiner N-method (nitrification and denitrification).

- 88 -

In the first step, organics centering around formic acid are removed by supplying oxygen by

aeration from the lower part of the reactor by a fixed bed holding microbes in a hollow cylindrical

carrier.

In the second step, NH3 is oxidized to NO2 and NO3 by supplying oxygen by aeration from the

lower part of the reactor by the fixed bed holding nitrification bacteria in the hollow cylindrical

carrier.

In the third step, NO2 and NO3 are reduced to N2 under the anaerobic conditions by a fluidized bed,

holding denitrification bacteria in a granular carrier.

In the fourth step, the organics slightly excessively added in the third process are removed by

aeration again to further enhance treatment efficiency, and solid-liquid separation is performed by

coagulation.

Because of the carrier’s excellent capability of holding microbes, Biofiner features a miniaturized

reactor and less sludge generation owing to promoted self-digestion.

After the fourth step, the treated waste water is fed to the residual cyano complex removal process.

<Cyano complex removal>

After the organic removal process, residual cyanogen (cyanogen complex and free cyanides) are

removed by the Prussian blue method. The waste water treated in the residual cyanogen removal

process is fed to the SS/COD removal process.

<SS/COD removal>

(1) SS (Suspended Solids) removal

The suspended solids carried over from the organic removal process are removed by a filter. With

the 2-layer filtration method, the filter includes anthracite with low specific gravity and large grain

size in the upper part and filter sand with high specific gravity and small grain size in the lower part

as filter media, and its sterical filtration allows a compact design. It is backwashed daily and

backwash waste water is returned to a backwash waste water tank. The waste water treated by the

filter is fed to an activated carbon adsorber.

(2) COD (Chemical Oxygen Demand) removal

The activated carbon adsorber adsorbes and removes organic COD. It is backwashed daily and

backwash waste water is returned to the backwash waste water tank. The waste water treated by

the activated carbon adsorber is fed to a waste water tank.

4) Plant operation

a. Power generation performance

Gross output: 500 MW

Net output: 425 MW

Internal power consumption: 75 MW

- 89 -

- Coal pretreating unit: 3.9 MW

- Coal gasification unit: 1.5 MW

- Gas clean-up unit: 5.7 MW

- Combined cycle unit: 5.1 MW

- Air separation unit: 53.1 MW

- Other common facilities: 5.7 MW

Overall efficiency (net, HHV basis): 41.5%

b. Process performance

Figure 3-28 Block Flow Chart


(1) Incoming coal volume (moisture content 32.65 wt%): 250.3ton/h

(2) Fluxant（Kaoline clay）: 17.8ton/h

(3) Gasifier oxygen supply volume (oxygen purity 95 vol%): 115.5ton/h

(4) Gasifier raw syngas volume (on the dry basis): 279.6ton/h

Composition (on the dry basis, vol%)

- H2: 19.4

- CO: 65.5

- CO2: 3.2

- N2: 10.0

- Ar: 0.5

- H2S & COS: 1.4

<By-product production volumes>

(5) Product gypsum (moisture content 10 wt%): 33.3ton/h

(6) Slag: 38.8ton/h

(7) Fly ash: 12.2ton/d

- 90 -

c. Environmental performance

“Exhaust gas”

Flow rate (on the dry basis): 2,040,000Nm3/h

Exhaust gas pr operties:

- NOx: 6.0ppmV (15％O2)

14.0ppmV (7% O2)

- SOx: 12.0ppmV (15％O2)

28.0ppmV (7% O2)

- Particulate: 4.8mg/Nm3

“Waste water”

Flow rate: 45m3/h

Composition:

- pH: 5.5 to 9

- SS: < 20mg/l

- Cyanide: < 0.2mg/l

- Heavy metals

Cr (Hexavalent): < 0.25mg/l

Cr (Trivalent): < 0.75mg/l

Cu: < 2.0mg/l

Hg: < 0.005mg/l

- Fat, Oil and Grease: < 5mg/l

- TKN: < 50mg/l

- Total-F: < 15mg/l

- BOD: < 20mg/l

- CODCr: < 120mg/l

- Should be lower than effluent standard for the other items as well.

d. Utility and chemical consumptions

The following describes the consumptions of utilities and chemicals at the IGCC plant.

“Utility consumptions”

Low-pressure steam (0.5 MPag): 95ton/h

Circulation cooling water (Δ = 10°C): 34,500ton/h

Boiler feed water: 51ton/h

Industrial water: 570ton/h

“Chemical consumptions”

Caustic soda (20 wt% aqueous solution): 4ton/d

Hydrochloric acid (15 wt% aqueous solution): 2ton/d

Limestone: 17.8ton/h

- 91 -

5) Plant layout planning

a. Plant layout drawing

The required area of the coal-fired IGCC plant is 350 m x 130 m (45,500m2). Figure3-29 shows

the layout of each facility.

Figure 3-29 Plant Layout Drawing


b. Bases for layout planning

The facilities are laid out most functionally and economically so as to minimize the following

large-diameter piping distances connecting each facility (function) block. The combustible gas

(raw syngas and treated syngas) piping and toxic gas (H2S) piping are shortened for safety.

(1) Minimum raw syngas and treated syngas piping distances among the coal gasification unit, gas

clean-up unit and combined cycle unit (gas turbine).

(2) Minimum oxygen supply piping distance between the coal gasification unit and air separation

unit.

(3) Minimum steam piping distance between the coal gasification unit and combined cycle unit

(HRSG).

Turbine compressed air piping, ASU-generated O2/N2 piping, coal pressure-feed piping,

gasification syngas piping and steam piping are assumed to be large-diameter piping.

6) Challenges and solutions in employing the proposed technology and system

a. Availability

As shown in the track record publicized at a Gasification Conference, one of the challenges of the

coal-fired IGCC plant is low availability.

a-1. Availability track record

(1) Buggenum plant: 80% (track record of 2009), on the syngas independent operation basis.

85% or more (track record of 2009), on the syngas and aux. fuel

combined operation basis.

- 92 -

(2) Wabash River plant: 70 to 80％ (track record of 2007 to 2008), on the syngas independent

operation basis.

77% (track record of Jan. to Sep. 2009), on the syngas independent

operation basis.

(3) Tampa plant: 80% (track record of 2004), on the syngas and aux. fuel combined

operation basis.

(4) Puertollano plant: 73% (track record of 2009), on the syngas independent operation basis.

Availability refers to a value obtained by dividing running hours by annual hours.

Major troubles of the four operating plants are as follows.

Blockage of the syngas cooler

Blockage of the wet scrubbing tower tray.

Erosion of the generated raw syngas piping of the gasifier.

Damage on the bearing of the ASU air compressor.

Leakage due to cracked syngas cooler.

Motor trip due to the overloaded slurry supply pump.

Wear of the slurry supply mixer.

Transport trouble of the char transport system.

Early damage on the gasifier internal firebricks.

Damage on the ceramic filter by vibrations.

Combustion vibrations of the gas turbine combustor.

Blockage in the ASU due to frozen moisture.

a-2. Solution

The above-mentioned four plants were designed in the 1990s and have been enhanced on annual

operating hours through many improvements. Recently, many experiences have been learned

mainly from a gasification plant operating in China, and it is expected to enhance availability by

reflecting those experiences on a new plant.

On the other hand, further enhancement of availability can be expected by utilizing an auxiliary

fuel as a backup and introducing an RAM (Reliability, Availability, Maintainability) analysis to

consider how to install spare string and equipment.

b. Construction cost

b-1. Comparison of the IGCC construction cost with other power generation technologies.

The estimated IGCC construction cost publicized by the U.S. Electric Power Research Institute

(EPRI) as of 2015 (on the Gulf Coast basis) is higher than other power generation technologies as

shown below.

- 93 -

Table 3-18 Estimated Construction Cost of Power Generation Facilities

Power Generation Technologies Construction Cost (US$/kW)

Coal: IGCC 2,600-2,850

Coal: PC 2,000-2,300

Natural Gas: NGCC 1,060-1,150

(Source) EPRI, Gasification Technologies Conference, 2011

b-2. Solution

Process licensers and equipment manufactures having gasification related technologies have been

aggressively addressing technological development toward cost reduction. Coal-fired IGCC is the

most promising technology for future cost reduction. When particularly combined with the Carbon

Capture and Storage (CCS) technology which takes a future global warming issue into account,

The EPRI report in Table 3-19 shows that the coal-fired IGCC will be comparable or rather

superior to other power generation technologies in terms of economic efficiency.

Table 3-19 Comparison of Plant Cost and Electricity Unit Price of Power Generation Facilities

Power Generation Technologies Total Plant Cost (US$/kW) Cost of Electricity (US$/MWh)

Coal: IGCC with CCS 3,100-3,800 85-101

Coal: PC with CCS 3,200-4,100 87-105

Natural Gas: NGCC 1,600-1,900 68-109


In estimating an electricity unit price, the coal and natural gas prices are assumed to be US$1.8 to

2.0/MMBtu and US$4 to 8/MMBtu, respectively.

Figure 3-30 shows effective technological development items for future reduction of the

construction cost and their extents of contribution, indicating a possibility of 46% reduction of

electricity unit price.

- 94 -

Figure 3-30 Improvement of Electricity Cost


The following lists main technological development items.

Coal pretreatment and feed system

Oxygen separation process

High-temperature high-pressure sulfur removal and recovery

Hydrogen membrane separation

Up-to-date CO2 removal technology

Up-to-date CO2 purification and pressurization system

Application of remodeled gas turbines

c. Facility configuration

c-1. Combination with a power generation plant and a chemical plant

The IGCC is the technology efficiently combining a power generation plant and a chemical plant.

The coal gasification unit, gas clean-up unit and air separation unit equivalent to the chemical

plants are new to the operators of the Mae Moh Power Plant, who are familiar with operating the

power generation plant. Because they are experienced in operation of a flue-gas desulfurization

facility which is a chemical plant, however, it is believed that they do not have strong resistance to

introduction of the IGCC plant.

c-2. Solution

For technological introduction, it is believed that operation maintenance problems can be reduced

by going through training provided by a gasification process licenser, using an actual plant, process

simulator, etc., and receiving various services such as a technical guidance, operational guidance

and maintenance/conservation management guidance after introduction.

- 95 -

d) Details of the proposed project (air-blown gasification)

1) Major Equipment Specification

Table 3-20 Major Equipment Specification

General

- Plant Configuration One (1) MHI air-blown, two stage entrained bed gasification train

- Installation Outdoor

- Turndown Capability Approximately 60% of gasifier heat input (roughly corresponds to 50% of power output)

- Main Fuel Mae Moh Coal

- Auxiliary. Fuels Natural Gas for start-up fuel of Gasifier & Gas turbine is assumed.

- Design Life 20 years is assumed.

Gasification System

- Gasifier 1 x 100%, Mitsubishi Air Blown Dry-Feed Entrained Bed, Membrane Waterwall, Two (2)-Stage Gasification

- Syngas Cooler (SGC) 1 x 100%, Sub Critical Drum Type , Forced Circulation

Pulverized Coal Feeding System

- Pulverized Coal Feeding System 1 x 100%, Lock Hopper System for one(1) Gasifier

Char Feeding Recovery System

- Char Cyclone 1 x 100%, Char Cyclone for one(1) Gasifier

- Porous Filter 4 x 25%, Porous Filter for one(1) Gasifier

- Char Feeding System 1 x 100%, Lock Hopper System for one(1) Gasifier

Slag Disposal System

- Slag Crusher in Pressure Vessel 1 x 100%, Hydraulically Driven Pinch Crusher for one(1) Gasifier

- Slag Lock Hopper 1 x 100%, Cylinder and Cone for one(1) Gasifier

Air Separation Unit (ASU)

- Air Separation Unit 1 x 100%, Cryogenic Air Separation

Gas Clean-up System

- Low Temperature Gas Cooling Unit (LTGC)

1 x 100%, Equips with scrubber, COS hydrosis and NH3 wash

- Acid Gas Removal Unit (AGR) 1 x 100%, Chemical Solvent absorption (MDEA) is assumed.

- Sulfur Recovery Unit (SRU) 1 x 100%, Gypsum Recovery is assumed.

Combined Cycle Power Block

- Combustion Turbine 1 x 100%, M701F type

- Heat Recovery Steam Generator 1 x 100%, Two pressure level steam cycle design with a natural circulation configuration

- Steam Turbine 1 x 100%, Tandem compound reheat turbine

(Note 1) For the capacity of equipment and/or facility, 100% means the required capacity for one (1) gasifier, except when specified otherwise.

(Note 2) Natural Gas is presently considered as start-up fuel of Gasifier and Gas turbine. (Source) MHI

- 96 -

2) Process Configuration of Air-blown IGCC

a. Simplified Process Flow of Air-blown IGCC

Figure 3-31 Process Flow of Air-blown IGCC

Gasifier & Syngas Cooler

Coal Bunker &

Coal Grinding

Coal Handling

Slag Handling

Water Treatment

LTGC &AGR

Sulfur Recovery

Sulfur Handling

Gas Turbine

HRSG & SCR

Steam Turbine

Condenser

Cooling Tower

Switch Yard

AirCompressor

Raw Water

Effluent

Generator

Stack

ASU

Owner

Mitsubishi (&Partner)

MHI(&Partner)Scope of Supply

Gasifier & Syngas Cooler

Coal Bunker &

Coal Grinding

Coal Handling

Slag Handling

Water Treatment

LTGC &AGR

Sulfur Recovery

Sulfur Handling

Gas Turbine

HRSG & SCR

Steam Turbine

Condenser

Cooling Tower

Switch Yard

AirCompressor

Raw Water

Effluent

Generator

Stack

ASU

Owner

Mitsubishi (&Partner)

MHI(&Partner)Scope of Supply

(Source) MHI

b. Plant Description

b-1. Gasification Plant

MHI Gasifier

The MHI gasifier uses a dry feed design that avoids the need for mixing the pulverized coal

feedstock with water as would otherwise be required by slurry transport designs. The MHI

air-blown system also reduces the auxiliary power that would otherwise be consumed by a

full-sized ASU required for oxygen-blown gasifiers and the high investment cost that goes with

those larger ASU-based configurations.

Since the nitrogen in the air (gasification agent) lowers the combustion gas temperature in the

gasifier, special attention is required to ensure both the proper discharge of molten ash and

maintaining a sufficiently high heat content in the syngas for stable burner operation in the gas

turbine.

MHI has adopted a two-stage gasification process as an effective solution to these issues. MHI’s

gasifier design features an up-flow two-stage configuration that consists of two chambers: a lower

combustor chamber and an upper reductor chamber.

A description of the major features of this configuration is provided below, and illustrated in Figure

3-32. The MHI gasifier configuration enables continuous molten slag discharge from the bottom of

the gasifier, and overall higher carbon conversion to syngas, both within the same pressure vessel.

- 97 -

MHI Stage One: Combustor

In the first stage, coal and recycled char are fed to the combustor chamber, along with the

oxygen-enriched air at a relatively high air/fuel ratio. Both full and partial oxidation reactions take

place (see Figure 3-32) to generate a mixture of gases, primarily CO and CO2. Water vapor needed

for “water shift” gasification reactions in the second stage is also generated here. Water vapor is

formed as a product of combustion involving the hydrocarbons contained in the coal volatile

matter that are liberated from the coal by the intense heating in this stage.

Figure 3-32 Operating Principle for the MHI Air-Blown Two-Stage Entrained-Bed Gasifier

Reductor Gasification of Char

Gas Cooling

Pyrolysis of Coal

Char + CO2 → 2CO

Char + H2O → CO + H2

CO + H2O → CO2 + H2

Combustor Combustion of Coal/Char

Melting Ash

Coal → Volatile matter + Char Volatile matter + O2 → CO2 + H2O

Char + O2 → CO + H2

Discharge of ash as slag

Air

Coal

HP SteamHP Steam

Syngas

CoalCombustor

Reductor

SGCSGCGasifierGasifier

Char

Air

Coal

HP SteamHP Steam

Syngas

CoalCombustor

Reductor

SGCSGCGasifierGasifier

Char

Temperature

Reductor

Combustor

Temperature

Reductor

Combustor

(Source) MHI

High temperatures enable the coal ash to separate from the gas stream in the form of molten slag.

The molten slag flows down to the bottom of the chamber, where it is quenched in water. The slag

is recovered in the form of a glassy bead-like byproduct with less than 0.1 percent unburned

carbon. The slag is in a glassy form and contains virtually no leachable trace elements. The slag

has a relatively high density, so the volume of slag is only about half that of the fly ash from a

conventional pulverized coal plant. This slag has possible commercial applications as road paving

materials or as a fine aggregate for concrete.

The air feed to the combustor section is enriched with oxygen to enhance this part of the process.

Oxygen enrichment adds to the operating flexibility of the gasifier, and also increases the heating

value of the syngas ultimately delivered to the gas turbine combustor.

The gasifier has a “membrane water wall” configuration that eliminates the need for a refractory

lining. An initial startup refractory lining is applied only for the inner surface of the combustor for

protection until it is gradually replaced by the formation of a solid state slag layer.

MHI Stage Two: Reductor

In the second stage, more coal is fed to the hot gas stream flowing upwards into the reductor, but

- 98 -

no additional air or oxygen is supplied.

In this fuel-rich, low-oxygen environment, the key reactions take place such as gasification of char

to CO, reduction of CO2 to CO, reduction of H2O to H2, additional pyrolysis of coal, and

subsequent gasification of products. These reactions are generally endothermic in nature, resulting

in a drop in gas mixture temperature before the gas stream exits at the top the gasifier.

At this reduced temperature, solid particles containing char or ash carryover are hardened so that

sticking and fouling of downstream heat exchanger surfaces is minimal, and not a concern.

Syngas Cooler and Char Removal

From the gasifier, the syngas flows to the syngas cooler where the gas is cooled and high pressure

(HP) steam is generated for further superheating and use in the power steam cycle. The cooler

includes an economizer section, an evaporator section with steam drum, and superheater sections.

From the syngas cooler, the gas flows to the char recovery and feed system. This system removes

the ash and char in the syngas and recycles it back into the gasifier. The system consists of a

cyclone, a set of porous filters, storage bin and distribution hoppers.

Air Separation Unit

For MHI’s air-blown gasifier, the majority of the gasification agent is supplied as air extracted

from the gas turbine compressor. Nitrogen is applied for both pulverized coal and char

transportation, therefore a small amount of oxygen as a byproduct of ASU is fed to the combustor

stage of the gasifier. As a result, the ASU is significantly less in terms of size and auxiliary power

than the much larger units needed for oxygen-blown gasifier design, and costs far less. Nitrogen is

also required for pneumatic coal feed to the gasifier from the distribution hoppers.

One full capacity air separation unit is provided to supply oxygen and nitrogen for the gasifier train.

Ambient air is compressed, cooled and dried by molecular sieves. By expansion and cooling, the

temperature is lowered and the air is partially liquefied. The air is then distilled in a distillation

column. This process produces oxygen at 95 percent purity and high purity nitrogen (<1 percent

O2). The oxygen is fed to the gasification unit to supplement the air. The nitrogen and oxygen are

fed to the gasifier from the ASU by one full capacity compressor for each stream.

Applicability of Mae Moh Coal for MHI Air-blown Gasifier

Mae Moh Coal has special features such as high moisture content and high ash content, especially

high CaO in ash. This high CaO in ash leads to low ash melting temperature, thus conventional

coal firing boilers, which generally require higher number such as 1,400 degree-C, is not well

fitted.

- 99 -

Figure 3-33 Typical Gasification Plant Process Flow Diagram

Air Separation Unit

Gasifier Coal Feeding

Porous Filter

Slag

N2

O2 Air

Char

G/T Compressor Extraction Air

Air Compressor

BFW

STM

Syngas Cooler

(Source) MHI

On the other hand, as mentioned above, air-blown gasifier discharges ash content in coal as molten

slag, thus very well fitted to the coal with high CaO like Mae Moh Coal. In addition, MHI

air-blown gasification has enough operation experience also for the moisture and ash content of the

coal and it will be easily applied for the commercial plant. In conclusion, MHI air-blown gasifier

can gasify Mae Moh Coal without any special consideration.

b-2. Gas treatment process

Basis of Design

The raw syngas from the porous filters requires additional treatment to make it suitable for

combustion in a gas turbine for electric power generation. Treatment is required to remove chloride,

sulfur, and ammonia from the syngas for process and emission considerations.

Though the raw syngas treatment configuration varies in detail dependent on the process

engineering firm, typical example can be summarized as follows:

Step 1. Syngas scrubbing for removal of chlorides.

Step 2. Catalytic hydrolysis of COS

Step 3. NH3 abatement by means of a water wash.

Step 4. Acid gas removal (AGR) by absorption with amine for H2S abatement. Sulfur

Recovery Unit is included.

- 100 -

Low Temperature Gas Cooling (LTGC)

The raw syngas is fed through a Scrubber to remove chlorides and trace metals and also fed to the

COS Hydrolysis Reactor to reduce COS concentration. After COS hydrolysis the syngas is cooled

in a series of exchangers to condense out most of the water. This includes a Syngas Cross

Exchanger used for heating the clean syngas. It is cooled further to around 40 deg C by trim

cooling using cooling water.

The process condensate produced by the cooling of the syngas is separated from the syngas vapor.

The cooled syngas is sent to the Ammonia Wash Column. The syngas vapor is then contacted with

clean water on wash trays for reducing ammonia and formate in the syngas overhead prior to being

sent to the Acid Gas Removal Unit.

Acid Gas Removal Units (AGR)

The Acid Gas Removal Unit removes the hydrogen sulfide from the syngas to meet environmental

emission regulations when the syngas is combusted in the gas turbine. In the Acid Gas Absorber,

the cooled syngas is contacted with a liquid solvent to remove the acid gas components. Clean

syngas exits the top of the Acid Gas Absorber and is sent through Syngas Cross Exchangers before

sent to the gas turbines.

On the other hand, the sulfur-related components captured in a solvent leave at the bottom of the

Absorber and sent to the Acid Gas Stripper. Here the sulfur related components is released again

from the solvent and sent to the Sulfur Recovery Unit (SRU), and clean solvent is recycled back to

the Acid Gas Absorber.

Sulfur Recovery Unit (SRU)

The Sulfur Recovery System produces sulfur-related byproducts such as elemental sulfur, sulfuric

acid and gypsum from the acid gas feed, dependent on the customer’s preference.

b-3. Gas turbine

General Description of the GT

The MHI M701F gas turbine is a robust unit with a very successful operating history. As of May

2011 MHI has sold 108 M701G units with natural gas firing. Moreover, the MHI M701F

combustion turbine is operated also on low BTU gas using diffusion combustion. There are 33

operating units on low BTU gas as of 2011 with a total of over 1,750,000 operating hours.

The MHI design philosophy follows from the success of the MHI M701D gas turbine in the

250MWe IGCC Demonstration Plant at Nakoso. Similar to the MHI M701D, the MHI M701F

features a cold end generator drive, 2 bearing rotor, and a 4 stage power turbine. It has a

horizontally split case for ease of access during maintenance. The rotor is cooled with filtered air.

Combustion System

The combustion system is designed for operation on low BTU syngas and start-up/ back-up fuel.

For operation on syngas, the diffusion type combustion system, modified from the typical steam

cooled Dry Low NOx type used on 701F class gas turbines firing natural gas is installed. There is

also a separate back-up fuel nozzle.

- 101 -

Although NOx emissions at gas turbine outlet can be reduced by some diluents or saturation

means, this design aims to achieve the highest gas turbine performance and to reduce NOx mainly

by SCR.

The design above has been proved to be feasible by the successful operation of 250 MW Nakoso

IGCC unit with MDEA gas clean-up.

Hot Gas Path

The hot gas path section is identical to a typical M701F gas turbine firing natural gas. The hot gas

path design will employ design features and materials that leverage MHI’s fleet experience while

seeking to minimize operating and maintenance cost.

Air Extraction

When MHI M701F is integrated with air-blown gasifier, extracted air from gas turbine is

introduced into booster air compressor and thus further compressed air is admitted to the gasifier as

gasification agent. All the air for gasification is supplied only with this means and it seems to be, as

it were, “full integration”. This process works successfully at the 250 MW Nakoso IGCC unit and

it will also be applied for the commercial plant using MHI M701F.

Accessory Systems

The MHI M701F fuel delivery system has been assessed for its suitability to supply syngas. The

fuel supply system is specifically designed to accommodate syngas with a high hydrogen

composition. A N2 inert purge system is used in the combustion system while firing on syngas to

ensure safe operation in a hydrogen-rich environment. The start-up fuel system is included in the

fuel delivery system to assure the starting process of the gasifier and gas clean up system.

Enclosure and Ventilation Systems

Enclosure and ventilation systems developed for natural gas fired gas turbines will be designed to

accommodate the larger piping, higher heat loads, and specific fuel characteristics associated with

syngas fuel. MHI has successfully employed this technique on low Btu fuel gas.

Control System

The control system will be designed for syngas operation to assure safe and reliable operation

while maintaining emissions within required limits. The control system will be configured for

start-up, transfer from start-up fuel to syngas, and operation at full load on syngas. The shutdown

sequence will be the reverse of the start-up sequence, operating at full load on syngas, reduce load

on syngas while admitting start-up fuel and shutdown on start-up fuel.

In summary, although there are no MHI 701F’s currently operating on syngas with air extraction,

MHI has a body of experience using low BTU fuels and has established a comprehensive

development testing program such as full scale combustion testing, feed back from full scale

operational testing at the 250 MW Nakoso IGCC unit, and other design validation programs to

take place while still meeting the requirements.

- 102 -

3) Plant Performance Summary

a. Power Generation Performance Summary

Table 3-21 Power Generation Performance of Air-blown IGCC

Item Air-blown IGCC (Mae Moh Coal)

Remarks

Gross Plant Output 571.3 MWe

Net Plant Output 505.4 MWe

(Aux. Power Consumption) / (Gross Plant Output) ratio

11.5 % Aux. Power Consumption for Mae Moh coal case is summary is indicated in c.

Net Plant Efficiency 43.4 %(HHV)

(Source) MHI

b. Process Performance Summary

Table 3-22 Process Performance of Air-blown IGCC

Item Air-blown IGCC

(Plant overall) Remarks

Coal Consumption 285.4 metric-t/h As Receieved Base

Oxygen Flow Rate 40.3 metric-t/h O2 Purity : 95vol%

Slag Discharge 38.5 metric-t/h Dry Basis

Elemental Sulfur 5.0 metric-t/h

(Source) MHI

c. Auxiliary Power Consumption

The table below shows the preliminary auxiliary power consumption for two (2) different cases.

Table 3-23 Auxiliary Power Consumption of Air-blown IGCC

No Item Air-blown IGCC


1 Coal Preparation Unit 9,300 kWe

2 Coal Gasification Unit 1,400 kWe

3 Gas Treating Unit 5,400 kWe

4 Combined Cycle Unit 16,400 kWe

5 Air Separation Unit 26,300 kWe

6 Others 7,200 kWe

Total 66,000 kWe

(Source) MHI

- 103 -

4) Environmental Performance Summary

a. Flue Gas Condition (@Stack Outlet)

Table 3-24 Flue Gas Condition of Air-blown IGCC (@Stack Outlet)

No Item Air-blown IGCC Remarks

1 GT Flue Gas Flow Rate 2,013,000 m3N/h Dry basis

2 SOｘ (@15%O2,dry) SOｘ (@7%O2,dry)

9.6 ppmV 22.4 ppmV

3 NOx (@15%O2,dry) NOx (@7%O2,dry)

6.0 ppmV 14.0 ppmV

4 Particulate Matter (@15%O2,dry) 4.8 mg/m3N

(Source) MHI

b. Effluent Condition

Table 3-25 Effluent Condition of Air-blown IGCC

No Item Air-blown IGCC Remarks

1 Effluent Flow Rate 340 m3/h During Normal Operation, Incl. Blow-down from Cooling Tower

2 BOD <20 mg/l

3 COD <120 mg/l

4 Suspended Solid <50 mg/l

5 Oil Content <5 mg/l

6 Hg <0.005 mg/l

7 Cr Hexavalent <0.25 mg/l

8 Cr Trivalent <0.75 mg/l

9 Cu <2 mg/l

10 Mn <5 mg/l

11 pH 5.5 - 9.0

(Source) MHI

- 104 -

5) Utility Consumption

Table 3-26 Utility Consumption of Air-blown IGCC

No Item Air-blown IGCC


1 Process Cooling Water 11,800 m3/h

2 Demin. Water 34 metric-t/h (Max.) 17 metric-t/h (Ave.)

Max. quantity incl. makeup for drum blow from SGC and HRSG

3 Service Water 1,260 metric-t/h (Max.) 1,250 metric-/h (Ave.)

4 Instrument Air 30 m3N/min (Cont.)

66 m3N/min (Int.)

5 Service Air 1 m3N/min (Cont.) 49 m3N/min (Int.)

(Source) MHI

Figure 3-34 Typical Plant Layout

360

m

220m

LTGC &AGR

SRU

Gasifier

ASUGT / ST&Generator

HRSG

WaterTreatment

CoolingTower

Flare

(Source) MHI

- 105 -

Figure 3-35 Typical Plant Construction Schedule

------ Year1 Year2 Year3 Year4 Year5 Year6

Pre-FEED

(Feasibility Study)

FEED including Detail Design /

Procurement, Construction &

Comissioning

(Source) MHI

e) Current Situation of Coal Mines and Coal Procurement Plan

1) Current situation of the coal mines

a. Geological overview

Coal resources in Thailand are mostly lignite and subbituminous coal belonging to the Tertiary

period of the Cenozoic. Many of the coal mines are concentratedly distributed in the northwest

region, but some of them are also distributed in the southern region of the peninsula. Coal was

formed in the intermountain basins or fault-caused depressed lands, both of which are distributed

in isolation, respectively. Many coal mines are relatively on a small scale and the Mae Moh coal

mine is not an exception. Figure 3-36 shows the situation of coal production other than the Mae

Moh Coal Mine. Currently, however, no coal mine is being operated other than the Mae Moh Coal

Mine.

Receive PO

COD

- 106 -

Figure 3-36 Coal Resource Distribution in Thailand

MyanmarMyanmarMyanmarMyanmarMyanmarMyanmarMyanmarMyanmarMyanmar

IndonesiaIndonesiaIndonesiaIndonesiaIndonesiaIndonesiaIndonesiaIndonesiaIndonesia Department of Mineral ResourcesDepartment of Mineral ResourcesDepartment of Mineral ResourcesDepartment of Mineral ResourcesDepartment of Mineral ResourcesDepartment of Mineral ResourcesDepartment of Mineral ResourcesDepartment of Mineral ResourcesDepartment of Mineral ResourcesMarch 12, 2001March 12, 2001March 12, 2001March 12, 2001March 12, 2001March 12, 2001March 12, 2001March 12, 2001March 12, 2001

Andaman SeaAndaman SeaAndaman SeaAndaman SeaAndaman SeaAndaman SeaAndaman SeaAndaman SeaAndaman Sea

Chiang MaiChiang MaiChiang MaiChiang MaiChiang MaiChiang MaiChiang MaiChiang MaiChiang Mai

TakTakTakTakTakTakTakTakTak

Surat ThaniSurat ThaniSurat ThaniSurat ThaniSurat ThaniSurat ThaniSurat ThaniSurat ThaniSurat Thani

BangkokBangkokBangkokBangkokBangkokBangkokBangkokBangkokBangkok

Suphan BuriSuphan BuriSuphan BuriSuphan BuriSuphan BuriSuphan BuriSuphan BuriSuphan BuriSuphan Buri

Gulf of ThailandGulf of ThailandGulf of ThailandGulf of ThailandGulf of ThailandGulf of ThailandGulf of ThailandGulf of ThailandGulf of Thailand

Prachub KhirikhanPrachub KhirikhanPrachub KhirikhanPrachub KhirikhanPrachub KhirikhanPrachub KhirikhanPrachub KhirikhanPrachub KhirikhanPrachub Khirikhan

Nakhon Si ThammaratNakhon Si ThammaratNakhon Si ThammaratNakhon Si ThammaratNakhon Si ThammaratNakhon Si ThammaratNakhon Si ThammaratNakhon Si ThammaratNakhon Si Thammarat

SongkhlaSongkhlaSongkhlaSongkhlaSongkhlaSongkhlaSongkhlaSongkhlaSongkhla

MalaysiaMalaysiaMalaysiaMalaysiaMalaysiaMalaysiaMalaysiaMalaysiaMalaysia

YalaYalaYalaYalaYalaYalaYalaYalaYala

LaosLaosLaosLaosLaosLaosLaosLaosLaos

NanNanNanNanNanNanNanNanNan

LoeiLoeiLoeiLoeiLoeiLoeiLoeiLoeiLoei

CambodiaCambodiaCambodiaCambodiaCambodiaCambodiaCambodiaCambodiaCambodia

Nakhon RatchasimaNakhon RatchasimaNakhon RatchasimaNakhon RatchasimaNakhon RatchasimaNakhon RatchasimaNakhon RatchasimaNakhon RatchasimaNakhon Ratchasima

0

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50

Kilometers

VietnamVietnamVietnamVietnamVietnamVietnamVietnamVietnamVietnam

100

VietnamVietnamVietnamVietnamVietnamVietnamVietnamVietnamVietnam

11ｰ 13ｰ

9ｰ

17ｰ

15ｰ

7ｰ

5ｰ

21ｰ

95ｰ

19ｰ

95ｰ 97ｰ 99ｰ

97ｰ 99ｰ

101ｰ 103ｰ

101ｰ 103ｰ

5ｰ105ｰ

21ｰ

19ｰ

105ｰ

7ｰ

9ｰ

13ｰ

11ｰ

17ｰ

15ｰ

Mae ChaemMae ChaemMae ChaemMae ChaemMae ChaemMae ChaemMae ChaemMae ChaemMae Chaem

Bo LuangBo LuangBo LuangBo LuangBo LuangBo LuangBo LuangBo LuangBo Luang

LiLiLiLiLiLiLiLiLi

Mae LamaoMae LamaoMae LamaoMae LamaoMae LamaoMae LamaoMae LamaoMae LamaoMae LamaoMae TuenMae TuenMae TuenMae TuenMae TuenMae TuenMae TuenMae TuenMae Tuen

Mae ThanMae ThanMae ThanMae ThanMae ThanMae ThanMae ThanMae ThanMae Than

Mae MohMae MohMae MohMae MohMae MohMae MohMae MohMae MohMae Moh

Mae TeepMae TeepMae TeepMae TeepMae TeepMae TeepMae TeepMae TeepMae Teep

Chiang MuanChiang MuanChiang MuanChiang MuanChiang MuanChiang MuanChiang MuanChiang MuanChiang Muan

Na DuangNa DuangNa DuangNa DuangNa DuangNa DuangNa DuangNa DuangNa Duang

Na KlangNa KlangNa KlangNa KlangNa KlangNa KlangNa KlangNa KlangNa Klang

Nong Ya PlongNong Ya PlongNong Ya PlongNong Ya PlongNong Ya PlongNong Ya PlongNong Ya PlongNong Ya PlongNong Ya Plong

KrabiKrabiKrabiKrabiKrabiKrabiKrabiKrabiKrabi

KantangKantangKantangKantangKantangKantangKantangKantangKantang

Active Coal MineSuspended Coal Mine

(Source) The Agency for Natural Resources and Energy of the Ministry of Economy, Trade and

Industry ”Clean Coal Technology Diffusion Project in 2009 (Survey of Effect on Coal Supply-Demand and Reduction of Environmental Burdens by Introduction of CCT into East Asian Region)”

The Mae Moh Coal Mine is located 30 km to the east of Lampang and the EGAT is developing

and operating it in the same district. The coal bed originated in the Mae Moh formation of the

Miocene to Pleiocene of the Neocene and its layers are named Layer J, K, Q, R and S from above.

The three layers, J, R and S, are poorly developed and not considered as the production targets.

The two layers, K and Q, are being mined as the production targets. These years, however, Layer J

with fewer split seams has been also considered as the mining target. The interburden of Layers K

and Q consists of 10 m to 30 m mudstone, etc.

- 107 -

Figure 3-37 Geological Column of Mae Moh Coal Mine

Triassic

15 - 320 m

300 - 420 m

Ter

tiary

-Mae

Mo

h G

roup

Plei-Recent

5 - 400 m

SS, ST, MS, SH, LST, Cong/Marine.

Sand, Silt, Clay, Gravel/Fluviatile

Semicon, F to C -grained, Cong, SS, ST MS,CS,Fining upward, Variegated color/Fluviatile.

Overburden

Semicon, CS, MS, brown-gray, Lignite layers.Gastropod/Qtz, Illite, Calcite etc/Lacustrine.

Interburden

Interburden

J

Q

R

K

S

(Source) EGAT-supplied material “Overview of Mae Moh Lignite Mine”

The following describes the layer situation of the coal bed.

Layer J: This layer consists of 13 thin layers drastically changing in thickness. Not considered as the

mining target because it has high sulfur content and changes drastically in layer thickness.

Since it is close to the ground surface and has a low strip ratio, however, a conditionally

advantageous portion is considered as the mining target.

Layer K: This layer has the thickness of 25 m to 30 m and is currently mined. Mixed mudstone

becomes thicker in the northern and southern areas, having a tendency of splitting up. The

coal quality becomes worse along with the tendency.

Layer Q: This layer has the thickness of 10 m to 30 m and is currently mined. As with Layer K,

mixed mudstone becomes thicker in the northern and southern areas, having a tendency of

splitting up. The coal quality becomes worse along with the tendency.

Layer R: This layer has the thickness of 1 m to 2 m and is not considered as the production target

now.

Layer S: This layer has the thickness of 1 m to 2 m and is not considered as the production target

now.

- 108 -

Figure 3-38 Coal Bed with Drastic Split Seams

(Source) EGAT-supplied material “Overview of Mae Moh Lignite Mine”

The geological structure of the Mae Moh Coal Mine is a synclinal structure having an axis in the

north-south direction. The deepest coal bed (Layer Q) existence depth at the synclinal bottom is

500 m below the ground surface. Geological inclination is 15 degrees to 20 degrees near the

current mining area. There are considerably many faults.

Figure 3-39 Main Cross-Sectional Charts

Cross-section (West - East)

Cross-section (South - North)

QK

(Source) EGAT-supplied material

- 109 -

Figure 3-40 Lower Part Structure of Layer Q

4.5 km

7 km

N

View of central sub-basin structure looking north, Base on Q floor. The central graben is clearly visible

(Note) The depth increases in order of red, yellow, green, blue and purple. (Source) EGAT-supplied material “Overview of Mae Moh Lignite Mine”

b. Overview of the coal mine

The Mae Moh Coal Mine started coal production by open-pit mining in 1955. Its production

volume in 1955 was 40,500 t. Along with addition and expansion of the Mae Moh Coal-Fired

Power Plant, the production volume continued to increase and exceeded 10 million t in 1991 and

15 million t in 1996, maintaining the annual production volume of 15 million t or more in the

2000s.

Figure 3-41 Coal Production Performance and Strip Ratio at Mae Moh Coal Mine

0

5

10

15

20

25

'93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10

Co

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(m

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n to

n)

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7.0

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Ra

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Coal production Strip Ratio

(Source) Information posted on the website of the Mae Moh Coal Mine (http://maemohmine.egat.co.th/production/index.html)

- 110 -

The mining target area of the Mae Moh Coal Mine extends about 4.5 km in the east-west direction

and about 7 km in the north-south direction, with the final mining depth of 500 m below the

ground surface. The total minable coal reserves of this area are estimated to be 825 million t. As of

January 2010, 333 million t of coal has been mined. Accordingly, 492 million t of minable coal

remains in the mining target area as of January 2010. As shown in Figure 3-42, there is a fossil

zone in the southwest of the mining target area, where fossils exist as cultural assets (fossils of

shellfish, trilobites, etc.). To preserve this zone, an inhibited (fossil) area which inhibits bench cut

for coal mining will come into being on its east side (south of the mining target area). It has been

confirmed that this area contains 150 million t of minable coal reserves, but no mining permission

has been obtained. Without these coal reserves, the remaining minable coal reserves are 342

million t.

Figure 3-42 Final Geometry of Mining Area

Inhibit (Fossil) Area

Dumping Area

Dumping Area

Power Plant

Coal StockpileFossil Zone


As mentioned above, the strip ratio has been transitioning between 4 and 6 (BCM26/t) since 2000.

The quality of raw coal is as shown in Table 3-27. It features a heating value as low as 2,300

kcal/kg on the average and the widely varying CaO content in the ashes, averaging as high as 23%.

26 Bank cubic meter (BCM)

- 111 -

Table 3-27 Quality of Raw Coal at Mae Moh Coal Mine

Specification Range

Heating Value (ar basis, kcal/kg) ≥ 2,300 1,300 ～ 3,300

Sulphur (ar basis, %) ≤ 3.3 1.8 ～ 5.0

CaO in ash (%) ≤ 23 2 ～ 52


Coal mining has been basically carried out from a shallow section to a deep one (north to south).

The coal has been mined by open-pit mining. Different from the cut-and-fill method generally

implemented in Australia, etc., the bench cut method is employed, which mines massive deposits

and does not backfill (partial backfilling is done). Currently, mining is being carried out

concurrently at two distant (not adjacent) pits, reaching as deep as 300 m below the ground surface

in the deepest section. The following table shows the combinations of equipments used for mining.

There are two types of stripping methods; (1) one is to dig with a hydraulic shovel, etc., truck mine

spoil to a crusher installed in the pit to crush to the size suitable for transportation by a belt conveyor,

and load it onto the belt conveyor to convey to a dumping area, and (2) the other is to dig and load

the mine spoil onto the belt conveyor at one time by a bucket wheel excavator to convey to the

dumping area. The coal is mined by the hydraulic shovel, etc., trucked to the crusher installed in the

pit, crushed to the size suitable for transportation by the belt conveyor, loaded onto the belt

conveyor, and conveyed to a coal stockpile.

Table 3-28 Combinations of Equipments Used for Mining

Pit Transportation

Truck and Shovel, Inpit Crusher Conveyor Belt Waste Removal

Bucket Wheel Excavator (BWE) Conveyor Belt

Coal Production Truck and Shovel, Inpit Crusher Conveyor Belt


Figure 3-43 Panoramic View of Pit


- 112 -

Figure 3-44 Mining Equipment

Hydraulic Front Shovel（11.5m3） Power Shovel（Electric Rope、11.5m3）

Bucket Wheel Excavator（3,000t/h） Inpit Crusher（4,500t/h）

Bucket Wheel Excavator（4,000t/h） Inpit Crusher（3,500t/h）

(Source) Mae Moh Lignite Mine internet website

Mining is mainly implemented by two contractors, but is partly done as a directly controlled project

of the Mae Moh Coal Mine (EGAT). The following table shows assignments of mining work.

- 113 -

Table 3-29 Assignments of Mining Work

Waste Removal Coal Production

Mae Moh Lignite Mine (EGAT) 5 - 10 % 30 %

Contractors 90 - 95 % 70 %


Figure 3-42 shows an anticipated landform upon completion of mining. It is planned to turn the

mined land (pit) into a reservoir and eventually make use of the entire mined land as cultural

facilities such as a park. A golf course, park and facility exhibiting the coal mine history, etc. have

been already constructed and opened to the public.

At the coal stockpile adjacent to the Mae Moh Power Plant, the coal conveyed by the belt conveyor

from the pit is stocked in 6 piles sorted out for each layer (sorted out based on the coal quality), and

is mixed at the outlet of the coal stockpile, adjusting a coal feed rate for each pile so as to keep the

constant grade at the time of feeding the coal to the power plant. The coal stockpile always stocks

the coal for one-week consumption (300,000 t). It is being expanded and will have another one pile

worth of stockpile facility in 2012.

Figure 3-45 Panoramic View of Coal Stockpile


- 114 -

2) Coal procurement plan

Currently, all the coal (lignite) produced at the Mae Moh Coal Mine is consumed at the Mae Moh Power

Plant as fuel for power generation. Annually, about 16 million t of coal is consumed for the total electrical

power plant capacity of 2,400 MW and annual total generated electric energy of 15,760 GWh.

Table 3-30 Facilities and Coal Consumption at Mae Moh Power Plant

Power Generation Capacity

Power GenerationLignite

Consumption

（MW）（GWh/year） (million ton/year)

4 150 985 1

5 150 985 1

6 150 985 1

7 150 985 1

8 300 1,970 2

9 300 1,970 2

10 300 1,970 2

11 300 1,970 2

12 300 1,970 2

13 300 1,970 2

Total 2,400 15,760 16

Unit No.

(Note) Units 1 to 3 were decommissioned. (Source) Information posted on the website of the Mae Moh Power Plant

（http://maemoh.egat.com/index_maemoh/index.php?content=technical）

Currently, the four plants, Units 4 to 7 (150 MW x 4), are under a replacement project and will be replaced

by a 600 MW supercritical pressure coal-fired power plant in 2017. The existing four plants will be

continuously operated until 2016 and the new plant is planned to be operated for 30 years from 2017 to

2046. The six plants, Units 8 to 13, are planned to be operated until 2035 as shown in Table 3-31. Coal

consumption based on the operation schedule of this plant is calculated to be 327 million t. Figure 3-46

shows annual coal consumption based on the data (Table 3-31) provided by the EGAT. Since the minable

coal reserves of the Mae Moh Coal Mine are 342 million t as mentioned above, there is a margin of 15

million t for the above-mentioned project.

- 115 -

Table 3-31 Coal Consumption Plan by EGAT unit : Million ton

Year

4 5 6 7 8 9 10 11 12 13

2010 1.02 1.02 1.02 1.02 1.96 1.96 1.96 1.96 1.96 1.96 15.86 15.86

2011 1.03 1.03 1.03 1.03 1.97 1.97 1.97 1.97 1.97 1.97 15.96 31.82

2012 0.99 0.99 0.99 0.99 1.91 1.91 1.91 1.91 1.91 1.91 15.45 47.27

2013 1.04 1.04 1.04 1.04 1.99 1.99 1.99 1.99 1.99 1.99 16.11 63.38

2014 0.92 0.92 0.92 0.92 1.78 1.78 1.78 1.78 1.78 1.78 14.35 77.73

2015 0.95 0.95 0.95 0.95 1.83 1.83 1.83 1.83 1.83 1.83 14.78 92.51

2016 0.94 0.94 0.94 0.94 1.81 1.81 1.81 1.81 1.81 1.81 14.62 107.13

2017 1.72 1.72 1.72 1.72 1.72 1.72 2.71 13.01 120.14

2018 1.60 1.60 1.60 1.60 1.60 1.60 2.51 12.11 132.25

2019 1.62 1.62 1.62 1.62 1.62 1.62 2.54 12.29 144.54

2020 1.64 1.64 1.64 1.64 1.64 1.63 2.56 12.39 156.93

2021 1.63 1.63 1.63 1.63 1.63 1.63 2.56 12.37 169.30

2022 1.63 1.63 1.63 1.63 1.63 1.63 2.56 12.37 181.67

2023 1.63 1.63 1.63 1.63 1.63 1.63 2.56 12.37 194.04

2024 1.61 1.61 1.61 1.61 1.61 1.60 2.51 12.14 206.18

2025 1.59 1.59 1.59 1.59 1.59 1.59 2.49 12.05 218.23

2026 1.58 1.58 1.58 1.58 1.58 1.58 2.47 11.96 230.19

2027 1.58 1.58 1.58 1.58 1.58 1.58 2.47 11.96 242.15

2028 1.59 1.59 1.59 1.59 1.59 1.58 2.47 11.98 254.13

2029 1.58 1.58 1.58 1.58 1.58 2.47 10.38 264.51

2030 1.54 1.54 1.54 1.54 2.40 8.56 273.07

2031 1.54 1.54 1.54 2.40 7.02 280.09

2032 1.54 1.54 2.40 5.48 285.57

2033 1.54 1.54 2.40 5.48 291.05

2034 1.54 1.54 2.40 5.48 296.53

2035 1.54 2.40 3.94 300.47

2036 2.40 2.40 302.87

2037 2.40 2.40 305.27

2038 2.40 2.40 307.67

2039 2.40 2.40 310.07

2040 2.40 2.40 312.47

2041 2.40 2.40 314.87

2042 2.40 2.40 317.27

2043 2.40 2.40 319.67

2044 2.40 2.40 322.07

2045 2.40 2.40 324.47

2046 2.40 2.40 326.87

Total 73.68 326.87

Lignite Consumption Plan

Cumulative Coal

Consumption

Mae Moh Power Plant new 4-7 replacemen

tYear Total

253.01


- 116 -

Figure 3-46 Coal Consumption Plan (1)

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Unit 4-7 (before replacement) Unit 4-7 (after replacement) Unit 8-13 Cumulative Coal Consumption

Remaining Coal Economical Reserve 342 million ton


Suppose one IGCC power plant is constructed and inaugurated in 2020, annual coal consumption of about

1.8 million t will be added to the above-mentioned plan. By increasing annual coal consumption, the

remaining minable coal reserves will run out in 2038.


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IGCC Cumulative Coal Consumption


Mine Out


“Decreasing Coal Consumption due to CaO Issue”

The average heating value of coal supplied from the Mae Moh Coal Mine is expected to increase to

3,000 kcal/kg in the 2020s. The CaO content in the ashes is lower than 20% for the moment, but is

expected to increase after 2014 to about 30% in the first half of the 2020s, about 35% in the latter half

of the 2020s, and about 40% thereafter. A higher heating value of the coal is expected to inhibit coal

consumption, but the higher CaO content in the ashes will cause boiler failures, deteriorating the

operating rate of the entire plant (based on on-site hearing).

- 117 -

By reference to the operation prospect of the plant with the EGAT’s presented CaO issue taken into

account, coal consumption was estimated on the assumption that the Units 4 and 5 (150 MW x 2) will

stop operation in 2014, Unit 8 (300 MW) in 2017, and all the existing plants (Units 9 to 13, 300 MW x

5) in 2024, respectively (see Figure 3-48). It is assumed that one plant (new Units 4 to 7) to be

replaced in 2017 and the IGCC are not subject to the CaO issue.

As shown in Figure 3-48, coal consumption will be reduced in 2014 because of shutdown of the Units

4 and 5 (150 MW x 2) and will be further reduced in 2017 because of shutdown of the Unit 8. Coal

consumption will increase in 2020 because the IGCC will start operating. In 2024, however, the coal

will be consumed only the replaced plant and the IGCC because all the existing plants will stop

operation. On this assumption, there will remain 61 million t of minable coal reserves even in 2046. If

this amount is divided by the IGCC’s annual consumption, or 1.8 million t, it is 34 years worth,

allowing additional construction of the 500 MW-class IGCC power plant as an alternative for the

existing Units 8 to 13 which will have been shut down.


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Coal consumption was estimated only as to the existing plants (Units 4 to 7: 2014 to 2016, Units 8 to

13: 2014 to 2035 based on the operation plan), assuming that a decrease in the operating rate by an

effect of CaO is 5% compared with the previous year (see Figure 3-49). A decrease in the operating

rate is not assumed for the four plants, Units 4 to 7, to be replaced in 2017 and the IGCC power plant.

As shown in Figure 3-49 coal consumption is reduced by the lower operating rate of the existing plant

from 2014, slowing down an increase in the cumulative total of coal consumption. On this assumption,

there will remain 32 million t of minable coal reserves even in 2046. If this amount is divided by

annual consumption of the IGCC power plant, or 1.8 million t, it is 18 years worth, allowing the IGCC

power plant to be operated for 46 years from 2020 to 2065.

“Response to CaO Issue”

In order to cope with an increase in the CaO content in the ashes, it is conceivable to introduce the

- 118 -

low-CaO coal. Since there are no coal reserves suitable for this purpose near Mae Moh or in Thailand,

the EGAT is thinking about importing the coal (lignite) up to 10% of annual consumption from

Myanmar, 400 km to 500 km distant.

A possibility of importing the coal from Myanmar is worth considering, if there is a railway

connecting a production area and Mae Moh straight. However, such long-distant trucking of a large

amount of coal is not very practicable, considering its cost and traffic safety on the transportation

route.


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“Coal Mining in Mining Restricted Area”

To supplement the coat which may run short, it is necessary to think about coal mining in the mining

restricted area mentioned in “Overview of the coal mine.” In order to make it possible to mine in this

area, the Mae Moh Coal Mine is considering punch mining (highwall mining), although it produces a

lower actual yield and costs more.

Chapter 4 Evaluation of Environmental and Social Impacts

- 120 -

(1) Analysis of Current Situation in Environmental and Social Aspects

a) Analysis of the current situation

In order to enhance the environmental performance, the Mae Moh Thermal Power Plant has already

additionally installed the desulfurization equipments for all the units. They were sequentially installed

from 1995 to 2000 because of growing concerns about the environmental issues around the power plant.

Atmospheric emission matters and effluent properties were greatly improved by them, leading to the

present day. The environmental standards have been reviewed accordingly, ensuring a management

condition in accordance with increasing environmental awareness in Thailand.

The following describes the current environmental situation by main environmental management item.

1) Air quality

In Thailand, the power plant has exclusive standards for the air quality. They have been set based on

whether the power generation facilities are existing ones or new ones, plus the fuel and output.

Table 4-1 shows the operation criteria of the currently managed Mae Moh Thermal Power Plant. An

information source is the competent authority at the time of publication.

Table 4-1 Atmospheric Emission Standards at Mae Moh Thermal Power Plant

Standard Values for Existing Power Plants (2001 edition)

SO2 (ppm) NOx (ppm, as NO2) PM (mg/Nm3)

Unit 1 – 3 (Note: Demolished) 1,300 500 180

Unit 4 - 13 320 500 180

(Note) Total SO2 load of the Mae Moh Units 1 to 13 < 11 t/h (Source) Official gazette of Ministry of Science, Technology and Environment, Thailand

The above table excerpts the atmospheric emission standards on the existing power generation facilities.

Including a publication in the Mae Moh district on Dec. 27, 1999, they have been partly revised several

times. The current version was eventually publicized in a Thai government gazette on Mar. 16, 2001.

As it is clear from the year of publication, these standards have lowered the criteria in accordance with

additional installation of the current desulfurization equipments. The Mae Moh Units 1 to 3 were

decided to be demolished, not remodeling the facilities. Namely, the criteria of the Mae Moh Units 1 to 3

are close to the performance of the Mae Moh Thermal Power Plant before installing the desulfurization

equipments for the Units 4 to 13, indicating remarkable improvement.

Next, Table 4-2 shows the emission standards for new thermal power plants in Thailand.

- 121 -

Table 4-2 Atmospheric Emission Standards for New Thermal Power Plants in Thailand

Standard Values for New Power Plants (published 15 Jan 2010)

SO2 (ppm) NOx (ppm, as NO2) PM (mg/Nm3)

Coal (<50MW) 360 200 80 1

Coal（>50MW） 180 200 80

2 Oil 260 180 120

3 Gas 20 120 60

4 Biomass 60 200 120

(Source) Official gazette of Ministry of Natural Resources and Environment, Thailand

The above emission standards were publicized in a Thai government gazette on Jan.15, 2010. The prior

version was publicized in 1996 and the main revisions are as follows.

Lowering of the SO2 criterion and reviewing of the output of the coal-fired power plant.

Lowering of the SO2 criterion of the oil-fired power plant.

Additions to the standards for the biomass power plant.

Enhancement of the environmental performance in the future new investment cases is targeted by

lowering the SO2 criterion and setting the criteria of the biomass power plant which produces renewable

energy.

The most recent emission results of the Mae Moh Thermal Power Plant are SO2 = 118 ppm, NOx = 280

ppm, and PM = 9 mg/Nm3, fully satisfying the emission standards.

2) Water quality

The effluent standards for the industrial plants and industrial estates apply to the water quality. Table 4-3

shows the effluent standards for the industrial plants and industrial estates, and the effluent properties

actually managed by the power plant. These standards apply to the effluent from the Mae Moh Thermal

Power Plant. In actual effluent management, the management values have been voluntarily raised for

eliminating the materials not came up in the operation process of the thermal power plant and controlling

the effluent properties. Given the above situation, it is determined that effluent management at the Mae

Moh Power Plant is appropriate.

The following table shows the target effluent standards of this project and the management standards for

the actual facilities.

Currently, the Mae Moh Thermal Power Plant is running, satisfying the effluent standards shown in the

table.

- 122 -

Table 4-3 Effluent Standards for Industrial Plants and Industrial Estates,

and Power Plant Management Values in Thailand

Industrial Effluent Standards Mae Moh Power Station

Unit Standard Values

(published 13 Feb 1996) Management Values

1 pH - 5.5 – 9.0 5.55 - 9.0

2 TDS (Total Dissolved Solid) mg/l <=3,000 (or <=5,000,

depending on condition) <=3,000

3 SS (Suspended Solids) mg/l <=50 (or <=150, depending

on condition) <=50

4 Temperature deg C <=40 <=40

5 Color and Odor - Not objectionable Not objectionable

6 Sulfide (as H2S) mg/l <=1.0 <=1.0

7 Cyanide (as HCN) mg/l <=0.2 -

Heavy Metals

1 Zn mg/l Maximum 5.0 Maximum 5.0

2 Cr (Hexavalent) mg/l Maximum 0.25 Maximum 0.25

3 Cr (Trivalent) mg/l Maximum 0.75 Maximum 0.75

4 As mg/l Maximum 0.25 Maximum 0.25

5 Cu mg/l Maximum 2.0 Maximum 2.0

6 Hg mg/l Maximum 0.005 Maximum 0.005

7 Cd mg/l Maximum 0.03 Maximum 0.03

8 Ba mg/l Maximum 1.0 Maximum 1.0

9 Se mg/l Maximum 0.02 Maximum 0.02

10 Pb mg/l Maximum 0.2 Maximum 0.2

11 Ni mg/l Maximum 1.0 Maximum 1.0

8

12 Mg mg/l Maximum 5.0 Maximum 5.0

9 FOG (Fat, Oil and Grease) mg/l <= 5 (or <=15, depending

on condition) <= 5

10 Formaldehyde mg/l <=1 -

11 Phenols mg/l <=1 -

12 Free Chlorine mg/l <=1 -

13 Pesticide mg/l None -

14 BOD (Biochemical Oxygen Demand)

mg/l <=20 (or <=60, depending

on condition) <=20

15 TKN (Total Kjeldahl Nitrogen) mg/l <=100 (or <=200,

depending on condition) <=100

16 COD (Chemical Oxygen Demand)

mg/l <=120(or<=240,depending

on condition) <=120

(Source) Official gazette of Ministry of Science, Technology and Environment, Thailand

It is not a direct effluent destination, but the standards for qround water are separately provided for

appropriate use of the power plant site and prevention of infiltration of environmental pollutants. Although

this investigation does not refer to the qround water because it is not the direct effluent destination, it

should be checked when evaluating an environmental impact.

- 123 -

The standards for effluent measuring methods are separately provided and must be complied with when

conducting an environmental and health impact assessment (EHIA).

For reference, the effluent standards for the offshore areas and the standards for surface water are

separately provided. That is, the standards in the above table are applicable to the Mae Moh Thermal

Power Plant which has to take into account an effect on inland ponds and rivers. When constructing along

the coast, applicable standards are separately provided and the relevant provisions have to be referred to.

3) Noise and vibrations

There are the standards for community noise, annoyance noise, and mining and quarrying noise, which

are shown in the following table.

Table 4-4 Noise Standards in Thailand

Description

1 Community Noise Standard 1) Maximum Lmax < 115 db(A) 2) Leq 24hours < 70db(A)

2 Annoyance Noise Standard

1) Annoyed Sound Level =10 db(A) 2) The sound is indicated to be annoyance provided that the

calculate annoyance level is higher than the sound pressure level of annoyed sound.2)

3 Noise from Mining and Quarry 1) Maximum Lmax < 115 db(A) 2) Leq 8hours < 75db(A) 3) Leq 24hours < 70db(A)

(Note) Leq =Weighted Equivalent Continuous Sound Level (Source) Official gazette of National Environmental Board, Ministry of Science, Technology and

Environment, Thailand

There are the standards for mining and quarrying vibrations, which are shown in Table 4-5.

Main noise source facilities in the current situation are induced draft fans and water feed pumps for the

Mae Moh Thermal Power Plant, and mining facilities, crushers, driving of dump trucks, belt conveyors

and blasting work for the coal mine. The devices at the Mae Moh Thermal Power Plant are not specially

designed ones. Given that they already have various operation track records, the noise preventive

measures are already in place.

Possible vibration source facilities are mainly steam turbines for the Mae Moh Thermal Power Plant, and

mining facilities, crushers, driving of dump trucks, belt conveyors and blasting work for the coal mine. As

with the current noise situation, no specially designed devices are used and the vibration preventive

measures are already in place.

- 124 -

Table 4-5 Standards for Mining and Quarrying Vibrations in Thailand

Frequency (Hz) 1 2 3 4 5 6 7 8 9 10

Velocity (mm/s) >4.7 >9.4 >12.7 >12.7 >12.7 >12.7 >12.7 >12.7 >12.7 >12.7

Displacement (mm) 0.75 0.75 0.67 0.51 0.40 0.34 0.29 0.25 0.23 0.20

Frequency (Hz) 11 12 13 14 15 16 17 18 19 20

Velocity (mm/s) >13.8 >15.1 >16.3 >17.6 >18.8 >20.1 >21.4 >22.6 >23.9 >25.1

Displacement (mm) 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20

Frequency (Hz) 21 22 23 24 25 26 27 28 29 30

Velocity (mm/s) >26.4 >27.6 >28.9 >30.2 >31.4 >32.7 >33.9 >35.2 >36.4 >37.7

Displacement (mm) 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20

Frequency (Hz) 31 32 33 34 35 36 37 38 39 40=<

Velocity (mm/s) >39.0 >40.2 >41.5 >42.7 >44.0 >45.2 >46.5 >47.8 >49.0 >50.8

Displacement (mm) 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20

(Source) Official gazette of Ministry of Natural Resources and Environment, Thailand

4) Waste materials

Waste materials include discharge of coal ashes peculiar to the coal-fired power plant, in addition to

general waste materials discharged from a workplace office, etc. and industrial waste materials consequent

upon inspection and maintenance. At the coal-fired power plant, the coal ashes account for the majority of

the entire discharge amount of the industrial waste materials, and it is always interested in securing a coal

ash disposal site.

Since the Mae Moh Thermal Power Plant is located next to the coal mine, the coal ashes have been

dumped into an coal ash dumping area. From viewpoints of increasing environmental awareness and

effective utilization of resources, however, it has been continuously addressing recycling of the coal ashes

these days and is cultivating their delivery destinations such as cement companies, and so on. Also, the

desulfurization equipments discharge gypsum as by-product and its delivery destinations are being

cultivated.

For the filled coal ash disposal site, its surface part has been covered with soil to construct a park, etc.,

promoting greening.

Table 4-6 Coal Ash Discharge Amount at Mae Moh Thermal Power Plant

2007 2008 2009 2010

Renewable (t) 1,633,688 1,575,764 1,358,495 1,512,353

Landfill (t) 2,566,845 2,517,547 2,894,865 2,898,890

Total (t) 4,200,533 4,093,311 4,253,360 4,411,243

(Source) Data aggregated by EGAT and Mae Moh Thermal Power Plant

- 125 -

b) Future prediction (When the project is not implemented)

The Mae Moh Thermal Power Plant has enhanced the environmental performance by the desulfurization

equipments, but its facilities are becoming more and more old-fashioned. They comply with the current

environmental standards, but when the future situation is predicted, investments in the clean coal

technology facilities are required for continuous environmental improvement.

Furthermore, it is predicted that power plant operation will be difficult because of impacts consequent

upon lower coal quality such as a higher CaO ratio in the ash content. Particularly, when there is a

combustion failure, it is expected that there will be a situation deviating from the environmental criteria

for a short period of time. Unless some measures are taken, a higher occurrence frequency of the

combustion failure is expected, possibly resulting in greater environmental impacts.

The IGCC has not only the superior environmental performance, but adaptability to low-grade coal with a

high CaO ratio in the ash content such as Mae Moh coal. Namely, if the conventional power generation

facilities are continuously operated without introducing the IGCC, an environment improvement

opportunity will be further postponed to the future even though there will be a low possibility of

deteriorating the environment .

(2) Environment Improvement Effects Consequent upon Project Implementation

Many environment improvement effects are expected by implementing this project. Greater improvement

effects are particularly expected in the air quality, water quality and waste materials (especially for coal

ashes). Since there is a difference in performance in each case depending on the individual devices to be

selected, some assumption are required to make a quantitative evaluation.

Particularly, the environmental performance of Japanese power generation facilities is extremely high. If

unnecessarily high-performance devices are introduced in comparison with the environmental regulation

values at the introduction site, however, they will have an effect on the economic efficiency of the project,

possibly compromising feasibility of the project.

Since the environmental performance should be determined, while considering economic efficiency and

discussing with the EGAT from an overall viewpoint, this investigation only focuses on evaluations based

on typical numerical values; actual effects will be determined in detailed investigation.

1) Environment improvement effects of the air quality

If the IGCC is combined with currently state-of-the-art gas purification facilities and denitrification

equipments, the Figure 4-1 shows the expected performance at the chimney outlet.

The capabilities of the IGCC’s gas purification facilities affect the desulfurization performance, the data of

the state-of-the-art devices are tentatively shown because the number of IGCC power generation facilities

in actual operation is lower than that of pulverized coal-fired boilers. Although a balance between the

required environmental performance and expenses should be considered in detailed investigation, the

- 126 -

environmental performance shown in Figure 4-1 is slightly beyond the specifications in view of the

environmental performance standard required in Thailand.

Denitrification equipments have been installed only at few of existing thermal power plants in Thailand.

Given the environmental regulation values of new power generation facilities, they are beyond the

specifications with respect to the environmental performance required in Thailand. If the denitrification

equipments are not installed, the NOx value will be about 50 ppm.

Only the situation of dust and soot differs from NOx and SOx. Since the IGCC has aversion to particle

errosion, it is required in designing that the number of microparticles in a combustion gas must be

extremely few. Since the devices are introduced based on the up-to-date specifications as per the

performance in Figure 4-1 for the current pulverized coal-fired boilers, it is not allowed to downgrade the

specifications because of cost-effectiveness. However, it is a coal mine area and there may be much dust

in the atmosphere from the beginning. The figure shows the dust deriving from the power generation

facilities, and the actual measurement values are the “dust in the atmosphere + dust caused by IGCC

operation.” In any case, the discharge amount is greatly lower than the current regulation values, showing

high environment improvement effects.

From the above, SOx and NOx removal capabilities are eventually determined by cost-effectiveness

within regulations. Even if the specifications are downgraded, however, substantial environment

improvement effects are expected because the IGCC basically has high environmental performance.

Figure 4-1 General comparison among environmental performance

(Oxygen Content in Exhaust Gas: 7% for PC Boiler, 15% for IGCC)

O2 7% for PC Boiler

O2 15% for IGCC

0

100

200

300

400

500

600

Exixting Mae Moh 8-13

(Regulation)


(Record, all average)

Standard for New Power

Plant

(>50MW, Coal fired)

New unit 4-7 replacement

plant

IGCC (O2 blown) IGCC (O2 blown)

(with NOx Removal

Equipment)

PP

M

NOx SOx Particulate


- 127 -

Figure 4-2 General comparison among environmental performance

(Oxygen Content in Exhaust Gas: 7% for PC Boiler, 7% for IGCC)

O2 7% for PC Boiler

O2 7% for IGCC

0

100

200

300

400

500

600


(Regulation)


(Record, all average)

Standard for New Power

Plant

(>50MW, Coal fired)

New unit 4-7 replacement

plant

IGCC (O2 blown) IGCC (O2 blown)

(with NOx Removal

Equipment)

PP

M

NOx SOx Particulate


2) Environment improvement effects of the water quality

The IGCC power plant generates electric power by a combination of a gas turbine and a steam turbine.

Since the output ratio of the steam turbine, which is a main consumer of water, is greatly lower than the

same-scale pulverized coal-fired power plant, about one third to half, water consumption decreases,

leading to a lower effluent volume. Water consumption also decreases because of a difference between the

IGCC’s gas purification facilities and the desulfurization equipments of the pulverized coal-fired power

plant. The water consumption differs depending on the selected desulfurization system. According to the

IGCC’s track records, however, the IGCC consumes less water than the same-scale pulverized coal-fired

power plant.

Since the total water consumption of the power generation facilities and desulfurization facilities is

reduced, the above-mentioned reduction is expected. A specific reduction volume needs to be calculated

in detailed planning of the facilities.

The effluent volume depends on the water consumption. The effluent volume of the power generation

facilities increases in proportion to the number of start and stop times. Since the EGAT has extremely high

facility availability, there are hardly start and stop operations, resulting in the low effluent volume from the

power generation facilities. On the other hand, much effluent is expected from the desulfurization

equipments because it is discharged in proportion to exhaust gas treatment volume.

Numerical calculations require detailed planning, but the effluent volume from the entire IGCC is reduced

as a whole.

- 128 -

This project plans to newly construct the waste water treatment facilities in view of the capabilities of the

existing waste water treatment facilities. The effluent quality is determined unambiguously by the facility

capabilities and the environment will not deteriorate. Since there is no occurrence of effluent peculiar to

introduction of the IGCC power plant to the existing power generation system, there is no factor of

becoming worse than now.

The environmental impacts by effluent are determined by the effluent volume and the effluent quality by

the waste water treatment facilities. Quantitative evaluations are difficult at this moment, but the

environment improvement effects of the water quality are expected of the IGCC because effluent

reduction is estimated. It is conceivable that underground water has run from the coal in the coal stockpile,

but since there is no simple expansion for introduction of the IGCC power plant, there is no factor of

becoming worse than now.

3) Applicability of the CDM

Thailand has ratified the UN Framework Convention on Climate Change (UNFCCC) and Kyoto Protocol.

Since the Kyoto Protocol regards Thailand as a developing country, it is the target country of the CDM. At

the time of conducting this investigation, no policy incentives have been set because Thailand has no

greenhouse gas reducing obligations or emission restrictions. The Thai government, however, is

concerned with the UNFCCC and considering a regulatory framework. Its specific approaches are as

follows.

Firstly, the Ministry of Finance is considering introduction of a carbon tax in the future. For instance, it has

started discussions on revamping a vehicle tax to the car manufacturers based on CO2 emissions instead of

engine size.

The government has been preparing a charging system for NOx, SOx, etc. It tries to support an

environmental fund by charging to emission gases, thereby diffusing and promoting a clean energy

project.

Furthermore, the Department of Mineral Fuels under the Ministry of Energy has started considering CO2

capture and storage (CCS). Although the government policies have not been determined, there are

growing interests.

As it is clear from either approach, the Thai government has been focusing on the UNFCCC to promote

various approaches. Furthermore, given that Thailand has a track record of concluding the CDM case,

applicability of the CDM is likely.

In the existing CDM system and methodology, however, the ACM001327 will be applied to new

construction of a coal-fired power plant. The application conditions mentioned in this ACM0013 require

that the electric energy generated with the target fuel exceed 50% of the total generated energy of the

target country or region. For this reason, the existing CDM cannot be applied. On the other hand, Japan

has started negotiations with a host country toward conclusion of the bilateral offset credit system,

27 Consolidated baseline and monitoring methodology for new grid connected fossil fuel fired power plants using a less Greenhouse Gas (GHG) intensive technology

- 129 -

centering around the Asian countries. Negotiations with Thailand are scheduled to start in the future and

new construction of a high-efficiency coal-fired power plant is expected to be the target of the bilateral

offset credit system. Chapter 5 estimates economic effects resulting from conclusion of the bilateral credit.

(3) Effects on Environmental and Social Aspects Consequent upon Project Implementation

a) Results of examining the environmental and social consideration items

1) Examination by the JICA Guidelines for Environmental and Social Considerations

The following examines the environmental and social consideration items according to the JICA

Guidelines for Environmental and Social Considerations “Appendix 4. Screening Form” and “Check

List.” Non-environmental and social consideration items are omitted. Table 4-7 shows the results of

utilizing the Check List.

Check results of utilizing “Appendix 4. Screening Form”

The case name, project implementation period, project implementing agent, etc. on Page 1 of Appendix 4

are omitted.

Question 1. Describe the location of the project site.

Omitted

Question 2. Brief the project scale and information (rough development area, facility area,

production volume, power generation, etc.).

2-1 Overview of the project (project scale and information)

Omitted

2-2 How did you confirm the necessity of the project? Is the project consistent with an upper-level

plan?

Omitted

2-3 Did you consider an alternative proposal before requesting?

Omitted

2-4 Did you have discussions with the stakeholders for confirming the necessity before requesting?

□ Yes ■ No

If Yes, check the box for the appropriate stakeholders.

□ Ministries concerned □ Local residents □ NGO □ Others ( )

Question 3. Is the project newly launched or already existing? If already existing, have you received

strong complaints from the local residents, or an improvement guidance or a construction cancellation order/shutdown order from the local environmental authority?

□ New □ Existing (with complaints, etc.) □ Existing (no complaints) ■ Others (Already existing, but the applied technology is new. The existing project has installed

the desulfurization equipments based on the past background to enhance the environmental performance. As a result, there are no more strong complaints, etc.)

- 130 -

Question 4. Is environmental impact assessment (EIA, IEE, etc.) required in your national systems as to the project? If yes, is it being implemented or planned? Describe the reason, if required.

■ Required (□ Already implemented ■ Being implemented/planned) (Reason if required: In implementing the project, deliberations are required based on a feasibility investigation and EHIA report in order to obtain approvals from the Ministry of Energy, Energy Policy & Planning Office (EPPO) and regulatory authority concerned.)

□ Not required □ Others ( ) Question 5. If the environment impact assessment is already in place, has environment assessment

been examined and approved based on the environment assessment system? If already approved, describe the date of approval and authorization agency.

□ Approved (with no strings) (Approved on; Authorization agency: ) □ Approved (with strings) (Approved on; Authorization agency ) □ Under examination □ Under implementation ■ Procedures not started yet □ Others ( )

Question 6. If additional approvals and licenses related to the environmental and social aspects are

required other than the environment assessment, describes their names. Have they been already obtained?

□ Obtained □ Required, but not obtained yet □ Not required ■ Others (Necessary to check and discuss the necessity of individual approvals and licenses

such as an agreement on pollution prevention with the stakeholders since the environmental equipments were additionally installed in the past.) (Approval and license names: )

Question 7. Are there the following “susceptible areas” in or around the project site?

■ YES □ NO □ National park and nationally designated protected area (nationally designated coastal area,

swamp, area for minority/indigenous people, cultural asset, etc.) ■ Primeval forest and tropical natural forest □ Ecologically important habitat (coral reefs, mangrove coast, mudflats, etc.) □ Habitat of precious species required to be protected by a domestic act, international treaty,

etc. □ Area subject to large-scale salt accumulation or soil erosion. □ Area strongly apt to desertification. □ Area having an archeologically, historically or culturally peculiar value. □ Living area of minority/indigenous people, nomads having a traditional living style, or an

area having a special social value.

Question 8. Are the following elements planned or assumed in the project?

□ YES ■ NO □ Non-voluntary relocation of residents (Scale: households , persons) □ Large-scale pumping of underground water (Scale: m3/year) □ Large-scale landfill, land development, cultivation (Scale: ha) □ Large-scale deforestation (Scale: ha)

Question 9. May the project have an adverse effect on the environment and society?

□ YES ■ NO □ Air pollution

- 131 -

□ Water contamination □ Soil contamination □ Waste materials □ Noise and vibrations □ Land subsidence □ Foul odor □ Topography and geology □ Bottom sediment □ Living organisms and ecological system □ Utilization of water □ Accidents □ Global warming □ Non-voluntary relocation of residents □ Local economy such as employment and livelihood □ Utilization of land and local resources □ Social organizations such as social capitals and local decision-making bodies □ Existing social infrastructure and social services □ Poverty group, indigenous//minority people □ Uneven distribution of harms and profits □ Conflict of interests in the area □ Gender □ Children’s rights □ Cultural assets □ Infectious diseases such as HIV/AIDS □ Others ( ) Overview of related social impacts: ( )

Question 10. (In case of load aid) Is the case incapable of identifying the project at this moment (for

example, two-step loan, sector loan, etc. incapable of identifying the project at the time of agreement)?

Omitted

Question 11. Disclosure of information and discussions with local stakeholders

When environmental and social considerations are required, do you agree to disclosing the information and having discussions with the local stakeholders according to the JICA Guidelines for Environmental and Social Considerations?

Omitted

- 132 -

Table 4-7 Check Lists for Environmental Matters on Thermal Power Plant Projects (from the JICA web site) C

ateg

ory

Environmental Items Main Check Items Yes:Y

No:NConfirmation of Environmental and Social

Considerations

(1) EIA and environmental Permits

(a) Have EIA reports been completed? (b) Have EIA reports been approved by authorities of the host country’s

government? (c) Have EIA reports been unconditionally approved? If conditions are imposed on

the approval of EIA reports, are the conditions satisfied? (d) In addition to the above approvals, have other required environmental permits

been obtained from the appropriate regulatory authorities of the host country’s government?

(a)N

(b)N

(c)N

(d)N

(a) According to Thai regulations, an EHIA (Environmental and Health Impact Assessment) report is required for the project.

(b)(c)(d) Future action.

(2) Explanation to the Public

(a) Are contents of the project and the potential impacts adequately explained to the public based on appropriate procedures, including information disclosure? Is understanding obtained from the public?

(b) Are proper responses made to comments from the public and regulatory authorities?

(a)N

(b)N(a)(b) Future action.

1. P

erm

its a

nd E

xpla

natio

n

(3) Alternative project (a) Have several alternatives been studied for this project? (including study on

environmental and social considerations) (a)Y

(a) Alternatives of installing pulverized coal boilers are studied briefly.

2. M

itiga

tion

mea

sure

s

(1) Air Quality

(a) Do air pollutants, such as sulfur oxides (SOx), nitrogen oxides (NOx), and soot and dust emitted by power plant operations comply with the country’s emission standards? Is there a possibility that air pollutants emitted from the project will cause areas that do not comply with the country’s ambient air quality standards?

(b) In the case of coal-fired power plants, is there a possibility that fugitive coal dust from coal piles, coal-handling facilities, and dust from coal ash disposal sites will cause air pollution? Are adequate measures taken to prevent the air pollution?

(a)Y

(b)Y

(a) Technical specification of IGCC can comply with the Thai emissions standards for new power stations.

(b) Mining section of Mae Moh power station spread water on coal piles periodically for preventing spontaneous ignition and it has an effect on reducing fugitive coal dust.

- 133 -

Cat

egor

y



Considerations

(2) Water quality

(a) Do effluents including thermal effluents from the power plant comply with the country’s effluent standards? Is there a possibility that the effluents from the project will cause areas that do not comply with the country’s ambient water quality standards or cause a significant temperature rise in the receiving waters?

(b) In the case of coal-fired power plants, do leachates from coal piles and coal ash disposal sites comply with the country’s effluent standards?

(c) Are adequate measures taken to prevent contamination of surface water, soil, groundwater, and seawater by the effluents?

(a)Y

(b)NA

(c)NA

(a) The effluent from the IGCC Power Plant will be within the Thai effluent standards, due to the effluent treatment facilities, and to release effluent after checking the water quality.

(b) Mining section of Mae Moh power station continuously monitor based on environmental regulations, but this project have no plan of extension on coal mining area.

(c) ditto.

(3) Wastes

(a) Are wastes, (such as waste oils, and waste chemical agents), coal ash, and by-product gypsum from flue gas desulfurization generated by the power plant operations properly treated and disposed of in accordance with the country’s standards?

(a)Y

(a) The wastes generated by IGCC operation will be treated in the same way with in existing Mae Moh Power Station. All regulations are already complied.

(4) Noise and Vibration (a) Do the noise and vibration accompanying operation meet the country's

standards? (a)Y

(a) The noise and vibration generated by IGCC operation will be complied with Thai standards treated in the same way with in existing Mae Moh Power Station. All regulations are already complied.

The Mae Moh Power Station is huge. The construction site of this project is limited and there are no residential areas close to the construction site, so there is no effect on the local area from noise and vibration.

(5) Subsidence (a) In the case of extraction of a large volume of groundwater, is there a possibility

that the extraction of groundwater will cause subsidence? (a)N

(a) There will be no use of groundwater to cause land subsidence. All water is supplied from existing reservoir.

(6) Odor (a) Are there any odor sources? Are adequate odor control measures taken? (a)N

(a) No chemical that would cause odors will be used. Mae Moh Power Station monitors odor periodically.

- 134 -

Cat

egor

y



Considerations

(1) Protected Areas (a) Is the project site located in protected areas designated by the country’s laws or

international treaties and conventions? Is there a possibility that the project will affect the protected areas?

(a)NA

(a) EGAT has been preparing EHIA for another new project in Mae Moh Power Station. This situation will be studied in the EHIA.

3. N

atur

al E

nvir

onm

ent

(2) Ecosystem

(a) Does the project site encompass primeval forests, tropical rain forests, ecologically valuable habitats (e.g., coral reefs, mangroves, or tidal flats)?

(b) Does the project site encompass the protected habitats of endangered species designated by the country’s laws or international treaties and conventions?

(c) If significant ecological impacts are anticipated, are adequate environmental protection measures taken to reduce the impacts on ecosystem?

(d) Is there a possibility that the amount of water (e.g., surface water, groundwater) used by the project will adversely affect aquatic environments, such as rivers? Are adequate measures taken to reduce the impacts on aquatic environments, such as aquatic organisms?

(e) Is there a possibility that discharge of thermal effluents, intake of a large volume of cooling water or discharge of leachates will adversely affect the ecosystem of surrounding water areas?

(a)Y

(b)NA

(c)NA

(d)NA

(e)NA

(a) The existing site is located in the mining district. Mining district is surrounded by forests. This forest will be studied whether it is important ecologically or not in the EHIA report.

(b)(c) EGAT has been preparing EHIA for another new project in Mae Moh Power Station. These situations will be studied in the EHIA.

(d)(e) EGAT has been preparing EHIA for another new project in Mae Moh Power Station. However, amount of intake and discharge water would be reduced when this project is realized.

- 135 -

Cat

egor

y



Considerations

4. S

ocia

l Env

iron

men

t

(1) Resttlement

(a) Is involuntary resettlement caused by project implementation? If involuntary resettlement is caused, are efforts made to minimize the impacts caused by the resettlement?

(b) Is adequate explanation on relocation and compensation given to affected persons prior to resettlement?

(c) Is the resettlement plan, including proper compensation, restoration of livelihoods and living standards developed based on socioeconomic studies on resettlement?

(d) Is compensation money handed over before relocation? (e) Is philosophy of compensation described in the paper? (f) Does the resettlement plan pay particular attention to vulnerable groups or

persons, including women, children, the elderly, people below the poverty line, ethnic minorities, and indigenous peoples?

(g) Are agreements with the affected persons obtained prior to resettlement? (h) Is the organizational framework established to properly implement

resettlement? Are the capacity and budget secured to implement the plan? (i) Is there any complaint processing system?

(a)N

(b)N

(c)N

(d)N

(e)N

(f)N

(g)N

(h)N

(i)N

(j)N

(a) - (j) There will be no resettlement.

- 136 -

Cat

egor

y



Considerations

(2) Living and Livelihood

(a) Is there a possibility that the project will adversely affect the living conditions of inhabitants? Are adequate measures considered to reduce the impacts, if necessary?

(b) Is sufficient infrastructure (e.g., hospitals, schools, roads) available for the project implementation? If existing infrastructure is insufficient, is a plan developed to construct new infrastructure or improve existing infrastructure?

(c) Is there a possibility that large vehicle traffic associated with the project will affect road traffic in the surrounding areas? Are adequate measures considered to reduce the impacts on traffic, if necessary?

(d) Is there a possibility that diseases (including communicable diseases, such as HIV) will be introduced due to immigration of workers associated with the project? Are adequate considerations given to public health, if necessary?

(e) Is there a possibility that the amount of water used (e.g., surface water, groundwater) and discharge of thermal effluents by the project will adversely affect existing water uses and uses of water areas (especially fishing)?

(a)N

(b)Y

(c)N

(d)N

(e)N

(a) EGAT has been preparing EHIA for another new project in Mae Moh Power Station. These situations will be studied in the EHIA. However, Mae Moh Power Station is within huge Mae Moh Mining district and residential area is not close to the mining district.

(b) Existing Mae Moh Power Station has already provided sufficient infrastructure.

(c) There will be little increase in the number of vehicles over the current level of traffic during the construction work. So there will be no impact on the traffic on local roads.

(d) Safety promotion meetings will be held by related personnel in regard to the implementation of the construction work, and every effort will be made to ensure the comprehensive safety management and safety education of workers and the protection of public health.

(e) There will be no particular impact.

(3) Heritage (a) Is there a possibility that the project will damage the local archeological,

historical, cultural, and religious heritage sites? Are adequate measures considered to protect these sites in accordance with the country’s laws?

(a)NA(a) EGAT has been preparing EHIA for another new

project in Mae Moh Power Station. This situation will be studied in the EHIA.

(4) Landscape (a) Is there a possibility that the project will adversely affect the local landscape?

Are necessary measures taken? (a)N

(a) EGAT already constructed flower park on the old ash dumping area. EGAT has been taken such kind of environmental improvement at Mae Moh Power Station.

- 137 -

Cat

egor

y



Considerations

(5) Ethnic minority, indigenous people

(a) Is there any consideration that reduces affects on culture and lifestyle of ethnic minority and indigenous people?

(b) Dose this project make consideration on the indigenous right of ethnic minority and indigenous people?

(a)NA

(b)NA(a)(b) There is no ethnic minority and indigenous

people near this project site.

(6) Working environment

(a) Dose this project comply with national regulations regarding to working environment?

(b) Dose this project consider the industrial accident prevention by hardware side such as installing safety equipment and managing hazardous substance?

(c) Dose this project manage the safety and health of project authorized people via software method such as making safety and health management plan and educating safety lectures to workers (including traffic safety and sanitation)?

(d) Dose this project consider the prevention method when the guard assigned this project affect adversely on the project authorized people and circumstances?

(a)Y

(b)Y

(c)Y

(d)N

(a) – (c) Safety promotion meetings will be held by related personnel in regard to the implementation of the construction work, and every effort will be made to ensure the comprehensive safety management and safety education of workers and the protection of public health.

(d) The guard will not affect adversely in Thailand.

(1) Impacts during Construction

(a) Are adequate measures considered to reduce impacts during construction (e.g., noise, vibrations, turbid water, dust, exhaust gases, and wastes)?

(b) If construction activities adversely affect the natural environment (ecosystem), are adequate measures considered to reduce impacts?

(c) If construction activities adversely affect the social environment, are adequate measures considered to reduce impacts?

(a)Y

(b)N

(c)N

(a) Mae Moh Power Station will be monitored in accordance with Thai regulations. Constructors of this project have an obligation to comply with these regulations.

(b) There will be no impact on the natural environment, as the project will construct power plant within mining district.

(c) The construction site is in the mining district, so there will be no effect on the social environment.

5. O

ther

s

(2) Accident Prevention Measures

(a) In the case of coal-fired power plants, are adequate measures planned to prevent spontaneous combustion at the coal piles? (e.g., sprinkler systems).

(a)Y(a) Existing Mae Moh Power Station have already

equip such kind of system, and this project will use existing coal piles.

- 138 -

Cat

egor

y



Considerations

(3) Monitoring

(a) Does the proponent develop and implement monitoring program for the environmental items that are considered to have potential impacts?

(b) Are the items, methods and frequencies included in the monitoring program

judged to be appropriate? (c) Does the proponent establish an adequate monitoring framework (organization,

personnel, equipment, and adequate budget to sustain the monitoring framework)?

(d) Are any regulatory requirements pertaining to the monitoring report system

identified, such as the format and frequency of reports from the proponent to the regulatory authorities?

(a)Y

(b)NA

(c)Y

(d)Y

(a) Air:

A device will be installed in the flue to measure air pollutants continuously, which will be monitored at all times in the central control room. There are already air quality measurements being made in the vicinity of mining district. These measurements will be continued in the future.

Water quality:

EGAT already monitor water quality in accordance with Thai regulations. These measurements will be continued in the future.

Noise:

Measurements of noise are maybe already being made at important locations in the vicinity of the mining district. These measurements will be continued in the future.

During construction:

As necessary, air and water quality, noise and vibration will be appropriately monitored or measured on the construction site.

(b) These measures are considered to be appropriate.

(c) EGAT will manage monitoring system in the same way of another new project for Mae Moh Power Station.

(d) Reports are currently being made periodically.

- 139 -

Cat

egor

y



Considerations

Reference to Checklist of Other Sectors

(a) Where necessary, pertinent items described in the Power Transmission and Distribution Lines checklist should also be checked (e.g., projects including installation of electric transmission lines and/or electric distribution facilities).

(b) Where necessary, pertinent items described in the Ports and Harbors checklist should also be checked (e.g., projects including construction of port and harbor facilities).

(a)N

(b)N

(a) Existing substation facilities are to be used.

(b) There will be no construction of port facilities.

6. N

ote

Notes on Using Environmental Checklist

(a) If necessary, the impacts to transboundary or global issues should be confirmed (e.g., the project includes factors that may cause problems, such as transboundary waste treatment, acid rain, destruction of the ozone layer, and global warming).

(a)Y(a) Emissions of greenhouses gases (carbon dioxide)

will be reduced due to the improvement in efficiency.

(Source) Prepared by Study Team based on JICA web site

- 140 -

2) Examination by the JBIC Guidelines for Confirmation of Environmental and Social Considerations

The following examines the environmental and social consideration items according to the Japan Bank

for International Cooperation (JBIC) Guidelines for Confirmation of Environmental and Social

Considerations, Reference Materials “Screening Form” and “Check List.”

Since the JICA Guidelines for Environmental and Social Considerations implemented in 1) have been

prepared based on the JBIC Guidelines, there are many duplications between them. The following

describes the results of examination except for the duplications.

Of the results of utilizing the Check List, Table 4-8 shows those except for the duplications.

Check results of utilizing the “Screening Form”

The case name, project implementation period, project implementing agent, etc. on Page 1 are

duplicated.

Questions

Questions 1 to 8

Duplicated

Question 9. Are the following elements planned in the project?

Duplicated

If Yes, describe the scale of appropriate characteristics and answer Question 10 and the rest.

If No, answer Question 11 and the rest. □ (1) Non-voluntary relocation of residents (Scale: persons) □ (2) Pumping of underground water (Scale: m3/year) □ (3) Landfill, land development, cultivation (Scale: ha) □ (4) Deforestation (Scale: ha)

Question 10. If any one of the above-mentioned elements is applicable, are there any scale

requirements for the “elements described in Question 9 in the country where the project is to be implemented? If any, does the project satisfy those requirements?

□ Serves as the basis. ■ Does not serve as the basis. □ Others ( )

Question 11. Does the aid of the JBIC or Nippon Export and Investment Insurance account for 5%

or less of the total project cost or is the amount of aid equivalent to 10,000,000 SDR or less in yen?

Omitted Question 12. Does the project have only minor environmental impacts or no foreseeable

environmental deterioration (for example, the maintenance project of the existing facilities, rehabilitation without expansion, and acquisition of interests without additional facility investments)?

(No)

If Yes, you do not need to answer the following questions.

If No., answer Question 13 and the rest.

- 141 -

Question 13. Does the project fall under the categories of the following specific sectors?

(Yes)

If Yes, check the box for the appropriate sector and answer Question 14.

If No, you do not need to answer the following questions. □ (1) Mine □ (2) Oil and natural gas development □ (3) Pipeline □ (4) Steel industry (including large furnaces) □ (5) Nonferrous metal refining □ (6) Petrochemistry (raw material production, including an industrial complexes) □ (7) Petroleum refining □ (8) Oil, gas and chemical material terminals □ (9) Paper and pulp □ (10) Production and transportation of harmful and hazardous materials (those

provided by the international treaties, etc.) ■ (11) Thermal power generation □ (12) Nuclear power generation □ (13) Hydroelectric generation, dams and reservoirs □ (14) Power transmission/transformation and power distribution (accompanied by

large-scale non-voluntary relocation of residents, large-scale deforestation, and undersea power transmission lines)

□ (15) Roads, railways and bridges □ (16) Airports □ (17) Ports and harbors □ (18) Sewage and effluent treatment (including the characteristics liable to affect or

located in an susceptible area) □ (19) Waste material treatment and disposal □ (20) Agriculture (accompanied by large-scale cultivation and irrigation) □ (21) Forestry, forestation □ (22) Tourism (hotel construction, etc.)

Question 14. Duplicated

- 142 -

Table 4-8 Check Lists for Environmental Matters on Thermal Power Plant Projects

(from the JBIC web site, excluding same questions of JICA guidline) 2.

Miti

gati

on

mea

sure

s

(4) Noise and Vibration

In the case of coal-fired power plants, are the facilities for coal unloading, coal storage areas, and facilities for coal handling designed to reduce noise?

Existing coal handling facilities will be used. These equipments comply with Thai environmental regulations.

(1) Impacts during Construction

If necessary, is health and safety education (e.g., traffic safety, public health) provided for project personnel, including workers?

As necessary, safety and environmental education will be provided by the EGAT.

5. O

ther

s

(2) Accident Prevention Measures

Are adequate accident prevention plans and mitigation measures developed to cover both the soft and hard aspects of the project, such as establishment of safety rules, installation of prevention facilities, and equipment, and safety education for workers? Are adequate measures for emergency response to accidental events considered?

Safety promotion meetings will be held by related personnel in regard to the implementation of the construction work, and every effort will be made to ensure the comprehensive safety management and safety education of workers and the protection of public health. The fuel facilities and fire prevention measures such as firefighting system at the Mae MohPower Station comply with Thai standards.

6. N

ote

Notes on Using Environmental Checklist

In the case of coal-fired power plants, the following items should be confirmed: Are coal quality standards established? Are the electric generation facilities planned by considering coal quality?

Coal quality forecast are given for this project. Power generation facilities will be specified to design complying with this coal specification.

(Source) Prepared by Study Team based on JBIC web site

b) Comparison with other options having less environmental and social impacts

The proposed project (IGCC installation project) has the highest environmental performance among the

commercial equipments as a coal-fired power generation system. Namely, there are two possible

non-coal-fired alternatives as options having less environmental and social impacts; they are 1) fuel

conversion and 2) installation of renewable energy. An idea of stopping the coal-fired power plant

having high environmental impacts is only a deskbound discussion and not worth consideration as a

counter proposal. The following describes and considers the possible options, respectively.

Alternative 1: Fuel conversion to coal with lower sulfur content or natural gas.

Alternative 2: Shift to a renewable energy-based power plant.

Alternative 1: Fuel conversion to imported coal with lower sulfur content or natural gas

The lignite used at the Mae Moh Thermal Power Plant as main fuel is one of few valuable energy

resources producible in Thailand. The Mae Moh Thermal Power Plant is the only coal-fired power

plant owned by the EGAT. Since it is located next to the Mae Moh Coal Mine, It is situated very far

- 143 -

from a coastal line.

Given this fact, when the fuel is converted from the lignite to the imported fuel, etc., there are

concerns about many problems in social considerations such as development of infrastructure for

import, land expropriation and traffic problems due to fuel transportation.

Alternative 2: Shift to a renewable energy-based power plant

Introduction of renewable energy is desirable from a viewpoint of environment improvement.

Thailand is also promoting utilization of renewable energies such as solar power generation and

wind power generation.

When considering as an alternative, however, it is not easy to fully replace the total generated

energy of the existing coal-fired power plants with renewable energy, requiring enormous cost and

time. Since renewable energies such as solar power generation and wind generation have lower

energy density than fossil fuels and are greatly susceptible to a natural environment, they cannot be

expected to play a role of a stable base power source such as the exiting lignite-fired power plants.

Accordingly, they can reduce SO2 and CO2 emissions by lowering coal consumption at the existing

coal-fired power plants, but cannot be considered as an alternative project.

As mentioned above, this alternative is expected to have merits from an environmental viewpoint, but

has much more demerits and risks in social impacts than the proposed project.

Accordingly, in order to inhibit SO2 emissions during a limited period without having a negative effect

on current supply-demand of electric power and social circumstances in Thailand, this proposal of the

IGCC power generation facilities installation project is evaluated to be the best and optimum project.

c) Discussions, etc. with the implementing agency

Since the organization of the project is determined based on the form of financing, the implementing

agency of this project cannot be identified at this moment, but it is expected that the EGAT will play a

significant role. Accordingly, discussions have been repeatedly held with the EGAT from the beginning

of this investigation, and the EGAT also organized a team for this investigation and has been executing

the work in a concerted manner.

In order to replace the preceding Mae Moh Thermal Power Plant, Units 4 to 7, the EGAT has already

started the EHIA procedures. In implementing this project, there is no particular difference in the

environmental impact values by the current power generation facilities, social and environmental aspects,

and ecological system. Accordingly, the supposed stakeholders are the same.

According to the JICA and JBIC environmental guidelines, the supposed stakeholders are largely

divided into the ministries concerned, local residents and NGOs. The EGAT has already started

discussions such as inviting the local residents to the Mae Moh Coal Mine and Power Plant to hold an

explanatory meeting.

- 144 -

The EHIA related information has been obtained accordingly at the time of conducting this investigation.

Since the EGAT’s current object persons of discussions directly become the stakeholders of this project,

continuous collaboration with the EGAT’s investigation teat allows collection of necessary information.

(4) Overview of Related Laws and Regulations for Environmental and Social Considerations in Host Country

a) Overview of the related laws and regulations for the environmental and social considerations

concerning project implementation

Chapter 4, Paragraph (3) shows the results of examination according to the JICA Guidelines for

Environmental and Social Considerations, “Appendix 4. Screen Form” and “Check List” and those of

examination according to the JBIC Guidelines for Confirmation of Environmental and Social

Considerations, Reference Materials “Screen Form” and “Check List.”

Based on the result of examination, it is necessary to clear compliance with various environmental

criteria, implementation of environmental impact assessment and discussions with the stakeholders. The

relevant environmental criteria, which should be satisfied as specific numerical values in implementing

the project, are as shown in Chapter 4, (1) a) “Analysis of the current situation.”

In Thailand, the Ministry of Energy holds jurisdiction over authorization of project implementation, and

the Ministry of Natural Resources and Environmental holds jurisdiction over the environmental

regulations for the projects such as EHIA. The latter also holds jurisdiction over the environment-related

laws and regulations.

All the environment-related laws and regulations can be satisfied by clearing the procedures with each

stakeholder including the ministries concerned according to a predetermined operation flow.

As a matter of course, it is necessary to maintain the same environment management system as the

current Mae Moh Thermal Power Plant even after starting shared use. The following shows an

environment assessment flow.

b) Details of EIA (Environmental Impact Assessment) of the host country required for project

implementation

Figure 4-3 shows the EGAT’s standard flow in constructing a power plant in Thailand. In order to realize

the project, it is necessary to obtain approvals from those concerned according to the procedural flow in

Figure 4-3. It includes examination of the EHIA report; The EHIA is a form requested in starting a study

on replacement of the Units 4 to 7 at the Mae Moh Thermal Power Plant. Health requirements have been

added to the former EIA.

The Pollution Control Department of the Ministry of Natural Resources and Environmental holds

jurisdiction over the legal basis of the current procedures, and the name of the act is “Enhancement and

Conservation of National Environmental Quality Act B.E. 2535 (abbreviated as NEQA1992).” The

EHIA is specifically provided by Chapter III. Environmental Protection, Part 4. Environmental Impact

- 145 -

Assessment of the NEQA1992.

Those applying for project implementation have to investigate and analyze the matters concerning

construction of the thermal power plant as to the pollution prevention items provided by the NEQA1992

before project implementation, summarize as the EHIA and obtain approvals from the regulatory

authorities. A monitoring period is generally one year, but it is assumed that about two years are

normally required, including all such as the results of EGAT’s hearings, monitoring, analyses,

considerations, discussions with the stakeholders, and approvals from the ministries concerned.

Figure 4-3 Project Approval Process

EHIA Report


(5) Matters to Be Accomplished by Host Country (Implementing Agency and Other Authorities Concerned) for Realization of Project

According to consideration of technological feasibility of this project, construction of the IGCC power

generation facilities at the Mae Moh Thermal Power Plant is very reasonable from viewpoints of

operational aptitude to variations of coal properties such as CaO, high environment performance, high

plant efficiency, etc. Despite technological superiority, however, this project does not have high

- 146 -

economic efficiency as a general investment project. Accordingly, it is necessary to consider not only the

measures to maximize the economic efficiency of this project, such as application of the bilateral credit,

but project formation by a PPP scheme.

Namely, the Thai government and implementing agency are expected to immediately implement the

following as the conditions for promoting this project.

(1) Cooperation of the implementing agency for environmental assessment and necessary

explanations to the local residents.

(2) Support for and promotion of acquisition of approvals and licenses according to the

procedural flow in Figure 4-3.

(3) Discussions with the stakeholders.

Chapter 5 Financial and Economic Evaluation

- 148 -

(1) Project Cost Integration

a) Plant construction cost

1) Construction cost calculating method and cost base

The range of estimate of this project shall be as shown in Figure 3-19, “Facility Configuration Diagram

of Coal-Fired IGCC Plant” The calculating method and the cost base are as follows:

The costs of the primary equipment for a coal gasification facility were calculated by

reference to the cost data that was received mainly from the licensor.

The costs of coal pretreatment, complex power generating, and air separation facilities were

estimated, inquired, and calculated.

The costs of sulfur recovery system CT-121 and the integrated effluent treatment facility were

calculated using abundant track record data owned by Chiyoda Corporation.

For any other facilities, the equipment costs were calculated from the equipment list by using an

approximate integration tool customized by Chiyoda Corporation and Aspentech’s Cost Estimation

Software, and the materials and construction costs were calculated, taking the layout drawing and the

process flow information into account. For the total cost, in-house data accumulated in Chiyoda

Corporation was reflected to the value. This estimate is based on the assumption that construction of the

plant will begin in December 2011 in Thailand.

2) Plant construction cost

Plant construction cost: US$1,400 million

For overseas procurement, the exchange rates used were ¥78.13/US$ and €0.79/US$.

The plant construction cost will need to be considered in more detail in subsequent investigations.

b) Required operators

A total of 62 operators are assumed to work in a 5-group shift system, reflecting the track record of the

IGCC plants currently operating in Shell Buggenum and the information about the coal drying facility

vendors. The base of assumption is as follows:

1 shift supervisor per group

9 operators per group (control room and site personnel)

1 process engineer on day duty

9 maintenance engineers on day duty (electrical, control, and mechanical engineers)

1 test analyzer on day duty

1 support personnel on day duty

c) Maintenance/service cost

Three percent of the construction cost was assumed for the maintenance and service costs based on the

track record of operation in the Shell Buggenum plant and others currently in operation, experiences of

the equipment vendors, and the information accumulated in Chiyoda Corporation.

- 149 -

(2) Outline of Results of Preparatory Financial and Economic Analyses

a) Results of financial analysis

The results of an analysis are outlined below with respect to the two types as detailed previously:

oxygen- and air-blown IGCC.

1) Evaluating method

In this project, we plan to establish and conduct a Japan-Thailand joint corporation, organized by a

Japanese trading company, electric power company, the EGAT, and others, in order to set up the power

generation business with the IGCCs.

The joint corporation will purchase the fuel, i.e. lignite from the EGAT, and will earn revenue by selling

generated electricity to the EGAT. In considering the economic efficiency of this project, one of the

points will be the electricity selling price (i.e. the price at which the EGAT will purchase the power).

For this reason, financial evaluation was made by comparing the internal rate of return that was obtained

assuming that the electricity selling price is US$0.05 to 0.12/kWh, with the opportunity cost of the

capital to be invested in this project (weighted average cost of capital: WACC).

2) Results of analysis of the FIRR obtained if an oxygen-blown coal IGCC is introduced

Assumptions

The following assumptions were made:

a. Scale and operation status of IGCC plant facility

Gross plant output: 500MW

Net plant output: 425MW

Availability: 85%

Net Plant efficiency: 41.5%

Gross generated electricity: 3,723GWh

Net generated electricity: 3,165GWh

b. Cash flow

Construction time: 5 years

Operating period: 25 years

Depreciation period: 25 years (fixed)

Construction funds payback grace period: 5 years

Construction funds payback period: 10 years

Equity ratio: 25%

c. Construction cost

Gross construction cost: US$2,800/kW

Net construction cost: US$3,294/kW

Construction cost: US$1,400 million

¥109.4 billion (ex-rate: ¥78.13/US$)

- 150 -

d. Fixed cost

Fixed asset tax rate: 0.1% (VS book value)

Insurance rate: 0.75% (VS book value)

Maintenance/service cost: 3.0% (VS construction cost)

Number of operators: 62 (manager 5 persons, operator 57

persons)

Unit labor: 150,000 baht/person/month (manager)

50,000 baht/person/month (operator)

e. Variable cost

Amount of lignite used: 250.3 t/h

Price of lignite: 775 baht/t

Limestone: 17.8 t/h

Price of limestone: 187 baht/t

Kaolin: 17.8 t/h

Price of kaolin: 187 baht/t

Industrial water: 570 t/h

Price of industrial water: 3.81 baht/m3

Circulating cooling water: 345 t/h (The amount resupplied is

assumed to be 1% of the circulation

flow volume.)

Price of circulating cooling water: 3.81 baht/m3

Boiler feedwater: 51 t/h

Price of boiler feedwater: 61.35 baht/m3

f. Sales of finished goods

Amount of electricity sold: Annually 3,165 GWh

Electricity selling price: US$0.05 to 0.12/kWh (sensitivity

analysis)

By-product:

Gypsum (sulfur recovery): 33.3 t/h

Fly ash: 12.2 t/day

Slag: 38.8 t/day

Price of by-product:

Gypsum (sulfur recovery): 20 baht/t

Fly ash: 170 baht/t

Slag: 106 baht/t (disposal cost)

(currently not yet commercialized, and

shall be disposed of.)

g. Interest rates etc.

Interest rate of long-term debt: Annual rate 6.5%

Interest rate of JICA overseas financing: Annual rate 2.5% (assumed)

Corporate tax: 30％

Exchange rate: 32 baht/US$

- 151 -

Energy fund28: Annually 50,000 baht/MW (during

construction time)

0.02 baht/kWh

Project cost procurement and opportunity costs

Out of the necessary funds for this project, 25% of the total amount was decided to be procured by the

company’s own fund, and 75% of it by borrowing. The fund procurement conditions for the joint

corporation (e.g. borrowing interest rates) were assumed as listed in the tables below. The interest rates

and the like were assumed to be conditions where the joint corporation would get finance from

commercial banks in Thailand; the amortization rate of the joint corporation was assumed to be the

return that the EGAT would require when investing its capital in the new power generation business.

Table 5-1 lists the project cost procurement conditions, and Table 5-2 summarizes the financing plan and

opportunity costs.

Table 5-1 Project cost procurement conditions

Debt Equity of SPC

Interest rate / amortizatuon rate Annual rate 6.5% 10.0%

Repracement grace 5 years NA

Prepayment period 10 years NA


Table 5-2 Financing plan and opportunity costs

（million US$)

NO. year Debt Equity Total

1 2015 3.50 3.50 0.2%

2 2016 105.00 35.00 140.00 10.0%

3 2017 420.00 140.00 560.00 39.9%

4 2018 315.00 105.00 420.00 29.9%

5 2019 210.00 70.00 280.00 20.0%

1,050.00 353.50 1,403.50 100.0%

74.8% 25.2% 100.0%

Total

Debt Commitment Fee Equity WACC

Interest rate /amortizatuon rate

6.5% 0.375% 10.0% 7.7%


FIRR calculation results

Figure 5-1 shows the results of calculating the internal rate of return when the electricity selling price

was varied from US$0.05 to 0.12/kWh.

The obtained FIRRs offer a condition where US$0.089/kWh exceeds the WACC if the interest rate of

debt for borrowing from a commercial bank in Thailand is 6.5%. However, if low-interest financing is

28 Charged, as the power develop fund, to each coal fired power generation plant.

- 152 -

obtained utilizing JICA overseas financing (2.5% is assumed in this example), the WACC is exceeded if

the electricity selling price is US$0.070/kWh.

Table 5-4 shows the FIRR account that was obtained for an electricity selling price of US$0.08/kWh and

a discount rate of 4.5%. In this example, the NPV will be US$277 million, while the benefit/cost (B/C)

ratio will be 1.26.

Figure 5-1 FIRR calculation results (oxygen-blown IGCC)

0.050 0.2

0.055 1.5

0.060 2.6

0.065 3.6

0.070 4.6

0.075 5.5

0.080 6.3

0.085 7.1

0.090 7.9

0.095 8.7

0.100 9.4

0.105 10.1

0.110 10.7

0.115 11.4

0.120 12.0

　

Electricity selling price(US$/kWh)

FIRR(%)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

0.05 0.06 0.07 0.08 0.09 0.10 0.11 0.12

Electricity selling price（US$/kWh）

FIR

R（%）

WACC: 7.7%(Interest:6.5%)



Table 5-3 WACC resulting if low-interest financing is utilized such as JICA overseas financing



2.5% 0.100% 10.0% 4.5%

(Note) The interest rate of financing was assumed to be 2.5%. (Source) Prepared by Study Team

FIRR sensitivity analysis

An FIRR sensitivity analysis was conducted by varying the construction cost, which is anticipated to

come more inexpensive for some reason such as future technological development.

For an electricity selling price of US$0.08/kWh, a 10% decrease in the construction cost will improve

the FIRR from 6.3% to 7.5%, and a 20% decrease in this cost will improve it to 8.8%. If the construction

cost decreases by 25%, the FIRR is guaranteed to exceed the amount twice larger than the WACC

(4.5%) obtained when a low-interest loan will be utilized such as JICA overseas financing.

NPV

An NPV sensitivity analysis was conducted by varying the discount rate.

For an electricity selling price of US$0.08/kWh, the NPV will take a positive value at a discount rate of

6%. That is, it will satisfy the investment requirements. Similarly, for an electricity selling price of

- 153 -

US$0.07/kWh, the NPV will take a positive value at a discount rate of 4%, and for an electricity selling

price of US$0.09/kWh, it will take a positive value at a discount rate of 7%.

Figure 5-2 Results of the FIRR sensitivity analysis on the construction cost (oxygen-blown IGCC)

(US$/kW) (%) 0.09 0.08 0.07

1,960 70 12.2 10.3 8.3

2,100 75 11.3 9.5 7.6

2,240 80 10.5 8.8 6.9

2,380 85 9.8 8.1 6.2

2,520 90 9.1 7.5 5.6

2,660 95 8.5 6.9 5.1

2,800 100 7.9 6.3 4.6

2,940 105 7.4 5.8 4.1

3,080 110 6.9 5.4 3.7

Electricity selling price (US$/kWh)

Construction cost

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

70 80 90 100 110

Constraction cost (%)

FIR

R（%）

Electricity selling price 0.09US$/kWh




Figure 5-3 NPV (oxygen-blown IGCC)

Discount rate

(%) 0.09 0.08 0.07

2.0 1,284 892 500

3.0 936 604 271

4.0 658 374 89

5.0 434 190 -55

6.0 254 43 -169

7.0 109 -75 -259

8.0 -9 -170 -330

9.0 -104 -245 -387

10.0 -181 -306 -430

Electricity selling price (US$/kWh)

-500

0

500

1,000

1,500

2 4 6 8 10Discout rate (%)

NP

V (m

il. U

S$)





- 154 -

Table 5-4 FIRR account (oxygen-blown IGCC) Precondition

Generation Performance Investment cost Cost Revenue Tax, Interest, etc.

500 MW 2,800 USD/kW 3 % of EPC cost 0.08 USD/kWh 0.1% FIRR= 6.3%

425 MW 1,400 mil.USD 24.22 USD/ton 20 Baht/ton 30%

85 % 25 years 775 Baht/ton 170 Baht/ton 6.5% NPV= 277 mil.USD

Net efficiency 41.5 % straight line 187 Baht/ton insurance 0.75% of plant cost

3.5 mil.USD Limestone 187 Baht/ton 150,000 Ex-rate: 1Baht = 0.0313 USD B/C ratio= 1.26

75:25 Demin. water 61.35 Baht/m3 50,000

3.81 Baht/m3 Number of manage 5

25 years Disposal Cost 106 Baht/ton Number of operato 57 persons 4.5%

-5 -4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Byproduct

Sulfur (gypsum) mil. ton 33.3 ton/hour 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 0.248 6.199

Ash (fly ash) mil. ton 12.2 ton/day 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.095

Ash (slag) mil. ton 38.8 ton/hour (not sale, disposal) 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 0.289 7.223

Consumption

Fluxant (Kaoline) mil. ton 17.8 ton/hour 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 3.313

Limestone mil. ton 17.8 ton/hour 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 0.133 3.313

Industrial water mil. ton 570 ton/hour 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 4.244 106.106

Cooling water mil. ton 34,500 ton/hour (99% circulating) 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 64.222

Boiler water mil. ton 51 ton/hour 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 0.380 9.494

-5 -4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Net Capacity MW 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425 425

Availability ％ 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85

Electricity (net) GWh 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 3,165 79,114

Fuel consumption

Total Investment 3.5 140.0 560.0 420.0 280.0 1,403.5

(Feed) 3.5 3.5

Debt 0.0 105.0 420.0 315.0 210.0 1,050.0

Equity 3.5 35.0 140.0 105.0 70.0 353.5

Total Revenue 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3

Sales Electricity 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 253.2 6,329.1

Sales Sulfur (gypsum) 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 3.9

Sales Ash (fly ssh) 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.5

Sales Ash (slag) Disposal (not sale)

Total Cost 0.8 0.8 0.8 0.8 159.3 158.9 158.6 158.2 157.9 157.5 157.2 156.8 156.5 156.1 155.8 155.4 155.1 154.7 154.4 154.0 153.7 153.3 153.0 152.6 152.3 151.9 151.6 151.2 150.9 3,949.6

Fuel (coal) 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 45.1 1,128.4

Labor 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 33.8

Maintenance 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 42.0 1,050.0

Industrial water 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 12.6

Cooling water 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 7.6

Boiler water 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 18.2

Fluxant (Kaoline) 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 19.4

Limestone 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 19.4

Disposal Cost Ash slag 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 23.9

Depreciation 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 56.0 1,400.0

Fixed asset tax 1.4 1.3 1.3 1.2 1.2 1.1 1.1 1.0 1.0 0.9 0.8 0.8 0.7 0.7 0.6 0.6 0.5 0.4 0.4 0.3 0.3 0.2 0.2 0.1 0.1 18.2

Energy Fund 0.8 0.8 0.8 0.8 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 52.6

Insurance 70.0 % Plant coas ratio / total cost 7.4 7.1 6.8 6.5 6.2 5.9 5.6 5.3 5.0 4.7 4.4 4.1 3.8 3.5 3.2 2.9 2.6 2.4 2.1 1.8 1.5 1.2 0.9 0.6 0.3 165.6

Interest mil.USD 6.8 7.3 35.0 57.8 75.2 69.6 63.7 57.4 50.6 43.5 35.8 27.7 19.0 9.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Net Income -0.8 -0.8 -0.8 -0.8 94.1 94.4 94.8 95.1 95.5 95.8 96.2 96.5 96.9 97.2 97.6 97.9 98.3 98.6 99.0 99.3 99.7 100.0 100.4 100.7 101.1 101.4 101.8 102.1 102.5 2,453.8

Tax 28.2 28.3 28.4 28.5 28.6 28.7 28.9 29.0 29.1 29.2 29.3 29.4 29.5 29.6 29.7 29.8 29.9 30.0 30.1 30.2 30.3 30.4 30.5 30.6 30.7 737.1

After Tax -0.8 -0.8 -0.8 -0.8 65.9 66.1 66.3 66.6 66.8 67.1 67.3 67.6 67.8 68.1 68.3 68.6 68.8 69.0 69.3 69.5 69.8 70.0 70.3 70.5 70.8 71.0 71.2 71.5 71.7 1,716.8

Free Cash Flow mil.USD -3.5 -140.8 -560.8 -420.8 -280.8 121.9 122.1 122.3 122.6 122.8 123.1 123.3 123.6 123.8 124.1 124.3 124.6 124.8 125.0 125.3 125.5 125.8 126.0 126.3 126.5 126.8 127.0 127.2 127.5 127.7 1,713.3

B/C ratio NPV 4.5%

Benefit 3,014 0 0 0 0 0 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 6,333

Cost(including Investment)

2,390 4 141 561 421 281 103 103 103 102 102 102 101 101 100 100 100 99 99 99 98 98 98 97 97 97 96 96 96 95 95 3,883

Discount rate

Interest rate

persons

Investment cost Maintenance feeElectricity sellingprice

Corporate Taxrate

Fixed asset Taxrate

Sulfur sellingprice (Gypsum)

Ash selling price

Labor costmanager

mil.USD

Year

mil.USD

Depreciationperiod

Fuel (Coal) price

Gross output

Availability(Plant factor)

Net output

Discount rate

Depreciationmethod

Debt / Equityratio

Feed

Industrial water

Fluxant (Kaoline)

Baht/person/mounth

Labor costoperator

Calculation term

Baht/person/mounth

Total

mil.USD

TotalYear

mil.USD


- 155 -

3) Results of analysis of the FIRR obtained if an air-blown coal IGCC is introduced

Assumptions

The following assumptions were made:

a. Scale and operation status of IGCC plant facility

Gross plant output: 571.3MW

Net plant outpou: 505.4MW

Availability: 85%

Net plant efficiency: 43.4%

Gross Generated electricity: 4,254GWh

Net Generated electricity: 3,763GWh

b. Cash flow

Construction time: 5 years

Operating period: 25 years

Depreciation period: 25 years (fixed)

Construction funds payback grace period: 5 years

Construction funds payback period: 10 years

Equity ratio: 25%

c. Construction cost

Gross construction cost: US$2,800/kW

Net construction cost: US$3,165/kW

Construction cost: US$1,600 million

¥125.0 billion (ex-rate: ¥78.13/US$)

d. Fixed cost

Fixed asset tax rate: 0.1% (VS book value)

Insurance rate: 0.75% (VS book value)

Maintenance/service cost: 3.0% (VS construction cost)

Number of operators: 62 (manager 5 persons, operator 57

persons)

Unit labor: 150,000 baht/person/month (manager)

50,000 baht/person/month (operator)

e. Variable cost

Amount of lignite used: 285.4 t/h

Price of lignite: 775 baht/t

Limestone: 15.6 t/h

Price of limestone: 187 baht/t

Kaolin: 0 t/h

Price of kaolin: 187 baht/t

Industrial water: 570 t/h

Price of industrial water: 3.81 baht/m3

Circulating cooling water: 118 t/h (The amount resupplied is

assumed to be 1% of the circulation

flow volume.)

Price of circulating cooling water: 3.81 baht/m3

Pure water: 17 t/h

- 156 -

Price of pure water 61.35 baht/m3

f. Sales of finished goods

Amount of electricity sold: Annually 3,763 GWh

Electricity selling price: US$0.05 to 0.12/kWh (sensitivity

analysis)

By-product:

Gypsum (sulfur recovery): 29.2 t/h

Fly ash: 0 t/day

Slag: 38.5 t/day

Price of by-product:

Gypsum (sulfur recovery): 20 baht/t

Fly ash: 170 baht/t

Slag: 106 baht/t (disposal cost)

(currently not yet commercialized, and

shall be disposed of.)

g. Interest rates etc.

Interest rate of long-term debt: Annual rate 6.5%

Interest rate of JICA overseas financing: Annual rate 2.5% (assumed)

Corporate tax: 30%

Exchange rate: 32 baht/US$

Energy fund Annually 50,000 baht/MW (during

construction time)

0.02 baht/kWh

Project cost procurement and opportunity costs

Like the case of oxygen-blown IGCC, out of the necessary funds for this project, 25% of the total

amount was decided to be procured by the company’s own fund, and 75% of it by borrowing. The fund

procurement conditions for the joint corporation (e.g. borrowing interest rates) were assumed as listed in

the tables below. The conditions such as the interest rates were assumed to be those for getting finance

from commercial banks in Thailand, and the amortization rate conditions for the joint corporation were

assumed to be the returns that the EGAT would require when investing its capital in the new power

generation business.

Table 5-5 Project cost procurement conditions

Debt Equity of SPC

Interest rate / amortizatuon rate Annual rate 6.5% 10.0%

Repracement grace 5 years NA

Prepayment period 10 years NA


- 157 -

Table 5-6 Financing plan and opportunity costs

（million US$)

NO. year Debt Equity Total

1 2015 4.00 4.00 0.2%

2 2016 119.97 39.99 159.96 10.0%

3 2017 479.89 159.96 639.86 39.9%

4 2018 359.92 119.97 479.89 29.9%

5 2019 239.95 79.98 319.93 20.0%

1,199.73 403.91 1,603.64 100.0%

74.8% 25.2% 100.0%

Total



6.5% 0.375% 10.0% 7.7%


FIRR calculation results

The obtained FIRRs offer a condition where US$0.085/kWh exceeds the WACC if the interest rate of

debt for borrowing from a commercial bank in Thailand is 6.5%. However, if low-interest financing is

obtained utilizing JICA overseas financing (2.5% is assumed in this example), the WACC is exceeded if

the electricity selling price is US$0.067/kWh. For an electricity selling price of US$0.08/kWh, the FIRR for air-blown IGCC,6.9%, was higher by 0.6

point than that for oxygen-blown IGCC. This was due to the fact that the construction cost per net output

for air-blown IGCC was lower by approximately 4% than that for oxygen-blown IGCC, the net plant

efficiency for air-blown IGCC was higher by 1.9%, and the net output for air-blown IGCC was bigger

by approximately 20%. Although changes may appear in some degree depending on the condition

(because this investigation is not extensive), the trend is considered not to be changed. Table 5-7 shows the FIRR account that was obtained for an electricity selling price of US$0.08/kWh and

a discount rate of 4.5%. In this example, the NPV will be US$428 million, while the B/C ratio will be

1.32. FIRR sensitivity analysis

Like the case for oxygen-blown IGCC, the sensitivity analysis was conducted by varying the

construction cost. For an electricity selling price of US$0.08/kWh, a 10% decrease in the construction

cost will improve the FIRR from 6.9% to 8.1%, and a 20% decrease in this cost will improve it to 9.4%;

The FIRR will be guaranteed to exceed the amount twice larger than the WACC (4.5%) obtained when a

low-interest loan will be utilized such as JICA overseas financing.

NPV

Like the case for oxygen-blown IGCC, the sensitivity analysis was conducted by varying the discount

rate. For an electricity selling price of US$0.08/kWh, the NPV will take a positive value at a discount

rate less than 7%. Similarly, for an electricity selling price of US$0.07/kWh, the NPV will take a

positive value at a discount rate of 5%, and for an electricity selling price of US$0.09/kWh, it will take a

positive value at a discount rate of 8%.

- 158 -

Figure 5-4 FIRR calculation results (air-blown IGCC)

0.050 0.9

0.055 2.1

0.060 3.2

0.065 4.2

0.070 5.2

0.075 6.1

0.080 6.9

0.085 7.8

0.090 8.5

0.095 9.3

0.100 10.0

0.105 10.7

0.110 11.4

0.115 12.1

0.120 12.7

　

Electricityselling price(US$/kWh)

FIRR(%)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

0.05 0.06 0.07 0.08 0.09 0.10 0.11 0.12

Electiricity selling prive（US$/kWh）

FIR

R（%）




Figure 5-5 Results of the FIRR sensitivity analysis on the construction cost (air-blown IGCC)

(US$/kW) (%) 0.09 0.08 0.07

1,960 70 12.9 11.0 9.0

2,100 75 12.0 10.2 8.2

2,240 80 11.2 9.4 7.5

2,380 85 10.4 8.7 6.9

2,520 90 9.8 8.1 6.3

2,660 95 9.1 7.5 5.7

2,800 100 8.5 6.9 5.2

2,940 105 8.0 6.4 4.7

3,080 110 7.5 5.9 4.3


Construction cost

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

14.0

70 80 90 100 110

Constraction cost (%)

FIR

R（%）





Figure 5-6 NPV (air-blown IGCC)

Discount rate

(%) 0.09 0.08 0.07

2.0 1,652 1,186 720

3.0 1,227 831 436

4.0 886 548 210

5.0 621 321 30

6.0 391 139 -113

7.0 211 -7 -226

8.0 66 -125 -317

9.0 -52 -220 -388

10.0 -147 -296 -444


-500

0

500

1,000

1,500

2 4 6 8 10Discout rate (%)

NP

V (

mil.

US$)





- 159 -

Table 5-7 FIRR account (air-blown IGCC) Precondition

Generation Performance Investment cost Cost Revenue Tax, Interest, etc.

571.3 MW 2,800 USD/kW 3 % of EPC cost 0.08 USD/kWh 0.1% FIRR= 6.9%

505.4 MW 1,600 mil.USD 24.22 USD/ton 20 Baht/ton 30%

85 % 25 years 775 Baht/ton 170 Baht/ton 6.5% NPV= 428 mil.USD

Net efficiency 43.4 % straight line 187 Baht/ton insurance 0.75% of plant cost

4.0 mil.USD Limestone 187 Baht/ton 150,000 Ex-rate: 1Baht = 0.0313 USD B/C ratio= 1.32

75:25 Demin. water 61.35 Baht/m3 50,000

3.81 Baht/m3 Number of manage 5

25 years Disposal Cost 106 Baht/ton Number of operato 57 persons 4.5%

-5 -4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Byproduct

Sulfur (gypsum) mil. ton 29.2 ton/hour 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 0.217 5.436

Ash (fly ash) mil. ton 0.0 ton/day 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

Ash (slag) mil. ton 38.5 ton/hou Disposal (not sale) 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 0.287 7.167

Consumption

Fluxant (Kaoline) mil. ton 0 ton/hour 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

Limestone mil. ton 15.6 ton/hour 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 0.116 2.904

Industrial water mil. ton 1,250 ton/hour 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 9.308 232.688

Cooling water mil. ton 11,800 ton/hour (99% circulating) 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 0.879 21.966

Boiler water mil. ton 17 ton/hour 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.127 3.165

-5 -4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Net Capacity MW 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4 505.4

Availability ％ 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85 85

Electricity (net) GWh 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 3,763 94,080

Fuel consumption

Coal mil. t 285.4 ton/hour 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 2.13 53.13


(Feed) 4.0 4.0

Debt 0.0 120.0 479.9 359.9 239.9 1,199.7

Equity 4.0 40.0 160.0 120.0 80.0 403.9

Total Revenue 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2

Sales Electricity 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 301.1 7,526.4

Sales Sulfur (gypsum) 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 3.4

Sales Ash (fly ssh) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0

Sales Ash (slag) Disposal (not sale)

Total Cost 0.9 0.9 0.9 0.9 180.2 179.8 179.4 179.0 178.6 178.2 177.8 177.4 177.0 176.6 176.2 175.8 175.4 175.0 174.6 174.2 173.8 173.4 173.0 172.6 172.2 171.8 171.4 171.0 170.6 4,459.2

Fuel (coal) 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 51.5 1,286.7

Labor 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 33.8

Maintenance 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 48.0 1,199.7

Industrial water 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 27.7

Cooling water 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 2.6

Boiler water 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 6.1

Fluxant (Kaoline) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Limestone 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 17.0

Disposal Cost Ash slag 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 23.7

Depreciation 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 64.0 1,599.6

Fixed asset tax 1.6 1.5 1.5 1.4 1.3 1.3 1.2 1.2 1.1 1.0 1.0 0.9 0.8 0.8 0.7 0.6 0.6 0.5 0.4 0.4 0.3 0.3 0.2 0.1 0.1 20.8

Energy Fund 0.9 0.9 0.9 0.9 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 62.4

Insurance 70.0 % Plant coas ratio / total cost 8.4 8.1 7.7 7.4 7.1 6.7 6.4 6.0 5.7 5.4 5.0 4.7 4.4 4.0 3.7 3.4 3.0 2.7 2.4 2.0 1.7 1.3 1.0 0.7 0.3 179.2

Net Income -0.9 -0.9 -0.9 -0.9 121.0 121.4 121.8 122.2 122.6 123.0 123.4 123.8 124.2 124.6 125.0 125.4 125.8 126.2 126.6 127.0 127.4 127.8 128.2 128.6 129.0 129.4 129.8 130.2 130.6 3,140.6

Tax 36.3 36.4 36.5 36.7 36.8 36.9 37.0 37.1 37.2 37.4 37.5 37.6 37.7 37.8 38.0 38.1 38.2 38.3 38.4 38.6 38.7 38.8 38.9 39.0 39.2 943.2

After Tax -0.9 -0.9 -0.9 -0.9 84.7 85.0 85.2 85.5 85.8 86.1 86.4 86.6 86.9 87.2 87.5 87.8 88.0 88.3 88.6 88.9 89.2 89.4 89.7 90.0 90.3 90.6 90.8 91.1 91.4 2,197.3


B/C ratio NPV 4.5%

Benefit 3,584 0 0 0 0 0 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 301 7,530

Cost(including Investment)

2,710 4 161 641 481 321 116 116 115 115 115 114 114 113 113 113 112 112 111 111 111 110 110 109 109 109 108 108 107 107 107 4,393

Labor costmanager

Discount rate

Debt / Equityratio

Feed

Industrial water

Calculation term

Discount rate

mil.USD

Total

Total

Gross output

Availability(Plant factor)

mil.USD

Year

Net output

mil.USD

Year

mil.USD

Investment cost Maintenance feeElectricity sellingprice

Corporate Taxrate

Fixed asset Taxrate

Sulfur sellingprice (Gypsum)

Fuel (Coal) price

Interest rate

persons

Ash selling priceDepreciationperiod

Depreciationmethod

Fluxant (Kaoline)

Baht/person/mounth

Labor costoperator

Baht/person/mounth


- 160 -

b) Results of economic analysis

1) Evaluating method

The economic feasibility of this project was verified with the economic internal rate of return

method.The economic efficiency of this project was evaluated by (1) selecting e alternative projects each

provided with a facility capacity that allows generation of the generated energy (net) with the same scale

as for our project, (2) obtaining the equivalent discount rates (EIRR) of both with the cost of this project

as the expense and with that of the alternative project as benefit, and then (3) comparing them with the

discount rate (interest rate +4 - 5%, 10% is assumed) that the EGAT uses to consider development of

power sources. Comparison with oxygen-blown IGCC was made in this verification.

2) Alternative project

As power generating plants that differ in power generation technology and fuel from and have the same

scale in our project, two alternatives as below were selected: (1) a ultra super critical power plant (USC)

coal fired power plant that uses imported coal as fuel, and (2) a GTCC plant that uses imported LNG as

fuel.

a. USC coal fired power generation plant

Assumptions

The alternative facility conditions are as follows:

Gross plant output: 452MW


Internal power consumption rate: 6%

Availability: 85%

Gross plant efficiency: 41.4% (The Plant efficiency setting is the value

applying if the plant is constructed in Thailand by

using a plant of the Japanese manufacturer as the base,

assuming that the relative turbine efficiency decreases

by 3%.)


Coal calorific value (net, ar): 6,200kcal/kg

Price of coal: US$115/t (CIF) (assumed from the Indonesia coal

FOB price)

Unit construction cost: US$1,850/kW (assumed current price in Thailand)

O&M cost: Assumed to be 80% of that of the IGCC plant.

Results of analysis

The EIRR of this project was 10% in cost comparison with the alternative project, which is a

USC coal fired power plan that uses imported coal as fuel as an alternative generation form (see

Table 5-8). The difference of initial investment between IGCC at Mae Moh and USC by imported

coal is recovered in 25 years after commencement at a discount rate of 10%. However, the

recovery years will be shorter, as a coal terminal such as discharging berth and stockyard and

transport infrastructure to power station for the construction of USC coal-fired power plant will

be needed and the initial investment will be higher.

- 161 -


(IGCC at Mae Moh vs USC by imported coal)

-500

-400

-300

-200

-100

0

100

-4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Cost

bal

ance （

mil. U

S$）


- 162 -

Table 5-8 EIRR account (IGCC at Mae Moh vs USC with imported coal) Assumption of IGCC Assumption of USCGross output 500 MW Gross output 452 MWNet output 425 MW Net output 425 MWAvailability 85% Availability 85%Gross efficiency 48.8% Gross efficiency 41.4%Net efficiency 41.5% Net efficiency 38.9% Construction cost 2,800 US$/kW Construction cost 1,850 US$/kWO&M cost 0.10 million US$/MW O&M cost 0.08 million US$/MW Fixed cost 0.09 million US$/MW Variable cost 0.01 million US$/MWFuel cost (coal) 24.22 US$/ｔ Fuel cost (coal) 115 US$/ｔCalorific valuue （gar） 14.70 MJ/kg 3,511 kcal/kg Calorific valuue （gar） 25.96 MJ/kg 6,200 kcal/kgFuel consumption 1.86 million t/year Fuel consumption 1.13 million t/year

Varaiable Fixed Total

mil.US$ MW ％ GWh ％ mil.US$ mil.US$ mil.US$ mil.US$ mil.US$ 百万US$ MW ％ GWh ％ mil.US$ mil.US$ mil.US$ mil.US$-5 2015 0 0.0 0.0-4 2016 140.0 140.0 83.6 83.6 -56.4-3 2017 560.0 560.0 334.6 334.6 -225.4-2 2018 420.0 420.0 250.9 250.9 -169.1-1 2019 280.0 280.0 167.3 167.3 -112.71 2020 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.92 2021 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.93 2022 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.94 2023 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.95 2024 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.96 2025 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.97 2026 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.98 2027 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.99 2028 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.9

10 2029 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.911 2030 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.912 2031 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.913 2032 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.914 2033 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.915 2034 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.916 2035 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.917 2036 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.918 2037 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.919 2038 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.920 2039 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.921 2040 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.922 2041 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.923 2042 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.924 2043 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.925 2044 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 452 85% 3,367 41.4% 129.7 35.7 165.4 70.9

1,400 93,075 1,126.2 150.6 1,083.8 1,234.3 3,760.6 836.4 84,164 3,241.4 892.9 4,970.7 1,210.2

EIRR= 10.0%

YearConstruction cost

GrossOutput

Availability

CostbalanceConstruct

ion costGrossOutput

Availability

Annualpower

generation

Grossefficiency

Fuel cost O&M cost

USC

TotalCost

（80% of IGCC）

O&M costTotalCost

IGCC

Annualpower

generation

Grossefficiency

Fuel cost

(Note) Coal terminal cost is not included in construction cost. (Source) Prepared by Study Team

- 163 -

EIRR sensitivity analysis

A sensitivity analysis was conducted regarding the unit construction cost of the alternative project

and the coal price. The result is shown in figure 5-8 and figure 5-9.

Figure 5-8 Sensitivity analysis with construction cost of USC by imported coal

(US$/kW) (%)

1,500 70 7.4

1,550 72 7.7

1,600 74 8.0

1,650 77 8.4

1,700 79 8.7

1,750 81 9.1

1,800 84 9.5

1,850 86 10.0

1,900 88 10.4

1,950 91 10.9

2,000 93 11.4

2,050 95 12.0

2,100 98 12.6

2,150 100 13.2

　 2,200 102 13.9

2,250 105 14.7

2,300 107 15.5

2,350 109 16.4

2,400 112 17.5

Construction cost EIRR(%)

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

22.0

1,500 1,600 1,700 1,800 1,900 2,000 2,100 2,200 2,300 2,400

Construction cost （US$/kW）

EIR

R（%）


Figure 5-9 Sensitivity analysis with the imported coal price

Coal price(US$/ｔ)

EIRR(%)

80 2.5

85 3.8

90 5.0

95 6.1

100 7.1

105 8.1

110 9.1

115 10.0

120 10.8

125 11.6

130 12.5

135 13.2

140 14.0

145 14.7

150 15.4

　

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

80 90 100 110 120 130 140 150

Coal price （US$/t）

EIR

R（%）


b. GTCC plant

Assumptions

The alternative facility conditions are as follows:

Gross plant output: 438MW (determined by on-site consumption rate)


- 164 -

O Internal power consumption rate: 2.9%

Availability: 85%

Gross plant efficiency: 55.8%


LNG calorific value (net, ar): 13,019kcal/kg

Price of LNG : US$ (CIF): US$16.9/million Btu (assumed as CIF Japan in

November 2011)

Unit construction cost: US$800/kW (assumed current price in Thailand)

O&M cost: Assumed to be 80% of that of the IGCC plant.

Results of analysis

In cost comparison with the GTCC plant that uses imported LNG as fuel in an alternative power

generation form, the EIRR of this project is 19.3% and the IGCC plant is economically superior

to the GTCC plant that uses imported LNG as fuel (see Table 5-9). The difference of initial

investment cost between IGCC at Mae Moh and GTCC by LNG is recovered in 6.5 years after

commencement at a discount rate of 10%. And also the recovery years will be even shorter than

6.5 years, as a LNG terminal for GTCC plant is needed and the initial investment will be higher.


(IGCC at Mae Moh vs GTCC by imported LNG)

-1000

-800

-600

-400

-200

0

200

400

600

800

1000

-4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Cost

bal

ance (m

il. U

S$)


- 165 -

Table 5-9 EIRR account (IGCC at Mae Moh vs GTCC with imported LNG) Assumption of IGCC Assumption of GTCCGross output 500 MW Gross output 438 MWNet output 425 MW Net output 425 MWAvailability 85% Availability 85%Gross efficiency 48.8% Gross efficiency 55.8%Net efficiency 41.5% Net efficiency 54.2%Construction cost 2,800 US$/kW Construction cost 800 US$/kWO&M cost 0.10 million US$/MW O&M cost 0.08 million US$/MW Fixed cost 0.09 million US$/MW Variable cost 0.01 million US$/MWFuel cost (coal) 24.22 US$/ｔ Fuel cost (LNG) 16.9 US$/MMBtuCalorific valuue （gar） 14.70 MJ/kg 3,511 kcal/kg Calorific valuue （gar） 54.61 MJ/kg 13,043 kcal/kgFuel consumption 1.86 million t/year Fuel consumption 0.39 million t/year

Varaiable Fixed Total

mil.US$ MW ％ GWh ％ mil.US$ mil.US$ mil.US$ mil.US$ mil.US$ mil.US$ MW ％ GWh ％ mil.US$ mil.US$ mil.US$ mil.US$

-5 2015 0.0 0 0-4 2016 140.0 140.0 35.0 35.0 -105.0-3 2017 560.0 560.0 140.1 140.1 -419.9-2 2018 420.0 420.0 105.0 105.0 -315.0-1 2019 280.0 280.0 70.0 70.0 -210.01 2020 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.62 2021 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.63 2022 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.64 2023 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.65 2024 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.66 2025 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.67 2026 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.68 2027 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.69 2028 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.6

10 2029 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.611 2030 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.612 2031 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.613 2032 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.614 2033 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.615 2034 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.616 2035 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.617 2036 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.618 2037 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.619 2038 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.620 2039 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.621 2040 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.622 2041 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.623 2042 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.624 2043 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.625 2044 500 85% 3,723 48.8% 45.0 6.0 43.4 49.4 94.4 438 85% 3,259 55.8% 325.4 34.6 360.0 265.6

1,400 93,075 1,126.2 150.6 1,083.8 1,234.3 3,760.6 350 81,477 8,135.3 864.4 9,349.9 5,589.4

EIRR= 19.3%

IGCC GTCC

YearO&M cost

Construction cost

GrossOutput

Availability

Annualpower

generation

Grossefficiency

Fuel costConstruction cost

GrossOutput

Availability

TotalCost

TotalCost

Costbalance

（80% of IGCC）

Annualpower

generation

Grossefficiency

Fuel cost O&M cost

(Note) LNG terminal cost is not included in construction cost. (Source) Prepared by Study Team

- 166 -

EIRR sensitivity analysis

A sensitivity analysis was conducted regarding the unit construction cost of the alternative project

and the coal price. The result is shown in figure 5-11 and figure 5-12.

Figure 5-11 Sensitivity analysis with construction cost of GTCC by imported LNG

(US$/kW) (%)

600 86 18.0

650 93 18.3

700 100 18.6

750 107 18.9

800 114 19.3

850 121 19.6

900 129 20.0

950 136 20.3

1,000 143 20.7

1,050 150 21.1

1,100 157 21.5

1,150 164 21.9

1,200 171 22.4

　

Construction cost EIRR(%)

15.0

17.0

19.0

21.0

23.0

25.0

600 700 800 900 1,000 1,100 1,200

Construction cost （US$/kW）

EIR

R（%）


Figure 5-12 Sensitivity analysis with LNG price

LNG price(US$/MMbtu)

EIRR(%)

10.0 10.0

11.0 11.6

12.0 13.0

13.0 14.4

14.0 15.7

15.0 17.0

16.0 18.2

17.0 19.4

18.0 20.5

19.0 21.6

20.0 22.7

21.0 23.8

22.0 24.8

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

22.0

24.0

26.0

10 12 14 16 18 20 22

LNG price （US$/MMbtu）

EIR

R（%）


c) Feasibility of bilateral credit

Japan has started negotiation with Asian countries after the following has been agreed on regarding the

new credit mechanism: determining that construction of the new market mechanism will be considered

in the 17th Conference of the Parties (COP17). This section shows an analysis conducted on the

assumption that the bilateral credit will be formed.

As explained previously, in Kingdom of Thailand, CDM does not apply because the ratio of the coal

- 167 -

fired power generation capacity to the total capacity is not larger than 50%, regarding the new

high-efficiency coal fired power generation technology. Japan has, however, started negotiation with

Asian countries in preparation for reaching an agreement concerning bilateral offset. We consider the

case where Japan and Thailand will have reached an agreement on this bilateral offset and a credit will

have been generated.

The CO2 credit was calculated provisionally and the effect on this project was considered herein by

comparing between the 500MW oxygen-blown IGCC plant being planted to be installed in this project

and the existing subcritical pressure coal fired power plant in the Mae Moh. In reaching a bilateral credit

agreement, it is, however, necessary to establish a methodology that is approved internationally as well

as bilaterally.

Our consideration shows that 1.13 million t of CO2 will decrease annually and a US$19.8 million credit

will be acquired annually, assuming that the credit cost is US$17.58/CO2-t (average cost in 2011). For

reference, the FIRR will improve by approximately 0.5% if it is calculated assuming that the period of

generation of this credit is the 10 years beginning at the start of operation.

d) Syngas production option

Initially, we assumed that no economic efficiency would be obtained owing to an expensive construction

cost of the coal IGCC plant. For this reason, we planned to improve the economic efficiency by

considering production and selling of syngas (an alternative of LPG herein for the following reason) as

an option. As described previously, we were, however, able to decide that this project will be feasible

financially by making a low interest loan; thus, we will not consider the syngas production option in this

investigation.

Because the investigation concerning the LPG market in Thailand was investigated earlier than the

others, the Thailand LPG market is outlined, as reference information, at the end of this chapter.

- 168 -

[Reference Information: Outline of demand and supply of LPG in Thailand]

1. Thailand LPG Consumption Trend

In Thailand, the LPG consumption was 5,941 thousand t29 in 2010. As for the ratios by application, the consumption for kitchen use30 occupies about 40 percent, followed by that for petrochemical feedstock (27%). In general, the LPG consumption exhibits an escalation tendency; particularly for application for petrochemical feedstock, the demand was significantly escalated from 461 thousand t in 2000 to 1,590 thousand t in 2010. On the other hand, the ratio of the construction of transportation LPG has continued to decrease in recent years partially because of those promotion measures31 for natural gas vehicles (NGV) that are taken by the Thailand government.

Figure 5-13 Transition of consumption by LPG application in Thailand (1990 to 2010)

0

1

2

3

4

5

6

7

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

(million t)

2010Captive

consumption 8%

Transportation 11%

Industrial 13%

Petrochemicalfeedstock 27%

Kitchen use 41%

(Note) Consumption by LPG and propane application (exclusive of butane) (Source) Ministry of Energy, Energy Policy and Planning Office, Energy Statistics: Table 2.3-5.

29 The consumptions by application in the source are in units of thousand t. 30 The consumption for kitchen use, represented as "Cooking" in the source, may include application of LPG heat for both domestic and business use (e.g. restaurants, hotels, and department stores). Although the statistical category is not clearly defined in the source, the gas supplier’s website includes a description of "Cooking," which shows they intend it as thermal demand by both domestic and business use. “Cooking – Unique Gas LPG is widely used among various kinds of users for cooking purpose, and some for heating purpose – this includes households, restaurants, hotels, and department stores, e.g. Central Department Store, Robinson Department Store, Tesco Lotus, etc.” Source: Unique Gas Home Page > PRODUCT & SERVICE (http://www.uniquegas.co.th/product.php) 31 To promote replacing the vehicles owned by the Thailand government and public organizations by natural gas vehicles. The waste collection vehicles and public buses owned by the Bangkok Metropolitan Administration have begun to be replaced by natural gas vehicles; in addition, a campaign has begun to promote convert taxies to natural gas vehicles. Source: SIAMGAS「ANNUAL REPORT 2010」p.25.

- 169 -

2. Thailand LPG Import and Export Trend

In 2010, the LPG import volume of Thailand was 1,694 thousand t (3,054 thousand kl), and the LPG export volume was 25 thousand t (46 thousand kl). The LPG import volume has been increasing sharply because the domestic production cannot keep up with recent increase in domestic demand; the ratio of the LPG import volume to the total supply volume reached 27.2% in 2010. On the other hand, the export volume has been decreasing dramatically; the ratio of the LPG export volume to the total supply volume was 0.4% in 2010.

Figure 5-14 Transition of import and export volume in Thailand

-2.0

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

(million t)

LPG Import

LPG Export

Export

Import

(Note) The graph shows the LPG import volume data as negative values. (Source) Ministry of Energy, Energy Policy and Planning Office, Energy Statistics: Table 2.3-6, 2.3-8. 3. Price of LPG

According to the data provided on the website of the Ministry of Commerce of Thailand, in recent years, the LPG import price decreased from US$884/t in 2008 to US$620/t in 2009, and increased again to US$773/t in 2010. This fluctuation in the import price may be due to the influence of the worldwide price fluctuation of LPG. On the other hand, as for domestic LPG prices in Thailand, the wholesale price (ex-refinery) is 13.69 baht/kg as of December 2010, and the retail price is 18.13 baht/kg. For the retail price, its upper limit has been regulated as 13.69 baht/kg beginning in March 2008, for the purpose of easing the consumers’ financial family burden32. The fixed LPG price system has been supporting the LPG price by using the contribution collected from petroleum products, such as gasoline and diesel oil, as the capital (Oil Fund)33.

32 IEEJ-APERC: Compendium of Energy Efficiency Policies of APEC Economies –Thailand: p.12. 33 Inexpensive LPG initially aimed at support of people’s life, for example, in the view of domesticity and food distribution. However, it was pointed out that a worldwide price increase of oil occurred around the same time, and fuel for taxies was converted to LPG for transportation use, in addition, LPG was smuggle to neighbor countries. Source: PATTAYA TODAY, Govt to lift fixed price on LPG, August 31, 2011.

- 170 -

In August 2011, the following proposal toward alteration of the LPG price system was reported: the previous fixed price of LPG not matching the market rate should be reconsidered, and credit cards should be issued to low-income earners instead of the uniform subsidy in the price.34 For this reason, henceforth, the retail price of LPG may greatly increase compared to the current level35. However, in September, National Energy Policy Council (NEPC), chaired by Prime Minister Yingluck Shinawatra, determined that the price of the LPG for domestic use will be kept at 18.13 baht /kg until the end of 201236.

Table 5-10 EIRR Transition of LPG import price in Thailand (2008 to 2010)

（US$/t） 2008 2009 2010

Propane gas in ThailandAverage import CIF price　（Cost, Insurance and Freight）

884 620 773

(Source 1) Created from website of Ministry of Commerce > Main Ex-Im Commodity, Harmonize System.

（US$/t） 2008 2009 2010

（Reference） Propane price 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q

Saudi Arabia/FOB price　（Free On Board）

831 848 856 549 451 390 519 650 735 705 595

Japan/CFR price　（Cost and Freight）

838 890 867 453 458 427 544 688 752 705 620

UK, North Sea/FOB price 810 834 865 495 416 355 491 605 695 621 597

(Source 2) World LP Gas Association: Statistics Review of Global LP Gas 2010 (Note) Propane import price (exclusive of butane)

Figure 5-15 Transition of LPG price in Thailand

8

10

12

14

16

18

20

200

5

200

6

200

7

200

8

200

9

201

0

(Baht/kg)

LPGRetail price（Bangkok metropolitan area）

LPGWholesale price （ex-refinery）

(Note) The LPG ex-refinery price (wholesale price) is exclusive of VAT. (Source) Ministry of Energy, Energy Policy and Planning Office, Energy Statistics: Table 8-8, 8-

34 Source: Same as above. 35 Mr. Suthep, Chief of the Secretariat of EPPO, commented that LPG pricing of 30 baht/kg was also possible. Source: Same as above. 36 Thailand Public Relations Department (Government Public Relations Department), Government to Increase Household Income, October 4, 2011, (http://thailand.prd.go.th/view_inside.php?id=5891)

Chapter 6 Planned Project Schedule

- 172 -

(1) Project overall operation

The project overall schedule is indicated in Figure 6-1.

Figure 6-1 Project overall schedule


This schedule takes into account essential requirements in implementing the project as a result of this

feasibility study (FS), including terms of operation to be conducted. Shown below are activity items

assumed for each important phase.

a) Detailed FS: 10-12 months

A detailed FS on the following items needs to be conducted in order to assess the project feasibility

(marketability) as well as for plant optimization. Documents necessary for environmental assessment

shall be also prepared during this phase.

Optimization of the flow scheme

Location survey

Determination of assumed coal property and implementation of drying tests and liquidity tests as

necessary

Operation request to each licenser and settlement of nondisclosure agreements as necessary

Review on the transferability of existing facilities

Documentation for environmental assessment

Calculation of the total budget

Economic assessment

b) FEED (Front End Engineering Design): 12-15 months

In this phase, a basic plan for the plant shall be developed and an EPC inquiry specification sheet shall

be prepared. Shown below are important activity items in this phase.

- 173 -

Determination of facility design specifications

Preparation of an EPC inquiry specification sheet (preparation of the Basic Design Package)

Inquiry/determination of the EPC contractor

c) EPC (Engineering, Procurement, Construction): 33-36 months

Basic/detailed design of the plant, material procurement, onsite construction, and trial operation shall be

done in this phase.

Some equipment (facilities) to be purchased in this project require 24 months for production, and thus

the whole EPC phase, from basic designing (reviewed by the EPC contractor) to launch of plant

operation including phases of designing, procurement, construction and trial operation as well as FEED

implementation as a prerequisite, would require 33-36 months in total.

- 174 -

Chapter 7 Implementing Organization

- 176 -

(1) Implementing Organization

Electricity Generating Authority of Thailand (EGAT) under the Ministry of Energy was established in

May 1969 as a result of merging three enterprises, namely, Yanhee Electricity Authority (YEA), Lignite

Authority (LA) and the North-East Electricity Authority (NEEA). EGAT used to be in charge of power

generation and distribution all over Thailand and directly supply electricity to large-scale customers as

well as provide wholesale electricity to MEA and PEA. However, due to establishment of subsidiary

corporations and incoming private capitals including from overseas as a result of liberalization of the

power generation sector, currently EGAT also purchases electricity. Also, the amount of power

interchange with Laos and Malaysia, which EGAT has had since before, has been recently increasing.

The installed capacity of EGAT is approximately 15,000MW (which accounts for approximately 49% of

the total capacity in the country), and according to the Summary of Thailand Power Development Plan

2010-2030 (PDP 2010) released in April 2010, EGAT will increase its installed capacity by 4,821MW by

2020.

Power generation plan 2010-2020

- EGAT 4,821MW- IPP 4,400MW- SPP 3,539MW- VSPP 2,335MW- Khanom CC 800MW- Purchase from foreign countries 5,669MW

Thanks to the capable human resources and excelled technical strength since its establishment, EGAT

has played a major role in development and operation in the power generation sector in Thailand. The

state enterprise covers a wide range of services including: preparation of the power development plans;

construction, operation and maintenance of power generation, distribution and transformation facilities;

fuel procurement; financial procurement in project development; and electricity purchase from IPPs.

As shown in Figure 7-1, EGAT has achieved stable electricity supply, currently operating gas-fired gas

turbine combined power plants, coal-fired power plants and hydraulic power plants, and thus its

operational capacity in this project is considered to be very high.

Also, EGAT maintains good financial conditions in scale and quality as indicated in the financial

statements below (Table 7-1), which proof the Authority’s sufficient financial ground to be engaged in a

large-scale project like this project.

- 177 -

Figure 7-1 EGAT Power Source Composition in 2010


Table 7-1 EGAT Financial Overview

Unit : Million Baht

2010 2009

Operating Performance

Revenues from sales and services 405,445.06 373,701.68

Income from sales and services 39,015.85 32,746.07

Gains (losses) on foreign exchange 910.36 1,175.27

Interest expenses 4,420.18 4,528.25

Net income - EGAT 37,355.13 31,227.37

Net income - minority interest 2,860.16 3,706.63

Financial Status

Total assets 469,415.42 474,189.38

Land, buildings and equipment - net 263,009.45 258,639.86

Total liabilities 173,181.45 198,678.59

Long-term debts 82,905.92 104,853.21

Equity and minority interest 296,233.97 275,510.79

Financial Ratios

Ratio of gross profit to net sales (%) 13.46 12.56

Ratio of net profit to net sales (%) 9.21 8.36

Rate of return on assets (%) 7.92 6.84

Debt to equity ratio (Times) 0.58 0.72

Time interest earned (Times) 10.39 8.90

(Source) EGAT Annual Report 2010

Total power energy: 57,630 GWh

Mae Moh (Units 4 to 7) 4,350GWh

(7.55%)

Gas turbine 276 GWh (0.48%)

Gas-fired 10,831 GWh

(18.79%)

Mae Moh (Units 8 to 13)13,663 GWh

(23.71%) Hydraulic

5,338 GWh (9.26%)

Combined cycle 23,167 GWh

(40,20%)

- 178 -

Chapter 8 Technical Advantages of Japanese Company

- 180 -

(1) Assumed participation forms of Japanese corporations (investment, equipment supply, facility operation management etc.)

Under a public-private partnership (PPP) scheme, Japanese corporations are expected to participate in

the project as a comprehensive system, not only supply of the IGCC plant facilities but also operation

and maintenance as the project implementing body.

At the moment, Japanese corporations are assumed to participate in the project as shown in Figure 8-1

(project structure).

Figure 8-1 Assumed project structure

IGCC PlantSPC

(Thai-Japan JV）

EGAT etc

JICA(Overseas Investment Loans)

EGAT

Coal Supply / Electricity Off-take

(Energy Conversion Agreement)

Equity ＆ O&MEquity & Soft Loan

EPCContract

Bilateral Credit Trading

Less Greenhouse Gas Emission

Mitsubishi & JPN Utilities etc

IGCC PlantSPC

(Thai-Japan JV）

EGAT etc

JICA(Overseas Investment Loans)

EGAT

Coal Supply / Electricity Off-take

(Energy Conversion Agreement)

Equity ＆ O&MEquity & Soft Loan

EPCContract

Bilateral Credit Trading

Less Greenhouse Gas Emission

Mitsubishi & JPN Utilities etc


With investments by the nine electric power companies (Hokkaido Electric Power, Tohoku Electric

Power, Tokyo Electric Power, Chubu Electric Power, Hokuriku Electric Power, Kansai Electric Power,

Chugoku Electric Power, Shikoku Electric Power and Kyushu Electric Power) and Electric Power

Development (J-POWER), a research institute named Clean Coal Power R&D Co., Ltd. was established

in 2001 with an aim of demonstrating the Japanese IGCC technology. The institute and the electric

power companies etc. have accumulated the know-how of the Nakoso IGCC plant, the first plant in

Japan, by designing, constructing and performing operation and maintenance, partly utilizing subsidies

from the Natural Resources and Energy Agency under the Ministry of Economy, Trade and Industry.

Enforcing testing on reliability, operability, durability and economic efficiency of IGCC in the process of

its demonstration, a future challenge is to actually propose and develop IGCC projects in Japan and

overseas.

In order to utilize valuable past performances and accumulated know-how of IGCC operation and

maintenance, Japanese electric power companies which have been involved in Nakoso IGCC plant

operation are expected to participate in this project as project implementing bodies.

- 181 -

(2) Advantages of Japanese corporations upon implementing this project (technical and economic aspects)

a) Technical advantages

Only four IGCC plants are reported as in operation around the globe to date, which were launched in

Europe and the United States in the 1990s, and to our best knowledge, the Nakoso Plant in Japan is the

only plant that reached the start of operation in this century. The Nakoso Plant recorded 2,238 hours of

continuous operation on November 11, 2011 and also reached 5,000 hours of annual operation time in

the long-term durable operation test as initially planned. The plan was the first in the world to achieve

more than 2,000 hours of long-term continuous operation within one year after the start of operation.

The IGCC development in Japan has steadily progressed through the steps of various surveys, element

technology research, preliminary verification test, design research etc. since the pilot plant testing

(subsidized by NEDO) which started in 1986. The outputs of the Nakoso IGCC Plant can be evaluated

as collective outcomes of clean coal technology in Japan to present. Know-how accumulated in the

Nakoso IGCC Plant which has demonstrated high performance and reliability will presumably be a

significant driver for Japan’s competitiveness for expanding the IGCC plant sales.

As for gas turbine technology to be combined with the IGCC technology, there are only four

manufacturers that are running their businesses in the IGCC market at global level. Among them,

Japan’s high efficient gas turbine technology holds a prominent position and also precedes other

international manufacturers.

Furthermore, Japanese manufacturers (Mitsubishi Heavy Industries and Hitachi) and engineering

corporation (Chiyoda Corporation) which hold high reliability and technology have developed concrete

IGCC projects and thus have technical advantages. A future challenge for them is to develop IGCC

plants with market competitiveness.

Particularly, type of gasifier suitable for this project is technically limited because the coal which will be

used in this project has many conditions for combustion. As of the time of this survey, only two

manufacturers retain both technologies of gasifier and high efficiency gas turbine suitable for

combusting the coal to be used in this project, one of which is a Japanese corporation. Another possible

scenario for implementing this project is to combine gasifier and high efficiency turbine technology by

two different corporations, but again only a limited number of engineering corporations could handle the

two technologies in combination, and thus the Japanese engineering corporation with experience of

introducing gasifier etc. is expected to have advantages.

b) Economic advantages

As proposed in the New Growth Strategy, the Japanese government promotes to export infrastructure

package through public-private partnerships. It is expected that partnerships between Japanese

corporation’s business activities and public finance such as JICA overseas loans: bring continuous

development impacts (employment, technology, promotion of trade and investment etc.) to recipient

countries at large scale which would not be induced only by public assistance such as regular ODA; as

well as reduce risks and costs of Japanese corporations’ overseas activities. To develop a project based

on such a public-private partnership would provide economic advantages to their business activities.

- 182 -

(3) Measures necessary to promote contract winning by the Japanese corporations

In order to promote contract winning by the Japanese corporations, they need to enhance their

competitiveness through expanding their IGCC sales and accumulating technical and economic

know-how on a market basis. One reason for the fact that only a few IGCC projects in the world are

feasible as a market-based business is that economic efficiency is significantly damaged due to its huge

initial investment cost.

Huge initial investment is required to reach commencement of IGCC plant operation, from a detail

feasibility study and detail designing to construction. Because of this significantly huge initial cost

compared with other power generation projects, IGCC projects face a negative spiral problem of not

being able to: make a final decision on executing project investment because of substantially decreased

project feasibility due to the loan interest; accumulate know-how on a market basis; and progress to

develop competitive IGCC plants.

Under such a circumstance, financial supports are needed to mitigate huge initial investment cost borne

by the project implementing body under the public-private partnership (PPP) scheme, from the detail

feasibility study to detail designing and construction, for enabling the IGCC project implementing body

can improve the project economic efficiency and reach a final project investment decision. The project

implementing body, on the other hand, needs to make efforts to negotiate with corporations (Japanese

manufacturers, engineering corporations etc.) which will receive a EPC contract for the IGCC plan to

offer a competitive construction cost, and the IGCC plant manufacturers should continuously enhance

cost reduction.

Supports from the Japanese government such as JICA overseas investment loans and cooperation

preparatory survey for PPP are expected upon conducting a detail feasibility study which will be the next

step after the completion of this survey.

Chapter 9 Financial Outlook

- 184 -

(1) Review for financial sources and a financial procurement plan

IGCC plants attract global attention for their power generation technology that effectively utilizes coal,

which is expected 180-190 years of reserve-production ratio and widely available in geopolitically stable

regions. As described in the survey results, high plan heat efficiency and environmental performance are

confirmed for IGCC, and thus this technology can be evaluated with highly promising results from the

technological aspect, even comparing with ultra supercritical pressure coal-fired thermal power

generation. IGCC technology, however, is yet to be deployed widely due to the substantial amount of

initial investment cost required, which in turn does not contribute to cost improvement for accelerating

deployment.

Under such a circumstance and with a vision of globally expanding Japanese IGCC technologies and

operation schemes, this project is willing to give a positive consideration to formulation of a PPP

scheme of public-private partnership and utilization of JICA overseas investment loans, yen loans and

JBIC overseas investment loans. It aims to realize the project by formulating competitive financing

under the PPP scheme to improve economic and business feasibility of the project.

Upon developing this project, joint capital participation with Japanese and Thai corporations (including

EGAT) is also expected.

The best finance structure shall be formulated throughout the implementation of further survey to be

made based on the above-mentioned issues.

(2) Feasibility of financial procurement

This project is expected to receive financial support at the government level as its aim corresponds with

the policy guidelines by both Japanese and Thai governments, that is, “development and deployment of

environmentally responsible sustainable energy and electricity infrastructure” which is aimed for

sustainable economic growth. Also, in this project, electricity is produced from coal mines at a

reasonable price with low supply risk, and EGAT which retains a sound financial footing will

presumably purchase electricity produced by this project based on a long-term contract. Therefore, a

highly collateralized project structure can be established. Furthermore, this project is expected to lead to

sales expansion and infrastructure export of the IGCC technologies and schemes in which Japanese

corporates have technical advantages.

Based on the above-mentioned conditions, financial procurement feasibility utilizing JICA overseas

investment loans, yen loans and JBIC overseas investment loans under the PPP scheme is considered to

be high.

(3) Cash flow analysis

In the plan of this project, 25% of the initial investment will be covered by self-owned capital and 75%

will be loaned. As for financial procurement, cash flow analysis was conducted on the two possibilities,

- 185 -

namely, to procure financial resources from commercial banks and to use soft loan such as JICA

overseas investment loans. The estimation result showed that soft loan such as JICA overseas investment

loan would be repayable by cash flow produced from the project in both cases of oxygen-blown and

air-blown IGCC (see Tables 8-1 and 8-2).

The analysis was conducted based on the following assumed conditions and US$0.08/kWh as an electric

power selling price.

Loan conditions of commercial banks

Interest rate: 6.5%/year

Repayment period: 10 years

Deferment period: 5 years

Low interest loans such as JICA overseas investment loan

Interest rate: 2.5%/year

Repayment period: 20 years

Deferment period: 5 years

- 186 -

Table 9-1 Cash flow analysis (oxygen-blown IGCC) -5 -4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044


(Feed) 3.5 3.5

Debt 0.0 105.0 420.0 315.0 210.0 1,050.0

Equity 3.5 35.0 140.0 105.0 70.0 353.5

Total Revenue 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3 253.3

Total Cost 0.8 0.8 0.8 0.8 159.3 158.9 158.6 158.2 157.9 157.5 157.2 156.8 156.5 156.1 155.8 155.4 155.1 154.7 154.4 154.0 153.7 153.3 153.0 152.6 152.3 151.9 151.6 151.2 150.9 3,949.6

Net Income -0.8 -0.8 -0.8 -0.8 94.1 94.4 94.8 95.1 95.5 95.8 96.2 96.5 96.9 97.2 97.6 97.9 98.3 98.6 99.0 99.3 99.7 100.0 100.4 100.7 101.1 101.4 101.8 102.1 102.5 2,453.8

Tax 28.2 28.3 28.4 28.5 28.6 28.7 28.9 29.0 29.1 29.2 29.3 29.4 29.5 29.6 29.7 29.8 29.9 30.0 30.1 30.2 30.3 30.4 30.5 30.6 30.7 737.1

After Tax -0.8 -0.8 -0.8 -0.8 65.9 66.1 66.3 66.6 66.8 67.1 67.3 67.6 67.8 68.1 68.3 68.6 68.8 69.0 69.3 69.5 69.8 70.0 70.3 70.5 70.8 71.0 71.2 71.5 71.7 1,716.8


Interest 6.5% Repayment perio 10 years-5 -4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Loan 0.0 105.0 420.0 315.0 210.0 1,050

Outstanding 0.0 111.8 539.1 889.1 1,156.9 1,071.2 979.9 882.6 779.1 668.8 551.3 426.2 293.0 151.1 0.0 8,500

Interest 0.0 6.8 7.3 35.0 57.8 75.2 69.6 63.7 57.4 50.6 43.5 35.8 27.7 19.0 9.8 559

Repayment 160.9 160.9 160.9 160.9 160.9 160.9 160.9 160.9 160.9 160.9 1,609


2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Loan 0.0 105.0 420.0 315.0 210.0 1,050

Outstanding 0.0 107.6 530.3 858.6 1,090.0 1,047.4 1,003.6 958.8 912.8 865.7 817.5 768.0 717.3 665.3 612.0 557.3 501.4 444.0 385.1 324.9 263.0 199.7 134.8 68.2 0.0 13,833

Interest 0.0 2.6 2.7 13.3 21.5 27.3 26.2 25.1 24.0 22.8 21.6 20.4 19.2 17.9 16.6 15.3 13.9 12.5 11.1 9.6 8.1 6.6 5.0 3.4 1.7 348

Repayment 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 69.9 1,398

mil.USD

mil.USD

Year

mil.USD

Year Total

mil.USD

Total

mil.USD

TotalYear

mil.USD


- 187 -

Table 9-2 Cash flow analysis (air-blown IGCC)

-5 -4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044


(Feed) 4.0 4.0

Debt 0.0 120.0 479.9 359.9 239.9 1,199.7

Equity 4.0 40.0 160.0 120.0 80.0 403.9

Total Revenue 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2 301.2

Total Cost 0.9 0.9 0.9 0.9 180.2 179.8 179.4 179.0 178.6 178.2 177.8 177.4 177.0 176.6 176.2 175.8 175.4 175.0 174.6 174.2 173.8 173.4 173.0 172.6 172.2 171.8 171.4 171.0 170.6 4,459.2

Net Income -0.9 -0.9 -0.9 -0.9 121.0 121.4 121.8 122.2 122.6 123.0 123.4 123.8 124.2 124.6 125.0 125.4 125.8 126.2 126.6 127.0 127.4 127.8 128.2 128.6 129.0 129.4 129.8 130.2 130.6 3,140.6

Tax 36.3 36.4 36.5 36.7 36.8 36.9 37.0 37.1 37.2 37.4 37.5 37.6 37.7 37.8 38.0 38.1 38.2 38.3 38.4 38.6 38.7 38.8 38.9 39.0 39.2 943.2

After Tax -0.9 -0.9 -0.9 -0.9 84.7 85.0 85.2 85.5 85.8 86.1 86.4 86.6 86.9 87.2 87.5 87.8 88.0 88.3 88.6 88.9 89.2 89.4 89.7 90.0 90.3 90.6 90.8 91.1 91.4 2,197.3



2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Loan 0.0 120.0 479.9 359.9 239.9 1,200

Outstanding 0.0 127.8 616.0 1,015.9 1,321.9 1,224.0 1,119.6 1,008.5 890.2 764.2 630.0 487.0 334.8 172.7 0.0 9,713

Interest 0.0 7.8 8.3 40.0 66.0 85.9 79.6 72.8 65.6 57.9 49.7 40.9 31.7 21.8 11.2 639

Repayment 183.9 183.9 183.9 183.9 183.9 183.9 183.9 183.9 183.9 183.9 1,839


2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Loan 0.0 120.0 479.9 359.9 239.9 1,200

Outstanding 0.0 123.0 605.9 981.0 1,245.5 1,196.7 1,146.7 1,095.5 1,043.0 989.2 934.0 877.5 819.5 760.1 699.3 636.8 572.9 507.3 440.1 371.2 300.6 228.2 154.0 78.0 0.0 15,806

Interest 0.0 3.0 3.1 15.1 24.5 31.1 29.9 28.7 27.4 26.1 24.7 23.4 21.9 20.5 19.0 17.5 15.9 14.3 12.7 11.0 9.3 7.5 5.7 3.9 1.9 398

Repayment 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 79.9 1,598

Total

mil.USD

Year Total

mil.USD

Total

mil.USD

mil.USD

Year

mil.USD

Year

mil.USD


- 188 -

Chapter 10 Action Plan and Issues

- 190 -

(1) Efforts being made toward the project implementation

Taking into account the future global energy demand, the effective utilization of coal is becoming a very

important issue. While oil and gas are considered to be depleted in about 40 and 60 years respectively

(although shale gas development may influence such conditions), the reserve-production ratio of coal is

expected to be about 190 years. Furthermore, coal is relatively widely distributed including

geopolitically stable regions. In terms of price, coal thermal power generation has achieved reasonable

electricity supply compared with other fossil fuels.

On the other hand, one concern in the international efforts being made against climate change is that coal

thermal power generation produces greenhouse gases such as CO2.

Under such a circumstance, both Japan and Thailand have significant interests and strong motivation to

promote clean coal technologies including IGCC which can realize the effective utilization of coal by

achieving higher power generation efficiency with consideration on environmental impacts.

The Japanese government places the infrastructure package export as a core element of its New Growth

Strategy. This approach is meant to formulate a scheme that Japanese corporations win a contract as a

comprehensive ‘system’ including not only supply of individual equipment and facilities but also

designing, construction, operation and maintenance in order to stay as a winner in the competitive

international market through advancing Japanese industries and enhancing the added values.

Infrastructure demands including the electricity sector are rapidly expanding and attract the global

attention as a sector with large potential growth. Like other countries including China and Korea in

addition to Europe and the United States which take part in the contract competitions through the

cooperation of the government and the private sector, Japan is also promoting infrastructure package

exports based on the public-private partnerships (PPP).

Since this project can be formulated by utilizing advanced manufacturing technology and excellent

operation and maintenance know-how accumulated through domestic projects including the Nakoso

IGCC Demonstration Plant and through appealing to the counterpart country of the Japanese technical

advantages such as high efficiency, high reliability and low environmental pressure, it is considered to

match the infrastructure package export policy promoted by the Japanese government.

Mitsubishi Corporation is considering the possibility of developing this project on a public-private

partnership (PPP) basis based on its long-term experience in power plant construction, operation and

maintenance in the Thai electricity sector and on the above-mentioned background.

After this survey, a detail feasibility survey etc. from the technical and economic aspects will be needed.

As this project is considered to contribute to achieving low carbon societies at the global scale and also

to have high potentials to grow as an infrastructure project scheme with which Japanese corporations can

have advantages in the international competition, it is expected that the Japanese government provide

continuous supports including financial aspects.

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(2) Efforts being made by counterpart government agencies and implementing bodies toward the project implementation

The Thai government has been promoting the best mixture of power sources. The Electricity Generating

Authority of Thailand (EGAT) under the Ministry of Energy released the “Summary of Thailand Power

Development Plan 2010-2030 (PDP 2010)” in April 2010 and is reviewing it for revision including the

impacts of the flood disaster occurred in Thailand last year on the economic growth and the vision of

nuclear power policy after the Great East Japan Earthquake. The Thai government is concerned about

the fact that the country currently highly depends on domestic natural gas as much as over 70% in the

power source ratio in the country, and has been progressively introducing LNG to satisfy increasing

electricity demands. A big challenge in such a circumstance is how to introduce coal thermal power

generation with environmental consideration and with the understanding of the Thai people.

The plan in the “PDP 2010” is to expand the installed capacity of coal fired power plant from 3,897MW

(2010) to 10,827MW by 2030, and the plan indicates a policy of promoting energy diversification

through power source development based on clean coal technology and climate change measures.

The Ministry of Energy of the Thai government and EGAT indicate their very strong interests and

expectations toward this project. Upon implementing this project survey also, EGAT provides full-scale

cooperation as a counterpart of the study team in terms of data provision and on-site acceptance by

formulating a working group for this survey.

As mentioned earlier, while the effective utilization of coal is now a mandate of the Thai government in

order to achieve “stable power source supply for future electricity demands”, the government inevitably

needs to give consideration to the people’s negative impressions against the normal coal thermal power

generation. Under such a circumstance, IGCC which excels in environmental performance as well as

efficiency will realize the strengthening of power generation sources by coal with public understanding

and thus be a significant option which will lead to enhanced energy diversification. Taking this point into

account, the Thai Ministry of Energy and EGAT have a strong interest, and also new power source

introduction by IGCC may be referred in the Power Development Plan which is currently under

revision.

The Thai government is also considering the possibility of sending a study team mainly formed by

EGAT to Japan in order to visit and learn clean coal technology including IGCC.

(3) Presence or absence of the counterpart’s legislative and financial constraints, etc.

Although there are quite a number of regulations to be complied in constructing new thermal power

plants in general in Thailand such as permission and authorization to be obtained (for example, in

relation to environmental regulation, there are Chapter 67 of Thai Constitution, and Environmental

Impact Assessment and Health Impact Assessment under the ordinance of Ministry of Natural Resources

and Environment etc), no particular legislative and financial constraints for realizing this project have

not been identified based on this survey results. However, in case of considering joint investment with

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EGAT which was established as a state company under the special law, the project implementing body

will be recognized as a state company depending on the investment ratio according to the Thai State

Enterprise Act (if the Thai government’s investment ratio is above 50%), and thus the project activities

may be restricted. Further thorough checking on this matter shall be made in the process of promoting

project formulation in future.

(4) Necessity of additional detail analysis

For realizing this project, detail feasibility survey needs to be conducted on both technical and economic

aspects. Based on the survey, a project feasibility evaluation shall be made in order to make an

investment decision including detail designing which is to be conducted as the following step.