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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 3-47 Coal Consumption Plan (2) ................................................................................................ 116
Figure 3-48 Coal Consumption Plan (3) ................................................................................................ 117
Figure 3-49 Coal Consumption Plan (4) ................................................................................................ 118
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
Figure 5-10 Recovery of increment of initial investment by difference of fuel and O & M cost
(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
Deputy Prime Minister
Chalerm Yoobamrung Police Captain, Former Minister of Interior, Former Minister of Justice
Deputy Prime Minister
Kowit Watana Police General, Former Deputy Prime Minister and Minister of Interior, Former Police Commissioner General
Deputy Prime Minister
Kittirat na Ranong President of Shinawatra University, Former managing director of the Stock Exchange of Thailand (SET)
Deputy Prime Minister
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)
(Source) IEA, Energy Balances of non-OECD Countries
- 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
(Source) IEA, Energy Balances of non-OECD Countries
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
Coal Oil Natural gas Hydropower and others
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
Coal Oil Natural gas Hydropower and others
TWh
(Source) IEA, Energy Balances of non-OECD Countries
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
(Source) IEA, Energy Balances of non-OECD Countries
- 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.
(Source) Prepared by Study Team
- 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
Local survey coordination, localsurvey interpretation
Survey regarding environmental andsocial considerations
Local survey coordination, localsurvey interpretation
Technical aspects: IGCCspecifications, conceptual design
Technical aspects: IGCCspecifications, conceptual design
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
(Source) Prepared by Study Team
- 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
(Source) Prepared by Study Team
- 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
Atsuo Sagawa The Institute of Energy Economics, Japan
Keisuke Tanaka Mitsubishi Corporation
Ryuzo Watari Chiyoda Corporation
Takehiko Inagaki Tokyo Electric Power Services Co., Ltd.
Krit Tangvisutthijit Thai-MC Company Limited
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:
Hirohito Morita The Institute of Energy Economics, Japan
Atsuo Sagawa The Institute of Energy Economics, Japan
Kouichi Koizumi The Institute of Energy Economics, Japan
Takuya Inoue Mitsubishi Corporation
Ryuzo Watari Chiyoda Corporation
Takehiko Inagaki Tokyo Electric Power Services Co., Ltd.
Krit Tangvisutthijit Thai-MC Company Limited
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:
Hirohito Morita The Institute of Energy Economics, Japan
Atsuo Sagawa The Institute of Energy Economics, Japan
Keisuke Tanaka Mitsubishi Corporation
Ryuzo Watari Chiyoda Corporation
Takehiko Inagaki Tokyo Electric Power Services Co., Ltd.
Kazuhiro Watanabe Thai-MC Company Limited
Krit Tangvisutthijit 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
(Source) Material provided by the EGAT
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
(Source) Prepared by Study Team based on Google Map
Figure 3-4 Mae Moh Coal Mine and Power Plant
2400MW Sub-CriticalPower Plant at Mae Moh
City at Mae Moh
0 2 km
(Source) Prepared by Study Team based on Google Map
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.
(Source) Prepared by Study Team
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
(Source) Prepared by Study Team based on EGAT data
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%
(Source) Prepared by Study Team based on EGAT data
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
(Source) Prepared by Study Team based on EGAT data
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)
(Source) Prepared by Study Team based on EGAT data
- 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
(Source) Prepared by Study Team based on EGAT data
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)
(Source) Prepared by Study Team
Figure 3-11 Candidate Site for New IGCC Power Plant (Outside Power Plant Area)
(Source) Prepared by Study Team
- 53 -
Figure 3-12 Candidate Site for New IGCC Power Plant (Backside, Option)
(Source) Prepared by Study Team
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
(Source) Prepared by Study Team
Figure 3-14 Regulating Pond
(Source) Prepared by Study Team
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)
(Source) Prepared by Study Team based on internal data
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
(Source) Prepared by Study Team based on internal data
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
(Source) Prepared by Study Team
- 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
(Source) Prepared by Study Team
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
(Source) Climatological Data For Period 1981 - 2010, Index 48328, Station 328201-Lampang
- 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
(Source) Climatological Data For Period 1981 - 2010, Index 48328, Station 328201-Lampang
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)
(Source) Climatological Data For Period 1981 - 2010, Index 48328, Station 328201-Lampang
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
(Source) Prepared by Study Team
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
(Source) Prepared by Study Team
- 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
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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
(Source) Prepared by Study Team
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
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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.
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(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.
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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.
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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.
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Basic design specifications
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)
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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.
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c. Gas clean-up unit
The gas clean-up unit consists of the following facilities.
COS conversion/raw syngas cooling
Acid gas removal
Basic design specifications
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
(Source) Prepared by Study Team
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.
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(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.
Basic design specifications
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
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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
Basic design specifications
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
(Source) Prepared by Study Team
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)
Basic design specifications
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%
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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.
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Figure 3-26 Simple Air Separation Unit Process Flow
(Source) Brochure of Taiyo Nippon Sanso
g. Waste water treatment unit
Basic design specifications
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
(Source) Prepared by Study Team
<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
(Source) Prepared by Study Team
(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
(Source) Prepared by Study Team
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
(Source) EPRI, Gasification Technologies Conference, 2011
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
(Source) EPRI, Gasification Technologies Conference, 2011
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
(Plant overall) Remarks
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
(Plant overall) Remarks
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
North
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
al P
rod
uct
ion
(m
illio
n to
n)
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
Strip
Ra
tio
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
(Source) EGAT-supplied material
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
(Source) EGAT-supplied material
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
(Source) EGAT-supplied material
Figure 3-43 Panoramic View of Pit
(Source) Prepared by Study Team
- 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 %
(Source) EGAT-supplied material
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
(Source) EGAT-supplied material
- 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
(Source) Prepared by Study Team based on the EGAT-supplied material
- 116 -
Figure 3-46 Coal Consumption Plan (1)
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
'10 '12 '14 '16 '18 '20 '22 '24 '26 '28 '30 '32 '34 '36 '38 '40 '42 '44 '46
Coal
Consu
mpt
ion (
mill
ion t
on)
0
50
100
150
200
250
300
350
400
450C
um
ulative
Coal C
onsu
mptio
n (m
illion to
n)
Unit 4-7 (before replacement) Unit 4-7 (after replacement) Unit 8-13 Cumulative Coal Consumption
Remaining Coal Economical Reserve 342 million ton
(Source) Prepared by Study Team based on the EGAT-supplied material
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.
Figure 3-47 Coal Consumption Plan (2)
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
'10 '12 '14 '16 '18 '20 '22 '24 '26 '28 '30 '32 '34 '36 '38 '40 '42 '44 '46
Coal
Consu
mpt
ion (m
illio
n t
on)
0
50
100
150
200
250
300
350
400
450
Cum
ulative
Coal C
onsu
mptio
n (m
illion to
n)
Unit 4-7 (before replacement) Unit 4-7 (after replacement) Unit 8-13
IGCC Cumulative Coal Consumption
Remaining Coal Economical Reserve 342 million ton
Mine Out
(Source) Prepared by Study Team based on the EGAT-supplied material
“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.
Figure 3-48 Coal Consumption Plan (3)
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
'10 '12 '14 '16 '18 '20 '22 '24 '26 '28 '30 '32 '34 '36 '38 '40 '42 '44 '46
Coal
Consu
mpt
ion (
mill
ion t
on)
0
50
100
150
200
250
300
350
400
450
Cum
ulative
Coal C
onsu
mptio
n (m
illion to
n)
Unit 4-7 (before replacement) Unit 4-7 (after replacement) Unit 8-13
IGCC Cumulative Coal Consumption
Remaining Coal Economical Reserve 342 million ton
(Source) Prepared by Study Team based on the EGAT-supplied material
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.
Figure 3-49 Coal Consumption Plan (4)
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
'10 '12 '14 '16 '18 '20 '22 '24 '26 '28 '30 '32 '34 '36 '38 '40 '42 '44 '46
Coal
Consu
mpt
ion (
mill
ion t
on)
0
50
100
150
200
250
300
350
400
450
Cum
ulative
Coal C
onsu
mptio
n (m
illion to
n)
Unit 4-7 (before replacement) Unit 4-7 (after replacement) Unit 8-13
IGCC Cumulative Coal Consumption
Remaining Coal Economical Reserve 342 million ton
(Source) Prepared by Study Team based on the EGAT-supplied material
“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.
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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.
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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)
Exixting Mae Moh 8-13
(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
(Source) Prepared by Study Team
- 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
Exixting Mae Moh 8-13
(Regulation)
Exixting Mae Moh 8-13
(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
(Source) Prepared by Study Team
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
Environmental Items Main Check Items Yes:Y
No:NConfirmation of Environmental and Social
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
Environmental Items Main Check Items Yes:Y
No:NConfirmation of Environmental and Social
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.
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Cat
egor
y
Environmental Items Main Check Items Yes:Y
No:NConfirmation of Environmental and Social
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.
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Cat
egor
y
Environmental Items Main Check Items Yes:Y
No:NConfirmation of Environmental and Social
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.
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Cat
egor
y
Environmental Items Main Check Items Yes:Y
No:NConfirmation of Environmental and Social
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.
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Cat
egor
y
Environmental Items Main Check Items Yes:Y
No:NConfirmation of Environmental and Social
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.
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Cat
egor
y
Environmental Items Main Check Items Yes:Y
No:NConfirmation of Environmental and Social
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
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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.
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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
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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
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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.
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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
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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
(Source) Prepared by Study Team based on EGAT data
(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
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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
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(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.
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(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
(Source) Prepared by Study Team
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%
(Source) Prepared by Study Team
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%)
WACC: 4.5%(Interest:2.5%)
(Source) Prepared by Study Team
Table 5-3 WACC resulting if low-interest financing is utilized such as JICA overseas financing
Debt Commitment Fee Equity WACC
Interest rate /amortizatuon rate
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
Electricity selling price 0.08US$/kWh
Electricity selling price 0.07US$/kWh
(Source) Prepared by Study Team
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$/kWh)
-500
0
500
1,000
1,500
2 4 6 8 10Discout rate (%)
NP
V (m
il. U
S$)
Electricity selling price 0.09US$/kWh
Electricity selling price 0.08US$/kWh
Electricity selling price 0.07US$/kWh
(Source) Prepared by Study Team
- 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
(Source) Prepared by Study Team
- 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
(Source) Prepared by Study Team
- 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
Debt Commitment Fee Equity WACC
Interest rate /amortizatuon rate
6.5% 0.375% 10.0% 7.7%
(Source) Prepared by Study Team
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$/kWh)
FIR
R(%)
WACC: 7.7%(Interest:6.5%)
WACC: 4.5%(Interest:2.5%)
(Source) Prepared by Study Team
Figure 5-5 Results of the FIRR sensitivity analysis on the construction cost (air-blown IGCC)
(US$/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
Electricity selling price(US$/kWh)
Construction cost
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
11.0
12.0
13.0
14.0
70 80 90 100 110
Constraction cost (%)
FIR
R(%)
Electricity selling price 0.09US$/kWh
Electricity selling price 0.08US$/kWh
Electricity selling price 0.07US$/kWh
(Source) Prepared by Study Team
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
Electricity selling price(US$/kWh)
-500
0
500
1,000
1,500
2 4 6 8 10Discout rate (%)
NP
V (
mil.
US$)
Electricity selling price 0.09US$/kWh
Electricity selling price 0.08US$/kWh
Electricity selling price 0.07US$/kWh
(Source) Prepared by Study Team
- 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
Total Investment 4.0 160.0 639.9 479.9 319.9 1,603.6
(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
Free Cash Flow mil.USD -4.0 -160.9 -640.7 -480.8 -320.8 148.7 148.9 149.2 149.5 149.8 150.1 150.3 150.6 150.9 151.2 151.5 151.7 152.0 152.3 152.6 152.9 153.1 153.4 153.7 154.0 154.3 154.5 154.8 155.1 155.4 2,193.3
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
(Source) Prepared by Study Team
- 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
Net plant output: 425MW
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%.)
Net plant efficiency: 38.9%
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$1,850/kW (assumed current price in Thailand)
O&M cost: Assumed to be 80% of that of the IGCC plant.
Results of analysis
The EIRR of this project was 10% in cost comparison with the alternative project, which is a
USC coal fired power plan that uses imported coal as fuel as an alternative generation form (see
Table 5-8). The difference of initial investment between IGCC at Mae Moh and USC by imported
coal is recovered in 25 years after commencement at a discount rate of 10%. However, the
recovery years will be shorter, as a coal terminal such as discharging berth and stockyard and
transport infrastructure to power station for the construction of USC coal-fired power plant will
be needed and the initial investment will be higher.
- 161 -
Figure 5-7 Recovery of increment of initial investment by difference of fuel and O & M cost
(IGCC at Mae Moh vs USC by imported coal)
-500
-400
-300
-200
-100
0
100
-4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Cost
bal
ance (
mil. U
S$)
(Source) Prepared by Study Team
- 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$/kW)
EIR
R(%)
(Source) Prepared by Study Team
Figure 5-9 Sensitivity analysis with the imported coal price
Coal price(US$/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$/t)
EIR
R(%)
(Source) Prepared by Study Team
b. GTCC plant
Assumptions
The alternative facility conditions are as follows:
Gross plant output: 438MW (determined by on-site consumption rate)
Net plant output: 425MW
- 164 -
O Internal power consumption rate: 2.9%
Availability: 85%
Gross plant efficiency: 55.8%
Net plant efficiency: 54.2%
LNG calorific value (net, ar): 13,019kcal/kg
Price of LNG : US$ (CIF): US$16.9/million Btu (assumed as CIF Japan in
November 2011)
Unit construction cost: US$800/kW (assumed current price in Thailand)
O&M cost: Assumed to be 80% of that of the IGCC plant.
Results of analysis
In cost comparison with the GTCC plant that uses imported LNG as fuel in an alternative power
generation form, the EIRR of this project is 19.3% and the IGCC plant is economically superior
to the GTCC plant that uses imported LNG as fuel (see Table 5-9). The difference of initial
investment cost between IGCC at Mae Moh and GTCC by LNG is recovered in 6.5 years after
commencement at a discount rate of 10%. And also the recovery years will be even shorter than
6.5 years, as a LNG terminal for GTCC plant is needed and the initial investment will be higher.
Figure 5-10 Recovery of increment of initial investment by difference of fuel and O & M cost
(IGCC at Mae Moh vs GTCC by imported LNG)
-1000
-800
-600
-400
-200
0
200
400
600
800
1000
-4 -3 -2 -1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Cost
bal
ance (m
il. U
S$)
(Source) Prepared by Study Team
- 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
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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(%)
(Source) Prepared by Study Team
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(%)
(Source) Prepared by Study Team
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
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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.
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[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.
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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
(Source) Prepared by Study Team
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.
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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.
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Figure 7-1 EGAT Power Source Composition in 2010
(Source) Material provided by the EGAT
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
(Source) Prepared by Study Team
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,
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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
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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
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
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
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
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
Interest 2.5% Repayment perio 20 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 0.0 107.6 530.3 858.6 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
(Source) Prepared by Study Team
- 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
Total Investment 4.0 160.0 639.9 479.9 319.9 1,603.6
(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
Free Cash Flow mil.USD -4.0 -160.9 -640.7 -480.8 -320.8 148.7 148.9 149.2 149.5 149.8 150.1 150.3 150.6 150.9 151.2 151.5 151.7 152.0 152.3 152.6 152.9 153.1 153.4 153.7 154.0 154.3 154.5 154.8 155.1 155.4 2,193.3
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 0.0 120.0 479.9 359.9 239.9 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
Interest 2.5% Repayment perio 20 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 0.0 120.0 479.9 359.9 239.9 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
(Source) Prepared by Study Team
- 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.
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